Edgar Filing: Midstates Petroleum Company, Inc.

Preliminary Information Statement

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

SCHEDULE 14C

(Rule 14c-101)

SCHEDULE 14C INFORMATION

Information Statement Pursuant to Section 14(c) of

the Securities Exchange Act of 1934

Check the appropriate box:

x	Preliminary Information Statement

¨	Confidential, for Use of the Commission Only (as permitted by Rule 14c-5(d)(2))

¨	Definitive Information Statement

MIDSTATES PETROLEUM COMPANY, INC.

(Name of Registrant as Specified in its Charter)

Payment of Filing Fee (Check the appropriate box):

x	No fee required.

¨	Fee computed on table below per Exchange Act Rules 14c-5(g) and 0-11.

Title of each class of securities to which transaction applies:

Aggregate number of securities to which transaction applies:

Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined):

Proposed maximum aggregate value of transaction:

Total fee paid:

¨	Fee paid previously with preliminary materials.

¨	Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.

Amount Previously Paid:

Form, Schedule or Registration Statement No.:

Filing Party:

Date filed:

Midstates Petroleum Company, Inc.

4400 Post Oak Parkway

Suite 1900

Houston, Texas 77027

LOGO

[ ], 2012

Dear Stockholder:

We are sending this information statement to holders of shares of common stock, par value $0.01 per share (the “Common Stock”), of Midstates Petroleum Company, Inc. (the “Company” or “we”). As previously announced, on August 11, 2012, we entered into an asset purchase agreement (the “Acquisition Agreement”) with Eagle Energy Production, LLC (“Eagle Energy”) pursuant to which we agreed to acquire certain interests in producing oil and gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and the related hedging instruments (the “Eagle Energy Acquisition”). The aggregate purchase price includes the issuance to Eagle Energy of 325,000 shares of Series A Mandatorily Convertible Preferred Stock with an initial liquidation preference of $1,000 per share (the “Preferred Stock”).

Our Common Stock is listed on the New York Stock Exchange. Under the rules of the New York Stock Exchange, the holders of a majority of the outstanding shares of the Common Stock must approve the issuance of the Preferred Stock because we will have issued securities (i) that are convertible into a number of shares of our Common Stock equal to or in excess of 20 percent of the number of shares of Common Stock outstanding before the issuance of the Preferred Stock and (ii) that represent voting power equal to or in excess of 20% of the total voting power outstanding prior to the issuance of the Preferred Stock. As permitted by the General Corporation Law of the State of Delaware, our Amended and Restated Certificate of Incorporation and our Bylaws, by resolutions adopted through written consent dated August 11, 2012, the holders of a majority of the outstanding shares of the Common Stock on such date approved the issuance of the Preferred Stock pursuant to the terms of the Acquisition Agreement and the issuance of shares of our Common Stock issuable upon conversion of the Preferred Stock (the “Stockholder Action”). The closing of the transactions contemplated by the Acquisition Agreement, including the issuance of the Preferred Stock to Eagle Energy, is expected to occur on or about October 1, 2012. At the time of its issuance, the Preferred Stock will not be convertible into Common Stock and will hold voting power equal to 19.9% of the total voting power outstanding before its issuance. Under the rules of the Securities and Exchange Commission, the Stockholder Action will not be effective until 20 calendar days after we mail this information statement to our stockholders. As a result, the Preferred Stock will only become convertible into Common Stock and represent voting power in excess of 19.9% of the total voting power beginning on the 21st calendar day after we mail this information statement to our stockholders.

We are mailing this information statement to our holders of record as of the close of business on September 26, 2012. This information statement is being provided to you for your information to comply with the requirements of the Securities Exchange Act of 1934, as amended. You are urged to read this information statement carefully in its entirety. However, no action is required on your part in connection with this document. No stockholder meeting will be held in connection with this information statement. We are not asking you for a proxy and you are requested not to send us a proxy.

We thank you for your continued support.

Very truly yours,

Stephen J. McDaniel

Chairman of the Board

NOTICE ABOUT INFORMATION CONTAINED IN

THIS INFORMATION STATEMENT

You should assume that the information in this information statement or any supplement is accurate only as of the date on the front page of this information statement. Our business, financial condition, results of operations and prospects may have changed since that date and may change again.

TABLE OF CONTENTS


NOTICE ABOUT INFORMATION CONTAINED IN THIS INFORMATION STATEMENT			i

INFORMATION STATEMENT AND NOTICE OF ACTION TAKEN WITHOUT A MEETING			1

SUMMARY			1

Action Approved by Written Consent of Stockholders Representing a Majority of Our Outstanding Common Stock			1

The Acquisition Agreement			2

Other Transactions			2

New York Stock Exchange Requirements			2

FORWARD-LOOKING STATEMENTS			3

UNAUDITED PRO FORMA FINANCIAL INFORMATION			5

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA			14

ACTION BY WRITTEN CONSENT			16

THE EAGLE ENERGY ACQUISITION			17

BACKGROUND OF THE TRANSACTION			20

Reasons for the Action Taken			20

Effects of the Proposed Issuance			20

No Dissenter’s Rights			21

Interest of Certain Persons in the Action Taken			21

THE ACQUISITION AGREEMENT			22

The Parties to the Acquisition Agreement			22

Accounting Treatment			23

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			24

DESCRIPTION OF CAPITAL STOCK			25

REGISTRATION RIGHTS			29

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			30

WHERE YOU CAN FIND MORE INFORMATION			55

STOCKHOLDERS SHARING AN ADDRESS			55

INDEX TO FINANCIAL STATEMENTS			F-1

ANNEX A – ASSET PURCHASE AGREEMENT			A-1

Midstates Petroleum Company, Inc.

4400 Post Oak Parkway

Suite 1900

Houston, Texas 77027

[ ], 2012

INFORMATION STATEMENT AND

NOTICE OF ACTION TAKEN WITHOUT A MEETING

WE ARE NOT ASKING YOU FOR A PROXY,

AND YOU ARE REQUESTED NOT TO SEND US A PROXY

SUMMARY

We are furnishing this information statement and notice of action taken without a meeting to our stockholders in connection with the approval by our board of directors of the matters described below and the subsequent approval of these matters by written consent of the holders of a majority of our outstanding Common Stock. All corporate approvals in connection with these matters have been obtained and this information statement is furnished solely for the purpose of informing stockholders of these corporate actions in the manner required by the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the General Corporation Law of the State of Delaware, our Amended and Restated Certificate of Incorporation and our Bylaws.

The record date for determining stockholders entitled to receive this information statement has been established as the close of business on September 26, 2012. On that date, there were [ ] shares of Common Stock and no shares of preferred stock issued and outstanding.

Action Approved by Written Consent of Stockholders Representing a Majority of Our Outstanding Common Stock (See page 16)

The corporate action described in this information statement was approved by the written consent of the holders of a majority of the Common Stock in accordance with the General Corporation Law of the State of Delaware, our Amended and Restated Certificate of Incorporation and our Bylaws. Only holders of our Common Stock were entitled to vote on matters submitted to our stockholders.

On August 11, 2012, the holders of a majority of our outstanding Common Stock approved by written consent the issuance of the Preferred Stock and the Common Stock into which the Preferred Stock will become convertible. On that date, there were 66,549,563 shares of our Common Stock issued and outstanding.

This information statement is being mailed to stockholders on or about [ ], 2012. The Preferred Stock to be issued in connection with the Eagle Energy Acquisition will not become convertible into shares of our Common Stock until the 21st day after the date on which we mail this information statement to our stockholders, and the holders of the Preferred Stock may not convert their shares of Preferred Stock before the first anniversary of the closing date of the Eagle Energy Acquisition, which is expected to occur on or about October 1, 2012. After such time, the Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Preferred Stock, into a number of shares of our Common Stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. In addition, the Preferred Stock will be subject to mandatory conversion into shares of our Common Stock on September 30, 2015 at a conversion price no greater than $13.50 per share and no less than $11.00 per share.

The Acquisition Agreement (See page 22)

On August 11, 2012, we entered into the Acquisition Agreement. Under the terms of the Acquisition Agreement, upon consummation of the Eagle Energy Acquisition, among other things:

•

we will acquire certain interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and the related hedging instruments from Eagle Energy;

•

we will pay to Eagle Energy $325,000,000 in cash, subject to adjustment as provided in the Acquisition Agreement;

•

we will issue to Eagle Energy 325,000 shares of Preferred Stock; and

•

we will enter into certain ancillary agreements with Eagle Energy, including a registration rights agreement, transition services agreement, escrow agreement and access agreement.

Other Transactions (See page 19)

In connection with the consummation of the Eagle Energy Acquisition, we anticipate entering into the following additional transactions (together with the Eagle Energy Acquisition, the “Transactions”):

•

the issuance and sale by us and Midstates Sub of $550 million aggregate principal amount of senior unsecured notes or, if such sale is not completed, the entrance by us and Midstates Sub into a $500 million bridge credit facility and, in either case, the use of proceeds therefrom to fund the cash portion of the purchase price of the Eagle Energy Acquisition and the expenses relating thereto and to repay a portion of the outstanding borrowings under our revolving credit facility; and

•

entry into an amendment to our revolving credit facility to, among other things, increase the borrowing capacity from $200 million to $250 million, subject to the satisfaction of certain conditions (the “Credit Agreement Amendment”).

New York Stock Exchange Requirements (See page 16)

Our Common Stock is listed on the New York Stock Exchange (the “NYSE”). Under Section 312.03 of the NYSE Listed Company Manual, stockholder approval is required prior to the issuance of shares of common stock, or of securities convertible into common stock, if:

•

such common stock or securities have, or will have upon issuance, voting power equal to 20% or more of the voting power outstanding before the issuance of such stock or securities convertible into common stock; or

•

the number of shares of common stock to be issued is, or will be upon issuance, equal to 20% or more of the number of shares of common stock outstanding before the issuance of the common stock or securities convertible into common stock.

Because the maximum number of shares of our Common Stock issuable upon conversion of the Preferred Stock would represent approximately 56% of the number of shares of our Common Stock outstanding prior to the issuance of the Preferred Stock and because, beginning on the 21st day after the mailing of this information statement, the Preferred Stock will represent voting power greater than 20% of the voting power before the issuance of the Preferred Stock, stockholder approval of the issuance of the convertible Preferred Stock is required under NYSE regulations.

FORWARD-LOOKING STATEMENTS

Various statements contained in or incorporated by reference into this information statement that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, are forward-looking statements. When used in this information statement, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

•

our business strategy;

•

estimated future net reserves and present value thereof;

•

technology;

•

cash flows and liquidity;

•

financial strategy, budget, projections and operating results;

•

oil and natural gas realized prices;

•

timing and amount of future production of oil and natural gas;

•

availability of drilling and production equipment;

•

availability of oilfield labor;

•

the amount, nature and timing of capital expenditures, including future development costs;

•

availability and terms of capital;

•

drilling of wells including our identified drilling locations;

•

successful results from our identified drilling locations;

•

marketing of oil and natural gas;

•

the closing, financing, integration and benefits of the Eagle Energy Acquisition or the effects of the acquisition on our cash position and levels of indebtedness;

•

infrastructure for salt water disposal;

•

property acquisitions;

•

costs of developing our properties and conducting other operations;

•

general economic conditions;

•

effectiveness of our risk management activities;

•

environmental liabilities;

•

counterparty credit risk;

•

the outcome of pending and future litigation;

•

governmental regulation and taxation of the oil and natural gas industry;

•

developments in oil-producing and natural gas-producing countries;

•

uncertainty regarding our future operating results; and

•

plans, objectives, expectations and intentions contained in this information statement that are not historical.

All forward-looking statements speak only as of the date of this information statement. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions including, but not limited to, those discussed in the prospectus for our initial public offering filed with the SEC on April 20, 2012, our Quarterly Reports for the periods ended March 31, 2012 and June 30, 2012 and our other filings with the SEC. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our 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 statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this information statement are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

UNAUDITED PRO FORMA FINANCIAL INFORMATION

In connection with the execution of the Acquisition Agreement and in order to fund, among other things, the cash portion of the Eagle Energy Acquisition, on August 11, 2012, we and Midstates Sub entered into a commitment letter to provide for an unsecured bridge credit facility in the amount of up to $500 million. The availability of loans under the bridge credit facility are subject to the consummation of the Eagle Energy Acquisition and other customary conditions and the proceeds may be used solely to fund the Eagle Energy Acquisition, to pay transaction costs and expenses in connection therewith or repay existing outstanding debt under the existing revolving credit facility.

On September 7, 2012, Midstates and Midstates Sub entered into an amendment to the existing secured revolving credit facility. This amendment provides for two sets of changes to the existing credit facility. The amendment provides for $35 million of non-conforming borrowing base loans, thereby increasing the borrowing base under the existing secured revolving credit facility from $200 million to $235 million. The effectiveness of this provision of the amended revolving credit facility was effective on September 7, 2012 and was not subject to the consummation of the Eagle Energy Acquisition.

In addition, the amendment will increase the borrowing base to $250 million and permit the issuance of the Preferred Stock in connection with the Eagle Energy Acquisition. It will also increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, from $275 million to $550 million, thereby permitting the incurrence of $550 million of senior notes without causing a $0.25 reduction in the borrowing base for every $1 of debt incurred or issued up to $550 million. The effectiveness of these provisions of the amended revolving credit facility is subject to the consummation of the Eagle Energy Acquisition and other customary conditions. If these conditions are satisfied, the amended revolving credit facility will mature on the fifth anniversary of the date on which these conditions are satisfied.

The Preferred Stock to be issued in connection with the Eagle Energy Acquisition will not become convertible into shares of our Common Stock until the 21st day after the date on which we mail to our stockholders this information statement regarding the issuance of the Preferred Stock, and the holders of the Preferred Stock may not convert before the first anniversary of the closing date of the Eagle Energy Acquisition. After such time, the Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Preferred Stock, into a number of shares of our Common Stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. In addition, the Preferred Stock will be subject to mandatory conversion into shares of our Common Stock on September 30, 2015 at a conversion price no greater than $13.50 per share and no less than $11.00 per share. Dividends on the Preferred Stock will accrue at a rate of 8.0% per annum, payable semi-annually, at our sole option in cash or through an increase in the liquidation preference. The Preferred Stock will rank senior to our Common Stock with respect to dividend rights and will participate, on an as converted basis, in any cash dividends or other distributions to holders of our Common Stock.

The unaudited pro forma condensed combined balance sheet as of June 30, 2012 is based on our unaudited condensed consolidated balance sheet as of June 30, 2012, adjusted to reflect the following items as though they had occurred on June 30, 2012:

•

the preliminary purchase accounting assigned to the assets to be acquired and liabilities to be assumed in the Eagle Energy Acquisition and the preliminary estimate of the fair value of the Preferred Stock;

•

nonrecurring estimated expenses associated with the Eagle Energy Acquisition and the commitment fees and other expenses associated with the bridge funding commitment;

•

the expected issuance of $550 million of senior notes and the related offering costs subject to amortization, the net proceeds from which will be used to fund the estimated cash purchase price of the

Eagle Energy Acquisition, to repay outstanding borrowings under the revolving credit facility and for general corporate purposes; and

•

the estimated amortizable fees associated with the increase in our borrowing base under the revolving credit facility from $200 million to $235 million and, upon the closing of the Eagle Energy Acquisition, from $235 million to $250 million.

The unaudited pro forma condensed combined income statement for the year ended December 31, 2011 is based on our audited consolidated income statement for the year ended December 31, 2011. The unaudited pro forma condensed combined income statement for the six months ended June 30, 2012 is based on our unaudited condensed consolidated income statement for the six months ended June 30, 2012. The unaudited pro forma condensed combined income statements for the year ended December 31, 2011 and for the six months ended June 30, 2012 have been adjusted to reflect the following items as though the Eagle Energy Acquisition and related transactions had occurred on January 1, 2011:

•

the revenues and direct operating expenses related the Eagle Energy Acquisition;

•

the depreciation, depletion, amortization and asset retirement obligation accretion related to the Eagle Energy Acquisition under the full cost method of accounting;

•

the historical general and administrative expense associated with the Eagle Energy Acquisition, net of amounts expected to be capitalized to oil and gas properties;

•

the dividend associated with the Preferred Stock to be issued in connection with the Eagle Energy Acquisition;

•

the estimated interest expense associated with the senior notes offering and the amortization of deferred financing costs, net of amounts expected to be capitalized to unevaluated oil and gas properties; and

•

the income tax effect of the adjustments outlined above.

The pro forma adjustments are based upon available information and certain assumptions that we believe are reasonable as of the date of this information statement. The pro forma adjustments reflected herein are preliminary and based on management’s estimations and expectations about the accounting that is expected to take place. In particular, the accounting for the Eagle Energy Acquisition is complex and entails determining the fair values of assets acquired and liabilities assumed. The Eagle Energy Acquisition will be accounted for using the purchase method of accounting. Accordingly, the final purchase price allocation is pending the finalization of appraisal valuations of certain tangible and any intangible assets acquired, which may result in an adjustment to the preliminary purchase price allocation. Any such adjustments to the preliminary estimates of fair value could be material. Therefore, the actual adjustments will differ from the pro forma adjustments, and the differences may be material.

These unaudited pro forma condensed combined financial statements have been prepared for comparative purposes only and may not be indicative of the results that would have occurred if we had completed these transactions at an earlier date or the results that may occur in the future. These unaudited pro forma condensed combined financial statements should be read in conjunction with our audited December 31, 2011 consolidated financial statements and notes thereto, the unaudited June 30, 2012 consolidated financial statements, Eagle Energy’s audited consolidated financial statements as of and for the years ended December 31, 2011 and 2010, and Eagle Energy’s unaudited consolidated financial statements as of and for the six months ended June 30, 2012, each included in this information statement.

Midstates Petroleum Company, Inc.

Unaudited Pro Forma Condensed Combined Balance Sheet as of June 30, 2012


	Midstates Historical			Pro forma adjustments							Midstates Pro Forma Combined
	Midstates Historical			Eagle Energy Assets			Notes Offering and Credit Agreement Amendment				Midstates Pro Forma Combined
CURRENT ASSETS
Cash and cash equivalents	$	11,689		$	—		$	518,750		(iii)	$	23,739
								(355,000	)	(iii)
								(151,700	)	(iii)
Accounts receivable - sales and other		19,567										19,567
Prepaid expenses and other current assets		11,846										11,846
Commodity derivative contracts		12,038			12,535	(i)		—				24,573

Total current assets		55,140			12,535			12,050				79,725
PROPERTY AND EQUIPMENT
Oil and gas properties
Proved properties		833,172			481,000	(i)						1,314,172
Unevaluated properties		95,600			120,000	(i)						215,600
Other property and equipment		2,168										2,168
Less: accumulated deprecation, depletion and amortization		(204,752	)		—							(204,752	)

		726,188			601,000			—				1,327,188
OTHER ASSETS
Commodity derivative contracts		6,247			6,195	(i)						12,442
Other noncurrent assets		3,660			—			14,750		(iii)		22,710
								4,300		(iv)

Total other assets		9,907			6,195			19,050				35,152

TOTAL ASSETS	$	791,235		$	619,730		$	31,100			$	1,442,065

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	90,107		$	—		$	—			$	90,107
Commodity derivative contracts		360										360

Total current liabilities		90,467			—			—				90,467
LONG-TERM LIABILITIES
Long-term debt		151,700			—			550,000		(iii)		550,000
								(151,700)		(iii)
Deferred income taxes		168,917			—			—				168,917
Asset retirement obligations and other long-term liabilities		10,012			1,671	(v)						11,683

Total long-term liabilities		330,629			1,671			398,300				730,600
STOCKHOLDERS’ EQUITY
Preferred stock, $0.01 par value, 50,000,000 shares authorized with $1,000 per share liquidation preference		—			263,059	(i)		—				263,059
Common stock, $0.01 par value, 300,000,000 shares authorized, 66,549,563 issued and outstanding		665										665
Additional paid-in-capital		536,352										536,352
Retained deficit/accumulated loss		(166,878	)					(12,200	)	(ii)		(179,078	)

Total Stockholders’ equity		370,139			263,059			(12,200	)			620,998

TOTAL LIABILITIES AND EQUITY	$	791,235		$	264,730		$	386,100			$	1,442,065

See accompanying notes.

Midstates Petroleum Company, Inc.

Unaudited Pro Forma Condensed Combined Income Statement for the year ended December 31, 2011


				Pro Forma Adjustments
	Midstates Historical			Eagle Energy Assets				Notes Offering and Credit Agreement Amendment				Midstates Pro Forma Combined
	(In thousands except share and per share amounts)
REVENUES
Oil, natural gas and natural gas liquids	$	213,812		$	73,446		(vi)	$				$	287,258
Gains (losses) on commodity derivative contracts—net		(4,844	)		4,240		(vi)						(604	)
Other		465			—								465

Total revenues		209,433			77,686								287,119
EXPENSES
Lease operating and workovers		17,335			12,130		(vi)						29,465
Severance and other taxes		12,422			3,090		(vi)						15,512
Depletion, depreciation, amortization and accretion		92,033			35,353		(vii)						127,386
General and administrative		68,915			4,474		(viii)						73,389
Other		—			—								—

Total expenses		190,705			55,047								245,752

OPERATING INCOME		18,728			22,639								41,367
OTHER INCOME/EXPENSE
Interest income		23			—								23
Interest expense		(2,094	)		—				(34,844	)	(x)		(36,938	)

NET INCOME (LOSS) BEFORE INCOME TAXES		16,657			22,639				(34,844	)			4,452
Pro forma income tax expense		23,156			9,101		(xi)		(14,007	)	(xi)		18,250

NET INCOME (LOSS)	$	(6,499	)	$	13,538			$	(20,837	)		$	(13,798	)
PREFERRED DIVIDEND		—			26,000		(ix)						26,000

NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	(6,499	)	$	(12,462	)		$	(20,837	)		$	(39,798	)

Pro forma earnings per share available to Midstates Petroleum Company, Inc. common stockholders:
Basic	$	(0.10	)									$	(0.61	)

Diluted	$	(0.10	)									$	(0.61	)

Pro forma weighted average number of Midstates Petroleum Company, Inc. common shares outstanding:
Basic		65,634,353											65,634,353		(xii)

Diluted		65,634,353											65,634,353		(xii)

See accompanying notes.

Midstates Petroleum Company, Inc.

Unaudited Pro Forma Condensed Combined Income Statement for the Six Months Ended June 30, 2012


				Pro Forma Adjustments
	Midstates Historical			Eagle Energy Assets			Notes Offering and Borrowing Base Increase				Midstates Pro Forma Combined
	(In thousands except share and per share amounts)
REVENUES
Oil, natural gas and natural gas liquids	$	109,140		$	47,097	(xiii)	$				$	156,237
Gains on commodity derivative contracts—net		23,478			16,165	(xiii)						39,643
Other		207			—							207

Total revenues		132,825			63,262			—				196,087
EXPENSES
Lease operating and workovers		12,388			7,263	(xiii)						19,651
Severance and other taxes		11,648			1,696	(xiii)						13,344
Depletion, depreciation and amortization		56,207			21,924	(xiv)						78,131
General and administrative		11,019			2,423	(xv)						13,442
Other		—			—							—

Total expenses		91,262			33,306			—				124,568

OPERATING INCOME		41,563			29,956			—				71,519
OTHER INCOME/EXPENSE
Interest income		150			—							150
Interest expense		(2,680	)		—			(16,172	)	(xvii)		(18,852	)

NET INCOME (LOSS) BEFORE INCOME TAXES		39,033			29,956			(16,172	)			52,818
Income tax expense		168,917			12,042	(xviii)		(6,501	)	(xviii)		174,458

NET INCOME (LOSS)	$	(129,884	)	$	17,914		$	(9,671	)		$	(121,641	)
PREFERRED DIVIDEND		—			13,000	(xvi)						13,000

NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$	(129,884	)	$	4,914		$	(9,671	)		$	(134,641	)

Earnings per share available to Midstates Petroleum Company, Inc. common stockholders:
Basic	$	(2.39	)								$	(2.48	)

Diluted	$	(2.39	)								$	(2.48	)

Weighted average number of Midstates Petroleum Company, Inc. common shares outstanding:
Basic		54,260,727										54,260,727		(xix)

Diluted		54,260,727										54,260,727		(xix)

See accompanying notes.

Note 1. Basis of Presentation

The unaudited pro forma condensed combined balance sheet as of June 30, 2012 is based on the unaudited condensed consolidated balance sheet of Midstates as of June 30, 2012, adjusted to reflect the following items as though they had occurred on June 30, 2012:

•

nonrecurring estimated expenses associated with the Eagle Energy Acquisition and the commitment fees and other expenses associated with the bridge funding commitment;

•

the expected issuance of $550 million of senior notes and the related offering costs subject to amortization, the net proceeds from which will be used to fund the estimated cash purchase price of the Eagle Energy Acquisition, to repay outstanding borrowings under the revolving credit facility and for general corporate purposes; and

•

the estimated amortizable fees associated with the increase in Midstates borrowing base under the revolving credit facility from $200 million to $235 million and, upon the closing of the Eagle Energy Acquisition, from $235 million to $250 million.

The unaudited pro forma condensed combined income statement for the year ended December 31, 2011 is based on the audited consolidated income statement of Midstates for the year ended December 31, 2011. The unaudited pro forma condensed combined income statement for the six months ended June 30, 2012 is based on the unaudited condensed consolidated income statement of Midstates for the six months ended June 30, 2012. The unaudited pro forma condensed combined income statements for the year ended December 31, 2011 and for the six months ended June 30, 2012 have been adjusted to reflect the following items as though the Eagle Energy Acquisition and related transactions had occurred on January 1, 2011:

•

the revenues and direct operating expenses related the Eagle Energy Acquisition;

•

the depreciation, depletion, amortization and asset retirement obligation accretion related to the Eagle Energy Acquisition under the full cost method of accounting;

•

the historical general and administrative expense associated with the Eagle Energy Acquisition; net of amounts expected to be capitalized to oil and gas properties;

•

the dividend associated with the Preferred Stock to be issued in connection with the Eagle Energy Acquisition;

•

the income tax effect of the adjustments outlined above.

The pro forma adjustments are based upon available information and certain assumptions that Midstates believes are reasonable as of the date of this Current Report on Form 8-K. The pro forma adjustments reflected herein are preliminary and based on management’s estimations and expectations about the accounting that is expected to take place. In particular, the accounting for the Eagle Energy Acquisition is complex and entails determining the fair values of assets acquired and liabilities assumed. The Eagle Energy Acquisition will be accounted for using the purchase method of accounting. Accordingly, the final purchase price allocation is pending the finalization of appraisal valuations of certain tangible and any intangible assets acquired, which may result in an adjustment to the preliminary purchase price allocation. Any such adjustments to the preliminary estimates of fair value could be material. Therefore, the actual adjustments will differ from the pro forma adjustments, and the differences may be material.

transactions at an earlier date or the results that may occur in the future. These unaudited pro forma condensed combined financial statements should be read in conjunction with the audited December 31, 2011 consolidated financial statements and notes thereto contained in Midstates’ Registration Statement on Form S-1, as amended (Registration No. 333-177966), the unaudited June 30, 2012 consolidated financial statements contained in Midstates’ quarterly report on Form 10-Q as filed with the SEC on August 14, 2012, Eagle Energy Company of Oklahoma, LLC’s audited consolidated financial statements as of and for the years ended December 31, 2011 and 2010 included as Exhibit 99.4 to this Form 8-K, and Eagle Energy Company of Oklahoma, LLC’s unaudited consolidated financial statements as of and for the six months ended June 30, 2012, included as Exhibit 99.5 to this Form 8-K.

Note 2. Assumptions and Adjustments

Unaudited Pro Forma Condensed Combined Balance Sheet as of June 30, 2012:

(i)	To record the preliminary purchase accounting assigned to the assets acquired and liabilities assumed with the Eagle Energy assets. The purchase price allocation is subject to change.

The fair value of the assets and liabilities acquired is described below:


Oil and gas properties	$	601,000
Hedges assumed—current		12,535
Hedges assumed—noncurrent		6,195
ARO assumed		(1,671	)

Total fair value of assets and liabilities acquired	$	618,059

The estimated fair value of the consideration to be transferred is described below:


Cash, with estimated purchase adjustments	$	355,000
Estimated fair value of Preferred Stock		263,059

Estimated fair value of consideration	$	618,059

(ii)	To record nonrecurring estimated expenses associated with the Eagle Energy Acquisition as well as commitment and other fees and expenses associated with the bridge funding commitment intended to be replaced by the notes offering.

(iii)

To record the issuance of $550 million of the notes and the related cash, net of approximately $15.0 million of offering costs and approximately $16.25 million related to the Eagle Energy Acquisition, the increase in our borrowing base from $200 million to $235 million and the increase in our borrowing base upon the closing of the Eagle Energy Acquisition from $235 million to $250 million. The net proceeds from this offering will be used to (1) pay the estimated cash portion of the purchase price of $355 million (including estimated closing adjustments and expenses related to the Transactions), (2) repay $151.7 million of our borrowings under our revolving credit facility and (3) for general corporate purposes.

(iv)	To record the estimated amortizable fees associated with the increase in our borrowing base from $200 million to $235 million and the fees associated with upsizing the borrowing base upon closing of the Eagle Energy Acquisition from $235 million to $250 million.

(v)	To record asset retirement obligation assumed from Eagle Energy.

Unaudited Pro Forma Condensed Combined Income Statement for the year ended December 31, 2011:

(vi)	To reflect the historical revenues and direct operating expenses related to Eagle Energy.

(vii)

To reflect depreciation, depletion, amortization and asset retirement obligation accretion expenses attributable to Eagle Energy.

(viii)

To adjust general and administrative expense for $5.1 million of additional expenses associated with Eagle Energy, net of amounts expected to be capitalized as directly attributable to oil and natural gas acquisition, exploration and development ($0.6 million).

(ix)

To record the 8% dividend, compounded semiannually, on 325,000 shares of Preferred Stock issued in connection with the Eagle Energy Acquisition. The 8% Preferred Stock dividend is payable in cash or through an increase in the liquidation preference. The shares of Preferred Stock have an initial liquidation value of $1,000 per share and are convertible into shares of common stock at $13.50 per share on the later of the 21st day after Midstates filing of a 14C Information Statement or the one year anniversary after issuance. The shares of Preferred Stock are mandatorily convertible into Midstates common stock on September 30, 2015 at a rate between $11.00 and $13.50 per common share, depending on Midstates average common stock price during the 15 trading days prior to the mandatory conversion date.

(x)

To reflect additional interest expense associated with this offering and to amortize $14.8 million in estimated offering expenses over an eight year period. Excluded from expenses is $7.9 million in estimated costs related to obtaining a bridge loan commitment in connection with the Eagle Energy Acquisition, as this amount is non-recurring. The interest expense is based upon a rate of 10.5% for the notes and is net of $23.5 million capitalized to unproved properties. A 0.125% increase in the notes’ actual interest rate would increase gross interest costs (before capitalization) by $687,500 per annum. Also includes amortization of $4.3 million of estimated fees and expenses related to the increase in Midstates borrowing base associated with its revolving credit facility from $200 million to $235 million and the upsizing of the borrowing base upon closing of the Eagle Energy Acquisition from $235 million to $250 million (five year amortization period).

(xi)	To adjust income tax expense for the impact of the adjustments outlined above at the estimated statutory rate (including state income taxes) of 40.2%.

(xii)

The weighted average shares assume Midstates completed its initial public offering on January 1, 2011. The Preferred Stock is considered participating securities for earnings per share purposes; however, these securities do not participate in undistributed net losses and therefore, do not impact weighted average shares outstanding. At a conversion price of $13.50, the conversion of the Preferred Stock would result in the issuance of 24,074,074 Midstates common shares before any increase in the liquidation preference.

Unaudited Pro Forma Condensed Combined Income Statement for the six months ended June 30, 2012:

(xiii)

To reflect the historical revenues and direct operating expenses related to Eagle Energy.

(xiv)

To reflect depreciation, depletion, amortization and asset retirement obligation accretion expenses attributable to Eagle Energy.

(xv)	To adjust general and administrative expense for $2.7 million of additional expenses associated with Eagle Energy, net of amounts expected to be capitalized as directly attributable to oil and natural gas acquisition, exploration and development ($0.3 million).

(xvi)

(xvii)

actual interest rate would increase gross interest costs (before capitalization) by $687,500 per annum. Also includes amortization of $4.3 million of estimated fees and expenses related to the increase in Midstates borrowing base associated with its revolving credit facility from $200 million to $235 million and the upsizing of the borrowing base upon closing of the Eagle Energy Acquisition from $235 million to $250 million (five year amortization period).

(xviii)

To adjust income tax expense for the impact of the adjustments outlined above at the estimated statutory rate (including state income taxes) of 40.2%.

(xix)

The Preferred Stock is considered participating securities for earnings per share purposes; however, these securities do not participate in undistributed net losses and therefore, do not impact weighted average shares outstanding. At a conversion price of $13.50, the conversion of the Preferred Stock would result in the issuance of 24,074,074 Midstates common shares before any increase in the liquidation preference.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

You should read the following selected financial data in conjunction with “Unaudited Pro Forma Financial Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and related notes thereto included elsewhere in this information statement. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable. The financial information included in this information statement may not be indicative of our future results of operations, financial position and cash flows.

Set forth below is our selected historical consolidated financial data (i) as of June 30, 2012 and for the six months ended June 30, 2012 and 2011, which has been derived from our unaudited condensed consolidated financial statements included elsewhere in this information statement; (ii) as of and for the years ended December 31, 2011, 2010 and 2009, which has been derived from our audited consolidated financial statements included elsewhere in this information statement, and as of and for the period from August 30, 2008 through December 31, 2008, which has been derived from our audited consolidated financial statements not included elsewhere in this information statement; (iii) for the period from January 1 to August 29, 2008 of Midstates Petroleum Corporation, our accounting predecessor, which has been derived from the audited financial statements of Midstates Petroleum Corporation not included elsewhere in this information statement; and (iv) as of and for the year ended December 31, 2007 of Midstates Petroleum Corporation, which has been derived from the unaudited consolidated financial statements of Midstates Petroleum Corporation not included elsewhere in this information statement.


	Successor																	Predecessor
	Six Months Ended June 30,					Year Ended December 31,									Period from August 30 to December 31, 2008			Period from January 1 to August 29, 2008			Year Ended December 31, 2007
	2012		2011			2011			2010			2009			Period from August 30 to December 31, 2008			Period from January 1 to August 29, 2008			Year Ended December 31, 2007
	(In thousands)																	(In thousands)
	(Unaudited)					(As restated) (1)															(unaudited)
Statement of operations data
Oil, gas and natural gas liquids revenues	$	109,140	$	95,828		$	213,812		$	89,111		$	30,133		$	8,689		$	27,458		$	14,647
Gains (losses) on commodity derivative contracts – net		23,478		(18,119	)		(4,844	)		(26,268	)		(5,987	)		14,062			(7,678	)		(5,363	)
Other revenue		207		114			465			209			108			43			113			234

Total revenues		132,825		77,823			209,433			63,052			24,254			22,794			19,893			9,518

Expenses:
Lease operating and workover (2)		12,388		6,275			16,117			12,861			10,328			3,918			4,975			3,731
Severance and other taxes (3)		11,648		9,495			13,640			6,986			3,059			805			2,354			1,258
Asset retirement accretion		298		86			334			175			120			37			79			113
General and administrative (4)		11,019		14,544			68,915			16,847			5,886			1,402			1,816			1,616
Depreciation, depletion and amortization		55,909		39,884			91,699			41,827			12,322			2,995			3,117			3,503
Impairment in carrying value of oil and gas properties		—		—			—			—			4,297			26,776			—			—

Total expenses		91,262		70,284			190,705			78,696			36,012			35,933			12,341			10,221

Income (loss) from operations		41,563		7,539			18,728			(15,644	)		(11,758	)		(13,139	)		7,552			(703	)


	Successor																		Predecessor
	Six Months Ended June 30,						Year Ended December 31,									Period from August 30 to December 31, 2008			Period from January 1 to August 29, 2008			Year Ended December 31, 2007
	2012			2011			2011			2010			2009			Period from August 30 to December 31, 2008			Period from January 1 to August 29, 2008			Year Ended December 31, 2007
	(In thousands)																		(In thousands)
	(Unaudited)						(As restated) (1)															(unaudited)
Other income (expense):
Interest income		150			12			23			9			6			7			12			34
Interest expense – net of amounts capitalized		(2,680	)		(134	)		(2,094	)		—			—			—			(854	)		(1,100	)

Total other income		(2,530	)		(122	)		(2,071	)		9			6			7			(842	)		(1,066	)

Income before taxes		39,033			7,417			16,657			(15,635	)		(11,752	)		(13,132	)		6,710			(1,769	)
Income tax expense		168,917			—			—			—			—			—			—			—

Net income (loss)	$	(129,884	)	$	7,417		$	16,657		$	(15,635	)	$	(11,752	)	$	(13,132	)	$	6,710		$	(1,769	)

(1)	See Note 11 to our Consolidated Financial Statements as of and for the year ended December 31, 2011.

(2)	Includes $1.5 million, $0.7 million, $2.1 million, $4.7 million, and $5.2 million in workover expense for the six months ended June 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009, respectively.

(3)	Includes $1.7 million, $0.4 million, $1.2 million, $0.6 million, and $0.2 million in ad valorem tax expense for the six months ended June 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009, respectively.

(4)	Includes $0.7 million, $7.9 million, $53.7 million, $1.5 million and $0.2 million in share-based compensation expense for the six months ended June 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009, respectively. See Note 7 to our Consolidated Financial Statements.


	Successor										Predecessor
	As of June 30, 2012		As of December 31,						As of December 31, 2008		As of December 31, 2007
	As of June 30, 2012		2011		2010		2009		As of December 31, 2008		As of December 31, 2007
	(In thousands)										(In thousands)
	(Unaudited)				(As restated) (1)						(unaudited)
Balance sheet data:
Cash and cash equivalents	$	11,689	$	7,344	$	11,917	$	4,353	$	3,214	$	1,000
Net property and equipment		726,188		574,079		397,126		271,726		209,939		30,640
Total assets		791,235		624,656		427,004		284,034		222,074		35,447
Long-term debt		151,700		234,800		89,600		29,800		21,800		20,100
Total members’/stockholders’ equity		370,139		285,502		255,879		235,334		192,006		2,510

(1)	See Note 11 to our Consolidated Financial Statements as of and for the year ended December 31, 2011.


	Successor																		Predecessor
	Six Months Ended June 30,						Year Ended December 31,									Period from August 30 to December 31, 2008			Period from January 1 to August 29, 2008			Year Ended December 31, 2007
	2012			2011			2011			2010			2009			Period from August 30 to December 31, 2008			Period from January 1 to August 29, 2008			Year Ended December 31, 2007
	(In thousands)																		(In thousands)
	(Unaudited)									(As restated) (1)												(unaudited)
Other financial data:
Net cash provided by operating activities	$	59,963		$	66,984		$	140,700		$	50,768		$	10,595		$	3,670		$	10,046		$	7,429
Net cash used in investing activities		(184,245	)		(102,302	)		(242,771	)		(139,618	)		(75,215	)		(5,451	)		(9,480	)		(15,709	)
Net cash provided by financing activities		128,627			33,856			97,498			96,414			65,759			4,995			1,792			8,275

(1)	See Note 11 to our Consolidated Financial Statements as of and for the year ended December 31, 2011.

ACTION BY WRITTEN CONSENT

Issuance of Shares of Our Common Stock Upon Conversion of Our Preferred Stock

On August 11, 2012, we entered into the Acquisition Agreement with Eagle Energy pursuant to which we agreed to issue to Eagle Energy 325,000 shares of the Preferred Stock with an initial liquidation preference of $1,000 per share as part of the consideration for the Eagle Energy Acquisition. The Preferred Stock will only become convertible into Common Stock beginning on the 21st calendar day after we mail this information statement to our stockholders, and the holders of the Preferred Stock may not convert their shares of Preferred Stock before the first anniversary of the closing date of the transaction, which is expected to occur on or about October 1, 2012. After such time, the Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Preferred Stock, into a number of shares of our Common Stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. Each share of Preferred Stock is mandatorily convertible into Common Stock on September 30, 2015 at a price of no greater than $13.50 per share and no less than $11.00 per share, or a maximum of 37,384,426 shares of our Common Stock in the aggregate assuming a conversion price of $11.00 and that all dividends are paid in kind until the mandatory conversion date, which would represent approximately 56% of our Common Stock outstanding on September 26, 2012.

Because our Common Stock is currently listed on the New York Stock Exchange and we are therefore subject to Section 312.03 of the Listed Company Manual, we must obtain stockholder approval before issuing Common Stock, or securities convertible into Common Stock, in any transaction or series of related transactions, if (i) the Common Stock has, or will have upon issuance, voting power equal to 20% or more of the voting power outstanding before the issuance of such stock or securities convertible into Common Stock or (ii) the number of shares of Common Stock to be issued is, or will be upon issuance, equal to 20% or more of the number of shares of Common Stock outstanding before the issuance of the Common Stock or securities convertible into Common Stock. Pursuant to Section 228 of the General Corporation Law of the State of Delaware, our Amended and Restated Certificate of Incorporation and our Bylaws, the written consent of the holders of shares of our outstanding capital stock, having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted, may be substituted for such meeting. On August 11, 2012, the holders of 36,121,546 shares of Common Stock, representing a majority of our then-outstanding voting power, approved by written consent the issuance of the Preferred Stock and the Common Stock upon conversion of the Preferred Stock (the “Written Consent”).

No Further Stockholder Action Needed

As a result of the Written Consent, stockholder approval of the issuance of the Preferred Stock and the Common Stock issuable upon conversion of the Preferred Stock has been obtained. We were not required under the General Corporation Law of the State of Delaware, our Amended and Restated Certificate of Incorporation or our Bylaws to obtain stockholder approval to issue the Preferred Stock. Accordingly, all necessary corporate approvals in connection with the matters referred to herein have been obtained and no further votes will be needed. The Preferred Stock will not become convertible into shares of Common Stock until the 21st day after the date on which we mail this information statement to our stockholders. Our board of directors does not intend to solicit any proxies or consents in connection with the foregoing actions.

This information statement is furnished solely for the purpose of informing stockholders regarding the actions taken by Written Consent and is being provided pursuant to the requirements of Rule 14c-2 promulgated under Section 13 of the Exchange Act.

THE EAGLE ENERGY ACQUISITION

As part of our strategy to increase our position in onshore basins in North America, we entered into the Acquisition Agreement on August 11, 2012. Pursuant to the Acquisition Agreement, we agreed to acquire certain interests in producing oil and natural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments. The aggregate purchase price, subject to adjustment as provided in the Acquisition Agreement, consists of (i) $325,000,000 in cash and (ii) 325,000 shares of our Preferred Stock with an initial liquidation preference of $1,000 per share. The Eagle Energy Acquisition will be effective June 1, 2012 and is expected to close on or about October 1, 2012, subject to customary closing conditions.

Eagle Energy is an independent energy company focused on exploration and development of oil and natural gas properties, with a focus on the Mississippian Lime formation in northwestern Oklahoma and southern Kansas. Eagle Energy was founded in 2009 and is headquartered in Tulsa, Oklahoma.

We believe Eagle Energy represents both a strategic and transformative acquisition for us. We believe the properties we are acquiring are in a market-recognized, horizontal oil play with a well understood geology. The Mississippian Lime has thousands of industry vertical wells with decades of production history and approximately 500 industry horizontal wells in the region. We believe the play has attractive economics, which are supported by high oil and NGLs content and competitive drilling and completion costs attributable to the relatively shallow nature of this carbonate-rich formation. The Eagle Energy Acquisition also increases our geographical diversification and scale by adding a new core area with approximately 600 gross potential oil- and liquids-weighted drilling locations and substantially increases our proved reserves and extends our reserve life. Furthermore, we believe that Eagle Energy complements our existing geological and operational profile. We expect that key members of Eagle Energy’s management will remain with the company for a year to assist us with the transaction. In addition, Eagle Energy executives are bound by a one year no solicitation agreement with respect to Eagle Energy employees.

Eagle Energy was an early mover in the Mississippian Lime, with a majority of its acreage residing in the core of the play in Woods County and Alfalfa County in northwestern Oklahoma. As of August 1, 2012, Eagle Energy had approximately 82,000 net acres prospective in the Mississippian Lime with 76,000 net acres in Woods and Alfalfa Counties, Oklahoma and 6,000 net acres in Kansas, in which the company held an average working interest of approximately 73%. Eagle Energy also had approximately 15,000 net acres in the Hunton formation in Lincoln County, Oklahoma. Eagle Energy’s underlying properties produced approximately 7,000 Boe/d as of August 10, 2012. NSAI, Eagle Energy’s independent reserve engineers, estimated the company’s net proved reserves to be 25.1 MMBoe as of December 31, 2011, 59% of which were comprised of oil and NGLs.

The Mississippian Lime is an expansive carbonate hydrocarbon system located on the Anadarko Shelf. The top of the formation is encountered between 4,000 feet and 7,000 feet. The Mississippian formation can reach 1,000 feet in gross thickness and the targeted porosity zone is between 50 and 100 feet in thickness. The formation had been historically developed utilizing vertical wellbores dating back to the 1940’s. In 2007, the application of horizontal drilling and multi-stage hydraulic fracturing demonstrated the potential for extracting significant additional quantities of oil, natural gas and NGLs from the formation. Since the beginning of 2009, there have been approximately 500 horizontal wells drilled in the Mississippian formation in northern Oklahoma and southern Kansas, including the 60 wells drilled by Eagle Energy. While horizontal wells are more expensive than vertical wells, a horizontal wellbore increases the production of hydrocarbons and adds significant recoverable reserves per well at a more competitive return on investment than vertical wells. With data collected from the thousands of vertical and horizontal wells that have been drilled by Eagle Energy and other operators in the region, we are better able to understand the permeability and porosity of the underlying rock properties, the amount of recoverable oil, natural gas and NGLs, and how to best identify productive reservoirs and potential horizontal well locations.

We believe Eagle Energy possesses the following competitive advantages:

•

early mover in the Mississippian Lime, with a majority of its acreage in the core of the play;

•

strong current cash flow with material untapped growth;

•

top quartile well results with recent initial projections in the 400 Boe/d to 1,460 Boe/d range; and

•

low cost producer with established and growing infrastructure.

For the year ended December 31, 2011 and the six months ended June, 30, 2012, Eagle Energy had net income of $23.6 million and a net loss of $1.8 million, respectively, and cash provided by operating activities of $48.8 million and $26.8 million, respectively.

We intend to fund the cash portion of the purchase price for, and expenses related to, the Eagle Energy Acquisition with the net proceeds from the issuance and sale by us and Midstates Sub of $550 million aggregate principal amount of senior unsecured notes or, if such sale is not completed, the entrance by us and Midstates Sub into a $500 million bridge credit facility and, in either case, the use of proceeds therefrom. The completion of such notes offering or entrance into the bridge credit facility is not a condition to the closing of the Eagle Energy Acquisition.

We and Eagle Energy have made customary representations, warranties and covenants in the Acquisition Agreement. Eagle Energy has made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Acquisition Agreement and the closing of the Eagle Energy Acquisition and not to engage in certain kinds of transactions during that period, subject to certain exceptions. We have agreed not to take certain specified actions without Eagle Energy’s consent during the time between execution of the Acquisition Agreement and the closing of the Eagle Energy Acquisition.

Consummation of the Eagle Energy Acquisition is subject to various conditions, including, among others, (1) the accuracy of representations and warranties of the parties as of the closing date, including the absence of any material adverse effect with respect to each of Eagle Energy’s business and our business, (2) the release of certain liens in connection with the repayment of Eagle Energy’s indebtedness, (3) the execution of certain ancillary documents and (4) other customary closing conditions.

The Acquisition Agreement contains certain customary termination rights for both us and Eagle Energy, including, among others, the right of either party to terminate the Acquisition Agreement if, subject to certain exceptions, the Eagle Energy Acquisition is not consummated by November 30, 2012. In the event either party terminates the Acquisition Agreement because of a breach by the other party of any of its obligations, representations, warranties, agreements or covenants, the breaching party may be liable for any and all damages of the terminating party arising from such breach. In addition, in the event of a willful and material breach of the Acquisition Agreement that results in the failure of a closing condition, the terminating party may elect to collect $65 million from the breaching party in lieu of pursuing actual damages.

The Preferred Stock will not become convertible into shares of our Common Stock until the 21st day after the date on which we mail this information statement to our stockholders, and the holders of the Preferred Stock may not convert their shares of Preferred Stock before the first anniversary of the closing date of the Eagle Energy Acquisition. After such time, the Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Preferred Stock, into a number of shares of our Common Stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. In addition, the Preferred Stock will be subject to mandatory conversion into shares of our Common Stock on September 30, 2015 at a conversion price no greater than $13.50 per share and no less than $11.00 per share. Dividends on the Preferred Stock will accrue at a rate of 8.0% per annum, payable semi-annually, at our sole option, in cash or through an increase in the liquidation preference. The Preferred Stock will also have the other

rights and terms set forth on the Certificate of Designation, including voting rights that are similar to those belonging to holders of our Common Stock on an as-converted basis (except with respect to the election of directors and the approval of certain transactions where the holders of the Preferred Stock would be entitled to consideration at least equal to the liquidation preference) until such time as holders of the Preferred Stock are permitted to convert their shares into Common Stock and the market price of our Common Stock is above $13.50 per share for 15 consecutive trading days. In addition, the holders of the Preferred Stock will have the right, subject to the terms and conditions set forth in the Certificate of Designations, to elect one member of the board of directors, and to approve certain corporate actions. The Preferred Stock will rank senior to our Common Stock with respect to dividend rights. The issuance of the Preferred Stock to Eagle Energy pursuant to the Acquisition Agreement has been approved by stockholders holding a majority of the outstanding shares of our Common Stock.

You should carefully review the audited and unaudited consolidated financial statements for Eagle Energy and the notes related thereto and our unaudited pro forma consolidated financial statements and the notes related thereto contained in this information statement.

For additional information about the terms of our shares of Preferred Stock and other outstanding stock, see “Description of Capital Stock.” For additional information about the terms of the registration rights agreement applicable to the shares of Common Stock issued upon conversion of the Preferred Stock, see “Registration Rights.”

Other Transactions

In connection with the consummation of the Eagle Energy Acquisition, we anticipate entering into the following additional transactions:

•

entry into the Credit Agreement Amendment to, among other things, increase the borrowing capacity under our revolving credit facility from $200 million to $250 million, subject to the satisfaction of certain conditions.

For additional information about the terms of the bridge credit facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Potential Bridge Credit Facility.” For additional information about the terms of the revolving credit facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Reserve-based Credit Facility.”

BACKGROUND OF THE TRANSACTION

Reasons for the Action Taken

Please read “The Eagle Energy Acquisition” above.

As partial consideration for the Eagle Energy Acquisition, we will issue to Eagle Energy 325,000 shares of Preferred Stock with an initial liquidation preference of $1,000 per share.

Effects of the Proposed Issuance

The issuance of a significant amount of Common Stock upon conversion of the Preferred Stock may adversely affect the price of the Common Stock. We have agreed to enter into a registration rights agreement in connection with the issuance of the Preferred Stock to permit the public resale of the shares of Common Stock underlying the Preferred Stock. The influx of such a substantial number of common shares into the public market could have a significant negative effect on the trading price of the Common Stock. As of September 26, 2012, approximately [ ] million shares of Common Stock were outstanding. An additional approximate 37.4 million shares of Common Stock will be outstanding upon automatic conversion of the outstanding Preferred Stock, assuming a conversion price of $11.00 per share and dividends are paid through an increase in the liquidation preference of the Preferred Stock until the mandatory conversion date. Issuance of these shares of Common Stock may substantially dilute the ownership interests of our existing stockholders. The potential issuance of such additional shares of Common Stock may create downward pressure on the trading price of our Common Stock. In recent years, broad stock market indices, in general, and smaller capitalization companies, in particular, have experienced substantial price fluctuations, and, since our initial public offering in April 2012, we have experienced wide fluctuations and a decline in the market price of our Common Stock.

Before the Preferred Stock becomes convertible into Common Stock, it will be entitled to 19.9% of the total voting power outstanding. After the Preferred Stock becomes convertible into Common Stock, it will vote with the Common Stock on an as-converted basis on all matters submitted to the holders of the Common Stock (except with respect to the election of directors and the approval of certain transactions where the holders of the Preferred Stock would be entitled to consideration at least equal to the liquidation preference) until the first anniversary of the date of issuance and the price of our Common Stock has been above $13.50 per share for at least 15 consecutive trading days. While the Preferred Stock has such voting power, Riverstone Holdings, LLC (“Riverstone”), which controls Eagle Energy, will have significant influence over our operations. In addition, for so long as at least 75% of the Preferred Stock is held by Riverstone and its affiliates, holders of the Preferred Stock, voting as a single class, will be entitled to elect one member of our board of directors, who must be an employee of Riverstone or one of its affiliates. The terms of the Preferred Stock also prohibit us from engaging in certain transactions without the consent of the holders of a majority of the Preferred Stock, including the following actions:

•

the creation or issuance of any class of capital stock senior to or on parity with the Preferred Stock;

•

the redemption, acquisition or purchase by us of any of our equity securities, other than a repurchase from an employee or director in connection with such person’s termination or as provided in the agreement pursuant to which such equity securities were issued;

•

any change to our certificate of incorporation or bylaws that adversely affects the rights, preferences, privileges or voting rights of the holders of the Preferred Stock;

•

acquisitions or dispositions for which the amount of consideration exceeds 20% of our market capitalization in any single transaction or 40% of our market capitalization for any series of transactions during a calendar year;

•

entering into certain transactions with affiliates, other than transactions that do not exceed, in the aggregate, $10 million in any calendar year;

•

certain corporate transactions unless the holders of the Preferred Stock would receive consideration consisting solely of cash and/or marketable securities with an aggregate fair market value equal to or greater than the liquidation preference on such shares of Preferred Stock; and

•

any increase or decrease in the size of our board of directors.

As a result of Riverstone’s equity ownership or voting power, director nominee and consent rights, our ability to engage in financing transactions or other significant transactions, such as a merger, acquisition, disposition or liquidation, may be limited. In connection with such transactions, conflicts of interest could arise between us and Riverstone, and any conflict of interest may be resolved in a manner that does not favor us.

No Dissenter’s Rights

The corporate action described in this information statement will not afford to stockholders the opportunity to dissent from the actions described herein or to receive an agreed or judicially appraised value for their shares.

Interest of Certain Persons in the Action Taken

No person who has been an officer or director of Midstates since January 1, 2012, nor any associate of such person, has any substantial interest by security holding or otherwise in the issuance of the shares of Common Stock underlying the shares of the Preferred Stock.

THE ACQUISITION AGREEMENT

Upon the consummation of the Eagle Energy Acquisition, we will acquire certain interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and the related hedging instruments from Eagle Energy for $325 million in cash and 325,000 shares of Preferred Stock. The cash purchase price that we will pay is subject to adjustments as described in the Acquisition Agreement.

We, Eagle Energy and Midstates Sub have made customary representations, warranties and covenants in the Acquisition Agreement. Eagle Energy has made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Agreement and the closing of the Eagle Energy Acquisition and not to engage in certain kinds of transactions during that period, subject to certain exceptions. We have agreed not to take certain specified actions without Eagle Energy’s consent during the time between execution of the Acquisition Agreement and the closing of the Eagle Energy Acquisition.

This summary of the material terms of the Acquisition Agreement is qualified in its entirety by reference to the Acquisition Agreement, which is attached as Annex A to this information statement and is incorporated herein by reference.

The Parties to the Acquisition Agreement

Midstates Petroleum Company, Inc.

4400 Post Oak Parkway, Suite 1900

Houston, Texas 77027

(713) 595-9400

We are an independent exploration and production company focused on the development of oil-prone resources in the Upper Gulf Coast Tertiary trend onshore in central Louisiana. Our current acreage positions and evaluation efforts are concentrated in the Wilcox interval of the trend. We are currently focused on the development of our inventory of identified drilling locations, which we will selectively allocate capital to by applying rigorous investment analysis in an effort to maximize our potential returns. We are focused on maximizing the net present value of our drilling opportunities by measuring risk and financial return, among other factors. In addition, we are the operator of the substantial majority of our properties, which enables us to better control timing, costs and drilling and completion techniques.

We were incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC, a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. Pursuant to the terms of a corporate reorganization that was completed immediately prior to the closing of our initial public offering on April 25, 2012, all of the interests in Midstates Petroleum Holdings LLC were exchanged for our newly issued common shares, and as a result, Midstates Petroleum Company LLC became our wholly-owned subsidiary.

Eagle Energy Production, LLC

200 Reunion Center

9 East 4th Street

Tulsa, Oklahoma 74103

(918) 746-1350

Midstates Petroleum Company LLC

4400 Post Oak Parkway, Suite 1900

Houston, Texas 77027

(713) 595-9400

Midstates Sub is our wholly owned subsidiary and our main operating company.

Accounting Treatment

In accordance with accounting principles generally accepted in the United States and in accordance with the Financial Accounting Standards Board’s Accounting Standards Codification Topic 805-Business Combinations, we will account for the Eagle Energy Acquisition as an acquisition of a business and as such, the results of operations of the Eagle Energy Assets subsequent to the closing date of the Eagle Energy Acquisition will be included in our results of operations and the assets acquired and the liabilities assumed in the Eagle Energy Acquisition will be recorded at their respective estimated fair values at the same date. Any excess of the total purchase price over the fair value of the identifiable tangible and intangible assets acquired and liabilities assumed will be recorded as goodwill.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information regarding the beneficial ownership of our Common Stock as of September 6, 2012 by:

•

each person to be known by us to be the beneficial owner of more than 5% of our outstanding shares of Common Stock;

•

each of our named executive officers;

•

each of our directors; and

•

all of our current executive officers and directors as a group.

Except as otherwise indicated, the person or entities listed below have sole voting and investment power with respect to all shares of our Common Stock beneficially owned by them, except to the extent this power may be shared with a spouse. All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more stockholders, as the case may be. Unless otherwise indicated, the address of each person or entity named in the table below is 4400 Post Oak Parkway, Suite 1900, Houston, Texas 77027.

As of September 6, 2012, approximately 66,535,256 million shares of our Common Stock were outstanding.


NAME AND ADDRESS OF BENEFICIAL OWNER	Shares Beneficially Owned		Percentage
FR Midstates Interholding, LP (1)		27,147,651		40.80	%
Stephen J. McDaniel		4,455,627		6.70	%
John A. Crum		861,301		1.29	%
Thomas L. Mitchell		290,399			*
Alex T. Krueger (2)		—		—
Anastasia Deulina (2)		—		—
John Mogford (2)		—		—
Mary P. Ricciardello		9,615			*
Loren M. Leiker		9,615			*
Stephen C. Pugh		244,245			*
John P. Foley		602,737			*
All directors and executive officers as a group (10 persons)		33,621,190		50.53	%

(1)

FR Midstates Interholding, L.P.’s general partner is FR XII Alternative GP, L.L.C. FR XII Alternative GP, L.L.C.’s managing member is First Reserve GP XII, L.P. The general partner of First Reserve GP XII, L.P. is First Reserve GP XII Limited. William E. Macaulay is a director of First Reserve GP XII Limited and has the right to appoint the majority of the board of directors of First Reserve GP XII Limited.

(2)

Messrs Krueger and Mogford are managing directors, and Ms. Deulina is a non-executive director, of First Reserve Management Limited, an affiliate of FR Midstates Interholding, L.P. Each of Messrs Krueger and Mogford and Ms. Deulina disclaim beneficial ownership of the shares that relate to and are described in footnote 3 above. The address of each of the persons mentioned in this paragraph is One Lafayette Place, Greenwich, Connecticut 06830.

DESCRIPTION OF CAPITAL STOCK

The authorized capital stock of Midstates consists of 300,000,000 shares of Common Stock and 50,000,000 shares of preferred stock of which no shares are issued and outstanding.

The following summary of the capital stock and Amended and Restated Certificate of Incorporation and Bylaws of Midstates does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our Amended and Restated Certificate of Incorporation and Bylaws.

Common Stock

Except as provided by law or in a preferred stock designation, holders of Common Stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of Common Stock are not entitled to vote on any amendment to the Amended and Restated Certificate of Incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to the Amended and Restated Certificate of Incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the DGCL. Subject to prior rights and preferences that may be applicable to any outstanding shares or series of preferred stock, holders of Common Stock are entitled to receive ratably in proportion to the shares of Common Stock held by them such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of Common Stock are fully paid and non-assessable, and the shares of Common Stock to be issued upon completion of this offering will be fully paid and non-assessable. The holders of Common Stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to the Common Stock. In the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs, holders of Common Stock will be entitled to share ratably in our assets in proportion to the shares of Common Stock held by then that are remaining after payment or provision for payment of all of our debts and obligations and after distribution in full of preferential amounts to be distributed to holders of outstanding shares of preferred stock, if any.

Preferred Stock

Our Amended and Restated Certificate of Incorporation authorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Series A Mandatorily Convertible Preferred Stock

Optional Conversion. The Preferred Stock will not become convertible into shares of our Common Stock until the 21st day after the date on which we mail to our stockholders this information statement regarding the issuance of the Preferred Stock, and the holders of the Preferred Stock may not convert before the first anniversary of the closing date of the Eagle Energy Acquisition. After such time, the Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Preferred Stock, into a number of shares of our Common Stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share.

Mandatory Conversion. The Preferred Stock will be subject to mandatory conversion into shares of our Common Stock on September 30, 2015 at a conversion price no greater than $13.50 per share and no less than $11.00 per share.

Dividend Rights. Dividends on the Preferred Stock will accrue at a rate of 8.0% per annum, payable semi-annually, at our sole option, in cash or through an increase in the liquidation preference.

Voting Rights. The Preferred Stock will also have the other rights and terms set forth on the Certificate of Designations, including voting rights that are similar to those belonging to holders of our Common Stock on an as-converted basis (except with respect to the election of directors and the approval of certain transactions where the holders of the Preferred Stock would be entitled to consideration at least equal to the liquidation preference) until such time as holders of the Preferred Stock are permitted to convert their shares into Common Stock and the market price of our Common Stock is above $13.50 per share for 15 consecutive trading days. In addition, the holders of the Preferred Stock will have the right, subject to the terms and conditions set forth in the Certificate of Designations, to elect one member of the board of directors, and to approve certain corporate actions.

Ranking. The Preferred Stock will rank senior to our Common Stock with respect to dividend rights.

Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation, our Bylaws and Delaware Law

Some provisions of Delaware law, and our Amended and Restated Certificate of Incorporation and our Bylaws described below, will contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise; or removal of our incumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Delaware Law

We will not be subject to the provisions of Section 203 of the DGCL, regulating corporate takeovers. In general, those provisions prohibit a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

•

the transaction is approved by the board of directors before the date the interested stockholder attained that status;

•

upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

•

on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Amended and Restated Certificate of Incorporation and Bylaws

Provisions of our Amended and Restated Certificate of Incorporation and Bylaws may delay or discourage transactions involving an actual or potential change in control or change in our management, including transactions in which stockholders might otherwise receive a premium for their shares, or transactions that our stockholders might otherwise deem to be in their best interests. Therefore, these provisions could adversely affect the price of our Common Stock.

Among other things, our Amended and Restated Certificate of Incorporation and Bylaws:

•

permit our board of directors to issue up to 50,000,000 shares of preferred stock, with any rights, preferences and privileges as they may designate;

•

provide that the authorized number of directors may be changed only by resolution of the board of directors;

•

at any time after the earlier of the date that (i) funds affiliated with First Reserve Management, L.P. (“First Reserve”) no longer own more than 25% of our Common Stock or (ii) First Reserve declares that a Trigger Date (as defined in our Amended and Restated Certificate of Incorporation and our Bylaws) has occurred:

•

provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of Common Stock having not less than the minimum number of votes that would be necessary to authorize such action at a meeting);

•

provide that all vacancies, including newly created directorships, may, except as otherwise required by law, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (prior to such time, vacancies may also be filled by the affirmative vote of the holders of a majority of our then outstanding Common Stock);

•

provide that our Bylaws may only be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding Common Stock (prior to such time, our Bylaws may be amended by the affirmative vote of the holders of a majority of our then outstanding Common Stock); and

•

provide that special meetings of our stockholders may only be called by the board of directors, the chief executive officer or the chairman of the board or the board of directors (prior to such time, a special meeting may also be called at the request of stockholders holding 25% of the outstanding shares entitled to vote);

•

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors which may be elected by holders of preferred stock, if any. This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors;

•

provide that we renounce any interest in the business opportunities of First Reserve and of our directors who are affiliated with First Reserve, other than directors employed by us, and that neither our directors affiliated with First Reserve, other than directors employed by us, nor First Reserve, have any obligation to offer us those opportunities;

•

eliminate the personal liability of our directors for monetary damages resulting from breaches of their fiduciary duty to the extent permitted by the DGCL and indemnify our directors and officers to the fullest extent permitted by Section 145 of the DGCL;

•

provide that stockholders seeking to present proposals before a meeting of stockholders or to nominate candidates for election as directors at a meeting of stockholders must provide notice in writing in a timely manner, and also specify requirements as to the form and content of a stockholder’s notice; and

•

not provide for cumulative voting rights, therefore allowing the holders of a majority of the shares of Common Stock entitled to vote in any election of directors to elect all of the directors standing for election, if they should so choose.

Limitation of Liability and Indemnification Matters

Our Amended and Restated Certificate of Incorporation limits the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

•

for any breach of their duty of loyalty to us or our stockholders;

•

for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

•

for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

•

for any transaction from which the director derived an improper personal benefit.

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our Amended and Restated Certificate of Incorporation and Bylaws also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our Amended and Restated Certificate of Incorporation and Bylaws also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision in our Amended and Restated Certificate of Incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

Transfer Agent and Registrar

The transfer agent and registrar for our Common Stock and the Preferred Stock is American Stock Transfer & Trust Company, LLC.

Listing

Our Common Stock is listed on the NYSE under the symbol “MPO.” The Preferred Stock will not be listed on any securities exchange.

REGISTRATION RIGHTS

In connection with the closing of the Eagle Energy Acquisition, we expect to enter into a registration rights agreement (the “Registration Rights Agreement”) with Eagle Energy, FRMI, Mr. McDaniel (the Chairman of our board), Mrs. McDaniel, our executive officers and certain other members of our management team. Pursuant to the Registration Rights Agreement, we have agreed to register the sale of shares of our Common Stock under the circumstances described below.

Demand Registration Rights. If we receive from (i) Eagle Energy, at any time after the conversion of the Preferred Stock into Common Stock in accordance with the Certificate of Designations, or (ii) First Reserve, at any time after October 25, 2012, a written request to file a registration statement with respect to the holders’ shares, then we shall, within five business days of receipt thereof, use commercially reasonable efforts to effect registration under the Securities Act of the sale of all shares that the holders request to be registered. We are required to provide notice of the demand request within 30 days following receipt of such demand request to all holders party to the Registration Rights Agreement. The holders have the right to cause up to an aggregate of twelve such demand registrations, provided neither Eagle Energy nor First Reserve, acting individually, may make more than six. In no event shall more than one demand registration occur within three months after the effective date of a registration statement filed pursuant to a demand request or within 60 days prior to our good faith estimate of the date of an offering and 180 days after the effective date of a registration statement we file. Further, we are not obligated to effect any demand registration in which the anticipated aggregate offering price included in such offering is equal to or less than $50,000,000. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. If we are a well-known seasoned issuer, any such demand registration may be for an automatic shelf registration statement.

Piggy-back Registration Rights. If, at any time, we propose to register an offering of Common Stock (subject to certain exceptions) for our own account, then we must give prompt notice to all holders party to the Registration Rights Agreement to allow them to include a specified number of their shares in that registration statement or offering.

Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our registration obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective. The obligations to register shares under the Registration Rights Agreement will terminate when no registrable shares remains outstanding. Registrable shares means (A) all outstanding shares of Common Stock other than shares (i) sold pursuant to an effective registration statement under the Securities Act, (ii) sold in a transaction exempt from registration under the Securities Act (including transactions pursuant to Rule 144), or (iii) that can be sold without volume limitations within 90 days under Rule 144 and (B) any (a) Common Stock issued and outstanding as a result of any conversion of the Preferred Stock or (b) Common Stock issued or issuable directly or indirectly with respect to the Common Stock referred to in clause (a) above by way of stock dividend or stock split or in connection with a combination of shares, recapitalization, reclassification, merger, consolidation or other reorganization.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this information statement. The following discussion contains “forward-looking statements” that are based on management’s current expectations, estimates and projections about our business and operations, and involves risks and uncertainties. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under “Forward-Looking Statements” and elsewhere in this information statement. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” has been revised for the effects of the restatement of our consolidated financial statements. See Note 11 to our Consolidated Financial Statements as of and for the year ended December 31, 2011.

Overview

We are an independent exploration and production company focused on the development of oil-prone resources in the Upper Gulf Coast Tertiary trend onshore in central Louisiana. Our current acreage positions and evaluation efforts are concentrated in the Wilcox interval of the trend. We are currently focused on the development of our significant inventory of identified drilling locations, to which we will selectively allocate capital by applying rigorous investment analysis in an effort to maximize our potential returns. We are focused on maximizing the net present value of our drilling opportunities by measuring risk and financial return, among other factors. In addition, we are the operator of the substantial majority of our properties, which enables us to better control timing, costs and drilling and completion techniques. As of June 30, 2012, our properties consisted of approximately 121 gross active producing wells, 95% of which we operate, and in which we held an average working interest of approximately 97% across our 103,400 net acre leasehold.

As of December 31, 2011, our estimated net proved reserves were 26.2 MMBoe, of which 75% was oil or NGLs and 43% was proved developed. During the six months ended June 30, 2012, our properties had aggregate average net daily production of approximately 8,090 Boe/d.

All of our growth has been driven through the development of our leasehold acreage. We initiated operations in 1993 in our North Cowards Gully project area and slowly aggregated leasehold acreage in that project area and others over the next eighteen years. In August 2008, First Reserve acquired a majority interest in us and, along with members of our senior management, provided a significant amount of growth capital to expand our exploration and development program. As a result of this increase in capital available for our operations, we have increased our average daily production at a compound annual growth rate of 82% from 995 Boe/d in the year ended December 31, 2008 to 8,090 Boe/d in the six months ended June 30, 2012. Our current activities are focused on evaluating and developing our asset base, optimizing our acreage position, and identifying potential expansion areas across the trend.

During the three and six months ended June 30, 2012, our average daily production was 7,904 Boe/d and 8,090 Boe/d, respectively. Our average daily production for the three months ended June 30, 2012 was below our average for the first quarter of 8,275 Boe/d. Oil production increased by approximately 10%, while natural gas and NGLs decreased approximately 21%, primarily due to continued severe declines on two higher GOR wells in our Central Fault Block area of South Bearhead Creek. Results that were below expectations from recent West Gordon wells and unplanned downtime were responsible for lower than projected volumes, which will be described in further detail below. We have revised our drilling plan for the remainder of 2012 to increase focus on the Pine Prairie project area while we continue to analyze the results of our drilling programs in the other areas.

As part of our strategy to increase our position in onshore basins in North America, we entered into an asset purchase agreement with Eagle Energy on August 11, 2012. Pursuant to the Acquisition Agreement, we agreed to acquire certain interests in producing oil and natural gas assets and unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments. The aggregate purchase price, subject to adjustment as provided in the Acquisition Agreement, consists of (i) $325,000,000 in cash and (ii) 325,000 shares of our Preferred Stock with an initial liquidation preference of $1,000 per share. The Eagle Energy Acquisition will be effective June 1, 2012 and is expected to close on or about October 1, 2012, subject to customary closing conditions.

In connection with the consummation of the Eagle Energy Acquisition, we anticipate entering into the following additional transactions:

•

the issuance and sale by us of $550 million aggregate principal amount of senior unsecured notes or, if such sale is not completed, the entrance by us into a $500 million bridge credit facility and, in either case, the use of proceeds therefrom to fund the cash portion of the purchase price of the Eagle Energy Acquisition and the expenses relating thereto and to repay a portion of the outstanding borrowings under our revolving credit facility; and

•

Factors that Significantly Affect our Results

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments, as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We generally hedge a portion of our expected future oil and gas production to reduce our exposure to fluctuations in commodity price. By removing a portion of commodity price volatility, we expect to reduce some of the variability in our cash flow from operations. See “Liquidity and Capital Resources—Commodity Derivative Contracts” and “Quantitative and Qualitative Disclosures About Market Risk—Commodity price exposure” for discussion of our hedging and hedge positions.

Like all businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from any given well is expected to decline. As a result, oil and natural gas exploration and production companies deplete their asset base with each unit of oil or natural gas they produce. We attempt to overcome this natural production decline by developing additional reserves through our drilling operations, acquiring additional reserves and production and implementing secondary recovery techniques. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production. We will maintain our focus on the capital investments necessary to produce our reserves as well as to add to our reserves through drilling and acquisition. Our ability to make the necessary capital expenditures is dependent on cash flow from operations as well as our ability to obtain additional debt and equity financing. That ability can be limited by many factors, including the cost of such capital and operational considerations.

The volumes of oil and natural gas that we produce are driven by several factors, including:

•

success in the drilling of new wells, including exploratory wells, and the recompletion of existing wells;

•

the amount of capital we invest in the leasing and development of our oil and natural gas properties;

•

facility or equipment availability and unexpected downtime;

•

delays imposed by or resulting from compliance with regulatory requirements; and

•

the rate at which production volumes on our wells naturally decline.

The following table sets forth summary data with respect to our production volumes for the periods presented:


	Six Months Ended June 30,				Year Ended December 31,
	2012		2011		2011		2010		2009
Production data:
Oil (MBbls)		852		753		1,610		945		497
Natural gas (MMcf)		2,369		1,924		4,918		2,253		690
Natural gas liquids (MBbls)		225		117		308		74		2
Oil equivalents (MBoe)		1,472		1,190		2,737		1,394		614
Average daily production (Boe/d)		8,090		6,577		7,499		3,820		1,682

Growth Drivers in 2012 and Beyond

We intend to drill and develop our current acreage position in the oil-prone portion of the Upper Gulf Coast Tertiary trend to maximize the value of our resource potential. We also plan to increase our leasehold position in the trend. We have identified an estimated 1,101 gross drilling locations on our current leased acreage position and on acreage we currently have under option that we believe will increase our reserves, production and cash flow. We have identified approximately 40 additional geologic structures throughout the trend that we believe have characteristics similar to our existing operating areas and we are actively pursuing the increase of our acreage position through leasing in these areas. In addition to increasing our acreage position through leasing, we may selectively pursue potential acquisitions of strategic assets or operating companies in the trend. Over time, we also expect to selectively target additional onshore basins in North America that would allow us to extend our competencies to large undeveloped acreage positions in hydrocarbon trends similar to our existing core area.

Our total 2011 capital expenditures were $264 million and we drilled or spud 32 wells. As of June 30, 2012, our total 2012 capital expenditure budget has been revised from $380 million to $365 million, approximately 6% of which will be spent developing acreage currently under lease in our expansion areas. Our capital expenditures for the six months ended June 30, 2012 were $206.5 million. Excluding planned expenditures associated with the Eagle Energy Acquisition, our 2012 budget consists of:

•

$292 million for drilling and completion capital;

•

$52 million for acquisition of acreage and seismic data; and

•

$21 million in unallocated funds which are available for facilities.

While we have budgeted $365 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results as the year progresses.

Basis of Presentation

On August 29, 2008, First Reserve purchased an approximate 72% interest in Midstates Petroleum Holdings LLC (the “FR Investment”). For financial reporting purposes, the FR Investment was accounted for as a purchase and resulted in a new basis of accounting reflecting estimated fair values for 100% of our assets and liabilities that were recorded at their estimated fair value as of the closing date, based on the purchase price paid in the transaction. Accordingly, the financial statements for periods subsequent to August 29, 2008, are presented on Midstates Petroleum Holdings LLC’s new basis of accounting giving effect to the transaction. Including its initial investment in August 2008, First Reserve acquired an approximate 77% aggregate equity interest in Midstates Petroleum Holdings LLC.

Sources of Our Revenues

Oil, natural gas and natural gas liquids. Our revenues are derived from the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from our high Btu content natural gas. Our oil and gas revenues do not include the effects of derivatives, and may vary significantly from period to period as a result of changes in production volumes or commodity prices.

Realized and unrealized gain (loss) on commodity derivative financial contracts. We utilize commodity derivatives to reduce our exposure to fluctuations in the prices of oil. In addition, we utilize derivatives to help mitigate our exposure to fluctuations in Louisiana Light Sweet (“LLS”) oil prices as compared to West Texas Intermediate (“NYMEX WTI”) benchmark oil prices. Accordingly, our income statements reflect (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices change and commodity derivatives contracts expire or new ones are entered into, and (ii) our realized gains or losses on the settlement of these commodity derivative contracts. Unrealized gains and losses result from changes in market valuations of derivatives as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, unrealized losses are recognized. Conversely, if the expected future commodity prices decrease compared to the contract prices on the derivatives, unrealized gains are recognized. Since we have elected not to apply hedge accounting to our derivatives, we reflect the unrealized and realized gains and losses in our current income statement periods based on the mark-to-market value at the end of each month. Cash flows associated with derivative financial instruments are reflected in cash flow from operations in our consolidated statement of cash flows.

Commodity prices. Our revenues are heavily influenced by commodity prices, which are subject to wide fluctuations in response to changes in supply and demand.

The table below sets forth the prices we received per unit of volume for our oil, natural gas, and NGLs, both including and excluding the effects of our commodity derivative contracts.


	Six Months Ended June 30,				Year Ended December 31,
	2012		2011		2011		2010		2009
Average sales prices:
Oil, without realized derivatives ($/Bbl)	$	109.30	$	108.34	$	110.25	$	80.29	$	55.07
Oil, with realized derivatives ($/Bbl)		95.59		97.53		99.85		79.37		57.69
Natural gas liquids ($/Bbl)		45.14		44.67		50.98		36.92		47.66
Natural gas ($/Mcf)		2.46		4.70		4.20		4.66		3.89

In general, differentials are adjustments to the benchmark price for oil based on grade and location of the sales point. All of our oil is sold at the market price for LLS, which has recently traded at a significant premium to NYMEX WTI prices. Our oil production benefits from higher pricing differentials relative to many other oil producers in other areas of North America. For example, for the six months ended June 30, 2012, the average realized price before the effect of commodity derivative contracts for our oil production was $109.30 per Bbl, compared to an average NYMEX WTI settlement price of $98.10 per Bbl for the same time period. In addition, our gas production benefits from relatively rich Btu content. As a result of natural gas processing, we benefit from an overall higher realized price relative to the Henry Hub benchmark. For example, for the six months ended June 30, 2012, the average realized price for our gas production was $2.46 per Mcf, compared to an average Henry Hub settlement price of $2.36 per MMBtu for the same period.

Other revenue. Other revenue consists of income derived from the recovery of administrative overhead, gas compression charges and saltwater disposal fees from third parties for their share of costs on company owned assets.

Our Expenses

Lease operating and workover expenses. These are daily costs incurred to bring oil and gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include natural gas transportation and treating expenses, as well as maintenance and repair expenses related to our oil and gas properties. Lease operating expenses include both a portion of costs that are fixed in nature, such as infrastructure costs, as well as variable costs resulting from additional wells and production. As production increases, our average lease operating expense per barrel of oil equivalent is typically reduced because fixed costs do not increase proportionately with production. Workover expense includes major remedial operations on a completed well to restore, maintain, or improve a well’s production and is closely correlated to the levels of workover activity. Because workover projects are pursued on an as needed basis and are not regularly scheduled, workover expense is not necessarily comparable from period to period.

Severance and other taxes. Severance taxes are paid on produced oil and gas based on a percentage of revenues from products sold at market prices or at fixed rates established by federal, state, or local taxing authorities. We attempt to take full advantage of all credits and exemptions in our various taxing jurisdictions. In general, the severance taxes we pay correlate to the changes in oil and gas revenues. Ad valorem taxes are property taxes assessed based on the value of property and are presented with severance and other taxes.

Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and systematically expense those costs on a unit of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties for which proved reserves have not yet been assigned, less accumulated amortization; (ii) estimated future expenditures to be incurred in developing proved reserves; and (iii) estimated dismantlement and abandonment costs.

Impairment of oil and gas properties/Ceiling test. Our historical policy as a privately-owned company has been to perform a ceiling test on an annual basis, and we performed a ceiling test at December 31, 2011, 2010 and 2009. However, we have applied Rule 4-10 of Regulation S-X going forward, which requires the ceiling test to be performed on at least a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price we received as of the first trading day of each month over the preceding 12 months (such average price is held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations.

General and administrative expense. General and administrative expense consists of overhead, including payroll and benefits for our corporate staff, non-cash charges for share-based compensation, costs of maintaining our headquarters, franchise taxes, audit and other professional fees and legal compliance. General and administrative expenses related to being a publicly traded company include: Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley compliance; expenses associated with listing on the NYSE; legal fees, investor relations expenses, registrar and transfer agent fees, director and officer liability insurance costs; and director compensation. As a result of being a publicly-traded company following our recently completed initial

public offering, we expect that our general and administrative expenses in future periods will increase (excluding the effects of our non-cash share-based compensation charge incurred during the year ended December 31, 2011 resulting from the transition from liability accounting to equity accounting as described in Note 7 to our audited financial statements for the year ended December 31, 2011).

Certain of our employees hold units in Midstates Incentive Holdings LLC that entitle the holders to a portion of the proceeds to be received by First Reserve upon sales of our common stock by FRMI. Any payments with respect to these units will only occur if and when First Reserve achieves certain minimum return hurdles (defined as certain multiples of First Reserve’s capital contributions plus investment expenses) on its investment through the sale of its shares of common stock. While these proceeds will not involve any cash payment by us, we will recognize a non-cash compensation expense, which may be material, in the period such payment is made. See Note 7 to our audited financial statements for the year ended December 31, 2011.

Interest expense. We finance a portion of our working capital requirements and capital expenditures with borrowings under our revolving credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our revolving credit facility in interest expense.

We capitalize a portion of our interest costs on unproved properties. Capitalized interest is depreciated over the useful life of assets in the same manner as the depreciation of the underlying assets.

Income Taxes. Midstates Petroleum Holdings LLC has historically not been subject to U.S. federal and certain state income taxes. As a result of our recently completed public offering and corporate reorganization, Midstates Petroleum Company, Inc. became subject to U.S. federal, state, local and foreign income taxes, effective April 25, 2012 and will be subject to tax at the prevailing corporate tax rates for future periods.

Results of Operations

The following table summarizes our revenues and production data for the period indicated.


	Three Months Ended June 30,						Six Months Ended June 30,						Year Ended December 31,
	2012			2011			2012			2011			2011			2010			2009
Revenues:
Oil	$	48,056		$	45,994		$	93,138		$	81,577		$	177,464		$	75,875		$	27,347
Natural gas		2,379			4,962			5,829			9,035			20,665			10,505			2,683
Natural gas liquids		3,901			3,171			10,173			5,216			15,683			2,731			103
Gains/(losses) on commodity derivative contracts—net		48,143			10,477			23,478			(18,119	)		(4,844	)		(26,268	)		(5,987	)
Other		103			60			207			114			465			209			108

Total revenues	$	102,582		$	64,664		$	132,825		$	77,823		$	209,433		$	63,052		$	24,254
Operating Expenses:
Lease operating and workover (1)	$	5,921		$	3,669		$	12,388		$	6,275		$	16,117		$	12,861		$	10,328
Severance and other taxes (2)		6,272			5,370			11,648			9,495			13,640			6,986			3,059
Asset retirement accretion		164			39			298			86			334			175			120
General and administrative		4,956			10,641			11,019			14,544			68,915			16,847			5,886
Depreciation, depletion and amortization		27,882			21,266			55,909			39,884			91,699			41,827			12,322
Impairment in the carrying value of oil and gas properties		—			—			—			—			—			—			4,297

Total expenses	$	45,195		$	40,985		$	91,262		$	70,284		$	190,705		$	78,696		$	36,012
Other Income (Expense):
Interest income		143			4			150			12			23			9			6
Interest expense—net of amounts capitalized		(990	)		(134	)		(2,680	)		(134	)		(2,094	)		—			—

Total other income (expense)		(847	)		(130	)		(2,530	)		(122	)		(2,071	)		9			6
Income tax expense		168,917			—			168,917			—			—			—			—

Net income (loss)	$	(112,377	)	$	23,549		$	(129,884	)	$	7,417		$	16,657		$	(15,635	)	$	(11,752	)
Production Data:
Oil (MBbls)		447			391			852			753			1,610			945			497
Natural gas (MMcf)		1,047			1,043			2,369			1,924			4,918			2,253			690
Natural gas liquids (MBbls)		98			70			225			117			308			74			2
Oil equivalents (MBoe)		719			635			1,472			1,190			2,737			1,394			614
Average daily production (Boe/d)		7,904			6,976			8,090			6,577			7,499			3,820			1,682
Average Sales Prices:
Oil, without realized derivatives (per Bbl)	$	107.56		$	117.48		$	109.30		$	108.34		$	110.25		$	80.29		$	55.07
Oil, with realized derivatives (per Bbl)		95.97			101.83			95.59			97.53			99.85			79.37			57.69
Natural gas (per Mcf)		2.27			4.76			2.46			4.70			4.20			4.66			3.89
Natural gas liquids (per Bbl)		39.83			45.58			45.14			44.67			50.98			36.92			47.66

(1)	Includes $0.7 million, $0.4 million, $1.5 million, $0.7 million, $2.1 million, $4.7 million, and $5.2 million in workover expense for the three and six months ended June 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009, respectively.

(2)	Includes $0.8 million, $0.2 million, $1.7 million, $0.4 million, $1.2 million, $0.6 million, and $0.2 million in ad valorem tax expense for the three and six months ended June 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009, respectively.

Three Months Ended June 30, 2012 as Compared to the Three Months Ended June 30, 2011

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and natural gas liquids, or NGLs, sales revenues increased by $0.2 million, or less than 1%, to $54.3 million during the second quarter of 2012 as compared to $54.1 million for the second quarter of 2011. Our revenues are a function of oil, natural gas, and NGL production volumes sold and average sales prices received for those volumes. Of the $0.2 million revenue variance, sales volume increases contributed $7.8 million, offset by unfavorable price variances of $7.6 million. Average daily production sold increased by 928 Boe per day, or 13%, to 7,904 Boe per day during the second quarter of 2012 as compared to 6,976 Boe per day during the second quarter of 2011. The increase in average daily production sold was primarily due to a greater number of producing wells during the 2012 period resulting from our increased drilling activity. Average oil sales prices, without realized derivatives, decreased by $9.92 per barrel or 8% to $107.56 per barrel for the second quarter of 2012 as compared to $117.48 per barrel for the second quarter of 2011.

Gains/losses on commodity derivative contracts—net. Net gains (losses) on our mark-to-market, MTM, derivative positions increased $37.6 million, or 359%, to a net gain of $48.1 million for the three months ended June 30, 2012 compared to a net gain of $10.5 million for the three months ended June 30, 2011. Our derivative positions moved from an unrealized gain of $16.6 million in the second quarter of 2011 to an unrealized gain of $53.3 million in the second quarter of 2012. The increase in our unrealized gains for the 2012 period were primarily attributable to an increase in volumes covered by derivative instruments and a general decline in oil prices during the 2012 period. The value of our derivative positions move inversely to the price of oil. The realized loss on derivatives for the three months ended June 30, 2012 was $5.2 million compared to a realized loss of $6.1 million for the three months ended June 30, 2011. Realized oil sales prices, with realized derivatives, averaged $95.97 per barrel for the second quarter of 2012 compared to $101.83 per barrel for the same period in 2011.

Lease operating and workover expenses. Lease operating and workover expenses increased $2.2 million, or 59%, to $5.9 million for the second quarter of 2012 compared to $3.7 million for the second quarter of 2011. Lease operating expenses increased $1.9 million, or 58%, to $5.2 million for the second quarter of 2012 as compared to $3.3 million for the second quarter of 2011. This increase was due to higher surface maintenance costs of $0.6 million due to increased road and lease maintenance, higher saltwater disposal costs of $0.5 million primarily attributable to central fault block wells in our South Bearhead Creek/Oretta operating area, and additional costs of $0.7 million, related to compression, well work charges and labor related costs, due to a greater number of producing wells period over period. Workover expenses increased $0.3 million, or 75%, to $0.7 million for the second quarter of 2012 as compared to $0.4 million for the second quarter of 2011. We completed ten workovers in the second quarter of 2012, which was an increase of four projects over the six workovers completed in the second quarter of 2011. Lease operating and workover expenses increased to $8.24 per Boe for the quarter ended June 30, 2012 from $5.78 per Boe for the quarter ended June 30, 2011, an increase of 43%, which was primarily attributable to the factors discussed above.

Severance and other taxes. Severance and other taxes increased $0.9 million, or 17%, to $6.3 million for the second quarter of 2012 compared to $5.4 million for the second quarter of 2011. Severance taxes increased $0.4 million, or 8%, to $5.5 million for the second quarter of 2012 as compared to $5.1 million for the second quarter of 2011. This increase was primarily attributable to slightly higher oil, natural gas and NGL sales revenue during the second quarter of 2012. Our severance taxes as a percentage of oil, natural gas and NGL sales revenue were 10.1% for the second quarter of 2012, compared to 9.5% in the second quarter of 2011. Ad valorem taxes increased $0.6 million, or 300%, to $0.8 million for the second quarter of 2012 as compared to $0.2 million for the second quarter of 2011, corresponding to a related increase in producing wells.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $ 6.6 million, or 31%, to $27.9 million for the second quarter of 2012 compared to $21.3 million for the second quarter of 2011. The DD&A rate for second quarter of 2012 was $38.78 per Boe compared to $33.49 per Boe for the second quarter of 2011. The increase in the DD&A rate per Boe versus the comparable 2011 period is primarily attributable to wells spud during the 2012 period on drilling locations that have probable and possible reserve classifications. We drill these wells to extend our proved reserves within the play. The impact on the DD&A rate is directly related to the timing of our evaluation of the well results and our ability to assign proved reserves to those wells.

General and administrative. Our general and administrative expenses, or G&A, decreased by $5.6 million, or 53%, to $5.0 million for the second quarter of 2012 compared to $10.6 million for the second quarter of 2011. The overall decrease is driven by a reduction in equity-based compensation expense of $6.6 million; in the second quarter of 2012, the Company recorded $0.7 million in share-based compensation related to restricted stock awards granted during the quarter compared to $7.3 million recorded in the second quarter 2011. This decrease was partially offset by an increase over the same periods of $1.1 million in other employee related costs, including salary and insurance, which relates to an overall increase in headcount from 48 full time employees during three months ended June 30, 2011 to 86 full time employees during the three months ended June 30, 2012.

Interest expense. Interest expense for the three months ended June 30, 2012 and for the three months ended June 30, 2011 was $2.7 million and $0.9 million, respectively. The increase in interest expense was primarily due to the higher average outstanding balances under our revolving credit facility during the 2012 period. Our average outstanding balance was $163.7 million during the 2012 period, versus $116.2 million for the 2011 period, and related to $1.0 million of the total interest expense of $2.7 million. The remainder of the interest expense for the three months ended June 30, 2012, $1.7 million, is attributable to interest expense of $1.5 million associated with our Preferred Units, which were redeemed in April 2012, and amortization of deferred loan costs of $0.2 million. Of total interest expense, $1.7 million and $0.7 million was capitalized, resulting in $1.0 million and $0.1 million in interest expense for the three months ended June 30, 2012 and June 30, 2011, respectively.

Provision for Income Taxes. Income tax expense was $168.9 million during the three months ended June 30, 2012. We were not a tax paying entity during the 2011 corresponding period and therefore, no income tax expense was recorded. With the consummation of our corporate reorganization (“Reorganization”) in connection with our initial public offering completed on April 25, 2012, we became a tax paying entity and as such, were required to record a charge against income equal to the estimated tax effect of the excess of the book carrying value of our net assets (primarily producing oil and gas properties) over their collective estimated tax bases as of the Reorganization date. As a result, during the three months ended June 30, 2012, we recorded a tax charge of $149.5 million associated with the Reorganization. During the three months ended June 30, 2012, we also recorded $19.4 million of income tax expense. This represents an application of our estimated effective tax rate (including state income taxes) for the three months ended June 30, 2012 of 34.4% to our income earned from the Reorganization date through the quarter end.

Six Months Ended June 30, 2012 as Compared to the Six Months Ended June 30, 2011

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and NGL sales revenues increased by $13.3 million, or 14%, to $109.1 million during the first six months of 2012 as compared to $95.8 million for the first six months of 2011. Our revenues are a function of oil, natural gas, and NGL production volumes sold and average sales prices received for those volumes. Of the $13.3 million revenue variance, sales volume increases contributed $17.7 million of the total, offset by unfavorable price variances of $4.4 million. Average daily production sold increased by 1,513 Boe/d, or 23%, to 8,090 Boe/d during the first six months of 2012 as compared to 6,577 Boe/d during the first six months of 2011. The increase in average daily production sold was primarily due to a greater number of producing wells during the 2012 period resulting from our increased drilling activity. Average oil sales prices, without realized derivatives, increased by $0.96 per barrel or 1% to $109.30 per barrel for the first six months of 2012 as compared to $108.34 per barrel for the first six months of 2011.

Gains/losses on commodity derivative contracts—net. Net gains (losses) on our MTM derivative positions increased $41.6 million, or 229%, to a $23.5 million gain for the six months ended June 30, 2012 compared to a net loss of $18.1 million for the six months ended June 30, 2011. Our derivative positions moved from an unrealized loss of $10.0 million in the six months ended June 30, 2011 to an unrealized gain of $35.2 million in the six months ended June 30, 2012. The increase in our unrealized gain for the 2012 period is primarily attributable to increases in volumes covered by derivative instruments and a general decline in oil prices during the latter part of the 2012 period. The value of our hedging instruments moves inversely to the price of oil. The realized loss on derivatives for the six months ended June 30, 2012 was $11.7 million compared to a realized loss of $8.1 million in the six months ended June 30, 2011. Realized oil sales prices, with realized derivatives, averaged $95.59 per barrel for the first six months of 2012 compared to $97.53 per barrel for the same period in 2011.

Lease operating and workover expenses. Lease operating and workover expenses increased $6.1 million, or 97%, to $12.4 million for the six months ended June 30, 2012 compared to $6.3 million for the six months ended June 30, 2011. Lease operating expenses increased $5.2 million, or 93%, to $10.8 million for the six months ended June 30, 2012 as compared to $5.6 million for the six months ended June 30, 2011. This increase was due to higher surface maintenance costs of $1.2 million due to increased road and lease maintenance, higher saltwater disposal of $1.4 million primarily attributable to central fault block wells in our South Bearhead Creek/Oretta operating area, and additional costs of $2.0 million, related to compression, well work charges and labor related costs due to a greater number of producing wells period over period. Workover expenses increased $0.8 million, or 114%, to $1.5 million for the six months ended June 30, 2012 as compared to $0.7 million for the six months ended June 30, 2011. We completed 19 workovers in the six months ended June 30, 2012, which was an increase of ten projects over the nine workovers completed in the six months ended June 30, 2011. Lease operating and workover expenses increased to $8.42 per Boe for the six months ended June 30, 2012 from $5.27 per Boe for the six months ended June 30, 2011, an increase of 60%, which was primarily a result of the incurrence of lease operating and workover costs during 2012 at a higher rate than the overall increase in production during the period.

Severance and other taxes. Severance and other taxes increased $2.1 million, or 23%, to $11.6 million for the six months ended June 30, 2012 compared to $9.5 million for the six months ended June 30, 2011. Severance taxes increased $0.9 million, or 10%, to $10.0 million for the six months ended June 30, 2012 as compared to $9.1 million for the six months ended June 30, 2011. This increase was primarily attributable to higher oil, natural gas and NGL sales revenue during the six months ended June 30, 2012. Our severance taxes as a percentage of oil, natural gas and NGL sales revenue were 9.1% for the six months ended June 30, 2012, compared to 9.5% in the six months ended June 30, 2011. Ad valorem taxes increased $1.3 million, or 325%, to $1.7 million for the six months ended June 30, 2012 as compared to $0.4 million for the six months ended June 30, 2011, corresponding primarily to a related increase in producing wells.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $16.0 million, or 40%, to $55.9 million for the six months ended June 30, 2012 compared to $39.9 million for the six months ended June 30, 2011. The DD&A rate for the six months ended June 30, 2012 was $37.97 per Boe compared to $33.52 per Boe for the six months ended June 30, 2011. The increase in DD&A expense for the six months ended June 30, 2012 was primarily due to higher production volumes during the 2012 period, as well as capital expenditures incurred during the 2012 period, without a corresponding proportionate increase in the total proved reserve base.

General and administrative. Our G&A expenses decreased by $3.5 million, or 24%, to $11.0 million for the six months ended June 30, 2012 compared to $14.5 million for the six months ended June 30, 2011. Primarily driving the decrease is a reduction in share-based compensation of $7.3 million, as $0.7 million was recorded during the six months ended June 30, 2012 compared to $7.9 million recorded during the six months ended June 30, 2011. This decrease was partially offset by the other components of general and administrative expenses, which increased primarily due to the overall growth in the company and headcount between June 30,

2011 and June 30, 2012. As of June 30, 2012, we had 86 full time employees compared to 48 employees as of June 30, 2011. The 79% increase in headcount resulted in a $2.3 million increase in employee-related costs to $5.5 million for the six months ended June 30, 2012, compared to $3.2 million for the six months ended June 30, 2011. Rent expense increased $0.4 million, or 133%, to $0.7 million for the six months ended June 30, 2012 compared to $0.3 million for the six months ended June 30, 2011, as the Company requires more workspace to accommodate the increase in headcount. Professional expenses increased $0.8 million, or 50%, to $1.6 million for the six months ended June 30, 2012 compared to $0.8 million for the six months June 30, 2011 primarily due to expenses associate with becoming a public company.

Interest expense. Interest expense for the six months ended June 30, 2012 and for the six months ended June 30, 2011 was $5.1 million and $1.5 million, respectively. The increase in interest expense was primarily due to the higher average outstanding balances under our revolving credit facility during the 2012 period. Our average outstanding balance was $199.2 million during the 2012 period, versus $107.3 million for the 2011 period, and related to $2.8 million of the total interest expense of $5.1 million. The remainder of the interest expense for the six months ended June 30, 2012, $2.3 million, related to interest expense of $2.1 million associated with our Preferred Units, which were redeemed in April 2012, and amortization of deferred loan costs of $0.2 million. Of total interest expense, $2.4 million and $1.3 million was capitalized, resulting in $2.7 million and $0.1 million in interest expense for the six months ended June 30, 2012 and June 30, 2011, respectively.

Provision for Income Taxes. Income tax expense was $168.9 million during the six months ended June 30, 2012. We were not a tax paying entity during the 2011 corresponding periods and therefore, no income tax expense was recorded. With the consummation of the Reorganization in connection with our initial public offering completed on April 25, 2012, we became a tax paying entity and as such, were required to record a charge against income equal to the estimated tax effect of the excess of the book carrying value of our net assets (primarily producing oil and gas properties) over their collective estimated tax bases as of the Reorganization date. As a result, during the six months ended June 30, 2012, we recorded a tax charge of $149.5 million associated with the Reorganization. During the six months ended June 30, 2012, we also recorded $19.4 million of income tax expense. This represents an application of our estimated effective tax rate (including state income taxes) for the six months ended June 30, 2012 of 49.7% to our income earned from the Reorganization date through the period end.

Year Ended December 31, 2011 as Compared to the Year Ended December 31, 2010

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and NGLs sales revenues increased by $124.7 million, or 140%, to $213.8 million during the year ended December 31, 2011 as compared to $89.1 million for the year ended December 31, 2010. Our revenues are a function of oil, natural gas, and NGLs production volumes sold and average sales prices received for those volumes. Of the $124.7 million revenue variance, sales volume increases contributed $74.4 million of the total, while price variance contributed $50.3 million. Average daily production sold increased by 3,679 Boe/d, or 96%, to 7,499 Boe/d during the year ended December 31, 2011 as compared to the year ended December 31, 2010. The increase in average daily production sold was primarily due to increased drilling activity resulting in 31 additional producing wells in operation during 2011 as compared to the prior year period. Average oil sales prices, without realized derivatives, increased by $29.96 per barrel, or 37%, to $110.25 per barrel for the year ended December 31, 2011 as compared to $80.29 per barrel for the year ended December 31, 2010.

Losses on commodity derivative contracts—net. Our MTM derivative positions moved from an unrealized loss of $25.4 million as of December 31, 2010 to an unrealized gain of $11.9 million as of December 31, 2011. The MTM change results from higher average hedge volumes and prices on December 31, 2011 compared to the open positions on December 31, 2010. The NYMEX WTI closing price on December 30, 2011 (the last trading day of 2011) was $98.83 per barrel compared to a closing price of $91.38 per barrel on December 31, 2010. The realized loss on derivatives for the year ended December 31, 2011 was $16.7 million compared to a realized loss of $0.9 million for the year ended December 31, 2010. The loss for the year ended December 31, 2011 was a

result of realized oil prices rising substantially for the year versus the prices at which we had oil production hedged for the period. Realized oil sales prices, without realized derivatives, averaged $110.25 per barrel for the year ended December 31, 2011 compared with $80.29 per barrel for the year ended December 31, 2010.

Lease operating and workover expenses. Lease operating and workover expenses increased $3.2 million, or 25%, to $16.1 million for the year ended December 31, 2011 compared to $12.9 million for the year ended December 31, 2010. Of this change, lease operating expenses increased $5.8 million, or 71%, to $14.0 million, due to 31 additional producing wells in operation during the period, which resulted in additional salt water disposal costs of $2.9 million, additional compression charges of $0.8 million, additional gas dehydration and chemical costs of $1.0 million, with the remaining variance primarily attributable to increases in labor related costs. Workover expenses decreased $2.6 million, or 55%, to $2.1 million for the year ended December 31, 2011 compared to $4.7 million for the year ended December 31, 2010. Lease operating and workover expenses decreased to $5.89 per Boe at December 31, 2011 from $9.23 per Boe at December 31, 2010, a decrease of 36%. This decrease was primarily a result of the 162% increase in production volumes from the year ended December 31, 2010 to the year ended December 31, 2011, without a commensurate increase in fixed costs.

Severance and other taxes. Severance and other taxes increased $6.6 million, or 94%, to $13.6 million for the year ended December 31, 2011 as compared to $7.0 million for the year ended December 31, 2010. Severance taxes increased by $6.0 million, or 93%, and accounted for $12.4 million of the 2011 amount. This increase was primarily attributable to higher oil, natural gas and NGLs sales revenue during the 2011 period. Severance taxes for the year ended December 31, 2011 and 2010 were 5.8% and 7.2%, respectively, as a percentage of oil, natural gas and NGLs sales revenue. The severance tax rate for the year ended December 31, 2011 was lower than the severance tax rate for the year ended December 31, 2010 due to an increase in production on wells qualifying for severance tax exemptions, which reduced 2011 severance tax expense by approximately $0.9 million.

Depreciation, depletion and amortization (DD&A). Depreciation, depletion and amortization expense increased $49.9 million, or 119%, to $91.7 million for the year ended December 31, 2011 compared to $41.8 million for the year ended December 31, 2010. The DD&A rate for the year ended December 31, 2011 was $33.50 per Boe compared to $30.00 per Boe for the year ended December 31, 2010. The increase in DD&A expense for the year ended December 31, 2011 was primarily due to the higher capital expenditures related to increased drilling and completion activities during the year, which resulted in a higher amortization base, and increased oil, natural gas and NGLs production, partially offset by the impact of higher total proved reserves.

General and administrative. Our G&A expenses increased to $68.9 million for the year ended December 31, 2011 from $16.8 million for the year ended December 31, 2010. The increase in G&A expenses of $52.1 million, or 310%, was primarily due to the expenses related to share-based compensation, which included a $53.7 million non-cash charge for share-based compensation for the year ended December 31, 2011, compared to a $1.5 million non-cash charge for the year ended December 31, 2010. Share-based compensation expense for the year ended December 31, 2011 included expense related to the accelerated vesting in November 2011 of restricted stock of one of our affiliates held by certain of our employees, as well as expense attributable to the change in fair value of certain equity awards accounted by the Company as liability awards up to December 5, 2011. (See “Notes to Consolidated Financial Statements—Note 7—Member’s Equity and Share-Based Compensation”). As of December 31, 2011, we had 51 full-time employees as compared to 43 employees as of December 31, 2010. The additional expenses related to the increase in headcount and professional fees paid to contractors of approximately $1.9 million, were offset by approximately $2.4 million less being paid in employee bonuses between periods.

Interest expense. Interest expense for the year ended December 31, 2011 and December 31, 2010 was $4.7 million and $1.7 million, respectively. The increase in interest expense is primarily due to the increase in outstanding balances under our prior revolving credit facility, resulting in an additional $2.7 million of interest expense and an increase in our interest rate, which increased such expense by $0.3 million. Of total interest expenses, $2.6 million and $1.7 million were capitalized, resulting in $2.1 million and no interest expenses for the years ended December 31, 2011 and 2010, respectively.

Year Ended December 31, 2010 as Compared to the Year Ended December 31, 2009

Oil, natural gas and natural gas liquids revenues. Our oil, natural gas and NGLs sales revenues increased by $59 million, or 196%, to $89.1 million during the year ended December 31, 2010 as compared to $30.1 million for the year ended December 31, 2009. Of the $59 million revenue variance, sales volume increases contributed $34.2 million of the total, while price variance contributed $24.8 million. Average daily production sold increased by 2,139 Boe/d, or 127%, to 3,820 Boe/d during the year ended December 31, 2010 as compared to the year ended December 31, 2009. The increase in average daily production sold was primarily due to the increased drilling activity in 2010 versus 2009. Average oil sales prices, without realized derivatives, increased by $25.22 per barrel or 46% to $80.29 per barrel for the year ended December 31, 2010 as compared to $55.07 per barrel the year ended December 31, 2009.

Gains (losses) on commodity derivative contracts—net. Our MTM derivative unrealized loss increased from $7.3 million as of December 31, 2009 to an unrealized loss of $25.4 million as of December 31, 2010. The MTM change results from the increase in NYMEX WTI prices between these two dates and the open volume hedge positions at the end of each period at prices lower than NYMEX WTI. The NYMEX WTI closing price on December 31, 2010 was $91.38 per barrel while the same price for December 31, 2009 was $79.36 per barrel. The realized loss on derivatives for the year ended December 31, 2010 was $0.9 million compared to a realized gain of $1.3 million for the year ended December 31, 2009. The loss for the year ended December 31, 2010 was a result of realized oil prices rising substantially for the year versus the prices at which we had oil production hedged for the period. Realized oil sales prices averaged $80.29 per barrel for the year ended December 31, 2010 compared with $55.07 per barrel for the year ended December 31, 2009.

Lease operating and workover expenses. Lease operating and workover expenses increased $2.6 million, or 25%, to $12.9 million for the year ended December 31, 2010 compared to $10.3 million for the year ended December 31, 2009. This change was primarily due to the increase in lease operating expenses of $3.1 million, or 60%, to $8.2 million for the year ended December 31, 2010 compared to $5.1 million for the year ended December 31, 2009, driven by our number of operating wells during 2010 versus 2009, which led to additional surface maintenance costs of $1.0 million, additional compression charges of $0.6 million, additional gas dehydration and chemical costs of $0.5 million, and the remainder from saltwater disposal and increases in labor related costs. Workover expenses decreased $0.5 million, or 10%, to $4.7 million for the year ended December 31, 2010 compared to $5.2 million for the year ended December 31, 2009. This decrease was primarily due to fewer workovers on our active wells and better cost control. Lease operating and workover expenses decreased to $9.23 per Boe at December 31, 2010 from $16.82 per Boe at December 31, 2009, a decrease of 45%. This decrease was primarily a result of the 127% increase in production volumes from the year ended December 31, 2009 to the year ended December 31, 2010.

Severance and other taxes. Severance and other taxes increased $3.9 million, or 126%, to $7.0 million for the year ended December 31, 2010 compared to $3.1 million for the year ended December 31, 2009. Our severance taxes for the year ended December 31, 2010 and 2009 were $6.4 million and $2.8 million, respectively, and were driven primarily by an increase in production during the same periods, which accounted for $4.2 million of the increase. Our severance taxes for the year ended December 31, 2010 and 2009 were 7.2% and 9.5%, respectively, as a percentage of oil, natural gas and NGLs revenues. The severance tax rate for the year ended December 31, 2010 was lower than the severance tax rate for the year ended December 31, 2009 due to an increase in production on wells qualifying for severance tax exemptions, which reduced severance taxes by approximately $0.7 million in 2010.

Depreciation, depletion and amortization (DD&A). Depreciation, depletion and amortization expense increased $29.5 million, or 239%, to $41.8 million for the year ended December 31, 2010 compared to the year ended December 31, 2009. The increase in DD&A expense for the year ended December 31, 2010 was primarily due to both increased production volumes and an increase in the DD&A rate. The DD&A rate for the year ended December 31, 2010 was $30.00 per Boe compared to $20.08 per Boe for the year ended December 31, 2009. This increase in the DD&A rate was due to an increase in capital expenditures without proportional associated proved reserve additions being booked within the period.

Impairment of oil and gas properties/Ceiling test. During the year ended December 31, 2010, we did not record a non-cash impairment charge. For the year ended December 31, 2009, we recorded non-cash impairment charges of $4.3 million as a result of net capitalized costs exceeding the ceiling limit calculated from the reserves data. In determining the amount of the non-cash impairment charges for such periods, we considered the application of the factors described under “—Critical Accounting Policies and Estimates—Impairment of Oil and Gas Properties/Ceiling Test.”

General and administrative. Our G&A expenses increased to $16.8 million for the year ended December 31, 2010 from $5.9 million for the year ended December 31, 2009, resulting in a change of $10.9 million, or 186%. In the year ended December 31, 2010, we incurred employee bonuses of approximately $4.9 million. In addition, our G&A expenses included a $1.5 million non-cash charge for stock-based compensation expense for the year ended December 31, 2010, compared to a $0.2 million non-cash charge for the year ended December 31, 2009. The increase in G&A expenses was primarily due to a $4.8 million increase in employee bonuses, a $4.8 million increase in expenses due to the addition of a significant number of employees to support our growth and a $1.3 million increase in expenses related to share-based compensation.

Interest expense. Interest costs for the years ended December 31, 2010 and 2009 were $1.7 million and $0.8 million, respectively. The $0.9 million increase in interest cost is primarily a result of a $1.0 million increase in outstanding balances under our prior revolving credit facility partially offset by $0.1 million from a reduction in interest rates. Of the total interest cost, all of the $1.7 million and $0.8 million were capitalized for the years ended December 31, 2010 and 2009.

Liquidity and Capital Resources

On a pro forma basis as of June 30, 2012, after giving effect to the issuance and sale by us of $550 million aggregate principal amount of senior unsecured notes and the use of proceeds therefrom to fund the cash portion of the purchase price of the Eagle Energy Acquisition and the expenses related thereto and to repay a portion of the outstanding borrowings under our revolving credit facility as described above, we expect to have approximately $23.7 million of cash and cash equivalents and availability of $250 million under our revolving credit facility. Alternatively, if we do not issue and sell such notes and instead enter into a $500 million bridge credit facility as described above, we expect to have approximately $11.7 million of cash and cash equivalents and availability of $221 million under our revolving credit facility.

Our primary sources of liquidity to date have been net proceeds from our initial public offering, equity provided by First Reserve and our management team, borrowings under our revolving credit facility and cash flows from operations. Our primary use of capital has been the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt capital markets, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Our total 2011 capital expenditures were $264 million, which consisted of:

•

$227 million for drilling and completion capital;

•

$27 million for acquisition of acreage and seismic data; and

•

$10 million for facilities and other capital items.

Excluding planned expenditures associated with the Eagle Energy Acquisition, our total 2012 capital expenditure budget is $365 million, which consists of:

•

$292 million for drilling and completion capital;

•

$52 million for acquisition of acreage and seismic data; and

•

$21 million in unallocated funds which are available for facilities.

Through June 30, 2012, approximately $206.5 million of our 2012 capital expenditure budget has been spent.

While we have budgeted $365 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. We believe the net proceeds from this offering together with cash flows from operations and additional borrowings under our revolving credit facility should be more than sufficient to fund our 2012 and our 2013 capital expenditure budget. However, because wells funded under our 2012 and 2013 future drilling plan represent only a small percentage of our gross identified operated drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of identified drilling locations should we elect to do so.

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—A substantial or extended decline in oil and, to a lesser extent, natural gas, prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments” in our prospectus dated April 19, 2012 and filed with the SEC pursuant to Rule 424(b) on April 20, 2012 and “—Quantitative and Qualitative Disclosures About Market Risk.”

We review leasehold acquisition opportunities on an ongoing basis. In addition, we may selectively pursue the acquisition of businesses that may be complimentary to ours. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Our cash flows for the six months ended June 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009 and are presented below:


	Six Months Ended June 30,						Year Ended December 31,
	2012			2011			2011			2010			2009
	(in thousands)
	(unaudited)
Net cash provided by operating activities	$	59,963		$	66,984		$	140,700		$	50,768		$	10,595
Net cash used in investing activities		(184,245	)		(102,302	)		(242,771	)		(139,618	)		(75,215	)
Net cash provided by financing activities		128,627			33,856			97,498			96,414			65,759

Net change in cash	$	4,345		$	(1,462	)	$	(4,573	)	$	7,564		$	1,139

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $60.0 million and $67.0 million for the six months ended June 30, 2012 and June 30, 2011, respectively. The decrease in net cash provided by operating activities was primarily the result of a decrease in realized oil, natural gas and NGL prices offset by a slight increase in production and favorable working capital changes in the 2012 period as compared to the same period of 2011. Net cash provided by operating activities was $140.7 million, $50.8 million and $10.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. The increases in net cash provided by operating activities for the year ended December 31, 2011 compared to the year ended December 31, 2010 and for the year ended December 31, 2010 compared to the year ended December 31, 2009 were primarily the result of an increase in oil, natural gas, and NGLs production as well as an increase in realized oil prices.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “—Quantitative and Qualitative Disclosures About Market Risk.”

Cash Flows Used in Investing Activities

We had net cash used in investing activities of $184.2 million and $102.3 million during the six months ended June 30, 2012 and June 30, 2011, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increase in net cash used in investing activities during first six months of 2012 compared to first six months of 2011 is attributable to continued expansion of our drilling programs, and acreage position, as well as growth of our business. We had net cash used in investing activities of $242.8 million, $139.6 million and $75.2 million during the years ended December 31, 2011, 2010 and 2009, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increases in net cash used in investing activities during the year ended December 31, 2011 compared to the year ended December 31, 2010 and during the year ended December 31, 2010 compared to the year ended December 31, 2009 were attributable to continued expansion of our drilling programs and growth of our business.

We expect our 2012 capital expenditure budget to be $365 million, which is a 38% increase over the $264 million incurred for 2011. Capital expenditures in the six months ended June 30, 2012 were $206.5 million. Expenditures for exploration and development of oil and natural gas properties are the primary use of our capital resources. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities was $128.6 million and $33.9 million for the six months ended June 30, 2012 and June 30, 2011, respectively. For these periods, cash sourced through financing activities was provided primarily by proceeds from the completion of our initial public offering (April 2012) and borrowings under our revolving credit facilities. Our outstanding amounts under the revolving credit facility at June 30, 2012 and June 30, 2011 were $151.7 million and $146.6 million, respectively. During the 2012 period, we completed our initial public offering which resulted in net proceeds of $213.8 million, of which $99.0 million was used to repay a portion of our revolving credit facility and $65.0 million was used to redeem the preferred units held by an affiliate of First Reserve. Net cash provided by financing activities was $97.5 million, $96.4 million and $65.8 million for the years ended December 31, 2011, 2010 and 2009, respectively. For these years, cash sourced through financing activities was provided primarily by First Reserve and members of our management and borrowings under our prior revolving credit facility. Our long-term debt was $151.7 million at June 30, 2012. Our long-term debt was $234.8 million, $89.6 million and $29.8 million at December 31, 2011, 2010 and 2009, respectively.

Reserve-based Credit Facility

As of August 30, 2012, we had a $500 million reserve-based revolving credit facility with a borrowing base of $235 million, after giving effect to the amendment described below. The facility matures in June 2017. The borrowing base under our revolving credit facility will be subject to redetermination on a semi-annual basis, effective September 1 and March 1, beginning March 1, 2013, and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by either us or the administrative agent, acting at the direction of lenders holding at least two-thirds of the outstanding loans and other obligations. The borrowing base will be determined by the lenders in good faith and consistent with their usual and customary oil and gas lending criteria in existence at that particular time. Our revolving credit facility is available for general corporate purposes, including, without limitation, working capital for exploration and production operations.

In connection with the execution of the Acquisition Agreement, on August 11, 2012, we entered into a commitment letter with (after giving effect to certain subsequent joinders) each of the initial purchasers and/or their affiliates to, among other things, provide a commitment to amend our revolving credit facility to increase the borrowing base to $250 million, as further described below, and accommodate the issuance, incurrence and/or compliance with the terms of the Preferred Stock and the $550 million aggregate principal amount of senior unsecured notes that may be issued by us and Midstates Sub. The effectiveness of the amended revolving credit facility is subject to the consummation of the Eagle Energy Acquisition and other customary conditions.

If entered into, the amended revolving credit facility would mature on the fifth anniversary of the entrance into the facility and the aggregate amount available under the credit facility would increase to $250 million, subject to reduction in the event that the amount of assets acquired in connection with the Eagle Energy Acquisition is less than expected. In addition, it would increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, from $275 million to $500 million. We are in discussions with our lenders to increase this threshold to $550 million, thereby permitting the incurrence of the $550 million aggregate principal amount of senior unsecured notes that may be issued by us and Midstates Sub without causing a $0.25 reduction in the borrowing base for every $1 of debt incurred or issued up to $550 million.

In addition, on August 11, 2012, we entered into a second commitment letter with SunTrust Bank, SunTrust Robinson Humphrey, Inc., Bank of America N.A. and Merrill Lynch, Pierce Fenner & Smith Incorporated to have an amendment to the existing secured revolving facility underwritten which provides for $35 million of non-conforming borrowing base loans (thereby increasing the borrowing base under the existing secured revolving credit facility from $200 million to $235 million) and waives the requirement to comply with the minimum current ratio financial covenant for the quarters ending September 30, 2012 and December 31, 2012. The availability of non-conforming borrowing base loans would end upon the earliest to occur of (i) the closing of the Eagle Energy Acquisition, (ii) the issuance of certain issued debt permitted under the existing revolving credit facility and (iii) the scheduled March 2013 borrowing base redetermination. Thereafter, subject to the other commitments contemplated by the other commitment letter discussed above, the borrowing base would reduce to $200 million and loans would be permitted subject to the $200 million borrowing base. Borrowings under the terms of the amended revolving credit facility would bear interest at the same rates applicable to our existing revolving credit facility, provided that if borrowing base usage exceeded $200 million the amount of applicable margin would increase to up to 3.00% in the case of base rate loans and 4.00% in the case of LIBOR loans. Similarly, commitment fees would be the same rates applicable to our existing revolving credit facility subject to an increase up to 0.625% if borrowing base usage exceeded $200 million. The effectiveness of this amended revolving credit facility is not subject to the consummation of the Eagle Energy Acquisition.

On September 7, 2012, we entered into an amendment that contemplates the arrangements set forth in each of the above mentioned commitment letters. Upon the effectiveness of the amendment, the borrowing base increased to $235 million and the changes contemplated by the second commitment letter occurred. The increase of the borrowing base to $250 million, as further described above, and the changes contemplated by the first commitment letter will happen subsequently upon the satisfaction of customary conditions found in acquisition financings. These conditions include (1) the consummation of the Eagle Energy Acquisition in accordance with the terms of the Acquisition Agreement (subject to any changes which are materially adverse to the lenders being approved by the parties to the first commitment letter), (2) the absence of a “Seller Material Adverse Effect” as defined in the Acquisition Agreement since 12:01 a.m. (CST) June 1, 2012, (3) the delivery of a reserve report in respect of the assets of Eagle Energy to be transferred pursuant to the Acquisition Agreement, (4) the consummation of the issuance of the Preferred Stock, (5) the delivery of a solvency certificate, (6) the accuracy in all material respects of specified representations in our existing revolving credit facility and in the Acquisition Agreement and (7) the release of liens on the assets to be transferred pursuant to the Acquisition Agreement. After each of the effectiveness of the amendment and the satisfaction of the conditions giving rise to, among other things, the increase in the borrowing base to $250 million, the revolving credit facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to

those set forth in our existing revolving credit facility. After the borrowing base is increased to $250 million, we will need to satisfy certain covenants related to transfer of assets of Eagle Energy, such as the delivery of mortgages in respect of certain transferred oil and gas properties.

Our obligations under our revolving credit facility are secured by substantially all of our and our subsidiary’s assets.

As of August 30, 2012, we had $191.7 million outstanding under our revolving credit facility.

At our election, interest is generally determined by reference to:

•

the London interbank offered rate, or LIBOR, plus an applicable margin between 1.75% and 2.75% per annum; or

•

the higher of (x) a domestic bank prime rate, (y) the federal funds rate plus 0.50% and (z) one-month LIBOR plus 1.00%, plus an applicable margin between 0.75% and 1.75% per annum.

Interest is generally payable quarterly for bank rate loans and on the last day of the applicable interest period for LIBOR loans, but not less frequently than quarterly.

Our revolving credit facility contains certain covenants that, among other things, limit our ability to:

•

incur indebtedness;

•

grant liens other than liens created pursuant to the revolving credit facility and certain permitted liens;

•

make certain loans, advances and investments;

•

make dividends, distributions or redemptions;

•

merge or consolidate;

•

engage in certain asset dispositions, including a sale of all or substantially all of our or our subsidiary’s assets;

•

enter into certain sale or leaseback arrangements;

•

enter into certain transactions with affiliates;

•

grant negative pledges or agree to restrict dividends or distributions from subsidiaries;

•

allow gas imbalances, take-or-pay or other prepayments with respect to oil and gas properties that would require us to deliver hydrocarbons in the future without then or thereafter receiving full payment therefor; or

•

enter into certain derivative arrangements.

Our revolving credit facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:

•

a current ratio, consisting of consolidated current assets, including the unused amount of the total commitments, to consolidated current liabilities, excluding non-cash derivative assets and liabilities, of not less than 1.0 to 1.0, as of the last day of any fiscal quarter; and

•

a debt coverage ratio, consisting of consolidated debt minus all unrestricted cash and cash equivalents (in an amount not to exceed $15 million) to EBITDA, of not more than 4.00 to 1.0 for the four quarters ended on the last day of each fiscal quarter.

We believe that we are in compliance with the terms of our revolving credit facility. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. Each of the following will be an event of default:

•

failure to pay any principal or interest due under the revolving credit facility or any amount of principal under any letter of credit when due or, failure to pay within a certain grace period, any fees or other amount payable under the credit agreement;

•

a representation or warranty is proven to be incorrect in any material respect on or as of the date made or deemed made;

•

failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject, in certain instances, to certain grace periods;

•

default by us on the payment of any other indebtedness in excess of 5.0% of the borrowing base currently in effect, or any other event occurs that permits or causes the acceleration of such indebtedness;

•

bankruptcy or insolvency events involving us or our subsidiary;

•

the entry of one or more judgments, orders, decrees, or arbitration awards involving in the aggregate a liability as to any single or related series of transactions, incidents or conditions in excess of 5.0% of the borrowing base currently in effect that remains unsatisfied, unvacated and unstayed pending appeal for a period of thirty days after the entry thereof; and

•

a change of control, as defined in the credit agreement.

The foregoing description of our revolving credit facility does not purport to be complete and is qualified in its entirety by reference to the full text of such document, which was publicly filed on June 13, 2012.

Potential Bridge Credit Facility

The commitment letter described above also provides for an unsecured bridge credit facility in the amount of up to $500 million. The availability of loans under the bridge credit facility is subject to the consummation of the Eagle Energy Acquisition and other customary conditions. The proceeds of the bridge credit facility may be used solely to fund the Eagle Energy Acquisition, to pay transaction costs and expenses in connection therewith or repay outstanding debt under the existing revolving credit facility. If entered into, the bridge credit facility will initially bear interest at LIBOR, subject to a 1.50% floor, plus 9.0% and thereafter such 9.0% margin is subject to increases. The bridge credit facility matures on the first anniversary of the closing date of the Eagle Energy Acquisition and contains customary terms regarding the conversion of the bridge loans into other debt instruments subject to certain caps on yield, the highest of which is set at 13.25%. The obligations under the bridge credit facility would be guaranteed by the same entities that guaranty the existing secured revolving credit facility. If entered into, the amended revolving credit facility would mature on the fifth anniversary of the entrance into the facility and the aggregate amount available under the credit facility would increase to $250 million, subject to reduction in the event that the amount of assets acquired in connection with the Eagle Energy Acquisition is less than expected. In addition, it would increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, from $275 million to $500 million thereby permitting the incurrence of the bridge loans or the issuance of other debt without causing a $0.25 reduction in the borrowing base for every $1 of debt incurred or issued above $275 million. The definitive loan documentation for the bridge loan facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to those in other similar transactions and will otherwise be similar to the terms set forth in the existing secured revolving credit facility. The definitive loan documentation for the amended revolving credit facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to the terms set forth in the existing secured revolving credit facility and which address the above mentioned accommodations and allowances.

Commodity Derivative Contracts

Due to the inherent volatility in oil and gas prices, we use commodity derivative instruments, such as collars, swaps, puts, and basis differential swaps to hedge price risk associated with a significant portion of our anticipated oil and gas production. By removing a majority of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the unrealized gains and losses on open positions are reflected currently in earnings. At each period end, we estimate the fair value of our commodity derivatives and recognize an unrealized gain or loss. For a summary of our commodity derivative contracts as of June 30, 2012, please see “Quantitative and Qualitative Disclosures About Market Risk—Commodity price exposure.”

Obligations and Commitments

We have the following contractual obligations and commitments as of June 30, 2012 (in thousands):


	Payments due by period (1)
	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
Contractual Obligations
Revolving credit facility	$	151,700	$	—	$	151,700	$	—	$	—
Drilling contracts (2)		6,150		6,150		—		—		—
Operating leases (2)		8,436		634		2,857		2,939		2,006
Seismic contracts (2)		8,824		8,324		500		—		—
Asset retirement obligations (3)		9,398		—		—		—		9,398
Other (2)		1,110		1,110		—		—		—

Total contractual cash obligations	$	185,618	$	16,218	$	155,057	$	2,939	$	11,404

(1)	Less than 1 year represents amounts for the remainder of 2012 (July 1 through December 31), 1-3 years represents amounts for 2013 and 2014, 3-5 years represents amounts for 2015 and 2016, and more than 5 years represents amounts after 2016.

(2)	See Note 12 in the Notes to the Unaudited Condensed Consolidated Financial Statements for a description of operating lease, drilling contract, seismic contract and other contract obligations.

(3)

Amounts represent our estimate of future asset retirement obligations on an undiscounted basis. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 5 in the Notes to the Unaudited Condensed Consolidated Financial Statements.

Amounts related to our derivative financial instruments are not included in the table above. See Note 4 to our Condensed Consolidated Financial Statements as of and for the six months ended June 30, 2012.

Critical Accounting Policies and Estimates

We prepare our financial statements and the accompanying notes in conformity with GAAP, which requires our management to make estimates and assumptions about future events that affect the reported amounts in our financial statements and the accompanying notes. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity and the degree of difficulty, subjectivity and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Our management routinely discusses the development, selection and disclosure of each of the critical accounting policies. Following is a discussion of our most critical accounting policies:

Reserves Estimates. Effective December 31, 2009, we adopted revised oil and gas disclosure requirements set forth by the SEC in Release No. 33-8995, “Modernization of Oil and Gas Reporting” and as codified by the Financial Accounting Standards Board (FASB) in Accounting Standards Codification (ASC) Topic 932, “Extractive Industries—Oil and Gas.” The rules include changes to the pricing used to estimate reserves, the option to disclose probable and possible reserves, revised definitions for proved reserves, additional disclosures with respect to undeveloped reserves, and other revised definitions and disclosures.

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing operating conditions and government regulations.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

Reserves as of December 31, 2011, 2010 and 2009 were calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each month, held flat for the life of the production, except where prices are defined by contractual arrangements.

We have elected not to disclose probable and possible reserves or reserve estimates in this information statement.

Revenue Recognition. Our revenue recognition policy is significant because revenue is a key component of the results of operations and of the forward-looking statements contained in the analysis of liquidity and capital resources. We record revenue in the month our production is delivered to the purchaser, but payment is generally received 30 to 90 days after the date of production. At the end of each month, we estimate the amount of production that was delivered to the purchaser and the price that will be received. We use our knowledge of our properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other factors as the basis for these estimates. We record the variances between our estimates and the actual amounts received in the month payment is received.

Share-Based Compensation. We account for share-based compensation awards in accordance with FASB ASC 718, Compensation—Stock Compensation. We measure stock-based compensation cost at fair value and generally recognize the corresponding compensation expense on a straight-line basis over the service period during which awards are expected to vest. We include share-based compensation expense in “General and administrative expense” in our consolidated statements of operations.

For the periods presented, we recognized compensation expense prior to our initial public offering related to purchases and grants of shares of common stock in Midstates Petroleum Holdings, Inc., a subchapter S corporation (“Petroleum Inc.”), through which our founders, management and certain of our employees held their equity interest in us, and purchases of units of Midstates Petroleum Holdings LLC during 2011 by certain employees and members of management. In connection with the audit of our financial statements, we restated our historical financial statements to account for certain share-based awards made in prior years under liability accounting as required by FASB ASC 718. As a result, we were required upon the occurrence of certain events to determine the fair value of outstanding shares of Petroleum Inc. common stock and units of Midstates Petroleum Holdings LLC purchased or granted in 2011 and previous years still held by certain members of management and employees in order to “mark-to-market” the liability associated with those share-based awards. In November 2011, all outstanding restricted shares in Petroleum Inc. were vested. In December 2011, the provisions of certain employment and other agreements that required our share-based awards to be accounted for under liability accounting were either amended or terminated, and, as a result, we now apply equity accounting for all share-based awards.

Financial Instruments. Our financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivatives. Commodity derivatives are recorded at fair value. The carrying amount of our other financial instruments approximate fair value because of the short-term nature of the items or variable pricing.

Derivative financial instruments are recorded in our consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative’s fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recorded within revenues in “Gains (losses) on commodity derivative contracts—net.” The related cash flow impact is reflected within cash flows from operating activities.

Asset Retirement Obligations. We have significant obligations to remove tangible equipment and facilities associated with our oil and natural gas wells, and to restore land at the end of oil and natural gas production operations. The removal and restoration obligations are associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculations are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlements and changes in the legal, regulatory, environmental and political environments.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2011, 2010 and 2009. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate due to changes in supply and demand. To partially reduce price risk caused by these market fluctuations, we have hedged in the past and expect to hedge a significant portion of our future production.

We utilize derivative financial instruments to manage risks related to changes in oil prices. As of June 30, 2012, we utilized fixed price swaps, collars, deferred-premium puts and basis differential swaps to reduce the volatility of oil prices on a portion of our future expected oil production.

For derivative instruments recorded at fair value, the credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on the balance sheet.

The following is a summary of our commodity derivative contracts as of June 30, 2012:


	Hedged Volume		Weighted- Average Fixed Price ($)
Oil (Bbls):
WTI Swaps – 2012		411,100	$	84.36
WTI Swaps – 2013		679,125		84.73
WTI Swaps – 2014		262,450		83.00
WTI Collars – 2012		82,800		85.00 – 127.28
WTI Deferred Premium Puts – 2012 (1)		276,000		79.01
WTI Basis Differential Swaps – 2012 (2)		505,300		9.73
WTI Basis Differential Swaps – 2013 (2)		679,125		6.30
Louisiana Light Sweet Swaps – 2012		315,180		116.55
Brent Crude Swaps – 2013		1,021,749		111.89


	Six Months Ended June 30, 2012
	(in thousands)
Derivative fair value at period end—asset (included in the balance sheet)	$	17,925
Realized net (loss) gain (included in the statement of operations)	$	(11,679	)
Unrealized net (loss) gain (included in the statement of operations)	$	35,157

(1)	2012 deferred premium puts represent the net effective floor price of a put with a strike price of $85.00/Bbl and a deferred premium of $5.99/Bbl. The premiums for these instruments are paid each month, concurrently with the settlement of the monthly put contracts.

(2)	We enter into swap arrangements intended to capture the positive differential between LLS pricing and NYMEX WTI pricing.

As of June 30, 2012, December 31, 2011, 2010 and 2009, assets and liabilities recorded at fair value in the balance sheets were categorized based upon the level of judgment associated with the inputs used to measure their value. Our only financial assets and liabilities that are measured at fair value as of December 31, 2011, 2010 and 2009 are the derivative instruments discussed above. At June 30, 2012, December 31, 2011 and 2010, all of our commodity derivative contracts were with three, two and one bank counterparties, respectively, and are all classified as Level 2. Our policy is to net derivative liabilities and assets where there is a legally enforceable master netting agreement with the counterparty.

In July 2012, we entered into several commodity derivative transactions to closely align the reference prices of our commodity derivative prices to the actual prices received for oil production. On August 10, 2012, the we had the following open commodity positions:


	Hedged Volume		Weighted- Average Fixed Price ($)
Oil (Bbls):
WTI Swaps – 2012		644,130	$	95.75
WTI Swaps – 2013		1,700,874		95.55
WTI Swaps – 2014		262,450		83.00
WTI Collars – 2012		68,850		85.00 to 127.28
WTI Deferred Premium Puts – 2012 (1)		229,500		79.01
WTI Basis Differential Swaps – 2012 (2)		789,480		9.81
WTI Basis Differential Swaps – 2013 (2)		1,700,874		5.91

(1)	2012 deferred premium puts represent the net effective floor price of a put with a strike price of $85.00/Bbl and a deferred premium of $5.99/Bbl. The premiums for these instruments are paid each month, concurrently with the settlement of the monthly put contracts.

(2)	We enter into swap arrangements intended to capture the positive differential between LLS pricing and NYMEX WTI pricing.

Interest rate risk. At June 30, 2012, we had indebtedness outstanding under our credit facility of $151.7 million, which bore interest at floating rates. The average annual interest rate incurred on this indebtedness for the three months ended June 30, 2012 and June 30, 2011 was approximately 2.5% and 3.0%, respectively. The average annual interest rate incurred on this indebtedness for the six months ended June 30, 2012 and June 30, 2011 was approximately 2.9% and 2.8%, respectively. The average annual interest rate incurred on this indebtedness for the years ended December 31, 2011, 2010 and 2009 was approximately 3.2%, 3.0% and 3.3%, respectively. A 1.0% increase in each of the average LIBOR and federal funds rate for the three months ended June 30, 2012 and three months ended June 30, 2011 would have resulted in an estimated $0.4 million and $0.3 million, respectively, increase in interest expense, of which a portion may be capitalized. A 1.0% increase in each of the average LIBOR and federal funds rate for the six months ended June 30, 2012 and six months ended June 30, 2011 would have resulted in an estimated $1.0 million and $0.5 million, respectively, increase in interest expense, of which a portion may be capitalized. A 1.0% increase in each of the average LIBOR and federal funds rate for the years ended December 31, 2011 and 2010 would have resulted in an estimated $1.5 million and $0.6 million, respectively, increase in interest expense, of which a portion may be capitalized.

