10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

(Mark One)
þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2009
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from          to

Commission File Number: 001-33784

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	20-8084793
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
123 Robert S. Kerr Avenue Oklahoma City, Oklahoma (Address of principal executive offices)	73102 (Zip Code)

Registrant’s telephone number, including area code:

(405) 429-5500

Former name, former address and former fiscal year, if changed since last report: Not applicable

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

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

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

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

(Do not check if a smaller reporting company)

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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on July 31, 2009, was 183,546,780.

SANDRIDGE ENERGY, INC.
FORM 10-Q
Quarter Ended June 30, 2009

INDEX

PART I. FINANCIAL INFORMATION
ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statement of Changes in Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	50
ITEM 4.	Controls and Procedures	53
PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	53
ITEM 1A.	Risk Factors	53
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
ITEM 4.	Submission of Matters to a Vote of Security Holders	55
ITEM 6.	Exhibits	55
EX-10.4
EX-10.5
EX-10.6
EX-31.1
EX-31.2
EX-31.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

2

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q (“Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (“Exchange Act”). Various statements contained in this Quarterly Report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements include projections and estimates concerning, among other things, 2009 capital expenditures, our liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, and elements of our business strategy. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008 (the “2008 Form 10-K”), the opportunities that may be pursued by us, competitive actions by other companies, changes in laws or regulations and other factors, many of which are beyond our control. The actual results or developments anticipated may not be realized or, even if substantially realized, they may not have the expected consequences to or effects on our company or our business or operations. The forward-looking statements contained herein are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements.

3

PART I. Financial Information

ITEM 1.   Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)

	June 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	621		$	636
Accounts receivable, net:
Trade		73,125			102,746
Related parties		201			6,327
Derivative contracts		207,342			201,111
Inventories		3,556			3,686
Costs in excess of billings		16,449			—
Other current assets		20,164			41,407
Total current assets		321,458			355,913
Natural gas and crude oil properties, using full cost method of accounting
Proved		4,996,188			4,676,072
Unproved		225,369			215,698
Less: accumulated depreciation, depletion and impairment		(3,765,118	)		(2,369,840	)
		1,456,439			2,521,930
Other property, plant and equipment, net		464,463			653,629
Derivative contracts		35,709			45,537
Investments		7,588			6,088
Restricted deposits		32,860			32,843
Other assets		45,799			39,118
Total assets	$	2,364,316		$	3,655,058
LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	15,380		$	16,532
Accounts payable and accrued expenses:
Trade		185,452			366,337
Related parties		176			230
Derivative contracts		6,238			5,106
Asset retirement obligation		128			275
Billings in excess of costs incurred		—			14,144
Total current liabilities		207,374			402,624
Long-term debt		2,146,615			2,358,784
Other long-term obligations		11,967			11,963
Derivative contracts		733			3,639
Asset retirement obligation		89,421			84,497
Total liabilities		2,456,110			2,861,507
Commitments and contingencies (Note 13)
Equity:
SandRidge Energy, Inc. stockholders’ equity:
Preferred stock, $0.001 par value, 50,000 shares authorized:
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at June 30, 2009 and no shares issued and outstanding in 2008; aggregate liquidation preference of $265,000 at June 30, 2009		3			—
Common stock, $0.001 par value, 400,000 shares authorized; 183,254 issued and 181,856 outstanding at June 30, 2009 and 167,372 issued and 166,046 outstanding at December 31, 2008		178			163
Additional paid-in capital		2,532,180			2,170,986
Treasury stock, at cost		(19,854	)		(19,332	)
Accumulated deficit		(2,604,327	)		(1,358,296	)
Total SandRidge Energy, Inc. stockholders’ (deficit) equity		(91,820	)		793,521
Noncontrolling interest		26			30
Total (deficit) equity		(91,794	)		793,551
Total liabilities and equity	$	2,364,316		$	3,655,058

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

4

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(Unaudited)
Revenues:
Natural gas and crude oil	$	103,039		$	292,134		$	224,280		$	497,621
Drilling and services		5,176			11,957			11,571			24,291
Midstream and marketing		19,642			69,488			45,598			115,897
Other		6,242			4,471			11,663			9,327
Total revenues		134,099			378,050			293,112			647,136
Expenses:
Production		41,450			40,254			87,029			74,442
Production taxes		593			13,519			2,084			22,739
Drilling and services		6,415			5,066			12,021			12,235
Midstream and marketing		18,450			64,733			41,812			105,151
Depreciation, depletion and amortization — natural gas and crude oil		34,350			72,256			94,443			137,332
Depreciation, depletion and amortization — other		14,034			15,780			26,760			33,745
Impairment		—			—			1,304,418			—
General and administrative		23,632			26,203			52,117			47,197
Loss (gain) on derivative contracts		18,992			159,768			(187,655	)		296,612
Loss (gain) on sale of assets		26,170			(7,734	)		26,350			(7,711	)
Total expenses		184,086			389,845			1,459,379			721,742
Loss from operations		(49,987	)		(11,795	)		(1,166,267	)		(74,606	)
Other income (expense):
Interest income		188			1,333			199			2,145
Interest expense		(42,419	)		(22,223	)		(83,167	)		(47,395	)
Income from equity investments		200			556			434			1,415
Other income, net		483			955			1,243			939
Total other (expense) income		(41,548	)		(19,379	)		(81,291	)		(42,896	)
Loss before income tax benefit		(91,535	)		(31,174	)		(1,247,558	)		(117,502	)
Income tax benefit		(365	)		(10,847	)		(1,534	)		(41,385	)
Net loss		(91,170	)		(20,327	)		(1,246,024	)		(76,117	)
Less: net income attributable to noncontrolling interest		4			16			7			851
Net loss attributable to SandRidge Energy, Inc. common stockholders		(91,174	)		(20,343	)		(1,246,031	)		(76,968	)
Preferred stock dividends and accretion		—			6,650			—			16,232
Loss applicable to SandRidge Energy, Inc. common stockholders	$	(91,174	)	$	(26,993	)	$	(1,246,031	)	$	(93,200	)
Basic and diluted loss per share applicable to SandRidge Energy, Inc. common stockholders	$	(0.52	)	$	(0.17	)	$	(7.38	)	$	(0.63	)
Weighted average number of SandRidge Energy, Inc. common shares outstanding:
Basic		174,154			155,204			168,767			148,124
Diluted		174,154			155,204			168,767			148,124

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

5

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(IN THOUSANDS)

	SandRidge Energy, Inc. Stockholders
	8.5% Convertible
	Perpetual Preferred								Additional
	Stock				Common Stock				Paid-In			Treasury			Accumulated			Noncontrolling
	Shares		Amount		Shares		Amount		Capital			Stock			Deficit			Interest			Total
	(Unaudited)
Six months ended June 30, 2009
Balance, December 31, 2008		—	$	—		166,046	$	163	$	2,170,986		$	(19,332	)	$	(1,358,296	)	$	30		$	793,551
Distributions to noncontrolling interest owners		—		—		—		—		—			—			—			(11	)		(11	)
Issuance of 8.5% convertible perpetual preferred stock		2,650		3		—		—		243,286			—			—			—			243,289
Issuance of common stock		—		—		14,480		15		107,684			—			—			—			107,699
Purchase of treasury stock		—		—		—		—		—			(522	)		—			—			(522	)
Stock-based compensation		—		—		—		—		12,389			—			—			—			12,389
Stock-based compensation excess tax benefit		—		—		—		—		(2,165	)		—			—			—			(2,165	)
Issuance of restricted stock awards, net of cancellations		—		—		1,330		—		—			—			—			—			—
Net (loss) income		—		—		—		—		—			—			(1,246,031	)		7			(1,246,024	)
Balance, June 30, 2009		2,650	$	3		181,856	$	178	$	2,532,180		$	(19,854	)	$	(2,604,327	)	$	26		$	(91,794	)

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

6

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

	Six Months Ended
	June 30,
	2009			2008
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,246,024	)	$	(76,117	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Provision for doubtful accounts		62			—
Depreciation, depletion and amortization		121,203			171,077
Impairment		1,304,418			—
Debt costs amortization		3,677			2,445
Deferred income taxes		4			(42,338	)
Unrealized loss on derivative contracts		1,823			235,489
Loss (gain) on sale of assets		26,350			(7,711	)
Investment income — restricted deposits		(17	)		(243	)
Income from equity investments		(434	)		(1,415	)
Stock-based compensation		10,368			7,260
Stock-based compensation excess tax benefit		(2,165	)		—
Changes in operating assets and liabilities		(77,283	)		8,387
Net cash provided by operating activities		141,982			296,834
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant and equipment		(524,266	)		(934,301	)
Proceeds from sale of assets		253,968			153,191
Loans to unconsolidated investees		—			(4,000	)
Fundings of restricted deposits		—			(781	)
Net cash used in investing activities		(270,298	)		(785,891	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,431,765			1,408,000
Repayments of borrowings		(1,645,278	)		(665,615	)
Dividends paid — preferred		—			(17,552	)
Noncontrolling interest distributions		(11	)		(4,059	)
Proceeds from issuance of 8.5% convertible perpetual preferred stock		243,289			—
Proceeds from issuance of common stock		107,699			—
Purchase of treasury stock		(522	)		(1,908	)
Debt issuance costs		(8,641	)		(17,056	)
Net cash provided by financing activities		128,301			701,810
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(15	)		212,753
CASH AND CASH EQUIVALENTS, beginning of period		636			63,135
CASH AND CASH EQUIVALENTS, end of period	$	621		$	275,888
Supplemental Disclosure of Noncash Investing and Financing Activities:
Change in accrued capital expenditures	$	(79,782	)	$	—
Accretion on redeemable convertible preferred stock	$	—		$	7,636

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

7

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.   Basis of Presentation

Nature of Business.  SandRidge Energy, Inc. and its subsidiaries (collectively, the “Company” or “SandRidge”) is an independent natural gas and crude oil company concentrating on exploration, development and production activities. The Company also owns and operates natural gas gathering and treating facilities and CO₂ treating and transportation facilities and has marketing and tertiary oil recovery operations. In addition, Lariat Services, Inc. (“Lariat”), a wholly owned subsidiary, owns and operates drilling rigs and a related oil field services business. The Company’s primary exploration, development and production areas are concentrated in West Texas. The Company also operates interests in the Mid-Continent, the Cotton Valley Trend in East Texas, the Gulf Coast and the Gulf of Mexico.

Interim Financial Statements.  The accompanying condensed consolidated financial statements as of December 31, 2008 have been derived from the audited financial statements contained in the 2008 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2008 Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to state fairly the information in the Company’s unaudited condensed consolidated financial statements have been included. These condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2008 Form 10-K.

2.   Significant Accounting Policies

For a description of the Company’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2008 Form 10-K.

Reclassifications.  Certain reclassifications have been made to prior period financial statements to conform to the current period presentation.

Recent Accounting Pronouncements.  Effective January 1, 2009, the Company implemented Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements,” for certain of its nonfinancial liabilities, in accordance with Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157” (“FSP 157-2”), which delayed the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and liabilities except those recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. This implementation did not have a material impact on the Company’s financial position or results of operations.

Effective January 1, 2009, the Company implemented SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an Amendment of Accounting Research Bulletin No. 51,” which established accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. SFAS No. 160 also establishes disclosure requirements to clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. The implementation of SFAS No. 160 resulted in changes to the presentation for noncontrolling interests and did not have a material impact on the Company’s results of operations and financial condition. All historical periods presented in the condensed consolidated financial statements reflect these changes to the presentation for noncontrolling interests. See Note 15.

Effective January 1, 2009, the Company implemented SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which changed disclosure requirements for derivative instruments and

8

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

hedging activities. SFAS No. 161 requires enhanced disclosure, including qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. The implementation of SFAS No. 161 did not have a material impact on the Company’s financial position or results of operations. See Note 10.

Effective for the period ended June 30, 2009, the Company implemented Financial Accounting Standards Board (“FASB”) Staff Position FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”), which amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” and Accounting Principles Board Opinion 28, “Interim Financial Reporting,” to require disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. The implementation of FSP FAS 107-1 and APB 28-1 resulted in additional disclosure about the fair value of the Company’s financial instruments and did not have an impact on the Company’s financial position or results of operations. See Note 3.

Effective for the period ended June 30, 2009, the Company implemented SFAS No. 165, “Subsequent Events,” which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before the financial statements are issued or available to be issued. See Note 17.

On December 31, 2008, the Securities and Exchange Commission (“SEC”) issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” which revises disclosure requirements for oil and gas companies. In addition to changing the definition and disclosure requirements for natural gas and crude oil reserves, the new rules change the requirements for determining natural gas and crude oil reserve quantities to permit the use of new technologies to determine proved reserves under certain criteria and allow companies to disclose their probable and possible reserves. The new rules also require companies to report the independence and qualifications of their reserves preparer or auditor and file reports when a third party is relied upon to prepare reserves estimates or when a third party conducts a reserves audit. The new rules also require natural gas and crude oil reserves to be reported and the full cost ceiling limitation to be calculated using a twelve-month average price rather than period-end prices. The use of a twelve-month average price could have had an effect on the Company’s 2008 and 2009 depletion rates for its natural gas and crude oil properties. The new rules are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, pending the contemplated alignment of certain accounting standards by the FASB with the new rules. The Company plans to implement the new requirements beginning in its Annual Report on Form 10-K for the year ended December 31, 2009. The Company is currently evaluating the impact of the new requirements on its consolidated financial statements.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” SFAS No. 168 replaces SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” and establishes the FASB Accounting Standards Codification as the source of authoritative accounting principles recognized by the FASB to be applied by non-governmental entities in the preparation of financial statements in conformity with GAAP. SFAS No. 168 is effective for interim and annual periods ending after September 15, 2009. The Company plans to implement this standard in its September 30, 2009 financial statements. The implementation of SFAS No. 168 is not expected to have a material impact on the Company’s financial position or results of operations.

3.   Fair Value Measurements

Effective January 1, 2008, the Company implemented SFAS No. 157 for its financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all assets and liabilities that are measured and reported on a fair value basis. Effective January 1, 2009, the Company implemented SFAS No. 157 for certain nonfinancial liabilities based on FSP 157-2, which delayed the effective date of SFAS No. 157 by one year for certain nonfinancial assets and liabilities, with no material impact to the Company’s financial position or results of operations as a result of this implementation.

9

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

As defined in SFAS No. 157, 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. SFAS No. 157 requires disclosure that establishes a framework for measuring fair value and expands disclosure about fair value measurements. The statement requires fair value measurements be classified and disclosed in one of the following categories:

Level 1:	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2:	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3:	Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

As required by SFAS No. 157, assets and liabilities measured at fair value 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, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, takes into account the market for the Company’s financial assets and liabilities, the associated credit risk and other factors as required under SFAS No. 157. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Fair Value of Derivative Contracts

As required by SFAS No. 157, the Company has classified its derivative contracts into one of three levels based upon the data relied upon to determine the fair value. The fair values of the Company’s natural gas and crude oil swaps and interest rate swaps are based upon quotes obtained from counterparties to the derivative contracts. The Company reviews other readily available market prices for its derivative contracts as there is an active market for these contracts. However, the Company does not have access to the specific valuation models used by its counterparties or other market participants. Included in these models are discount factors that the Company must estimate in its calculation. Additionally, the Company applies a value weighted average credit default risk rating factor for its counterparties in determining the fair value of its derivative contracts. Based on the inputs for the fair value measurement, the Company classified its derivative contract assets and liabilities as Level 3.

The following table summarizes the Company’s financial assets and liabilities measured at fair value on a recurring basis by SFAS No. 157 pricing levels as of June 30, 2009:

								Assets/
	Fair Value Measurements Using:							Liabilities at
Description	Level 1		Level 2		Level 3			Fair Value
	(In thousands)
Derivative assets	$	—	$	—	$	243,051		$	243,051
Derivative liabilities		—		—		(6,971	)		(6,971	)
	$	—	$	—	$	236,080		$	236,080

10

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

The tables below set forth a reconciliation of the Company’s derivative contracts measured at fair value using significant unobservable inputs (Level 3) during the three and six months ended June 30, 2009 (in thousands):

Three Months Ended June 30, 2009
Balance at March 31, 2009	$	345,913
Total gains or losses (realized/unrealized)		(16,351	)
Purchases, issuances and settlements		(93,482	)
Transfers in and/or out of Level 3		—
Balance at June 30, 2009	$	236,080

Six Months Ended June 30, 2009
Balance at December 31, 2008	$	237,903
Total gains or losses (realized/unrealized)		189,009
Purchases, issuances and settlements		(190,832	)
Transfers in and/or out of Level 3		—
Balance at June 30, 2009	$	236,080
Changes in unrealized gains (losses) on derivative contracts held as of June 30, 2009	$	1,823

See Note 10 for further discussion of the Company’s derivative contracts.

Fair Value of Debt

The Company measures fair value of its long-term debt in accordance with SFAS No. 157, giving consideration to the effect of the Company’s credit risk. The estimated fair value of the Company’s senior notes, based on quoted market prices, and the carrying value at June 30, 2009 were as follows (in thousands):

	Fair Value		Carrying Value
Senior Floating Rate Notes due 2014	$	277,304	$	350,000
8.625% Senior Notes due 2015		583,011		650,000
9.875% Senior Notes due 2016, net of discount		355,918		350,242
8.0% Senior Notes due 2018		646,934		750,000

The Company’s carrying value for its senior credit facility and remaining fixed rate debt instruments approximate fair value based on current rates applicable to similar instruments. See Note 8 for further discussion of the Company’s long-term debt.

11

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

4.   Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

	June 30,			December 31,
	2009			2008
Natural gas and crude oil properties:
Proved	$	4,996,188		$	4,676,072
Unproved		225,369			215,698
Total natural gas and crude oil properties		5,221,557			4,891,770
Less accumulated depreciation, depletion and impairment(1)		(3,765,118	)		(2,369,840	)
Net natural gas and crude oil properties capitalized costs		1,456,439			2,521,930
Land		13,937			11,250
Non natural gas and crude oil equipment(2)		563,358			764,792
Buildings and structures		85,066			71,859
Total		662,361			847,901
Less accumulated depreciation, depletion and amortization		(197,898	)		(194,272	)
Net capitalized costs		464,463			653,629
Total property, plant and equipment, net	$	1,920,902		$	3,175,559

(1)	Includes cumulative full cost ceiling limitation impairment charges of $3,159.4 million and $1,855.0 million at June 30, 2009 and December 31, 2008, respectively.
(2)	The amount of capitalized interest included in the above non natural gas and crude oil equipment balance at both June 30, 2009 and December 31, 2008 was approximately $3.8 million.