We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. See “Business—Marketing and Major Customers” for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties.

While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such counterparties as we

deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits. The counterparties on our derivative instruments currently in place are lenders under our revolving credit facility with investment grade ratings, and we are likely to enter into any future derivative instruments with these or other lenders under our revolving credit facility which also carry investment grade ratings. Several of our significant customers for oil and gas receivables have a credit rating below investment grade or do not have rated debt securities. In these circumstances, we have considered the lack of investment grade credit rating in addition to the other factors described above.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements.

WHERE YOU CAN FIND MORE INFORMATION

We file periodic reports, proxy and information statements and other information with the SEC in accordance with the requirements of the Exchange Act. Our SEC filings are available to the public over the Internet at the SEC’s web site at www.sec.gov. You also may read and copy any document we file at the SEC’s public reference room in Washington, D.C. Please call the SEC at 1-800-SEC-0330 for further information about the public reference room. Our Common Stock is listed and traded on the New York Stock Exchange under the trading symbol “MPO.”

You may request a copy of our filings with the SEC at no cost, by making written or telephone requests for such copies to:

Midstates Petroleum Company, Inc.

Attention: Investor Relations

4400 Post Oak Parkway

Suite 1900

Houston, Texas 77027

(713) 595-9400

You should rely only on the information provided in this filing. You should not assume that the information in this information statement is accurate as of any date other than the date of this document. We have not authorized anyone else to provide you with any information.

STOCKHOLDERS SHARING AN ADDRESS

We will deliver only one information statement to multiple stockholders sharing an address unless we have received contrary instructions from one or more of the stockholder. We undertake to deliver promptly, upon written or oral request, a separate copy of this information statement to a stockholder at a shared address to which a single copy of the information statement is delivered. A stockholder can notify us that the stockholder wishes to receive a separate copy of the information statement by contacting us at the address or phone number set forth above. Conversely, if multiple stockholders sharing an address receive multiple information statements and wish to receive only one, such stockholders can notify us at the address or phone number set forth above.

INDEX TO FINANCIAL STATEMENTS


Midstates Petroleum Holdings LLC

Report of independent registered public accounting firm			F-2
Consolidated balance sheets as of December 31, 2011 (Restated) and 2010 (Restated)			F-3
Consolidated statements of operations for the years ended December 31, 2011 (Restated), 2010 (Restated) and 2009 (Restated)			F-4
Consolidated statement of members’ equity for the years ended December 31, 2011 (Restated), 2010 (Restated) and 2009 (Restated)			F-5
Consolidated statements of cash flows for the years ended December 31, 2011 (Restated), 2010 (Restated) and 2009 (Restated)			F-6
Notes to consolidated financial statements			F-7

Midstates Petroleum Company, Inc.

Unaudited condensed consolidated balance sheets as of June 30, 2012 and December 31, 2011			F-31
Unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2012 and 2011			F-32
Unaudited condensed consolidated statement of members’ equity for the six months ended June 30, 2012			F-33
Unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2012 and 2012			F-34
Notes to unaudited condensed consolidated financial statements			F-35

Eagle Energy Company of Oklahoma, LLC

Report of independent auditors			F-54
Consolidated balance sheets as of December 31, 2011 and 2010			F-55
Consolidated statements of income for the years ended December 31, 2011 and 2010 and for the period from December 11, 2009 through December 31, 2009			F-56
Consolidated statements of changes in members’ equity for the years ended December 31, 2011 and 2010 and for the period from December 11, 2009 through December 31, 2009			F-57
Consolidated statements of cash flows for the years ended December 31, 2011 and 2010 and for the period from December 11, 2009 through December 31, 2009			F-58
Notes to consolidated financial statements			F-59

Eagle Energy Company of Oklahoma, LLC

Unaudited condensed consolidated balance sheets as of June 30, 2012 and December 31, 2011			F-77
Unaudited condensed consolidated statements of income for the six months ended June 30, 2012 and June 30,			F-78
Unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2012			F-79
Notes to unaudited condensed consolidated financial			F-80

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Midstates Petroleum Company, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Midstates Petroleum Holdings, LLC and subsidiary (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Midstates Petroleum Holdings, LLC and subsidiary as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted new accounting guidance on December 31, 2009 related to the estimation of oil and gas reserves.

As discussed in Note 11, the accompanying 2009, 2010 and 2011 financial statements have been restated to correct an error.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 1, 2012

(April 9, 2012 as to the note on Subsequent Events and the effect of the restatement of the 2009, 2010 and 2011 financial statements discussed in Note 11)

F-2

Midstates Petroleum Holdings LLC

Consolidated Balance Sheets


	December 31, 2011			December 31, 2010
	(In thousands)
	(As restated) (1)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7,344		$	11,917
Accounts receivable:
Oil and gas sales		23,792			14,141
Severance tax refund		3,413			—
Other		249			537
Prepayments		2,642			383
Inventory		5,713			1,173
Commodity derivative contracts		4,957			—

Total current assets		48,110			28,151

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting:
Proved properties		644,393			351,544
Unevaluated properties		76,857			101,366
Other property and equipment		1,672			1,360
Less accumulated depreciation, depletion, and amortization		(148,843	)		(57,144	)

Net property and equipment		574,079			397,126

OTHER ASSETS:
Commodity derivative contracts		588			—
Security deposit and other noncurrent assets		1,879			1,727

Total other assets		2,467			1,727

TOTAL	$	624,656		$	427,004

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$	73,255		$	42,619
Commodity derivative contracts		12,599			12,657

Total current liabilities		85,854			55,276

LONG-TERM LIABILITIES:
Asset retirement obligations		7,627			2,859
Commodity derivative contracts		10,178			16,464
Long-term debt		234,800			89,600
Other long-term liabilities		695			6,926

Total long-term liabilities		253,300			115,849

COMMITMENTS AND CONTINGENCIES (Note 10)
MEMBERS’ EQUITY (including $0 and $47 million of preferred units, respectively)		285,502			255,879

TOTAL	$	624,656		$	427,004

Unaudited pro forma amount of undistributed earnings to be reclassified to paid to capital upon completion of the offering	$	17,122

(1)	See Note 11.

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

F-3

Midstates Petroleum Holdings LLC

Consolidated Statements of Operations


	Years ended December 31,
	2011			2010			2009
	(As restated) (1)			(As restated) (1)			(As restated) (1)
REVENUES:
Oil sales	$	177,464		$	75,875		$	27,347
Natural gas sales		20,665			10,505			2,683
Natural gas liquid sales		15,683			2,731			103
Losses on commodity derivative contracts — net		(4,844	)		(26,268	)		(5,987	)
Other		465			209			108

Total revenues		209,433			63,052			24,254

EXPENSES:
Lease operating		15,234			8,733			5,312
Workover		2,101			4,683			5,226
Severance tax		12,422			6,431			2,849
Asset retirement accretion		334			175			120
General and administrative		68,915			16,847			5,886
Depreciation, depletion, and amortization		91,699			41,827			12,322
Impairment in carrying value of oil and natural gas properties		—			—			4,297

Total expenses		190,705			78,696			36,012

OPERATING INCOME (LOSS)		18,728			(15,644	)		(11,758	)

OTHER INCOME
Interest income		23			9			6
Interest expense — net of amounts capitalized		(2,094	)		—			—

NET INCOME (LOSS)	$	16,657		$	(15,635	)	$	(11,752	)

Unaudited pro forma income tax provision (benefit)	$	23,156		$	(6,318	)	$	(4,592	)

Unaudited pro forma net loss	$	(6,499	)	$	(9,317	)	$	(7,160	)

Unaudited pro forma basic and diluted loss per share	$	(0.10	)	$	(0.14	)	$	(0.11	)
Unaudited pro forma basic and diluted weighted average shares outstanding		65,634,353			65,634,353			65,634,353

(1)	See Note 11.

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

F-4

Midstates Petroleum Holdings LLC

Consolidated Statement of Members’ Equity


BALANCE—January 1, 2009	$	192,006
Members’ contribution (net of $3.0 million related to the issuance of unrestricted shares in Petroleum Inc. for cash and initially treated as a liability award. See Note 7)		55,080
Net loss		(11,752	)

BALANCE—December 31, 2009 (As restated, see Note 11)		235,334
Members’ contribution (net of $2.17 million related to the issuance of unrestricted shares in Petroleum Inc. for cash and initially treated as a liability award. See Note 7)		—
Preferred equity units issued (see Note 7)		36,180
Preferred units converted from common units (see Note 7)		5,080
Common units converted to preferred units (see Note 7)		(5,080	)
Net loss		(15,635	)

BALANCE—December 31, 2010 (As restated, see Note 11)		255,879
Distribution to members—preferred equity units		(47,000	)
Distribution to members—return on preferred equity units		(3,572	)
Members’ contribution (includes $2.7 million related to the issuance of unrestricted units of the Company for cash and initially treated as a liability award. See Note 7)		2,870
Reclassification of liability for share-based awards related to the transition from liability to equity accounting (see Note 7)		60,668
Net income		16,657

BALANCE—December 31, 2011 (As restated, see Note 11)	$	285,502

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

F-5

Midstates Petroleum Holdings LLC

Consolidated Statements of Cash Flows


	Years ended December 31,
	2011			2010			2009
	(As restated) (1)			(As restated) (1)			(As restated) (1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	16,657		$	(15,635	)	$	(11,752	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized (gains) losses on commodity derivative contracts, net		(11,889	)		25,398			7,283
Asset retirement accretion		334			175			120
Depreciation, depletion, and amortization		91,699			41,827			12,363
Impairment in carrying value of oil and natural gas properties		—			—			4,297
Share-based compensation		53,744			1,518			234
Change in operating assets and liabilities:
Accounts receivable — oil and gas sales		(9,651	)		(10,355	)		(1,459	)
Accounts receivable — other		(3,125	)		(452	)		515
Prepayments and other assets		(2,259	)		2,290			(2,645	)
Inventory		(4,540	)		(65	)		568
Accounts payable, accrued liabilities, and other		9,730			5,753			1,071
Other		—			314			—

Net cash provided by operating activities		140,700			50,768			10,595

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment		(242,619	)		(139,618	)		(72,237	)
Investment in acquired property		—			—			(3,017	)
Other (including escrowed deposit)		(152	)		—			39

Net cash used in investing activities		(242,771	)		(139,618	)		(75,215	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		145,200			60,000			13,000
Repayment of long-term borrowings		—			(200	)		(5,000	)
Cash received for units		2,870			38,350			58,080
Distributions to members		(50,572	)		—			—
Other		—			(1,736	)		(321	)

Net cash provided by financing activities		97,498			96,414			65,759


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(4,573	)		7,564			1,139

Cash and cash equivalents, beginning of year		11,917			4,353			3,214

Cash and cash equivalents, end of year	$	7,344		$	11,917		$	4,353

SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued — not paid	$	61,590		$	36,022		$	8,688

Cash paid for interest net of capitalized interest of $2.6 million, $1.7 million, and $0.8 million, respectively	$	1,594		$	—		$	—

Reclassification of liability for share-based compensation to member’s equity (see Note 7)	$	6,924		$	—		$	—

(1)	See Note 11.

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

F-6

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Holdings LLC (the “Company”) and its wholly owned subsidiary, Midstates Petroleum Company LLC (“Subsidiary”), engages in the business of the drilling for and production of oil, natural gas and natural gas liquids. The Company currently has oil and gas operations solely in the state of Louisiana.

At December 31, 2011, the Company is 76.73% owned by FR Midstates Holdings LLC (“FR Midstates”) and 22.64% owned by Midstates Petroleum Holdings, Inc. (“Petroleum Inc.”), through which the Company’s founders, management and certain employees hold their equity interests, and 0.63% owned by certain members of management and employees.

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Company include the accounts of the Company and Subsidiary. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and reflect, in the opinion of the Company’s management, all adjustments necessary to present fairly the financial position as of, and the results of operations for, the periods presented. All intercompany transactions have been eliminated in consolidation.

The Company operates its oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. The Company’s management evaluates performance based on one business segment as there are not different economic environments within the operation of the Company’s oil and natural gas properties.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include, but are not limited to, the amount of recoverable oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; the fair value of commodity derivative contracts; the fair value of share-based compensation; and the valuation of future asset retirement obligations.

Cash and Cash Equivalents

The Company considers all short-term investments with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of allowance for uncollectible accounts. The carrying amount of the Company’s accounts receivable approximate fair value because of the short-term nature of the instruments. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2011 and 2010, the Company had no allowance for doubtful accounts.

F-7

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Oil and Natural Gas Properties

The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Historically, total capitalized internal costs in any given period have not been material to total oil and gas costs capitalized in such period. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities are sold, in which case a gain or loss is generally recognized in income.

For the years ended December 31, 2011, 2010 and 2009, depletion expense related to oil and gas properties was $91.4 million, $41.6 million and $12.1 million, respectively and $33.40, $29.85 and $19.79 per barrel of oil equivalent (“Boe”), respectively.

Unevaluated Property

Oil and gas unevaluated properties and properties under development include costs that are not being depleted or amortized. These costs represent investments in unproved properties. The Company excludes these costs until proved reserves are found, until it is determined that the costs are impaired or until major development projects are placed in service, at which time the costs are moved into oil and natural gas properties subject to amortization. All unproved property costs are reviewed at least annually to determine if impairment has occurred.

Oil and Gas Reserves

Proved oil and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB), which subsequent to December 31, 2008 require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. The Company’s reserve estimates at December 31, 2011, 2010 and 2009 were prepared by a third-party petroleum engineer, Netherland, Sewell & Associates, Inc. (“NSAI”). Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company depletes its oil and gas properties using the units-of-production method. Capitalized costs of oil and natural gas properties subject to amortization are depleted over proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property and Equipment

Other property and equipment consists of vehicles, furniture and fixtures, and computer hardware and software and are carried at cost. Depreciation is provided principally using the straight-line method over the estimated useful lives of the assets, which range from five to seven years. Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized. For the years ended December 31, 2011, 2010 and 2009, depreciation expense related to other property and equipment was $0.3 million, $0.2 million and $0.2 million, respectively.

F-8

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Impairment of Oil and Gas Properties/Ceiling Test

The Company’s historical policy as a privately-owned company has been to perform a ceiling test on an annual basis. However, beginning September 30, 2011, the ceiling test is performed on a quarterly basis. The test establishes a limit (ceiling) on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization (DD&A) and the related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of: (i) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged to expense in the accompanying consolidated statements of operations.

For the year ended December 31, 2011 and 2010, capitalized costs did not exceed the ceiling and no impairment to oil and gas properties was required. In calculating the ceiling test for the year ended December 31, 2009, the Company identified that capitalized costs exceeded the ceiling and impaired oil and gas properties by $4.3 million.

Depreciation, Depletion, and Amortization (DD&A)

DD&A of oil and gas properties is calculated using the Units of Production Method (UOP). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced by the cost of those reserves. The result is to recognize expense at the same pace that the reservoirs are estimated to be depleting. The amortization base in the UOP calculation includes the sum of proved property costs net of accumulated DD&A, estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value.

Revenue Recognition

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred and collection of the revenues is reasonably assured. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

The Company follows the sales method of accounting for oil and gas revenues, whereby revenue is recognized for all oil and gas sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil and gas reserves. The Company had no significant imbalances at December 31, 2011 or 2010.

Income Taxes

The Company is not a taxpaying entity for federal income tax purposes and, accordingly, it does not recognize any expense for such taxes. The income tax liability resulting from the Company’s activities is the responsibility of the Company’s members. In the event of an examination of the Company’s tax return, the tax liability of the members could be changed if an adjustment of the Company’s income or loss is ultimately sustained by the taxing authorities.

F-9

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

The unaudited pro forma income tax provision (benefit) on the consolidated statements of operations reflects the effect of the Company’s anticipated initial public offering. After consummation, the Company will be subject to U.S. federal and certain state income taxes. The 2011 pro forma effective tax rate of 139% differs from the expected federal statutory rate of 35% due to state income taxes of up to 8.0% (or 5.2%, net of the federal benefit for the year ended December 31, 2011) and certain permanent differences related to the valuation of share-based compensation expense. The 2010 and 2009 pro forma effective tax rate reflected herein differs from the expected federal statutory rate of 35% due to state income taxes of up to 8.0% (or 3.9%, net of federal benefit, for the years ended December 31, 2010 and 2009.). For 2010 and 2009, presented, there were no material permanent differences, with the exception of the year ended December 31, 2010, which included an adjustment for percentage of depletion for tax purposes in excess of book of approximately 2.9%. No valuation allowance was deemed necessary due to the presence of future net taxable amounts in excess of deferred tax assets; management placed no reliance on other future taxable income.

The Company, on a pro forma basis, would have recorded a tax provision during the year ended December 31, 2011 of $23.2 million (unaudited). The Company, on a pro forma basis, would have recorded a tax benefit during the years ended December 31, 2010 and 2009 of $(6.3) million (unaudited) and $(4.6) million (unaudited), respectively.

In addition, on a pro forma basis, a recalculation of the ceiling test during the year ended December 31, 2010 on an after-tax basis would have resulted in an impairment of $36.3 million (unaudited). The pro forma recalculation of the ceiling test for the years ended December 31, 2011 and 2009 on an after tax basis did not indicate any additional impairment.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, debt, and commodity derivative contracts. Commodity derivative contracts are recorded at fair value (see Note 3). The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The carrying amount of the Company’s other financial instruments approximate fair value because of the short-term nature of the items or variable pricing.

Derivative financial instruments are recorded in the consolidated balance sheets as either an asset or liability measured at estimated fair value. Changes in the derivative’s fair value are recognized currently in earnings as gains and losses in the period of change. The gains or losses are recorded in “Gains (losses) on commodity derivative contracts—net.” The related cash flow impact is reflected within cash flows from operating activities.

Asset Retirement Obligations

The legal obligations associated with the retirement of long-lived assets are recognized at estimated fair value at the time that the obligation is incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. The Company estimates the fair value of an asset retirement obligation in the period in which the obligation is incurred and can be reliably measured. The corresponding asset retirement cost is capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, any adjustment is recorded in the full cost pool. See Note 5.

F-10

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Capitalized Interest

Interest from external borrowings is capitalized on unevaluated properties using the weighted-average cost of outstanding borrowings until the project is substantially complete and ready for its intended use, which for oil and gas assets is at the first production from the field. Capitalized interest is depleted over the useful lives of the assets in the same manner as the depletion of the underlying assets. For the years ended December 31, 2011, 2010 and 2009, interest capitalized to unevaluated properties was $2.6 million, $1.7 million and $0.8 million, respectively.

Pro Forma Financial Information

The pro forma balance sheet information as of December 31, 2011 reflects the pro forma reclassification of undistributed gains to paid-in capital as a result of the Company no longer being a limited liability company upon closing of the offering. Simultaneously with the closing of the offering, all members’ equity will be exchanged for common stock of Midstates Petroleum Company, Inc. through a constructive distribution to the owners, followed by a contribution to capital of the corporate entity.

The pro forma statements of operations information for all periods presented reflects the impact of Midstates’ change in capital structure as if it had occurred at the beginning of the earliest period presented. Pro forma net income (loss) per basic and diluted share is determined by dividing the pro forma net income (loss) by the number of common shares expected to be outstanding immediately following the offering.

Subsequent Events

The Company has evaluated subsequent events through February 1, 2012, the date the consolidated financial statements were issued.

3. Fair Value Measurements of Financial Instruments

The Company uses a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further divided into the following fair value input hierarchy:

Level 1—Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

Level 2—Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are commodity derivative contracts with fair values based on inputs from actively quoted markets. The Company uses a market approach to estimate the fair values of its commodity derivative contracts, utilizing commodity futures price strips for the underlying commodities provided by a reputable third-party.

Level 3—Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

Assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

F-11

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments—Commodity derivative contracts reflected in the consolidated balance sheets are recorded at estimated fair value.

At December 31, 2011 and 2010, all of the Company’s commodity derivative contracts were with two and one bank counterparties, respectively, and are classified as Level 2.


	Fair Value Measurements at December 31, 2011
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	—	$	—	$	—
Commodity derivative deferred premium puts		—		1,673		—		1,673
Commodity derivative collars		—		397		—		397
Commodity derivative differential swaps		—		4,200		—		4,200

Total assets		—		6,270		—		6,270

Liabilities:
Commodity derivative oil swaps		—		23,162		—		23,162
Commodity derivative deferred premium puts		—		340		—		340
Commodity derivative collars		—		—		—		—
Commodity derivative differential swaps		—		—		—		—

Total liabilities	$	—	$	23,502	$	—	$	23,502

	Fair Value Measurements at December 31, 2010
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	—	$	—	$	—
Commodity derivative deferred premium puts		—		—		—		—
Commodity derivative collars		—		—		—		—

Total assets		—		—		—		—

Liabilities:
Commodity derivative oil swaps		—		27,735		—		27,735
Commodity derivative deferred premium puts		—		1,386		—		1,386
Commodity derivative collars		—		—		—		—

Total liabilities	$	—	$	29,121	$	—	$	29,121

Derivative instruments listed above are presented gross and include collars, swaps, and put options that are carried at fair value. The Company records the net change in the fair value of these positions in “Gains (losses) on commodity derivative contracts—net” in the Company’s consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company classifying its derivatives as Level 2 instruments. This observable data includes the forward curve for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves.

F-12

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

For additional information on the Company’s derivative instruments and balance sheet presentation, see Note 4.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Retirement Obligations (ARO’s)—The Company estimates the fair value of ARO’s based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, the amount and timing of settlements, the credit-adjusted risk-free rate and inflation rates. See Note 5 for a summary of changes in ARO’s.

4. Risk Management and Derivative Instruments

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. Management believes it is prudent to manage the variability in cash flows by entering into derivative financial instruments to economically hedge a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and options, to manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are generally placed with major financial institutions that the Company believes are minimal credit risks. The oil and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at December 31, 2011 would have been approximately $5.5 million.

Commodity Derivative Contracts

The Company uses commodity derivative contracts to manage its exposure to commodity price volatility.

F-13

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

As of December 31, 2011, the Company had the following open commodity positions:


	Hedged Volume		Weighted- Average Fixed Price
Oil (Bbls):
Swaps – 2012		893,400	$	84.16
Swaps – 2013		679,125		84.73
Swaps – 2014		262,450		83.00

Collars – 2012		164,700	$	85.00 – $127.28

Deferred Premium Puts – 2012 (1)		549,000	$	79.01

Basis Differential Swaps – 2012 (2)		1,134,600	$	9.78
Basis Differential Swaps – 2013 (2)		182,500		7.50

(1)	2012 deferred premium puts represent the net effective floor price of a put with a strike price of $85.00/Bbl and a deferred premium of $5.99/Bbl. The premiums for these instruments are paid each month, concurrently with the settlement of the monthly put contracts.

(2)	We enter into swap arrangements intended to capture the positive differential between LLS pricing and NYMEX WTI pricing.

Balance Sheet Presentation

The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s consolidated balance sheets at December 31, 2011 and 2010, respectively (in thousands):


Type	Balance Sheet Location (1)	December 31, 2011			December 31, 2010
Oil Swaps	Derivative financial instruments —Current Assets	$	—			—
Oil Swaps	Derivative financial instruments —Non-Current Assets		—			—
Oil Swaps	Derivative financial instruments — Current Liabilities		(13,046	)		(11,394	)
Oil Swaps	Derivative financial instruments —Non-Current Liabilities		(10,116	)		(16,341	)
Deferred Premium Puts	Derivative financial instruments — Current Assets		1,673			—
Deferred Premium Puts	Derivative financial instruments — Non-Current Assets		—			—
Deferred Premium Puts	Derivative financial instruments — Current Liabilities		(278	)		(1,263	)
Deferred Premium Puts	Derivative financial instruments —Non-Current Liabilities		(62	)		(123	)
Collars	Derivative financial instruments — Current Assets		397			—
Collars	Derivative financial instruments — Non-Current Assets		—			—
Collars	Derivative financial instruments — Current Liabilities		—			—
Collars	Derivative financial instruments —Non-Current Liabilities		—			—
Basis Differential Swaps	Derivative financial instruments — Current Assets		3,612			—
Basis Differential Swaps	Derivative financial instruments — Non-Current Assets		588			—
Basis Differential Swaps	Derivative financial instruments — Current Liabilities		—			—
Basis Differential Swaps	Derivative financial instruments —Non-Current Liabilities		—			—

Total		$	(17,232	)	$	(29,121	)

F-14

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

(1)

The fair value of derivative instruments reported in the Company’s consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net derivative fair values as reported in the Company’s consolidated balance sheets as of December 31, 2011 and 2010, respectively (in thousands):


	December 31, 2011			December 31, 2010
Consolidated balance sheet classification:
Current derivative instruments:
Assets	$	4,957		$	—
Liabilities		(12,599	)		(12,657	)

Non-current derivative instruments:
Assets		588			—
Liabilities		(10,178	)		(16,464	)

Gains (Losses) on Commodity Derivative Contracts

The Company does not designate its commodity derivative contracts as hedging instruments for financial reporting purposes. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in “Gains (losses) on commodity derivative contracts—net”, within revenues in the consolidated statements of operations.

For the years ended December 31, 2011, 2010 and 2009, the Company realized net gains (losses) of ($16.7) million, ($0.9) million and $1.3 million, respectively.

For the years ended December 31, 2011, 2010 and 2009, the Company recorded net unrealized gains (losses) of $11.9 million, ($25.4) million and ($7.3) million, respectively, related to the change in fair value of the derivative financial instruments in “Gains (losses) on commodity derivative contracts—net.”

5. Asset Retirement Obligation

For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the asset retirement obligation at inception is capitalized as part of the carrying amount of the related long-lived assets. Asset retirement obligations approximated $7.6 million and $2.9 million as of December 31, 2011 and 2010, respectively.

The liability has been accreted to its present value as of December 31, 2011 and 2010. The Company evaluated its wells and determined a range of abandonment dates through 2058.

The following table details the change in the asset retirement obligations for the years ended December 31, 2011, 2010 and 2009, respectively (in thousands):


	Year ended December 31, 2011			Year ended December 31, 2010			Year ended December 31, 2009
Asset retirement obligations at the beginning of the year	$	2,859		$	2,274		$	1,828
Liabilities incurred		1,294			474			341
Revisions		3,196			—			—
Liabilities settled		(56	)		(64	)		(15	)
Current period accretion expense		334			175			120

Asset retirement obligations at the end of the year	$	7,627		$	2,859		$	2,274

F-15

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Revisions during the year ended December 31, 2011 were due to an increase in estimated future abandonment costs based upon actual well abandonment costs incurred during the year that were higher than previous estimates due to higher oilfield service pricing.

6. Long-Term Debt

The Company’s long-term debt as of December 31, 2011 and 2010, is as follows (in thousands):


	December 31, 2011		December 31, 2010
Credit Facility—senior loan facility	$	234,800	$	89,600

As of December 31, 2011, the Company’s credit facility consisted of a $300 million senior revolving credit facility (the “Facility”) with a borrowing base of $235 million. The Facility has a maturity date of December 10, 2014. Borrowings under the Facility are secured by substantially all of the Company’s oil and natural gas properties. Borrowings under the Facility currently bear interest at LIBOR plus an applicable margin between 2.00% and 2.75% per annum. At December 31, 2011 and 2010, the weighted-average interest rate was 3.2% and 3.0%, respectively.

In addition to interest expense, the credit agreement requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of 0.5% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

The borrowing base is subject to semiannual redeterminations in March and September. The terms of the Facility can require monthly repayments to the extent that monthly borrowing base reductions or borrowing base redeterminations cause the outstanding borrowings to exceed the availability under the Facility.

The Facility contains financial covenants, which, among other things, set a maximum ratio of debt to earnings before income tax, depletion, depreciation, and amortization (EBITDA) of not more than 3.75 to 1, a minimum current ratio (as defined therein) of not less than 1.0 to 1.0 and various other standard affirmative and negative covenants including, but not limited to, restrictions on our ability to make any dividends, distributions or redemptions.

The Company is in compliance with the financial debt covenants set forth in the credit agreement.

7. Members’ Equity and Share-Based Compensation

Common and Preferred Units

The Company, FR Midstates, and Petroleum Inc. are parties to a Third Amended and Restated Limited Liability Company Agreement (the “Third Amended LLC Agreement”) entered into as of December 15, 2011, under which certain common and mandatorily redeemable convertible preferred units (the “New Preferred Units”) of the Company are authorized for issuance. Common and New Preferred Units each have the same voting rights. New Preferred Units require an investment of $1,000 per unit. Common units may be issued at a price determined by the Board in its sole discretion, provided that, as long as there are New Preferred Units outstanding that may be converted into common units, such price will not be less than $1,000 per common unit.

During the year ended December 31, 2010, there were 255,138 common units issued and outstanding. During the year ended December 31, 2011, 1,604 common units were purchased for cash by members of management and no units were retired, resulting in 256,742 common units issued and outstanding at December 31, 2011.

F-16

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Second Amended and Restated Limited Liability Agreement

Prior to December 15, 2011, the Company, FR Midstates, and Petroleum Inc. were parties to the Second Amended and Restated Limited Liability Agreement which allowed for the issuance of common and preferred units. At January 1, 2010, there were no preferred units issued or outstanding. In June 2010, the Company authorized the issuance of redeemable convertible preferred units (the “Preferred Units”) and concurrently, 5,080 common units previously issued in 2009 were converted to Preferred Units. Any outstanding Preferred Units were classified as members’ equity in the Company’s consolidated balance sheets as they are not mandatorily redeemable.

During the year ended December 31, 2010, 47,000 Preferred Units were issued and outstanding. During the year ended December 31, 2011, all 47,000 Preferred Units issued and outstanding were retired by payment of a distribution to members, including interest, of approximately $50.6 million. There were no additional issuances of Preferred Units during the year ended December 31, 2011, and there were no Preferred Units outstanding at December 31, 2011.

Third Amended and Restated Limited Liability Agreement

Pursuant to the Third Amended LLC Agreement, the Company may issue up to 40,000 New Preferred Units, or $40,000,000 in aggregate value, between December 15, 2011 and June 10, 2015. The New Preferred Units have a liquidation value of $1,000 per unit and bear interest, compounded quarterly, at a rate of 8% plus the greater of LIBOR or 1.5%. The New Preferred Units are convertible on or after the one year anniversary of the date of issuance into a number of common units with a fair market value (as determined by the Board) equal to the liquidation value plus any accrued interest and are redeemable for cash at any time at the option of the Company, but are mandatorily redeemable for cash on June 10, 2015, unless otherwise converted. In addition, a fixed interest charge of 1.5% of the aggregate capital invested in the New Preferred Units is payable upon redemption or conversion. At December 31, 2011, there were no New Preferred Units issued or outstanding. Due to the mandatory redemption feature, any future issuances of New Preferred Units will be classified as a liability in the Company’s consolidated balance sheets.

Share-Based Compensation

During the periods presented, certain restricted and unrestricted shares in Petroleum Inc., certain unrestricted units in the Company, and certain units in Midstates Incentive Holdings, LLC (“Midstates Incentive”) had been issued to employees of the Company.

Prior to December 5, 2011, due to certain rights to call shares and units in the Company for cash, the Company’s share-based payments awarded to employees were accounted for as liability awards pursuant to ASC Topic 718, “Compensation—Stock Compensation.” As such, the Company calculated the fair value of the share-based awards on a quarterly basis using the Company’s estimated market value and the total fair value of the awards was recorded within “Other long-term liabilities” in the Company’s consolidated balance sheets. Any changes in the fair value of the liability awards was recorded as share-based compensation expense within “General and administrative expense” in the Company’s consolidated statements of operations, which was the same line item as cash compensation paid to the same employees.

Historically, the Company’s determination of the fair value of each of the units was affected by: i) the Company’s risk adjusted proved, possible, and probable reserves; ii) internal assessment of long-term commodity prices; iii) current values of the Company’s non-oil and gas assets and liabilities; and iv) a number of complex

F-17

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

and subjective variables. Although the fair value of the share-based payments is determined in accordance with GAAP, that value may not be indicative of the fair value observed in a market transaction between a willing buyer and a willing seller.

Effective as of November 22, 2011 (the “Effective Date”), the Board of Directors of Petroleum Inc. accelerated the vesting of all restricted stock in Petroleum Inc. The vesting resulted in the recognition of previously unrecognized share-based compensation expense at the estimated fair market value of the restricted stock held by employees at the Effective Date. Petroleum Inc. determined the fair market value of Petroleum Inc.’s common stock based on management’s estimates.

On December 5, 2011, Employment Agreements with employees of Subsidiary, a Stockholders’ Agreement by and among stockholders in Petroleum Inc. and a Unitholders’ Agreement by and among the members of the Company were either terminated or amended such that, following such terminations and amendments, no purchase option of Petroleum Inc. or the Company will be exercisable before 6 months and a day after the employee has been exposed to the risks and rewards of ownership of either the common stock of Petroleum Inc. or common units of the Company, and any such repurchase will be executed at fair value on the date of repurchase. The result of these terminations and amendments is a transition as of December 5, 2011 from liability accounting to equity accounting for the Company’s share-based compensation plans and accordingly, the Company will no longer recognize changes in estimated fair value of outstanding share based awards in the income statement. The Company increased members’ equity by a total of $63.4 million (comprised of $60.7 million related to shares and units issued prior to 2011, and $2.7 million related to units issued during 2011 and included in Members’ contributions in the Consolidated Statement of Members’ Equity), which represented the estimated fair value of the awards as of December 5, 2011, and decreased other long-term liabilities by the same amount to account for the change to equity accounting.

The following table summarizes share-based compensation expense recognized by the Company for shares in Petroleum Inc. and the Company’s common units for the years ended December 31, 2011, 2010 and 2009 (in thousands):


	Year Ended December 31, 2011		Year Ended December 31, 2010		Year Ended December 31, 2009
Restricted and unrestricted shares and units and Acceleration of vesting of restricted units	$	53,744	$	1,518	$	234
Incentive units		—		—		—

Total non-cash compensation expense	$	53,744	$	1,518	$	234

Restricted Shares.

Restricted shares in Petroleum Inc. were awarded at no cost to the recipient with a vesting period that commenced on the grant date and terminated on the fifth anniversary or upon certain changes in control of the Company, including but not limited to mergers, acquisitions, or a public offering (a “Triggering Event”).

As a result of the vesting discussed above, there is no unrecognized compensation cost and there are no outstanding restricted shares in Petroleum Inc. as of December 31, 2011.

F-18

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

The table below summarizes activity relating to the restricted shares held in Petroleum, Inc. During all periods presented, there were no restricted common units of the Company outstanding:


	Restricted Shares
Outstanding at January 1, 2009		—
Granted		59.1
Vested		—
Forfeited		—

Outstanding at December 31, 2009		59.1
Granted		42.7
Vested		—
Forfeited		—

Outstanding at December 31, 2010		101.8
Granted		24.6
Vested (see above)		(115.6	)
Forfeited		(10.8	)

Outstanding at December 31, 2011		—

Unrestricted Shares and Units.

Unrestricted shares and Company units are purchased by the recipient on the grant date and are fully vested upon purchase, or represent restricted shares which have vested. For shares and Company units purchased, any difference between the recipient’s purchase price and the grant date fair value is recognized as compensation expense on the grant date.

The following table summarizes the weighted average grant-date fair value and intrinsic value of the vested unrestricted shares and units outstanding as of December 31, 2011 and 2010. There are no restricted units in the Company:


	December 31, 2011		December 31, 2010
Unrestricted Shares (held in Petroleum Inc.)
Number of vested shares		196.8		71.5
Weighted average grant date fair value per share	$	75,908	$	74,825
Aggregate net change from grant date fair value	$	44,138,021	$	391,463
Total value	$	59,076,715	$	3,530,954

Unrestricted Units (held in the Company)
Number of vested units		1,605		—
Weighted average grant date fair value per unit	$	791	$	—
Aggregate net change from grant date fair value	$	3,494,420	$	—
Total value	$	4,763,817	$	—

Incentive Units.

As of December 31, 2011, 1,666 Class A and Class B incentive units were issued and outstanding. Upon the occurrence of certain changes of control of the Company, including a sale by FR Midstates of 100% of its interest in the Company, a sale of all or substantially all of the assets of the Company, or a merger resulting in a change in majority ownership (each, a “Vesting Event”), holders of incentive units shall receive out of proceeds

F-19

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

otherwise distributable to FR Midstates a percentage interest in the amounts distributed to FR Midstates in excess of certain multiples of FR Midstates’ aggregate capital contributions and investment expenses (“FR Midstates’ Profits”). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FR Midstates and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the Class A and Class B incentive units. To date, no compensation expense related to the incentive units has been recognized by the Company, as the occurrence of a Vesting Event is not considered probable, and thus, the amount of FR Midstates’ Profits, if any, cannot be determined.

8. Related Party Transactions

A minority owner of Petroleum Inc. is a significant owner of one of the Company’s vendors. For the years ended December 31, 2011, 2010 and 2009, the amount paid to this vendor was $2.0 million, $1.0 million and $0.6 million, respectively. The amount payable at December 31, 2011 and 2010 was $0.1 million and $0.1 million, respectively.

9. Concentrations of Credit Risk and Significant Customers

Financial instruments which potentially subject the Company to credit risk consist primarily of cash balances, accounts receivable and derivative financial instruments.

The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company.

The Company normally sells production to a relatively small number of purchasers, as is customary in the exploration, development and production business. The Company typically sells a substantial portion of production under short-term (usually one month) contracts tied to a local index. The Company does not have any long-term, fixed-price sales contracts. For the year ended December 31, 2011, two purchasers accounted for 39% and 38%, respectively, of the Company’s revenue. For the year ended December 31, 2010, three purchasers accounted for 66%, 19% and 12%, respectively, of the Company’s revenue. For the year ended December 31, 2009, two purchasers accounted for 66% and 14%, respectively, of the Company’s revenue.

Substantially all of the Company’s accounts receivable result from the sale of oil, natural gas and natural gas liquids. At December 31, 2011, three purchasers accounted for approximately 46%, 32% and 15%, respectively, of the accounts receivable balance. At December 31, 2010, three purchasers accounted for approximately 49%, 28% and 15%, respectively, of the accounts receivable balance.

Derivative financial instruments are generally executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. The Company also has netting arrangements in place with counterparties to reduce credit exposure. The Company has not experienced any losses from such instruments.

F-20

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

10. Commitments and Contingencies

Contractual Obligations

At December 31, 2011, contractual obligations for drilling contracts, long-term operating leases and seismic contracts are as follows:


	Total		2012		2013		2014		2015 and beyond
Drilling contracts	$	7,210	$	7,210	$	—	$	—	$	—
Non-cancellable office lease commitments		1,339		581		606		152		—
Seismic contracts		7,213		7,213		—		—		—

Net minimum commitments	$	15,762	$	15,004	$	606	$	152	$	—

For the years ended December 31, 2011, 2010 and 2009, the Company expensed $0.6 million, $0.6 million and $0.4 million, respectively, for office rent.

Litigation

The Company is a defendant in an action brought by Clovelly Oil Company, or the plaintiff, in the 13th Judicial District Court in Louisiana in May 2009. The plaintiff alleges that the Company is subject to an unrecorded Joint Operating Agreement (“JOA”) dated July 16, 1972, as a result of the Company’s 2007 purchase of a 43.75% working interest in certain acreage. The plaintiff alleges that the Company is bound by the 1972 JOA and that the Plaintiff is entitled to 56.25% of the Company’s 242.28-acre Crowell Land & Mineral lease. The Company was not a party to the JOA, and believes that it is protected by the Louisiana Public Records Doctrine, which generally holds that instruments involving real property are without effect as to third parties unless the instrument is filed of record in the appropriate mortgage or conveyance records of the parish in which such property is located.

The Company made a motion for summary judgment on all of the plaintiff’s claims, and the 13th Judicial District Court granted that motion on August 14, 2009. The plaintiff appealed the district court’s decision to the Third Circuit Court of Appeal, and on April 7, 2010, the Third Circuit Court of Appeal reversed and remanded the case back to the district court for trial. On August 9, 2010, the plaintiff amended its original petition to add Wells Fargo Bank, National Association, which holds a mortgage on the acreage as a defendant.

In December 2010, the Company filed a Motion for Partial Summary Judgment asking the district court to declare that the JOA does not apply to any new leases acquired after July 16, 1972 that are not extension or renewal leases. On September 27, 2011, the district court granted the Company’s motion for partial summary judgment. The district court also granted a motion for summary judgment filed by Wells Fargo Bank, National Association asserting that, as a mortgage holder of a mortgage covering the applicable lease, Wells Fargo Bank, National Association is protected by the Public Records Doctrine.

On October 17, 2011, the plaintiff filed an appeal to the Third Circuit Court of Appeal. The Third Circuit Court of Appeals has agreed to hear oral arguments in May 2012.

Although the outcome of a lawsuit cannot be predicted with certainty, the Company does not believe the ultimate outcome of this case will result in a material impact on its financial position, results of operations or cash flows.

F-21

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

The Company is involved in other disputes or legal actions arising in the ordinary course of business. The Company does not believe the outcome of such disputes or legal actions will result in a material impact on the Company’s financial position, results of operations, or cash flows.

11. Restatement

For the year ended December 31, 2009

The Company restated its consolidated financial statements for the year ended December 31, 2009. Subsequent to issuing its 2009 financial statements, the Company determined that certain errors were made as follows:

•

An overstatement of $1.4 million in the impairment in carrying value of oil and natural gas properties resulting from the transfer of $2.4 million of unevaluated properties to proved properties that should have remained in unevaluated properties, and a calculation error in the ceiling test of $1.0 million. The net effect of this adjustment reduced the 2009 operating loss and net loss by $1.4 million.

•

The Company’s share-based compensation plan, which grants restricted and unrestricted shares, should have been accounted for as a liability plan rather than an equity plan due to the existence of certain Company call options on equity share-based compensation. As a result, the Company transferred $3.2 million from members’ equity to other long-term liabilities, with no effect on operating loss for the year.

•

Net cash provided by operating activities and net cash used in investing activities were both overstated by $2.8 million as a result of the inclusion in the statement of cash flows of the change in the balance of certain investments in property and equipment that were accrued, but not paid. Related to this correction, the Company corrected the disclosure of supplemental cash flow information (presented on the statement of cash flows) of investments in property and equipment that were accrued, but not paid, as of December 31, 2009 from $0.5 million to $8.7 million.

The following table presents the impact of the errors on previously reported amounts (in thousands):


	As Originally Reported			Adjustment			Restated
Effected income statement items:
Impairment in carrying value of oil and natural gas properties	$	5,719		$	(1,422	)	$	4,297
Total expenses		37,434			(1,422	)		36,012
Operating loss		(13,180	)		1,422			(11,758	)
Net income (loss)		(13,174	)		1,422			(11,752	)

Unaudited pro forma income tax benefit		(5,138	)		546			(4,592	)
Unaudited pro forma net loss		(8,036	)		876			(7,160	)

Unaudited pro forma basic and diluted loss per share	$	(0.12	)	$	0.01		$	(0.11	)

Effected members’ equity items:
Net income (loss)		(13,174	)		1,422			(11,752	)
Members’ equity		237,146			(1,812	)		235,334

Effected cash flow items:
Net income (loss)		(13,174	)		1,422			(11,752	)
Impairment in carrying value of oil and natural gas properties		5,719			(1,422	)		4,297
Accounts payable and accrued liabilities		3,893			(2,822	)		1,071
Net cash provided by operating activities		13,417			(2,822	)		10,595

Investment in property and equipment		(75,059	)		2,822			(72,237	)
Net cash used in investing activities		(78,037	)		2,822			(75,215	)

Non cash transactions — investments in property and equipment accrued, but not paid		456			8,232			8,688

F-22

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

For the year ended December 31, 2010

The Company restated its consolidated financial statements for the year ended December 31, 2010. Subsequent to issuing its 2010 financial statements, the Company determined that certain errors were made as follows:

•

The Company’s share-based compensation plan, which grants restricted and unrestricted shares, should have been accounted for as a liability plan rather than an equity plan due to the existence of certain Company call options on equity share-based compensation. As a result, the Company transferred $6.9 million from members’ equity to other long-term liabilities, and increased the operating loss and net loss by $0.5 million for the year.

•

Net cash provided by operating activities was understated by $0.3 million and net cash provided by financing activities was overstated by an equivalent amount as a result of the inclusion of the amortization of debt issuance costs in net cash provided by financing activities rather than net cash provided by operating activities. The Company recorded an adjustment to decrease the line item other (cash flows from financing activities) by $0.3 million and to increase the line item other (cash flows from operating activities) by $0.3 million.

The following table presents the impact of the errors on previously reported amounts (in thousands):


	As Originally Reported			Adjustment			Restated
Effected income statement items:
General and administrative	$	16,358		$	489		$	16,847
Total expenses		78,207			489			78,696
Operating loss		(15,155	)		(489	)		(15,644	)
Net loss		(15,146	)		(489	)		(15,635	)

Unaudited pro forma income tax benefit		(6,120	)		(198	)		(6,318	)
Unaudited pro forma net loss		(9,026	)		(291	)		(9,317	)

Unaudited pro forma basic and diluted loss per share	$	(0.13	)	$	(0.01	)	$	(0.14	)

Effected balance sheet items:
Other long-term liabilities		2			6,924			6,926
Total long-term liabilities		108,925			6,924			115,849

Effected members’ equity items:
Net loss		(15,146	)		(489	)		(15,635	)
Members’ equity		263,817			(7,938	)		255,879

Effected cash flow items:
Net loss		(15,146	)		(489	)		(15,635	)
Share-based compensation		1,029			489			1,518
Other		—			314			314
Net cash provided by operating activities		50,454			314			50,768

Other:		(1,422	)		(314	)		(1,736	)
Net cash provided by financing activities		96,728			(314	)		96,414

F-23

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

For the year ended December 31, 2011

The Company has restated its consolidated financial statements for the year ended December 31, 2011. Subsequent to filing Amendment No. 6 to Form S-1 Registration Statement on March 6, 2012, the Company determined that the equity valuation originally used to record the estimated fair value of share-based compensation expense related to the final ‘mark to market’ of the Company’s equity awards upon the transition from liability accounting to equity accounting on December 5, 2011 did not properly consider the increased probability of the Company’s successful consummation of an initial public offering in the near term and the related impact on the Company’s valuation in the public market attributable to increased liquidity in the Company’s shares and a higher emphasis on forward looking multiples. The Company’s revised equity valuation resulted in an increase in share-based compensation expense included in general and administrative expense in the accompanying income statement.

The following table presents the impact of the error on previously reported amounts (in thousands):


	As Originally Reported		Adjustment			Restated
Effected income statement items:
General and administrative	$	27,970	$	40,945		$	68,915
Total expenses		149,760		40,945			190,705
Operating income		59,673		(40,945	)		18,728
Net income		57,602		(40,945	)		16,657

Unaudited pro forma income tax provision		23,156		—			23,156
Unaudited pro forma net income (loss)		34,446		(40,945	)		(6,499	)

Unaudited pro forma basic and diluted earnings (loss) per share	$	0.52	$	(0.62	)	$	(0.10	)

Effected members’ equity items:
Share-based compensation		19,723		40,945			60,668
Net income		57,602		(40,945	)		16,657
Members’ equity		285,502		—			285,502

Effected cash flow items:
Net income		57,602		(40,945	)		16,657
Share-based compensation		12,799		40,945			53,744
Net cash from operating activities		140,700		—			140,700

12. Supplemental Oil and Gas Disclosures—unaudited

The supplemental data presented herein reflects information for all of the Company’s oil and natural gas producing activities.

Capitalized Costs

The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2011 and 2010 (in thousands):


	December 31, 2011			December 31, 2010
Proved properties	$	644,393		$	351,544
Less: Accumulated depreciation, depletion, amortization and impairment		(148,187	)		(56,781	)

Proved properties, net		496,206			294,763
Unproved properties		76,857			101,366

Total oil and gas properties, net	$	573,063		$	396,129

F-24

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the years ended December 31, 2011, 2010 and 2009 (in thousands):


	For the Year Ended December 31, 2011		For the Year Ended December 31, 2010		For the Year Ended December 31, 2009
Acquisition costs:
Proved properties	$	—	$	—	$	3,017
Unproved properties		—		—		—
Exploration costs		16,900		6,754		3,144
Development costs		249,419		164,748		74,090
Asset retirement costs		5,444		175		120

Total costs incurred	$	271,763	$	171,677	$	80,371

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2011, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The evaluation activities are expected to be completed within three to five years.


	Total		2011			2010			2009			2008 and Prior
Property acquisition costs, net	$	63,752	$	(35,132	)	$	(12,688	)	$	(14,547	)	$	126,119
Exploration and development costs		8,023		8,023			—			—			—
Capitalized interest		5,082		2,600			1,305			830			347

Total	$	76,857	$	(24,509	)	$	(11,383	)	$	(13,717	)	$	126,466

The property acquisition cost data includes the original purchase price allocation at the time of First Reserve’s investment in August 2008. Subsequently, net reductions represent the reclassification of unevaluated costs into the full cost pool, offset by current lease acquisition costs of unevaluated properties.

Estimated Quantities of Proved Oil and Natural Gas Reserves

The reserve estimates at December 31, 2011, 2010 and 2009 presented in the table below are based on reports prepared by Netherland Sewell and Associates, Inc., independent reserve engineers, in accordance with the FASB’s authoritative guidance on oil and gas reserve estimation and disclosures. At December 31, 2011, all of the Company’s oil and natural gas producing activities were conducted within the continental United States.

The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.

F-25

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

The following table sets forth the Company’s net proved, proved developed and proved undeveloped reserves at December 31, 2011, 2010 and 2009 (1):


	Oil (MBbl)			Gas (MMcf)			NGL (MBbl)			MBoe
2009
Proved reserves
Beginning balance		4,788			5,087			—			5,636
Revisions of previous estimates		(804	)		1,110			61			(558	)
Extensions, discoveries and other additions		3,513			7,089			37			4,732
Sales of reserves in place		—			—			—			—
Purchases of reserves in place		577			662			9			696
Production		(497	)		(690	)		(2	)		(614	)

Net proved reserves at December 31, 2009		7,577			13,258			105			9,892
Proved developed reserves, December 31, 2009		2,786			4,392			19			3,536
Proved undeveloped reserves, December 31, 2009		4,791			8,866			86			6,356

2010
Proved reserves
Beginning balance		7,577			13,258			105			9,892
Revisions of previous estimates		(2,220	)		(1,043	)		49			(2,346	)
Extensions, discoveries and other additions		7,515			17,944			234			10,740
Sales of reserves in place		—			—			—			—
Purchases of reserves in place		—			—			—			—
Production		(945	)		(2,253	)		(74	)		(1,394	)

Net proved reserves at December 31, 2010		11,927			27,906			314			16,892
Proved developed reserves, December 31, 2010		5,392			14,203			141			7,900
Proved undeveloped reserves, December 31, 2010		6,535			13,703			173			8,992

2011
Proved reserves
Beginning balance		11,927			27,906			314			16,892
Revisions of previous estimates		(2,650	)		(6,500	)		1,661			(2,072	)
Extensions, discoveries and other additions		8,049			22,204			2,364			14,114
Sales of reserves in place		—			—			—			—
Purchases of reserves in place		—			—			—			—
Production		(1,610	)		(4,918	)		(308	)		(2,738	)

Net proved reserves at December 31, 2011		15,716			38,692			4,031			26,196
Proved developed reserves, December 31, 2011		6,479			17,987			1,802			11,279
Proved undeveloped reserves, December 31, 2011		9,237			20,705			2,229			14,917

(1)	The following table sets forth the benchmark prices used to determine our estimated proved reserves from proved oil and gas reserves for the periods indicated.

F-26

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements


	At December 31,
	2011		2010		2009
Oil and Natural Gas Prices (1):
Oil (per barrel (“Bbl”))	$	92.71	$	75.96	$	57.65
Natural gas (per million British thermal units (“MMBtu”))	$	4.118	$	4.376	$	3.866

(1)	Benchmark prices for oil and natural gas at December 31, 2011, 2010 and 2009 reflect the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months, using Plains WTI posted prices for oil and Platt’s Gas Daily Henry Hub prices for natural gas.

Purchases of Reserves in Place

An acquisition of an interest in three producing wells and various leases from Sandridge Energy Inc. in the North Cowards Gully field was closed in June 2009. As of year-end 2009, 696 MBoe of proved reserves were attributable to the acquired assets.

Extensions, Discoveries and Other Additions

In 2011, the Company had a total of 14,114 MBoe of additions from extensions and discoveries as a result of infill drilling and field delineation activities. Approximately 6,200 MBoe were from Pine Prairie, 5,500 MBoe were from West Gordon, 2,200 MBoe were from South Bearhead Creek/Oretta and 200 MBoe were from a new expansion area.

In 2010, the Company had a total of 10,740 MBoe of additions from extensions and discoveries as a result of infill drilling and field delineation activities. Approximately 4,400 MBoe were from South Bearhead Creek/Oretta, 3,300 Mboe were from Pine Prairie, 2,600 Mboe were from North Cowards Gully and 400 MBoe were from a new expansion area.

In 2009, the Company had a total of 4,732 MBoe of additions from extensions and discoveries as a result of infill drilling and field delineation activities. Approximately 1,940 Mboe were from Pine Prairie, 1,700 were from South Bearhead Creek/Oretta, 860 Mboe were from West Gordon and 230 Mboe were from North Cowards Gully.

Sales of Reserves in Place

There were no sales of reserves in place since January 1, 2009.

Revision of Previous Estimates

In 2011, the Company had net negative revisions of 2,072 MBoe primarily due to production performance in South Bearhead Creek and North Cowards Gully, partially offset by positive revisions in Pine Prairie.

In 2010, the Company had net negative revisions of 2,346 MBoe primarily due to production performance in West Gordon and North Cowards Gully and the removal of proved reserves in our Pine Prairie field associated with horizons in operated and non-operated wells that fell outside a five year development window. These reductions were partially offset by positive revisions in South Bearhead Creek/Oretta.

In 2009, the Company had net negative revisions of 558 MBoe primarily due to production performance in Pine Prairie and North Cowards Gully.

F-27

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $57.65/Bbl WTI posted price for oil and $3.866/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2009, $75.96/Bbl WTI posted price for oil and $4.376/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2010, and $92.71/Bbl WTI posted price for oil and $4.118/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2011. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s oil and natural gas reserves at December 31, 2011, 2010, and 2009.


	At Year Ended December 31,
	2011			2010			2009
	(In thousands)
Future cash inflows	$	2,141,204		$	1,131,970		$	506,561
Future production costs		606,265			526,704			148,076
Future development costs		413,155			215,101			83,444
Future income tax expense (1)		—			—			—

Future net cash flows		1,121,784			390,165			275,041
10% annual discount for estimated timing of cash flows		(429,039	)		(92,077	)		(116,694	)

Standardized measure of discounted future net cash flows	$	692,745		$	298,088		$	158,347

(1)

Does not include the effects of income taxes on future revenues because as of December 31, 2011, 2010 and 2009, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the company’s equity holders. Following its corporate reorganization, the Company will be a corporation and subject to U.S. federal and state income taxes. If the Company was subject to entity-level taxation, the unaudited pro forma future income tax expense at December 31, 2011, 2010, and 2009 would have been $127,534, $25,676 and $6,561, respectively. The unaudited pro forma Standardized Measure at December 31, 2011, 2010, and 2009 would have been $565,211, $272,412, and $151,785, respectively.

F-28

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the periods presented.


	Year Ended December 31,
	2011			2010			2009
	(In thousands)
January 1,	$	298,088		$	158,347		$	82,895

Net changes in prices and production costs		214,601			3,095			5,852
Net changes in future development costs		(5,446	)		(19,123	)		366
Sales of oil and natural gas, net		(184,055	)		(69,264	)		(16,746	)
Extensions		361,485			216,006			80,659
Discoveries		—			—			—
Purchases of reserves in place		—			—			8,554
Revisions of previous quantity estimates		(31,833	)		(38,117	)		(8,897	)
Previously estimated development costs incurred		46,691			16,955			—
Accretion of discount		29,809			15,835			8,289
Net change in income taxes		—			—			—
Changes in timing, other		(36,595	)		14,354			(2,625	)

Period End	$	692,745		$	298,088		$	158,347

13. Subsequent Events

New Preferred Units

On December 15, 2011, the Company, FR Midstates, and Petroleum Inc. entered into the Third Amended LLC Agreement under which certain common and New Preferred Units of the Company were authorized for issuance. Pursuant to the Third Amended LLC Agreement, as further amended in March 2012, the Company may issue up to 65,000 New Preferred Units, or $65,000,000 in aggregate value, between December 15, 2011 and June 10, 2015. The New Preferred Units have a liquidation value of $1,000 per unit, bear interest, compounded quarterly, at a rate of 8% plus the greater of LIBOR or 1.5%, and are convertible on or after the one year anniversary of the date of issuance into a number of common units with a fair market value (as determined by our board of directors) equal to the liquidation value plus any accrued interest. The New Preferred Units are redeemable at any time at the option of the Company, but are mandatorily redeemable for cash on June 10, 2015, unless otherwise converted. In addition, a fixed interest charge of 1.5% of the aggregate capital invested in the New Preferred Units is payable upon redemption or conversion.

On January 4, 2012, and again on February 9, 2012, the Company issued 20,000 New Preferred Units (for a total of 40,000 New Preferred Units) to FR Midstates for aggregate cash proceeds of $40,000,000. On April 3, 2012, the Company issued an additional 25,000 New Preferred Units (for a total of 65,000 New Preferred Units outstanding) to FR Midstates for additional cash proceeds of $25,000,000. Due to the mandatory redemption feature, any issuances of New Preferred Units will be classified as a liability in the Company’s consolidated balance sheets.

F-29

Midstates Petroleum Holdings LLC

Notes to Consolidated Financial Statements

Reserved-based credit facility

In connection with the March 2012 redetermination, our borrowing base was reduced from $235 million to $210 million. Under the terms of our revolving credit facility and as a result of the reduction in our borrowing base, we are required to repay the amount by which the principal balance of our outstanding loans and our letter of credit obligations exceed our borrowing base. Under the terms of the revolving credit facility, we are permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice to us regarding such borrowing base reduction. However, we intend to use a portion of the proceeds from this offering to repay a substantial portion of the outstanding indebtedness under our revolving credit facility.

14. Unaudited Quarterly Information


	Year Ended December 31, 2011
	First Quarter			Second Quarter		Third Quarter		Fourth Quarter
Total revenues	$	13,159		$	64,664	$	92,458	$	39,152
Operating income (loss)		(16,140	)		23,679		49,110		(37,921	)
Net income (loss)		(16,132	)		23,549		48,512		(39,272	)
Basic income (loss) per share		N/A			N/A		N/A		N/A
Shares used in basic per share computation		N/A			N/A		N/A		N/A
Diluted income (loss) per share		N/A			N/A		N/A		N/A
Shares used in diluted per share computation		N/A			N/A		N/A		N/A


	Year Ended December 31, 2010
	First Quarter			Second Quarter		Third Quarter			Fourth Quarter
Total revenues	$	10,157		$	30,720	$	11,151		$	11,024
Operating income (loss)		(2,012	)		12,643		(10,729	)		(15,546	)
Net income (loss)		(2,011	)		12,646		(10,727	)		(15,543	)
Basic income (loss) per share		N/A			N/A		N/A			N/A
Shares used in basic per share computation		N/A			N/A		N/A			N/A
Diluted income (loss) per share		N/A			N/A		N/A			N/A
Shares used in diluted per share computation		N/A			N/A		N/A			N/A

* * * * *

F-30

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)


	June 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,689		$	7,344
Accounts receivable:
Oil and gas sales		18,777			23,792
Severance tax refund		275			3,413
Other		515			249
Prepayments		5,350			2,642
Inventory		6,496			5,713
Commodity derivative contracts		12,038			4,957

Total current assets		55,140			48,110

PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting:
Proved properties		833,172			644,393
Unevaluated properties		95,600			76,857
Other property and equipment		2,168			1,672
Less accumulated depreciation, depletion, and amortization		(204,752	)		(148,843	)

Net property and equipment		726,188			574,079

OTHER ASSETS:
Commodity derivative contracts		6,247			588
Security deposit and other noncurrent assets		3,660			1,879

Total other assets		9,907			2,467

TOTAL	$	791,235		$	624,656

LIABILITIES AND MEMBERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	27,122		$	35,731
Accrued liabilities		62,985			37,524
Commodity derivative contracts		360			12,599

Total current liabilities		90,467			85,854

LONG-TERM LIABILITIES:
Asset retirement obligations		9,398			7,627
Commodity derivative contracts		—			10,178
Long-term debt		151,700			234,800
Deferred income taxes		168,917			—
Other long-term liabilities		614			695

Total long-term liabilities		330,629			253,300

COMMITMENTS AND CONTINGENCIES (Note 12)

STOCKHOLDERS’/MEMBERS’ EQUITY
Capital contributions		—			322,496
Preferred stock, $0.01 par value, 50,000,000 shares authorized, no shares issued or outstanding, respectively		—			—
Common stock, $0.01 par value, 300,000,000 shares authorized, 66,549,563 shares issued and outstanding, respectively		665			—
Additional paid-in-capital		536,352			—
Retained deficit/accumulated loss		(166,878	)		(36,994	)

Total stockholders’/members’ equity		370,139			285,502

TOTAL	$	791,235		$	624,656

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

F-31

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
REVENUES:
Oil sales	$	48,056		$	45,994		$	93,138		$	81,577
Natural gas sales		2,379			4,962			5,829			9,035
Natural gas liquid sales		3,901			3,171			10,173			5,216
Gains (Losses) on commodity derivative contracts—net		48,143			10,477			23,478			(18,119	)
Other		103			60			207			114

Total revenues		102,582			64,664			132,825			77,823

EXPENSES:
Lease operating and workover		5,921			3,669			12,388			6,275
Severance and other taxes		6,272			5,370			11,648			9,495
Asset retirement accretion		164			39			298			86
General and administrative		4,956			10,641			11,019			14,544
Depreciation, depletion, and amortization		27,882			21,266			55,909			39,884

Total expenses		45,195			40,985			91,262			70,284

OPERATING INCOME		57,387			23,679			41,563			7,539

OTHER INCOME (EXPENSE)
Interest income		143			4			150			12
Interest expense—net of amounts capitalized		(990	)		(134	)		(2,680	)		(134	)

Total other income (expense)		(847	)		(130	)		(2,530	)		(122	)

INCOME BEFORE TAXES		56,540			23,549			39,033			7,417
Income tax expense		168,917			—			168,917			—

NET INCOME (LOSS)	$	(112,377	)	$	23,549		$	(129,884	)	$	7,417

Pro forma loss per share:
Basic and Diluted (Note 10)	$	(1.85	)		N/A		$	(2.39	)		N/A

Pro forma weighted average shares outstanding:
Basic and Diluted (Note 10)		60,887			N/A			54,261			N/A

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

F-32

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED STATEMENT OF CHANGES IN STOCKHOLDERS’/MEMBERS’ EQUITY

(Unaudited)

(In thousands)


	Common Stock				Capital Contributions			Additional Paid- in-Capital		Retained Deficit/ Accumulated Loss			Total Stockholders’/ Members’ Equity
	Number of Shares		Amount		Capital Contributions			Additional Paid- in-Capital		Retained Deficit/ Accumulated Loss			Total Stockholders’/ Members’ Equity
Balance as of December 31, 2011		—	$	—	$	322,496		$	—	$	(36,994	)	$	285,502
Issuance of common stock		47,634,353		476		(476	)		—		—			—
Reclassification of members’ contributions		—		—		(322,020	)		322,020		—			—
Proceeds from the sale of common stock		18,000,000		180		—			213,659		—			213,839
Stock-based compensation		915,210		9		—			673		—			682
Net loss		—		—		—			—		(129,884	)		(129,884	)

Balance as of June 30, 2012		66,549,563	$	665	$	—		$	536,352	$	(166,878	)	$	370,139

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

F-33

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)


	Six months ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(129,884	)	$	7,417
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized (gains) losses on commodity derivative contracts, net		(35,157	)		9,982
Asset retirement accretion		298			86
Depreciation, depletion, and amortization		55,909			39,884
Share-based compensation		682			7,949
Deferred income taxes		168,917			—
Amortization of deferred financing costs		376			383
Change in operating assets and liabilities:
Accounts receivable—oil and gas sales		5,015			(1,181	)
Accounts receivable—other		2,872			305
Prepayments and other assets		(2,708	)		117
Inventory		(783	)		(104	)
Accounts payable		(3,077	)		(6,920	)
Accrued liabilities		(2,371	)		9,069
Other		(126	)		(3	)

Net cash provided by operating activities	$	59,963		$	66,984

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment		(184,245	)		(102,302	)

Net cash used in investing activities	$	(184,245	)	$	(102,302	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings		20,067			57,000
Repayment of long-term borrowings		(103,167	)		—
Proceeds from issuance of mandatorily redeemable convertible preferred units		65,000			—
Repayment of mandatorily redeemable convertible preferred units		(65,000	)		—
Proceeds from sale of common stock, net of initial public offering expenses of $6.1 million		213,839			—
Deferred loan costs		(2,112	)		(500	)
Cash received for units		—			170
Distributions to members		—			(22,811	)
Other		—			(3	)

Net cash provided by financing activities	$	128,627		$	33,856

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		4,345			(1,462	)
Cash and cash equivalents, beginning of period		7,344			11,917

Cash and cash equivalents, end of period	$	11,689		$	10,455

SUPPLEMENTAL INFORMATION:
Non-cash transactions—investments in property and equipment accrued—not paid	$	79,400		$	28,800
Cash paid for interest, net of capitalized interest of $2.4 million and $1.3 million, respectively	$	2,763		$	158

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

F-34

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Business

Midstates Petroleum Company, Inc., through its wholly owned subsidiary Midstates Petroleum Company LLC, engages in the business of drilling for, and production of, oil, natural gas and natural gas liquids, and currently has oil and gas operations solely in the state of Louisiana. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC, which was previously a wholly-owned subsidiary of Midstates Petroleum Holdings LLC. Pursuant to the terms of a corporate reorganization that was completed in connection with the closing of Midstates Petroleum Company, Inc.’s initial public offering, all of the interests in Midstates Petroleum Holdings LLC were exchanged for newly issued common shares Midstates Petroleum Company, Inc., and as a result, Midstates Petroleum Company LLC became a wholly-owned subsidiary of Midstates Petroleum Company, Inc. and Midstates Petroleum Holdings LLC ceased to exist as a separate entity. The terms “the Company,” “we,” “us,” “our,” and similar terms when used in the present tense, prospectively or for historical periods since April 25, 2012, refer to Midstates Petroleum Company, Inc. and its subsidiary, and for historical periods prior to April 25, 2012, refer to Midstates Petroleum Holdings LLC and its subsidiary, unless the context indicates otherwise. The term “Holdings LLC” refers solely to Midstates Petroleum Holdings LLC prior to the corporate reorganization.

On April 25, 2012, the Company completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, the Company registered the offer and sale of 27,600,000 shares of $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments. The Company’s sale of the shares in its initial public offering closed on April 25, 2012 and its initial public offering terminated upon completion of the closing.