In 2009, the asset lives of certain drilling, oil field services, midstream and other assets were changed to align with industry average lives for similar assets.

Sale of Midstream Assets.  In June 2009, the Company completed the sale of its gathering and compression assets located in the Piñon Field, part of the West Texas Overthrust (“WTO”) located in Pecos and Terrell counties, Texas. Net proceeds to the Company were approximately $197.5 million. The sale resulted in a loss of approximately $26.5 million. In conjunction with the sale, the Company entered into a gas gathering agreement and an operations and maintenance agreement. Under the gas gathering agreement, the Company has dedicated its Piñon Field acreage for priority gathering services for a period of twenty years and the Company will pay a fee that was negotiated at arms’ length for such services. Pursuant to the operations and maintenance agreement, the Company will operate and maintain the gathering system assets sold for a period of twenty years unless the Company or the buyer of the assets chooses to terminate the agreement.

Sale of East Texas Deep Rights.  In June 2009, the Company completed the sale of its drilling rights in East Texas below the depth of the Cotton Valley formation for net proceeds of approximately $55.9 million, subject to certain post-closing adjustments. The sale of the deep rights was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

5.   Impairment

Under the full cost method of accounting, the net book value of natural gas and crude oil properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenue from proved natural gas and crude oil properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of natural gas and crude oil

12

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

properties, plus the cost of properties not subject to amortization. In calculating future net revenues, prices and costs used are those as of the end of the appropriate period. These prices are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. The Company has entered into various commodity derivative contracts; however, these derivative contracts are not accounted for as cash flow hedges. Accordingly, the effect of these derivative contracts has not been considered in calculating the full cost ceiling limitation as of June 30, 2009.

The net book value, less related deferred tax liabilities, is compared to the ceiling limitation on a quarterly and annual basis. Any excess of the net book value, less related deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling limitation in the subsequent period.

During the first quarter of 2009, the Company reduced the carrying value of its natural gas and crude oil properties by $1,304.4 million due to the full cost ceiling limitation. As the full cost ceiling exceeded the net capitalized costs at June 30, 2009, there was no such reduction of the Company’s carrying value of its natural gas and crude oil properties during the second quarter of 2009.

6.   Costs in Excess of Billings (Billings in Excess of Costs Incurred)

In June 2008, the Company entered into an agreement with a subsidiary of Occidental Petroleum Corporation (“Occidental”) to construct a CO₂ treating plant (the “Century Plant”) and associated compression and pipeline facilities for $800.0 million. The Company will construct the Century Plant and Occidental will pay a minimum of 100% of the contract price, plus any subsequent agreed-upon revisions, to the Company through periodic cost reimbursements based upon the percentage of the project completed by the Company. Upon start-up, the Century Plant, located in Pecos County, Texas, will be owned and operated by Occidental for the purpose of separating and removing CO₂ from natural gas delivered by the Company. Pursuant to a thirty-year treating agreement executed simultaneously with the construction agreement, Occidental will remove CO₂ from the Company’s delivered production volumes. The Company will retain all methane gas from the Century Plant.

The Company accounts for construction of the Century Plant using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Provisions for a contract loss are recognized when it is determined that a loss will be incurred. Costs in excess of billings (billings in excess of costs incurred) were $16.4 million and ($14.1) million and were reported as a current asset and current liability in the condensed consolidated balance sheets at June 30, 2009 and December 31, 2008, respectively.

7.   Asset Retirement Obligation

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation for the period from December 31, 2008 to June 30, 2009 is as follows (in thousands):

Asset retirement obligation, December 31, 2008	$	84,772
Liability incurred upon acquiring and drilling wells		1,409
Revisions in estimated cash flows		(162	)
Liability settled in current period		—
Accretion of discount expense		3,530
Asset retirement obligation, June 30, 2009		89,549
Less: Current portion		128
Asset retirement obligation, net of current	$	89,421

13

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

8.   Long-Term Debt

Long-term debt consists of the following (in thousands):

	June 30,		December 31,
	2009		2008
Senior credit facility	$	18,000	$	573,457
Other notes payable:
Drilling rig fleet and related crude oil field services equipment		25,360		33,030
Mortgage		18,393		18,829
Senior Floating Rate Notes due 2014		350,000		350,000
8.625% Senior Notes due 2015		650,000		650,000
9.875% Senior Notes due 2016, net of $15,258 discount		350,242		—
8.0% Senior Notes due 2018		750,000		750,000
Total debt		2,161,995		2,375,316
Less: Current maturities of long-term debt		15,380		16,532
Long-term debt	$	2,146,615	$	2,358,784

For the three months ended June 30, 2009 and 2008, interest payments, net of amounts capitalized, were approximately $65.4 million and $25.4 million, respectively. For the six months ended June 30, 2009 and 2008, interest payments, net of amounts capitalized, were approximately $75.4 million and $50.8 million, respectively.

Senior Credit Facility.  The amount the Company can borrow under its senior secured revolving credit facility (the “senior credit facility”) is limited to a borrowing base, which was $985.4 million at June 30, 2009. The senior credit facility matures on November 21, 2011 and is available to be drawn on and repaid so long as the Company is in compliance with its terms, including certain financial covenants as fully described below.

The senior credit facility contains various covenants that limit the ability of the Company and certain of its subsidiaries to grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. Additionally, the senior credit facility limits the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions, including under the series of senior notes discussed below.

The senior credit facility contains financial covenants, including maintaining agreed levels for the (i) ratio of total funded debt to EBITDAX (as defined in the senior credit facility), which may not exceed 4.5:1.0 calculated using the last four completed fiscal quarters, (ii) ratio of EBITDAX to interest expense plus current maturities of long-term debt, which must be at least 2.5:1.0 calculated using the last four completed fiscal quarters, and (iii) ratio of current assets to current liabilities, which must be at least 1.0:1.0. In the current ratio calculation (as defined in the senior credit facility) any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s derivative contracts are disregarded. As of June 30, 2009, the Company was in compliance with all of the financial covenants under the senior credit facility.

The obligations under the senior credit facility are guaranteed by certain Company subsidiaries and are secured by first priority liens on all shares of capital stock of each of the Company’s material present and future subsidiaries; all intercompany debt of the Company; and substantially all of the Company’s assets, including proved natural gas and crude oil reserves representing at least 80% of the discounted present value (as defined in the senior credit facility) of proved natural gas and crude oil reserves reviewed in determining the borrowing base for the senior credit facility.

14

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

At the Company’s election, interest under the senior credit facility is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 2.00% and 3.00% per annum, or (b) the ‘base rate,’ which is the higher of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Bank of America or (iii) the Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 1.00% and 2.00% per annum. Interest is payable quarterly for prime rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest is paid at the end of each three-month period. The average annual interest rates paid on amounts outstanding under the senior credit facility were 2.68% and 2.28% for the three months and six months ended June 30, 2009, respectively.

The Company’s borrowing base is redetermined in April and October of each year. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, natural gas and crude oil prices and production. Accordingly, the Company’s ability to develop its properties and changes in commodity prices impact the borrowing base. The borrowing base remained unchanged at $1.1 billion as a result of the April 2009 redetermination; however, the issuance of the 9.875% Senior Notes due 2016 (discussed below) in May 2009 caused the borrowing base to be reduced to $985.4 million. The Company has incurred additional costs related to the senior credit facility as a result of changes to the borrowing base. These costs have been deferred and are included in other assets in the accompanying condensed consolidated balance sheets. At June 30, 2009, the Company had $18.0 million outstanding under the senior credit facility along with $24.5 million in outstanding letters of credit.

On October 3, 2008, Lehman Brothers Commodity Services, Inc. (“Lehman Brothers”), a lender under the Company’s senior credit facility, filed for bankruptcy. At the time that its parent, Lehman Brothers Holdings Inc., declared bankruptcy on September 15, 2008, Lehman Brothers elected not to fund its pro rata share, or 0.29%, of borrowings requested by the Company under the senior credit facility. Accordingly, the Company does not anticipate that Lehman Brothers will fund its pro rata share of any future borrowing requests. The Company does not expect this reduced availability of amounts under the senior credit facility to impact its liquidity or business operations.

Other Notes Payable.  The Company has financed a portion of its drilling rig fleet and related oil field services equipment through the issuance of notes secured by the equipment. At June 30, 2009, the aggregate outstanding balance of these notes was $25.4 million, with annual fixed interest rates ranging from 7.64% to 8.67%. The notes have a final maturity date of December 1, 2011 and require aggregate monthly installments of principal and interest in the amount of $1.2 million. The notes have a prepayment penalty (currently ranging from 0.50% to 2.00%) that is triggered if the Company repays the notes prior to maturity.

The debt incurred to purchase the downtown Oklahoma City property that serves as the Company’s corporate headquarters is fully secured by a mortgage on one of the buildings and a parking garage located on the property. The note underlying the mortgage bears interest at 6.08% annually and matures on November 15, 2022. Payments of principal and interest in the amount of approximately $0.5 million are due on a quarterly basis through the maturity date. During 2009, the Company expects to make payments of principal and interest on this note totaling $0.9 million and $1.1 million, respectively.

Senior Floating Rate Notes Due 2014 and 8.625% Senior Notes Due 2015.  In May 2008, pursuant to an exchange offer exempted from registration under the Securities Act of 1933, as amended (the “Securities Act”), the Company exchanged its senior term loans for senior unsecured notes with registration rights which were subsequently exchanged for substantially identical notes pursuant to an exchange offer registered under the Securities Act. The effect of the exchange offers resulted in the Company issuing $350.0 million of Senior Floating Rate Notes due 2014 (“Senior Floating Rate Notes”) in exchange for the total outstanding principal amount of its senior floating rate term loan and $650.0 million of 8.625% Senior Notes due 2015 (“8.625% Senior Notes”) in exchange for the total outstanding principal amount of its 8.625% senior term loan. Terms of these senior notes are

15

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

substantially identical to those of the exchanged senior term loans and the terms of the unregistered notes for which the senior term loans were exchanged. These senior notes are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries. See Note 19 for condensed consolidating financial information of the subsidiary guarantors.

The Senior Floating Rate Notes bear interest at LIBOR plus 3.625% (4.83% at June 30, 2009), except for the period from April 1, 2008 to June 30, 2008, for which the interest rate was 6.323%. Interest is payable quarterly with principal due on April 1, 2014. The average interest rates paid on outstanding Senior Floating Rate Notes for the three months and six months ended June 30, 2009 were 4.83% and 4.95%, respectively, without consideration of the interest rate swap discussed below. The 8.625% Senior Notes bear interest at a fixed rate of 8.625% per annum with the principal due on April 1, 2015. Under the terms of the 8.625% Senior Notes, interest is payable semi-annually and, through the interest payment due on April 1, 2011, interest may be paid, at the Company’s option, either entirely in cash or entirely with additional fixed rate senior notes. If the Company elects to pay the interest due during any period in additional fixed rate senior notes, the interest rate will increase to 9.375% during that period. All interest payments made to date on the 8.625% Senior Notes have been paid in cash.

In January 2008, the Company entered into a $350.0 million notional interest rate swap agreement to fix the variable LIBOR interest rate on the floating rate senior term loan for the period from April 1, 2008 to April 1, 2011. As a result of the exchange of the floating rate senior term loan to Senior Floating Rate Notes, the interest rate swap is now used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at an annual rate of 6.26% through April 1, 2011. In May 2009, the Company entered into a $350.0 million notional interest rate swap agreement to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at an annual rate of 6.69% for the period from April 1, 2011 to April 1, 2013. The two interest rate swaps effectively serve to fix the Company’s variable interest rate on its Senior Floating Rate Notes for the majority of the term of these notes. These swaps have not been designated as hedges.

The Company may redeem, at specified redemption prices, some or all of the Senior Floating Rate Notes at any time and some or all of the 8.625% Senior Notes on or after April 1, 2011.

The Company incurred $26.1 million of debt issuance costs in connection with the senior term loans. As the senior term loans were exchanged for unsecured senior notes with substantially identical terms, the remaining unamortized debt issuance costs on the senior term loans will be amortized over the terms of the Senior Floating Rate Notes and the 8.625% Senior Notes. These costs are included in other assets in the accompanying condensed consolidated balance sheets.

9.875% Senior Notes Due 2016.  In May 2009, the Company completed a private placement of $365.5 million of unsecured 9.875% Senior Notes due 2016 (“9.875% Senior Notes”) to qualified institutional investors eligible under Rule 144A of the Securities Act. These notes were issued at a discount which will be amortized into interest expense over the term of the notes. Net proceeds from the offering were approximately $342.2 million after deducting offering expenses of $7.8 million. The Company used the net proceeds from the offering to repay outstanding borrowings under the senior credit facility and for general corporate purposes. The notes bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. The 9.875% Senior Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices. The notes are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries. See Note 19 for condensed consolidated financial information of the subsidiary guarantors. The notes will become freely tradable 180 days after their issuance, pursuant to Rule 144 under the Securities Act.

Debt issuance costs of $7.8 million incurred in connection with the offering of the 9.875% Senior Notes are included in other assets in the condensed consolidated balance sheet and are being amortized over the term of the notes.

16

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

8.0% Senior Notes Due 2018.  In May 2008, the Company issued $750.0 million of unsecured 8.0% Senior Notes due 2018 (“8.0% Senior Notes”). The notes bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices. The 8.0% Senior Notes are jointly and severally, unconditionally guaranteed on an unsecured basis, by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries. See Note 19 for condensed consolidated financial information of the subsidiary guarantors. The notes became freely tradable on November 17, 2008, 180 days after their issuance, pursuant to Rule 144 under the Securities Act.

The Company incurred $16.0 million of debt issuance costs in connection with the offering of the 8.0% Senior Notes. These costs are included in other assets in the condensed consolidated balance sheet and amortized over the term of the notes.

The indentures governing all of the senior notes contain financial covenants similar to those of the senior credit facility and include limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of June 30, 2009, the Company was in compliance with all of the covenants contained in the indentures governing the senior notes.

9.   Other Long-Term Obligations

The Company has recorded a long-term obligation for amounts to be paid under a settlement agreement with Conoco, Inc. entered into in January 2007. The Company agreed to pay approximately $25.0 million plus interest, payable in $5.0 million increments on April 1, 2007, July 1, 2008, July 1, 2009, July 1, 2010 and July 1, 2011. The payment to be made on July 1, 2009 has been included in accounts payable-trade in the accompanying condensed consolidated balance sheets at June 30, 2009 and December 31, 2008. The non-current unpaid settlement amount of $10.0 million has been included in other long-term obligations in the accompanying condensed consolidated balance sheets at June 30, 2009 and December 31, 2008.

10.   Derivatives

The Company’s derivative contracts have not been designated as hedges. The Company records all derivative contracts, which include commodity derivatives and interest rate swaps, at fair value. Changes in derivative contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in loss (gain) on derivative contracts for the commodity derivative contracts and in interest expense for the interest rate swaps in the consolidated statements of operations. Commodity derivative contracts are settled on a monthly basis. Settlements on the interest rate swaps occur quarterly. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheet.

Commodity Derivatives.  The Company is exposed to commodity price risk, which impacts the predictability of its cash flows related to the sale of natural gas and crude oil and is managed by the Company’s use of commodity derivative contracts. These derivative contracts allow the Company to limit its exposure to a portion of its projected natural gas and crude oil sales. None of the Company’s derivative contracts may be terminated early as a result of a party having its credit rating downgraded. At June 30, 2009 and December 31, 2008, the Company’s commodity derivative contracts consisted of fixed price swaps and basis swaps, which are described below:

Fixed price swaps	The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Basis swaps	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for natural gas from a specified delivery point.

17

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Interest Rate Swaps.  The Company is exposed to interest rate risk on its long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as the Company’s interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.

The Company has entered into two interest rate swap agreements to manage the interest rate risk on a portion of its floating rate debt by effectively fixing the variable interest rate on its Senior Floating Rate Notes. See Note 8 for further discussion of the Company’s interest rate swaps.

Fair Value of Derivatives.  The balance sheet classification of assets and liabilities related to derivative contracts is summarized below at June 30, 2009 and December 31, 2008 (in thousands):

	Balance Sheet	Fair Value
Type of Contract	Classification	June 30, 2009		December 31, 2008
Derivative assets
Natural gas swaps	Derivative assets-current	$	202,430	$	188,045
Crude oil price swaps	Derivative assets-current		4,912		13,066
Natural gas swaps	Derivative assets-noncurrent		34,557		45,537
Interest rate swaps	Derivative assets-noncurrent		1,152		—
Total derivative assets		$	243,051	$	246,648
Derivative liabilities
Interest rate swaps	Derivative liabilities-current	$	6,238	$	5,106
Natural gas basis swaps	Derivative liabilities-noncurrent		733		3,639
Total derivative liabilities		$	6,971	$	8,745

A counterparty to one of the Company’s derivative contracts, Lehman Brothers, declared bankruptcy on October 3, 2008. Due to Lehman Brothers’ bankruptcy and the declaration of bankruptcy by its parent, Lehman Brothers Holdings Inc., on September 15, 2008, the Company has not assigned any value to this derivative contract as of June 30, 2009.