The proceeds of the Company’s initial public offering, based on the public offering price of $13.00 per share, were approximately $358.8 million. After subtracting underwriting discounts and commissions of $21.5 million and the net proceeds to the selling stockholders of $117.3 million, the Company received net proceeds of approximately $220.0 million from the registration and sale of 18,000,000 common shares (or $213.8 million net of offering expenses paid directly by the Company). The Company used $67.1 million of the net proceeds to redeem convertible preferred units in Holdings LLC, including interest and other charges, and $99.0 million to pay down a portion of the borrowings under its revolving credit facility. The Company used the remaining $47.7 million to fund the execution of its growth strategy through its drilling program. The Company did not receive any of the proceeds from the sale of the 9,600,000 shares by the selling stockholders. Immediately after the initial public offering and exercise of the option, First Reserve Midstates Interholding LP and its affiliates own approximately 41.4% of the Company’s outstanding common stock.

At June 30, 2012, the Company operated oil and natural gas properties as one reportable segment: the exploration, development and production of oil, natural gas and natural gas liquids. The Company’s management evaluated performance based on one reportable segment as there were not different economic environments within the operation of its oil and natural gas properties.

All pro forma and per share information presented in the accompanying unaudited financial statements have been adjusted to reflect the effects of the Company’s initial public offering.

F-35

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

2. Summary of Significant Accounting Policies

Basis of Presentation

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto included in MPCI’s Registration Statement on Form S-1, as amended (Registration No. 333-177966).

All intercompany transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year’s consolidated financial statements and related footnotes to conform them to the current year presentation. In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Recent Accounting Pronouncements

The Company reviewed recently issued accounting pronouncements that became effective during the six months ended June 30, 2012, and determined that none would have a material impact on the Company’s condensed consolidated financial statements.

3. Fair Value Measurements of Financial Instruments

•

Level 1—Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.

•

Level 3—Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.

F-36

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Derivative Instruments—Commodity derivative contracts reflected in the condensed consolidated balance sheets are recorded at estimated fair value. At June 30, 2012 and December 31, 2011, all of the Company’s commodity derivative contracts were with three and two bank counterparties, respectively, and are classified as Level 2.


	Fair Value Measurements at June 30, 2012
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	14,799	$	—	$	14,799
Commodity derivative deferred premium puts		—		1,015		—		1,015
Commodity derivative collars		—		380		—		380
Commodity derivative differential swaps		—		7,371		—		7,371

Total assets		—		23,565		—		23,565

Liabilities:
Commodity derivative oil swaps	$	—	$	4,397	$	—	$	4,397
Commodity derivative deferred premium puts		—		180		—		180
Commodity derivative collars		—		10		—		10
Commodity derivative differential swaps		—		1,053		—		1,053

Total liabilities	$	—	$	5,640	$	—	$	5,640

F-37

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements


	Fair Value Measurements at December 31, 2011
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Assets:
Commodity derivative oil swaps	$	—	$	—	$	—	$	—
Commodity derivative deferred premium puts		—		1,673		—		1,673
Commodity derivative collars		—		397		—		397
Commodity derivative differential swaps		—		4,200		—		4,200

Total assets		—		6,270		—		6,270

Liabilities:
Commodity derivative oil swaps	$	—	$	23,162	$	—	$	23,162
Commodity derivative deferred premium puts		—		340		—		340
Commodity derivative collars		—		—		—		—
Commodity derivative differential swaps		—		—		—		—

Total liabilities	$	—	$	23,502	$	—	$	23,502

Derivative instruments listed above are presented gross and include collars, swaps, and put options that are carried at fair value. The Company records the net change in the fair value of these positions in “Gains (losses) on commodity derivative contracts—net” in the Company’s unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company classifying its derivatives as Level 2 instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves.

For additional information on the Company’s derivative instruments and balance sheet presentation, see Note 4.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s condensed consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Asset Retirement Obligations (ARO’s)—The Company initially estimates the fair value of ARO’s based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, the amount and timing of settlements, the credit-adjusted risk-free rate and inflation rates. See Note 5 for a summary of changes in ARO’s.

4. Risk Management and Derivative Instruments

F-38

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

derivative financial instruments, including swaps and options, to manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are generally placed with major financial institutions that the Company believes are minimal credit risks. The oil and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that management believes have a high degree of historical correlation with actual prices received by the Company for its oil and gas production.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at June 30, 2012 would have been approximately $18.3 million.

Commodity Derivative Contracts

As of June 30, 2012, the Company had the following open commodity positions:


	Hedged Volume		Weighted-Average Fixed Price
Oil (Bbls):
WTI Swaps—2012		411,100	$	84.36
WTI Swaps—2013		679,125		84.73
WTI Swaps—2014		262,450		83.00

WTI Collars—2012		82,800	$	85.00 - 127.28

WTI Deferred Premium Puts—2012 (1)		276,000	$	79.01

WTI Basis Differential Swaps—2012 (2)		505,300	$	9.73
WTI Basis Differential Swaps—2013 (2)		679,125		6.30

LLS Swaps—2012		315,180	$	116.55

Brent Swaps—2013		1,021,749	$	111.89

(1)	2012 deferred premium puts represent the net effective floor price of a put with a strike price of $85.00/Bbl and a deferred premium of $5.99/Bbl. The premiums for these instruments are paid each month, concurrently with the settlement of the monthly put contracts.

(2)	The Company enters into swap arrangements intended to capture the positive differential between the Louisiana Light Sweet (“LLS”) pricing and West Texas Intermediate (“NYMEX WTI”) pricing.

F-39

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

Balance Sheet Presentation

The following table summarizes the gross fair value of derivative instruments by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the Company’s condensed consolidated balance sheets at June 30, 2012 and December 31, 2011, respectively (in thousands):


Type	Balance Sheet Location (1)	June 30, 2012			December 31, 2011
Oil Swaps	Derivative financial instruments—Current Assets	$	6,633		$	—
Oil Swaps	Derivative financial instruments—Non-Current Assets		8,166			—
Oil Swaps	Derivative financial instruments—Current Liabilities		(2,225	)		(13,046	)
Oil Swaps	Derivative financial instruments—Non-Current Liabilities		(2,172	)		(10,116	)
Deferred Premium Puts	Derivative financial instruments—Current Assets		1,015			1,673
Deferred Premium Puts	Derivative financial instruments—Non-Current Assets		—			—
Deferred Premium Puts	Derivative financial instruments—Current Liabilities		(180	)		(278	)
Deferred Premium Puts	Derivative financial instruments—Non-Current Liabilities		—			(62	)
Collars	Derivative financial instruments—Current Assets		380			397
Collars	Derivative financial instruments—Non-Current Assets		—			—
Collars	Derivative financial instruments—Current Liabilities		(10	)		—
Collars	Derivative financial instruments—Non-Current Liabilities		—			—
Basis Differential Swaps	Derivative financial instruments—Current Assets		7,060			3,612
Basis Differential Swaps	Derivative financial instruments—Non-Current Assets		311			588
Basis Differential Swaps	Derivative financial instruments—Current Liabilities		(996	)		—
Basis Differential Swaps	Derivative financial instruments—Non-Current Liabilities		(57	)		—

Total		$	17,925		$	(17,232	)

(1)

The fair value of derivative instruments reported in the Company’s condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation. The following table reports the net derivative fair values as reported in the Company’s condensed consolidated balance sheets as of June 30, 2012 and December 31, 2011, respectively (in thousands):


	June 30, 2012			December 31, 2011
Consolidated balance sheet classification:
Current derivative instruments:
Assets		12,038			4,957
Liabilities		(360	)		(12,599	)

Non-current derivative instruments:
Assets		6,247			588
Liabilities		—			(10,178	)

Gains/Losses on Commodity Derivative Contracts

F-40

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table presents realized net gains (losses) and unrealized net gains (losses) recorded by the Company related to the change in fair value of the derivative financial instruments in “Gains (losses) on commodity derivative contracts—net” for the periods presented (in thousands):


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
Realized net gains (losses)		(5,180	)		(6,130	)		(11,679	)		(8,137	)
Unrealized net gains (losses)		53,323			16,607			35,157			(9,982	)

5. Asset Retirement Obligations

Asset retirement obligations represent the future abandonment costs of tangible assets, such as wells, service assets and other facilities. The fair value of the asset retirement obligation at inception is capitalized as part of the carrying amount of the related long-lived assets. Asset retirement obligations approximated $9.4 million and $7.6 million as of June 30, 2012 and December 31, 2011, respectively.

The liability has been accreted to its present value as of June 30, 2012 and December 31, 2011. The Company evaluated its wells and determined a range of abandonment dates through 2058.

The following table reflects the changes in the Company’s asset retirement obligations for the six months ended June 30, 2012 (in thousands):


Asset retirement obligations at January 1, 2012	$	7,627
Liabilities incurred		1,470
Revisions		3
Liabilities settled		—
Current period accretion expense		298

Asset retirement obligations at June 30, 2012	$	9,398

6. Long-Term Debt

The Company’s long-term debt as of June 30, 2012 and December 31, 2011 is as follows (in thousands):


	June 30, 2012		December 31, 2011
Revolving credit facility	$	151,700	$	234,800
Less: current maturities of debt		—		—

Long-term debt	$	151,700	$	234,800

On June 8, 2012, Midstates Petroleum Company LLC entered into a Second Amended and Restated Credit Agreement among Midstates Petroleum Company LLC, as borrower, the Company, as guarantor, the lenders party thereto and SunTrust Bank, as the new administrative agent (the “Amended Credit Agreement”).

The Amended Credit Agreement increased the size of the revolving credit facility from $300 million to $500 million, added additional lenders to the bank group and set the initial borrowing base at $200 million. In addition, the lenders under the Amended Credit Agreement have agreed that there will be no reduction in the Company’s borrowing base under the Amended Credit Agreement for the issuance of up to $275 million of senior unsecured notes. In the event that the Company elects to issue senior unsecured notes in excess of $275

F-41

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

million, the borrowing base will be reduced by 25% of the face value (without giving effect to any original issue discount) of such notes in excess of $275 million. The Amended Credit Agreement also extended the maturity date of the revolving credit facility from December 10, 2014 to June 8, 2017. At the closing of the Amended Credit Agreement, the Company borrowed $20.0 million under the revolving credit facility.

Borrowings under the Amended Credit Agreement continue to be secured by substantially all of the Company’s oil and natural gas properties and currently bear interest at LIBOR plus an applicable margin between 1.75% and 2.75% per annum. At June 30, 2012 and December 31, 2011, the weighted-average interest rate was 2.9% and 3.2%, respectively.

In addition to interest expense, the Amended Credit Agreement requires the payment of a commitment fee each quarter. The commitment fee is computed at the rate of either 0.375% or 0.50% per annum based on the average daily amount by which the borrowing base exceeds the outstanding borrowings during each quarter.

The borrowing base under the Amended Credit Agreement is subject to semiannual redeterminations in March and September and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by the Company or the administrative agent, acting on behalf of lenders holding at least two—thirds of the outstanding loans and other obligations.

Under the terms of the revolving credit facility, the Company is required to repay the amount by which the principal balance of its outstanding loans and its letter of credit obligations exceed its redetermined borrowing base. The Company is permitted to make such repayment in six equal successive monthly payments commencing 30 days following the administrative agent’s notice regarding such borrowing base reduction.

The revolving credit facility contains financial covenants, which, among other things, set a maximum ratio of debt to earnings before interest, income tax, depletion, depreciation, and amortization (EBITDA) of not more than 4.0 to 1, a minimum current ratio (as defined therein) of not less than 1.0 to 1.0 and various other standard affirmative and negative covenants including, but not limited to, restrictions on the Company’s ability to make any dividends, distributions or redemptions. As of June 30, 2012, the Company is in compliance with the financial debt covenants set forth in the Amended Credit Agreement.

In connection with the Amended Credit Agreement, the Company incurred legal fees and fees payable to the lending banks of approximately $2.1 million, which together with the remaining unamortized fees associated with the revolving credit facility prior to the amendment, will be amortized as additional interest expense over the new maturity date of June 8, 2017.

The Company’s credit facility at December 31, 2011 and through June 7, 2012, consisted of a $300 million senior revolving credit facility (the “Facility”) with a borrowing base, as redetermined in March 2012, of $210 million. Prior to the amendment, the revolving credit facility had a maturity date of December 10, 2014 and bore interest at LIBOR plus an applicable margin between 2.00% and 2.75% per annum. In April 2012, the Company repaid $103.2 million of the outstanding Facility balance.

The Company believes the carrying amount of the Amended Credit Agreement at June 30, 2012 approximates its fair value (Level 2) due to the variable nature of the applicable interest rate.

F-42

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

7. Mandatorily Redeemable Convertible Preferred Units

In December 2011, Holdings LLC, FR Midstates Holdings LLC (“FR Midstates”) and Midstates Petroleum Holdings, Inc. (“Petroleum Inc.”) entered into an amended and restated limited liability company agreement, which was later amended in March 2012, to provide for the issuance of up to 65,000, or $65 million in aggregate value, of certain mandatorily redeemable convertible preferred units (the “Preferred Units”) between December 15, 2011 and June 10, 2015. The Preferred Units had a liquidation value of $1,000 per unit and bore interest, compounded quarterly, at a rate of 8% plus the greater of LIBOR or 1.5%. The Preferred Units were convertible into units of Holdings LLC on or after the one year anniversary of the date of issuance into a number of common units with a fair market value (as determined by the Board of Directors) equal to the liquidation value plus any accrued interest and were redeemable for cash at any time at the option of Holdings LLC, but were mandatorily redeemable for cash on June 10, 2015, unless otherwise converted. In addition, a fixed interest charge of 1.5% of the aggregate capital invested in the Preferred Units was payable upon redemption or conversion.

On January 4, 2012, and again on February 9, 2012, Holdings LLC issued 20,000 Preferred Units (for a total of 40,000 Preferred Units) to FR Midstates for aggregate cash proceeds of $40.0 million. On April 3, 2012, Holdings LLC issued an additional 25,000 preferred units to FR Midstates for aggregate cash proceeds of $25.0 million.

On April 26, 2012, Midstates Petroleum Company, Inc. used $67.1 million of the proceeds from its initial public offering to redeem the Preferred Units in full, including interest and other charges. As such, at June 30, 2012, the Preferred Units are no longer outstanding. Midstates Petroleum Company, Inc. recorded $2.1 million related to interest expense associated with these Preferred Units for the six months ended June 30, 2012.

8. Equity and Share-Based Compensation

At December 31, 2011, Holdings LLC had 256,742 common units issued and outstanding. On April 24, 2012, in connection with Midstates Petroleum Company, Inc.’s initial public offering, a corporate reorganization occurred and each common unit of Holdings LLC was converted into approximately 185.5 common shares of Midstates Petroleum Company, Inc. and as a result, Midstates Petroleum Company, Inc. issued 47,634,353 shares of its common stock.

On April 25, 2012, Midstates Petroleum Company Inc. completed its initial public offering of common stock pursuant to a registration statement on Form S-1 (File 333-177966), as amended and declared effective by the SEC on April 19, 2012. Pursuant to the registration statement, Midstates Petroleum Company, Inc. registered the offer and sale of 27,600,000 shares of $0.01 par value common stock, which included 6,000,000 shares of stock sold by the selling shareholders and 3,600,000 shares of common stock sold by the selling stockholders pursuant to an option granted to the underwriters to cover over-allotments. Midstates Petroleum Company, Inc.’s sale of the shares in its initial public offering closed on April 25, 2012.

After the corporate reorganization and the completion of its initial public offering discussed above, Midstates Petroleum Company, Inc. is authorized to issue up to a total of 300,000,000 shares of its common stock with a par value $0.01 per share, and 50,000,000 shares of its preferred stock with a par value of $0.01 per share. Holders of Midstates Petroleum Company, Inc.’s common shares are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders and to receive ratably in proportion to the shares of common stock held by them any dividends declared from time to time by the board of directors. The common shares have no preferences or rights of conversion, exchange, pre-exemption or other subscription rights. At June 30, 2012, Midstates Petroleum Company, Inc. had 66,549,563 shares of its common stock issued and outstanding.

F-43

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

With respect to preferred shares, Midstates Petroleum Company, Inc. is authorized, without further stockholder approval, to establish and issue from time to time one or more classes or series of preferred stock with such powers, preferences, rights, qualifications, limitations and restrictions as determined by its board of directors. At June 30, 2012, no preferred shares were issued or outstanding.

Share-Based Compensation, pre Initial Public Offering

During the six months ended June 30, 2011, certain restricted and unrestricted shares in Petroleum Inc., through which Holdings LLC’s founders, members of management and certain employees previously held their equity interests, certain unrestricted units in Holdings LLC, and certain units in Midstates Incentive Holdings, LLC (“Midstates Incentive”) had been issued to employees of Holdings LLC.

Additionally, in March 2011, Holdings LLC’s Chief Executive Officer, in connection with the commencement of his employment, purchased 17.3 shares of common stock of Petroleum Inc. and contemporaneously received a grant of 24.6 shares of common stock in Petroleum Inc. that vested as described further below. No other shares or units were issued during the 2011 period. The Company determined the grant date fair value of the share based award to be $80,013 per Petroleum Inc. share ($3.4 million in aggregate), or after taking into account the corporate reorganization attributable to the initial public offering completed on April 25, 2012, $4.26 per share of Midstates Petroleum Company, Inc. common stock. The Company recognized stock compensation in accordance with ASC Topic 718, “Compensation—Stock Compensation” based upon the grant date fair value and immediately expensed the difference between the grant date fair value and the price paid for the purchased shares of Petroleum Inc., as well as additional compensation expense related to the liability accounting for the Company’s share-based awards discussed below.

Prior to December 5, 2011, due to certain rights to call shares and units in Holdings LLC for cash, Holdings LLC’s share-based payments awarded to employees were accounted for as liability awards pursuant to ASC Topic 718, “Compensation—Stock Compensation.” As such, Holdings LLC calculated the fair value of the share-based awards on a quarterly basis using estimated market value and the total fair value of the awards was recorded within “Other long-term liabilities” in Holding LLC’s condensed consolidated balance sheets. Any change in the fair value of the liability awards was recorded as share-based compensation expense within “General and administrative expense” in Holdings LLC’s condensed consolidated statements of operations, which was the same line item as cash compensation paid to the same employees.

Historically, Holdings LLC’s determination of the fair value of each of the units was affected by: i) Holdings LLC’s risk adjusted proved, possible, and probable reserves; ii) internal assessment of long-term commodity prices; iii) current values of Holdings LLC’s non-oil and gas assets and liabilities; and iv) a number of complex and subjective variables. Although the fair value of the share-based payments is determined in accordance with GAAP, that value may not be indicative of the fair value observed in a market transaction between a willing buyer and a willing seller.

Effective as of November 22, 2011, the Board of Directors of Petroleum Inc. accelerated the vesting of all restricted stock in Petroleum Inc. The vesting resulted in the recognition of previously unrecognized share-based compensation expense at the estimated fair market value of the restricted stock held by employees at November 22, 2011. Petroleum Inc. determined the fair market value of Petroleum Inc.’s common stock based on management’s estimates.

On December 5, 2011, Employment Agreements with employees of Midstates Petroleum Company LLC, a Stockholders’ Agreement by and among stockholders in Petroleum Inc. and a Unitholders’ Agreement by and

F-44

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

among the members of Holdings LLC were either terminated or amended such that the rights within those agreements to call shares in Petroleum Inc. and units in Holdings LLC for cash no longer required Holdings LLC’s share-based payments awarded to employees to be accounted for as liability awards. As a result the Company transitioned as of December 5, 2011 from liability accounting to equity accounting for the Company’s share-based compensation plans and accordingly, the Company no longer recognized changes in the estimated fair value of outstanding share-based awards in the statements of operations.

Restricted Shares.

Restricted shares in Petroleum Inc. were awarded at no cost to the recipient with a vesting period that commenced on the grant date and terminated on the fifth anniversary or upon certain changes in control of Holdings LLC, including but not limited to mergers, acquisitions, or a public offering (a “Triggering Event”).

As a result of the vesting on November 22, 2011, as discussed above, there is no unrecognized compensation cost and as a result of the corporate reorganization in April 2012, each share of Petroleum Inc. was converted into 18,762 shares of common stock of Midstates Petroleum Company, Inc. As a result, there are no outstanding restricted shares in Petroleum Inc. as of June 30, 2012.

Unrestricted Shares and Units.

Unrestricted shares in Petroleum Inc. and units of Holdings LLC were purchased by the recipient on the grant date and were fully vested upon purchase, or represented restricted shares which have vested. For shares of Petroleum Inc and units of Holdings LLC purchased, any difference between the recipient’s purchase price and the grant date fair value was recognized as compensation expense on the grant date. As a result of the corporate reorganization in April 2012, each share of Petroleum, Inc. and each unit of Holdings LLC were converted into 18,762 and 185.5 shares respectively, of Midstates Petroleum Company, Inc. common stock. As a result, at June 30, 2012, there are no Petroleum, Inc. shares or Holdings LLC units outstanding.

Incentive Units.

At June 30, 2012, 1,659 incentive units were issued and outstanding. In connection with the corporate reorganization that occurred immediately prior to our initial public offering, these incentive units held in the Company were contributed to FR Midstates Interholding, LP (“FRMI”) in exchange for incentive units in FRMI. Holders of FRMI incentive units will receive, out of proceeds otherwise distributable to FRMI, a percentage interest in the amounts distributed to FRMI in excess of certain multiples of FRMI’s aggregate capital contributions and investment expenses (“FRMI Profits”). Although any future payments to the incentive unit holders will be made out of the proceeds otherwise distributable to FRMI and not by the Company, the Company will be required to record a non-cash compensation charge in the period any payment is made related to the FRMI incentive units. To date, no compensation expense related to the incentive units has been recognized by the Company, as any payout under the incentive units is not considered probable, and thus, the amount of FRMI Profits, if any, cannot be determined.

Share-based Compensation, Post-Initial Public Offering

2012 Long Term Incentive Plan

On April 20, 2012, Midstates Petroleum Company, Inc. established the 2012 Long Term Incentive Plan (the “2012 LTIP”) and filed a Form S-8 with the SEC, registering 6,563,435 shares for future issuance under the terms of the 2012 LTIP. The 2012 LTIP provides a means for the Company to attract and retain employees,

F-45

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

directors and consultants, and a method whereby employees, directors and consultants of the Company who contribute to its success can acquire and maintain stock ownership or awards, the value of which is tied to the performance of the Company, thereby strengthening their concern for the welfare of the Company and their desire to remain employed.

The 2012 LTIP provides for the granting of Options (Incentive and other), Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Dividend Equivalents, Bonus Stock, Other Stock-Based Awards, Annual Incentive Awards, Performance Awards, or any combination of the foregoing (the “Awards”). Subject to certain limitations as defined in the 2012 LTIP, the terms of each Award are as determined by the Compensation Committee of the Board of Directors. A total of 6,563,435 common share Awards are authorized for issuance under the 2012 LTIP and shares of stock subject to an Award that expire, or are canceled, forfeited, exchanged, settled in cash or otherwise terminated, will again be available for future Awards under the 2012 LTIP.

Non-vested Stock Awards.

Subsequent to the completion of the Company’s initial public offering and pursuant to the 2012 LTIP, the Company issued 916,594 shares of restricted common stock to directors, management and employees. Shares granted under the LTIP vest ratably over a period of three years (one-third on each anniversary of the grant).

The fair value of restricted stock grants is based on the value of the Company’s common stock on the date of grant. Compensation expense is recognized ratably over the requisite three year service period. As of June 30, 2012, the Company assumed no annual forfeiture rate because of the Company’s lack of turnover and history for this type of award.

The following table summarizes the Company’s non-vested share award activity for the six months ended June 30, 2012:


	Shares			Weighted Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2011		—
Granted		916,594		$	13.16
Vested		—		$	—
Forfeited		(1,384	)	$	13.00

Non-vested shares outstanding at June 30, 2012		915,210		$	13.16

Unrecognized expense as of June 30, 2012 for all outstanding restricted stock awards was $11.4 million and will be recognized over a weighted average period of 2.8 years.

At June 30, 2012, 5,648,225 shares remain available for issuance under the terms of the 2012 LTIP.

F-46

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

The following table summarizes share-based compensation costs recognized by the Company for the periods presented (in thousands):


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2012		2011		2012		2011
Restricted and unrestricted Petroleum Inc. shares and Holdings LLC units	$	—	$	7,299	$	—	$	7,949
Incentive units		—		—		—		—
2012 LTIP restricted shares		682		—		682		—

Total share-based compensation expense		682		7,299		682		7,949

9. Income Taxes

Prior to its corporate reorganization (See Note 1), the Company was a limited liability company and not subject to federal income tax or state income tax (in most states). Accordingly, no provision for federal or state income taxes was recorded prior to the corporate reorganization as the Company’s equity holders were responsible for income tax on the Company’s profits. In connection with the closing of the Company’s IPO, the Company merged into a corporation and became subject to federal and state income taxes. The Company’s book and tax basis in assets and liabilities differed at the time of the corporate reorganization due primarily to different cost recovery periods utilized for book and tax purposes for the Company’s oil and natural gas properties. In the second quarter of 2012, the Company recorded a net deferred tax expense of $149.5 million to recognize a deferred tax liability related to the Company’s initial book and tax basis differences due to its change in tax status.

Subsequent to the corporate reorganization, the Company’s effective tax rate is expected to be 49.7% The Company’s effective tax rate differs from the federal statutory rate of 35% due to: (i) the inability to use pre-IPO losses to offset post-IPO earnings, and (ii) state income taxes. The Company expects to incur a tax loss in the current year (due principally to the ability to expense certain intangible drilling and development costs under current law) and thus no current income taxes are anticipated to be paid. This tax loss is expected to result in a Net Operating Loss carryforward at year-end; however, no valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize all tax attributes. This future taxable income arises from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax bases. Management is not relying on other sources of taxable income in concluding that no valuation allowance is needed.

As of June 30, 2012, the Company has not recorded a reserve for any uncertain tax positions.

10. Earnings (Loss) Per Share

The Company’s nonvested stock awards, which are granted as part of the 2012 LTIP, contain nonforfeitable rights to dividends and as such, are considered to be participating securities and are included in the computation of basic and diluted earnings (loss) per share, pursuant to the two-class method. In the calculation of basic earnings (loss) per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.

F-47

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

The computation of diluted earnings per share attributable to common shareholders reflects the potential dilution that could occur if securities or other contracts to issue common shares that are dilutive were exercised or converted into common shares (or resulted in the issuance of common shares) and would then share in the earnings of the Company. During the periods in which the Company records a loss from continuing operations attributable to common shareholders, securities would not be dilutive to net loss per share and conversion into common shares is assumed to not occur. Diluted net income per share attributable to common shareholders is calculated under both the two-class method and the treasury stock method; the more dilutive of the two calculations is presented.

The following table is a calculation of the pro forma basic and diluted weighted-average shares outstanding for the three and six months ended June 30, 2012.


	For the Three Months Ended June 30,
	2012								2011
	Income			Shares		Per Share			Income		Shares		Per Share
	(in thousands, except per share amounts)
Net Loss	$	(112,377	)
Loss Allocable to Nonvested Restricted Stock (1)		—

Basic Net Loss Attributable to Common Stock	$	(112,377	)		60,887	$	(1.85	)		N/A		N/A		N/A

Effect of Dilutive Securities:
N/A (2)		—			—

Diluted Net Loss Attributable to Common Stock	$	(112,377	)		60,887	$	(1.85	)		N/A		N/A		N/A


	For the Six Months Ended June 30,
	2012								2011
	Income			Shares		Per Share			Income		Shares		Per Share
	(in thousands, except per share amounts)
Net Loss	$	(129,884	)
Loss Allocable to Nonvested Restricted Stock (1)		—

Basic Net Loss Attributable to Common Stock	$	(129,884	)		54,261	$	(2.39	)		N/A		N/A		N/A

Effect of Dilutive Securities:
N/A (2)		—			—

Diluted Net Loss Attributable to Common Stock	$	(129,884	)		54,261	$	(2.39	)		N/A		N/A		N/A

(1)

Due to the basic net loss attributable to common shareholders for the three and six months ended June 30, 2012, the Company excluded 626,921 and 313,460 weighted-average outstanding nonvested restricted stock, respectively, from the computations of net loss per share because these securities do not participate in undistributed net losses.

(2)	At June 30, 2012, there were no other dilutive securities outstanding to consider for the periods presented as unvested restricted stock grants had already been considered as part of the two-class method.

The aggregate number of common and nonvested restricted shares outstanding at June 30, 2012 was 65,634,353 and 915,210, respectively.

F-48

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

11. Related Party Transactions

At June 30, 2012, a minority owner of Petroleum Inc. was also a significant owner of one of the Company’s vendors. For the three and six months ended June 30, 2012, the amount paid to this vendor was $0.8 million and $1.5 million, respectively. For the three and six months ended June 30, 2011, the amount paid to this vendor was $0.8 million and $1.1 million, respectively.

The amount payable at June 30, 2012 and December 31, 2011 was $0.2 million and $0.1 million, respectively.

12. Commitments and Contingencies

Contractual Obligations

At June 30, 2012, contractual obligations for drilling contracts, long-term operating leases, seismic contracts and other are as follows (in thousands):


	Total		2012 (remainder)		2013		2014		2015		2016 and beyond
Drilling contracts	$	6,150		6,150		—		—		—		—
Non-cancellable office lease commitments (1)	$	8,436		634		1,418		1,439		1,459		3,486
Seismic contracts	$	8,824		8,324		500		—		—		—
Other	$	1,110		1,110		—		—		—		—

Net minimum commitments	$	24,520	$	16,218	$	1,918	$	1,439	$	1,459	$	3,486

(1)

On June 4, 2012, the Company executed an amendment to its office space lease agreement for relocation to a new floor within its current office building. Under the terms of the amendment, the Company’s obligation for its existing premises on two floors will terminate and rental obligations for the new premises will begin upon substantial completion of the remodeling work in the new premises, which is projected to be October 2012, and when the Company will take possession of the new premises. The amended lease agreement will have a term of 66 months.

Litigation

Clovelly Oil Company.

The Company is a defendant in an action brought by Clovelly Oil Company (the “Plaintiff” or “Clovelly”) in the 13th Judicial District Court in Louisiana in May 2009. The Plaintiff alleges that the Company is subject to an unrecorded Joint Operating Agreement (“JOA”) dated July 16, 1972, as a result of the Company’s 2007 purchase of a 43.75% working interest in certain acreage. The Plaintiff further alleges that the Company is bound by the 1972 JOA and that the Plaintiff is entitled to 56.25% of the Company’s 242.28-acre Crowell Land & Mineral lease. The Company was not a signatory to the JOA, and believes that it is protected by the Louisiana Public Records Doctrine, which generally provides that instruments involving real property are without effect as to third parties unless the instrument is filed of record in the appropriate mortgage or conveyance records of the parish in which such property is located.

The Company made a motion for summary judgment on all of the Plaintiff’s claims, and the 13th Judicial District Court granted that motion on August 14, 2009. The Plaintiff appealed the district court’s decision to the Third Circuit Court of Appeal, and on April 7, 2010, the Third Circuit Court of Appeal reversed and remanded the case to the district court for trial. On August 9, 2010, the Plaintiff amended its original petition to add Wells Fargo Bank, N. A., which holds a mortgage on the acreage, as a defendant.

F-49

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

In December 2010, the Company filed a Motion for Partial Summary Judgment asking the district court to declare that the JOA does not apply to any new leases acquired after July 16, 1972 which are not extension or renewal leases. On September 27, 2011, the district court granted the Company’s motion for partial summary judgment. The district court also granted a motion for summary judgment filed by Wells Fargo asserting that, as a mortgage holder of a mortgage covering the applicable lease, Wells Fargo is protected by the Public Records Doctrine. The Plaintiff again appealed.

On June 6, 2012, the Third Circuit Court of Appeal reversed the district court’s partial summary judgment decision that the JOA does not apply to any new leases. It held that, if the Company is subject to the JOA, then the JOA applies to leases acquired by the Company after the 2007 purchase that are within the acreage covered by the JOA. Separately, the Court of Appeal upheld the district’s court decision that Wells Fargo is protected by the Public Records Doctrine. The Court of Appeal then remanded the case to the district court for a determination of whether the Company had assumed the obligations under the JOA.

The Company timely filed an Application for Rehearing of the June 6 decision, and the Court of Appeal has not yet ruled on the application. If appropriate relief is not obtained from the Court of Appeal on rehearing, the Company will evaluate whether to file a writ of certiorari to the Louisiana Supreme Court seeking review and reversal of the Court of Appeal’s decision.

A final adverse court decision that the Company is subject to the JOA could entitle Clovelly to a 56.25% interest in the leases affected by the litigation. Approximately 2.0 MMBOE of the Company’s 26.2 MMBOE of total proved reserves as of December 31, 2011 are attributable to properties that would potentially be subject to Clovelly’s interest. Such an adverse court decision could result in a material adverse effect on our financial condition, future planned operations and/or cash flow.

The Company disputes the allegations and intends to continue to vigorously defend against this litigation.

Other.

We are involved in other disputes or legal actions arising in the ordinary course of our business. We may not be able to predict the timing or outcome of these or future claims and proceedings with certainty, and an unfavorable resolution of one or more of such matters could have a material adverse effect on our financial condition, results of operations or cash flows. Currently, we are not party to any legal proceedings that, individually or in the aggregate, are reasonably expected to have a material adverse effect on our financial position, results of operations, or cash flows.

F-50

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

13. Subsequent Events

New Commodity Hedges

In July 2012, the Company entered into several commodity derivative transactions to more closely align the reference prices of its commodity derivative prices to the actual prices received for oil production. On August 10, 2012, the Company had the following open commodity positions:


	Hedged Volume		Weighted-Average Fixed Price
Oil (Bbls):
Swaps—2012		644,130	$	95.77
Swaps—2013		1,700,874		95.55
Swaps—2014		262,450		83.00

Collars—2012		68,850	$	85.00 - $127.28

Deferred Premium Puts—2012 (1)		229,500	$	79.01

Basis Differential Swaps—2012 (2)		789,480	$	9.81
Basis Differential Swaps—2013 (2)		1,700,874	$	5.91

Long-term Debt

On July 13, 2012, the Company borrowed an additional $20.0 million pursuant to the terms of the Amended Credit Facility.

Eagle Acquisition

On August 11, 2012, the Company and Midstates Petroleum Company, LLC (“Midstates Sub”), a wholly owned subsidiary of the Company, entered into an Asset Purchase Agreement (the “Agreement”) with Eagle Energy Production, LLC (“Eagle”), pursuant to which Midstates Sub agreed to acquire certain interests in producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and the related hedging instruments (the “Eagle Acquisition”). The aggregate purchase price, subject to adjustment as provided in the Agreement, consists of (a) $325 million in cash and (b) 325,000 shares of Series A Preferred Stock of the Company with an initial liquidation preference of $1,000 per share.

Eagle, the Company and Midstates Sub have made customary representations, warranties and covenants in the Agreement. Eagle has made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Agreement and the closing of the Eagle Acquisition and not to engage in certain kinds of transactions during that period, subject to certain exceptions. The Company has agreed not to take certain specified actions without Eagle’s consent during the time between execution of the Agreement and the closing of the Eagle Acquisition.

Consummation of the Eagle Acquisition is subject to various conditions, including, among others, (1) the accuracy of representations and warranties of the parties as of the closing date, including the absence of any material adverse effect with respect to each of Eagle’s business and the Company’s business, (2) the release of certain liens in connection with the repayment of Eagle’s indebtedness, (3) the execution of certain ancillary documents and (4) other customary closing conditions. The Eagle Acquisition will be effective June 1, 2012 and closing is expected to occur on or about October 1, 2012. The Agreement may be terminated under customary circumstances.

F-51

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

The Series A Preferred Stock will not become convertible into shares of the Company’s common stock until the 21st day after the date on which the Company mails to its stockholders an information statement regarding the issuance of the Series A Preferred Stock, and the holders of the Series A Preferred Stock may not convert before the first anniversary of the closing date of the Eagle Acquisition. After such time, the Series A Preferred Stock may be converted, in whole but not in part, at the option of the holders of a majority of the outstanding shares of Series A Preferred Stock, into a number of shares of the Company’s common stock calculated by dividing the then-current liquidation preference by the conversion price of $13.50 per share. In addition, the Series A Preferred Stock will be subject to mandatory conversion into shares of the Company’s common stock on September 30, 2015 at a conversion price no greater than $13.50 per share and no less than $11.00 per share. Dividends on the Series A Preferred Stock will accrue at a rate of 8.0% per annum, payable semi-annually, at the sole option of the Company, in cash or through an increase in the liquidation preference. The Series A Preferred Stock will also have the other rights and terms set forth on the Certificate of Designation, including voting rights that are similar to those belonging to holders of the Company’s common stock on an as-converted basis (except with respect to the election of directors and the approval of certain transactions where the holders of the Series A Preferred Stock would be entitled to consideration at least equal to the liquidation preference) until such time as holders of the Series A Preferred Stock are permitted to convert their shares into common stock and the market price of the Company’s common stock is above the conversion price for 15 consecutive trading days. In addition, the holders of the Series A Preferred Stock will have the right, subject to the terms and conditions set forth in the Certificate of Designations, to elect one member of the board of directors, and to approve certain corporate actions. The Series A Preferred Stock will rank senior to the Company’s common stock with respect to dividend rights. The issuance of the Series A Preferred Stock to Eagle pursuant to the Agreement has been approved by stockholders holding a majority of the outstanding shares of the Company’s common stock.

The purchase will be accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the Company is required to allocate the purchase price to tangible and identifiable intangible assets acquired and liabilities assumed based on their fair values at the Closing Date. The excess of the purchase price over those fair values, if any, is recorded as goodwill. Disclosures required by ASC 805, Business Combinations, will be provided once the closing occurs and the initial accounting for the acquisition is complete.

Commitment for Bridge Credit Facility and Amendment to Revolver

In connection with the execution of the Agreement, on August 11, 2012, the Company and Midstates Sub entered into a commitment letter with (after giving effect to certain subsequent joinders) Bank of America, N.A., Merrill Lynch, Pierce Fenner & Smith Incorporated, SunTrust Bank and SunTrust Robinson Humphrey, Inc., Goldman Sachs Lending Partners LLC and Morgan Stanley Senior Funding, Inc. to, among other things, (A) provide for an unsecured bridge credit facility in the amount of up to $500 million and (B) provide a commitment to amend the existing secured revolving credit facility to increase the borrowing base to $250 million and to accommodate, among other things, the issuance, incurrence and/or compliance with the terms of the Preferred Stock, bridge loans and other debt securities that may be issued or loans that may be incurred in lieu of, or in connection with the replacement of the bridge loans, including senior unsecured notes. The availability of loans under the bridge credit facility and the effectiveness of the amended revolving credit facility are subject to the consummation of the Eagle Acquisition and other customary conditions. The proceeds of the bridge credit facility may be used solely to fund the Eagle Acquisition, to pay transaction costs and expenses in connection therewith or repay existing outstanding debt under the existing revolving credit facility. If entered into, the bridge credit facility will initially bear interest at LIBOR, subject to a 1.50% floor, plus 9.0% and thereafter such 9.0% margin is subject to increases. The bridge credit facility matures on the first anniversary of the closing date of the Eagle Acquisition and contains customary terms regarding the conversion of the bridge loans into other debt instruments subject to certain caps on yield, the highest of which is set at 13.25%. The

F-52

MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

obligations under the bridge credit facility would be guaranteed by the same entities that guaranty the existing secured revolving credit facility. If entered into, the amended revolving credit facility would mature on the fifth anniversary of the entrance into the facility and the aggregate amount available under the credit facility would increase to $250 million, subject to reduction in the event that the amount of assets acquired in connection with the Eagle Acquisition is less than expected. In addition, it would increase the allowance for the incurrence of certain unsecured indebtedness, without a corresponding reduction in the borrowing base, from $275 million to $500 million thereby permitting the incurrence of the bridge loans or the issuance of other debt without causing a $0.25 reduction in the borrowing base for every $1 of debt incurred or issued above $275 million. The definitive loan documentation for the bridge loan facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to those in other similar transactions and will otherwise be similar to the terms set forth in the existing secured revolving credit facility. The definitive loan documentation for the amended revolving credit facility will contain representations and warranties, affirmative, negative and financial covenants and events of default similar to the terms set forth in the existing secured revolving credit facility and which address the above mentioned accommodations.

In addition, on August 11, 2012, the Company and Midstates Sub entered into a second commitment letter with SunTrust Bank, SunTrust Robinson Humphrey, Inc., Bank of America N.A. and Merrill Lynch, Pierce Fenner & Smith Incorporated to underwrite an amendment to the existing secured revolving facility which provides for $35 million of non-conforming borrowing base loans (thereby increasing the borrowing base under the existing secured revolving credit facility from $200 million to $235 million) and waives the requirement to comply with the minimum current ratio financial covenant for the quarters ending September 30, 2012 and December 31, 2012. This amendment is not dependent upon the consummation of the Eagle Acquisition. The availability of non-conforming borrowing base loans will end upon the earliest to occur of (i) the closing of the Eagle Acquisition, (ii) the issuance of certain unsecured indebtedness permitted under the existing secured revolving credit facility and (iii) the scheduled March 2013 borrowing base redetermination. Thereafter, subject to the other commitments contemplated by the other commitment letter discussed above, the borrowing base would reduce to $200 million and loans would be permitted subject to the $200 million borrowing base. Borrowings under the terms of the amended revolving credit facility would bear interest at the same rates applicable to the existing secured revolving credit facility, provided that if borrowing base usage exceeded $200 million the amount of applicable margin would increase to up to 3.00% in the case of base rate loans and 4.00% in the case of LIBOR loans. Similarly, commitment fees would be the same rates applicable to the existing secured revolving credit facility subject to an increase up to 0.625% if borrowing base usage exceeded $200 million. The definitive loan documentation for this amended revolving credit facility will be effective upon the satisfaction of customary conditions and contain representations and warranties, affirmative, negative and financial covenants and events of default substantially the same as the terms set forth in the existing secured revolving credit facility.

F-53

Report of Independent Auditors

The Board of Directors and Members of

Eagle Energy Company of Oklahoma, LLC

We have audited the accompanying consolidated balance sheets of Eagle Energy Company of Oklahoma, LLC as of December 31, 2011 and 2010, and the related consolidated statements of income, changes in members’ equity, and cash flows for the years ended December 31, 2011, and 2010, and the period from December 11, 2009 (Inception) to December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Eagle Energy Company of Oklahoma, LLC at December 31, 2011 and

2010, and the consolidated results of its operations and its cash flows for the years ended December 31,

2011, and 2010, and the period from December 11, 2009 (Inception) to December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

April 13, 2012

F-54

Eagle Energy Company of Oklahoma, LLC

Consolidated Balance Sheets


	December 31
	2011		2010
	(In Thousands)
Assets
Cash	$	9,986	$	3,675
Accounts receivable		20,052		13,674
Derivative assets, net		6,435		3,163
Prepaid expenses and other current assets		778		818

Total current assets		37,251		21,330

Properties and equipment, net—successful efforts method		205,198		140,347
Noncurrent derivative assets, net		28		2,643
Other noncurrent assets		3,960		2,115

Total assets	$	246,437	$	166,435

Liabilities and members’ equity
Current liabilities:
Accounts payable and accrued liabilities		21,717		8,235

Total current liabilities		21,717		8,235

Long-term debt		114,000		86,500
Asset retirement obligations		1,545		780
Contingent liabilities and commitments (Note 8)
Members’ equity		109,175		70,920

Total liabilities and members’ equity	$	246,437	$	166,435

See accompanying notes.

F-55

Eagle Energy Company of Oklahoma, LLC

Consolidated Statement of Income


	Years Ended December 31,						For the Period
	2011			2010			December 11, 2009 (Inception) to December 31, 2009
	(In Thousands)
Revenues:
Oil and gas sales	$	73,446		$	30,340		$	945
Realized and unrealized gains (losses) on derivatives		4,240			9,893			(354	)

Total revenues		77,686			40,233			591

Expenses:
Lease operating		12,130			9,173			83
Production taxes		3,090			2,195			67
Depletion, depreciation, and amortization		18,889			9,739			80
Impairment of oil and gas properties		6,338			2,188			—
Exploration		804			—			—
General and administrative		5,074			3,441			1,919
Other		813			31			30

Total expenses		47,138			26,767			2,179

Operating income (loss)		30,548			13,466			(1,588	)

Other income (expenses):
Interest expense		(6,965	)		(4,021	)		(83	)
Other		(27	)		(258	)		(8	)

Total other income (expenses)		(6,992	)		(4,279	)		(91	)

Net income (loss)	$	23,556		$	9,187		$	(1,679	)

See accompanying notes.

F-56

Eagle Energy Company of Oklahoma, LLC


	Total Members’ Equity
	(In Thousands)
Members’ equity at December 11, 2009 (Inception)	$	—
Contributions		35,000
Distributions		(1,048	)
Net income		(1,679	)

Members’ equity at December 31, 2009	$	32,273
Contributions		30,000
Distributions		(540	)
Net income		9,187

Members’ equity at December 31, 2010	$	70,920
Contributions		15,000
Distributions		(301	)
Net income		23,556

Members’ equity at December 31, 2011	$	109,175

See accompanying notes.

F-57

Eagle Energy Company of Oklahoma, LLC

Consolidated Statement of Cash Flows


	For the Years Ended December 31,						For the period
	2011			2010			December 11, 2009 (Inception) to December 31, 2009
	(In Thousands)
Operating activities
Net income (loss)	$	23,556		$	9,187		$	(1,679	)
Adjustments to reconcile to cash provided by operations:
Depletion, depreciation and amortization		18,889			9,739			80
Amortization of debt financing costs		1,182			934			30
Impairment of oil and gas properties		6,338			2,188			—
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable		(6,378	)		(11,680	)		(4,082	)
Prepaid expenses and other current assets		37			(787	)		(31	)
Accounts payable		5,797			2,918			790
Changes in current and noncurrent derivative assets, net		(657	)		(6,160	)		354

Net cash provided by operating activities		48,764			6,339			(4,538	)

Investing activities
Acquisitions of oil and gas properties		(7,600	)		(33,566	)		(61,565	)
Capital expenditures		(74,890	)		(46,760	)		—
Other		—			(8	)		—

Net cash used in investing activities		(82,490	)		(80,334	)		(61,565	)

Financing activities
Borrowings under credit agreements		27,500			43,500			43,000
Debt financing costs		(2,163	)		(650	)		(2,429	)
Contributions by members		15,000			27,000			35,000
Distributions		(300	)		(600	)		(1,048	)

Net cash provided by financing activities		40,037			69,250			74,523
Increase (decrease) in cash		6,311			(4,745	)		8,420
Cash at the beginning of the year		3,675			8,420			—

Cash at the end of the year	$	9,986		$	3,675		$	8,420

Supplemental non-cash transactions:
Change in accrued capital expenditures	$	1,829		$	4,587		$	—
Change in asset retirement obligations	$	765		$	484		$	—
Noncash property contribution	$	—		$	3,000		$	—

See accompanying notes.

F-58

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

1. Organization, Operations and Basis of Presentation

Organization and Operations

Unless otherwise noted, the terms “we,” “us,” “our,” “management” and other similar terms refer to Eagle Energy Company of Oklahoma, LLC (the Company), an Oklahoma limited liability company. We were formed on December 11, 2009 (Inception) with a focus on the acquisition, exploration, development, and production of natural gas and crude oil in the Mid-Continent region of the United States. Our wholly owned subsidiary, Eagle Energy Operating GP, LLC is the general partner (0.01%) of Eagle Energy Operating Company, LLC in which we own a substantial majority interest (99.99%). Eagle Energy Operating Company operates its wholly owned subsidiary, Eagle Energy Production, LLC.

The Company is headquartered in Tulsa, Oklahoma. The Company’s operations are primarily in Oklahoma, in the counties of Woods, Alfalfa and Lincoln, with drilling efforts primarily focused in the Mississippian Limestone geological formations.

2. Summary of Significant Accounting Policies

Basis of Presentation

We prepared the consolidated financial statements in accordance with accounting principles generally accepted in the United States and included the accounts of the Company and our wholly owned, controlled subsidiaries. We eliminated intercompany accounts and transactions.

Use of Estimates

The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil and natural gas reserves used in calculating depreciation, depletion and amortization (DD&A); the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations; future asset retirement obligations; impairments of undeveloped properties; and valuations of derivatives. These estimates are discussed further throughout these notes.

Cash and Cash Equivalents

All highly liquid investments purchased with an original maturity of three months or less are considered cash equivalents.

Product Revenues

Revenues from sales of crude oil, natural gas and other hydrocarbons are recognized when the product is sold and delivered. Production revenue from properties in which we have an interest with other producers is recognized based on actual volumes sold (the sales method) during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be non-recoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. The Company has no material imbalances at December 31, 2011 or 2010.

F-59

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

Accounts Receivable

The Company sells oil, natural gas and related products to various customers and participates with other parties in the drilling, completion and operation of oil and natural gas wells. Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The Company had no allowance for doubtful accounts at December 31, 2011 or 2010; and there was no provision for bad debt expense for any period presented.

Accounts receivable is comprised of the following at December 31, 2011 and 2010:


	December 31,
	2011		2010
	(In Thousands)
Receivables by product or service:
Sale of oil, natural gas and related products	$	10,197	$	5,169
Joint interest owners		9,682		8,118
Other		173		387

Accounts receivable	$	20,052	$	13,674

Inventory

Inventory, which is included in Prepaid expenses and other current assets, consists principally of tubular goods, spare parts and equipment that is used in the Company’s drilling operations. Inventory is stated at the lower of cost or market and is relieved using the specific identification method. The inventory balance was $515 thousand and $562 thousand at December 31, 2011 and 2010, respectively. There were no provisions related to obsolete or slow-moving inventory for either year.

Properties and Equipment

The Company’s oil and gas exploration and production activities are accounted for using the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expense. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.

Properties and Equipment

Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the unit-of-production method based on estimated proved developed oil and gas reserves on a field basis. Depletion of producing leasehold costs is based on the unit-of-production method using estimated proved oil and gas reserves on a field basis. The rates we utilize under the units-of-production methodology are based on our estimates of proved oil and gas reserves.

F-60

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as Impairment of oil and gas properties in the Consolidated Statement of Operations. Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage and other relevant factors.

Other exploration costs, including geological and geophysical costs and lease delay rentals are charged to expense as incurred and are included in Exploration expenses.

We record other property and equipment at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repairs are expensed as incurred. Depreciation for these assets is computed using the straight-line method over estimated useful lives. Upon retirement or disposition of assets, the costs and related accumulated depreciation are removed from the accounts with the resulting gain or losses, if any, reflected in results of operations.

Impairment of Long-lived Assets

The Company reviews its proved oil and gas properties for impairment whenever events or changes in circumstances indicate, in our management’s judgment, that a decline in the recoverability of their carrying value may have occurred. Assets are grouped for impairment purposes at the field level. When an indicator of impairment has occurred, we compare our estimate of undiscounted cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Judgment’s and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs and appropriate discount rates.

Debt Placement Costs

Costs incurred for debt borrowings are capitalized as paid and amortized over the life of the associated debt instrument using the effective interest method. When debt is retired prior to scheduled maturity, remaining placement costs associated with that debt are expensed. Unamortized debt financing costs were $3.01 million and $2.12 million as of December 31, 2011 and 2010, respectively, and are included in Other non-current assets.

Asset Retirement Obligations

The Company has obligations under its lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (ARO) primarily relate to costs necessary to plug and abandon wells. We record an asset and a liability upon incurrence equal to the present value of each expected future ARO. These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium.

F-61

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

The ARO asset is depreciated in a manner consistent with the depreciation or depletion of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in Depletion, depreciation and amortization expenses.

A roll forward of our asset retirement obligation liability is presented below:


	December 31,
	2011		2010
	(In Thousands)
Beginning balance	$	780	$	296
Liabilities incurred during the period		165		475
Revisions in cost estimates		545		—
Accretion expense		55		9

Ending balance	$	1,545	$	780

Derivatives

In addition to requirements under our credit agreements, the Company utilizes commodity derivative financial instruments, including swaps and collars, to manage risks related to changes in oil, natural gas and NGL prices. See Note 10—Derivative Instruments for further discussion. The Company records all derivative instruments as either assets or liabilities measured at their estimated fair value. We do not hedge volumes in excess of our expected oil, natural gas and NGL production (i.e. we do not enter into speculative trading positions). We have not designated our derivative instruments as cash flow hedges for accounting purposes, but they do serve as economic hedges of our production. All realized gains and losses from the settlement of commodity derivative instruments and unrealized gains and losses from valuation changes in the remaining unsettled commodity derivative instruments are reported in Realized and unrealized gains (losses) on derivatives revenues. Unrealized gains are included in current and noncurrent assets and unrealized losses are included in current and noncurrent liabilities on the Consolidated Balance Sheet, respectively.

Our derivatives are presented on a net basis, as those with both gain and loss positions are held by a single counterparty and are subject to a master netting arrangement. We determine current and noncurrent classification based on the timing of expected future cash flows of individual trades.

Under the terms of our credit facility, we are required to execute all hedge transactions with an approved counterparty. All of our derivative financial instruments are currently executed with the agent bank of our senior credit facility. The creditworthiness of our counterparty is subject to continual review by our management and we believe the risk of non-performance to be low.

The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement. We are not required to provide any collateral support to our counterparty other than cross collateralization with the properties securing our credit facility. Under the terms of our credit facility, new hedge positions are limited to 85% of projected future production for three years and 75% of projected production for the fourth year following the date of the hedge transaction.

F-62

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

Reclassifications

Prior year amortization of debt placement costs have been reclassified from Depreciation, depletion and amortization expense to conform to current year presentation in Other income (expense).

3. Property and Equipment

Acquisitions

In December of 2009, we closed on our purchase of proved and unproved properties from Special Exploration Co., Inc. (Special) located in Lincoln, Alfalfa and Woods counties in Oklahoma. The purchase had an effective date of September 1, 2009, on which date Special conveyed all of its right, title and interest in the properties to Eagle Energy Production, LLC along with related operating contracts. The purchase price was $61.28 million (which is net of a purchase price adjustment of $2.71 million that was received during 2010) and the purchase price was allocated to the oil and gas properties acquired on a property-by-property basis.

At December 31, 2009, these wells were externally managed by Special. In February 2010, the Company took over operatorship of all properties purchased from Special. During 2010, we completed additional purchases of incremental ownership interests in these properties from nine separate parties.

During 2010, we acquired ownership interests in certain oil and gas property in Haskell County, Oklahoma, for $3 million from HISAW partners, a related party. This acquisition was in addition to the related assets, as discussed in Note 4.

During 2011, we closed on an agreement with an unrelated party to acquire additional ownership interests in certain oil and gas property leases in northwest Oklahoma for a purchase price of $7.6 million. This consisted of $1.6 million of proved property and $6 million of unproved property.

These acquisitions qualify as business combinations, and as such, the Company estimated the fair value as of each acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. To estimate the fair value of proved properties, the Company used a discounted cash flow model and made market assumptions for future commodity prices, projections of estimated quantities of reserves, expectations for timing and amount of future development and operating costs, and projections of future rates of production, and expected recovery rates. Due to the unobservable nature of the inputs, these estimates of the proved and unproved oil and gas properties are considered Level 3 fair value measurements; see further discussion in Note 9—Fair Value Measurements.

F-63

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

Properties and equipment

Properties and equipment are carried at cost and include the following at December 31, 2011 and 2010:


	Estimated Useful Life	2011			2010
	(In Thousands)
Proved properties	(a)	$	189,886		$	145,351
Unproved properties	(b)		27,359			3,351
Construction in progress	(b)		15,939			391
Office and other equipment	36-60 months		690			1,097

Total at cost			233,874			150,191
Accumulated depletion, depreciation, and amortization			(28,676	)		(9,843	)

Properties and equipment, net			205,198			140,347

(a)	Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).

(b)	Unproved properties and construction in progress are not yet subject to depreciation and depletion.

During 2011, the Company recognized an impairment of $1.4 million on its well and equipment costs located in Haskell County, Oklahoma. These wells have not produced commercially. Management evaluated the estimated future cash flows of the field and determined that required significant infrastructure investments in the area render the wells uneconomic. We recognized additional impairment charges of $3.9 million on remaining undeveloped acreage located in Haskell County, Oklahoma and $1 million related to undeveloped acreage in Lincoln County, Oklahoma and Northwest Oklahoma expiring in 2012. During 2010, the Company recognized an impairment charge of $2.2 million related to undeveloped acreage held by leases expiring in Haskell County.

4. Related Party Transactions

In March of 2010, the Company’s CEO, Steve Antry, contributed undeveloped acreage to the Company for consideration of three million Series A units. As disclosed in Note 3, we have recognized non-cash impairment charges related to this acreage during 2011 and 2010.

The Company paid for goods and services in the amount of $899 thousand and $989 thousand in 2011 and 2010, respectively, from certain well servicing companies in which Mr. Antry directly and indirectly holds a controlling interest.

The Company is required to pay R/C IV Eagle Holdings, L.P. (“Riverstone”, its largest Series A Unitholder) an annual monitoring fee equal to $250 thousand. When Riverstone’s total capital contributions to the Company equal $100 million, the annual monitoring fee is equal to 1% of the aggregate amount of its capital contributions. We paid $250 thousand and $258 thousand in 2011 and 2010, respectively, to Riverstone related to this monitoring fee, which is recorded in Other income (expense).

The Company is obligated to pay a commitment fee promptly upon the funding of any Series A Unit capital contribution. The amount of such commitment fee is equal to 2% of each capital contribution made by Series A members. During 2011 and 2010, respectively, we received contributions of $14.2 million and $26.6 million from R/V IV Eagle Holdings, LP and $789 thousand and $421 thousand from Mr. Antry and we distributed 2% of such contributions back to each party. We accounted for the contributions and distributions as increases and decreases in equity.

F-64

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

5. Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities are comprised of the following at December 31, 2011 and 2010:


	December 31,
	2011		2010
	(In Thousands)
Accounts payable, trade	$	8,525	$	38
Accrued capital costs—gross		11,035		7,343
Accrued lease operating expenses		999		724
Accrued general and administrative expenses		497		34
Accrued interest payable		478		68
Other		183		28

Total	$	21,717	$	8,235

6. Debt

In 2009, the Company entered into a senior revolving credit agreement with a syndication of banks (the Lenders), totaling $150 million (the Credit Facility). During 2011, we amended and restated the Credit Facility which included an increase to $250 million. Borrowings under the Credit Facility are secured by the assets of Eagle Energy Production, LLC (which represents virtually all of the Company’s assets), including its oil and gas properties. Twice annually, the participating lenders determine the maximum amount of the $250 million which will be available for borrowings and letters of credit (Borrowing Base). The calculation is based on the lenders’ customary practices and standards, which focus on the value and nature of the assets which secure the facility. As of December 31, 2011, the Borrowing Base was $105 million. Borrowings under the Credit Facility incur interest at a LIBOR-based rate plus a margin which increases based on increases in the amount of the Borrowing Base (ranging from 2 to 3 percent) which is due and payable monthly and the principal balance is due August 2014. Issued letters of credit incur a standby fee ranging from 2 to 3 percent (also based on increases in the amount of the Borrowing Base). A commitment fee is assessed at a rate of 0.5%, dependent on the unused portion of the Credit Facility. As of December 31, 2011 and 2010, borrowings of $79 million and $74 million, respectively, were outstanding under this facility. Our letter of credit facility had total capacity of $10 million as of December 31, 2011 and 2010, respectively, of which $302 thousand and $262 thousand was outstanding, respectively. Amounts obligated for letters of credit are not reflected as debt on our consolidated balance sheet. The annual weighted-average interest rate on borrowings outstanding under the facility at December 31, 2011 and 2010 was 4.80% and 5.01%, respectively.

Our Credit Facility requires the Company to maintain certain specific financial ratios. The ratio of consolidated EBITDAX (generally defined as earnings before interest, taxes, depreciation, depletion, amortization, exploration expenses, and non-cash items which affect net income) to total interest expense may not be less than 2.75 to 1.00, the ratio of consolidated funded senior indebtedness to EBITDAX may not be greater than 4.00 to 1.00, the consolidated current ratio may not be less than 1.00 to 1.00, and the ratio of consolidated funded total indebtedness to EBITDAX may not be greater than 4.50 to 1.00. Further, the ratio of total proved reserves (discounted at 9%) to total consolidated funded indebtedness must be greater than 1.50 to 1.00.

In addition, the Credit Facility contains covenants that limit the Company’s ability to, among other things, incur indebtedness secured by certain liens or encumber its assets, engage in certain sale-leaseback transactions, and consolidate, merge or dispose of all or substantially all of its assets. As of December 31, 2011, we were in compliance with all financial covenants. If an event of default occurs and is continuing, the Lenders may declare all amounts due under the Credit Facility to be immediately due and payable.

F-65

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

In August of 2011, Eagle Energy Production, LLC entered into a second lien credit agreement with Citibank, as agent and issuer for the participating lenders, totaling $50 million (the “Second Facility”) which retired the existing $12.5 million second lien in place executed December 2010. The Second Facility includes cross-default provisions with the Credit Facility. Prepayment of principal of borrowings under the Second Facility is not permitted without the consent of the Credit Facility lenders.

Borrowings under the Second Facility are secured by the Company’s oil and gas properties and incur interest at a LIBOR-based rate plus a margin of 9 percent. Such interest is due and payable on a monthly basis and the principal balance is due February 2015. As of December 31, 2011 and 2010, $35 million and $12.5 million, respectively, were outstanding under our second lien facilities. The annual weighted-average interest rate on borrowings outstanding under these facilities at December 31, 2011 and 2010 was 10.06% and 9.47%, respectively.

We paid cash interest of $5.8 million, $3.1 million and $83 thousand during the years ended December 31, 2011, 2010 and the period ended 2009, respectively.

The amounts of required future principal payments as of December 31, 2011 are as follows:


	(In Thousands)
2012	$	—
2013		—
2014		79,000
2015		35,000
2016		—

	$	114,000

7. Concentration of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable and derivative instruments. The Company maintains cash and cash equivalents in bank deposit accounts which may at times exceed federally insured limits.

We have not experienced any significant losses from uncollectible receivables. The Company believes the creditworthiness of its customer base is high and has not experienced any significant write-downs in its account receivable balances. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Sales to purchasers of greater than ten percent of operating revenues consist of the following:


	For the years ended December 31,
Purchaser	2011			2010			2009
SemGas, L.P.		22	%		29	%		0.0	%
ConocoPhillips		46	%		9	%		0.0	%
DCP Midstream LLC		14	%		29	%		0.0	%
Scissor Tail Energy, LLC		10	%		25	%		0.0	%

If we were to lose any one of our customers, the loss could temporarily delay production and sale of oil and natural gas in our producing area, however, management believes that a substitute customer to purchase the impacted production volumes could be identified.

F-66

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

8. Commitments and Contingencies

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. We are unable to estimate the costs of asset additions or modifications which may be necessary to comply with any new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

We are involved in various legal actions and claims arising in the ordinary course of our business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

Commitments

Total rental charges incurred were $7.6 million, $3.7 million and $3 thousand in 2011, 2010 and 2009, respectively. Rent charges incurred for drilling rigs are capitalized under the successful efforts method of accounting.

9. Fair Value Disclosures

The Company’s derivative financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities at fair value on a non-recurring basis. As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.

These inputs can be readily observable, market corroborated or generally unobservable. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The Company classifies fair value balances based on the observability of those inputs.

The three levels of the fair value hierarchy are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards and options.

F-67

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table summarizes by level the Company’s financial assets that were accounted for at fair value on a recurring basis as of December 31, 2011 and 2010, based on the fair value hierarchy:


	Fair Value Measurements at December 31, 2011 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2011
Energy derivative assets	$	—	$	6,463	$	—	$	6,463


	Fair Value Measurements at December 31, 2010 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2010
Energy derivative assets	$	—	$	5,806	$	—	$	5,806

The Level 2 instruments presented in the table above consist of oil, liquids and natural gas collars and swaps. The Company utilizes the mark-to-market valuation reports provided by our counterparty for monthly settlement purposes to determine the valuation of our derivative instruments. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk, as required in the authoritative guidance. The Company calculated the credit adjustment for derivatives in an asset position using the credit default swap rate for our counterparty. Based on this computation the adjustment for credit risk is not significant. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

During 2011, we recorded an impairment charge on our Haskell County oil and gas well and equipment costs based on our estimate of fair value on a nonrecurring basis. Significant assumptions used in our assessment include estimates of future reserve quantities, estimates of future prices using a forward NYMEX curve adjusted for locational differences, expected capital costs including infrastructure costs required to produce the wells and a discount rate of ten percent. Based on the capital costs required to produce and ultimately market production from the wells we determined them to be uneconomic and fully impaired the costs.

10. Derivative Instruments

All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at their estimated fair value, see Note 9—Fair Value Measurements. We do not enter into these arrangements for speculative trading purposes.

F-68

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

As of December 31, 2011, the table on the following page sets forth our outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedges.


Period	Contract	Quantity Type	Notional Volume		Range of Hedge Prices
Natural Gas
2012	Swap	MMBtu		2,114,100	$	6.51
2013	Swap	MMBtu		176,700	$	6.52
2012	Collar	MMBtu		492,000	$	4.50-5.15
2013	Collar	MMBtu		1,524,000	$	4.00-5.61
2014	Collar	MMBtu		1,189,500	$	4.38-5.38
2015	Collar	MMBtu		25,500	$	4.00-4.92

Crude oil
2012	Swap	Bbls		38,814		86.63
2013	Swap	Bbls		18,647		86.19
2014	Swap	Bbls		1,500		86.30
2012	Collar	Bbls		209,000	$	90.47-$103.24
2013	Collar	Bbls		145,500	$	84.01-$97.43
2014	Collar	Bbls		118,500	$	87.62-$95.76
2015	Collar	Bbls		9,400	$	85.00- $95.25

NGLs
2012	Swap	Gallons		9,874,200	$	1.64
2013	Swap	Gallons		7,543,200	$	1.50
2014	Swap	Gallons		4,956,000	$	1.46

Natural gas basis
2012	Swap	MMBtu		2,114,100		(0.46	)
2013	Swap	MMBtu		176,700		(0.46	)

The combined fair value of derivatives included in our consolidated balance sheet as of December 31, 2011 and 2010 is summarized below. We conduct derivative activities with only one financial institution, who is the agent of our Credit Facility. This may result in a concentration of credit risk. Our derivative assets and liabilities are presented in our consolidated balance sheets on a net basis, as our derivatives with both gain and loss positions are held by a single counterparty and are subject to a master netting arrangement. The fair value amounts in the table below are presented on a gross basis:


	December 31,
	2011		2010
	(In Thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Natural gas—derivatives	$	9,412	$	7,596
NGLs—derivatives	$	758	$	—
Derivative liabilities:
Crude Oil—derivatives	$	1,703	$	1,791
Natural gas—derivatives	$	714	$	—
NGLs—derivatives	$	1,290	$	—

F-69

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

The following table summarizes the effect of the Company’s derivative contracts on the accompanying consolidated statements of operations for the years ended December 31, 2011 and 2010 (in thousands):


Type of Contract	Location of Gain Recognized in Income	December 31,
Type of Contract	Location of Gain Recognized in Income	2011		2010
Energy derivatives	Realized and unrealized gain on derivatives	$	4,240	$	9,893

The following table summarizes the cash settlements and valuation gains and losses from our commodity derivative contracts for the years ended December 31, 2011 and 2010 (in thousands):


	December 31,
Oil and Natural Gas Derivatives	2011		2010
Realized gain	$	3,583	$	3,421
Unrealized gain		657		6,472

Realized and unrealized gains on derivatives		4,240		9,893

11. Members’ Equity and Distributions

The Company was initially funded through (i) a $35 million contribution from its affiliate R/V IV Eagle Holdings, LP (in exchange for Series A Units in the Company) and (ii) a $3 million contribution from S&L Antry, LLC (beneficially owned by Steve and Lisa Antry) and Steve Antry relating to the purchase of HISAW undeveloped acreage. During 2011 and 2010, respectively, an additional $15 million and $27 million was contributed by the initial Series A Unit holders.