The following table summarizes the effect of the Company’s derivative contracts on the condensed consolidated statements of operations for the three and six-month periods ended June 30, 2009 and 2008 (in thousands):

		Amount of (Gain) Loss Recognized in Income
		Three Months Ended						Six Months Ended
	Location of (Gain) Loss	June 30,						June 30,
Type of Contract	Recognized in Income	2009			2008			2009			2008
Interest rate swap	Interest expense	$	(2,641	)	$	(9,643	)	$	(1,354	)	$	(10,449	)
Natural gas and crude oil swaps	Loss (gain) on derivative contracts		18,992			159,768			(187,655	)		296,612
Total		$	16,351		$	150,125		$	(189,009	)	$	286,163

18

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

The following table summarizes the cash settlements and valuation gains and losses on commodity derivative contracts for the three and six-month periods ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009			2008		2009			2008
Realized (gain) loss	$	(94,747	)	$	58,003	$	(193,136	)	$	50,674
Unrealized loss		113,739			101,765		5,481			245,938
Loss (gain) on derivative contracts	$	18,992		$	159,768	$	(187,655	)	$	296,612

Net gains of $2.6 million ($3.9 million unrealized gain and $1.3 million realized losses) and $1.4 million ($3.7 million unrealized gain and $2.3 million realized losses) related to the interest rate swaps discussed above were included in interest expense in the condensed consolidated statement of operations for the three months and six months ended June 30, 2009, respectively. Unrealized gains of $9.6 million and $10.4 million were included in the condensed consolidated statements of operations for the three months and six months ended June 30, 2008, respectively.

See Note 3 for additional discussion on the fair value measurement of the Company’s derivative contracts.

19

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Open Derivative Contracts.  At June 30, 2009, the Company’s open natural gas and crude oil commodity derivative contracts consisted of the following:

Natural Gas

	Notional		Weighted Avg.
Period and Type of Contract	(MMcf)(1)		Fixed Price
July 2009 — September 2009
Price swap contracts		18,710	$	8.09
Basis swap contracts		15,640	$	(0.74	)
October 2009 — December 2009
Price swap contracts		19,010	$	8.46
Basis swap contracts		15,640	$	(0.74	)
January 2010 — March 2010
Price swap contracts		20,475	$	7.95
Basis swap contracts		20,250	$	(0.74	)
April 2010 — June 2010
Price swap contracts		19,793	$	7.32
Basis swap contracts		20,475	$	(0.74	)
July 2010 — September 2010
Price swap contracts		20,010	$	7.55
Basis swap contracts		20,700	$	(0.74	)
October 2010 — December 2010
Price swap contracts		20,010	$	7.97
Basis swap contracts		20,700	$	(0.74	)
January 2011 — March 2011
Basis swap contracts		25,650	$	(0.47	)
April 2011 — June 2011
Basis swap contracts		25,935	$	(0.47	)
July 2011 — September 2011
Basis swap contracts		26,220	$	(0.47	)
October 2011 — December 2011
Basis swap contracts		26,220	$	(0.47	)
January 2012 — March 2012
Basis swap contracts		20,020	$	(0.54	)
April 2012 — June 2012
Basis swap contracts		20,020	$	(0.54	)
July 2012 — September 2012
Basis swap contracts		20,240	$	(0.54	)
October 2012 — December 2012
Basis swap contracts		20,240	$	(0.54	)

(1) Assumes ratio of 1:1 for Mcf to MMBtu and excludes a total notional of 3,680 MMcf from 2009 contracts for the Lehman Brothers’ basis swap contract.

20

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Crude Oil

	Notional		Weighted Avg.
Period and Type of Contract	(in MBbls)		Fixed Price
July 2009 — September 2009
Price swap contracts		46	$	126.61
October 2009 — December 2009
Price swap contracts		46	$	126.51

11.   Income Taxes

In accordance with GAAP, the Company estimates for each interim reporting period the effective tax rate expected for the full fiscal year and uses that estimated rate in providing income taxes on a current year-to-date basis.

The provisions (benefits) for income taxes consisted of the following components for the three and six-month periods ended June 30 (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Current:
Federal	$	(50	)	$	—		$	(2,220	)	$	—
State		(315	)		945			682			1,024
		(365	)		945			(1,538	)		1,024
Deferred:
Federal		—			(10,749	)		4			(41,236	)
State		—			(1,043	)		—			(1,173	)
		—			(11,792	)		4			(42,409	)
Total benefits	$	(365	)	$	(10,847	)	$	(1,534	)	$	(41,385	)

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Deferred tax assets are reduced by a valuation allowance if a determination is made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. For the year ended December 31, 2008, the Company determined it was appropriate to record a full valuation allowance against its net deferred tax asset. For the six-month period ended June 30, 2009, the Company recorded a $438.5 million increase to the previously established valuation allowance. The increase is primarily a result of not recording a tax benefit for the current period loss before income taxes of $1,247.6 million.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain tax attributes on an annual basis following an ownership change. The Company has experienced several owner shifts, within the meaning of IRC Section 382, since the time of its last ownership change, which occurred in June 2008. Further owner shifts occurring during the three-year period beginning as of June 2008 may result in another ownership change. In the event another ownership change occurs, the application of IRC Section 382 may limit the amount of tax attributes, including the 2009 projected net operating loss, that the Company can utilize on an annual basis. The Company will continue to closely monitor its ownership activity.

No reserves for uncertain income tax positions have been recorded pursuant to FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN 48”). Tax

21

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

years 1994 to present remain open for the majority of taxing authorities due to net operating loss utilization. The Company’s accounting policy is to recognize interest and penalties, if any, related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for interest and penalties at June 30, 2009.

For the three-month period ended June 30, 2009 and 2008, income tax payments, net of refunds, were approximately $3.6 million and $1.7 million, respectively. For the six-month period ended June 30, 2009 and 2008, income tax payments, net of refunds, were approximately $3.0 million and $1.9 million, respectively.

12.   Earnings (Loss) Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock and outstanding convertible preferred stock. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the three and six-month periods ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Weighted average basic common shares outstanding		174,154		155,204		168,767		148,124
Effect of dilutive securities:
Restricted stock		—		—		—		—
Convertible preferred stock outstanding		—		—		—		—
Weighted average diluted common and potential common shares outstanding		174,154		155,204		168,767		148,124

For the three-month periods ended June 30, 2009 and 2008, restricted stock awards covering 2.4 million shares and 1.3 million shares, respectively, were excluded from the computation of net loss per share because their effect would have been antidilutive. For the six-month periods ended June 30, 2009 and 2008, restricted stock awards covering 2.5 million shares and 1.3 million shares, respectively, were excluded from the computation of net loss per share because their effect would have been antidilutive.

In computing diluted earnings per share, the Company evaluated the if-converted method with respect to its outstanding 8.5% convertible perpetual preferred stock for the three and six-month periods ended June 30, 2009 and with respect to its then outstanding redeemable convertible preferred stock for the three and six-month periods ended June 30, 2008. Under this method, the Company assumes the conversion of the preferred stock to common stock and determines if this is more dilutive than including the preferred stock dividends (paid and unpaid) in the computation of income available to common stockholders. The Company determined the if-converted method is not more dilutive for the three and six-month periods ended June 30, 2009 and 2008.

13.   Commitments and Contingencies

The Company is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings that, individually or in the aggregate, could have a material effect on the financial condition, results of operations or cash flows of the Company.

14.   Redeemable Convertible Preferred Stock

In November 2006, the Company sold 2,136,667 shares of redeemable convertible preferred stock to finance a portion of its acquisition of NEG Oil & Gas, LLC. Each holder of redeemable convertible preferred stock was entitled to quarterly cash dividends at the annual rate of 7.75% of the accreted value, or $210 per share, of their

22

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

redeemable convertible preferred stock. Each share of redeemable convertible preferred stock was initially convertible into ten shares, and ultimately convertible into 10.2 shares, of common stock at the option of the holder. A summary of dividends declared and paid on the redeemable convertible preferred stock is as follows (in thousands, except per share data):

		Dividends
Declared	Dividend Period	per Share		Total		Payment Date
January 31, 2007	November 21, 2006 — February 1, 2007	$	3.21	$	6,859	February 15, 2007
May 8, 2007	February 2, 2007 — May 1, 2007		3.97		8,550	May 15, 2007
June 8, 2007	May 2, 2007 — August 1, 2007		4.10		8,956	August 15, 2007
September 24, 2007	August 2, 2007 — November 1, 2007		4.10		8,956	November 15, 2007
December 16, 2007	November 2, 2007 — February 1, 2008		4.10		8,956	February 15, 2008
March 7, 2008	February 2, 2008 — May 1, 2008		4.01		8,095	(1)
May 7, 2008	May 2, 2008 — May 7, 2008		4.01		501	May 7, 2008

(1) Includes $0.6 million of prorated dividends paid to holders of redeemable convertible preferred shares at the time their shares converted to common stock in March 2008. The remaining dividends of $7.5 million were paid during May 2008.

On March 30, 2007, certain holders of the Company’s common units (consisting of shares of common stock and a warrant to purchase redeemable convertible preferred stock upon the surrender of common stock) exercised warrants to purchase redeemable convertible preferred stock. The holders converted 526,316 shares of common stock into 47,619 shares of redeemable convertible preferred stock.

During March 2008, holders of 339,823 shares of the Company’s redeemable convertible preferred stock elected to convert those shares into 3,465,593 shares of the Company’s common stock. Additionally, during May 2008, the Company converted the remaining outstanding 1,844,464 shares of its redeemable convertible preferred stock into 18,810,260 shares of its common stock as permitted under the terms of the redeemable convertible preferred stock. These conversions resulted in increases to additional paid-in capital totaling $452.2 million, which represents the difference between the par value of the common stock issued and the carrying value of the redeemable convertible shares converted. The Company also recorded charges to retained earnings totaling $7.2 million in accelerated accretion expense related to the converted redeemable convertible preferred shares. Prorated dividends totaling $0.5 million for the period from May 2, 2008 to the date of conversion (May 7, 2008) were paid to the holders of the converted shares on May 7, 2008. On and after the conversion date, dividends ceased to accrue and the rights of common unit holders to exercise outstanding warrants to purchase redeemable convertible preferred shares terminated.

Approximately $0.5 million and $8.6 million in paid and unpaid dividends on the redeemable convertible preferred stock has been included in the Company’s earnings per share calculations for the three-month period and six-month period ended June 30, 2008, respectively, as presented in the condensed consolidated statements of operations.

15.   Equity

Preferred Stock.  The following table presents information regarding the Company’s preferred stock (in thousands):

	June 30,		December 31,
	2009		2008
Shares authorized		50,000		50,000
Shares outstanding at end of period		2,650		—

23

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

In January 2009, the Company completed a private placement of 2,650,000 shares of 8.5% convertible perpetual preferred stock to qualified institutional investors eligible under Rule 144A under the Securities Act. The offering included 400,000 shares of convertible perpetual preferred stock issued upon the full exercise of the initial purchaser’s option to cover over-allotments. Net proceeds from the offering were approximately $243.3 million after deducting offering expenses of approximately $8.6 million. The Company used the net proceeds from the offering to repay outstanding borrowings under the senior credit facility and for general corporate purposes.

Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100 and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of the Company’s common stock, subject to adjustments upon the occurrence of certain events. Each holder of the convertible perpetual preferred stock is entitled to an annual dividend of $8.50 per share to be paid semi-annually in cash, common stock or a combination thereof at the Company’s election, with the first dividend payment due in February 2010. The convertible perpetual preferred stock is not redeemable by the Company at any time. After February 20, 2014, the Company may cause all outstanding shares of the convertible perpetual preferred stock to automatically convert into common stock at the then-prevailing conversion rate if certain conditions are met.

Common Stock.  The following table presents information regarding the Company’s common stock (in thousands):

	June 30,		December 31,
	2009		2008
Shares authorized		400,000		400,000
Shares outstanding at end of period		181,856		166,046
Shares held in treasury		1,398		1,326

During March 2008, the Company issued 3,465,593 shares of common stock upon the conversion of 339,823 shares of its redeemable convertible preferred stock. In May 2008, the Company converted the remaining 1,844,464 outstanding shares of its redeemable convertible preferred stock into 18,810,260 shares of its common stock as permitted under the terms of the redeemable convertible preferred stock. See additional discussion in Note 14.

In April 2009, the Company completed a registered underwritten offering of 14,480,000 shares of its common stock, including 2,280,000 shares of common stock acquired by the underwriters from the Company to cover over-allotments. Net proceeds to the Company from the offering were approximately $107.7 million, after deducting offering expenses of approximately $2.3 million, and were used to repay a portion of the amount outstanding under the senior credit facility and for general corporate purposes.

Treasury Stock.  The Company makes required tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. As a result of such transactions, the Company withheld approximately 71,000 shares having a total value of $0.5 million and approximately 52,000 shares having a total value of $1.9 million during the six-month periods ended June 30, 2009 and 2008, respectively. These shares were accounted for as treasury stock.

In February 2008, the Company transferred 184,484 shares of its treasury stock into an account established for the benefit of the Company’s 401(k) Plan. The transfer was made in order to satisfy the Company’s $5.0 million accrued payable to match employee contributions made to the plan during 2007. The historical cost of the shares transferred totaled approximately $2.4 million and resulted in an increase to the Company’s additional paid-in capital of approximately $2.6 million.

Equity Compensation.  The Company awards restricted common stock under incentive compensation plans, and such awards vest over specified periods of time, subject to certain conditions. Awards issued prior to 2006 had vesting periods of one, four or seven years. All awards issued during and after 2006 have four year vesting periods.

24

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Shares of restricted common stock are subject to restriction on transfer. Unvested restricted stock awards are included in the Company’s outstanding shares of common stock.

For the three-month and six-month periods ended June 30, 2009, the Company recognized stock-based compensation expense of $5.2 million and $10.4 million, net of $0.8 million and $2.0 million capitalized, respectively, related to restricted common stock. For the three-month and six-month periods ended June 30, 2008, the Company recognized stock-based compensation expense of $4.1 million and $7.3 million, respectively, related to restricted common stock. There was no stock-based compensation capitalized in 2008. Stock-based compensation expense is reflected in general and administrative expenses in the condensed consolidated statements of operations.

Effective June 5, 2009, the Company adopted the SandRidge Energy, Inc. 2009 Incentive Plan (the “2009 Incentive Plan”). Under the terms of the 2009 Incentive Plan, the Company may grant stock options, stock appreciation rights, shares of restricted stock, restricted stock units and other forms of awards based on the value (or increase in the value) of shares of the common stock of the Company for up to 12,000,000 shares of common stock. The 2009 Incentive Plan also permits cash incentive awards. Consistent with the prior plan, the Company intends for shares of restricted stock to be the primary form of awards granted under the 2009 Incentive Plan.

Noncontrolling Interest.  On January 1, 2009, the Company implemented SFAS No. 160, which established accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. As required by SFAS No. 160, the noncontrolling interest in one of the Company’s subsidiaries represents an ownership interest in the consolidated entity and is included as a component of equity in the condensed consolidated balance sheets and condensed consolidated statement of changes in equity.

16.   Related Party Transactions

The Company has transactions with certain stockholders and other related parties in the ordinary course of business. These transactions primarily consist of purchases of drilling equipment and sales of oil field service supplies. Following is a summary of significant transactions with such related parties for the three and six-month periods ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Sales to and reimbursements from related parties	$	974	$	27,070	$	4,406	$	52,426
Purchases of services from related parties	$	5,464	$	19,171	$	14,406	$	39,061

The Company leases office space in Oklahoma City from a member of its Board of Directors. The Company believes that the payments made under this lease are at fair market rates. Rent expense related to the lease totaled $0.2 million and $0.3 million for the three-month periods ended June 30, 2009 and 2008, respectively. For the six-month periods ended June 30, 2009 and 2008, rent expense under this lease was $0.5 million and $0.7 million, respectively. The lease expires in August 2009.

Larclay, L.P.  Until April 15, 2009, Lariat and its partner Clayton Williams Energy, Inc. (“CWEI”) each owned a 50% interest in Larclay L.P. (“Larclay”), a limited partnership, and, until such time, Lariat operated the rigs owned by the partnership. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay pursuant to the terms of an Assignment and Assumption Agreement (the “Larclay Assignment”) entered into between Lariat and CWEI on March 13, 2009. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay from and after April 15, 2009. The Company fully impaired

25

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

both the investment in and notes receivable due from Larclay at December 31, 2008. There were no additional losses on Larclay during the three or six-month period ended June 30, 2009 or as a result of the Larclay Assignment.

The following table summarizes the Company’s other transactions with Larclay for the three and six-month periods ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Sales to and reimbursements from Larclay	$	214	$	12,035	$	2,962	$	22,973
Purchases of services from Larclay	$	—	$	13,288	$	1,762	$	23,958

	June 30,		December 31,
	2009		2008
Accounts receivable from Larclay	$	5	$	6,060
Accounts payable to Larclay	$	—	$	152

17.   Subsequent Events

Events occurring after June 30, 2009 were evaluated as of August 6, 2009, the date this Quarterly Report was issued, in compliance with SFAS No. 165 to ensure that any subsequent events that met the criteria for recognition and/or disclosure in this report have been included. No such events were noted.

18.   Business Segment Information

The Company has three business segments: exploration and production, drilling and oil field services and midstream gas services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the acquisition, development and production of natural gas and crude oil properties. The drilling and oil field services segment is engaged in the land contract drilling of natural gas and crude oil wells. The midstream gas services segment is engaged in the purchasing, gathering, processing, treating and selling of natural gas. The all other column in the tables below includes items not related to the Company’s reportable segments including the Company’s CO₂ gathering and sales operations and corporate operations.