The Company’s Series A Unit holders have the right, among other things, to appoint a Board of Directors. Pursuant to the Company’s operating agreement, Riverstone has the right to appoint three directors, and the Company’s management has the right to appoint two directors.

The following items require approval of the Board of Directors and two thirds of the Series A Units.

•

making capital calls to fund capital contributions

•

making distributions other than cash distributions (cash distributions only require Board of Director approval)

•

removing any member of the Company’s management team

•

effecting a liquidation event of the Company and

•

changing the Company’s experts on technical matters

The Company is authorized to issue Series B Units as an incentive to its management team, employees and key advisors. These units constitute “profits interests” and have an initial threshold value of $0. The recipients of the Series B Units are not required to contribute capital upon receipt of the B units. However, under certain circumstances, the Series B Unitholders may be allocated items of income or loss for Federal Income Tax purposes. Further, the Series B Unitholders may participate in distributions from the Company based upon a contractual formula. The Series B Units have limited voting rights, are subject to various performance and forfeiture provisions, and are subject to a vesting schedule based on length of service with the Company. As of December 31, 2011 and 2010, respectively, there were 119,149 and 117,000 outstanding Series B Units.

F-70

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

The Series B Units vest according to the following schedule: 20% on each of the first three grant anniversary dates, and 40% upon a liquidation event. Management has evaluated the terms of the awards and, in particular, the fact that the value of the units is contingent upon certain liquidity events which have not yet occurred, and has determined that related compensation expense for 2011 and 2010 is $0.

For purposes of determining capital account balances, the Company allocates net income to its unit holders based on contractually determined profit and loss sharing arrangements and actual cash or property contributions and distributions. Distributions are made pursuant to what is commonly referred to as a “waterfall” whereby the Series B Units increase their share of the distributions as the Series A Units achieve certain cash returns.

12. Income Taxes

The Company is organized as a limited liability company and is classified as a partnership for federal income tax purposes. Due to its partnership classification, the Company is not subject to federal income tax. Similarly, most states treat entities classified as partnerships for federal income tax purposes as partnerships for state purposes. As such, income tax liabilities are passed through to the members.

13. Subsequent Events

We evaluated subsequent events through April 13, 2012, which is the day the financial statements were issued.

On March 19, 2011 a fire began at the Company operated Buckles 1H-3 during drilling which resulted in damage to the drilling rig on location, other equipment in the area and some adjacent property. We incurred charges during the year related to clean up and site remediation. We filed suit against our insurer for specific performance under our policy and ultimately entered mediation. On March 29, 2012, a tentative settlement agreement was reached under which we anticipate that we will recover approximately $600,000 for charges incurred.

Information Subsequent to Initial Date of Report of Independent Auditors (Unaudited)

On August 11, 2012, the Company entered into an Asset Purchase Agreement (the “Agreement”) with Midstates Petroleum Company, LLC (“Midstates”), pursuant to which the Company has agreed to sell substantially all of its producing oil and natural gas assets, unevaluated leasehold acreage in Oklahoma and Kansas and related hedging instruments. The aggregate purchase price, subject to adjustment as provided in the Agreement, consists of (a) $325 million in cash and (b) 325,000 shares of Series A Preferred Stock of the Company with an initial liquidation preference of $1,000 per share.

The Company and Midstates have made customary representations, warranties and covenants in the Agreement. Midstates has agreed not to take certain specified actions without the Company’s consent during the time between execution of the Agreement and the closing of the sale. The Company has made certain additional customary covenants, including, among others, covenants to conduct its business in the ordinary course between the execution of the Agreement and the closing and not to engage in certain kinds of transactions during that period, subject to certain exceptions.

F-71

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

connection with the repayment of our indebtedness, (3) the execution of certain ancillary documents and (4) other customary closing conditions. The sale will be effective June 1, 2012 and closing is expected to occur on or about October 1, 2012. The Agreement may be terminated under customary circumstances.

Amounts outstanding under our credit facilities will be retired with the proceeds received at closing.

F-72

Eagle Energy Company of Oklahoma, LLC

Supplemental Oil and Gas Disclosures

(Unaudited)

14. Supplemental Oil and Gas Disclosures—(Unaudited)

The supplemental data presented herein reflects information for all of the Company’s oil and natural gas producing activities.

Capitalized Costs

The following table sets forth the capitalized costs related to the Company’s oil and natural gas producing activities at December 31, 2011 and 2010:


	2011			2010
	(In Thousands)
Proved properties	$	205,825		$	145,742
Unproved Properties		27,359			3,351

Total at cost		233,184			149,093
Less: Accumulated depletion, depreciation, and amortization		(28,367	)		(9,718	)

Total oil and gas properties, net		204,817			139,375

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the years ended December 31, 2011 and 2010 and for the period from December 11, 2009 (Inception) to December 31, 2009:


	December 31,
	2011		2010		2009
	(In Thousands)
Acquisition
Proved	$	1,565	$	32,652	$	59,935
Unproved		24,008		1,843		1,508
Exploration		804		—		—
Development		57,753		52,374		—
Asset retirement obligations		765		485		296

Total costs incurred	$	84,895	$	87,354	$	61,739

•

Costs incurred include capitalized and expensed items

•

Exploration costs include the costs incurred for geological and geophysical activity

Estimated Quantities of Proved Oil and Natural Gas Reserves

The reserve estimates presented in the following table at December 31, 2011 are based on reports prepared by Netherland, Sewell & Associates, Inc., independent reserve engineers. The reserve report was prepared in accordance with the FASB’s authoritative guidance on oil and gas reserve estimation and disclosures. All of the Company’s oil and natural gas producing activities are conducted within the continental United States.

F-73

Eagle Energy Company of Oklahoma, LLC

Supplemental Oil and Gas Disclosures

(Unaudited)

The following table sets forth the Company’s net proved, proved developed and proved undeveloped reserves at December 31, 2011, 2010 and 2009:


	Oil (MBbl)			Gas (MMcf)			NGL (MBbl) (1)			MBoe
2009
Proved reserves
Beginning balance		—			—			—			—
Acquisition of reserves		1,651			123,324			—			22,206
Production		—			(143	)		—			(24	)

Net proved reserves at December 31, 2009		1,651			123,181			—			22,182
Proved developed reserves, December 31, 2009		168			33,583			—			5,766
Proved undeveloped reserves, December 31, 2009		1,483			89,598			—			16,416

2010
Proved reserves
Beginning balance		1,651			123,181			—			22,182
Revisions of previous estimates		342			(90,150	)		—			(14,684	)
Extensions and discoveries		1,097			24,658			—			5,207
Acquisition of reserves		222			9,248			—			1,764
Production		(77	)		(4,593	)		—			(843	)

Net proved reserves at December 31, 2010		3,235			62,344			—			13,626
Proved developed reserves, December 31, 2010		1,358			38,430			—			7,763
Proved undeveloped reserves, December 31, 2010		1,877			23,914			—			5,863

2011
Proved reserves
Beginning balance		3,235			62,344			—			13,626
Revisions of previous estimates		(460	)		(31,248	)		2,482			(3,185	)
Extensions and discoveries		6,721			34,625			3,669			16,160
Production		(424	)		(4,023	)		(422	)		(1,517	)

Net proved reserves at December 31, 2011		9,072			61,698			5,729			25,084
Proved developed reserves, December 31, 2011		2,989			28,121			2,809			10,486
Proved undeveloped reserves, December 31, 2011		6,083			33,577			2,920			14,598

(1)	Prior to 2011, the Company’s reserve estimates were prepared based on wet gas volumes. Beginning in 2011, NGLs reserve volumes have been estimated separately.

F-74

Eagle Energy Company of Oklahoma, LLC

Supplemental Oil and Gas Disclosures

(Unaudited)

Revisions of previous estimates

Revisions in 2011 and 2010 primarily relate to the reclassification of reserves from proved to probable locations not expected to be developed within five years. Beginning in mid-2010 through the end of 2011, the Company devoted substantially all of its capital spending to its Mississippian Limestone properties. As such, negative reserve revisions relate primarily to reserves related to the Hunton formation not expected to be developed within five years.

Extensions and discoveries

Extensions and discoveries in 2011 and 2010 relate primarily to drilling activity in our Mississippian Limestone properties.

Acquisition of Reserves

Acquired reserves for 2009 are comprised entirely of the mineral interests acquired from Special. Reserves acquired in 2010 consist primarily of incremental working interests in existing wells previously acquired from Special.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include depreciation, depletion and amortization of capitalized acquisition, exploration and development costs.

Our estimated proved reserves and related future net revenues and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The un-weighted arithmetic average first-day-of-the-month prices for the prior 12 months were $60.94/Bbl WTI posted price for oil and $3.87/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2009, $79.79/Bbl WTI posted price for oil and $4.39/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2010, and $92.71/Bbl WTI posted price for oil and $4.118/MMBtu Platt’s Gas Daily Henry Hub for natural gas at December 31, 2011. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.

Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

F-75

Eagle Energy Company of Oklahoma, LLC

Supplemental Oil and Gas Disclosures

(Unaudited)


	December 31,
	2011			2010			2009
Future cash inflows	$	1,323,470		$	531,864		$	577,347
Future production costs		(335,130	)		(174,464	)		(164,944	)
Future development costs		(132,396	)		(57,382	)		(150,999	)
Future income tax expense (1)		—			—			—

Future net cash flows		855,944			300,018			261,404
10% annual discount for estimated timing of cash flows		(419,693	)		(139,487	)		(124,132	)

Standardized measure of discounted future net cash flows	$	436,251		$	160,531		$	137,272

(1)

Does not include the effects of income taxes on future revenues because as of December 31, 2011, 2010 and 2009, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. If the Company were subject to entity-level taxation, the unaudited pro forma future income tax expense at December 31, 2011, 2010 and 2009 would have been $279,032, $74,620 and $79,269, respectively. The unaudited pro forma Standardized Measure at December 31, 2011, 2010 and 2009 would have been $291,472, $121,533 and $95,645, respectively.

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the periods presented.


	2011			2010			2009
	(in thousands)
January 1,	$	160,531		$	137,272		$	—
Net changes in prices and production costs		84,297			44,838			—
Net changes in future development costs		(25,413	)		(8,289	)		—
Sales of oil and natural gas, net		(59,896	)		(20,839	)		(864	)
Extensions		296,677			47,957			—
Discoveries		—			—			—
Purchases of reserves in place		—			23,302			138,136
Revisions of previous quantity estimates		(37,532	)		(90,867	)		—
Previously estimated development costs incurred		31,500			112			—
Accretion of discount		16,053			13,727			—
Net change in income taxes		—			—			—
Changes in timing, other		(29,966	)		13,318			—

Period End	$	436,251		$	160,531		$	137,272

F-76

Eagle Energy Company of Oklahoma, LLC

Condensed Consolidated Balance Sheets

(Unaudited)


	June 30, 2012			December 31, 2011
	(In Thousands)
Assets
Cash	$	3,803		$	9,986
Accounts receivable		21,708			20,052
Derivative assets, net		12,535			6,435
Prepaid expenses and other current assets		960			778

Total current assets		39,006			37,251

Properties and equipment—successful efforts method		257,612			233,874
Less—accumulated depreciation, depletion and amortization		(25,692	)		(28,676	)

Properties and equipment, net		231,920			205,198
Noncurrent derivative assets, net		6,195			28
Other noncurrent assets		4,450			3,960

Total assets	$	281,571		$	246,437

Liabilities and members’ equity
Current liabilities:
Accounts payable and accrued liabilities		19,544			21,717

Total current liabilities		19,544			21,717

Long-term debt		153,000			114,000
Asset retirement obligations		1,671			1,545
Contingent liabilities and commitments (Note 8)
Members’ equity		107,356			109,175

Total liabilities and members’ equity	$	281,571		$	246,437

See accompanying notes.

F-77

Eagle Energy Company of Oklahoma, LLC

Condensed Consolidated Statements of Income

(Unaudited)


	Six Months Ended June 30,
	2012			2011
	(In Thousands)
Revenues:
Oil and gas sales	$	47,097		$	27,621
Realized and unrealized gains (losses) on derivatives		16,165			(1,028	)

Total revenues		63,262			26,593

Expenses:
Lease operating		7,263			5,386
Production taxes		1,696			2,018
Depletion, depreciation, and amortization		12,889			7,193
Impairment of oil and gas properties		35,767			409
Exploration		11			102
General and administrative		2,723			1,295
Other		(35	)		45

Total expenses		60,314			16,448

Operating income		2,948			10,145

Other income (expenses):
Interest expense		(4,648	)		(2,987	)
Other		(119	)		(55	)

Total other income (expenses)		(4,767	)		(3,042	)

Net income (loss)	$	(1,819	)	$	7,103

See accompanying notes.

F-78

Eagle Energy Company of Oklahoma, LLC

Condensed Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
	2012			2011
	(In Thousands)
Operating activities
Net income (loss)	$	(1,819	)	$	7,103
Adjustments to reconcile to cash provided by operations:
Depletion, depreciation and amortization		12,889			7,193
Amortization of debt financing costs		551			532
Impairment of oil and gas properties		35,767			409
Cash provided (used) by changes in current and noncurrent assets and liabilities:
Accounts receivable		(1,656	)		3,877
Prepaid expenses and other current assets		(181	)		(234	)
Accounts payable		(5,398	)		1,256
Changes in current and noncurrent derivative assets, net		(12,267	)		2,259
Other noncurrent assets		(1,041	)		—

Net cash provided by operating activities		26,845			22,395

Investing activities
Capital expenditures		(72,028	)		(41,151	)

Net cash used in investing activities		(72,028	)		(41,151	)

Financing activities
Borrowings under credit agreements		39,000			6,000
Contributions by members		—			15,000
Distributions		—			(300	)

Net cash provided by financing activities		39,000			20,700
Increase (decrease) in cash		(6,183	)		1,944
Cash at the beginning of the year		9,986			3,675

Cash at the end of the period	$	3,803		$	5,619

Supplemental non-cash transactions:
Change in accrued capital expenditures	$	3,225		$	(2,581	)
Change in asset retirement obligations	$	126		$	82

See accompanying notes.

F-79

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

1. Organization, Operations and Basis of Presentation

Organization and Operations

2. Summary of Significant Accounting Policies

Basis of Presentation

Our accompanying interim condensed consolidated financial statements are unaudited and do not include all disclosures required in annual financial statements and therefore should be read in conjunction with the consolidated financial statements and notes thereto of the Company as of December 31, 2011 and 2010 and the years then ended and for the period from December 11, 2009 (Inception) through December 31, 2009, included elsewhere in this information statement.

The accompanying condensed consolidated financial statements of the Company include the accounts of the Company and our wholly owned subsidiaries. All intercompany transactions have been eliminated in consolidation.

In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the fair presentation have been included. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. Actual results could differ from those estimates. The results for the six months ended June 30, 2012 and 2011 are not necessarily indicative of annual results.

3. Impairments of Oil and Gas Properties

As a result of declines in forward natural gas prices, we performed an impairment assessment of our oil and gas producing properties. As a result of this assessment, we recorded a $35.1 million impairment of capitalized costs related to properties producing from the Hunton formation located in Lincoln county, Oklahoma.

The impairment recorded has been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy. Our assessment utilized estimates of future discounted cash flows. Significant judgments and assumptions in these assessments include estimates of recoverable reserve quantities, estimates of future crude oil and natural gas prices using a forward NYMEX curve adjusted for locations basis differentials, future natural gas liquids prices, expected capital costs related to future development activity and a discount rate of 10% for proved reserves.

F-80

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

4. Fair Value Disclosures

Assets and Liabilities Measure at Fair Value on a Recurring Basis

The Company utilizes a valuation framework based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further divided into the following fair value input hierarchy:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives, such as over-the-counter forwards and options.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table summarizes by level the Company’s financial assets that were accounted for at fair value on a recurring basis as of June 30, 2012 and December 31, 2011, based on the fair value hierarchy:


	Fair Value Measurements at June 30, 2012 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value as of June 30, 2012
Energy derivative assets	$	—	$	18,730	$	—	$	18,730

	Fair Value Measurements at December 31, 2011 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2011
Energy derivative assets	$	—	$	6,463	$	—	$	6,463

F-81

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

The Level 2 instruments presented in the previous table consist of oil, liquids and natural gas collars and swaps. The Company utilizes the mark-to-market valuation reports provided by our counterparty for monthly settlement purposes to determine the valuation of our derivative instruments. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk, as required in the authoritative guidance. The Company calculated the credit adjustment for derivatives in an asset position using the credit default swap rate for our counterparty. Based on this computation, the adjustment for credit risk is not significant. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Asset Retirement Obligations—The Company initially estimates the fair value of asset retirement obligations (ARO) based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, the amount and timing of settlements and the credit-adjusted risk-free interest rate and inflation rates.

See Note 3 for additional discussion related to the impairment recorded at June 30, 2012 based on a non-recurring fair value measurement.

5. Derivative Instruments

The Company is exposed to fluctuations in crude oil and natural gas prices on its production. The Company believes it is prudent to manage the variability in cash flows by entering into derivative financial instruments to economically hedge a portion of its crude oil, natural gas liquids and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to manage fluctuations in cash flows resulting from changes in commodity prices. These derivative contracts are placed with the lead of our credit facility. The commodity reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil, natural gas liquids and natural gas production.

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparty on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty.

F-82

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

As of June 30, 2012, the below table sets forth our outstanding commodity derivative contracts, all of which settle monthly, and none of which were designated as hedges.


Period	Contract	Quantity Type	Notional Volume		Range of Hedge Prices
Natural Gas
2012	Swap	MMBtu		1,043,100	$	6.52
2013	Swap	MMBtu		176,700	$	6.52
2012	Collar	MMBtu		744,000	$	3.25-3.88
2013	Collar	MMBtu		2,170,913	$	3.48-4.45
2014	Collar	MMBtu		1,806,420	$	3.77-4.87
2015	Collar	MMBtu		64,667	$	3.50-4.63

Crude oil
2012	Swap	Bbls		12,771		85.38
2013	Swap	Bbls		18,647		86.16
2014	Swap	Bbls		1,500		86.30
2012	Collar	Bbls		189,000	$	90.33-$105.63
2013	Collar	Bbls		217,587	$	86.97-$101.29
2014	Collar	Bbls		167,917	$	88.09-$98.89
2015	Collar	Bbls		13,400	$	87.50- $99.38

NGLs
2012	Swap	Gallons		8,215,200	$	1.74
2013	Swap	Gallons		11,302,200	$	1.63
2014	Swap	Gallons		7,266,000	$	1.58

Natural gas basis
2012	Swap	MMBtu		1,043,100		(0.46	)
2013	Swap	MMBtu		176,700		(0.46	)

The combined fair value of derivatives included in our consolidated balance sheet as of June 30, 2012 and December 31, 2011 is summarized below. We conduct derivative activities with only one financial institution, who is the agent of our credit facility. This may result in a concentration of credit risk. Our derivative assets and liabilities are presented in our consolidated balance sheets on a net basis, as our derivatives with both gain and loss positions are held by a single counterparty and are subject to a master netting arrangement. The fair value amounts in the table below are presented on a gross basis:


	June 30, 2012		December 31, 2011
	(In Thousands)
Derivatives not designated as hedging instruments:
Derivative assets:
Crude Oil—derivatives	$	5,525	$	—
Natural gas—derivatives	$	7,596	$	9,412
NGLs—derivatives	$	9,638	$	758
Derivative liabilities:
Crude Oil—derivatives	$	2,655	$	1,703
Natural gas—derivatives	$	1,374	$	714
NGLs—derivatives	$	—	$	1,290

F-83

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

The following table summarizes the effect of the Company’s derivative contracts on the accompanying consolidated statements of operations for the six months ended June 30, 2012 and 2011 (in thousands):


		June 30,
Type of Contract	Location of Gain Recognized in Income	2012		2011
Energy derivatives	Realized and unrealized gain (loss) on derivatives	$	16,165	$	(1,028	)

The following table summarizes the cash settlements and valuation gains and losses from our commodity derivative contracts for the six months ended June 30, 2012 and 2011 (in thousands):


	June 30,
Oil and Natural Gas Derivatives	2012		2011
Realized gain	$	3,898	$	1,231
Unrealized gain		12,267		(2,259	)

Realized and unrealized gains on derivatives		16,165		(1,028	)

6. Debt

The Company’s long-term debt as of June 30, 2012 and December 31, 2011 is as follows:


	June 30, 2012		December 31, 2011
	(In Thousands)
Senior Facility	$	118,000	$	79,000
Second Facility		35,000		35,000

	$	153,000	$	114,000

As of June 30, 2012, the Company’s credit facility consisted of a $250 million senior revolving credit facility (the Senior Facility) with a borrowing base of $145 million, which was most recently re-determined in April 2012. The Senior Facility has a maturity date of August 2014. Borrowings under the Senior Facility are secured by substantially all of the Company’s oil and natural gas properties.

Borrowings under the Senior Facility incur interest at a LIBOR-based rate plus a margin which increases based on increases in the amount of the Borrowing Base (ranging from 2 to 3 percent) which is due and payable monthly. At June 30, 2012 and December 31, 2011, the weighted-average interest rate was 4.5% and 4.8%, respectively. A commitment fee is assessed at a rate of 0.5%, dependent on the unused portion of the Credit Facility.

The borrowing base is subject to semiannual redeterminations in March and September and up to one additional time per six month period following each scheduled borrowing base redetermination, as may be requested by the Company.

Our Senior Facility requires the Company to maintain certain specific financial ratios. The ratio of consolidated EBITDAX (a non-GAAP measure generally defined as earnings before interest, taxes, depreciation, depletion, amortization, exploration expenses, and non-cash items which affect net income) to total interest expense may not be less than 2.75 to 1.00, the ratio of consolidated funded senior indebtedness to EBITDAX may not be greater than 4.00 to 1.00, the consolidated current ratio may not be less than 1.00 to 1.00, and the

F-84

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

ratio of consolidated funded total indebtedness to EBITDAX may not be greater than 4.50 to 1.00. Further, the ratio of total proved reserves (discounted at 9%) to total consolidated funded indebtedness must be greater than 1.50 to 1.00.

As of June 30, 2012, we were in compliance with all financial covenants. If an event of default occurs and is continuing, the Lenders may declare all amounts due under the Senior Facility to be immediately due and payable.

Additionally, we have a second lien credit agreement totaling $50 million (the “Second Facility”). The Second Facility includes cross-default provisions with the Credit Facility. Prepayment of principal of borrowings under the Second Facility is not permitted without the consent of the Credit Facility lenders. The Second Facility has a maturity date of February 2015. Borrowings under the Second Facility are secured by the Company’s oil and gas properties and incur interest at a LIBOR-based rate plus a margin of 9 percent. The annual weighted-average interest rate on borrowings outstanding under this facility at June 30, 2012 and December 31, 2011 was 10.9% and 10.1%, respectively.

The Company believes the carrying amounts of our Senior Facility and Second Facility approximate their fair value due to the variable nature of the applicable interest rates.

7. Related Party Transactions

The Company paid for goods and services in the amount of $634 thousand and $572 thousand for the six months ended June 30, 2012 and 2011, respectively, from certain well servicing companies in which our CEO, Mr. Steve Antry directly and indirectly holds a controlling interest.

8. Commitments and Contingencies

The Company is a defendant in an action brought by two working interest owners with respect to a 156 acre mineral interest located in Lincoln county, Oklahoma. The plaintiffs allege that their interests were not properly pooled prior to the expiration of the lease. The matter is currently set for a full hearing before the OCC in October of 2012. The Company intends to vigorously defend against the plaintiff’s claims and has asserted an indemnity on this issue against Special Energy Corporation arising from the purchase and sale agreement related to the Company’s purchase of these assets.

9. Subsequent Events

We evaluated subsequent events through September 5, 2012, which is the day the financial statements were issued.

F-85

Eagle Energy Company of Oklahoma, LLC

Notes to Consolidated Financial Statements

Asset Sale

Consummation of the sale is subject to various conditions, including, among others, (1) the accuracy of representations and warranties of the parties as of the closing date, including the absence of any material adverse effect with respect to each of the Company’s business and Midstates’s business, (2) the release of certain liens in connection with the repayment of our indebtedness, (3) the execution of certain ancillary documents and (4) other customary closing conditions. The sale will be effective June 1, 2012 and closing is expected to occur on or about October 1, 2012. The Agreement may be terminated under customary circumstances.

Amounts outstanding under our credit facilities will be retired with the proceeds received at closing. In the normal course of operations, we have advanced an additional $19 million on our Senior Facility and $15 million on our Second Facility subsequent to June 30, 2012.

F-86

ANNEX A

ASSET PURCHASE AGREEMENT

BY AND BETWEEN

EAGLE ENERGY PRODUCTION, LLC

and

MIDSTATES PETROLEUM COMPANY, LLC

DATED AUGUST 11, 2012

TABLE OF CONTENTS


ARTICLE I DEFINITIONS		7

Section 1.1	Definitions	7

ARTICLE II PURCHASE AND SALE; PURCHASE PRICE		24

Section 2.1	Purchase and Sale	24
Section 2.2	Purchase Price; Allocation of Purchase Price	26
Section 2.3	Closing Settlement Statement	27
Section 2.4	Closing Payments	27
Section 2.5	Post-Closing Adjustments	28
Section 2.6	Revenues and Expenses	29
Section 2.7	Parent Guaranty	29

ARTICLE III SELLER’S REPRESENTATIONS AND WARRANTIES		29

Section 3.1	Organization and Good Standing	29
Section 3.2	Authority; Authorization of Agreement	29
Section 3.3	Consents; No Violations	30
Section 3.4	Legal Proceedings	30
Section 3.5	Bankruptcy	30
Section 3.6	Foreign Person	30
Section 3.7	Material Contracts	30
Section 3.8	No Violation of Laws	32
Section 3.9	Preferential Rights	32
Section 3.10	Royalties, Etc	32
Section 3.11	Environmental	32
Section 3.12	Imbalances	32
Section 3.13	Drilling Obligations	32
Section 3.14	Current Commitments	32
Section 3.15	Brokers	32
Section 3.16	Plugging and Abandonment Obligations	33
Section 3.17	Disclosure Not Prohibited	33
Section 3.18	No Prepayments	33
Section 3.19	Taxes	33
Section 3.20	Tax Partnerships	33
Section 3.21	Equipment and SWD Wells	33
Section 3.22	Operation of the Assets	34
Section 3.23	Non-Consent Operations	34
Section 3.24	Compliance with Permits	34
Section 3.25	Lease Status; Rentals	34
Section 3.26	Seller’s Receipt of Payments for Production	34
Section 3.27	Payout Status	34
Section 3.28	Suspense Funds	34
Section 3.29	Certain Actions	34
Section 3.30	No Seller Material Adverse Effect	34
Section 3.31	Investment Representations	34
Section 3.32	Employee Matters.	35

ARTICLE IV BUYER’S REPRESENTATIONS AND WARRANTIES		36

Section 4.1	Organization and Good Standing	36
Section 4.2	Capitalization	36

A-i


Section 4.3	Authority; Authorization of Agreement	36
Section 4.4	Consents; No Violations	36
Section 4.5	Registration Rights	37
Section 4.6	SEC Documents	37
Section 4.7	Claims, Disputes and Litigation	37
Section 4.8	Bankruptcy	38
Section 4.9	Independent Evaluation	38
Section 4.10	Financing	38
Section 4.11	Representations by Parent as to the Preferred Shares and Common Shares	38
Section 4.12	Brokers	39
Section 4.13	No Buyer Material Adverse Effect	39

ARTICLE V COVENANTS		39

Section 5.1	Conduct of Business	39
Section 5.2	Access; Disclaimers; Record Retention	41
Section 5.3	Return or Destruction of Information	42
Section 5.4	Notification of Breaches	42
Section 5.5	Disclosure Schedules	43
Section 5.6	Tax Matters	43
Section 5.7	Governmental Bonds and Third Party Deposits	44
Section 5.8	Financing	44
Section 5.9	Schedule 14C	47
Section 5.10	No Solicitation	47
Section 5.11	Employment Offers	47
Section 5.12	Parent Interim Covenants	48
Section 5.13	Maintenance of Common Shares Reserved for Issuance	49
Section 5.14	Hedges	49
Section 5.15	HSR Act	49

ARTICLE VI CONDITIONS PRECEDENT TO CLOSING		49

Section 6.1	Conditions Precedent to Seller’s Obligation to Close	49
Section 6.2	Conditions Precedent to Buyer’s Obligation to Close	50

ARTICLE VII CLOSING		51

Section 7.1	Closing	51
Section 7.2	Closing Obligations	51
Section 7.3	Records	53

ARTICLE VIII TITLE MATTERS		53

Section 8.1	General Disclaimer of Title Warranties and Representations	53
Section 8.2	Notice of Title Defects; Defect Adjustments	53
Section 8.3	Consents to Assign; Preferential Purchase Rights	59

ARTICLE IX ENVIRONMENTAL MATTERS		60

Section 9.1	General Disclaimer of Environmental Warranties and Representations	60
Section 9.2	Notice of Environmental Defects; Defect Adjustments	60

ARTICLE X ASSUMPTION; INDEMNIFICATION		65

Section 10.1	Assumption by Buyer; Retained Obligations	65
Section 10.2	Indemnification Obligations of Seller	66
Section 10.3	Indemnification Obligations of Buyer	67
Section 10.4	Indemnification Procedure	67

A-ii


Section 10.5	Claims Period	68
Section 10.6	Limits of Liability	69
Section 10.7	Sole and Exclusive Remedy; Recourse Against Escrowed Funds	69
Section 10.8	Compliance with Express Negligence Rule	70
Section 10.9	Insurance Proceeds	71
Section 10.10	Tax Benefits	71
Section 10.11	Adjustment to Purchase Price	71
Section 10.12	Disclaimer	71

ARTICLE XI TERMINATION; SPECIFIC PERFORMANCE		72

Section 11.1	Grounds for Termination	72
Section 11.2	Effect of Termination	73
Section 11.3	Specific Performance	73
Section 11.4	Confidentiality	73

ARTICLE XII MISCELLANEOUS PROVISIONS		74

Section 12.1	Notices	74
Section 12.2	Schedules and Exhibits	75
Section 12.3	Assignment; Successors in Interest	75
Section 12.4	Number; Gender	75
Section 12.5	Captions	75
Section 12.6	Controlling Law	75
Section 12.7	Consent to Jurisdiction, Etc.; Waiver of Jury Trial	75
Section 12.8	Severability	76
Section 12.9	Counterparts	76
Section 12.10	No Third-Party Beneficiaries	76
Section 12.11	Amendment; Waiver	76
Section 12.12	Entire Agreement	76
Section 12.13	Cooperation Following the Closing	76
Section 12.14	Transaction Costs	77
Section 12.15	Construction	77
Section 12.16	Section 1031 Like-Kind Exchange	77
Section 12.17	Non-Recourse	78
Section 12.18	Excluded Losses	78
Section 12.19	Publicity	78
Section 12.20	Time of Essence	78
Section 12.21	Name Change	79

A-iii

EXHIBITS


Exhibit A
Part A		Undeveloped Leases and Allocated Values; Producing Leases
Part B		Wells and Allocated Values
Part C		Future Well Locations and Allocated Values
Exhibit B		Excluded Assets
Exhibit C		Form of Escrow Agreement
Exhibit D		Form of Parent Guaranty
Exhibit E		Form of Assignment and Assumption Agreement
Exhibit F		Form of Access Agreement
Exhibit G		SWD Wells
Exhibit H		Terms of Registration Rights Agreement
Exhibit I		Form of Transition Services Agreement
Exhibit J		Form of Certificate of Designations

		DISCLOSURE SCHEDULES

Schedule 1.1(a)		Seller’s Knowledge Persons
Schedule 1.1(b)		Buyer’s Knowledge Persons
Schedule 1.1(c)		Scheduled Permitted Encumbrances
Schedule 1.1(d)		Defensible Title
Schedule 2.1(m)		Hedges
Schedule 2.3		Form of Settlement Statement
Schedule 3.1		Seller Foreign Qualifications
Schedule 3.3		Consents; No Violations
Schedule 3.4		Legal Proceedings
Schedule 3.7		Material Contracts
Schedule 3.8		No Violation of Laws
Schedule 3.9		Preferential Rights
Schedule 3.10		Royalties, Etc.
Schedule 3.11		Environmental
Schedule 3.12		Imbalances
Schedule 3.13		Drilling Obligations
Schedule 3.14		Current Commitments
Schedule 3.16		Plugging and Abandonment Obligations
Schedule 3.17		Disclosure Not Prohibited
Schedule 3.18		No Prepayments
Schedule 3.19		Taxes
Schedule 3.20		Tax Partnerships
Schedule 3.21		Equipment and SWD Wells
Schedule 3.22		Operation of the Assets
Schedule 3.23		Non-Consent Operations
Schedule 3.24		Compliance with Permits
Schedule 3.25		Lease Status; Rentals
Schedule 3.26		Seller’s Receipt of Payments for Production
Schedule 3.27		Payout Status
Schedule 3.28		Suspense Funds
Schedule 3.29		Certain Actions
Schedule 3.30		No Seller Material Adverse Effect
Schedule 4.1		Buyer Foreign Qualifications
Schedule 4.5		Registration Rights

A-iv


Schedule 4.13		No Buyer Material Adverse Effect
Schedule 5.1		Conduct of Business
Schedule 5.1(f)		Employment Contracts
Schedule 5.1(l)		Capital Expenditure Budget
Schedule 5.7		Governmental Bonds and Third Party Deposits
Schedule 5.11		Employment Offers

A-v

ASSET PURCHASE AGREEMENT

THIS ASSET PURCHASE AGREEMENT (this “Agreement”) is dated the 11th day of August, 2012, by and between Eagle Energy Production, LLC, a Delaware limited liability company (“Seller”), and Midstates Petroleum Company, LLC, a Delaware limited liability company (“Buyer”). Seller and Buyer are sometimes hereinafter referred to individually as a “Party” and collectively as the “Parties.” This Agreement is joined by Midstates Petroleum Company, Inc., a Delaware corporation (“Parent”), for the limited purposes set forth on the signature page hereto.

WHEREAS, Seller desires to sell, and Buyer desires to purchase, all of the Assets, as hereinafter defined; and

WHEREAS, the Parties have reached agreement regarding the sale and purchase of the Assets.

NOW, THEREFORE, based on the mutual covenants and agreements herein contained, the Parties agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions. In this Agreement, capitalized terms have the meanings provided in this Section 1.1, unless defined elsewhere in this Agreement. All references to Sections refer to Sections in this Agreement and all references to Exhibits or Schedules refer to Exhibits or Schedules attached to and made a part of this Agreement.

“2012 Seller Audited Financial Statements” has the meaning set forth in Section 5.8(b)(ii).

“AAA” means the American Arbitration Association.

“Access Agreement” means an access agreement in the form attached hereto as Exhibit F.

“Acquisition Proposal” has the meaning set forth in Section 5.10.

“Action” means any action, cause of action, notice of violation, audit, complaint, demand, suit, arbitration, mediation, claim, proceeding or investigation.

“Adjusted Cash Purchase Price” has the meaning set forth in Section 2.2(c).

“AFEs” has the meaning set forth in Section 3.14.

“Affiliate” means, with respect to any Person, another Person that, directly or indirectly, through one or more intermediaries, controls or is controlled by, or is under common control with, such first Person. The term “control” and its derivatives with respect to any Person means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities or other voting interests, by contract or otherwise.

“Agreement” has the meaning set forth in the introductory paragraph.

“Allocated Value” means, with respect to any Future Well, Undeveloped Lease or Well, as applicable, the amount set forth on Exhibit A under the column titled “Allocated Values” for such Future Well, Undeveloped Lease or Well.

“Alternative Financing Commitment” has the meaning set forth in Section 5.8(a).

“Antitrust Laws” has the meaning set forth in Section 5.15.

“Article IX Environmental Liabilities” has the meaning set forth in Section 9.1.

“Assets” has the meaning set forth in Section 2.1.

“Assignment” means the Assignment and Assumption Agreement from Seller to Buyer pertaining to the Assets, substantially in the form attached to this Agreement as Exhibit E.

“Assumed Obligations” has the meaning set forth in Section 10.1(a).

“Business Day” means any day except Saturday, Sunday or any day on which federally chartered banks in the United States are required to be closed.

“Buyer” has the meaning set forth in the introductory paragraph.

“Buyer Basket” has the meaning set forth in Section 10.6.

“Buyer De Minimis Liabilities” has the meaning set forth in Section 10.6.

“Buyer Indemnified Parties” has the meaning set forth in Section 10.2(a).

“Buyer Losses” has the meaning set forth in Section 10.2(e).

“Buyer Material Adverse Effect” means any change, inaccuracy, effect, event, result, occurrence, condition or fact (for the purposes of this definition, each, an “event”) (whether foreseeable or not, whether in the ordinary course of business or not, and whether covered by insurance or not) that has had or would reasonably be expected to have, individually or in the aggregate with any other event or events, a material adverse effect on (a) Parent’s or Buyer’s ability to consummate the transactions contemplated by, or to perform its obligations under, this Agreement and the Operative Documents to which it is or will be, as applicable, a party or (b) the value of Parent and its subsidiaries, taken as a whole, and/or any of Parent’s and its subsidiaries’ (including Buyer’s) assets and properties, taken as a whole; provided, however, that, for purposes of clause (b) hereof, a Buyer Material Adverse Effect shall not include such material adverse effects resulting from (i) general changes in Hydrocarbon prices, (ii) general changes in industry, economic, financial or political conditions or markets, (iii) changes in conditions or developments generally applicable to the oil and gas industry in any area or areas where the assets and properties of Parent (or any of its subsidiaries, including Buyer) are located, (iv) acts of God, including storms, tornados and other natural disasters, (v) civil unrest or similar disorder, terrorist acts, any outbreak of hostilities of war and (vi) changes or proposed changes in Law after the Effective Time; provided further, however, that any event referred to in clauses (ii), (iii), (iv), (v) or (vi) shall be taken into account in determining whether a Buyer Material Adverse Effect has occurred or could reasonably be expected to occur to the extent that such event has a disproportionate effect on the Parent’s and its subsidiaries’ assets and properties compared to other participants in the industry in which Parent operates.

“Buyer’s Representatives” has the meaning set forth in Section 5.2(a).

“Buyer Subject Parties” has the meaning set forth in Section 8.2(h)(ii).

“Cash Purchase Price” means $325,000,000.

“Certificate of Designations” means the Certificate of Designations of Series A Convertible Preferred Stock, substantially in the form attached hereto as Exhibit J.

A-2

“Claims” means any and all assertions, charges, demands, liabilities, obligations, promises, agreements, controversies, challenges, damages, remedies, Actions, rights, costs, losses, debts, and expenses (including attorneys’ fees and costs) and interest of any kind whatsoever, known or unknown, whether in law or equity and whether arising under federal, state, local or non-U.S. law.

“Claims Period” has the meaning set forth in Section 10.5(a).

“Closing” has the meaning set forth in Section 7.1.

“Closing Date” has the meaning set forth in Section 7.1.

“Closing Environmental Defect Adjustment Amount” means, after giving effect to the limitations set forth in Section 9.2(c), the aggregate amount of all Remediation Amounts that have been agreed to in writing by the Parties prior to the Closing Date or determined prior to the Closing Date in accordance with Section 9.2(d) and with respect to which Seller has elected the remedy described in Section 9.2(b)(i).

“Closing Failure” means (a) in the case of Buyer, Buyer’s inability or failure for any reason to make the Closing Payment or deliver the Registration Rights Agreement, if all conditions precedent to Buyer’s obligation to make such payment under Section 6.2 are satisfied or waived in accordance with the terms of this Agreement (other than those conditions precedent which by their terms can only be satisfied simultaneously with the Closing but which are capable of being satisfied at the Closing) and (b) in the case of Seller, Seller’s inability or failure for any reason to deliver the Assignments or the TSA in accordance with Section 7.2(b)(i) or 7.2(b)(vi).

“Closing Payment” means the delivery at Closing of the Adjusted Cash Purchase Price and the Preferred Shares Purchase Price.

“Closing Settlement Statement” has the meaning set forth in Section 2.3.

“Closing Title Benefit Adjustment Amount” means, after giving effect to the limitations set forth in Section 8.2(h)(ii), the aggregate amount of all Title Benefit Amounts that have been agreed to in writing by the Parties prior to the Closing Date or determined prior to the Closing Date in accordance with Section 8.2(i).

“Closing Title Defect Adjustment Amount” means, after giving effect to the limitations set forth in Section 8.2(h)(i), the aggregate amount of all Title Defect Amounts that have been agreed to in writing by the Parties prior to the Closing Date or determined prior to the Closing Date in accordance with Section 8.2(i) and with respect to which Seller has elected the remedy described in Section 8.2(d)(i) or 8.2(d)(iii).

“Code” means the Internal Revenue Code of 1986, as amended.

“Commitment Letter” has the meaning set forth in Section 4.10.

“Common Shares” means the shares of common stock, par value $0.01, of Parent, issuable upon conversion of the Preferred Shares.

“Confidentiality Agreements” has the meaning set forth in Section 5.2(f).

“Consent” has the meaning set forth in Section 3.3.

“Consideration Difference” has the meaning set forth in Section 2.5(d).

“Contract” shall mean any written or oral contract or agreement, including any indenture, debenture, note, bond, loan agreement, collective bargaining agreement, lease, mortgage, franchise agreement, license agreement, purchase order, letter of credit, farmin or farmout agreement, participation, exploration or development

A-3

agreement, crude oil, condensate or natural gas purchase and sale agreement, gathering, transportation, processing or marketing agreement, operating agreement, balancing agreement, unitization agreement, facilities and/or equipment lease, production handling agreement, joint venture agreement, area of mutual interest agreement, salt water disposal lease, disposal agreement or injection agreement, and other similar contracts.

“Cure Period” has the meaning set forth in Section 8.2(c).

“Customary Post-Closing Consents” means any consents and approvals from Governmental Authorities for the assignment of the Assets by Seller to Buyer that are customarily obtained after closing in connection with a transaction similar to the one contemplated by this Agreement.

“Defensible Title” means such title of Seller to the Future Wells, Undeveloped Leases and Wells that, as of the Effective Time and as of the Closing Date, subject to Permitted Encumbrances (other than with respect to item (d) below, which shall not be subject to Permitted Encumbrances):

(a) entitles Seller, with respect to each Well or Future Well, as applicable, shown on Exhibit A, to receive not less than the percentage set forth on Exhibit A as the Net Revenue Interest of all Hydrocarbons produced, saved and marketed from such Well or Future Well, as applicable, without decrease throughout the life of such Well or Future Well, as applicable, except (i) decreases in connection with those operations in which Seller may elect after the date hereof to be a nonconsenting party (to the extent such election is permitted under Section 5.1), (ii) decreases resulting from reversion of interest to co-owners with respect to operations in which such co-owners elect, after the date hereof, not to consent, (iii) decreases resulting from the establishment or amendment, after the date hereof, of pools or units, (iv) decreases required to allow other working interest owners to make up past underproduction or pipelines to make up past under deliveries or (v) as otherwise expressly stated on Exhibit A;

(b) obligates Seller to bear, with respect to each Well or Future Well, as applicable, shown on Exhibit A, a percentage of the costs and expenses relating to the drilling, maintenance, development and operation of such Well or Future Well, as applicable, that is not greater than the Working Interest set forth on Exhibit A for such Well or Future Well, as applicable, without increase throughout the life of such Well or Future Well, as applicable, except increases in Working Interest to the extent that they (i) are accompanied by at least a proportionate increase in the Net Revenue Interest of Seller with respect to such Well or Future Well, as applicable, (ii) result from contribution requirements with respect to defaulting co-owners under applicable operating agreements or Law, (iii) result from co-owners electing under applicable operating agreements or forced pooling orders not to participate in an operation relating to such Well or Future Well, as applicable or (vi) are otherwise expressly stated on Exhibit A;

(c) entitles Seller, with respect to each Undeveloped Lease shown on Exhibit A, to not less than the Net Acres set forth on Exhibit A with respect to such Undeveloped Lease;

(d) except as set forth on Schedule 1.1(c), with respect to each Undeveloped Lease, is free and clear of royalties, non-participating royalties, overriding royalties, reversionary interests, and other burdens upon, measured by, or payable out of production created by, through or under Seller, but not otherwise; and

(e) is free and clear of all Encumbrances.

“Eagle Credit Document Releases” has the meaning given such term in Section 6.1(d).

“Eagle Credit Documents” means, collectively, the Eagle First Lien Credit Documents and the Eagle Second Lien Credit Documents.

“Eagle First Lien Administrative Agent” means Société Générale, in its capacity as administrative agent under the Eagle First Lien Credit Agreement, or any of its successors in such capacity.

A-4

“Eagle First Lien Credit Agreement” means the Amended and Restated Credit Agreement (as amended, restated or otherwise modified from time to time), dated as of August 26, 2011, among Eagle Energy Company of Oklahoma, LLC, Seller, as borrower, certain financial institutions party thereto, as lenders, the Eagle First Lien Administrative Agent, Société Générale, as letter of credit issuer, and SG Americas Securities, LLC, as bookrunner and sole lead arranger.

“Eagle First Lien Credit Documents” means, collectively, as the same may be amended, restated or otherwise modified from time to time, (i) the Eagle First Lien Credit Agreement and (ii) all notes, security documents, mortgages, intercreditor agreements, guaranties and other Loan Documents (as such term is defined in the Eagle First Lien Credit Agreement) entered into by Seller and its subsidiaries in connection with the Eagle First Lien Credit Agreement

“Eagle First Lien Payoff Amount” means, as of the Closing Date, the aggregate amount of principal, interest, fees, premiums, reimbursable expenses, reimbursement obligations, cash collateralization requirements and other amounts (including all Obligations (as such term is defined in the Eagle First Lien Credit Agreement)) that are required to be paid on such date in order for (i) the Eagle First Lien Credit Documents to be terminated in accordance with their terms and (ii) all Encumbrances granted pursuant to the Eagle First Lien Credit Documents to be fully and finally released.

“Eagle Second Lien Administrative Agent” means Citibank, N.A., in its capacity as administrative agent under the Eagle Second Lien Credit Agreement, or any of its successors in such capacity.

“Eagle Second Lien Credit Agreement” means the Second Lien Credit Agreement (as amended, restated or otherwise modified from time to time), dated as of August 26, 2011, among Eagle Energy Company of Oklahoma, LLC, Seller, as borrower, certain financial institutions party thereto, as lenders, the Eagle Second Lien Administrative Agent and Citigroup Global Markets Inc. and SG Americas Securities, LLC, as joint bookrunners and co-lead arrangers.

“Eagle Second Lien Credit Documents” means, collectively, as the same may be amended, restated or otherwise modified from time to time, (i) the Eagle Second Lien Credit Agreement and (ii) all notes, security documents, mortgages, intercreditor agreements, guaranties and other Loan Documents (as such term is defined in the Eagle Second Lien Credit Agreement) entered into by Seller and its subsidiaries in connection with the Eagle Second Lien Credit Agreement.

“Eagle Second Lien Payoff Amount” means, as of the Closing Date, the aggregate amount of principal, interest, fees, premiums, reimbursable expenses, reimbursement obligations, cash collateralization requirements and other amounts (including all Obligations (as such term is defined in the Eagle Second Lien Credit Agreement)) that are required to be paid on such date in order for (i) the Eagle Second Lien Credit Documents to be terminated in accordance with their terms and (ii) all Encumbrances granted pursuant to the Eagle Second Lien Credit Documents to be fully and finally released.

“Easements” has the meaning set forth in Section 2.1(g).

“Effective Time” means 12:01 a.m. Central time on June 1, 2012.

“Encumbrance” means any lien, mortgage, security interest, defect, pledge, charge or similar encumbrance.

“Environmental Arbitrator” has the meaning set forth in Section 9.2(d)(i).

“Environmental Condition” means a condition existing on the date of this Agreement with respect to the air, soil, subsurface, surface waters, ground waters and/or sediments that causes an Asset (or Seller with respect to an Asset) (a) not to be in compliance with Environmental Laws or (b) to be subject to a present (rather than future) obligation under Environmental Laws to perform remedial or corrective action.

A-5

“Environmental Defect” means an Environmental Condition with respect to an Asset that is not set forth on Schedule 3.11.

“Environmental Defect Claim Date” shall mean 5:00 p.m. (Central time) on the date that is sixty (60) calendar days after the Execution Date (inclusive).

“Environmental Defect Notice” and “Environmental Defect Notices” have the meaning set forth in Section 9.2(a).

“Environmental Dispute Escrow Amount” means a number of Preferred Shares having an aggregate initial Liquidation Preference equal to the sum of the following amounts (after taking into account Section 9.2(c)): (i) the aggregate of all Remediation Amounts in respect of Environmental Defects asserted properly and timely by Buyer in accordance with Section 9.2(a), which are to be submitted for resolution in accordance with Section 9.2(d) plus (ii) the Remediation Amount attributable to an Environmental Defect for which Seller elects to assume Remediation responsibility pursuant to Section 9.2(b)(ii) and which Remediation has not been adequately completed (as determined in accordance with Section 9.2(b)) prior to Closing.

“Environmental Laws” means the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq.; the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq.; the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air Act, 42 U.S.C. § 7401 et seq.; the Hazardous Materials Transportation Act, 49 U.S.C. § 5101 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; and all similar Laws of any Governmental Authority having jurisdiction over the Assets in question addressing pollution or protection of the environment and, to the extent enacted or promulgated before the Closing Date, all amendments to such Laws and all regulations implementing any of the foregoing. The term “Environmental Laws” does not include any changes in Laws occurring after the Effective Time.

“Environmental Matters” has the meaning set forth in Section 9.2(e)(i).

“Equipment” has the meaning set forth in Section 2.1(e).

“ERISA” has the meaning set forth in Section 3.32(b).

“Escrow Agent” means an escrow agent reasonably acceptable to Seller and Buyer and named as such in the Escrow Agreement or its successor or assign as contemplated by the Escrow Agreement.

“Escrow Agreement” means an Escrow Agreement by and among Seller, Buyer and the Escrow Agent, substantially in the form attached hereto as Exhibit C, with such changes as the Escrow Agent may reasonably request, as such agreement may be extended, amended or replaced from time to time in accordance with its terms.

“Escrow Amounts” means the General Escrow Amount, the Title Dispute Escrow Amount (if any) and the Environmental Dispute Escrow Amount (if any).

“Escrow Claims Period” means the period beginning on the Closing Date and terminating on the first (1st) anniversary of the Closing Date.

“Escrow Release Date” means 5:00 p.m. (Central Time) on the first (1st) Business Day that is one year after the Closing Date.

“Exchange Act” means the Securities Exchange Act of 1934, as amended.

A-6

“Excluded Assets” means all right, title and interest of Seller (and/or any of its Affiliates) in and to the following assets and properties (and any other assets and properties not expressly included in the definition of “Assets”): (a) all of Seller’s (and its Affiliates’) corporate minute books, financial records and other business records to the extent such books and records are related to Seller’s (or any of its Affiliates’) business generally or are otherwise not directly related to the Assets, (b) all claims for refunds, credits, loss carryforwards and similar tax assets with respect to (i) Property Taxes or any other Taxes, in each case, attributable to any period (or portion thereof) prior to the Effective Time, (ii) Income Taxes of Seller (or any of its Affiliates) or (iii) any Taxes attributable to any of the assets or properties described in this definition, (c) all personal computers and associated peripherals and all radio and telephone equipment (and licenses related thereto), (d) all of Seller’s (and its Affiliates’) computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property, (e) all documents and instruments of Seller (or any of its Affiliates) that may be protected by an attorney-client privilege (other than title opinions and reports on status of title, in each case, with respect to title to any of the Assets), (f) all documents prepared or received by Seller (or any of its Affiliates) with respect to (i) lists of prospective purchasers for the Assets, (ii) bids submitted by prospective purchasers of the Assets (other than Buyer or any of its Affiliates), (iii) analyses by Seller, its Affiliates or any of its (or their, as applicable) representatives of any bids submitted by any prospective purchaser, (iv) correspondence between or among Seller (and/or any of its Affiliates), its (and, if applicable, their respective) representatives and any prospective purchaser (other than Buyer or any of its Affiliates) and (v) correspondence between Seller (and/or any of its Affiliates) or any of its (and/or, if applicable, their respective) representatives with respect to any bids, prospective purchasers of the Assets or the transactions contemplated by this Agreement, (g) the corporate office of Seller located at 9 East 4th Street, Suite 200, Tulsa, Oklahoma (“Seller’s Corporate Office”) and all personal property and fixtures located therein, (h) all trucks, cars, drilling/workover rigs and rolling stock and all equipment, pipe and inventory not historically or currently used in connection with the ownership or operation of the Assets (whether located on or off the Assets), (i) all of the bonds, letters of credit, guarantees, deposits and other pre-payments posted by Seller (or any of its Affiliates) with any Governmental Authorities or any other Third Parties (including those set forth on Schedule 5.7), in each case, to the extent an adjustment to the Purchase Price is not made pursuant to Section 2.2(c) or 2.5 with respect thereto, (j) all production, trade credits, receivables and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time or with respect to any of the assets and properties described in this definition, (k) all accounts (including bank accounts) and all cash on hand, (l) all rights and interests (i) under any policy or agreement of insurance or indemnity agreement, (ii) under any bond, letter of credit or guarantee or (iii) to any insurance proceeds or awards, (m) any Hydrocarbon and/or other mineral lease acquired by Seller after the Execution Date and prior to Closing that is not a Post-Execution Option Lease and (n) all of the assets and properties set forth on Exhibit B.

“Excluded Losses” has the meaning set forth in Section 10.2(c).

“Exclusivity Period” means the period from and after the date hereof until the earlier to occur of the Closing and the termination of this Agreement pursuant to Article XI.

“Execution Date” means August 11, 2012.

“Field Employees” has the meaning set forth in Section 5.11(a).

“Final Settlement Statement” has the meaning set forth in Section 2.5(a).

“Financing” has the meaning set forth in Section 4.10.

“Financing Commitment” has the meaning set forth in Section 5.8(a).

“Financing Modification Requirements” has the meaning set forth in Section 5.8(a).

A-7

“Financing Sources” means the Persons that have committed to provide or otherwise entered into agreements in connection with the Financing in connection with the transactions contemplated hereby and their respective Affiliates, officers, directors, employees and representatives involved in the Financing and permitted successors and assigns. Any of the foregoing Persons is a “Financing Source.”

“Fundamental Representations” mean the representations and warranties set forth in Sections 3.1, 3.2, 3.15, 4.1, 4.2, 4.3, 4.5, 4.11 and 4.12.

“Future Location” means each location identified on Part C of Exhibit A for a future completion or for a well to be drilled in the future.

“Future Well” means an existing well with behind-pipe potential at a Future Location or a well to be drilled in the future at a Future Location.

“General Escrow Amount” means, at Closing an amount equal to twenty percent (20%) of the Preferred Shares Purchase Price.

“Governmental Authority” means any federal, state, local, municipal or other governments; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal.

“Hazardous Substances” means any: (a) chemical, product, material, substance or waste defined as or included in the definition of “hazardous substance,” “hazardous material,” “hazardous waste,” “restricted hazardous waste,” “oil and gas waste,” “solid waste,” “extremely hazardous substance,” “toxic substance,” “contaminant,” “pollutant,” or terms of similar meaning or import as defined pursuant to Environmental Laws; (b) petroleum hydrocarbons, petroleum products, petroleum substances, natural gas, crude oil, or any components, fractions, or derivatives thereof released into the environment or (c) asbestos containing materials, polychlorinated biphenyls, radioactive materials, urea formaldehyde foam insulation, NORM or radon gas.

“Hedges” has the meaning set forth in Section 2.1(m).

“HSR Act” shall mean the Hart Scott Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations thereunder.

“HSR Filing” has the meaning set forth in Section 5.15.

“Hydrocarbons” means oil, gas, condensate and any other hydrocarbons produced or processed in association therewith (whether or not such item is in liquid or gaseous form), or any combination or constituents thereof, and any minerals produced in association therewith.

“Imbalances” shall mean all Well Imbalances and Pipeline Imbalances.

“Income Taxes” shall mean all income, capital gains, franchise and similar Taxes.

“Indemnified Party” has the meaning set forth in Section 10.4(a).

“Indemnifying Party” has the meaning set forth in Section 10.4(a).

“Independent Accountants” has the meaning set forth in Section 2.5(b).

“Individual Environmental Threshold” has the meaning set forth in Section 9.2(c).

A-8

“Individual Title Benefit Threshold” has the meaning set forth in Section 8.2(h)(ii).

“Individual Title Defect Threshold” has the meaning set forth in Section 8.2(h)(i).

“Initial Seller Audited Financial Statements” has the meaning set forth in Section 5.8(b)(i).

“Interim Period” shall mean that period of time commencing with the Effective Time and ending at 7:00 a.m. (local time where the Assets are located) on the Closing Date.

“Invasive Activities” has the meaning set forth in Section 5.2(b).

“Knowledge” means (a) with respect to Seller, the actual knowledge of the individuals set forth on Schedule 1.1(a) and (b) with respect to Buyer, the actual knowledge of the individuals set forth on Schedule 1.1(b).

“Lands” has the meaning set forth in Section 2.1(a).

“Laws” means any and all applicable laws, statutes, ordinances, permits, decrees, writs, injunctions, orders, codes, judgments, principles of common law, rules or regulations that are promulgated, issued or enacted by a Governmental Authority having jurisdiction.

“Leases” has the meaning set forth in Section 2.1(a).

“Legal Dispute” has the meaning set forth in Section 12.7(a).

“Legal Proceedings” means any and all actions, proceedings, suits and causes of action by or before any Governmental Authority and all arbitration proceedings.

“Liabilities” shall mean any and all claims, causes of action, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines and other costs and expenses (including attorneys’ fees and other legal costs and expenses), including any of the foregoing arising out of or otherwise attributable to personal injury or death, property damage or environmental damage or remediation.

“Liquidation Preference” refers to the liquidation preference of the Preferred Shares as set forth in the Certificate of Designations, as may be adjusted in accordance with the terms of the Certificate of Designation. The initial Liquidation Preference of each share of Series A Convertible Preferred Stock shall equal $1,000.

“Losses” has the meaning set forth in Section 10.2(c).

“Lowest Cost Response” means the response consistent with or allowed under Environmental Laws that addresses Environmental Conditions for which Remediation is required pursuant to Environmental Laws or this Agreement at the lowest cost as compared to any other response that is consistent with or otherwise allowed under Environmental Law. Taking no action shall constitute the Lowest Response Cost if, after investigation, taking no action is determined to be consistent with or otherwise allowed under Environmental Laws. If taking no action is not consistent with or otherwise allowed under Environmental Laws, the least costly active remedy, such as (i) a risk-based closure that may or may not require institutional controls such as deed restrictions limiting the use of the Asset to its present or similar uses or prohibiting the installation of shallow groundwater wells or (ii) the installation of engineering controls or physical barriers to contain, stabilize, prevent migration of or exposure to Hazardous Substances, including caps, dikes, encapsulation, leachate collection systems, and similar barriers or controls, shall be the Lowest Cost Response. The Lowest Cost Response shall not include (a) the costs of Buyer’s or any of its Affiliate’s employees, project manager(s) or attorneys, (b) expenses for matters that are costs of doing business, including those costs that would be required to operate pollution control

A-9

equipment that is installed as part of a Remediation, e.g., those costs that would ordinarily be incurred in the day-to-day operations of the Asset, (c) overhead costs of Buyer or its Affiliates, (d) costs and expenses that would not have been required under Environmental Laws as they exist on the date of this Agreement, (e) costs or expenses incurred in connection with Remediation that is designed to achieve standards that are more stringent than those required for similar facilities or that fails to reasonably take advantage of applicable risk reduction or risk assessment principles allowed under applicable Environmental Laws and/or (f) any costs or expenses relating to any expansion, renovation or change in use of the Asset.

“Marketing Period” means the first period of 21 consecutive days after the date hereof throughout which: (i) Buyer shall have the Required Information that Seller is required to provide to Buyer pursuant to Sections 5.8(b)(i) and 5.8(c)(i); provided that if Seller shall in good faith reasonably believe it has delivered the Required Information, it may deliver to Buyer a written notice to that effect (stating when it believes it completed such delivery), in which case the Marketing Period shall be deemed to have commenced on the date Buyer receives such notice unless Buyer in good faith reasonably believes Seller has not completed delivery of the Required Information and, within four Business Days after Buyer’s receipt of such notice, delivers a written notice to Seller to that effect (stating to the extent reasonably possible which Required Information Seller has not delivered), and (ii) nothing has occurred and no condition exists that would cause any of the conditions set forth in Section 6.2 to fail to be satisfied assuming the Closing were scheduled for any time during such 21 consecutive day period; provided, that the days from and including August 18, 2012 through September 3, 2012 and from and including November 21, 2012 through November 23, 2012 shall not be included in determining the Marketing Period; provided further, that the Marketing Period shall not be deemed to have commenced if, following the commencement of, but prior to the completion of, the Marketing Period, (A) Ernst & Young LLP shall have withdrawn its audit opinion with respect to any financial statements contained in the audited financial statements of Seller; (B) the financial statements included in the Required Information that are available to Buyer on the first day of any such 21 consecutive day period would be required to be updated under Rule 3-12(g)(1)(ii) or (g)(2)(iii), as applicable, of Regulation S-X in order to be sufficiently current on any day during such 21 consecutive day period to permit a registration statement including such financial statements to be declared effective by the SEC on the last day of such period, in which case the Marketing Period shall not be deemed to commence unless and until the receipt by Buyer of updated Required Information that would be required under Rule 3-12(g)(1)(ii) or (g)(2)(iii), as applicable, of Regulation S-X to permit a registration statement using such financial statements to be declared effective by the SEC on the last day of such period; or (C) Seller issues a statement or provides notice indicating its intent to restate any material historical financial statements of Seller included in the Required Information or that any such restatement is under consideration or may be a possibility, in which case the Marketing Period shall not be deemed to commence unless and until such restatement has been completed and the relevant financial statements have been amended or Seller has announced or provided notice that it has concluded that no restatement shall be required in accordance with GAAP.

“Material Contracts” means has the meaning set forth in Section 3.7(a).

“Net Acres” means, as computed separately with respect to each Undeveloped Lease, the product of (a) the number of gross acres in the lands covered by such Undeveloped Lease, multiplied by (b) the lessor’s undivided percentage interest in oil, gas and/or other minerals in the lands covered by such Undeveloped Lease, multiplied by (c) Seller’s Working Interest in such Undeveloped Lease.

“Net Revenue Interest” means, with respect to any Well or Future Well, as applicable, the percentage or fractional interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Well after giving effect to all royalties, overriding royalties, production payments, carried interests, net profits interests, reversionary interests and other burdens upon, measured by, or payable out of production therefrom.

“NORM” means naturally occurring radioactive material.

“Operating Expenses” shall mean all operating expenses and capital expenditures to the extent incurred in the ownership and/or operation of the Assets, including all costs of insurance, Taxes (but excluding Property

A-10

Taxes and Income Taxes), all overhead and general and administrative costs and expenses (but excluding general corporate legal or accounting expenses), all costs and expenses (including salary and benefits costs and expenses) associated with the employees of Eagle Energy Company of Oklahoma, LLC or its subsidiaries (but not including bonuses payable as a result of the transaction contemplated by this Agreement) and all costs and expenses associated with Seller’s Corporate Office. For the avoidance of doubt, Operating Expenses shall not include any fees or expenses payable to Riverstone or its Affiliates (other than Eagle Energy Company of Oklahoma, LLC and its subsidiaries).

“Operative Documents” means the Escrow Agreement, the TSA (if any), the Certificate of Designations, the Registration Rights Agreement, the Parent Guaranty, the Access Agreement (if any), the Assignment and all other documents and instruments entered into by one or both of the Parties or one or more of their respective Affiliates, as applicable, in connection with this Agreement.

“Outside Date” has the meaning set forth in Section 11.1(c).

“Parent” has the meaning set forth in the introductory paragraph.

“Parent Guaranty” has the meaning given such term in Section 2.7.

“Parties” has the meaning set forth in the introductory paragraph.

“Party” has the meaning set forth in the introductory paragraph.

“Pending Article X Claim Amount” has the meaning set forth in Section 10.7(e).

“Pending Article X Claims” has the meaning set forth in Section 10.7(e).

“Pending Environmental Claim Amount” has the meaning set forth in Section 9.2(e)(iv).

“Pending Environmental Claims” has the meaning set forth in Section 9.2(e)(iv).

“Pending Title Claim Amount” has the meaning set forth in Section 8.2(j)(iv).

“Pending Title Claims” has the meaning set forth in Section 8.2(j)(iv).

“Permitted Encumbrances” means:

(a) lessor’s royalties, non-participating royalties, overriding royalties, reversionary interests, and other burdens upon, measured by, or payable out of production with respect to any Well or Future Well, as applicable, if the net cumulative effect of such burdens does not (i) operate to reduce the Net Revenue Interest of Seller in such Well or Future Well, as applicable, below the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, or (ii) obligate Seller to bear a Working Interest for such Well or Future Well, as applicable, that is greater than the Working Interest set forth on Exhibit A for such Well or Future Well, as applicable (unless Seller’s Net Revenue Interest for such Well or Future Well, as applicable, is greater than the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, in the same or greater proportion as any increase in such Working Interest);

(b) liens for Taxes or assessments not yet due or delinquent;

(d) conventional rights of reassignment upon final intention to abandon or release the applicable Assets;

(e) all applicable Laws and rights reserved to or vested in any Governmental Authority (i) to control or regulate any Asset in any manner, (ii) by the terms of any right, power, grant or Permit or by any provision of Law, to terminate such right, power, grant or Permit or to purchase, condemn, expropriate, or recapture or to

A-11

designate a purchaser of any of the Assets, (iii) to use any Asset in a manner which does not materially impair the use of such Asset for the purposes for which it is currently used or operated, as applicable, by Seller or (iv) to enforce any obligations or duties affecting the Assets;

(f) rights of a common owner of any interest in rights-of-way or easements currently held by Seller and such common owner as tenants in common or through common ownership to the extent that the same does not materially impair the use or operation of the Assets as currently used or operated;

(g) easements, conditions, covenants, restrictions, servitudes, permits, rights-of-way, surface leases and other rights in or applicable or pertaining to the Assets for the purpose of surface operations, roads, alleys, highways, railways, pipelines, transmission lines, transportation lines, distribution lines, power lines, telephone lines, and removal of timber, grazing, logging operations, canals, ditches, reservoirs and other similar purposes, or for the joint or common use of real estate, rights-of-way, facilities and equipment (i) that, individually or in the aggregate, do not prevent or materially interfere with the operation or use of any of the Assets and (ii) that the net cumulative effect of does not (A) with respect to any Well or Future Well, as applicable, (1) operate to reduce the Net Revenue Interest of Seller in such Well or Future Well, as applicable, below the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, or (2) obligate Seller to bear a Working Interest for such Well or Future Well, as applicable, that is greater than the Working Interest set forth on Exhibit A for such Well or Future Well, as applicable (unless Seller’s Net Revenue Interest for such Well or Future Well, as applicable, is greater than the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, in the same or greater proportion as any increase in such Working Interest) and (B) with respect to any Undeveloped Lease, reduce the Net Acres for any Undeveloped Lease to an amount less than the Net Acres set forth on Exhibit A for such Undeveloped Lease;

(h) vendors, carriers, warehousemen’s, repairmen’s, mechanics’, workmen’s, materialmen’s or construction liens or other similar liens arising by operation of Law in the ordinary course of business in respect of obligations which are not yet due;

(i) the terms and provisions of each Lease and Material Contract if the net cumulative effect thereof do not, individually or in the aggregate, (i) prevent or materially interfere with the operation or use of any of the Assets as such Assets are being operated or used by Seller as of the date hereof, (ii) operate to reduce the Net Revenue Interest of Seller in such Well or Future Well, as applicable, below the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, (iii) obligate Seller to bear a Working Interest for such Well or Future Well, as applicable, that is greater than the Working Interest set forth on Exhibit A for such Well or Future Well, as applicable (unless Seller’s Net Revenue Interest for such Well or Future Well, as applicable, is greater than the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, in the same or greater proportion as any increase in such Working Interest) or (iv) reduce the Net Acres for any Undeveloped Lease to an amount less than the Net Acres set forth on Exhibit A for such Undeveloped Lease;

(j) all Preferential Purchase Rights set forth on Schedule 3.9 and all other Preferential Purchase Rights that do not apply to the transactions contemplated hereby;

(k) all Encumbrances created pursuant to the Oil and Gas Owners’ Lien Act of 2010, 52 Okla. Stat. 549.1-549.12 or the Kansas Uniform Commercial Code, K.S.A. 84-9-339a;

(l) any Encumbrance affecting the Assets that is discharged by Seller at or prior to Closing;

(m) (i) all matters (A) specifically set forth on Exhibit A and (B) relating to or arising out of any of the matters set forth on Schedules 3.4, 1.1(c) and 5.1 and (ii) the release or expiry of any of the Undeveloped Leases set forth on Schedule 1.1(d).