26

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operating revenues less operating expenses and depreciation, depletion and amortization. Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):

	Exploration and			Drilling and Oil			Midstream Gas						Consolidated
	Production			Field Services			Services			All Other			Total
Three Months Ended June 30, 2009
Revenues	$	103,727		$	55,975		$	71,838		$	6,511		$	238,051
Inter-segment revenue		(64	)		(50,877	)		(52,742	)		(269	)		(103,952	)
Total revenues	$	103,663		$	5,098		$	19,096		$	6,242		$	134,099
Operating loss	$	(5,248	)	$	(2,801	)	$	(28,030	)	$	(13,908	)	$	(49,987	)
Interest expense, net		(41,387	)		(558	)		—			(286	)		(42,231	)
Other income, net		483			—			200			—			683
Loss before income taxes	$	(46,152	)	$	(3,359	)	$	(27,830	)	$	(14,194	)	$	(91,535	)
Capital expenditures(2)	$	121,347		$	188		$	17,340		$	8,813		$	147,688
Depreciation, depletion and amortization	$	35,025		$	6,909		$	2,115		$	4,335		$	48,384
Three Months Ended June 30, 2008
Revenues	$	293,472		$	108,720		$	219,819		$	5,653		$	627,664
Inter-segment revenue		(44	)		(96,856	)		(151,523	)		(1,191	)		(249,614	)
Total revenues	$	293,428		$	11,864		$	68,296		$	4,462		$	378,050
Operating (loss) income	$	(6,545	)	$	4,644		$	6,553		$	(16,447	)	$	(11,795	)
Interest expense, net		(19,823	)		(770	)		—			(297	)		(20,890	)
Other income (expense), net		848			(109	)		664			108			1,511
(Loss) income before income taxes	$	(25,520	)	$	3,765		$	7,217		$	(16,636	)	$	(31,174	)
Capital expenditures(2)	$	459,135		$	17,870		$	38,203		$	7,993		$	523,201
Depreciation, depletion and amortization	$	72,998		$	9,344		$	3,359		$	2,335		$	88,036

27

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

	Exploration and			Drilling and Oil			Midstream Gas						Consolidated
	Production			Field Services			Services			All Other			Total
Six Months Ended June 30, 2009
Revenues	$	225,660		$	149,789		$	166,205		$	12,407		$	554,061
Inter-segment revenue		(130	)		(138,380	)		(121,695	)		(744	)		(260,949	)
Total revenues	$	225,530		$	11,409		$	44,510		$	11,663		$	293,112
Operating loss(1)	$	(1,101,110	)	$	(5,556	)	$	(27,820	)	$	(31,781	)	$	(1,166,267	)
Interest expense, net		(81,205	)		(1,191	)		—			(572	)		(82,968	)
Other income, net		1,243			—			434			—			1,677
Loss before income taxes	$	(1,181,072	)	$	(6,747	)	$	(27,386	)	$	(32,353	)	$	(1,247,558	)
Capital expenditures(2)	$	383,231		$	2,201		$	41,288		$	17,764		$	444,484
Depreciation, depletion and amortization	$	95,785		$	14,195		$	3,957		$	7,266		$	121,203
At June 30, 2009
Total assets	$	1,894,446		$	246,173		$	109,640		$	114,057		$	2,364,316
Six Months Ended June 30, 2008
Revenues	$	500,438		$	188,558		$	368,054		$	11,507		$	1,068,557
Inter-segment revenue		(88	)		(164,372	)		(254,671	)		(2,290	)		(421,421	)
Total revenues	$	500,350		$	24,186		$	113,383		$	9,217		$	647,136
Operating (loss) income	$	(53,934	)	$	2,496		$	6,585		$	(29,753	)	$	(74,606	)
Interest expense, net		(43,235	)		(1,412	)		—			(603	)		(45,250	)
Other income, net		780			109			1,306			159			2,354
(Loss) income before income taxes	$	(96,389	)	$	1,193		$	7,891		$	(30,197	)	$	(117,502	)
Capital expenditures(2)	$	813,900		$	35,791		$	69,429		$	15,181		$	934,301
Depreciation, depletion and amortization	$	138,588		$	21,692		$	6,133		$	4,664		$	171,077
At December 31, 2008
Total assets	$	2,986,070		$	275,164		$	284,281		$	109,543		$	3,655,058

(1)	The operating loss for the exploration and production segment for the six-month period ended June 30, 2009 includes a $1,304.4 million non-cash full cost ceiling impairment on the Company’s natural gas and crude oil properties.
(2)	Capital expenditures are presented on an accrual basis.

19.   Condensed Consolidating Financial Information

The Company is providing condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. Subsidiary guarantors are wholly owned and have, jointly and severally, unconditionally guaranteed on an unsecured basis the Company’s 8.625% Senior Notes and Senior Floating Rate Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary

28

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; and (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves guarantors.

The Company has not presented separate financial and narrative information for each of the subsidiary guarantors because it believes that such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees.

Effective May 1, 2009, SandRidge Energy, Inc., the parent, contributed all of its rights, title and interest in its natural gas and crude oil related assets and accompanying liabilities to one of its wholly owned subsidiaries, leaving it with no natural gas or crude oil related assets or operations.

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc. and its wholly owned subsidiary guarantors, prepared on the equity basis of accounting. The non-guarantor subsidiaries are minor and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of the financial position, results of operations, or cash flows had the subsidiary guarantors operated as independent entities.

29

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Condensed Consolidating Balance Sheets

	June 30, 2009
	Parent			Guarantor
	Company			Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	162		$	459	$	—		$	621
Accounts and notes receivable, net		58,417			364,633		(349,724	)		73,326
Derivative contracts		—			207,342		—			207,342
Other current assets		—			40,169		—			40,169
Total current assets		58,579			612,603		(349,724	)		321,458
Property, plant and equipment, net		—			1,920,902		—			1,920,902
Investment in subsidiaries		2,249,681			—		(2,249,681	)		—
Other assets		44,548			128,792		(51,384	)		121,956
Total assets	$	2,352,808		$	2,662,297	$	(2,650,789	)	$	2,364,316
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	320,147		$	215,205	$	(349,724	)	$	185,628
Other current liabilities		6,238			15,508		—			21,746
Total current liabilities		326,385			230,713		(349,724	)		207,374
Long-term debt		2,118,243			79,756		(51,384	)		2,146,615
Asset retirement obligation		—			89,421		—			89,421
Other liabilities		—			12,700		—			12,700
Total liabilities		2,444,628			412,590		(401,108	)		2,456,110
(Deficit) equity		(91,820	)		2,249,707		(2,249,681	)		(91,794	)
Total liabilities and equity	$	2,352,808		$	2,662,297	$	(2,650,789	)	$	2,364,316

30

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

	December 31, 2008
	Parent		Guarantor
	Company		Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	18	$	618	$	—		$	636
Accounts and notes receivable, net		863,129		66,463		(820,519	)		109,073
Derivative contracts		201,111		—		—			201,111
Other current assets		3,194		41,899		—			45,093
Total current assets		1,067,452		108,980		(820,519	)		355,913
Property, plant and equipment, net		1,106,623		2,068,936		—			3,175,559
Investment in subsidiaries		1,002,336		—		(1,002,336	)		—
Other assets		135,161		39,809		(51,384	)		123,586
Total assets	$	3,311,572	$	2,217,725	$	(1,874,239	)	$	3,655,058
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	163,068	$	1,024,018	$	(820,519	)	$	366,567
Other current liabilities		5,106		30,951		—			36,057
Total current liabilities		168,174		1,054,969		(820,519	)		402,624
Long-term debt		2,323,458		86,710		(51,384	)		2,358,784
Asset retirement obligation		12,759		71,738		—			84,497
Other liabilities		13,660		1,942		—			15,602
Total liabilities		2,518,051		1,215,359		(871,903	)		2,861,507
Equity		793,521		1,002,366		(1,002,336	)		793,551
Total liabilities and equity	$	3,311,572	$	2,217,725	$	(1,874,239	)	$	3,655,058

31

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Condensed Consolidating Statements of Operations

	Parent			Guarantor
	Company			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Three Months Ended June 30, 2009
Revenues	$	9,588		$	124,558		$	(47	)	$	134,099
Expenses:
Direct operating expenses		5,561			87,564			(47	)		93,078
General and administrative		5,152			18,480			—			23,632
Depreciation, depletion, amortization and impairment		4,689			43,695			—			48,384
(Gain) loss on derivative contracts		(30,704	)		49,696			—			18,992
Total expenses		(15,302	)		199,435			(47	)		184,086
Income (loss) from operations		24,890			(74,877	)		—			(49,987	)
Equity earnings from subsidiaries		(75,008	)		—			75,008			—
Interest expense, net		(41,421	)		(810	)		—			(42,231	)
Other income, net		—			683			—			683
Loss before income tax benefit		(91,539	)		(75,004	)		75,008			(91,535	)
Income tax benefit		(365	)		—			—			(365	)
Net loss		(91,174	)		(75,004	)		75,008			(91,170	)
Less: net income attributable to noncontrolling interest		—			4			—			4
Net loss attributable to SandRidge Energy, Inc.	$	(91,174	)	$	(75,008	)	$	75,008		$	(91,174	)
Three Months Ended June 30, 2008
Revenues	$	104,294		$	275,013		$	(1,257	)	$	378,050
Expenses:
Direct operating expenses		20,010			97,085			(1,257	)		115,838
General and administrative		10,130			16,073			—			26,203
Depreciation, depletion, and amortization		29,007			59,029			—			88,036
Loss on derivative contracts		159,768			—			—			159,768
Total expenses		218,915			172,187			(1,257	)		389,845
(Loss) income from operations		(114,621	)		102,826			—			(11,795	)
Equity earnings from subsidiaries		103,440			—			(103,440	)		—
Interest expense, net		(20,002	)		(888	)		—			(20,890	)
Other (expense) income, net		(7	)		1,518			—			1,511
(Loss) income before income tax benefit		(31,190	)		103,456			(103,440	)		(31,174	)
Income tax benefit		(10,847	)		—			—			(10,847	)
Net (loss) income		(20,343	)		103,456			(103,440	)		(20,327	)
Less: net income attributable to noncontrolling interest		—			16			—			16
Net (loss) income attributable to SandRidge Energy, Inc.	$	(20,343	)	$	103,440		$	(103,440	)	$	(20,343	)