(n) any Encumbrance for purchase money mortgages or similar types of financing securing residential property or a ranch or farm affecting the lessor’s mineral interest in (i) any of the Assets set forth in item 10 on

A-12

Schedule 1.1(c) and (ii) any non-producing Lease, which have not been subordinated to such Lease, but, in the case of clause (ii), only to the extent that such unsubordinated Encumbrances (A) are liquidated in amount, (B) do not reduce the undivided interest in all Hydrocarbons produced, saved and sold from or attributable to any of the Assets and (C) do not obligate Seller to bear a greater Working Interest than that set forth on Exhibit A for any Asset; and

(o) all other Encumbrances, Contracts, instruments, obligations, defects and irregularities affecting the Assets that, individually or in the aggregate, (i) do not prevent or materially interfere with the operation or use of any of the Assets, (ii) do not reduce the Net Revenue Interest of Seller in such Well or Future Well, as applicable, below the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, (iii) do not obligate Seller to bear a Working Interest for such Well or Future Well, as applicable, that is greater than the Working Interest set forth on Exhibit A for such Well or Future Well, as applicable (unless Seller’s Net Revenue Interest for such Well or Future Well, as applicable, is greater than the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, in the same or greater proportion as any increase in such Working Interest) and (iv) do not reduce the Net Acres for any Undeveloped Lease to an amount less than the Net Acres set forth on Exhibit A for such Undeveloped Lease.

“Permits” has the meaning set forth in Section 2.1(j).

“Person” means an individual, partnership, corporation, limited liability company, trust or other entity.

“Pipeline Imbalance” shall mean any net difference between the quantity of Hydrocarbons attributable to the Assets required to be delivered by Seller under any Related Contract relating to the purchase and sale, gathering, transportation, storage, processing, marketing or treating of such Hydrocarbons and the actual quantity of Hydrocarbons attributable to the Assets delivered by Seller pursuant to the relevant Related Contract.

“Post-Execution Option Lease Amount” shall mean an amount equal to all (a) documented costs paid to lessors (or other third parties, as applicable) by (or on behalf of) Seller, including cash bonus consideration and pre-paid delay rentals and (b) broker’s fees, recording fees, title examination expenses (including abstract costs, title opinion costs and all other third party costs of due diligence), legal expenses, title curative costs, land costs, drafting and other costs and expenses incurred by Seller and payable to a third party, in each case, in the acquisition (after the Execution Date and before the Closing Date) of any Post-Execution Option Leases.

“Post-Execution Option Leases” means all Hydrocarbon and/or other mineral leases and mineral interests acquired by Seller after the Execution Date and prior to the Closing Date if (a) the acquisition of such mineral leases and/or mineral interests is done in connection with the completion of a drilling unit or in response to a pooling agreement or order and is contemplated in the capital expenditure budget set forth in Schedule 5.1(l) or (b) prior to Seller’s acquisition thereof, Buyer agreed (within five (5) Business Days of Seller’s written request with respect thereto) in writing to acquire (and pay all Post-Execution Option Lease Amounts associated with) such leases and mineral interests at Closing.

“Pre-Effective Time Operating Expenses” has the meaning set forth in Section 2.6(a).

“Pref-Right Asset” has the meaning set forth in Section 8.3(b).

“Preferential Purchase Right” has the meaning set forth in Section 8.3(a).

“Preferred Shares” means shares of the Series A Convertible Preferred Stock.

“Preferred Shares Purchase Price” means 325,000 shares of Series A Convertible Preferred Stock with an initial Liquidation Preference equal to one thousand dollars ($1,000) per share.

A-13

“Property Taxes” shall mean ad valorem, property, excise, sales, use, severance, production or similar Taxes (including any interest, fine, penalty or additions to Tax imposed by any Governmental Authority in connection with such Taxes) based upon the operation or ownership of the Assets or the production of Hydrocarbons therefrom but excluding, for the avoidance of doubt, (a) Income Taxes and (b) Transfer Taxes.

“Purchase Price” has the meaning set forth in Section 2.2(a).

“Records” has the meaning in Section 2.1(k).

“Registration Rights Agreement” shall mean the Registration Rights Agreement by and between Seller and Parent and dated as of the Closing Date, with substantially the terms set forth on Exhibit H attached to this Agreement.

“Related Contracts” shall mean those Contracts to which Seller (or an Affiliate of Seller) is a party, that relate to the Assets or the ownership or operation thereof and that will be binding on Buyer or any of the Assets after the Closing; provided that, the defined term “Related Contracts” shall not include any (a) Excluded Asset or (b) Lease or other instrument creating or assigning any real property interest.

“Remediation” means with respect to an Environmental Condition, the implementation and completion of any investigation, monitoring, remedial, removal, response, construction, closure, disposal or other corrective actions required under Environmental Laws to correct or remove such Environmental Condition, or to restore the operation to compliance with Environmental Laws, using the Lowest Cost Response.

“Remediation Amount” means with respect to an Environmental Condition, the present value (using an annual discount rate of ten percent (10%)) of the cost (net to Seller’s interest) of the Lowest Cost Response to such Environmental Condition.

“Reports” has the meaning set forth in Section 4.6(a).

“Required Information” has the meaning set forth in Section 5.8(c).

“Retained Obligations” has the meaning set forth in Section 10.1(b).

“Rules” means the Commercial Arbitration Rules of the AAA, in effect at the time the relevant arbitration is initiated.

“SEC” means the U.S. Securities and Exchange Commission.

“Section 10.2(a)(iv) Claims” has the meaning set forth in Section 10.7(b).

“Securities Act” means the Securities Act of 1933, as amended.

“Seller” has the meaning set forth in the introductory paragraph.

“Seller Financial Statements” has the meaning set forth in Section 5.8(b)(ii).

“Seller Indemnified Parties” has the meaning set forth in Section 10.3(a).

“Seller Losses” has the meaning set forth in Section 10.3(c).

“Seller Material Adverse Effect” means any change, inaccuracy, effect, event, result, occurrence, condition or fact (for the purposes of this definition, each, an “event”) (whether foreseeable or not, whether in the ordinary course of business or not, and whether covered by insurance or not) that has had or would reasonably be expected

A-14

to have, individually or in the aggregate with any other event or events, a material adverse effect on (a) Seller’s ability to consummate the transactions contemplated by, or to perform its obligations under, this Agreement and the Operative Documents to which it is or will be, as applicable, a party or (b) the value of the Assets, taken as a whole; provided, however, that, for purposes of clause (b) hereof, a Seller Material Adverse Effect shall not include such material adverse effects resulting from (i) general changes in Hydrocarbon prices, (ii) general changes in industry, economic, financial or political conditions or markets, (iii) changes in conditions or developments generally applicable to the oil and gas industry in any area or areas where the Assets are located, (iv) acts of God, including storms, tornados and other natural disasters, (v) civil unrest or similar disorder, terrorist acts, any outbreak of hostilities of war and (vi) changes or proposed changes in Law after the Effective Time; provided further, however, that any event referred to in clauses (ii), (iii), (iv), (v) or (vi) shall be taken into account in determining whether a Seller Material Adverse Effect has occurred or could reasonably be expected to occur to the extent that such event has a disproportionate effect on the Assets or Seller compared to other participants in the industry in which Seller operates.

“Seller Severance Benefits” has the meaning set forth in Section 5.11(a).

“Seller Subject Parties” has the meaning set forth in Section 12.17(a).

“Seller Unaudited Financial Statements” has the meaning set forth in Section 5.8(b)(i).

“Seller’s Corporate Office” has the meaning set forth in the definition of “Excluded Assets”.

“Series A Convertible Preferred Stock” means Parent’s Series A Mandatorily Convertible Preferred Stock having the rights, preferences and privileges set forth in the Certificate of Designations.

“Subject Consent Asset” has the meaning set forth in Section 8.3(d).

“SWD Wells” has the meaning set forth in Section 2.1(f).

“Tax” and “Taxes” means (a) all taxes, assessments, fees, and other charges of any kind whatsoever imposed by any Governmental Authority, including any federal, state, local and/or foreign income tax, surtax, remittance tax, presumptive tax, net worth tax, special contribution tax, production tax, value added tax, withholding tax, gross receipts tax, windfall profits tax, profits tax, ad valorem tax, personal property tax, real property tax, sales tax, goods and services tax, service tax, transfer tax, use tax, excise tax, premium tax, stamp tax, motor vehicle tax, entertainment tax, insurance tax, capital stock tax, franchise tax, occupation tax, payroll tax, employment tax, unemployment tax, disability tax, alternative or add-on minimum tax and estimated tax, (b) any interest, fine, penalty or additions to tax imposed by a Governmental Authority in connection with any item described in clause (a), and (c) any liability for the payment of any amounts described in clauses (a) and (b) as a result of being a member of an affiliated, consolidated, combined or unitary group, or being a party to any agreement or arrangement whereby liability for payment of such amounts was determined or taken into account with reference to the liability of any other Person, or as a transferee or successor or otherwise.

“Tax Allocation” has the meaning set forth in Section 2.2(b).

“Tax Returns” means any report, return, election, document, estimated tax filing, declaration, claim for refund, information returns, or other filing provided to any Governmental Authority with respect to Taxes, including any schedules or attachments thereto and any amendment thereof.

“Terminating Party” has the meaning set forth in Section 11.1(b).

“Title IV Liability” has the meaning set forth in Section 3.32(b).

“Title Arbitrator” has the meaning set forth in Section 8.2(i).

A-15

“Title Benefit” means, with respect to any Well or Future Well, as applicable, any right, circumstance or condition that operates to (a)(i) increase the Net Revenue Interest of Seller in such Well or Future Well, as applicable, to an amount above the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, to the extent that such right, circumstance or condition does not cause a proportionately greater increase in Seller’s Working Interest in such Well or Future Well, as applicable, above the Working Interest set forth on Exhibit A for such Well or Future Well, as applicable (based on the ratio of the Working Interest to the Net Revenue Interest for such Well or Future Well, as applicable, as set forth on Exhibit A) or (ii) obligate Seller to bear a Working Interest in such Well or Future Well, as applicable, that is less than the Working Interest set forth on Exhibit A for such Well or Future Well, as applicable, to the extent that such right, circumstance or condition does not cause any decrease in Seller’s Net Revenue Interest for such Well or Future Well, as applicable, below the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, or (b) increase the Net Acres of Seller in such Undeveloped Lease to an amount greater than that set forth on Exhibit A with respect to such Undeveloped Lease.

“Title Benefit Amount” means the amount of a Title Benefit as determined pursuant to Section 8.2(g) or 8.2(i).

“Title Benefit Notice” has the meaning set forth in Section 8.2(b).

“Title Benefit Property” has the meaning set forth in Section 8.2(b).

“Title Defect” means any Encumbrance, defect or other matter that causes Seller not to have Defensible Title in and to any Well, Future Well or Undeveloped Lease; provided that the following shall not be considered Title Defects:

(p) defects in the chain of title or in the relevant Asset itself consisting of the failure to recite marital status in a document or omissions of successions of heirship, succession or probate or estate proceedings, unless Buyer provides affirmative evidence that such failure or omission results in another Person’s superior valid claim of title to the relevant Asset;

(q) (i) in respect of a Well, defects that pertain to any formation or common source of supply other than any formation set forth on Exhibit A as being owned by Seller with respect to such Well and (ii) in respect of any Undeveloped Lease, defects that pertain to any formation or common source of supply other than any formation set forth on Exhibit A as being owned by Seller with respect to such Undeveloped Lease;

(r) defects arising out of lack of corporate or other entity authorization unless Buyer provides affirmative evidence that the action was not authorized and results in another Person’s superior valid claim of title to the relevant Asset;

(s) defects based on a gap in Seller’s chain of title in the applicable county records, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain or runsheet, which documents shall be included in any Title Defect Notice submitted with respect thereto;

(t) defects arising from any change in Law after the Effective Time;

(u) defects that have been cured by the Marketable Record Title Act (Okla. Stat. tit. 16, § 71 et seq.), the Simplification of Land Titles Act (Okla. Stat. tit. 16, § 61 et seq.), the Marketable Record Title Act (K.S.A. 58-3401-K.S.A. 58-3412) or other title curative statute or by Laws of limitations or prescription, including adverse possession and the doctrine of laches as reasonably demonstrated by Seller;

(v) defects arising from prior oil and gas leases relating to lands covered by any Leases that are not released of record and that have expired, as such expiration is reasonably demonstrated by Seller or would otherwise be waived by a reasonable and prudent operator of oil and gas properties in the area where the affected Lease applies;

A-16

(w) defects arising from a Well, Future Well or Undeveloped Lease being subject to landowner consents for surface use on such Well, Future Well or Undeveloped Lease to the extent the same does not materially impair Seller’s use or ownership of the same;

(x) defects that affect only which Person has the right to receive royalty payments and that does not affect the validity of the relevant underlying Asset;

(y) defects arising from (or with respect to) any maintenance of uniform interest provision under any joint operating agreement that does not apply to the transactions contemplated by this Agreement or, in connection with the transactions contemplated by this Agreement, has been waived by the applicable counterparty affected by such provision;

(z) defects based solely on (i) lack of information in Seller’s files, the lack of third-party records or the unavailability of information from Governmental Authorities, (ii) references to a document(s) if such document(s) is not in Seller’s files or (iii) tax assessment, tax payment or similar records (or the absence of such activities or records);

(aa) defects arising solely from any Undeveloped Lease set forth on Part 1 of Schedule 1.1(d) being released prior to the Closing Date or from any Undeveloped Lease set forth on Part 2 of Schedule 1.1(d) expiring prior to the Closing Date; and

(bb) such other defects or irregularities in the title to the Assets that (i) do not materially interfere with the operation, value or use of the Assets (or portion thereof) affected thereby (as currently used or owned) or (ii) would be accepted by a reasonably prudent purchaser engage in the business of owning and operating oil and gas properties in the region where the Assets are located.

“Title Defect Amount” means the amount of a Title Defect as determined pursuant to Section 8.2(f) or 8.2(i).

“Title Defect Claim Date” shall mean 5:00 p.m. (Central time) on the date that is sixty (60) calendar days after the Execution Date (inclusive).

“Title Defect Notices” and “Title Defect Notice” have the meaning set forth in Section 8.2(a).

“Title Defect Property” has the meaning set forth in Section 8.2(a).

“Title Dispute Escrow Amount” means a number of Preferred Shares having an aggregate initial Liquidation Preference equal to the sum of the following amounts (without duplication and after taking into account Section 8.2(h)):

(cc) the aggregate of all Title Defect Amounts in respect of Title Defects asserted properly and timely by Buyer in accordance with Section 8.2(a), which are to be submitted for resolution in accordance with Section 8.2(i); plus

(dd) (i) where (A) the Parties have agreed in writing prior to Closing as to the existence of specified Title Defects and the Title Defect Amount in respect of each such Title Defect and (B) Seller has notified Buyer prior to Closing that Seller intends to attempt to cure such Title Defects after Closing pursuant to Section 8.2(d)(ii), the aggregate amount of all such Title Defect Amounts.

“Title Liabilities” has the meaning set forth in Section 8.1.

“Title Matters” has the meaning set forth in Section 8.2(j)(i).

“Transfer Taxes” has the meaning set forth in Section 5.6(a).

A-17

“Transferred Field Employees” has the meaning set forth in Section 5.11(a).

“TSA” means the Transition Services Agreement by and between Seller and Parent, substantially in the form attached to this Agreement as Exhibit I.

“U.S. Dollars” shall mean the lawful currency of the United States.

“Undeveloped Lease” means any Lease identified as an “Undeveloped Lease” in Part A of Exhibit A.

“Well Imbalance” shall mean any imbalance at the wellhead or applicable thereto between the amount of Hydrocarbons produced from, or allocable to, a Well, in each case, attributable to the interests of Seller therein and the share of production from such Well to which Seller is entitled, together with any appurtenant rights and obligations concerning future in kind and/or cash balancing at the wellhead.

“Wells” has the meaning set forth in Section 2.1(b).

“Willful and Material Breach” means (a) a willful or deliberate act or a willful or deliberate failure to act, which act or failure to act constitutes in and of itself a material breach of this Agreement and which was undertaken with the knowledge that such act or failure to act would be, or would reasonably be expected to cause, a material breach of this Agreement or (b) a Closing Failure.

“Working Interest” means with respect to any Well, Future Well or Undeveloped Lease, as applicable, the percentage or fractional interest in and to such Well, Future Well or Undeveloped Lease, as applicable, that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such Well, Future Well or Undeveloped Lease, as applicable, but without regard to the effect of any royalties, overriding royalties, production payments, net profits interests and other similar burdens upon, measured by, or payable out of production therefrom.

ARTICLE II

PURCHASE AND SALE; PURCHASE PRICE

Section 2.1 Purchase and Sale. At the Closing, effective as of the Effective Time and subject to the terms and conditions of this Agreement, Seller agrees to sell, assign, transfer and convey to Buyer and Buyer agrees to purchase, accept and pay for all of Seller’s right, title and interest in and to the following (collectively, the “Assets”):

(a) The Hydrocarbon and/or other mineral leases and mineral interests described on Part A of Exhibit A hereto (the “Leases”) and any other Hydrocarbon and/or other mineral leases and mineral interests held or owned by Seller together with all other Hydrocarbon and/or mineral leases, working interests, leasehold interests, interests under compulsory pooling orders, operating rights and other rights authorizing the owner, holder or lessee thereof to explore for and produce Hydrocarbons and other minerals underlying the lands covered by the Leases, or any lands pooled, unitized or communitized with any of the Leases, and all other Hydrocarbon and mineral interests, net revenue interests, mineral interests, royalty interests, payments out of production and other similar agreements and rights, whether producing or non-producing, and any rights to acquire any of the foregoing interests by Contract, pooling order or otherwise, in and to the lands covered by the Leases or lands unitized, pooled, communitized or consolidated therewith (the “Lands”).

(b) All of the oil and/or gas wells identified on Part B of Exhibit A hereto (the “Wells”) and any other oil, gas, water, CO2 or injection wells located on any of the Leases, the Lands and/or any other properties described in Section 2.1(a), in each case, whether producing, shut-in or temporarily or permanently abandoned.

(c) All rights, titles in interest arising under any unitization, pooling and/or communitization agreements, declarations or designations and statutorily, judicially or administratively created drilling, spacing and/or production units related to any of the Leases, the Wells, the Lands or any of the other assets or properties described in the foregoing provisions of this Section 2.1.

A-18

(d) All Hydrocarbons produced from, or otherwise allocated to, any of the Leases, Lands, Wells or any of the other assets or properties described in the foregoing provisions of this Section 2.1 from and after the Effective Time.

(e) All production facilities, tanks, tank batteries, separators, flow lines, pipelines, pipeline gathering systems, dehydrators, valves, meters, scrubbers and equipment, and other tangible personal and mixed property, inventory, fixtures and improvements of every kind and character located upon the Leases, the Lands or any of the other assets or properties described in the foregoing provisions of this Section 2.1, or otherwise pertaining to a Well, an SWD Well or any of the other assets or properties described in this Section 2.1 (the “Equipment”).

(f) Those certain saltwater disposal wells described on Exhibit G hereto (the “SWD Wells”) and any other salt water disposal wells owned by Seller.

(g) To the extent assignable (with consent, where applicable), all easements, servitudes, permits, licenses, surface leases, rights-of-way and other similar real property interests relating to surface operations or for use or occupancy of the surface or the subsurface applicable to the Leases, the Lands, the Wells, the SWD Wells, the Equipment or any of the other assets or properties described in this Section 2.1 (the “Easements”).

(h) To the extent assignable (with consent, where applicable), all Related Contracts.

(i) To the extent the same are assignable or transferrable (with consent, where applicable), and further to the extent the same are directly related to any of the Assumed Obligations, all claims, rights and causes of action, including causes of action for breach of warranty, against third parties, asserted or unasserted, known or unknown, and Seller grants to Buyer the right to be subrogated to such rights, claims and causes of action.

(j) All permits, licenses, consents, approvals, franchises, certificates and other authorizations from Governmental Authorities, as well as any applications for the same (collectively, the “Permits”), to the extent assignable (with consent, where applicable) and to the extent related to any of the Leases, the Wells, the SWD Wells, Equipment or any of the other assets or properties described in this Section 2.1 or the use thereof.

(k) All of Seller’s files, records and data relating to the items described in the preceding subsections above, including title records (including title opinions and curative documents), surveys, maps and drawings, correspondence, geological records and information, production, facility and well records and data, electric logs, core data, pressure data, decline curves, graphical production curves and all related matters and construction documents except (i) to the extent the transfer, delivery or copying of such records may be restricted by Contract with a third party; (ii) all documents and instruments of Seller that may be protected by the attorney-client privilege (other than title opinions and curative documents); (iii) all accounting and Tax files, books, records, Tax returns and Tax work papers related to such items; and (iv) to the extent assignable without the payment of a fee to a third party (other than Seller’s Affiliates) or the incurrence of another penalty that Buyer has not separately agreed in writing to pay, all of Seller’s proprietary geophysical and seismic records, data and information (collectively, the “Records”).

(l) All Post-Execution Option Leases.

(m) Subject to the provisions of Section 5.14, to the extent transferrable, all derivative, option, hedge or future contracts relating to the Assets or the production attributable to the Assets held by Seller and set forth on Schedule 2.1(m) (the “Hedges”).

Notwithstanding anything to the contrary set forth herein, Seller shall reserve and retain all of the Excluded Assets and, for the avoidance of doubt, the Assets shall not include any of the Excluded Assets.

A-19

Section 2.2 Purchase Price; Allocation of Purchase Price.

(a) The purchase price for the Assets under this Agreement shall be an amount equal to the sum of the Cash Purchase Price and the Preferred Shares Purchase Price (the “Purchase Price”). The Adjusted Cash Purchase Price shall be paid by Buyer in accordance with Section 2.4 at Closing in U.S. Dollars by wire transfer in same day funds to one or more bank accounts of Seller (the details of which shall be provided by Seller to Buyer by written notice given at least three (3) Business Days prior to Closing) or as otherwise provided in Section 2.4. The Preferred Shares Purchase Price shall be delivered by Buyer to Seller and the Escrow Agent at Closing in accordance with Section 2.4.

(b) Seller and Buyer agree that the Purchase Price (a portion of which is based upon the fair market value of the Preferred Shares, as determined based upon a valuation to be provided by Ernst & Young, LLP or as otherwise agreed by Buyer and Seller) and any other items constituting consideration for federal and applicable state income Tax purposes will be allocated among the Assets in accordance with Section 1060 of the Code and the Treasury Regulations promulgated thereunder (the “Tax Allocation”). In making such allocation with respect to any hedge arrangements, current market information will be used to determine fair market value. No later than sixty (60) days after the Closing Date, Buyer shall prepare and deliver to Seller, for Seller’s review and approval, a draft of the Tax Allocation. Seller and Buyer shall use commercially reasonable efforts to agree on a final Tax Allocation. If Buyer and Seller are unable to agree on such final Tax Allocation within thirty (30) days after the delivery by Buyer of the draft Tax Allocation, Buyer and Seller shall jointly retain an Independent Accountant (which may in turn select an appraiser if needed) to resolve the disputed item. The cost of such Independent Accountant (and appraiser) shall be borne fifty percent (50%) by Buyer and fifty percent (50%) by Seller. Seller and Buyer agree to report the transactions contemplated by this Agreement consistent with the Tax Allocation, as agreed to or as determined by the Independent Accountant, and as amended from time to time based on any adjustments to the Purchase Price, on any Tax Return, including Internal Revenue Service Form 8594, unless otherwise required by a final determination as defined in Section 1313 of the Code. Each Party agrees to promptly advise the other Party regarding the existence of any Tax audit, controversy or litigation related to the Tax Allocation.

(c) The Cash Purchase Price shall be adjusted at Closing as follows (as so adjusted, the “Adjusted Cash Purchase Price”):

(i) The Cash Purchase Price shall be adjusted upward by the following amounts (without duplication of any amounts):

(A) an amount equal to the value (based upon the Contract price in effect as of the Effective Time or the most recent sales price received by Seller for similar Hydrocarbons in the same area if there is no Contract price in effect as of the Effective Time) of all Hydrocarbons produced from the Assets in storage or existing in stock tanks, pipelines and/or plants (including inventory) above the pipeline connection or upstream of the sales meter, as applicable, as of the Effective Time, less amounts payable as royalties, overriding royalties and other burdens upon, measured by or payable out of such production;

(B) an amount equal to all Operating Expenses and all other costs and expenses paid, incurred or accrued by Seller or Eagle Energy Company of Oklahoma, LLC (or its subsidiaries), that are directly attributable or related to the Assets from and after the Effective Time (whether paid before or after the Effective Time and including any deposits and pre-payments related to any of the Related Contracts), including (1) royalties and other burdens upon, measured by or payable out of proceeds of production and (2) rentals and other lease maintenance payments;

(C) the amount of all Property Taxes prorated to Buyer in accordance with Section 5.6(b) but paid (or payable) by Seller (or any of its Affiliates);

(D) an amount equal to the Closing Title Benefit Adjustment Amount;

A-20

(E) the Post-Execution Option Lease Amount, if any;

(F) all amounts required to be paid by Seller to hedge counterparties due to the termination of any Hedges in effect on the Execution Date; and

(G) any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer, in each case, as an upward adjustment to the Purchase Price.

(ii) The Cash Purchase Price shall be adjusted downward by the following amounts (without duplication of any amounts):

(A) an amount equal to all proceeds received by Seller and its Affiliates and attributable to the ownership or operation of the Assets during the Interim Period, including from the sale of Hydrocarbons produced from the Assets or allocable thereto during the Interim Period, net of all costs and expenses (other than Operating Expenses and any other costs or expenses, in each case, taken into account in calculating an adjustment to the Purchase Price pursuant to Section 2.2(c)(i)(B)) incurred in earning or receiving such proceeds, in each case, to the extent the same are not reimbursed to Seller;

(B) an amount equal to the Closing Environmental Defect Adjustment Amount and the Closing Title Defect Adjustment Amount;

(C) the amount of all Property Taxes prorated to Seller in accordance with Section 5.6(b) but paid (or payable) by Buyer;

(D) all amounts required to be paid to Seller by hedge counterparties due to the termination of any Hedges in effect on the Execution Date; and

(E) any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer, in each case, as a downward adjustment to the Purchase Price.

Section 2.3 Closing Settlement Statement. No later than five (5) Business Days before the Closing Date, Seller shall deliver to Buyer a draft settlement statement setting forth its calculation of the Adjusted Cash Purchase Price (the “Closing Settlement Statement”), which statement shall be substantially in the form of Schedule 2.3 and which shall reflect each adjustment made in accordance with this Agreement as of the date of preparation of such Closing Settlement Statement and the calculation of the adjustments used to determine such amount.

Section 2.4 Closing Payments. At Closing, Buyer shall pay the amounts described in Sections 2.4(a) and 2.4(d), and Parent shall deliver the Preferred Shares Purchase Price as described in Sections 2.4(c) and 2.4(d):

(a) to the Escrow Agent, Preferred Shares having an initial Liquidation Preference equal to the Escrow Amounts to be held in accordance with the Escrow Agreement;

(b) to (i) the Eagle First Lien Administrative Agent, an amount equal to the Eagle First Lien Payoff Amount (by wire transfer in same day funds in U.S. Dollars or as otherwise specified by the Eagle First Lien Credit Agreement) and (ii) the Eagle Second Lien Administrative Agent, an amount equal to the Eagle Second Lien Payoff Amount (by wire transfer in same day funds in U.S. Dollars or as otherwise specified by the applicable Eagle Second Lien Credit Agreement);

(c) to Seller, an amount equal to the Adjusted Cash Purchase Price (by wire transfer in same day funds in U.S. Dollars to one or more bank accounts of Seller (the details of which shall be provided by Seller to Buyer by written notice given at least three (3) Business Days prior to Closing)), less the sum of (i) the Eagle First Lien Payoff Amount and (ii) the Eagle Second Lien Payoff Amount; and

A-21

(d) Parent shall issue to Seller the Preferred Shares Purchase Price less the Escrow Amounts.

Section 2.5 Post-Closing Adjustments.

(a) Following Closing, Seller shall prepare a final settlement statement setting forth its calculation of the Adjusted Cash Purchase Price (the “Final Settlement Statement”), which statement shall be substantially in the form of Schedule 2.3, and Seller shall deliver the same to Buyer no later than the forty-fifth (45th) day following the Closing Date. The Final Settlement Statement delivered by Seller to Buyer shall be final and binding on the Parties unless Buyer objects within forty-five (45) days after receipt thereof by: (i) notifying Seller in writing of each objection and (ii) delivering to Seller a detailed statement describing the basis for each objection along with any modifications to the Final Settlement Statement proposed by Buyer. Any component of Seller’s Final Settlement Statement that is not the subject of a proper and timely objection by Buyer shall be final and binding on the Parties. If Seller agrees with the modifications to the Final Settlement Statement proposed by Buyer, such modified Final Settlement Statement shall be final and binding on the Parties. If Seller does not agree with the modifications to the Final Settlement Statement proposed by Buyer, Seller shall, within fifteen (15) days after its receipt of Buyer’s objection(s) and calculations, notify Buyer in writing of its disagreement, which notice shall contain a detailed statement describing the basis of its disagreement to each objection. Throughout the period following the Closing Date, Buyer shall provide Seller and its counsel, accountants and other advisors reasonable access (with the right to make copies) to the Records for the purposes of the review and objection right contemplated herein.

(b) Seller and Buyer shall use all commercially reasonable efforts to resolve any dispute arising under Section 2.5(a); provided, however, that if they fail to resolve any dispute within seventy-five (75) days following Seller’s notice to Buyer that it disagrees with Buyer’s objection(s) or the modifications to the Final Settlement Statement proposed by Buyer, then, by written notice from Seller or Buyer to the other, such disagreement may be submitted for resolution to KPMG LLP or such other firm of independent accountants of national standing to which Buyer and Seller agree in writing (the “Independent Accountants”). Within ten (10) days after the Independent Accountants have been retained, each of Seller and Buyer shall furnish, at its own expense, to the Independent Accountants and the other Party a written statement of its position with respect to each matter in dispute. Within five (5) Business Days after the expiration of such ten (10)-day period, Seller and Buyer may deliver to the Independent Accountants and to each other their respective responses to the other’s position on each matter in dispute. With each submission, Seller and Buyer may also furnish to the Independent Accountants such other information and documents as they deem relevant or such information and documents as may be requested by the Independent Accountants with appropriate copies or notification being given to the other. The Independent Accountants may, at their discretion, conduct a conference concerning the disputed matter(s) with Seller and Buyer, at which conference Seller and Buyer shall each have the right to present additional documents, materials and other information and to have present its advisors, counsel and accountants.

(c) The Independent Accountants shall be directed to promptly, and in any event within thirty (30) days after their appointment pursuant to Section 2.5(b), render their decision on the disputed matter(s). The Independent Accountants’ determination as to each matter in dispute shall be set forth in a written statement delivered to Seller and Buyer, which shall include the Independent Accountants’ determination of the Final Settlement Statement, all of which shall be final and binding on the Parties. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Independent Accountants.

(d) Any difference in the Adjusted Cash Purchase Price as set forth in the Closing Settlement Statement and the amount of the Adjusted Cash Purchase Price set forth in the Final Settlement Statement (as finally agreed to or otherwise resolved pursuant to this Section 2.5) shall be settled by the owing Party to the owed Party within ten (10) Business Days by the owing Party paying the amount of such difference (the “Consideration Difference”) to the owed Party. All amounts paid pursuant to this Section 2.5(d) shall be delivered in U.S. Dollars by wire transfer of immediately available funds to the account specified in writing by the owed Party.

A-22

Section 2.6 Revenues and Expenses.

(a) Subject to the last sentence of this Section 2.6(a), Seller shall be entitled to all of the rights of ownership attributable to the Assets (including the right to all production, proceeds of production and other proceeds) attributable to the period of time prior to the Effective Time. Except as expressly set forth in this Agreement and subject to the provisions hereof and the occurrence of the Closing, Buyer shall be entitled to all of the rights of ownership attributable to the Assets (including the right to all production, proceeds of production and other proceeds) attributable to the period from and after the Effective Time. Subject to the other provisions of this Agreement, (i) until the first (1st) anniversary of the Closing, all Operating Expenses that are incurred by Seller and attributable to the period prior to the Effective Time (such Operating Expenses, the “Pre-Effective Time Operating Expenses”), shall be paid by or allocated to Seller, as applicable and (ii) all other Operating Expenses shall be paid by or allocated to Buyer, as applicable.

(b) If, after the delivery of the Final Settlement Statement pursuant to the provisions of Section 2.5, (i) either Party receives monies (including proceeds of production) belonging to the other Party pursuant to Section 2.6(a) 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 Operating Expenses that are the obligation of the other Party pursuant to Section 2.6(a) or otherwise, then the obligated Party shall, within five (5) Business Days after the end of the month in which the applicable invoice 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 2.6(a) 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 2.6 against amounts owing by it to such other Party pursuant to this Section 2.6, but not otherwise.

(c) From and after the first (1st) anniversary of the Closing, Buyer shall be entitled to all of Seller’s right, title and interest in and to all claims, rights and causes of action, asserted or unasserted, known or unknown, including claims for refunds, in each case, with respect to the Pre-Effective Time Operating Expenses.

Section 2.7 Parent Guaranty. Concurrently with the execution of this Agreement, Parent shall execute and deliver to Seller the Parent Guaranty substantially in the form of Exhibit D (the “Parent Guaranty”).

ARTICLE III

SELLER’S REPRESENTATIONS AND WARRANTIES

Seller represents and warrants to Buyer and Parent the following:

Section 3.1 Organization and Good Standing. Seller is a limited liability company, duly organized and validly existing under the Laws of the State of Delaware and has all requisite limited liability company power and authority to own, lease and operate its properties, including the Assets, and to carry on its business as currently conducted. Seller is duly licensed or qualified to do business as a foreign limited liability company in the jurisdictions listed in Schedule 3.1 and is in good standing in all such jurisdictions in which such qualification is required by Law, except where the failure to be so qualified would not have a Seller Material Adverse Effect.

Section 3.2 Authority; Authorization of Agreement. Seller has all requisite limited liability company power and authority to execute and deliver this Agreement and the Operative Documents to which it is (or will be, as applicable) a party, to consummate the transactions contemplated by this Agreement and the Operative Documents to which it is (or will be, as applicable) a party and to perform all of its obligations under this Agreement and the Operative Documents to which it is a party. The execution and delivery by Seller of this Agreement and the other Operative Documents to which it is (or will be, as applicable) a party, the performance

A-23

by Seller of its obligations hereunder and thereunder and the consummation by Seller of the transactions contemplated hereby and thereby have been duly authorized by all requisite limited liability company action on the part of Seller. This Agreement has been, and each Operative Document to which Seller is (or will be) a party has been (or will be, as applicable) duly executed and delivered by Seller, and constitutes (or when executed and delivered by Seller, shall constitute) the valid and binding obligations of Seller, enforceable against Seller in accordance with their respective terms, except as such enforceability may be limited by any applicable bankruptcy, insolvency or other Laws relating to or affecting the enforcement of creditors’ rights and general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

Section 3.3 Consents; No Violations. Except for (a) any Customary Post-Closing Consents, (b) any consents or approvals listed on Schedule 3.3, (c) any Preferential Purchase Rights listed on Schedule 3.9 and (d) as may be required under any (i) Material Contracts or (ii) Related Contracts that are not Material Contracts and that are terminable upon not greater than sixty (60) days’ notice without penalty, (A) there are no consents to assignment or other prohibitions on assignment (each a “Consent”) that are applicable to the transfer of the Assets by Seller to Buyer hereunder or otherwise applicable in connection with the consummation of the transactions contemplated by this Agreement by Seller and (B) Seller’s execution and delivery of this Agreement and the Operative Documents to which it is a party and the consummation of the transactions contemplated hereby and thereby by Seller shall not:

(1) conflict with, violate, breach or require the consent of any Person under any of the terms, conditions or provisions of the organizational documents of Seller;

(2) conflict with, violate or breach any provision of, or require any filing, consent or approval under, any Laws applicable to Seller except (in each case) where such violation or the failure to make or obtain such filing, consent or approval would not have a Seller Material Adverse Effect;

(3) except with respect to the Eagle Credit Documents, conflict with, result in a breach of, constitute a default under or constitute an event that with notice or lapse of time, or both, would constitute a default under, accelerate or permit the acceleration of the performance required by, create in any Person the right to terminate, modify or cancel, or require any consent, authorization or approval under, in each case, any Material Contract; or

(4) result in the creation or imposition of any Encumbrance upon one or more of the Assets except for the Permitted Encumbrances.

Section 3.4 Legal Proceedings. Schedule 3.4 sets forth all Legal Proceedings pending or, to Seller’s Knowledge, threatened in writing, against Seller with respect to any of the Assets. This Section 3.4 does not include any matters with respect to Environmental Laws, such matters being addressed exclusively in Section 3.11 and Article IX.

Section 3.5 Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated or, to Seller’s Knowledge, threatened, against Seller or any of its subsidiaries.

Section 3.6 Foreign Person. Seller is not a “foreign person” within the meaning of Section 1445 of the Code.

Section 3.7 Material Contracts.

(a) Schedule 3.7 sets forth all Related Contracts of the type described below to which Seller is a party (collectively, all of such Related Contracts, the “Material Contracts”):

(i) any Related Contract that can reasonably be expected to result in aggregate payments by Seller of more than Two Hundred Fifty Thousand Dollars ($250,000) during the current or any subsequent fiscal year of Seller or Five Hundred Thousand Dollars ($500,000) in the aggregate over the term of such Related Contract (based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

A-24

(ii) any Related Contract that can reasonably be expected to result in aggregate revenues to Seller of more than Two Hundred Fifty Thousand Dollars ($250,000) during the current or any subsequent fiscal year of Seller or Five Hundred Thousand Dollars ($500,000) in the aggregate over the term of such Related Contract (based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

(iii) any Related Contract that is a Hydrocarbon purchase and sale, transportation, processing or similar Related Contract that is not terminable by Seller or any of its Affiliates that is a party thereto without penalty on sixty (60) days or less notice;

(iv) any Related Contract that constitutes a lease, under which Seller is the lessor or the lessee of real or personal property which lease (A) cannot be terminated by Seller without penalty upon sixty (60) days or less notice and (B) involves an annual base rental of more than One Hundred Thousand Dollars ($100,000);

(v) any Related Contract of Seller with an Affiliate of Seller that will not be terminated prior to Closing;

(vi) any executory Related Contract that constitutes (A) a pending purchase and sale agreement, farmout or farm-in agreement or other Contract providing for the purchase, sale or earning of any material asset included in or related to the Assets, (B) an area of mutual interest agreement and (C) a participation agreement, exploration agreement, development agreement, joint venture agreement, joint operating agreement, unit agreement or other similar Contract;

(vii) any Related Contract that constitutes a non-competition agreement or any other Contract that purports to restrict, limit or prohibit the manner in which, or the locations in which, Seller conducts business, including area of mutual interest Contracts;

(viii) any Related Contract that includes any calls on, or options to purchase, Hydrocarbon production;

(ix) any Related Contract that includes any “tag along” or similar rights allowing a third party to participate in future sales of any of the Assets;

(x) any Related Contract, the primary purpose of which is to indemnify another Person, if such Related Contract would reasonably be expected to result in a liability to Buyer of more than $250,000;

(xi) any Related Contract that is a seismic or other geophysical acquisition agreement or license;

(xii) the Hedges; and

(xiii) powers of attorney relating to the Assets that are still in effect.

(b) Except as set forth on Schedule 3.7 and except for such matters that would not have a Seller Material Adverse Effect, (i) the Material Contracts are in full force and effect, (ii) the Material Contracts are enforceable against Seller and, to Seller’s Knowledge, any other Person that is a party to such Material Contract, in each case, in accordance with their respective terms except as such enforceability may be limited by any applicable bankruptcy, insolvency or other Laws relating to or affecting creditors’ rights and general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity), (iii) there exist no defaults under the Material Contracts by Seller or, to Seller’s Knowledge, by any other Person that is a party to such Material Contracts and (iv) no event has occurred under any of the Material Contracts that with notice or lapse of time or both would constitute any default under any Material Contract by Seller or, to Seller’s Knowledge, any other Person who is a party to such Material Contract. Except as set forth on Schedule 3.7, there are no material disputes pending or, to the Knowledge of Seller, threatened under any Material Contract. Prior to the execution of this Agreement, Seller has furnished or made available to Buyer true and complete copies of each Material Contract and all amendments, supplements and waivers thereto.

A-25

Section 3.8 No Violation of Laws. To Seller’s Knowledge, except as set forth on Schedule 3.8, Seller is not in violation of any Laws with respect to its ownership and operation of the Assets. This Section 3.8 does not include any matters with respect to Environmental Laws, such matters being addressed exclusively in Section 3.11 and Article IX.

Section 3.9 Preferential Rights. Except as set forth on Schedule 3.9, there are no preferential rights to purchase that are applicable to the transactions contemplated hereby with respect to the Assets.

Section 3.10 Royalties, Etc. Except as set forth on Schedule 3.10, to Seller’s Knowledge, Seller has paid all royalties, overriding royalties and other burdens due by Seller with respect to the Assets, or if not so paid, is contesting or suspending payment of such royalties, overriding royalties and other burdens in good faith, and Schedule 3.10 sets forth all such contested or suspended payment amounts with respect to such royalties, overriding royalties and other burdens.

Section 3.11 Environmental.

(a) Except as set forth on Schedule 3.11, to Seller’s Knowledge, the Assets are in compliance with the applicable requirements of Environmental Laws, and Seller has not entered into nor are the Assets subject to any currently effective agreements, consents, orders, decrees, judgments or other directives of any Governmental Authority pursuant to Environmental Laws, except in either case for such non-compliance, agreements, consents, orders, decrees, judgments or other directives that would not reasonably be expected to have a Seller Material Adverse Effect.

(b) Except as set forth on Schedule 3.11, Seller has not received written notice from any Person of an Environmental Condition that would reasonably be expected to have a Seller Material Adverse Effect.

(c) To Seller’s Knowledge, except as set forth on Schedule 3.11, Seller is not aware of any pending Legal Proceedings under any Environmental Laws that involve Seller and that relate to any agreement giving rise to an obligation under Environmental Laws.

(d) To Seller’s Knowledge, all material written reports, studies, notices from Governmental Authorities, and other material documents specifically addressing environmental matters related to Seller’s ownership or operation of the Assets, which are in Seller’s possession have been made available to Buyer.

The representations and warranties of this Section 3.11 are the sole representations and warranties of Seller with respect to matters arising under or related to Environmental Laws or any other agreements imposing obligations with respect to matters regulated under Environmental Laws.

Section 3.12 Imbalances. To Seller’s Knowledge, Schedule 3.12 sets forth all Imbalances attributable to Seller’s interest in the Assets as of the date set forth on such Schedule 3.12.

Section 3.13 Drilling Obligations. Except as set forth on Schedule 3.13, Seller has no unfulfilled drilling obligations affecting the Leases by virtue of a Related Contract, other than provisions requiring optional drilling as a condition of maintaining or earning all or a portion of an Undeveloped Lease.

Section 3.14 Current Commitments. Schedule 3.14 sets forth as of the date of this Agreement all authorizations for expenditures (“AFEs”) in excess of $100,000 per individual AFE or series of related AFEs, in each case, received or issued by Seller and relating to Seller’s interest in the Assets to drill or rework wells or for other capital expenditures pursuant to any of the Material Contracts, in each case, for which all of the activities anticipated in such AFEs or commitments have not been completed as of the date of this Agreement.

Section 3.15 Brokers. No broker, finder or investment bank is entitled to any brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation to an intermediary in connection with the

A-26

negotiation, execution or delivery of this Agreement or any agreement or transaction contemplated hereby based on any arrangements made by or on behalf of Seller for which Buyer shall have (directly or indirectly) any responsibility, liability, or expense.

Section 3.16 Plugging and Abandonment Obligations. With the exception of those Wells identified on Schedule 3.16, there are no Wells operated by Seller that (a) relate or are subject to an order from any Governmental Authority requiring that such Well be plugged and abandoned, (b) are not in use for purposes of production or injection, nor suspended or temporarily abandoned, or, to Seller’s Knowledge, that have been plugged and abandoned, but have not been plugged or abandoned in accordance with all applicable requirements of each Governmental Authority having jurisdiction over such Well, (c) to Seller’s Knowledge, are not properly permitted by the Governmental Authority having jurisdiction thereover, (d) have not been drilled and completed within the limits permitted by all applicable Related Contracts or (e) to Seller’s Knowledge, have been produced in excess of allowables allocated thereto by the Governmental Authority having jurisdiction thereover or subject to penalties on allowables after the Effective Time because of overproduction. The representations and warranties in this Section 3.16 shall not apply to any Remediation obligations.

Section 3.17 Disclosure Not Prohibited. Except as set forth on Schedule 3.17, neither Seller nor the Assets are subject to any Contracts which restrict or prohibit Seller from disclosing to Buyer information that is material to Buyer’s review, inspection, ownership and operation of the Assets.

Section 3.18 No Prepayments. Except as disclosed on Schedule 3.18, Seller is not obligated by virtue of any prepayment arrangement for the sale of Hydrocarbons and/or any take or pay or other similar provisions of a production payment or other arrangement, to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to the Assets at some future time without then or thereafter receiving full payment therefor.

Section 3.19 Taxes. Except as set forth in Schedule 3.19, (a) all material Tax Returns required to be filed with respect to the Assets prior to the date hereof have been filed, and such returns are true and accurate in all material respects, (b) all Taxes shown as due on such Tax Returns have been paid, (c) there are no material liens on any of the Assets that arose in connection with any failure to pay any Tax and (d) there is no material claim pending by any Governmental Authority in connection with any Tax or any Tax Return described in clauses (a) or (b).

Section 3.20 Tax Partnerships. Except as set forth on Schedule 3.20, none of Seller’s interest in the Assets is subject to tax partnership reporting for federal income tax purposes.

Section 3.21 Equipment and SWD Wells.

(a) Except as described on Schedule 3.21, all Equipment, SWD Wells and currently producing Wells are, to Seller’s Knowledge, in all material respects, in a state of reasonable repair (subject to normal wear and tear, maintenance and ongoing upgrades or replacement consistent with past practice) so as to be adequate for present uses and operations.

(b) Except as set forth on Schedule 3.21, to Seller’s Knowledge, Seller has all material Easements and Permits necessary to access, construct, operate, maintain and repair the Equipment, the SWD Wells and currently producing Wells, as applicable, in the ordinary course of business as currently conducted. Except for Permitted Encumbrances, Seller (i) has the contractual right to use or is the exclusive or non-exclusive legal and beneficial owner of the Easements, (ii) has conducted its operations in a manner that does not violate any of the terms of any such Easements and (iii) except as set forth on Schedule 3.21, has not received written notice of revocation or termination of any such Easements.

(c) Except as described on Schedule 3.21, Seller has good and defensible title to (or, in the case of a leasehold interest, such legally enforceable rights to use) the Equipment and SWD Wells, free and clear of all Encumbrances other than Permitted Encumbrances.

A-27

Section 3.22 Operation of the Assets. Except as described in Schedule 3.22, since the Effective Time and until the date hereof, (a) all Assets operated by Seller have been operated only in the ordinary course of business consistent with past practices of Seller and Section 5.1 and (b) there has not been any material damage, destruction or loss with respect to the Assets. The representations and warranties in this Section 3.22 shall not apply to any of the Leases.

Section 3.23 Non-Consent Operations. Except as described in Schedule 3.23, from the Effective Time until the date hereof, Seller has not elected (or been deemed to have elected) to be a non-consenting party with respect to any Well.

Section 3.24 Compliance with Permits. Except as set forth on Schedule 3.24, To Seller’s Knowledge, Seller has obtained and is maintaining all Permits that are necessary or required for the ownership, development and operation of the Assets by Seller, and (a) all such Permits are in full force and effect and (b) there are no proceedings pending or, to Seller’s Knowledge, threatened in writing before any Governmental Authority that seek the revocation, cancellation, suspension or adverse modification thereof.

Section 3.25 Lease Status; Rentals. Except as set forth on Schedule 3.25, Seller has not received written notice of (a) any request or demand for payments, adjustments of payments or performance pursuant to obligations under the Leases that is still outstanding and (b) any default with respect to the payment or calculation of rentals that has not been cured.

Section 3.26 Seller’s Receipt of Payments for Production. Except as described in Schedule 3.26, to Seller’s Knowledge, Seller is currently receiving from all purchasers of production revenues not less than the Net Revenue Interest for each Well reflected on Exhibit A, without suspense or any indemnity other than the normal division order warranty of title.

Section 3.27 Payout Status. To Seller’s Knowledge, Schedule 3.27 contains a true and correct list of the status of any “payout” balance (net to the interest of Seller), as of the dates set forth on Schedule 3.27, for each Well that is subject to a reversion or other adjustment at some level of cost recovery or payout.

Section 3.28 Suspense Funds. Schedule 3.28 lists (a) all funds held in suspense by Seller that are attributable to the Assets, (b) a description of the source of such funds and the reason they are being held in suspense and (c) if known, the name or names of the Persons claiming such funds or to whom such funds are owed.

Section 3.29 Certain Actions. Except as set forth in Schedule 3.29, since the Effective Time until the date hereof, there has been no action taken by the Seller that would have required the consent of Buyer under Section 5.1 had the action been taken from and after the date hereof.

Section 3.30 No Seller Material Adverse Effect. Except as set forth in Schedule 3.30, since the Effective Time there has been no Seller Material Adverse Effect.

Section 3.31 Investment Representations.

(a) Experience; Status.

(i) Seller has substantial experience in analyzing and investing in companies like Parent and is capable of evaluating the merits and risks of its investment in Parent and has the capacity to protect its own interests. To the extent necessary, Seller has retained, at its own expense, and relied upon, appropriate professional advice regarding the investment, tax and legal merits and consequences of an investment in the Preferred Shares that Seller will receive at Closing and the Common Shares issuable upon conversion of such Preferred Shares.

(ii) Seller is an “accredited investor” (as such term is used in Rule 501 under the Securities Act), is able to bear the economic risk of its investment in the Preferred Shares and the Common Shares indefinitely and has sufficient net worth to sustain a loss of its entire investment in Parent without economic hardship if such loss should occur.

A-28

(b) Access to Information.

(i) Seller has had an opportunity to discuss Parent’s business, management and financial affairs with the members of Parent’s management and has had the opportunity to review Parent’s operations and facilities. Seller has also had an opportunity to ask questions of the officers of Parent, which questions were answered to its satisfaction. Seller acknowledges that it is familiar with the nature of Parent’s business. Seller has received and had an opportunity to read the Reports.

(ii) Seller has not received representations or warranties from Parent or Buyer, or their employees, affiliates, attorneys, accountants or agents, except as set forth in this Agreement and has undertaken such due diligence pertaining to Parent and Buyer as Seller deems adequate. Seller has, as of the execution and delivery of this Agreement, no Knowledge of any fact that results in the breach of any representation, warranty or covenant of Buyer or Parent given hereunder.

(iii) Seller understands that the ownership of the Preferred Shares and the Common Shares involves numerous risks, including those described under the heading “Risk Factors” in Parent’s filings with the SEC.

(i) Seller is acquiring the Preferred Shares and the Common Shares issuable upon conversion of such Preferred Shares solely for investment for its own account, not as a nominee or agent, and not with the view to, or for resale in connection with, any distribution thereof in any transaction in violation of the securities Laws of the United States of America or any state. Seller understands that the Preferred Shares and the Common Shares issuable upon conversion of such Preferred Shares have not been registered under the Securities Act or applicable state securities laws by reason of a specific exemption from the registration provisions of the Securities Act and applicable state securities laws, the availability of which depends upon, among other things, the bona fide nature of the investment intent and the accuracy of Seller’s representations as expressed herein. Seller understands that Parent is relying, in part, upon the representations and warranties contained in this Section 3.31 for the purpose of determining whether this transaction meets the requirements for such exemptions.

(ii) Seller acknowledges and understands that it must bear the economic risk of its investment in the Preferred Shares and the Common Shares issuable upon conversion of such Preferred Shares for an indefinite period of time because such Preferred Shares and such Common Shares must be held indefinitely unless subsequently registered under the Securities Act and applicable state securities laws or unless an exemption from such registration is available.

(iii) Seller understands that any transfer agent of Parent will be issued stop transfer instructions with respect to the Preferred Shares and the Common Shares unless such transfer is subsequently registered under the Securities Act and applicable state securities laws or unless an exemption from such registration is available.

Section 3.32 Employee Matters.

(a) Seller is not a party to any collective bargaining agreement with respect to any individuals who are employed by Seller or an Affiliate who provide services related to the Assets.

(b) Neither Seller nor any trade or business, whether or not incorporated, that together with Seller would be deemed a “controlled group” within the meaning of Section 4001 of the Employee Retirement Security Act of 1974, as amended (“ERISA”) or Section 414 of the Code has any liability (or has within the past six (6) years) had any liability (including any contingent liability under Section 4204 of ERISA) with respect to any plan subject to Title IV of ERISA that would be, or could be reasonably expected to become, a Liability of Buyer or any of its Affiliates (“Title IV Liability”).

A-29

ARTICLE IV

BUYER’S REPRESENTATIONS AND WARRANTIES

Parent and Buyer represents and warrants to Seller the following:

Section 4.1 Organization and Good Standing. Each of Parent and Buyer is a corporation or limited liability company, as applicable, duly organized and validly existing under the Laws of the State of Delaware and has all requisite corporate or limited liability company, as applicable, power and authority to own, lease and operate its properties and to carry on its business as currently conducted. Buyer is duly licensed or qualified to do business as a foreign corporation or limited liability company, as applicable, in the jurisdictions listed in Schedule 4.1 and is in good standing in all such jurisdictions in which such qualification is required by Law, except where the failure to be so qualified would not have a Buyer Material Adverse Effect.

Section 4.2 Capitalization. As of the Execution Date, the authorized capital stock of the Parent consists of 300,000,000 Common Shares and 50,000,000 shares of preferred stock. As of August 6, 2012, there were issued and outstanding 66,549,563 Common Shares and no shares of preferred stock. The outstanding Common Shares have been duly authorized and are validly issued and outstanding, fully paid and non-assessable, and subject to no preemptive rights (and were not issued in violation of any preemptive rights). As of the date of this Agreement, there are no Common Shares or shares of preferred stock reserved for issuance, except the Common Shares underlying the Preferred Shares and Common Shares issuable upon conversion or exercise of derivative securities issued under Parent’s long-term equity or other compensation plans, the Parent does not have outstanding any securities providing the holder the right to acquire Common Shares or preferred stock, and the Parent does not have any commitment to authorize, issue, or sell any Common Shares or preferred stock other than pursuant to this Agreement and the Certificate of Designations.

Section 4.3 Authority; Authorization of Agreement. Each of Buyer and Parent has all requisite corporate power and authority to execute and deliver this Agreement and the Operative Documents to which it is a party or signatory, to consummate the transactions contemplated by this Agreement and the Operative Documents to which it is (or will be, as applicable) a party or a signatory and to perform all of its obligations under this Agreement and the Operative Documents to which it is (or will be, as applicable) a party or a signatory. The execution and delivery by each of Buyer and Parent of this Agreement and the other Operative Documents to which it is (or will be, as applicable) a party, the performance by each of Buyer and Parent of its obligations hereunder and thereunder and the consummation by each of Buyer and Parent of the transactions contemplated hereby and thereby have been duly authorized by all requisite corporate action on the part of Buyer and Parent, respectively. This Agreement has been, and each Operative Document to which Buyer or Parent is (or will be) a party has been (or will be, as applicable) duly executed and delivered by Buyer or Parent respectively, and constitutes (or when executed and delivered by Buyer or Parent, shall constitute) the valid and binding obligations of Buyer or Parent, respectively, enforceable against it in accordance with their respective terms, except as such enforceability may be limited by any applicable bankruptcy, insolvency or other Laws relating to or affecting the enforcement of creditors’ rights and general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

Section 4.4 Consents; No Violations. There are no Consents that are applicable in connection with the consummation of the transactions contemplated by this Agreement by Buyer or Parent and the execution and delivery of this Agreement by each of Buyer and Parent and the Operative Documents to which it is a party and the consummation of the transactions contemplated hereby and thereby by it shall not:

(i) conflict with, violate, breach or require the consent of any Person under any of the terms, conditions or provisions of its organizational documents;

(ii) conflict with, violate or breach any provision of, or require any filing, consent or approval under, any Laws applicable to it except (in each case) where such violation or the failure to make or obtain such filing, consent or approval would not have a Buyer Material Adverse Effect; or

A-30

(iii) conflict with, result in a breach of, constitute a default under or constitute an event that, with notice or lapse of time, or both, would constitute a default under, accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under: (i) any material agreement or any mortgage, indenture, loan, credit agreement or other agreement evidencing indebtedness for borrowed money to which it is a party or by which it (or any of its assets) is bound, except (in each case) where such conflict, breach or default would not materially affect Buyer’s ability to consummate the transactions contemplated hereby or (ii) any order, judgment or decree of any Governmental Authority.

Section 4.5 Registration Rights. Schedule 4.5 lists all registration rights agreements to which Parent is a party and true and complete copies of such agreements have been provided to Seller. The consummation of the transactions contemplated by this Agreement and the Operative Documents will not conflict with, violate or breach any of the terms, conditions or provisions of the agreements listed on Schedule 4.5.

Section 4.6 SEC Documents.

(a) Parent has filed with the SEC all reports and statements (including any amendments thereto) required to be so filed by it since April 17, 2012 pursuant to Sections 13(a), 14(a) and 15(d) of the Exchange Act, and has made available to Seller each registration statement, report, proxy statement or information statement (other than preliminary materials) it has so filed, each in the form filed with the SEC (collectively, the “Reports”).

(b) As of the Execution Date, Buyer represents that, as of the date it was filed with the SEC, each Report (i) complied in all material respects with the applicable requirements of the Exchange Act and the rules and regulations thereunder and (ii) did not include any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made therein, in the light of the circumstances under which they were made, not misleading, except for such statements, if any, as have been modified by subsequent filings with the SEC prior to the Execution Date. As of the Closing Date, Buyer represents that, as of the date it was filed with the SEC, each Report (i) complied in all material respects with the applicable requirements of the Exchange Act and the rules and regulations thereunder and (ii) did not include any untrue statement of a material fact or omit to state a material fact necessary in order to make the statements made therein, in the light of the circumstances under which they were made, not misleading, except for such statements, if any, as have been modified by subsequent filings with the SEC prior to the Closing Date.

(c) Each of the consolidated balance sheets included in or incorporated by reference into the Reports (including the related notes and schedules) fairly presents in all material respects the consolidated financial position of Parent and its subsidiaries as of its date, and each of the consolidated statements of operations, cash flows and changes in stockholders’ equity included in or incorporated by reference into the Reports (including any related notes and schedules) fairly presents in all material respects the results of operations, cash flows or changes in stockholders’ equity, as the case may be, of Parent and its subsidiaries for the periods set forth therein (subject, in the case of unaudited statements, to (i) such exceptions as may be permitted by Form 10-Q of the SEC and (ii) normal year end audit adjustments), in each case in accordance with generally accepted accounting principles consistently applied during the periods involved, except as may be noted therein. Except as and to the extent set forth on the consolidated balance sheet of Parent and its subsidiaries included in the most recent Report filed prior to the date of this Agreement that includes such a balance sheet, including all notes thereto, as of the date of such balance sheet, neither Parent nor any of its subsidiaries has any liabilities or obligations of any nature (whether accrued, absolute, contingent or otherwise) that would be required to be reflected on, or reserved against in, a balance sheet of Parent or in the notes thereto prepared in accordance with generally accepted accounting principles consistently applied, other than liabilities or obligations which do not and are not reasonably likely to have, individually or in the aggregate, a Buyer Material Adverse Effect.

Section 4.7 Claims, Disputes and Litigation. As of the date of this Agreement, there are no Legal Proceedings pending or, to Buyer’s Knowledge, threatened in writing against Buyer that would prevent the consummation by Buyer of the transactions contemplated by this Agreement and the Operative Documents.

A-31

Section 4.8 Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s Knowledge, threatened against Buyer or its subsidiaries.

Section 4.9 Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities such as the Assets and is aware of the risks of that business. In making its decision to enter into this Agreement and to consummate the transactions contemplated herein, subject to the express provisions of this Agreement, Buyer (i) has relied on its own independent investigation and evaluation of the Assets and (ii) has undertaken such due diligence pertaining to the Assets as Buyer deems adequate. Buyer has, as of the execution and delivery of this Agreement, no Knowledge of any fact that results in the breach of any representation, warranty or covenant of Seller given hereunder.

Section 4.10 Financing. The financing of the Cash Purchase Price will consist of debt financing provided to Parent and/or Buyer, which may consist of proceeds from a loan or the sale of debt securities (the “Financing”). Buyer has delivered to Seller true and complete copies of fully executed commitment letters pursuant to which certain of the parties named therein agreed, subject to the terms and conditions thereof, to lend the amounts set forth therein for the purposes of funding the Cash Purchase Price at Closing (the “Commitment Letter”). As of the Execution Date, the Commitment Letter is in full force and effect and is a legal, valid and binding obligation of Buyer and, to the Knowledge of the Buyer, the other parties thereto, the financing commitments thereunder have not been withdrawn or terminated, and the Commitment Letter has not been amended, supplemented or otherwise modified in any respect. No event has occurred that, with or without notice, lapse of time or both, would constitute a default or breach on the part of Buyer or Parent (as applicable) under any term of the Commitment Letter. Buyer has no reason to believe that it or any of the other parties to the Commitment Letter will be unable to satisfy on a timely basis any term or condition of the Commitment Letter required to be satisfied by it. Buyer has no reason to believe that any portion of the Financing to be made thereunder will otherwise not be available to Buyer on a timely basis to consummate the transactions contemplated hereby. Buyer and its Affiliates are not required to pay any fees or other amounts to the Financing Sources in connection with the Financing prior to the execution of this Agreement, except those fees and other amounts which Buyer and its Affiliates have paid in full as of the Execution Date. The obligations of the other parties to the Commitment Letter to fund the full amount of the Financing to Buyer pursuant to the terms of the Commitment Letter are not subject to any conditions other than the conditions set forth in the Commitment Letter. There are no side contracts or understandings (other than for customary fee letters and engagement letters) related to the Financing under the Commitment Letter other than as expressly set forth in the Commitment Letter. At the Closing, Buyer will have readily available funds that are sufficient to pay the Cash Purchase Price on the terms contemplated hereby.

Section 4.11 Representations by Parent as to the Preferred Shares and Common Shares.

(a) Upon consummation of the transactions contemplated by this Agreement and the issuance of the Preferred Shares in connection therewith, the Preferred Shares will be duly authorized, validly issued, fully paid and non-assessable, and free and clear of any Encumbrances other than restrictions on transfer imposed by applicable federal or state securities Laws. The Preferred Shares have the rights, privileges and preferences set forth in the Certificate of Designations. The Certificate of Designations has been duly adopted and authorized, and when filed with, and accepted by, the Secretary of State of Delaware, will be binding upon the Parent.

(b) The Common Shares reserved for issuance upon conversion of the Preferred Shares have been duly authorized and reserved for issuance and, when issued upon conversion of the Preferred Shares in accordance with their terms, such Common Shares will be duly authorized, validly issued, fully paid and non-assessable, and free and clear of any Encumbrances other than restrictions on transfer imposed by applicable federal or state securities Laws. The issuance of the Common Shares will not be subject to any preemptive or similar rights.

(c) Upon issuance in accordance with this Agreement, and assuming the accuracy of the representations and warranties of Seller set forth in Article III, the Preferred Shares and the Common Shares issued in accordance

A-32

with the terms of this Agreement will be issued in accordance with all applicable securities Laws and all Common Shares issuable upon conversion of the Preferred Shares will be approved for listing on the NYSE subject only to official notice of issuance.

Section 4.12 Brokers. Other than Suntrust Robinson Humphrey, Evercore Partners and Bank of America Merrill Lynch, the fees and expenses of which will be paid by Parent, no broker, finder or investment bank is entitled to any brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation to an intermediary in connection with the negotiation, execution or delivery of this Agreement or any agreement or transaction contemplated hereby based on any arrangements made by or on behalf of Buyer.

Section 4.13 No Buyer Material Adverse Effect. Except as set forth in Schedule 4.13, since March 31, 2012, there has been no Buyer Material Adverse Effect.

ARTICLE V

COVENANTS

Section 5.1 Conduct of Business. Except as set forth on Schedule 3.14 or 5.1, except as required by Governmental Authority or Law, and except as specifically contemplated by this Agreement, from the date of this Agreement until the earlier to occur of the Closing and the termination of this Agreement in accordance with the provisions of Article XI, unless Buyer shall otherwise consent in writing (which consent shall not be unreasonably withheld, conditioned or delayed), Seller shall, and shall direct its subsidiaries to:

(a) if Seller is the operator thereof, operate the Assets in the ordinary course consistent with Seller’s past practice;

(b) maintain, in all material respects, the Records in the ordinary course consistent with Seller’s past practice;

(c) use all commercially reasonable efforts to maintain insurance coverage on the Assets furnished as of the date hereof by third parties in the amounts and of the types in place as of the date hereof;

(d) give prompt written notice to Buyer of any (i) emergency with respect to, or material damage or destruction of, the Assets with respect to which Seller is the operator, (ii) violation or notices of violations of Law, including Environmental Law, with respect to the Assets with respect to which Seller is the operator or the transactions contemplated by this Agreement, (iii) claims received or made with respect to the Assets with respect to which Seller is the operator or the transactions contemplated by this Agreement and (iv) any such emergency damage, destruction, violation or claim with respect to the Assets about which Seller obtains Knowledge; provided, however, that the failure to give such notice shall not be taken into account in determining whether the condition in Section 6.2(b) has been satisfied; provided, further, that any items identified in any notice provided pursuant to this Section 5.1(d) shall be taken into account for all other purposes of this Agreement;

(e) use Seller’s commercially reasonable efforts (which the Parties acknowledge and agree shall not obligate Seller to make any payments in excess of the amount of any payments it is making or has agreed to make as of the date hereof, with all such payments being in the ordinary course of business consistent with past practice) to retain the services of its officers, managers, employees and consultants and to maintain satisfactory relationships with those persons having business relationships with Seller and its Affiliates to the extent related to the Assets;

(f) except with respect to the agreements listed in number 8 on Schedule 5.1, not, with respect to any of the employees of Seller immediately prior to the Closing who provide services to the Assets, (i) increase any compensation or benefits (other than (A) customary increases in compensation in the ordinary course of business consistent with past practice made to employees and (B) the payment of bonus amounts in accordance with bonus

A-33

plans and programs in the ordinary course of business consistent with past practice), grant any new incentive awards, establish any new bonus plan or arrangement or enter into, amend or extend (or permit the extension of) any employment or consulting agreement, except in each case as required by Laws or pursuant to an employment Contract listed on Schedule 5.1(f), (ii) adopt any new employee benefit plan or agreement or amend (except as required by Laws or pursuant to an employment Contract listed on Schedule 5.1(f)) any existing employee benefit plan in any material respect, (iii) grant any severance pay rights (other than pursuant to the severance policies or agreements of Seller and its Affiliates described in Schedule 5.11) or (iv) terminate any such employee or hire any new employee;

(g) not grant or create any Preferential Purchase Right, Consent or other transfer restriction with respect to any of the Assets;

(h) not sell, transfer, abandon, farmout, lease, encumber exchange or otherwise dispose of any Assets except for (i) any of the foregoing that would be Permitted Encumbrances, (ii) dispositions (including acreage swaps and exchanges) that are set forth on Schedule 5.1, (iii) the sale and/or disposal of Hydrocarbons attributable to the Assets in the ordinary course of business, (iv) dispositions of immaterial obsolete inventory or equipment included in the Assets and (v) immaterial sales, transfers, exchanges and other dispositions that are made in connection with any election to participate made under (or in connection with) any pooling agreement or order;

(i) except for any Related Contract entered into in connection with any activity permitted pursuant to Section 5.1(h)(v) or 5.1(l), not enter into any Related Contract that, if entered into prior to the date of this Agreement, would be required to be listed on Schedule 3.7;

(j) not terminate or materially amend or modify any Material Contract or otherwise waive, release or assign any material rights, claims or benefits of Seller under any Material Contract;

(k) not enter into any derivative, option, hedge or futures contracts;

(l) excepting emergency operations, any operations proposed, consented to or undertaken in connection with any forced pooling notice or order, any operations conducted pursuant to the capital expenditure budget set forth in Schedule 5.1(l), not (i) propose or commit to any single operation, or series of related operations, reasonably anticipated to require capital expenditures by Seller in excess of $100,000, (ii) make any capital expenditures with respect to any operation, or series of related operations, in excess of $100,000, or (iii) propose or make capital expenditures subject to clauses (i) and (ii) in excess of $500,000 in the aggregate;

(m) not dismantle or decommission any material Equipment or other facilities or close pits or restore the surface of such Wells or SWD Wells, facilities or pits;

(n) not surrender or abandon, or waive any material rights with respect to the Leases, Wells or SWD Wells; and

(o) not agree, in writing or otherwise, to take any action prohibited by any of the foregoing provisions of this Section 5.1.

Buyer acknowledges that Seller owns undivided interests in certain of the assets and properties comprising the Assets, and Buyer agrees that the acts or omissions of other Working Interest owners (including the operators) that are not Seller or an Affiliate of Seller shall not constitute a breach of the provisions of this Section 5.1, nor shall any action required by a vote of Working Interest owners constitute such a breach so long as Seller has voted its interest in a manner that complies with the provisions of this Section 5.1.

A-34

Section 5.2 Access; Disclaimers; Record Retention.

(a) From the date hereof until the Closing Date (or earlier termination of this Agreement pursuant to Article XI), subject to the provisions of this Section 5.2 and the obtaining of any required Consents, including Consents of operators of the Assets (which Consents Seller shall use all commercially reasonable efforts to obtain), Seller will give Buyer, its Affiliates and its and their respective officers, employees, agents, accountants, attorneys, investment bankers and other authorized representatives (collectively, “Buyer’s Representatives”) reasonable access, during normal business hours, to the offices, Records and Assets of Seller, for purposes of conducting Buyer’s title and environmental due diligence with respect to the Assets. All investigations and due diligence conducted by Buyer or any of Buyer’s Representatives shall (i) be conducted at Buyer’s sole cost, risk and expense, in such manner so as not to interfere with the conduct of the business of Seller and, to the extent so requested by Seller, under the supervision of a representative of Seller and (ii) not be conducted without prior notice to, and approval of, Seller. Notwithstanding the foregoing, Buyer shall not (A) have access to personnel records of Seller relating to individual performance or evaluation records, medical histories or other information, the disclosure of which, in Seller’s reasonable opinion, could subject Seller, any of its Affiliates or any of the other Seller Subject Parties to risk of liability (unless such information is sufficiently redacted in order to allow such disclosure) without prior written consent of Seller or (B) have access to any information if doing so could violate any Related Contract or Law to which Seller or any of its Affiliates is a party or is subject or which such Person believes in good faith could jeopardize any attorney-client or other legal privilege. Notwithstanding anything herein to the contrary, neither Buyer nor any of Buyer’s Representatives shall have access to, or shall be permitted to conduct, any environmental due diligence (including any Phase I environmental property assessments) with respect to any Asset where Seller does not have the authority to grant access to such Persons for such due diligence; provided, however that Seller shall use all commercially reasonable efforts (which shall not require the payment of any monies by Seller) to obtain such access for such Persons with respect to any such Asset.

(b) Before conducting any sampling, boring, drilling or other invasive investigation activities (“Invasive Activities”) on or with respect to any of the Assets, Buyer shall (i) based on Buyer’s conduct of Phase I environmental property assessments with respect thereto, have a reasonable belief that such Asset is affected by an Environmental Condition, (ii) furnish Seller with a written description of (A) the basis for Buyer’s reasonable belief that such Asset is affected by an Environmental Condition and (B) the proposed scope of the Invasive Activities to be conducted, including a description of the activities to be conducted, and a description of the approximate location and expected timing of such activities and (iii) obtain the prior written consent of Seller (which consent may be withheld by Seller in its sole and absolute discretion) to undertake such Invasive Activities; provided, however that if Seller does not give its written consent to undertake such Invasive Activities within three days, then Buyer may, in its sole discretion, within three days of notice of such nonconsent or expiration of the three-day period referred to above, elect to remove the Asset with respect to which Buyer so proposed to conduct such Invasive Activities from the Assets being conveyed by Seller to Buyer at Closing pursuant hereto, in which case the Purchase Price shall be reduced by an amount equal to the Allocated Value thereof.

(c) Buyer shall coordinate its environmental property assessments, physical inspections of the Assets and other due diligence activity with Seller and (if applicable) all third party operators of the Assets to minimize any inconvenience to or interruption of the conduct of business by such Persons. Buyer shall, and shall cause all of Buyer’s Representatives to, abide by Seller’s and any third party operator’s, as applicable, safety rules, regulations and operating policies while conducting its due diligence evaluation of the Assets, including any environmental or other inspection or assessment of the Assets. Buyer hereby releases, indemnifies, defends and holds harmless each of the operators of the Assets and the Seller Indemnified Parties from and against any and all Liabilities arising out of, resulting from or relating to any field visit, environmental property assessment or other due diligence activity conducted by Buyer or any of Buyer’s Representatives with respect to the Assets, including entry by Buyer or any of Buyer’s Representatives into the offices of Seller, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE,

A-35

CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY THIRD PARTY OPERATOR OR ANY SELLER INDEMNIFIED PARTY, EXCEPTING ONLY LIABILITIES ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SUCH THIRD PARTY OPERATOR OR SELLER INDEMNIFIED PARTY.

(d) Buyer agrees to promptly (and in any event no less than forty-eight (48) hours after their receipt or creation), provide Seller with copies of all final reports and test results prepared by Buyer or any of Buyer’s Representatives that contain data collected or generated from Buyer’s due diligence with respect to the Assets (including all environmental and title reports). Seller shall not be deemed by its receipt of said documents or otherwise to have made any representation or warranty, expressed, implied or statutory, as to the condition of the Assets or to the accuracy of said documents or the information contained therein.

(e) Upon completion of Buyer’s due diligence, Buyer shall at its sole cost and expense (i) repair all damage done to the Assets in connection with Buyer’s due diligence, (ii) restore the Assets to the approximate same or better condition than they were prior to commencement of Buyer’s due diligence and (iii) remove all equipment, tools or other property brought onto the Assets in connection with Buyer’s due diligence. Any disturbance to the Assets resulting from Buyer’s due diligence will be promptly corrected by Buyer.

(f) Neither Seller nor any of its representatives makes any representation or warranty as to the accuracy of any information provided pursuant to this Section 5.2, and Buyer may not rely on the accuracy of any such information, in each case, other than as expressly set forth in the representations and warranties contained in Article III. All information provided or made available to Buyer or any of its representatives will be subject to the Confidentiality Agreements dated as of May 1, 2012 and July 23, 2012 between Eagle Energy of Oklahoma, LLC and Parent (the “Confidentiality Agreements”).

(g) After the Closing, for a period of six (6) years after the Closing (and for such additional time thereafter until final resolution of all disputes under this Agreement), Buyer shall provide to Seller reasonable access to the Records and allow Seller, at Seller’s sole cost and expense, to copy the Records.

(h) Buyer shall preserve and keep the Records in its possession for at least six (6) years following the Closing Date (and for such additional time thereafter until final resolution of all disputes under this Agreement) or for such longer period as may be required by Law or any applicable court order.

Section 5.3 Return or Destruction of Information. In the event of termination of this Agreement in accordance with the provisions of Article XI, Buyer shall promptly, and in any event, with five (5) days after such termination, return or cause to be returned to Seller, or, at Buyer’s option, destroy or cause to be destroyed (in which case, promptly after such destruction, an authorized officer of Buyer shall certify, in writing, to Seller that such destruction has occurred), all documents and other materials obtained from or on behalf of Seller in connection with the transactions contemplated hereby and shall keep confidential any such information, all in accordance with the provisions of the Confidentiality Agreements.

Section 5.4 Notification of Breaches. Until the Closing (or, if earlier, the termination of this Agreement in accordance with the provisions of Article XI):

(a) Buyer shall use reasonable efforts to notify Seller promptly after Buyer obtains Knowledge that any representation or warranty of Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Seller prior to or on the Closing Date has not been so performed or observed in any material respect. Following receipt of such notice, Seller shall use its reasonably best efforts to cure such condition or perform such covenant or agreement; provided, however¸ that the failure to so cure or perform pursuant to this

A-36

Section 5.4(a) shall not be taken into account in determining whether the condition in Section 6.2(b) has been satisfied; provided further, that the breach or nonperformance indentified in any notice provided pursuant to this Section 5.4(a) shall be taking into account for all other purposes of this Agreement.

(b) Seller shall use reasonable efforts to notify Buyer promptly after Seller obtains Knowledge that any representation or warranty of Buyer contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of Closing Date or that any covenant or agreement to be performed or observed by Buyer prior to or on the Closing Date has not been so performed or observed in any material respect. Following receipt of such notice, Buyer shall use its reasonably best efforts to cure such condition or perform such covenant or agreement; provided, however¸ that the failure to so cure or perform pursuant to this Section 5.4(b) shall not be taken into account in determining whether the condition in Section 6.1(b) has been satisfied; provided further, that the breach or nonperformance identified in any notice provided pursuant to this Section 5.4(b) shall be taking into account for all other purposes of this Agreement.

Section 5.5 Disclosure Schedules. From time to time up to the earlier of the date that is three (3) Business Days prior to the Closing Date and the termination of this Agreement pursuant to Article XI, each Party shall have the right to supplement or amend the Schedules attached hereto (other than Schedule 5.1) that it has delivered to disclose any matter that (a) of which such Party did not have Knowledge on the Execution Date after reasonable due diligence with respect thereto or (b) arises subsequent to the Execution Date, which fact shall be certified by an officer of such Party. To the extent, in the aggregate, that any such supplements and/or amendments result in a Seller Material Adverse Effect (in the case of supplements and/or amendments by Seller) or a Buyer Material Adverse Effect (in the case of supplements and/or amendments by Buyer), such supplements and/or amendments shall not have the effect of modifying this Agreement for purposes of determining the satisfaction of the conditions set forth in Sections 6.2(a) and 6.2(b) (in the case of supplements and/or amendments by Seller) or in Sections 6.1(a) and 6.1(b) (in the case of supplements and/or amendments by Buyer), but shall have the effect of modifying this Agreement for all other purposes (including for purposes of Article X). To the extent, in the aggregate, that any such supplements and/or amendments that relate to clause (b) of the first sentence of this Section 5.5 do not result in a Seller Material Adverse Effect (in the case of supplements and/or amendments by Seller) or a Buyer Material Adverse Effect (in the case of supplements and/or amendments by Buyer), such supplements and/or amendments shall have the effect of modifying this Agreement for all purposes (including for purposes of Articles VI and X). Notwithstanding the foregoing, any supplements and/or amendments to the Schedules as a result of any action taken or not taken in accordance with Section 5.1 shall not be taken into consideration in determining whether a Seller Material Adverse Effect has occurred.

Section 5.6 Tax Matters.

(a) Transfer Taxes. All excise, sales, use, purchase, stamp, transfer, documentary, filing, registration, recordation, value added and other similar Taxes and fees, if any, that are imposed on or with respect to the purchase and sale of the Assets (collectively, “Transfer Taxes”) shall be borne solely by Buyer. The Parties shall cooperate to the extent reasonably requested by the other Party in connection with the qualification for, and obtainment of, any exemption with respect to Transfer Taxes.

(b) Property Taxes and Income Taxes. Until the first (1st) anniversary of the Closing, except to the extent already taken into account by the Parties in the determination of the Adjusted Cash Purchase Price, Seller shall retain responsibility for, pay, indemnify and hold harmless Buyer and its Affiliates from and against (i) all Property Taxes imposed on or with respect to the ownership and operation of the Assets for any Tax period, or portion thereof, ending on or prior to the Effective Time and (ii) Income Taxes of Seller and its Affiliates. Except to the extent already taken into account by the Parties in the determination of the Adjusted Cash Purchase Price, Buyer shall be responsible for, pay, indemnify and hold harmless Seller and its Affiliates and all of the other Seller Subject Parties from and against all Taxes other than those that are the responsibility of Seller according to the preceding sentence. For purposes of allocating Property Taxes to any portion of a Tax period under this Section 5.6(b), (A) in the case of Property Taxes that are based upon or related to income or receipts or imposed

A-37

on a transactional basis such as severance or production taxes, such allocation will be made using a closing of the books method as if the Tax period ended immediately prior to the end of the Effective Time, and (B) in the case of any other Property Taxes, such Taxes will be allocated pro-rata based on the number of days in the relevant portion of the Tax period before or after the Effective Time, as compared to the number of days in the entire Tax period. For purposes of clause (A) of the preceding sentence, any exemption, deduction, credit or other item that is calculated on an annual basis shall be allocated pro rata per day based on the number of days in the relevant portion of the Tax period as compared to the number of days in the entire Tax period. To the extent the actual amount of Taxes is not determinable at Closing (or when the Final Settlement Statement is determined), Buyer and Seller shall utilize the most recent information available in estimating the amount of Property Taxes for purposes of Sections 2.2(c)(i)(C), 2.2(c)(ii)(C), 2.3 and 2.5.

(c) Tax Cooperation. The Parties shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of Tax Returns and any audit, litigation or other proceeding with respect to Taxes relating to the Assets. Such cooperation shall include the retention and (upon another Party’s request) the provision of records and information that are relevant to any such Tax Return or audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided under this Agreement. The Parties agree that the Preferred Shares are properly classified as common stock under Section 305 of the Code and agree to report consistently with such treatment on all Tax Returns and in any audit, litigation or other proceeding, except to the extent that, as a result of a change in applicable circumstances or Law, different treatment is required by applicable Law. Further, Buyer agrees that it will not withhold any tax on any dividends (whether actual or deemed) made on the Preferred Shares provided that the holder of the Preferred Shares provides Buyer with a properly executed IRS Form W-9.

(d) Refunds. Each Party shall be entitled to any refund, credit, or offset with respect to Taxes for which such Party is responsible under this Section 5.6. If a Party receives a refund, credit, or offset to which the other Party is entitled, the Party receiving the refund, credit, or offset shall pay an amount of cash equal to the value thereof to the Party entitled to the refund, credit, or offset within thirty (30) Business Days after receipt.

Section 5.7 Governmental Bonds and Third Party Deposits. Buyer understands and acknowledges that none of the bonds, letters of credit, guarantees and deposits posted by (or on behalf of) Seller with any Governmental Authorities or any other Third Parties and relating to the Assets, other than those for which an adjustment to the Purchase Price is made pursuant to Section 2.2(c) or 2.5, are transferable to Buyer. At the Closing, Buyer shall cause all of the bonds, letters of credit, guarantees and deposits described on Schedule 5.7 to be returned to Seller.

Section 5.8 Financing.

(a) Buyer shall, and shall cause Parent and its subsidiaries to, use all commercially reasonable efforts to obtain the Financing on the terms and conditions described in the Commitment Letter, when applicable, any Alternative Financing Commitment or, when applicable, the Commitment Letter or Alternative Financing Commitment, each as amended, modified or replaced in accordance with the Financing Modification Requirements (collectively, the “Financing Commitment”), including using all commercially reasonable efforts (i) to maintain in effect the Financing Commitment and to negotiate and enter into definitive agreements with respect thereto on the terms and conditions contained in the Financing Commitment or on other terms no less favorable to Buyer, (ii) to satisfy (or cause Parent and its subsidiaries to satisfy) on a timely basis all conditions in such definitive agreements, (iii) subject to the terms and conditions contemplated in the Financing Commitment, to consummate the Financing at or prior to the Closing, (iv) to comply with its obligations under the Financing Commitment and (v) to cause the Persons providing the Financing to fund the Financing contemplated by the Financing Commitment on the Closing Date (including by enforcing its rights under the Financing Commitment). Buyer shall deliver to Seller true and complete copies of all agreements (other than any fee letters and engagement letters) pursuant to which any such alternative source shall have committed to provide Buyer with any portion of the Financing. Buyer shall give Seller prompt notice upon becoming aware of any

A-38

material breach by any party to the Financing Commitment or any termination of the Financing Commitment. Buyer shall refrain (and shall cause its subsidiaries to refrain) from taking, directly or indirectly, any action that would reasonably be expected to result in a failure of any of the conditions contained in the Financing Commitment or in any definitive agreement related to the Financing. Buyer shall not agree, without Seller’s prior written consent, to or permit any replacement, amendment, supplement or other modification of, or waive any of its rights under, all or a portion of the Financing Commitment if such replacement, amendment, supplement, modification or waiver (1) reduces the aggregate amount of the Financing Commitment, (2) imposes new or additional conditions or otherwise amends, expands or modifies any of the conditions to the Financing in any respect that could make such conditions less likely to be satisfied before the Closing or that would expand the possible circumstances under which such conditions would not be satisfied by the Closing Date, (3) can reasonably be expected to delay the Closing or the date on which the Financing would be obtained or (4) could adversely impact the ability of Buyer and its Affiliates to enforce their rights against other parties to the Financing Commitment or the definitive agreements relating to the Financing (the “Financing Modification Requirements”). In the event that the Buyer becomes aware of any event or circumstance that makes procurement of any portion of the Financing unlikely to occur in the manner or from the sources contemplated in the Commitment Letters, Buyer shall promptly notify Seller and shall use all commercially reasonable efforts to arrange as promptly as practicable, but in no event later than one day prior to the Closing Date, any such portion from alternative debt financing sources, on terms and conditions consistent with the Financing Modification Requirements (any such alternative financing actually obtained by Buyer, an “Alternative Financing Commitment”). Buyer shall keep Seller informed on a current basis of the status of its efforts to obtain the Financing, provide Seller with copies of all documents related to the Financing. Notwithstanding anything to the contrary herein, if Buyer’s inability to consummate the Financing is attributable to Seller’s failure to comply with its obligations under Sections 5.8(b)(i) and (c)(i), then, for all purposes under this Agreement, Buyer shall not be deemed in breach of the covenant in this Section 5.8(a), the representations in Section 4.10 or the covenant in Section 7.2(a)(iii) with respect to the Cash Purchase Price.

(b) Seller Financial Statements.

(i) Seller shall use all commercially reasonable efforts to deliver to Buyer, as soon as practicable but not later than August 24, 2012, an audited balance sheet of Seller as of December 31, 2011 and 2010 and audited statements of income, changes in members’ equity and cash flows for each of the years ended December 31, 2011, 2010 and 2009 (or since inception, if earlier) (collectively, the “Initial Seller Audited Financial Statements”) and an unaudited balance sheet of Seller as of June 30, 2012 and statements of income and cash flows as of and for the year-to-date periods ended June 30, 2012 and 2011 (collectively, the “Seller Unaudited Financial Statements”). The Initial Seller Audited Financial Statements and the Seller Unaudited Financial Statements shall comply with the rules and regulations of the SEC, and Seller shall use all commercially reasonable efforts to cause its independent registered public accountants to perform a SAS 100 review of the Seller Unaudited Financial Statements.

(ii) Seller shall use all commercially reasonable efforts to deliver to Buyer, as soon as practicable but not later than the sixtieth (60th) day after Closing, an audited balance sheet of Seller as of September 30, 2012 and audited statements of income, changes in members’ equity and cash flows for the nine months ended September 30, 2012 and unaudited statements of income, changes in members’ equity and cash flows for the nine months ended September 30, 2011 (collectively, the “2012 Seller Audited Financial Statements,” and together with the Initial Seller Audited Financial Statements and the Seller Unaudited Financial Statements, the “Seller Financial Statements”). The 2012 Seller Audited Financial Statements shall comply with the rules and regulations of the SEC. Notwithstanding the foregoing, the 2012 Seller Audited Financial Statements shall include an audit opinion only if required by the SEC. Buyer shall use commercially reasonable efforts to assist any auditor of the 2012 Seller Audited Financial Statements in the completion of such audit, including assistance in performing any required independence procedures.

A-39

(c) From the Execution Date until the Closing Date, Seller shall use its commercially reasonable efforts to, and shall use its commercially reasonable efforts to cause its Affiliates, subsidiaries, auditors, engineers, representatives and advisors to, provide such reasonable cooperation as may be reasonably requested by Buyer and that is customary in connection with financings comparable to the Financing, including: (i) using commercially reasonable efforts to (A) furnish to Buyer and its Financing Sources, as promptly as practicable all financial, business and other pertinent information, comfort letters, certificates and other materials reasonably required by Buyer for Buyer to produce the financial statements and other offering document information to consummate the Financing, including all financial statements (including, on a timely basis, appropriate unaudited financial statements and related management’s discussion and analysis and summary and selected financial statements), pro forma financial statements, financial and other data and information, including a description of the business, of the type and in the form required by Regulation S-X and Regulation S-K under the Securities Act and of type and in the form customarily included in an offering memorandum under Rule 144A of the Securities Act and (information required to be delivered pursuant to this clause (i) and Section 5.8(b)(i), the “Required Information”) and (B) providing Buyer and its representatives with reasonable access to the representatives, employees, properties and Books and Records of Seller and its subsidiaries or other cooperation reasonably requested by Buyer in connection with the preparation of such financial statements; provided, however, that such financial statements (including the preparation thereof) shall be the responsibility of Buyer; (ii) using commercially reasonable efforts to make senior management, representatives and advisors of Seller available to participate in a reasonable number of meetings, conference calls, presentations, due diligence sessions, drafting sessions and other in person sessions with prospective lenders, investors and rating agencies in connection with the Financing, including through a customary “road show”; (iii) using commercially reasonable efforts to assist with the preparation of (A) an offering memorandum, bank information memoranda, private placement memoranda and similar documents and other marketing materials, including “roadshow” or investor meeting slides to be used in connection with the Financing (including requesting any consents of accountants for use of their reports in any materials relating to the Financing and the delivery of one or more customary representation letters) and (B) materials for rating agency presentations; (iv) reasonably cooperating with the marketing efforts of Buyer and the Financing Sources for any portion of the Financing (including using commercially reasonable efforts to ensure that any syndication efforts benefit materially from the existing lending relationships of the Seller); (v) using commercially reasonable efforts to facilitate the pledging of Assets in connection with the Financing and the Buyer’s current financing arrangements; (vi) using commercially reasonable efforts to obtain accountants’ comfort letters and legal opinions reasonably requested by Buyer; (vii) using commercially reasonable efforts to provide to the Financing Sources all documentation and other information required by regulatory authorities with respect to Seller under applicable “know your customer” and anti-money laundering rules and regulations, including without limitation the PATRIOT Act; (viii) taking corporate actions in connection with the Closing reasonably necessary to permit the completion of the Financing; and (ix) facilitating the execution and delivery (at the Closing) of definitive documents related to the Financing as may be reasonably requested by Buyer; provided, however, that none of Seller or its Affiliates, shall be required to pay any commitment or other similar fee or incur any other liability in connection with the Financing. Buyer shall promptly, upon request by Seller, reimburse Seller for all out-of-pocket costs and expenses (including outside attorneys’ fees) incurred by Seller, in connection with the cooperation contemplated by this Section 5.8(c). All non-public information provided from one Party or its representatives to the other Party or its representatives pursuant to this Section 5.8(c) shall be kept confidential in accordance with the Confidentiality Agreement, except that Buyer shall be permitted to disclose such information regarding the Seller to potential lenders, investors or their respective agents, advisors or other representatives in connection with the Financing. Seller hereby consents to the reasonable use of its logos in connection with the Financing, provided that such logos are not used in a manner that is reasonably likely to harm or disparage Seller or its marks. To the extent practicable, Seller and its representatives shall be given a reasonable opportunity to review and comment on any written materials, documents or memoranda to be presented at any meetings conducted in connection with the Financing, and Buyer shall give due consideration to any comments proposed by Seller and its representatives. Buyer shall reimburse Seller and its Affiliates for all out of pocket costs and expenses incurred in performing its obligations under Sections 5.8(b), 5.8(c) and 5.9. Nothing in this Section 5.8(c) shall require any cooperation or other action by Seller to the extent such cooperation or action would interfere unreasonably with Seller’s business and operations.

A-40

Section 5.9 Schedule 14C.

(a) Parent shall use all commercially reasonable efforts to file with the SEC a preliminary Schedule 14C relating to the issuance of the Preferred Shares as promptly as practicable following receipt of the Seller Financial Statements and mail to Parent’s stockholders a definitive Schedule 14C relating to the issuance of the Preferred Shares as permissible under the rules and regulations of the SEC and the guidance of the staff of the SEC. Notwithstanding anything to the contrary herein, if Buyer’s inability to prepare or file the Schedule 14C or receive SEC approval of the Schedule 14C is attributable to Seller’s failure to deliver information in accordance with Sections 5.8(b) and 5.9(b), then, for all purposes under this Agreement, Buyer shall not be deemed in breach of the covenant in this Section 5.9(a).

(b) From the Execution Date until the date on which the Preferred Shares become convertible pursuant to the terms of the Certificate of Designations, Seller shall, and shall use commercially reasonable efforts to cause its Affiliates, subsidiaries, auditors, engineers, representatives and advisors to, provide such cooperation and information as may be reasonably requested by Buyer in connection with the preparation, filing and SEC review of the Schedule 14C.

Section 5.10 No Solicitation. During the Exclusivity Period, Seller shall not, and shall not authorize or permit any of its Affiliates or any of its or their representatives to, directly or indirectly, (a) encourage, solicit, initiate, facilitate or continue inquiries regarding an Acquisition Proposal, (b) enter into discussions or negotiations with, or provide any information to, any Person (other than as permitted under this Agreement and other than to Buyer or any of its Affiliates and/or its or their respective representatives) concerning a possible Acquisition Proposal or (c) enter into any agreements or other instruments (whether or not binding) regarding an Acquisition Proposal. Sellers shall immediately cease and cause to be terminated, and shall cause its Affiliates and all of its and their representatives to immediately cease and cause to be terminated, all existing discussions and negotiations with any Persons (other than Buyer and/or its Affiliates) with respect to, or that could lead to, an Acquisition Proposal. For purposes of this Agreement, an “Acquisition Proposal” means any inquiry, proposal or offer from any Person (other than Buyer and/or any of its Affiliates) relating to the direct or indirect disposition, whether by sale, merger or otherwise (other than Buyer or any of its Affiliates) of all or any portion of Seller or the Assets. Seller shall promptly, and in any case within three (3) Business Days after receipt thereof, advise Buyer orally and in writing of any Acquisition Proposal, any request for information relating to an Acquisition Proposal, or any inquiry or discussion that could reasonably be expected to lead to an Acquisition Proposal, the material terms of such Acquisition Proposal, request or discussion, and identity of the Persons involved.

Section 5.11 Employment Offers.

(a) Attached as Schedule 5.11 is a list of all of Seller’s (and/or Eagle Energy Operating Company LLC’s) field employees who provide services related to the Assets (the “Field Employees”). Schedule 5.11 includes the title, base compensation (hourly wage rate or annual salary), total annual compensation (including incentive and similar compensation), vacation time, and benefits Seller (or its Affiliates) provides to each Field Employee, including a description of the benefits under the Seller’s (and/or Eagle Energy Operating Company LLC’s) severance plan(s) and eligibility therefor (the “Seller Severance Benefits”). No later than twenty (20) days prior to Closing, Buyer will make offers to each Field Employee that include base compensation and benefits at least substantially comparable in the aggregate to the base compensation and benefits stated in Schedule 5.11 for each Field Employee (it being understood and agreed by the Parties that the foregoing shall not require Buyer to offer the Field Employees the benefits described in number 6 on Schedule 5.11) and will offer incentive compensation and other employee benefits comparable to similarly situated new hires of Buyer. Such offers (i) will require each Field Employee to accept the offer within ten (10) days of the offer being communicated to such Field Employee, (ii) will be conditioned on such Field Employee passing Buyer’s standard pre-employment screening and (iii) employment with Buyer will commence with, and be conditioned on, the occurrence of Closing. Those Field Employees who accept Buyer’s offer and commence employment with Seller will become “Transferred Field Employees.” Buyer will maintain the base compensation of the Transferred Field Employees at least equal

A-41

to the compensation provided in the Buyer’s offer of employment to the Field Employees for at least six (6) months following Closing. If Buyer terminates a Transferred Field Employee within six (6) months following the Closing and such termination would have qualified the terminated Transferred Field Employee to severance pay under either Sellers’s (or its Affiliates’) or Buyer’s severance plans, Buyer will provide to such terminated Transferred Field Employee severance pay under the Seller Severance Benefits or Buyer’s severance plans, whichever is greater.

(b) Buyer may conduct discussions and negotiations with other employees of the Seller and its Affiliates with regard to employment by Buyer, and Seller will take commercially reasonable efforts to make its employees available to representatives of Buyer. Nothing in this Agreement, whether express or implied, shall constitute (i) an obligation of Buyer to maintain the employment of any particular employee of Seller or its Affiliates, (ii) an amendment or modification to, or be construed as amending or modifying, any benefit plan, program or agreement sponsored, maintained or contributed to by Buyer or shall limit the right of the Buyer to amend, terminate or otherwise modify any such benefit plan, program or agreement. No employee of Seller or its Affiliates is intended to be a beneficiary of the provisions of this Section 5.11.

(c) Other than the specific obligations with respect to Field Employees outlined in Section 5.11(a) and, except as provided in the TSA, Buyer will not assume, and Seller agrees to retain sole responsibility for and to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged) all obligations and Liabilities, known or unknown, including any Title IV Liability, with respect to the compensation arrangements and employee benefit plans of Seller and its Affiliates, and all other liabilities with respect to the employees of Seller or its Affiliates relating to periods prior to Closing and, with respect to any employee of Seller or its Affiliates who is not a Transferred Field Employee or otherwise hired by Buyer, except as provided in the TSA, relating to any time period, whether before or after Closing.

Section 5.12 Parent Interim Covenants. Except as required by any Governmental Authority or Law and except as specifically contemplated by this Agreement, from and after the date hereof until the earlier to occur of the Closing and the termination of this Agreement in accordance with the provisions of Article XI, unless Seller shall otherwise consent in writing (which consent shall not be unreasonably withheld, conditioned or delayed), Parent shall not, and shall not permit any of its subsidiaries to, directly or indirectly, do any of the following:

(a) acquire by merging or consolidating with, by purchasing a substantial equity interest in or a substantial portion of the assets of or by any other manner, any business, corporation, partnership, association or other business organization or division thereof if such transaction would reasonably be expected to prevent or materially delay the consummation of the transactions contemplated by this Agreement;

(b) adopt or propose to adopt any amendments to its charter documents that would reasonably be expected to prevent or materially delay the consummation of the transactions contemplated by this Agreement;

(c) declare, set aside or pay any dividend or other distribution payable in cash, capital stock, property or otherwise with respect to any of its equity interests; split, combine or reclassify any of its equity interests; or combine or reclassify any of its equity interests;

(d) authorize or create, or increase the authorized amount of, any shares of any class or series of stock of Parent ranking senior to or on parity with the Series A Convertible Preferred Stock with respect to the payment of dividends, redemption or the distribution of assets upon any liquidation, dissolution or winding up of Parent;

(e) take any of the actions described in Section 4(c) of the Certificate of Designations; or

(f) take or agree in writing or otherwise to take any of the actions precluded by the foregoing provision of this Section 5.12.

A-42

Section 5.13 Maintenance of Common Shares Reserved for Issuance. From and after the date hereof until there are no Preferred Shares outstanding, Parent shall at all times reserve for issuance a sufficient number of Common Shares for issuance upon the conversion of the Preferred Shares.

Section 5.14 Hedges. Seller shall use its commercially reasonable efforts to novate any hedges relating to the Assets and in effect on the Closing Date and Buyer shall use its commercially reasonable efforts to cooperate with Seller in connection therewith; provided that all costs, expenses and fees of Buyer and Seller and each of their respective Affiliates, agents and representatives associated with any such novation shall be borne by Buyer.

Section 5.15 HSR Act. If Seller believes that issuance or delivery of any Common Shares upon any conversion of Preferred Shares hereunder held by Seller would require filings with or the approval of any governmental authority under the HSR Act, or any other U.S. federal or state antitrust laws or requirements (collectively, “Antitrust Laws”), Seller may notify Buyer of such requirement, and shall state in such notice whether Seller intends to make a filing under the HSR Act. Within ten (10) Business Days following receipt of any such notification from Seller that informs Buyer that Seller intends to make a filing under the HSR Act (the “HSR Filing”), Buyer and Seller shall each prepare and file with the Department of Justice and the Federal Trade Commission the notification and report form required with respect to such conversion by the HSR Act, and request early termination of the waiting period thereunder. In connection with the HSR Filing, Seller and Buyer shall respond promptly to any inquiries from the Department of Justice or the Federal Trade Commission concerning such filings and shall comply in all material respects with the filing requirements of the HSR Act. Seller and Buyer shall cooperate with each other and, subject to the terms of any applicable confidentiality agreements, shall promptly furnish all information to the other party that is necessary in connection with such parties’ compliance with the HSR Act in connection with the HSR Filing; provided, however, that to the extent provision of such information requires the participation or cooperation of a third party non-Affiliate of Seller or Buyer, as applicable, Seller and Buyer shall only be required to use commercially reasonable efforts to obtain such information. Seller and Buyer shall keep each other fully advised with respect to any requests from or communications with the Department of Justice or the Federal Trade Commission concerning the HSR Filing filings and shall consult with each other with respect to all responses thereto. Seller and Buyer shall use all commercially reasonable efforts to take all actions reasonably necessary in connection with the HSR Act or any other applicable Antitrust Law in order to cause any applicable waiting period to expire and any other required related governmental approval to be obtained in connection with the conversion of Preferred Shares. Seller shall be responsible for paying the fees due in connection with any HSR Filing and shall reimburse Buyer and its Affiliates for all out of pocket costs and expenses incurred in making any such filing and for otherwise performing its obligations under this Section 5.15.

ARTICLE VI

CONDITIONS PRECEDENT TO CLOSING

Section 6.1 Conditions Precedent to Seller’s Obligation to Close. The obligation of Seller to proceed with the Closing is subject to the satisfaction (or waiver in writing in whole or in part by Seller, in Seller’s sole discretion) of each of the following conditions precedent:

(a) the representations and warranties of Parent and Buyer (i) contained in Article IV of this Agreement (other than Section 4.13) shall be true and correct as of the date hereof and as of the Closing Date, with the same effect as if made at and as of such date (except to the extent expressly made as of an earlier date, in which case as of such earlier date), except where the failure of such representations and warranties to be so true and correct (without giving effect to any limitation or qualifier as to “materiality” or “Buyer Material Adverse Effect” or words of similar import set forth therein) does not have, and would not reasonably be expected to have, individually or in the aggregate, a Buyer Material Adverse Effect and (ii) contained in Section 4.13 shall be true and correct as of the date hereof and as of the Closing Date, with the same effect as if made at and as of such date (except to the extent expressly made as of an earlier date, in which case as of such earlier date);

A-43

(b) Parent and Buyer shall have performed or complied in all material respects with all covenants and obligations contained in this Agreement to be performed or complied with by Parent and Buyer prior to or at Closing;

(c) there shall be no order of any Governmental Authority having appropriate jurisdiction restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated herein;

(d) Seller shall have received (i) releases, in a form reasonably satisfactory to Buyer (that are effective or will become effective upon payment of the Eagle First Lien Payoff Amount and Eagle Second Lien Payoff Amount to the Eagle First Lien Administrative Agent and the Eagle Second Lien Administrative Agent, respectively), with respect to all Encumbrances granted pursuant to the Eagle First Lien Credit Documents and the Eagle Second Lien Credit Documents (the “Eagle Credit Document Releases”) and (ii) customary payoff letters, in a form reasonably satisfactory to Buyer, from the Eagle First Lien Administrative Agent and Eagle Second Lien Administrative Agent indicating that upon payment (in accordance with Section 7.2(a)(iii)) and receipt by it of the Eagle First Lien Payoff Amount and the Eagle Second Lien Payoff Amount, respectively, that the Eagle First Lien Credit Documents and Eagle Second Lien Credit Documents, respectively, shall be terminated in accordance with their terms (other than indemnities and other obligations that by the express terms of the Eagle Credit Documents survive the termination thereof);

(e) Buyer shall have duly adopted and filed with the Secretary of State of the State of Delaware the Certificate of Designations in the form attached hereto as Exhibit J (the “Certificate of Designations”) and such filing shall have been accepted;

(f) the NYSE shall have approved the supplemental listing application with respect to the Common Shares, and Parent shall have delivered to Seller a copy of such supplemental listing application countersigned by the NYSE and no notice of delisting from the NYSE shall have been received by Parent with respect to the Common Shares and Seller shall have received a certificate signed on behalf of Parent by an executive officer of Parent to such effect; and

(g) Parent and Buyer shall have delivered, or caused to be delivered, all of the items set forth in Section 7.2(a) that are required to be delivered by (or on behalf of) it or any of its Affiliates.

Section 6.2 Conditions Precedent to Buyer’s Obligation to Close. The obligation of Buyer to proceed with the Closing is subject to the satisfaction (or waiver in writing in whole or in part by Buyer, in Buyer’s sole discretion) of each of the following conditions precedent:

(a) the representations and warranties of Seller (i) contained in Article III of this Agreement (other than Section 3.30) shall be true and correct as of the date hereof and as of the Closing Date, with the same effect as if made at and as of such date (except to the extent expressly made as of an earlier date, in which case as of such earlier date), except where the failure of such representations and warranties to be so true and correct (without giving effect to any limitation or qualifier as to “materiality” or “Seller Material Adverse Effect” or words of similar import set forth therein) does not have, and would not reasonably be expected to have, individually or in the aggregate, a Seller Material Adverse Effect and (ii) contained in Section 3.30 shall be true and correct as of the date hereof and as of the Closing Date, with the same effect as if made at and as of such date (except to the extent expressly made as of an earlier date, in which case as of such earlier date);

(b) Seller shall have performed or complied in all material respects with all covenants and obligations contained in this Agreement to be performed or complied with by Seller prior to or at Closing;

(c) there shall be no order of any Governmental Authority having appropriate jurisdiction restraining, enjoining or otherwise prohibiting the consummation of the transactions contemplated herein;

(d) Seller shall have received the Eagle Credit Document Releases and provided complete copies thereof to Buyer;

A-44

(e) Seller shall have delivered, or caused to be delivered, the items set forth in Section 7.2(b) that are required to be delivered by (or on behalf of) it; and

(f) Seller shall have delivered, or cause to be delivered, the Acquisition Reserve Report (as defined in the Commitment Letter).

For the avoidance of doubt, Parent and Buyer acknowledge that Parent and Buyer’s obligations to consummate the transactions contemplated by this Agreement on the terms set forth herein are not conditioned upon the availability or consummation of the Financing (or any other debt or equity financing) or receipt of the proceeds therefrom and reaffirm their obligation to consummate the transactions contemplated by this Agreement irrespective and independently of the availability of the Financing, any Alternative Financing or any other debt or equity financing.

ARTICLE VII

CLOSING

Section 7.1 Closing. The sale by Seller and the purchase by Buyer of the Assets pursuant to this Agreement (the “Closing”) shall, unless otherwise agreed to in writing by the Parties, take place at the offices of Vinson & Elkins, LLP, 1001 Fannin Street, Suite 2500, Houston, Texas 77002 at 10:00 a.m. local time on October 1, 2012 if, as of such date, all of the conditions to Closing in Article VI have been satisfied (except those conditions that by their nature are to be satisfied at Closing, but subject to the satisfaction of such conditions at Closing). If all the conditions in Article VI have not then been satisfied (except those conditions that by their nature are to be satisfied at Closing, but subject to the satisfaction of such conditions at Closing) or waived by such date then the Closing shall, unless otherwise agreed to in writing by the Parties, take place on the date that is three (3) Business Days after the date such conditions have been so satisfied (except those conditions that by their nature are to be satisfied at Closing, but subject to the satisfaction of such conditions at Closing) or waived; provided, however, that if the Marketing Period has not ended at the time of the satisfaction or, to the extent permitted, waiver of conditions set forth in Article VI (other than those conditions that by their terms are to be satisfied at Closing, but subject to the satisfaction or, to the extent permitted, waiver of such conditions at Closing), the Closing shall occur on the date following the satisfaction or waiver of such conditions that is the earliest to occur of (x) a date during the Marketing Period to be specified by Buyer on no less than two (2) Business Days’ notice to Seller (it being understood that such date may be conditioned upon the simultaneous completion of the Financing) or (y) the third Business Day after the final day of the Marketing Period or (z) at such other place, time and date as shall be agreed by the Parties. The date on which the Closing occurs is referred to in this Agreement as the “Closing Date.”

Section 7.2 Closing Obligations.

(a) At the Closing, Buyer and Parent (as applicable) shall deliver the following items (all documents to be executed or acknowledged by Buyer or Parent (as applicable) will be duly executed and acknowledged, where required, by an authorized signatory of Buyer or Parent (as applicable)):

(i) the Assignments in sufficient counterparts to facilitate recording in each of the counties in which the Assets included in such Assignments are located;

(ii) assignments, on appropriate forms, of any state, federal or tribal Leases and any other Leases with Governmental Authorities in sufficient counterparts to facilitate filing with each applicable Governmental Authority;

(iii) the payments and deliverables described in Section 2.4;

A-45

(iv) a certificate duly executed by an authorized officer of Buyer, dated as of the Closing, certifying on behalf of Buyer that the conditions set forth in Sections 6.1(a) and 6.1(b) have been fulfilled;

(v) the TSA, the Access Agreement (if applicable) and the Registration Rights Agreement;

(vi) a legal opinion of Baker Botts L.L.P. to the Seller in a form reasonably acceptable to Seller, dated as of the Closing Date, regarding the issuance and authorization of the Preferred Shares and the Common Shares into which the Preferred Shares are convertible, the applicability of an exemption from registration under the Securities Act in connection with the issuance of the Preferred Shares in accordance with this Agreement and the issuance of the Common Shares upon conversion of the Preferred Shares in accordance with the Certificate of Designations;

(vii) any change of operator forms required to be filed by the Oklahoma Corporation Commission or the Kansas Corporation Commission;

(viii) a certificate of Parent’s transfer agent with respect to the Preferred Shares, evidencing a book entry position in the name of the Seller;

(ix) a copy of the Certificate of Designations, certified by the Secretary of State of Delaware; and

(x) any other agreements, instruments and documents that are required by other terms of this Agreement to be executed and/or delivered by Buyer or Parent (as applicable) at the Closing.

(b) At the Closing, Seller shall deliver the following items (all documents to be executed or acknowledged by Seller will be duly executed and acknowledged, where required, by an authorized signatory of Seller):

(i) the Assignments in sufficient counterparts to facilitate recording in each of the counties in which the Assets included in such Assignments are located;

(iii) an executed statement described in Treasury Regulation §1.1445-2(b)(2), reasonably satisfactory to Buyer, certifying that Seller (or its tax owner) is not a foreign person within the meaning of Section 1445 of the Code;

(iv) letters in lieu of transfer orders directing all purchasers of production to make payment to Buyer of proceeds attributable to production from the Assets from and after the Effective Time (which such letters in lieu will be delivered by Buyer to the purchasers of production from the Assets);

(v) a certificate duly executed by an authorized officer of Seller dated as of the Closing, certifying on behalf of Seller that the conditions set forth in Sections 6.2(a) and 6.2(b) have been fulfilled;

(vi) the TSA, the Access Agreement (if applicable) and the Registration Rights Agreement;

(vii) any change of operator forms required to be filed by the Oklahoma Corporation Commission or the Kansas Corporation Commission; and

(viii) any other agreements, instruments and documents that are required by other terms of this Agreement to be executed and/or delivered by Seller at the Closing.

A-46

Section 7.3 Records. As soon as reasonably practicable (and, in any event, no later than sixty (60) days), after the termination of the TSA in accordance with its terms, Seller shall deliver the Records to Buyer at Seller’s offices, and Buyer shall have five (5) Business Days after the first (1st) day Seller makes the Records available to Buyer to remove the Records from Seller’s offices. Seller shall have no obligation to deliver any Records to Buyer that include information relating to Excluded Assets unless Buyer requests that such information be redacted from such Records, in which case, Seller shall cause such information to be redacted (at Buyer’s sole cost and expense) from such Records and, thereafter, shall deliver such Records to Buyer. Notwithstanding the foregoing or any other provision in this Agreement to the contrary, from and after the termination of the TSA in accordance with its terms, Seller may retain a copy of any or all of the Records.

ARTICLE VIII

TITLE MATTERS

Section 8.1 General Disclaimer of Title Warranties and Representations. Except for the Buyer’s remedies for breach by Seller of Section 5.1 (collectively, the “Title Liabilities”), Seller makes no warranty or representation, express, implied, statutory or otherwise pursuant to this Agreement, the Assignment or any other Operative Document, with respect to Seller’s title to any of the Assets, and Buyer hereby acknowledges and agrees that, except for the Title Liabilities, Buyer’s sole and exclusive remedy for any defect of title, including any Title Defect, with respect to any of the Assets (other than any Title Liabilities) shall be as set forth in this Article VIII. Without limiting the generality of the foregoing, except for the Title Liabilities, (i) the provisions of Article X shall not apply with respect to any defect in title (including any Title Defect) to any of the Assets or any breach of any representation, warranty or covenant relating to or affecting title (including any Title Defect) to any of the Assets, (ii) this Article VIII shall, to the fullest extent permitted by Law, be the exclusive right and remedy of Buyer with respect to Title Defects or other deficiency in title to any Asset and (iii) except as provided in this Article VIII, Buyer releases, remises and forever discharges Seller, its Affiliates and all of the other Seller Subject Parties from any and all Claims whatsoever, whether in law or in equity, known or unknown, or otherwise, which Buyer might now or subsequently may have, based on, relating to or arising out of, any Title Defect or other deficiency in title to any Asset.

Section 8.2 Notice of Title Defects; Defect Adjustments.

(a) Title Defect Notices. On or before the Title Defect Claim Date, Buyer may deliver claim notices to Seller meeting the requirements of this Section 8.2(a) (collectively the “Title Defect Notices,” and each individually a “Title Defect Notice”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Title Defects and which Buyer intends to assert as a Title Defect pursuant to this Article VIII. For all purposes of this Agreement, except as provided in Section 8.1, but otherwise notwithstanding anything herein to the contrary, Buyer shall be deemed to have waived, and neither Seller, its Affiliates nor any of the other Seller Subject Parties shall have any liability for, any Title Defect that Buyer fails to assert as a Title Defect by a Title Defect Notice received by Seller on or before the Title Defect Claim Date. To be effective, each Title Defect Notice shall be in writing, and shall include (i) a description of the alleged Title Defect(s), (ii) a description of the Asset(s) affected by the Title Defect (each a “Title Defect Property”), (iii) the Allocated Value of each Title Defect Property, (iv) supporting documents available to Buyer reasonably necessary for Seller to verify the existence of the alleged Title Defect(s) and (v) the amount by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations upon which Buyer’s belief is based.

(b) Title Benefit Notices. Seller shall have the right, but not the obligation, to deliver to Buyer on or before the Title Defect Claim Date a notice setting forth any matters that in Seller’s reasonable opinion constitute Title Benefits and which Seller intends to assert as Title Benefits pursuant to this Article VIII (each, a “Title Benefit

A-47

Notice”). For all purposes of this Agreement and notwithstanding anything herein to the contrary, Seller shall be deemed to have waived, and Buyer shall have no liability for, any Title Benefit that Seller fails to assert as a Title Benefit by a Title Benefit Notice received by Buyer on or before the Title Defect Claim Date. To be effective, each Title Benefit Notice shall be in writing and shall include (i) a description of the alleged Title Benefit, (ii) the Asset(s) affected by the Title Benefit (each a “Title Benefit Property”), (iii) the Allocated Value of each Title Benefit Property, (iv) supporting documents available to Seller reasonably necessary for Buyer to verify the existence of the alleged Title Benefit and (v) the amount by which Seller reasonably believes the Allocated Value of each Title Benefit Property is increased by the Title Benefit and the computations upon which Seller’s belief is based.

(c) Seller’s Right to Cure. Seller shall have the right, but not the obligation, to attempt, at its sole cost, to cure at any time prior to the date that is one-hundred twenty (120) days after the Closing (the “Cure Period”), any Title Defects of which it has timely received a Title Defect Notice from Buyer; provided, however, that if after pursuit of other remedies reasonably available to Seller to cure any such Title Defect, Seller reasonably believes that such Title Defect can be cured through a quiet title or similar proceeding, then the Cure Period with respect to such Title Defect shall be extended to the lesser of the conclusion of such proceeding or eighteen (18) months following Seller’s receipt of a Title Defect Notice with respect thereto, notwithstanding Seller’s previous attempt to cure such Title Defect without the use of a quiet title or similar proceeding, so long as Seller, at its sole cost and expense, initiates the quiet title or similar proceeding on or before the end of the Cure Period and diligently pursues such proceeding.

(d) Remedies for Title Defects. Subject to Seller’s continuing right to dispute the existence of a Title Defect and/or the Title Defect Amount asserted by Buyer with respect thereto, in the event that any Title Defect timely asserted by Buyer in accordance with Section 8.2(a) is not waived in writing by Buyer or cured on or before the Closing Date, then, subject to the provisions of Section 8.2(h), Seller shall, at its sole option, elect to:

(i) reduce the Purchase Price by an amount determined pursuant to Section 8.2(f) as being the value of such Title Defect Amount;

(ii) exercise its right to attempt to cure (in whole or in part) the Title Defect pursuant to Section 8.2(c);

(iii) retain the entirety of the Well, Future Well or Undeveloped Leases (and the related Assets), as the case may be, that is adversely affected by such Title Defect if the Title Defect Amount asserted by Buyer with respect thereto is greater than fifty percent (50%) of the Allocated Value of the Well, Future Well or Undeveloped Leases (and the related Assets), in which event, (A) if this election is made prior to the Closing, the Purchase Price shall be adjusted downward by an amount equal to the Allocated Value of such Title Defect Property, such Title Defect Property shall not be assigned by Seller to Buyer at Closing and such Title Defect Property shall no longer be included within the definition of Assets for any purpose under this Agreement and (B) if this election is made following the Closing, then Seller and Buyer shall jointly instruct the Escrow Agent to release from the Title Dispute Escrow Amount, a number of Preferred Shares with an aggregate Liquidation Preference equal to the Title Defect Amount previously asserted by Buyer with respect to such Title Defect Property (less an amount equal to the net proceeds received by Buyer with respect to such Title Defect Property) and Buyer shall assign such Title Defect Property to Seller (pursuant to an assignment substantially in the form of the Assignment) contemporaneously with the releases of such Preferred Shares from escrow; or

(iv) if applicable, terminate this Agreement pursuant to Section 11.1(d).

(e) Remedies for Title Benefits. Title Benefit Amounts finally determined in accordance with Section 8.2(g) or 8.2(i), as applicable, may be used exclusively to offset Title Defect Amounts that exceed the Individual Title Defect Threshold in accordance with Section 8.2(h)(ii).

A-48

(f) Title Defect Amount. The Title Defect Amount resulting from a Title Defect shall be the amount by which the Allocated Value of the Title Defect Property is reduced as a result of the existence of such Title Defect and shall be determined in accordance with the following terms and conditions:

(i) if Buyer and Seller agree in writing on the Title Defect Amount, then that amount shall be the Title Defect Amount;

(ii) if the Title Defect is an Encumbrance that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(iii) if the Title Defect represents a discrepancy between (A) the actual Net Acres for any Undeveloped Lease and (B) the Net Acres for such Undeveloped Lease stated on Exhibit A, then the Title Defect Amount shall be the product obtained by multiplying the Allocated Value for such Undeveloped Lease set forth on Exhibit A by a fraction, the numerator of which is the Net Acre decrease for such Undeveloped Lease and the denominator which is the Net Acres for such Undeveloped Lease stated on Exhibit A; provided that if the Title Defect does not affect such Undeveloped Lease throughout the life of such Undeveloped Lease, then the Title Defect Amount determined under this Section 8.2(f)(iii) shall be reduced to take into account the applicable time period only;

(iv) if the Title Defect represents a discrepancy between (A) Seller’s Net Revenue Interest for any Well or Future Well, as applicable, and (B) the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, then the Title Defect Amount shall be the product of (x) the Allocated Value of such Well or Future Well, as applicable, multiplied by (y) a fraction, the numerator of which is the absolute value of such Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable; provided that if the decreased Net Revenue Interest does not affect the Well or Future Well, as applicable, throughout the life of the Well or Future Well, as applicable, then the Title Defect Amount determined under this Section 8.2(f)(iv) shall be reduced to take into account the applicable time period only;

(v) if the Title Defect represents an obligation, Encumbrance upon or other defect in title with respect to the Title Defect Property of a type not described above, then the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation; provided, however, that if such Title Defect is reasonably capable of being cured, the Title Defect Amount shall not be greater than the lesser of (A) the reasonable cost and expense of curing such Title Defect and (B) the Allocated Value attributable to the Title Defect Property;

(vi) the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs, losses or amounts included in another Title Defect Amount pertaining to such Title Defect Property hereunder; and

(vii) notwithstanding anything to the contrary in this Article VIII, the aggregate Title Defect Amounts attributable to the effects of all Title Defects under this Article VIII, upon any Title Defect Property, shall not exceed the Allocated Value attributable to such Title Defect Property.

(g) Title Benefit Amount. The Title Benefit Amount resulting from a Title Benefit shall be the amount by which the Allocated Value of the Title Benefit Property is increased as a result of the existence of such Title Benefit and shall be determined in accordance with the following terms and conditions:

(i) if Buyer and Seller agree in writing on the Title Benefit Amount, then that amount shall be the Title Benefit Amount;

A-49

(ii) if the Title Benefit represents a discrepancy between (A) the actual Net Acres for any Undeveloped Lease and (B) the Net Acres for such Undeveloped Lease stated on Exhibit A, then the Title Benefit Amount shall be the product obtained by multiplying the Allocated Value for such Undeveloped Lease set forth on Exhibit A by a fraction, the numerator of which is the Net Acre increase for such Undeveloped Lease and the denominator of which is the Net Acres for such Undeveloped Lease stated on Exhibit A; provided that if the Title Benefit does not affect such Undeveloped Lease throughout the life of such Undeveloped Lease, then the Title Benefit Amount determined under this Section 8.2(g)(ii) shall be reduced to take into account the applicable time period only;

(iii) if the Title Benefit represents a discrepancy between (A) Seller’s Net Revenue Interest for any Well or Future Well, as applicable, and (B) the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable, then the Title Benefit Amount shall be the product of (x) the Allocated Value of such Well or Future Well, as applicable, multiplied by (y) a fraction, the numerator of which is the absolute value of such Net Revenue Interest increase and the denominator of which is the Net Revenue Interest set forth on Exhibit A for such Well or Future Well, as applicable; provided that if the increased Net Revenue Interest does not affect the Well or Future Well, as applicable, throughout the life of the Well or Future Well, as applicable, then the Title Benefit determined under this Section 8.2(g)(iii) shall be reduced to take into account the applicable time period only;

(iv) if the Title Benefit with respect to the Title Benefit Property is of a type not described above, the Title Benefit Amount shall be determined by taking into account the Allocated Value of the Title Benefit Property, the portion of the Title Benefit Property affected by the Title Benefit, the legal effect of the Title Benefit, the economic effect of the Title Benefit over the life of the Title Benefit Property, the values placed upon the Title Benefit by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation; and

(v) The Title Benefit Amount with respect to a Title Benefit Property shall be determined without duplication of any benefit included in another Title Benefit Amount pertaining to such Title Benefit Property.

(h) Limits on Liability for Title Benefit and Title Defects.

(i) Notwithstanding anything to the contrary contained in this Agreement, in no event shall there be any adjustments to the Purchase Price (or any other remedies provided) under this Agreement in respect of Title Defects, and neither Seller (nor any of the other Seller Subject Parties) shall be responsible for any individual Title Defect, (i) for which the Title Defect Amount does not exceed Fifty Thousand Dollars ($50,000) (the “Individual Title Defect Threshold”) and (ii) for any Title Defect exceeding the Individual Title Defect Threshold unless, and subject to Section 8.2(h)(iii), (A) the sum of (1) all Title Defect Amounts (excluding any Title Defect Amounts attributable to Title Defects cured by Seller or with respect to which Seller elects to cure pursuant to Section 8.2(c)) that each individually exceed the Individual Title Defect Threshold, (2) all Remediation Amounts that each individually exceed the Individual Environmental Threshold and (3) all Buyer Losses (excluding the Buyer De Minimis Liabilities) incurred by the Buyer Indemnified Parties, exceeds (B) the Buyer Basket, after which point Buyer shall be entitled to adjustments to the Purchase Price or other remedies hereunder only with respect to Title Defects that are attributable to such Title Defect Amounts in excess of the Buyer Basket but that do not exceed the Title Dispute Escrow Amount.

(ii) Notwithstanding anything to the contrary contained in this Agreement, in no event shall there be any remedies provided under this Agreement in respect of Title Benefits, and neither Buyer (nor any of the other Buyer Subject Parties) shall be responsible for any individual Title Benefit, (i) for which the Title Benefit Amount does not exceed Fifty Thousand Dollars ($50,000) (the “Individual Title Benefit Threshold”) and (ii) for any Title Benefit exceeding the Individual Title Benefit Threshold unless, and subject to Section 8.2(h)(iii), the sum of all Title Benefit Amounts that each individually exceed the Individual Title Benefit Threshold exceeds the Buyer Basket, after which point Seller shall be entitled to remedies hereunder only with respect to Title Benefits that are attributable to such Title Benefit Amounts in excess the Buyer Basket.

A-50

(iii) Notwithstanding the foregoing or anything to the contrary set forth herein, the amount of any Title Benefit Amounts with respect to which Seller is entitled to a remedy pursuant to Section 8.2(h)(ii) shall be credited against any Title Defect Amounts with respect to which Buyer is entitled to a remedy pursuant to Section 8.2(h)(i). In the event the aggregate amount of any Title Benefit Amounts with respect to which Seller is entitled to a remedy pursuant to Section 8.2(h)(ii) (A) equals or exceeds the aggregate Title Defect Amounts with respect to which Buyer is entitled to a remedy pursuant to Section 8.2(h)(i), neither Party shall be entitled to any adjustment to the Purchase Price (or any other remedy hereunder) with respect to any Title Defect Amounts or Title Benefit Amounts and (B) is less than the aggregate Title Defect Amounts with respect to which Buyer is entitled to a remedy pursuant to Section 8.2(h)(i), except to the extent of the offset against Title Defect Amounts described in the first sentence of this Section 8.2(h)(iii), Seller shall not be entitled to any adjustment to the Purchase Price (or any other remedy hereunder) with respect thereto. Notwithstanding anything to the contrary set forth herein, neither Buyer nor Seller shall have any remedy under this Agreement with respect to any Title Defect or Title Benefit, as applicable, in excess of the Title Defect Amount or Title Benefit Amount claimed by it in the Title Defect Notice or Title Benefit Notice submitted by it to the other Party pursuant to Section 8.2(a) or 8.2(b), as applicable.

(i) Title Dispute Resolution. Seller and Buyer shall attempt to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts no later than three (3) Business Days prior to the Closing Date. If Seller and Buyer fail to agree in writing by such time, each Title Defect, Title Benefit, Title Defect Amount and Title Benefit Amount in dispute shall be exclusively and finally resolved pursuant to this Section 8.2(i). There shall be a single arbitrator, who shall be a title attorney experienced in oil and gas titles involving properties in the regional area in which the Title Defect Properties are located (the “Title Arbitrator”). The Title Arbitrator shall be selected by mutual written agreement of Buyer and Seller within fifteen (15) Business Days after the Closing Date, and absent such agreement, by the Houston, Texas office of the AAA. The place of arbitration shall be Houston, Texas and the arbitration shall be conducted in accordance with the Rules, to the extent such Rules do not conflict with the terms of this Article VIII. In addition to being bound by and adhering to the Rules and practices of the AAA and Law on arbitrator neutrality, the Title Arbitrator shall not have worked as an employee or outside counsel for any Party or its Affiliates during the five (5) year period preceding the arbitration or have any financial interest in the dispute. The Title Arbitrator’s determination shall be made within twenty (20) days after the closing of the hearing and shall be final and binding upon both Parties, without right of appeal. In making his determination, the Title Arbitrator shall be bound by the rules set forth in this Article VIII and the Rules. The Title Arbitrator, however, may not award Buyer a greater Title Defect Amount than the Title Defect Amount claimed by Buyer in the applicable Title Defect Notice, nor a lower Title Defect Amount than the Title Defect Amount proposed by Seller in its response to such Title Defect Notice, and may not award Seller a greater Title Benefit Amount than the Title Benefit Amount claimed by Seller in the applicable Title Benefit Notice or a lower Title Benefit Amount proposed by Buyer in response to the Title Benefit Notice. The Title Arbitrator shall determine the specific disputed Title Defect, Title Benefit, Title Defect Amount and/or Title Benefit Amount that is the subject of the arbitration and may not award damages, interest or penalties to either Party with respect to any other matter. Each of Seller and Buyer shall bear its own legal fees and other costs of presenting its case. Seller and Buyer shall each bear one-half of the costs and expenses of the Title Arbitrator. Within ten (10) days after the Title Arbitrator delivers written notice to Buyer and Seller of any award with respect to a Title Defect Amount or a Title Benefit Amount, to the extent such Title Defect Amount or Title Benefit Amount would otherwise be required to be paid by one Party to the other Party pursuant to the terms of this Article VIII, Buyer shall pay to Seller the awarded Title Benefit Amount and, in the case of Title Defect Amounts, Seller shall instruct the Escrow Agent to release from the Title Dispute Escrow Amount to Buyer an amount of Preferred Shares with an aggregate Liquidation Preference equal to the awarded Title Defect Amount. If the Title Defect Amount ultimately determined by the Title Arbitrator or the Parties with respect to the Title Defect is less than the Title Defect Amount claimed by Buyer in the Title Defect Notice applicable thereto, then within the aforesaid ten (10) day period, Buyer and Seller shall jointly instruct the Escrow Agent to release to Seller from the Title Dispute Escrow Amount a number of Preferred Shares with an aggregate Liquidation Preference equal to the amount by which the Title Defect Amount claimed by Buyer in the applicable Title Defect Notice exceeds such awarded Title Defect Amount.

A-51

(j) Recourse Against Escrowed Funds.

(i) Buyer, on behalf of itself and all other Buyer Indemnified Parties, acknowledges and agrees that the Title Dispute Escrow Amount shall be the sole and exclusive source of satisfaction of all (and neither Seller nor its Affiliates nor any other Seller Subject Parties shall under any circumstance have any personal liability or obligation for the satisfaction of any) (A) Title Defects properly asserted by Buyer (and with respect to which, after giving effect to the provisions of this Article VIII Buyer is entitled to a remedy) pursuant to this Article VIII and (B) breaches by Seller of Article VIII (collectively, “Title Matters”). The Title Dispute Escrow Amount shall be used solely to satisfy Title Matters or will be released to Seller in accordance with this Section 8.2(j).

(ii) The aggregate liability of Seller to Buyer in connection with all Title Matters shall in no event exceed the Title Dispute Escrow Amount then held in escrow under the Escrow Agreement and Buyer, on its own behalf and on behalf of each other Buyer Indemnified Party, hereby covenants forever not to assert, file, prosecute, commence, institute (or sponsor or facilitate any Person in connection with the foregoing), any complaint or lawsuit or any legal, equitable, arbitral or administrative proceeding of any nature, against Seller, any of its Affiliates or any of the other Seller Subject parties in connection with or relating to any Title Matters. If Buyer asserts a Title Defect claim under this Article VIII, Buyer shall, subject to the limitations on Seller’s liability hereunder, be entitled to be paid the Title Defect Amount determined in accordance with Section 8.2(f), solely by receiving from the Escrow Agent all or a portion of the then available Title Dispute Escrow Amount in an amount equal to such Title Defect Amount (to be comprised by an amount of Preferred Shares with an aggregate Liquidation Preference equal to the awarded Title Defect Amount). After such time as the Title Dispute Escrow Amount is exhausted or released from escrow, Buyer shall have no recourse against Seller, any of its Affiliates or any of the other Seller Subject Parties in respect of any Title Matters or for any unsatisfied Title Defect Amounts.

(iii) If Buyer asserts a Title Defect claim under this Article VIII, Buyer shall, subject to the limitations on Seller’s liability hereunder, be entitled to be paid the Title Defect Amount determined in accordance with Section 8.2(f), solely by receiving from the Escrow Agent all or a portion of the then available Title Dispute Escrow Amount in an amount equal to such Title Defect Amount (such payment to be comprised of an amount of Preferred Shares with an aggregate Liquidation Preference equal to the awarded Title Defect Amount or, if less, the then remaining amount of the Title Dispute Escrow Amount).

(iv) All (A) claims in respect of Title Defects and Title Defect Amounts asserted properly and timely by Buyer in accordance with this Agreement prior to the Title Defect Claim Date that become subject to dispute resolution in accordance with Section 8.2(i) and that are not resolved by the Title Arbitrator or the Parties and satisfied by Seller (through releases from the escrow of the Title Dispute Escrow Amount or title curative work), (B) Title Defects which Seller has elected to attempt to cure pursuant to Section 8.2(d)(ii) and for which Buyer contests the adequacy or completeness of the cure (or the remaining Title Defect Amount (if any) then applicable after taking into account the curative work) through arbitration in accordance with Section 8.2(j)(v) and (C) Title Defects which Seller has elected to attempt to cure pursuant to Section 8.2(d)(ii) and for which the Cure Period has been extended beyond the applicable Escrow Release Date, shall be deemed to be “Pending Title Claims” to the extent and for so long as, as of the applicable Escrow Release Date, any of the Escrow Amount remains in escrow pursuant to the Escrow Agreement and has not been released or exhausted. The dollar amount of all Title Defect Amounts (not to exceed, with respect to any alleged Title Defect included in any Pending Title Claim, the Title Defect Amount claimed by Buyer in the Title Defect Notice applicable thereto) claimed in good faith in respect of Pending Title Claims are hereinafter referred to as the “Pending Title Claim Amount.” On the first (1st) Business Day following the Escrow Release Date, Buyer and Seller shall jointly execute and deliver to the Escrow Agent written instructions instructing the Escrow Agent to release and deliver to Seller the then remaining balance of the Title Dispute Escrow Amount (and all earnings thereon) in excess of the (if any) Pending Title Claim Amount. The Pending Title Claim Amount will continue to be held in escrow by the Escrow Agent pursuant to the terms of the Escrow Agreement until such time as the Pending Title Claims have been fully resolved in accordance with Article VIII; provided, however, if the remaining balance of the Title Dispute

A-52

Escrow Amount at any time or from time to time thereafter exceeds the then remaining Pending Title Claim Amount, then Seller and Buyer shall promptly notify the Escrow Agent in writing that the excess amount (in an amount of Preferred Shares with an aggregate Liquidation Preference equal to such excess amount) shall be released promptly to Seller.

(v) All Title Defects which Seller has elected to attempt to cure pursuant to Section 8.2(d)(ii) for which Buyer disputes the adequacy or completeness of the cure (or the remaining Title Defect Amount (if any) then applicable after taking into account the curative work) shall be submitted to the Title Arbitrator for resolution. In making his determination the Title Arbitrator shall adhere to the applicable rules, procedures, process and provisions set forth in Section 8.2(i).

(vi) Notwithstanding anything to the contrary set forth herein, a number of Preferred Shares with an aggregate Liquidation Preference equal to the portion of the Title Dispute Escrow Amount allocable to any Title Defect (or the applicable portion thereof) with respect to which Seller elected to cure pursuant to Section 8.2(d)(ii) shall be released by the Escrow Agent to Seller promptly after such Title Defect has been cured and at the request of Seller, Buyer shall promptly instruct the Escrow Agent to release such number of Preferred Shares to Seller.

Section 8.3 Consents to Assign; Preferential Purchase Rights.

(a) Prior to Closing, Seller shall send to each holder of a Consent set forth in Part B of Schedule 3.3, a notice (in material compliance with the contractual provisions applicable to such Consent) seeking such Person’s consent to the transactions contemplated hereby. Prior to Closing, with respect to each preferential purchase right, right of first refusal or other similar right (each, a “Preferential Purchase Right”) pertaining to an Asset and the transactions contemplated hereby, including those set forth on Schedule 3.9, Seller shall send to the holder of each such Preferential Purchase Right a notice in material compliance with the contractual provisions applicable to such Preferential Purchase Right.

(b) If, prior to the Closing, any holder of a Preferential Purchase Right notifies Seller that it intends to consummate the purchase of the Asset to which its Preferential Purchase Right applies, or if the time for exercising such Preferential Purchase Right has not expired (each such Asset subject to an exercised or outstanding Preferential Purchase Right at Closing, a “Pref-Right Asset”), then such Pref-Right Asset shall be excluded from the Assets to be acquired by Buyer, and the Purchase Price shall be reduced by the Allocated Value of such Pref-Right Asset. Seller shall be entitled to all proceeds paid by a Person exercising a Preferential Purchase Right with respect to a Pref-Right Asset. If the holder of a Preferential Purchase Right applicable to a Pref-Right Asset thereafter fails to consummate the purchase of such Pref-Right Asset on or before the date that is one hundred twenty (120) days after the Closing Date (or the time for exercising such Preferential Purchase Right expires without exercise by the holder thereof), then Seller shall so notify Buyer, and Buyer shall purchase, on or before that date that is ten (10) days following its receipt of such notice of such Preferential Purchase Right being waived or the time for exercising such right has expired, such Pref-Right Asset from Seller, under the terms of this Agreement, for a price equal to the Allocated Value of such Pref-Right Asset.

(c) All Assets with respect to which any Preferential Purchase Right applicable thereto has been waived or as to which the period to exercise such right has expired prior to the Closing shall (in each case) be included in the Assets sold and conveyed to Buyer at the Closing pursuant to the provisions of this Agreement.

(d) If as of the Closing, Seller has not obtained a Consent set forth in Part B of Schedule 3.3, and the failure to obtain such Consent would cause (A) the assignment of the Assets affected thereby to Buyer to be void and/or (B) the termination of the Asset under the express terms thereof (each, a “Subject Consent Asset”) then such Subject Consent Asset shall be excluded from the Assets to be conveyed to Buyer at Closing and the Purchase Price shall be reduced by the Allocated Value of the excluded Asset. In the event that a Consent with respect to a Subject Consent Asset that was not obtained prior to the Closing Date is obtained within one hundred twenty (120) days following the Closing Date then, within ten (10) days after such Consent is obtained, Seller shall

A-53

assign to Buyer such Subject Consent Asset pursuant to an assignment in form and substance substantially similar to the Assignment, effective as of the Effective Time, and Buyer shall pay to Seller, under the terms of this Agreement, a price equal to the Allocated Value of such Subject Consent Asset (as adjusted pursuant to Section 2.6). From and after the Closing, until the earlier of the date that is one hundred twenty (120) days after Closing and the date that any Consent applicable to a Subject Consent Asset that has not been assigned to Buyer pursuant hereto is obtained, Seller shall continue to use all commercially reasonable efforts (at Buyer’s sole cost and expense) to obtain each such Consent. Except for any Subject Consent Assets, all Assets subject to any Consent that is outstanding as of the Closing shall be included in the Assets conveyed to Buyer at Closing and Buyer shall have no claim against (including no claim under this Article VIII), and Seller shall have no liability for, its failure to obtain any such Consent; provided, however, that for ninety (90) days following the Closing Date, Seller will continue, at Buyer’s sole cost and expense, to exercise commercially reasonable efforts to obtain the Consent of the holders of such unsatisfied Consent, and thereafter will provide, at Buyer’s sole cost and expense, such assistance as Buyer may reasonably require in connection with Buyer’s efforts to secure the Consent.

(e) If the Subject Consent Asset is a Contract, and Buyer is assigned the other Assets to which the Contract relates, but the Contract is not transferred to Buyer due to the unattained Consent, Seller will continue after Closing to use reasonable efforts to obtain such Consent, which the Parties acknowledge and agree shall not require Seller to pay any monies for which Buyer has not separately agreed in writing to reimburse Seller (or otherwise be responsible) so that such Contract can be transferred to Buyer upon the receipt of such Consent.

ARTICLE IX

ENVIRONMENTAL MATTERS

Section 9.1 General Disclaimer of Environmental Warranties and Representations. Except as otherwise set forth in Section 3.11, Seller makes no warranty or representation, express, implied, statutory or otherwise, pursuant to this Agreement, the Assignment or any other Operative Document with respect to compliance with or liabilities arising under or related to Environmental Laws. Buyer hereby acknowledges and agrees that Buyer’s sole and exclusive remedy for any Liabilities, Claims, Losses or obligations at law or under any agreement (including under this Agreement), in each case, arising under or related to (i) any Environmental Law, (ii) any alleged breach by Seller of either any representation or warranty in Article III (other than Section 3.11) or in any certification in the certificate delivered by Seller to Buyer at Closing pursuant to Section 7.2(b) or any covenants in this Agreement, (iii) any Environmental Condition or (iv) any breach by Seller of this Article IX ((i), (ii), (iii) and (iv) collectively, the “Article IX Environmental Liabilities”) shall be as set forth in this Article IX. Notwithstanding any other provisions of this Agreement to the contrary, (A) the provisions of Article X shall not apply or afford any remedy whatsoever with respect to any Article IX Environmental Liabilities and (B) the provisions of this Article IX, shall not limit or otherwise reduce or modify any remedy of Buyer under Article X with respect to any breach by Seller of the representation and warranty set forth in Section 3.11. This Article IX shall, to the fullest extent permitted by Law, be the sole and exclusive right and remedy of Buyer with respect to Article IX Environmental Liabilities. Except as provided in this Article IX, Buyer releases, remises and forever discharges Seller, its Affiliates and all of the other Seller Subject Parties from any and all suits, legal or administrative proceedings, Claims, demands, damages, losses, costs, liabilities, interest or causes of Action whatsoever, in law or in equity, known or unknown, which Buyer might now or subsequently may have, based on, relating to or arising out of, any Article IX Environmental Liability.

Section 9.2 Notice of Environmental Defects; Defect Adjustments.

(a) Environmental Defect Notices. On or before the Environmental Defect Claim Date, Buyer must deliver claim notices to Seller meeting the requirements of this Section 9.2(a) (as such notices may be amended or supplemented until the Environmental Defect Claim Date, collectively, the “Environmental Defect Notices,” and

A-54

each individually an “Environmental Defect Notice”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Environmental Defects and which Buyer intends to assert as an Environmental Defect pursuant to this Article IX. Except with respect to Buyer’s remedy under Article X with respect to any breach by Seller of the representation and warranty set forth in Section 3.11, for all purposes of this Agreement, Buyer shall be deemed to have waived, and neither Seller, any of the Seller Indemnified Parties nor any of the other Seller Subject Parties, shall have any liability for any Environmental Defect that Buyer fails to assert as an Environmental Defect by any Environmental Defect Notice received by Seller on or before the Environmental Defect Claim Date. To be effective, each Environmental Defect Notice shall be in writing and shall include (i) a description of the matter constituting the alleged Environmental Defect, (ii) a description of each Asset (or portion thereof) that is affected by the alleged Environmental Defect, (iii) Buyer’s reasonable assertion of the Allocated Value of the portion of the Assets affected by the alleged Environmental Defect and (iv) supporting documents reasonably necessary for Seller to verify the existence of the alleged Environmental Defect. Each Environmental Defect Notice may include a calculation of the Remediation Amount (itemized in reasonable detail) that Buyer reasonably asserts is attributable to such alleged Environmental Defect. Buyer’s calculation of the Remediation Amount included in the Environmental Defect Notice must describe in reasonable detail the Remediation proposed for the Environmental Condition that gives rise to the asserted Environmental Defect and identify all assumptions used by Buyer in calculating the Remediation Amount, including the standards that Buyer asserts must be met to comply with Environmental Laws and all assumptions used to calculate the Lowest Cost Response. Notwithstanding anything to the contrary in this Article IX, the aggregate Remediation Amounts attributable to the effects of all Environmental Defects under this Article IX upon any Asset that is affected by the alleged Environmental Defect shall not exceed the Allocated Value attributable to such Asset. To give Seller an opportunity to commence reviewing and curing Environmental Defects, Buyer agrees to use all commercially reasonable efforts to give Seller, on or before the end of each calendar week prior to the Environmental Defect Claim Date, written notice (which shall not constitute an Environmental Defect Notice) of all Environmental Defects discovered by Buyer during the preceding calendar week, which notice shall be preliminary in nature and may be supplemented prior to the Environmental Defect Claim Date; provided that failure to provide a preliminary notice of an Environmental Defect shall not prejudice Buyer’s right to assert such Environmental Defect in accordance with the terms hereunder.

(b) Remedies for Environmental Defects. Subject to Seller’s continuing right to dispute the existence of an Environmental Defect and/or the Remediation Amount asserted with respect thereto, in the event that any Environmental Defect timely asserted by Buyer in an Environmental Defect Notice in accordance with Section 9.2(a) is not waived in writing by Buyer or reasonably cured on or before the Closing Date, then Seller shall, at its sole option, elect (subject in each case, to the provisions of Section 9.2(c)) to:

(i) reduce the Purchase Price by an amount equal to the Remediation Amount of such Environmental Defect;

(ii) assume responsibility for the Remediation of such Environmental Defect; or

(iii) if applicable, terminate this Agreement pursuant to Section 11.1(d).

If Seller elects the option set forth in Section 9.2(b)(i), Buyer shall be deemed to have assumed responsibility for Remediation of such Environmental Defect and all liabilities with respect thereto. If Seller elects the option set forth in Section 9.2(b)(ii), Seller shall use all commercially reasonable efforts to diligently implement such Remediation in a manner which is consistent with the requirements of Environmental Laws and the Lowest Cost Response for the type of Remediation that Seller elects to undertake and Seller shall use all commercially reasonable efforts to implement such Remediation in a manner which is consistent with the requirements of Environmental Laws, taking into consideration Buyer’s use and operation of the Assets in a timely fashion for the type of Remediation Seller elects to undertake, and, upon advance written notice, Buyer hereby grants Seller reasonable access to the affected Assets after the Closing Date to implement and complete such Remediation in accordance with the Access Agreement and acknowledges that there shall be no reduction to the Purchase Price with respect to such Environmental Defect. Buyer agrees to cooperate with Seller in its

A-55

undertaking of any such work including by allowing use of necessary utilities and other equipment at the location in question. Seller agrees to bear its pro-rata share of any increase in Buyer’s costs of such utility that are attributable to Seller’s actions pursuant to Section 9.2(b)(ii). Upon completion of Remediation, Seller shall promptly, at its sole cost and expense and without any cost or expense to Buyer or its Affiliates, (1) close all bore holes from its Remediation in accordance with recognized industry standards, (2) repair all damage done to the Assets in connection with the Remediation and (3) remove all equipment, tools or other property brought onto the Assets in connection with the Remediation. Seller shall keep Buyer reasonably informed regarding any Remediation. In completing the Remediation, Seller shall provide Buyer with draft copies of all documents to be submitted to any Governmental Authorities regarding the Remediation and shall reasonably cooperate with Buyer to incorporate comments provided by it to Seller regarding such documents. In addition, Seller shall promptly provide Buyer with copies of any correspondence with any Governmental Authority regarding the Remediation and shall provide Buyer with the opportunity to participate in any meetings with any Governmental Authority regarding the Remediation. Seller shall be solely responsible for obtaining any Permits associated with the Remediation. Seller shall promptly remove any waste material generated during the Remediation from the Assets. Seller shall require any contractors or subcontractors entering the Assets in connection with the Remediation to provide Buyer with certificates of insurance demonstrating coverage under Commercial General Liability, Contractors Pollution Liability, and Errors and Omissions Liability insurance policies in a form reasonably acceptable to Buyer and naming Buyer as an additional insured. With respect to any provision of this Article IX that refers to any Remediation completed by Seller, Seller will be deemed to have adequately completed the Remediation (A) upon receipt of a certificate of approval or completion from the applicable Governmental Authority that the Remediation has been implemented to the extent necessary to comply with existing Laws or (B) if no certificate or approval is available under Environmental Law or upon express written consent of Buyer, upon mutual agreement of the Parties, upon receipt of a certificate from an independent, licensed professional engineer that the Remediation has been implemented to the extent necessary to comply with Environmental Laws; provided that, if the Parties cannot agree, the issue of whether the Remediation is completed shall be resolved by the dispute resolution procedures set forth in Section 9.2(d). If the Lowest Cost Response requires the implementation of institutional controls, Buyer agrees to accept all such controls and to cooperate with Seller by arranging for prompt execution and recording of all legal instruments required to implement the institutional controls.

(c) Limits on Liability for Environmental Defects. Notwithstanding anything to the contrary, (i) in no event shall there be any remedies available to Buyer under this Agreement in respect of Environmental Defects, and neither Seller, any of its Affiliates nor any of the other Seller Subject Parties shall be responsible for any individual Environmental Defect, for which the Remediation Amount does not exceed Fifty Thousand Dollars ($50,000) (the “Individual Environmental Threshold”) and (ii) in no event shall there be any remedies available to Buyer under this Agreement in respect of Environmental Defects, and neither Seller, any of its Affiliates nor any of the other Seller Subject Parties shall be responsible for any Environmental Defect, for which the Remediation Amount exceeds the Individual Environmental Threshold (excluding any Remediation Amounts attributable to Environmental Defects which Seller elects to remediate pursuant to Section 9.2(b)(ii)), unless (A) the sum of (1) all Title Defect Amounts (excluding any Title Defect Amounts attributable to Title Defects cured by Seller or with regard to which Seller elects to cure pursuant to Section 8.2(c)) that each individually exceed the Individual Title Defect Threshold, (2) all Remediation Amounts that each individually exceed the Individual Environmental Threshold (excluding any Remediation Amounts attributable to Environmental Defects which Seller elects to remediate pursuant to Section 9.2(b)(ii)) and (3) all Buyer Losses (excluding the Buyer De Minimis Liabilities) incurred by the Buyer Indemnified Parties, exceeds (b) the Buyer Basket, after which point Buyer shall be entitled to adjustments to the Purchase Price or other remedies hereunder only with respect to Environmental Defects that are attributable to such Environmental Defect Amounts in excess of the Buyer Basket but that do not exceed the Environmental Dispute Escrow Amount. The Parties agree that if the same Environmental Defect affects more than one Asset, then the Remediation Amounts for each Asset affected by such Environmental Defect shall be aggregated, without duplication of any costs or losses included in another Remediation Amount hereunder, for the purposes of determining whether the Individual Environmental Threshold has been met with respect to such Environmental Defect. Notwithstanding anything to the contrary set

A-56

forth herein, Buyer shall not have any remedy under this Agreement with respect to any Environmental Defect in excess of the Remediation Amount claimed by it in the Environmental Defect Notice submitted by it to the Seller pursuant to Section 9.2(a).

(d) Environmental Dispute Resolution.

(i) Seller and Buyer shall attempt to agree on all Environmental Defects and Remediation Amounts no later than the three (3) Business Days prior to Closing. If Seller and Buyer fail to agree in writing by such time, the Environmental Defects and/or Remediation Amounts in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 9.2(d). There shall be a single arbitrator, who shall be an environmental attorney with at least ten (10) years’ experience in environmental matters involving oil and gas producing properties in the regional area in which the affected Assets are located, as selected by mutual agreement of Buyer and Seller within fifteen (15) days after the Closing Date, and absent such agreement, by the Houston, Texas office of the AAA (the “Environmental Arbitrator”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Rules, to the extent such Rules do not conflict with the terms of this Article IX. In addition to being bound by and adhering to the Rules and practices of the AAA and applicable law on arbitrator neutrality, the Environmental Arbitrator shall not have worked as an employee or outside counsel for any Party or its Affiliates during the five (5) year period preceding the arbitration or have any financial interest in the dispute. The Environmental Arbitrator’s determination shall be made within twenty (20) days after submission of the matters in dispute and shall be final and binding upon the Parties, without right of appeal. In making his determination, the Environmental Arbitrator shall be bound by the rules set forth in this Article IX and the Rules. The Environmental Arbitrator, however, may not award Buyer a greater Remediation Amount than the Remediation Amount claimed by Buyer in its Environmental Defect Notice, nor a lower amount than the Remediation Amount proposed by Seller in its response to such Environmental Defect Notice unless the Arbitrator determines that the alleged Environmental Defect is not an Environmental Defect within the meaning of this Agreement. The Environmental Arbitrator shall act as an expert for the limited purpose of determining whether a disputed Environmental Defects exists and/or the appropriate Remediation Amounts and may not award damages, interest or penalties to either Party with respect to any matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Environmental Arbitrator. Within ten (10) days after the Environmental Arbitrator delivers written notice to Buyer and Seller of any award with respect to a Remediation Amount, and subject to this Section 9.2, Seller shall direct the Escrow Agent to release from the Environmental Dispute Escrow Amount an amount of Preferred Shares with an aggregate Liquidation Preference equal to the amount, if any, so awarded by the Environmental Arbitrator to Buyer. If the Remediation Amount ultimately determined by the Environmental Arbitrator with respect to any Environmental Defect is less than the Remediation Amount claimed by Buyer in the applicable Environmental Defect Notice with respect to such Environmental Defect, then within the aforesaid ten (10) day period, Buyer shall instruct the Escrow Agent to release from the Environmental Dispute Escrow Amount to Seller a number of Preferred Shares with an aggregate Liquidation Preference equal to the amount by which the Remediation Amount claimed by Buyer in the applicable Environmental Defect Notice exceeds such Remediation Amount.

(ii) All Environmental Defects which Seller has elected to attempt to remediate pursuant to Section 9.2(b)(ii) for which Buyer disputes the adequacy or completeness of the Remediation shall be submitted to the Environmental Arbitrator for resolution. In making his determination the Environmental Arbitrator shall adhere to the rules, procedures, process and provisions set forth in Section 9.2(d)(i).

(e) Recourse Against Escrowed Funds.

(i) Buyer, on behalf of itself and all other Buyer Indemnified Parties, acknowledges and agrees that the Environmental Dispute Escrow Amount shall be the sole and exclusive source for satisfaction of all (and neither Seller, its Affiliates nor any other Seller Subject Party shall under any circumstance have any personal liability or obligation for the satisfaction of any) (A) Environmental Defects timely asserted in an Environmental Defect

A-57

Notice delivered by Buyer to Seller in accordance with Section 9.2(a) and (B) Seller’s breach of Article IX (collectively, the “Environmental Matters”). The Environmental Dispute Escrow Amount shall be used solely to satisfy Environmental Matters or will be released to Seller in accordance with this Article IX.

(ii) The aggregate liability of Seller to Buyer in connection with all Environmental Matters shall in no event exceed the Environmental Dispute Escrow Amount and Buyer, on its own behalf and on behalf of each other Buyer Indemnified Party, hereby acknowledges and further covenants forever not to assert, file, prosecute, commence, institute (or sponsor or purposely facilitate any Person in connection with the foregoing), any complaint or lawsuit or any legal, equitable, arbitral or administrative proceeding of any nature, against Seller, its Affiliates or any of the other Seller Subject Parties in connection with or relating to any Environmental Matters or any other matter arising under any Environmental Law with respect to the operation of the Assets on or before the Closing Date. After such time as the escrowed Environmental Dispute Escrow Amount is exhausted or released from escrow, Buyer shall have no recourse against Seller, any of its Affiliates or any of the other Seller Subject Parties in respect of any Environmental Matters, for any unsatisfied Remediation Amounts or Seller’s breach of Article IX.

(iii) If a Buyer asserts a claim under this Article IX for any Environmental Matter prior to the Escrow Release Date, Buyer shall, subject to the limitations on liability hereunder, be entitled to be paid the Remediation Amount determined in accordance with Section 9.2(d), solely by receiving from the Escrow Agent an amount of the Environmental Dispute Escrow Amount equal to such Remediation Amount (or, if less, the then remaining amount of the Environmental Dispute Escrow Amount) (such payment to be comprised of an amount of Preferred Shares with an aggregate Liquidation Preference equal to the Remediation Amount or, if less the then remaining amount of the Environmental Dispute Escrow Amount).

(iv) All (A) claims in respect of Environmental Defects and Remediation Amounts asserted properly and timely by Buyer in accordance with this Agreement prior to the Environmental Defect Claim Date that become subject to dispute resolution in accordance with Section 9.2(d) and that are not resolved by the Environmental Arbitrator or the Parties and satisfied by Seller (through releases from the then escrowed Environmental Dispute Escrow Amount) prior to the Escrow Release Date and (B) Environmental Defects for which Seller has elected to assume responsibility for Remediation pursuant to Section 9.2(b)(ii) for which Buyer contests the adequacy or completeness of the Remediation through arbitration in accordance with Section 9.2(d) that are not resolved and satisfied prior to the Escrow Release Date shall be deemed to be “Pending Environmental Claims” to the extent and for so long as any of the Environmental Dispute Escrow Amount remains in escrow pursuant to the Escrow Agreement. The aggregate dollar amount claimed in good faith in respect of all Pending Environmental Claims is hereinafter referred to as the “Pending Environmental Claim Amount”. On the first (1st) Business Day following the Escrow Release Date, Buyer and Seller shall jointly execute and deliver to the Escrow Agent written instructions instructing the Escrow Agent to release and deliver to Seller, the then remaining balance of the Environmental Dispute Escrow Amount held in escrow (and all earnings thereon) in excess of the (if any) the Pending Environmental Claim Amount. An amount of the Environmental Dispute Escrow Amount equal to the Pending Environmental Claim Amount will continue to be held by the Escrow Agent pursuant to the terms of the Escrow Agreement until such time as the Pending Environmental Claims have been fully resolved and Escrow Agreement shall be deemed to be extended accordingly; provided, however, if the remaining balance of the Environmental Dispute Escrow Amount at any time or from time thereafter exceeds the then remaining Pending Environmental Claim Amount, then Seller and Buyer shall promptly notify the Escrow Agent in writing that the excess amount (in an amount of Preferred Shares with an aggregate Liquidation Preference equal to such excess amount) shall be released promptly to Seller.

(f) NORM, Wastes and Other Substances. 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

A-58

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 and other wastes or Hazardous Substances. NORM containing material and/or 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.

ARTICLE X

ASSUMPTION; INDEMNIFICATION

Section 10.1 Assumption by Buyer; Retained Obligations.

(a) Without limiting Buyer’s rights to indemnity under this Article X, from and after the Closing, Buyer assumes and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged) all obligations and Liabilities, known or unknown (other than the Retained Obligations), with respect to the Assets regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, including all obligations and Liabilities (i) relating in any manner to the use, ownership or operation of the Assets, (ii) relating in any manner to the Remediation of any Environmental Condition attributable to an Environmental Defect with respect to which Seller has elected the option set forth in Section 9.2(b)(i), (iii) to furnish makeup gas and/or settle Imbalances according to the terms of the applicable gas sales, processing, gathering or transportation Contracts, (iv) to pay owners of Working Interests, royalties, overriding royalties and other interests with respect to Hydrocarbons produced from (or attributable to) the Assets and/or the revenues or proceeds attributable to sales thereof, including those held in suspense, (v) to properly plug and abandon any and all pipelines and wells included in the Assets (including any such wells that are inactive or temporarily abandoned), (vi) to replug any well or wellbore included in the Assets, or previously plugged well or wellbore included in the Assets, (vii) to dismantle or decommission and remove any personal property, Equipment and other property of whatever kind related to or associated with operations and activities conducted by whomever on the Assets, (viii) to clean up and/or remediate the Assets in accordance with Laws and Related Contracts, (ix) to perform all obligations applicable to or imposed on the lessee, owner or operator under the Leases and the Related Contracts, or as required by Law, and (x) relating in any manner to the litigation listed in Part 1 of Schedule 3.4 (all of said obligations and Liabilities, including the payment of all Taxes, the “Assumed Obligations”).

(b) Notwithstanding anything in this Agreement to the contrary, Buyer neither assumes nor hereby agrees to fulfill, perform, pay or discharge (or cause to be fulfilled, performed, paid or discharged), and Seller agrees to retain sole responsibility for and to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged) all obligations and Liabilities, known or unknown, with respect to (i) the Excluded Assets, (ii) the litigation listed in Part 2 of Schedule 3.4, (iii) any personal injury or death arising out of Seller’s ownership or operation of the Assets prior to the Closing Date, and (iv) the liabilities and obligations described in Section 5.11(c), in each case regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time (all of said obligations and Liabilities, the “Retained Obligations”).

A-59

Section 10.2 Indemnification Obligations of Seller.

(a) Subject to the terms of Articles VIII and IX and the other terms of this Article X, from and after the Closing Date, Seller will indemnify, defend and hold harmless Buyer and its Affiliates and their respective directors, officers, employees and agents (collectively, the “Buyer Indemnified Parties”) from, against and in respect of any and all Losses arising out of or resulting from:

(i) any breach of any representation or warranty (other than any of Seller’s Fundamental Representation) made by Seller in Article III or in any certification in the certificate delivered by Seller to Buyer at Closing pursuant to Section 7.2(b); provided, however, that for purposes of determining whether any representations and warranties (other than any representations and warranties set forth in Section 3.11) have been breached, all Seller Material Adverse Effect qualifications and other materiality qualifications contained in such representations and warranties shall be disregarded;

(ii) any breach of any Fundamental Representation made by Seller in Article III or in any certification in the certificate delivered by Seller to Buyer at Closing pursuant to Section 7.2(b); provided, however, that for purposes of determining whether any representations and warranties have been breached, all Seller Material Adverse Effect qualifications and other materiality qualifications contained in such representations and warranties shall be disregarded;

(iii) any breach of any covenant, agreement or undertaking made by Seller in this Agreement; and

(iv) the Retained Obligations;

Notwithstanding any other provision of Article X in this Agreement to the contrary, Buyer shall have no rights under this Article X in respect of any Article IX Environmental Liability or in respect of Article VIII.

(b) Neither Seller (other than Seller in breach of this Agreement), its Affiliates nor any other Seller Subject Parties shall have any liability under any provision of this Agreement for any Loss to the extent that such Loss relates to any action taken by Buyer, Seller or any other Person after the Closing Date. Buyer shall take and shall cause its Affiliates to take all reasonable steps to mitigate any Loss upon becoming aware of any event which would reasonably be expected to, or does, give rise thereto.

(c) “Losses” means any and all Claims, Liabilities and damages whenever arising or incurred (including amounts paid in settlement, costs of investigation and reasonable attorneys’ fees and expenses); provided, however, that the term Losses shall exclude any consequential, punitive, special, indirect, incidental or exemplary damages or damages for lost profits or opportunity costs or damages based upon a multiple of earnings or other financial measure arising under or in connection with this Agreement or the transactions contemplated by this Agreement, except to the extent such damages constitute part of a third party claim (such items excluded from Losses, collectively, the “Excluded Losses”).

(d) The Parties acknowledge and agree that the provisions of any anti-indemnity statute relating to oilfield services and associated activities shall not be applicable to this Agreement and/or the transactions contemplated by this Agreement.

(e) The Losses of the Buyer Indemnified Parties described in this Section 10.2 as to which the Buyer Indemnified Parties are entitled to indemnification hereunder are hereinafter collectively referred to as the “Buyer Losses.”

A-60

Section 10.3 Indemnification Obligations of Buyer.

(a) Subject to the other terms of this Article X, from and after the Closing Date, Buyer will indemnify, defend and hold harmless Seller and its Affiliates and their respective directors, officers, employees and agents (collectively, the “Seller Indemnified Parties”) from, against and in respect of any and all Losses arising out of or resulting from:

(i) any breach of any representation or warranty (other than any of Buyer’s Fundamental Representation) made by Buyer in Article IV or in any certification in the certificate delivered by Buyer to Seller at Closing pursuant to Section 7.2(a); provided, however, that for purposes of determining whether any representations and warranties have been breached, all Buyer Material Adverse Effect qualifications and other materiality qualifications contained in such representations and warranties shall be disregarded;

(ii) any breach of any Fundamental Representation made by Buyer in Article IV or in any certification in the certificate delivered by Buyer to Seller at Closing pursuant to Section 7.2(a) provided, however, that for purposes of determining whether any representations and warranties have been breached, all Buyer Material Adverse Effect qualifications and other materiality qualifications contained in such representations and warranties shall be disregarded;

(iii) any breach of any covenant, agreement or undertaking made by Buyer in this Agreement; and

(iv) the Assumed Obligations.

(b) Seller shall take all reasonable steps to mitigate any Seller Losses upon becoming aware of any event which would reasonably be expected to, or does, give rise thereto.

(c) The Losses of the Seller Indemnified Parties described in this Section 10.3 as to which the Seller Indemnified Parties are entitled to indemnification hereunder are hereinafter collectively referred to as “Seller Losses.”

Section 10.4 Indemnification Procedure.

(a) Promptly after receipt by a Buyer Indemnified Party or a Seller Indemnified Party (and any other Seller Subject Parties) (hereinafter collectively referred to as an “Indemnified Party”) of notice by a third party (including any Governmental Authority) of any Actions or the commencement of any audit with respect to which such Indemnified Party may be entitled to receive payment hereunder for any Buyer Losses or any Seller Losses (as the case may be), Buyer or Seller, as applicable, shall notify Buyer or Seller, as the case may be (in such capacity, Buyer or Seller are hereinafter referred to as an “Indemnifying Party”), of such Action; provided, however, that the failure to so notify the Indemnifying Party will relieve the Indemnifying Party from liability under this Agreement with respect to such Action or audit only if, and only to the extent that, the defense of such Actions is prejudiced as a result of the failure to notify the Indemnifying Party. The Indemnifying Party will have the right, at its sole expense, upon written notice delivered to the Indemnified Party within fifteen (15) calendar days after receiving such notice, to assume the defense of such Action with counsel selected by the Indemnifying Party and reasonably satisfactory to the Indemnified Party. In the event, however, that the Indemnifying Party declines or fails to (1) assume the defense of the Action on the terms provided above or (2) employ counsel reasonably satisfactory to the Indemnified Party, in any case within such fifteen (15) day period, then such Indemnified Party may employ counsel to represent or defend it in any such Action and the Indemnifying Party will (subject to the other terms and provisions of this Agreement) pay the reasonable fees and disbursements of such counsel as incurred; provided, however, that the Indemnifying Party will not be required to pay the fees and disbursements of more than one counsel for all Indemnified Parties in any jurisdiction in any single Action. For avoidance of doubt, the fees and disbursements of counsel of any Buyer Indemnified Party in connection with a Buyer Loss shall be satisfied solely by receiving from the Escrow Agent a portion of the General Escrow Amount in an amount equal to such fees and disbursements. In any Action with respect to which indemnification

A-61

is being sought hereunder, the Indemnified Party or the Indemnifying Party, whichever is not assuming the defense of such Action, will have the right to participate in such matter and to retain its own counsel at such Party’s own expense. The Indemnifying Party or the Indemnified Party, as the case may be, will at all times use all commercially reasonable efforts to (i) diligently conduct the defense of any Action for which they are maintaining the defense and (ii) keep the Indemnified Party or the Indemnifying Party, as the case may be, reasonably apprised of the status of the defense of any Action the defense of which they are maintaining and to cooperate in good faith with each other with respect to the defense of any such Action.

(b) No Indemnified Party may settle or compromise any Claim or consent to the entry of any judgment with respect to which indemnification is being sought hereunder without the prior written consent of the Indemnifying Party, unless (A) such settlement, compromise or consent includes an unconditional release of the Indemnifying Party from all liability arising out of such Claim, (B) does not contain any admission or statement of any wrongdoing or liability on behalf of the Indemnifying Party and (C) does not contain any equitable order, judgment or term which in any manner affects, restrains or interferes with the business of the Indemnifying Party or any of the Indemnifying Party’s Affiliates. An Indemnifying Party may not, without the prior written consent of the Indemnified Party, settle or compromise any Claim or consent to the entry of any judgment with respect to which indemnification is being sought hereunder unless (i) such settlement, compromise or consent includes an unconditional release of the Indemnified Party from all liability arising out of such Claim, (ii) does not contain any admission or statement of any wrongdoing or liability on behalf of the Indemnified Party and (iii) does not contain any equitable order, judgment or term which in any manner affects, restrains or interferes with the business of the Indemnified Party or any of the Indemnified Party’s Affiliates.

(c) A Claim for indemnification by an Indemnified Party for any matter not involving an Action by a third party may be asserted by written notice from Buyer or Seller, as applicable, to the Indemnifying Party from whom indemnification is sought. Such notice will specify with reasonable specificity the basis for such Claim.

Section 10.5 Claims Period.

(a) For purposes of this Agreement, the “Claims Period” shall be the period during which a claim for indemnification under this Article X may be asserted by a Buyer Indemnified Party or a Seller Indemnified Party.

(b) With respect to any Buyer Losses arising under:

(i) Section 10.2(a)(i), the Claims Period shall begin on the Closing Date and terminate on the date that is twelve (12) months following the Closing;

(ii) Section 10.2(a)(ii), the Claims Period shall begin on the Closing Date and terminate on the date that is eighteen (18) months following the Closing;

(iii) Section 10.2(a)(iii), to the extent the covenants, agreements or undertakings referred to therein are (A) performable on or prior to Closing, the Claims Period shall begin on the Closing Date and terminate on the date that is twelve (12) months following the Closing or (B) performable after Closing, the Claims Period shall continue for the period specified with respect to such covenant or, if no such period is specified, until such covenant, agreement or undertaking is fully performed; and

(iv) Section 10.2(a)(iv), the Claims Period shall continue without limitation of time.

(i) Section 10.3(a)(i), the Claims Period shall begin on the Closing Date and terminate on the date that is twelve (12) months following the Closing;

(ii) Section 10.3(a)(ii), the Claims Period shall begin on the Closing Date and terminate on the date that is eighteen (18) months following the Closing;

A-62

(iii) Section 10.3(a)(iii), to the extent the covenants, agreements or undertakings set forth therein are (A) performable on or prior to Closing, the Claims Period shall begin on the Closing Date and terminate on the date that is twelve (12) months following the Closing and (B) performable after Closing, the Claims Period shall continue for the period specified with respect to such covenant or, if no such period is specified, until such covenant, agreement or undertaking is fully performed; and

(iv) Section 10.3(a)(iv), the Claims Period shall continue until such covenant, agreement or undertaking is fully performed.

(d) No claim for indemnity under this Agreement may be asserted against Buyer (or any of its Affiliates or any of the other Buyer Subject Parties) or Seller (or any of its Affiliates or any of the other Seller Subject Parties) after the applicable Claims Period. Notwithstanding the foregoing or any other provision to the contrary set forth in this Agreement, if, prior to the close of business on the last Business Day of the applicable Claims Period, either Party shall have been properly notified (in accordance with the provisions of Section 10.4) by the other Party of a claim for indemnity hereunder and such claim shall not have been finally resolved or disposed of as of such date and time, such claim shall continue to survive and shall remain a basis for indemnity hereunder until such claim is finally resolved or disposed of in accordance with the terms hereof.

Section 10.6 Limits of Liability. Notwithstanding anything to the contrary set forth herein, the Buyer Indemnified Parties shall not assert a claim against Seller for indemnification under Sections 10.2(a)(i) or 10.2(a)(iii) (other than, in the case of a claim for indemnification under Section 10.2(a)(iii) with respect to any covenant of Seller performable after Closing) for Buyer Losses unless the amount of such Buyer Losses exceeds Fifty Thousand Dollars ($50,000) (those Buyer Losses that do not exceed such Fifty Thousand Dollars ($50,000) threshold shall be referred to as the “Buyer De Minimis Liabilities”) and then not until (a) the sum of (i) all Title Defect Amounts (excluding any Title Defect Amounts attributable to Title Defects cured by Seller or with respect to which Seller elects to cure pursuant to Section 8.2(c)) that each individually exceed the Individual Title Defect Threshold, (ii) all Remediation Amounts that each individually exceed the Individual Environmental Threshold and (iii) all Buyer Losses (excluding the Buyer De Minimis Liabilities) incurred by the Buyer Indemnified Parties, exceeds (b) an amount equal to $15,000,000 (the “Buyer Basket”) and then the recoverable Losses shall be limited to those that exceed the Buyer Basket but that do not exceed the General Escrow Amount.

Section 10.7 Sole and Exclusive Remedy; Recourse Against Escrowed Funds.

(a) From and after the Closing, other than the remedies set forth in Articles VIII and IX, the remedies set forth in this Article X shall provide the sole and exclusive remedies arising out of, in connection with, relating to or arising under this Agreement or any certificate delivered by one Party to the other Party at Closing, whether based on contract, tort, strict liability, other laws or otherwise (other than Claims arising from actual fraud), including any breach or alleged breach of any representation, warranty, covenant or agreement made herein or any other document contemplated herein or delivered pursuant hereto. The Parties and Parent acknowledge and agree that from and after the Closing the remedies available in this Section 10.7 supersede (and each Party and Parent waives and releases) any other remedies available at law or in equity including rights of rescission, rights of contribution and Claims arising under applicable statutes.

(b) Except with respect to Claims relating to, or arising from, Buyer Losses that are subject to Section 10.2(a)(iv) (collectively, the “Section 10.2(a)(iv) Claims”), Buyer, on behalf of itself and all other Buyer Indemnified Parties, acknowledges, agrees and covenants forever that, notwithstanding anything to the contrary set forth in this Agreement:

(i) after the Closing, the General Escrow Amount shall be the sole and exclusive source of funds for satisfaction of all (and neither Seller, its Affiliates nor any other Seller Subject Parties shall under any circumstance have any personal liability or obligation for the satisfaction of any) Claims by any Buyer Indemnified Parties for any Losses, Claims or otherwise under Section 10.2, in connection with, arising out of or resulting from the subject matter of this Agreement or any of the Operative Documents and/or the transactions contemplated hereby or thereby;

A-63

(ii) hereby covenants forever it will not assert, file, prosecute, commence, institute (or sponsor or facilitate any Person in connection with the foregoing), any complaint or lawsuit or any legal, equitable, arbitral or administrative proceeding of any nature, against Seller, its Affiliates or any other Seller Subject Parties in connection with any Claims or Losses (including those set forth in Section 10.2) in connection with, arising out of or resulting from the subject matter of this Agreement or any of the Operative Documents; and/or the transactions contemplated hereby or thereby in excess of the General Escrow Amount; and

(iii) from and after such time as the General Escrow Amount is exhausted or fully released, no Buyer Indemnified Party shall be entitled to seek indemnity under this Agreement or otherwise and no Buyer Indemnified Party shall have any recourse against Seller, any of its Affiliates or any other Seller Subject Parties for any Claims, unpaid Losses or otherwise (including those set forth in Section 10.2) in connection with, arising out of or resulting from the subject matter of this Agreement or any of the Operative Documents and/or the transactions contemplated hereby or thereby.

(c) Notwithstanding anything to the contrary set forth herein, none of Seller, its Affiliates or any of the other Seller Subject Parties shall have any liability or obligation for any Claims or Losses (including those set forth in Section 10.2 in connection with, arising out of or resulting from the subject matter of this Agreement or any of the Operative Documents and/or the transactions contemplated hereby or thereby and including any Section 10(2)(a)(iv) Claims) of Buyer or any other Buyer Indemnified Party or otherwise to Buyer or any other Buyer Indemnified Party with respect to any such Claims or Losses in excess of the Adjusted Cash Purchase Price.

(d) If a Buyer Indemnified Party asserts an indemnity claim under this Article X during the Escrow Claims Period, the Buyer Indemnified Party shall be entitled to indemnification by Seller in accordance with this Article X solely by receiving from the Escrow Agent all or a portion of the Escrow Amount in an amount of Preferred Shares with an aggregate Liquidation Preference equal to the amount of such indemnity claim.

(e) All Claims asserted by a Buyer Indemnified Party pursuant to this Article X during the applicable Escrow Claims Period that are not resolved and satisfied during such Escrow Claims Period (including the obligation to pay any such indemnity claim) shall be deemed to be “Pending Article X Claims.” The dollar amount of all Losses claimed in good faith in respect of Pending Article X Claims are hereinafter referred to as the “Pending Article X Claim Amount.”

(f) On the Escrow Release Date, Buyer and Seller shall jointly execute and deliver to the Escrow Agent written instructions instructing the Escrow Agent to release and deliver to Seller the remaining balance of the General Escrow Amount (and all earnings thereon) in excess of the Pending Article X Claim Amount (if any). From and after the Escrow Release Date, the Pending Article X Claim Amount will continue to be held by the Escrow Agent pursuant to the terms of the Escrow Agreement until all Pending Article X Claims have been resolved by the Parties in writing or in a court of competent jurisdiction. Except as provided herein with respect to Section 10.2(a)(iv) Claims, at and after such time as the Escrow Amount is exhausted or released, the Buyer Indemnified Parties shall not be entitled to seek indemnity under this Agreement or otherwise, and the Buyer Indemnified Parties shall have no recourse against Seller, any of its Affiliates or any other Seller Subject Parties for any unpaid Losses or otherwise in respect of any Section 10.7 Claim or this Agreement.

(g) Buyer, on behalf of itself and all other Buyer Indemnified Parties hereby waives all breaches of representations and warranties of Seller of which Buyer has Knowledge as of the date hereof, and Seller shall have no liability with respect thereto.

Section 10.8 Compliance with Express Negligence Rule. ALL RELEASES, LIMITATIONS ON LIABILITY AND INDEMNITIES CONTAINED IN THIS AGREEMENT, INCLUDING THOSE IN THIS ARTICLE X, SHALL APPLY IN THE EVENT OF THE SOLE, JOINT AND/OR CONCURRENT NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF THE PARTY WHOSE LIABILITY IS RELEASED, DISCLAIMED, LIMITED OR INDEMNIFIED.

A-64

Section 10.9 Insurance Proceeds. The Buyer Losses and Seller Losses giving rise to any Claim hereunder shall be reduced by any insurance proceeds or other payments actually received by the Indemnified Party in satisfaction of any Losses giving rise to the Claim. Buyer shall use all commercially reasonable efforts to recover under insurance policies or under other rights of recovery for Losses prior to seeking payment (including indemnification) under this Agreement.

Section 10.10 Tax Benefits. The amount of any Buyer Losses and Seller Losses giving rise to any Claim hereunder shall be reduced to the extent of any Tax savings or benefits realizable by any Indemnified Party that is attributable to any deduction, loss, credit or other tax benefit resulting from or arising out of such Loss.

Section 10.11 Adjustment to Purchase Price.

(a) For all Tax purposes, the Parties agree to treat (and will cause each of their respective Affiliates to treat) any indemnification payment made under this Article X as an adjustment to the Purchase Price unless otherwise required by Law.

(b) Notwithstanding anything to the contrary contained in this Agreement, the Parties agree that the indemnification provisions set forth in this Agreement shall not apply to any Claims or Losses to the extent such Claims or Losses are accounted for in any adjustments to the Purchase Price made pursuant to Section 2.2 or 2.5.

Section 10.12 Disclaimer.

(a) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE III, AND WITHOUT LIMITING THE GENERALITY OF SECTIONS 8.1 AND 9.1, (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 BUYER AFFILIATE, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER OR ANY BUYER AFFILIATE BY ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLER OR ANY SELLER AFFILIATE).

(b) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE III, AND WITHOUT LIMITING THE GENERALITY OF SECTIONS 8.1, 9.1 AND 10.1, 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 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 GENERATED BY THE ASSETS, (V) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (VI) THE CONDITION, QUALITY, SUITABILITY OR MARKETABILITY OF THE ASSETS, INCLUDING THE MARKETABILITY OF ANY HYDROCARBONS, (VII) THE AVAILABILITY OF GATHERING OR TRANSPORTATION FOR HYDROCARBONS, (VIII) 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 AND (IX) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ANY BUYER AFFILIATE, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO. EXCEPT AS AND TO THE EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE III, SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY,

A-65

FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT, EXCEPT AS AND TO THE EXTENT OTHERWISE PROVIDED IN ARTICLE III, 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 AND TO THE EXTENT EXPRESSLY SET FORTH IN SECTION 3.11, SELLER HAS NOT MADE 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 SUBJECT TO SELLER’S REPRESENTATIONS IN SECTION 3.11, BUYER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION.

(d) SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION 10.12 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

ARTICLE XI

TERMINATION; SPECIFIC PERFORMANCE

Section 11.1 Grounds for Termination. Subject to Section 11.2, this Agreement may be terminated (except for the provisions referenced in Section 11.2 below) at any time prior to Closing upon the occurrence of any one or more of the following:

(a) by the mutual written agreement of the Parties;

(b) by either Party (the “Terminating Party”) by giving written notice to the other Party, if the other Party has breached (or is in breach) of this Agreement, which breach would give rise to a failure of a condition set forth in Article VI to be satisfied and is not cured by such breaching Party by the Outside Date; provided, however, that neither Seller nor Buyer shall be entitled to terminate this Agreement under this Section 11.1(b) if at the time such termination right is exercised, such Terminating Party is in breach of this Agreement and such breach would give rise to a failure of a condition set forth in Article VI to be satisfied.

(c) by either Party (by giving written notice to the other Party), if Closing has not occurred by November 30, 2012 (the “Outside Date”); and

(d) by either Party (by giving written notice to the other Party), if the sum of (i) all Title Defect Amounts that have been agreed to in writing by the Parties prior to the Closing or determined prior to the Closing in accordance with Section 8.2(i), plus (ii) all Remediation Amounts that have been agreed to in writing by the Parties prior to the Closing or determined prior to the Closing in accordance with Section 9.2(d), plus (iii) the sum of all Title Defect Amounts and Remediation Amounts claimed by Buyer pursuant to Sections 8.2(a) and 9.2(a), respectively (and which are not otherwise included in clauses (i) and/or (ii) of this Section 11.1(d)), equals twenty percent (20%) or more of the Cash Purchase Price.

A-66

Section 11.2 Effect of Termination.

(a) If this Agreement is terminated in accordance with Section 11.1 other than as a result of a Willful and Material Breach, such termination shall be without liability for damages to either Party, except with respect to any Party who has breached its obligations under this Agreement and except that Article I, Article XI, and Sections 3.15, 4.12, 12.1, 12.3, 12.4, 12.5, 12.6, 12.7, 12.8, 12.9, 12.10, 12.11, 12.12, 12.14, 12.15, 12.18 and 12.20 shall survive termination of this Agreement.

(b) In the event of a Willful and Material Breach as a result of which this Agreement is terminated in accordance with Section 11.1, the Terminating Party may, subject to Section 12.18, seek any remedy available at law or equity; provided, however, that in the event of a Willful and Material Breach that constitutes a Closing Failure as a result of which this Agreement is terminated in accordance with Section 11.1, the Terminating Party may elect to collect $65,000,000 from the breaching Party as liquidated damages in lieu of pursuing actual damages, which amount shall be payable within three Business Days after such termination in U.S. Dollars to an account designated in writing by the non-Terminating Party.

(c) The provision for payment of liquidated damages in Section 11.2(b) has been included because, in the event this Agreement is terminated in accordance with Section 11.1 because of a Willful and Material Breach by a Party that constitutes a Closing Failure, the actual damages to be incurred by the terminating Party can reasonably be expected to approximate the amount of liquidated damages called for herein and because the actual amount of such damages would be difficult if not impossible to measure accurately.

Section 11.3 Specific Performance. The Parties each acknowledge that the rights of each Party to consummate the transactions contemplated by this Agreement are special, unique and of extraordinary character and that, in the event that any Party violates or fails or refuses to perform any covenant or agreement made it in this Agreement, the non-breaching Party may be without an adequate remedy at law. The Parties agree, therefore, that in the event that any Party violates or fails or refuses to perform any covenant or agreement made by such Party in this Agreement, any non-breaching Party may, subject to the terms of this Agreement, institute and prosecute an Action to enforce specific performance of such covenant or agreement, in addition to pursuing any other remedy available at law or in equity.

Section 11.4 Confidentiality. Notwithstanding the termination of this Agreement or any other provision of this Agreement to the contrary but subject to the next sentence of this Section 11.4, the terms of the Confidentiality Agreements shall remain in full force and effect in accordance with their terms. If Closing of the transaction contemplated under the terms of this Agreement occurs, the Confidentiality Agreements shall terminate (which termination shall be effective as of Closing).

A-67

ARTICLE XII

MISCELLANEOUS PROVISIONS

Section 12.1 Notices. All notices, communications and deliveries under this Agreement will be made in writing signed by or on behalf of the Party making the same, will specify the Section under this Agreement pursuant to which it is given or being made, and will be delivered personally or by facsimile transmission or sent by registered or certified mail (return receipt requested) or by nationally recognized overnight courier (with evidence of delivery and postage and other fees prepaid) as follows:

If to Buyer:

Midstates Petroleum Company, LLC

4400 Post Oak Parkway, Suite 1900

Houston, Texas

Attn: Thomas Mitchell

Telephone No.: 713.595.9451

Facsimile No.: 713.595.9494

with a copy (which shall not constitute notice) to:

Baker Botts L.L.P.

910 Louisiana Street

Houston, TX 77002

Attn: Joshua Davidson

Hillary H. Holmes

Telephone No.: 713.229.1508

Facsimile No.: 713.229.7708

If to Seller:

Eagle Energy Production, LLC

9 East 4th Street, Suite 200

Tulsa, OK 74103

Attn: Steve Antry

Ben Kemendo

Telephone No.: 918.746.1350

Facsimile No.: 918.746.1379

with a copy (which shall not constitute notice) to:

Vinson & Elkins LLP

666 Fifth Avenue, 26th Floor

New York, NY 10103-0040

Attn: James J. Fox

Telephone No.: 212.373.0131

Facsimile No.: 917.849.5328

and

Riverstone Holdings LLC

712 Fifth Avenue, 51st Floor

New York, New York 10019

Attn: Robert Tichio

Telephone No.: 212.271.2935

Facsimile No.: 888.801.9301

A-68

or to such other representative or at such other address or facsimile number of a Party as such Party may furnish to the other Parties in writing. Any such notice, communication or delivery will be deemed given or made upon the date of receipt by the applicable Party.

Section 12.2 Schedules and Exhibits. The Schedules and Exhibits to this Agreement are hereby incorporated into this Agreement and are hereby made a part of this Agreement as if set out in full in this Agreement.

Section 12.3 Assignment; Successors in Interest. No assignment or transfer by any Party of its rights and obligations under this Agreement will be made except with the prior written consent of the other Party; provided, however, that without the consent of Seller but with notice to Seller, Buyer may, without relieving Buyer from its liabilities or obligations hereunder, assign this Agreement, and its rights and obligations hereunder, to an entity formed, controlled and primarily owned by Buyer or Parent; provided further, that, after Closing, a Party may assign its rights and obligations hereunder but no such assignment shall release any Party from any of its obligations under this Agreement. This Agreement will be binding upon and will inure to the benefit of the Parties and their successors and permitted assigns, and any reference to a Party will also be a reference to a successor or permitted assign.

Section 12.4 Number; Gender. Whenever the context so requires, the singular number will include the plural and the plural will include the singular, and the gender of any pronoun will include the other genders.

Section 12.5 Captions. The titles, captions and table of contents contained in this Agreement are inserted in this Agreement only as a matter of convenience and for reference and in no way define, limit, extend or describe the scope of this Agreement or the intent of any provision of this Agreement. Unless otherwise specified to the contrary, all references to Articles and Sections are references to Articles and Sections of this Agreement and all references to Schedules or Exhibits are references to Schedules and Exhibits, respectively, to this Agreement.

Section 12.6 Controlling Law. This Agreement will be governed by and construed and enforced in accordance with the internal laws of Texas without reference to its choice of law rules.

Section 12.7 Consent to Jurisdiction, Etc.; Waiver of Jury Trial.

(a) Subject to Sections 2.5, 8.2(i) and 9.2(d), each of the Parties hereby irrevocably consents and agrees that any Action arising in connection with any disagreement, dispute, controversy or Claim arising out of or relating to this Agreement or any related document (for purposes of this Section 12.7, a “Legal Dispute”) shall exclusively be brought in the courts of the State of Texas, or the federal courts located in the Southern District of the State of Texas. The Parties agree that, after a Legal Dispute is before a court as specified in this Section 12.7 and during the pendency of such Legal Dispute before such court, all Actions with respect to such Legal Dispute, including any counterclaim, cross-claim or interpleader, shall be subject to the exclusive jurisdiction of such court. Each of the Parties hereby waives, and agrees not to assert, as a defense in any Legal Dispute that it is not subject thereto or that such Action may not be brought or is not maintainable in such court or that its property is exempt or immune from execution or that the Action is brought in an inconvenient forum or that the venue of the Action is improper. Each Party agrees that a final judgment in any Action described in this Section 12.7 after the expiration of any period permitted for appeal and subject to any stay during appeal shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by Laws.

(b) Notwithstanding anything in Section 12.6 or 12.7(a) to the contrary, each of the Parties hereby irrevocably consents and agrees that it will not bring or support any Action (whether at law, in equity, in contract, in tort or otherwise) against the Financing Sources in any way relating to this Agreement or any of the transactions contemplated by this Agreement, including any dispute arising out of or relating in any way to the Commitment Letter or other Financing Commitment or the performance thereof, in any forum other than the Supreme Court of the State of New York, in New York County, or, if under applicable Law exclusive jurisdiction is vested in the federal courts, the federal courts located in the Southern District of New York (and appellate courts thereof). The provisions of this Section 12.7(b) shall be enforceable by each Financing Source.

A-69

(c) THE PARTIES HEREBY WAIVE IRREVOCABLY ANY AND ALL RIGHTS TO DEMAND A TRIAL BY JURY IN CONNECTION WITH THIS AGREEMENT, THE TRANSACTIONS CONTEMPLATED HEREBY OR ANY DOCUMENT CONTEMPLATED HEREIN OR OTHERWISE RELATED HERETO, INCLUDING ANY DISPUTE ARISING OUT OF OR RELATING TO THE FINANCING COMMITMENT OR THE PERFORMANCE THEREOF.

Section 12.8 Severability. Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction will, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions of this Agreement, and any such prohibition or unenforceability in any jurisdiction will not invalidate or render unenforceable such provision in any other jurisdiction. To the extent permitted by Laws, the Parties waive any provision of Laws which renders any such provision prohibited or unenforceable in any respect.

Section 12.9 Counterparts. This Agreement may be executed simultaneously in two or more counterparts, each of which shall be deemed an original and all of which together shall constitute but one and the same instrument. Facsimile or scanned and emailed transmission of any signed original document or retransmission of any signed facsimile or scanned and emailed transmission will be deemed the same as delivery of an original. At the request of any Party, the Parties will confirm facsimile or scanned and emailed transmission by signing a duplicate original document.

Section 12.10 No Third-Party Beneficiaries. Except for (i) the right of the Seller Indemnified Parties to seek indemnification pursuant to Article X, (ii) the right of the Buyer Indemnified Parties to seek indemnification pursuant to Article X and (iii) the rights of the Financing Sources pursuant to Sections 12.7(b), 12.7(c), 12.11(c) and 12.17(b) and this Section 12.10, nothing expressed or implied in this Agreement is intended, or will be construed, to confer upon or give any Person other than the Parties, and their successors or permitted assigns, any rights, remedies, obligations or liabilities under or by reason of this Agreement, or result in such Person being deemed a third party beneficiary of this Agreement; provided, however, only Seller may bring a Claim under or with respect to this Agreement on behalf of the Seller Indemnified Parties and only Buyer may bring a Claim under or with respect to this Agreement on behalf of the Buyer Indemnified Parties.

Section 12.11 Amendment; Waiver.

(a) Any amendment, extension or waiver of any provision of this Agreement will be valid only if set forth in an instrument in writing signed by both Seller and Buyer.

(b) A waiver by a Party of the performance of any covenant, agreement, obligation, condition, representation or warranty will not be construed as a waiver of any other covenant, agreement, obligation, condition, representation or warranty. A waiver by any Party of the performance of any act will not constitute a waiver of the performance of any other act or an identical act required to be performed at a later time.

(c) The Parties hereby expressly agree that the provisions of Sections 12.7(b), 12.7(c), 12.10 and 12.17(b) and this Section 12.11(c) shall not be amended in any manner adverse to the Financing Sources without the prior written consent of the Financing Sources.

Section 12.12 Entire Agreement. This Agreement, the Confidentiality Agreements and the documents executed pursuant to this Agreement supersede all negotiations, agreements and understandings between the Parties with respect to the subject matter of this Agreement and constitute the entire agreement between the Parties.

Section 12.13 Cooperation Following the Closing. Following the Closing, each of the Parties shall deliver to the others such further information and documents and shall execute and deliver to the others such further instruments and agreements as the other Party shall reasonably request to consummate or confirm the transactions provided for in this Agreement, to accomplish the purpose of this Agreement or to assure to the other Party the benefits of this Agreement.

A-70

Section 12.14 Transaction Costs.

Except as otherwise provided herein, each Party and Parent will be responsible for its own legal fees and other expenses incurred in connection with the negotiation, preparation, execution or performance of this Agreement.

Section 12.15 Construction.

(a) This Agreement has been freely and fairly negotiated between the Parties. If an ambiguity or question of intent or interpretation arises, this Agreement will be construed as if drafted jointly by the Parties and no presumption or burden of proof will arise favoring or disfavoring any Party because of the authorship of any provision of this Agreement. Any reference to any Law will be deemed also to refer to such Law as amended, modified, succeeded or supplemented from time to time and in effect at any given time, and all rules and regulations promulgated thereunder, unless the context requires otherwise. The words “include,” “includes,” and “including” do not limit the preceding terms or words and shall be deemed to be followed by “without limitation.” Pronouns in masculine, feminine and neuter genders will be construed to include any other gender, and words in the singular form will be construed to include the plural and vice versa, unless the context otherwise requires. Unless the context otherwise requires, the terms “day” and “days” mean and refer to calendar day(s). The words “this Agreement,” “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.

(b) The inclusion of any information in any Schedule shall not be deemed an admission or acknowledgment, in and of itself and solely by virtue of the inclusion of such information in any Schedule, that such information is required to be listed in any Schedule or that such items are material. The headings, if any, of the individual sections of each of the Schedules are inserted for convenience only and shall not be deemed to constitute a part thereof or a part of this Agreement. The Schedules are arranged in sections corresponding to those contained in Article III and Article V merely for convenience, and the disclosure of an item in one section of a Schedule as an exception to a particular representation or warranty shall be deemed adequately disclosed as an exception with respect to all other representations or warranties to the extent that the relevance of such item to such representations or warranties is reasonably apparent on the face of such item, notwithstanding the presence or absence of an appropriate section of any Schedule with respect to such other representations or warranties or the presence or absence of a reference thereto in any Schedule or in the particular representation or warranty.

(c) The specification of any dollar amount in the representations and warranties or otherwise in this Agreement or in any Schedule is not intended and shall not be deemed to be an admission or acknowledgment of the materiality of such amounts or items, nor shall the same be used in any dispute or controversy between the Parties to determine whether any obligation, item or matter (whether or not described herein or included in any Schedule) is or is not material for purposes of this Agreement (other than with respect to any representation, warranty or provision of this Agreement in which such specification occurs).

Section 12.16 Section 1031 Like-Kind Exchange. Seller and Buyer hereby agree that Seller shall have the right at any time prior to completion of all the transactions that are to occur at Closing to assign all or a portion of its rights under this Agreement to a “qualified intermediary” (as that term is defined in Section 1.1031(k)-1(g)(4)(iii) of the Treasury Regulations) in order to accomplish the transaction in a manner that will comply, either in whole or in part, with the requirements of a like-kind exchange pursuant to Section 1031 of the Code. Likewise, Buyer shall have the right at any time prior to completion of all the transactions that are to occur at Closing to assign all or a portion of its rights under this Agreement to an “exchange accommodation titleholder” (as that term is defined in IRS Revenue Procedure 2000-37, 2000-2 C.B. 308) for the same purpose. If Seller assigns all or any of its rights under this Agreement for this purpose, Buyer agrees to (a) consent to Seller’s assignment of their rights in this Agreement, which assignment shall be in a form reasonably acceptable to Buyer and (b) pay the Purchase Price (or a designated portion thereof as specified by Sellers) into a qualified escrow or qualified trust account at Closing as directed in writing. If Buyer assigns all or any of its rights under this

A-71

Agreement for this purpose, Seller agree to (i) consent to Buyer’s assignment of its rights in this Agreement, which assignment shall be in a form reasonably acceptable to Sellers, (ii) accept the Purchase Price from the exchange accommodation titleholder at Closing and (iii) at Closing, convey and assign the Assets (or any portion thereof) as directed by Buyer. Seller and Buyer acknowledge and agree that any assignment of this Agreement (or any rights hereunder) to a qualified intermediary or exchange accommodation titleholder shall not release any Party from any of its respective liabilities and obligations hereunder, and that neither Party represents to the other Party that any particular tax treatment will be given to any Party as a result thereof. The Party electing to assign all or any of its rights under this Agreement pursuant to this Section 12.16 shall defend, indemnify, and hold harmless the other Party and its Affiliates from all Claims relating to such election.

Section 12.17 Non-Recourse.

(a) No past, present or future director, officer, employee, member, partner, shareholder or other owner (whether direct or indirect), Affiliate, agent, attorney or representative of Seller or its Affiliates (collectively, all such Persons, the “Seller Subject Parties”) shall have any liability for any obligations or liabilities of Seller under this Agreement or for any Claims or Losses based on, in respect of, or by reason of, the transactions contemplated hereby and thereby.

(b) Subject to the rights of the parties to any Financing Commitment under the terms thereof, none of the Parties, nor any of their respective Affiliates, solely in their respective capacities as parties to this Agreement, shall have any rights or claims against any Financing Source, solely in its capacity as a lender or arranger in connection with the Financing, and the Financing Sources, solely in their respective capacities as lenders or arrangers, shall not have any rights or claims against any Party or any Person related to a Party hereto, in connection with this Agreement or the Financing, whether at law or equity, in contract, in tort or otherwise.

Section 12.18 Excluded Losses. Notwithstanding anything to the contrary in this Agreement or otherwise, in no event shall any of the Buyer Indemnified Parties or the Seller Indemnified Parties be entitled under this Agreement (including Article X) or otherwise to recover from Seller, any Affiliate of Seller or any of the other Seller Subject Parties or Buyer, any Affiliate of Buyer or any of the other Buyer Subject Parties, as applicable, and Buyer, on behalf of each of the Buyer Indemnified Parties, and Seller, on behalf of each of the Seller Indemnified Parties, waive any right to recover any Excluded Losses. This Section 12.18 shall not restrict any Party’s rights under Section 11.2 or any Party’s right to obtain specific performance.

Section 12.19 Publicity. Prior to the Closing, neither of the Parties nor their Affiliates shall issue any press release or similar public announcement pertaining to this Agreement or the transactions contemplated hereby without the prior consent of the other Party (which consent shall not be unreasonably withheld, delayed or conditioned), except where such release or announcement is deemed in good faith by the releasing or disclosing Party to be required by Law or under the rules and regulations of a recognized stock exchange on which shares of such Party or any of its Affiliates are listed, so long as prior to making any such release or announcement, the releasing or announcing Party shall provide a copy of the portion of the release or public announcement containing such information to the other Party; provided, however, that, in the case of any press release or public announcement to be issued or made in connection with Closing, the Parties agree to reasonably cooperate in advance of such issuance, announcement or public disclosure.

Section 12.20 Time of Essence. This Agreement contains a number of dates and times by which performance or the exercise of rights is due, and the Parties intend that each and every such date and time be the firm and final date and time, as agreed. For this reason, each Party hereby waives and relinquishes any right it might otherwise have to challenge its failure to meet any performance or exercise any rights by the election date applicable to it on the basis that its late action constitutes substantial performance, to require the other Party to show prejudice, or on any equitable grounds. Without limiting the foregoing, time is of the essence in this Agreement. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which

A-72

is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

Section 12.21 Name Change. As promptly as practicable, but in any case within sixty (60) days after the Closing Date, Buyer shall eliminate the use of the name “Eagle” and any variants thereof from the Assets, and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates. Buyer shall be solely responsible for any direct or indirect costs or expenses incurred by it in complying with the provisions of this Section 12.21.

Signature Page Follows.

A-73

IN WITNESS WHEREOF, the Parties and Parent have executed this Agreement on the day and year first set forth above.


SELLER:

EAGLE ENERGY PRODUCTION, LLC

By:		/s/ Steve Antry
Name:		Steve Antry
Title:		Authorized Person

BUYER:

MIDSTATES PETROLEUM COMPANY, LLC

By:		/s/ Thomas L. Mitchell
Name:		Thomas L. Mitchell
Title:		Executive Vice President and Chief Financial Officer

PARENT:

Parent has executed this Agreement solely to evidence its agreement to be bound by and to perform the provisions of this Agreement applicable to it.
MIDSTATES PETROLEUM COMPANY, INC.

By:		/s/ John A. Crum
Name:		John A. Crum
Title:		President and Chief Executive Officer