32

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

	Parent			Guarantor
	Company			Subsidiaries			Eliminations			Consolidated
	(In thousands)
Six Months Ended June 30, 2009
Revenues	$	58,271		$	236,946		$	(2,105	)	$	293,112
Expenses:
Direct operating expenses		27,737			143,664			(2,105	)		169,296
General and administrative		15,515			36,602			—			52,117
Depreciation, depletion, amortization and impairment		627,478			798,143			—			1,425,621
(Gain) loss on derivative contracts		(237,351	)		49,696			—			(187,655	)
Total expenses		433,379			1,028,105			(2,105	)		1,459,379
Loss from operations		(375,108	)		(791,159	)		—			(1,166,267	)
Equity earnings from subsidiaries		(791,369	)		—			791,369			—
Interest expense, net		(81,190	)		(1,778	)		—			(82,968	)
Other income, net		102			1,575			—			1,677
Loss before income tax benefit		(1,247,565	)		(791,362	)		791,369			(1,247,558	)
Income tax benefit		(1,534	)		—			—			(1,534	)
Net loss		(1,246,031	)		(791,362	)		791,369			(1,246,024	)
Less: net income attributable to noncontrolling interest		—			7			—			7
Net loss attributable to SandRidge Energy, Inc.	$	(1,246,031	)	$	(791,369	)	$	791,369		$	(1,246,031	)
Six Months Ended June 30, 2008
Revenues	$	168,610		$	480,893		$	(2,367	)	$	647,136
Expenses:
Direct operating expenses		35,523			173,700			(2,367	)		206,856
General and administrative		17,300			29,897			—			47,197
Depreciation, depletion, and amortization		51,936			119,141			—			171,077
Loss on derivative contracts		296,612			—			—			296,612
Total expenses		401,371			322,738			(2,367	)		721,742
(Loss) income from operations		(232,761	)		158,155			—			(74,606	)
Equity earnings from subsidiaries		158,081			—			(158,081	)		—
Interest expense, net		(43,610	)		(1,640	)		—			(45,250	)
Other (expense) income, net		(63	)		2,417			—			2,354
(Loss) income before income tax benefit		(118,353	)		158,932			(158,081	)		(117,502	)
Income tax benefit		(41,385	)		—			—			(41,385	)
Net (loss) income		(76,968	)		158,932			(158,081	)		(76,117	)
Less: net income attributable to noncontrolling interest		—			851			—			851
Net (loss) income attributable to SandRidge Energy, Inc.	$	(76,968	)	$	158,081		$	(158,081	)	$	(76,968	)

33

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (CONTINUED)

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantor
	Company			Subsidiaries			Eliminations		Consolidated
	(In thousands)
Six Months Ended June 30, 2009
Net cash provided by operating activities	$	104,718		$	37,264		$	—	$	141,982
Net cash used in investing activities		(240,992	)		(29,306	)		—		(270,298	)
Net cash provided by (used in) financing activities		136,418			(8,117	)		—		128,301
Net increase (decrease) in cash and cash equivalents		144			(159	)		—		(15	)
Cash and cash equivalents at beginning of period		18			618			—		636
Cash and cash equivalents at end of period	$	162		$	459		$	—	$	621
Six Months Ended June 30, 2008
Net cash (used in) provided by operating activities	$	(133,603	)	$	430,437		$	—	$	296,834
Net cash used in investing activities		(384,314	)		(401,577	)		—		(785,891	)
Net cash provided by (used in) financing activities		730,540			(28,730	)		—		701,810
Net increase in cash and cash equivalents		212,623			130			—		212,753
Cash and cash equivalents at beginning of period		62,967			168			—		63,135
Cash and cash equivalents at end of period	$	275,590		$	298		$	—	$	275,888

34

ITEM 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with our condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as our audited consolidated financial statements and the accompanying notes included in our 2008 Form 10-K.

The financial information with respect to the three and six-month periods ended June 30, 2009 and June 30, 2008 that is discussed below is unaudited. In the opinion of management, this information contains all adjustments, consisting only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Overview of Our Company

We currently generate the majority of our consolidated revenues, earnings and cash flow from the production and sale of natural gas and crude oil. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and crude oil and on our ability to find and economically develop and produce natural gas and crude oil reserves. Prices for natural gas and crude oil fluctuate widely. In order to reduce our exposure to these fluctuations, we enter into derivative commodity contracts for a portion of our anticipated future natural gas and crude oil production. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital expenditure programs.

We operate businesses that are complementary to our exploration, development and production activities. We own related gas gathering and treating facilities, a gas marketing business and an oil field services business. The extent to which each of these supplemental businesses contributes to our consolidated results of operations largely is determined by the amount of work each performs for third parties. Revenues and costs related to work performed by these businesses for our own account are eliminated in consolidation and, therefore, do not contribute to our consolidated results of operations.

Segment Overview

We operate in three business segments: exploration and production, drilling and oil field services and midstream gas services. The all other column in the tables below includes items not related to our reportable segments including our CO₂ gathering and sales operations and corporate operations. Management evaluates the performance of our business segments based on operating income, which is defined as segment operating revenue less operating expenses and depreciation, depletion and amortization. Results of these measures provide important

35

information to us about the activity and profitability of our lines of business. Set forth in the table below is financial information regarding each of our business segments (in thousands).

	Exploration and			Drilling and Oil			Midstream Gas						Consolidated
	Production			Field Services			Services			All Other			Total
Three Months Ended June 30, 2009
Revenues	$	103,727		$	55,975		$	71,838		$	6,511		$	238,051
Inter-segment revenue		(64	)		(50,877	)		(52,742	)		(269	)		(103,952	)
Total revenues	$	103,663		$	5,098		$	19,096		$	6,242		$	134,099
Operating loss	$	(5,248	)	$	(2,801	)	$	(28,030	)	$	(13,908	)	$	(49,987	)
Interest expense, net		(41,387	)		(558	)		—			(286	)		(42,231	)
Other income, net		483			—			200			—			683
Loss before income taxes	$	(46,152	)	$	(3,359	)	$	(27,830	)	$	(14,194	)	$	(91,535	)
Three Months Ended June 30, 2008
Revenues	$	293,472		$	108,720		$	219,819		$	5,653		$	627,664
Inter-segment revenue		(44	)		(96,856	)		(151,523	)		(1,191	)		(249,614	)
Total revenues	$	293,428		$	11,864		$	68,296		$	4,462		$	378,050
Operating (loss) income	$	(6,545	)	$	4,644		$	6,553		$	(16,447	)	$	(11,795	)
Interest expense, net		(19,823	)		(770	)		—			(297	)		(20,890	)
Other income (expense), net		848			(109	)		664			108			1,511
(Loss) income before income taxes	$	(25,520	)	$	3,765		$	7,217		$	(16,636	)	$	(31,174	)

	Exploration and			Drilling and Oil			Midstream Gas						Consolidated
	Production			Field Services			Services			All Other			Total
Six Months Ended June 30, 2009
Revenues	$	225,660		$	149,789		$	166,205		$	12,407		$	554,061
Inter-segment revenue		(130	)		(138,380	)		(121,695	)		(744	)		(260,949	)
Total revenues	$	225,530		$	11,409		$	44,510		$	11,663		$	293,112
Operating loss(1)	$	(1,101,110	)	$	(5,556	)	$	(27,820	)	$	(31,781	)	$	(1,166,267	)
Interest expense, net		(81,205	)		(1,191	)		—			(572	)		(82,968	)
Other income, net		1,243			—			434			—			1,677
Loss before income taxes	$	(1,181,072	)	$	(6,747	)	$	(27,386	)	$	(32,353	)	$	(1,247,558	)
Six Months Ended June 30, 2008
Revenues	$	500,438		$	188,558		$	368,054		$	11,507		$	1,068,557
Inter-segment revenue		(88	)		(164,372	)		(254,671	)		(2,290	)		(421,421	)
Total revenues	$	500,350		$	24,186		$	113,383		$	9,217		$	647,136
Operating (loss) income	$	(53,934	)	$	2,496		$	6,585		$	(29,753	)	$	(74,606	)
Interest expense, net		(43,235	)		(1,412	)		—			(603	)		(45,250	)
Other income, net		780			109			1,306			159			2,354
(Loss) income before income taxes	$	(96,389	)	$	1,193		$	7,891		$	(30,197	)	$	(117,502	)

(1) The operating loss for the exploration and production segment for the six-month period ended June 30, 2009 includes a $1,304.4 million non-cash full cost ceiling impairment on our natural gas and crude oil properties.

36

Exploration and Production Segment

The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our natural gas and crude oil production, the quantity of natural gas and crude oil we produce and changes in the fair value of commodity derivative contracts we use to reduce the volatility of the prices we receive for our natural gas and crude oil production. A three and six-month comparison of production and prices is presented in the following table:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Production data:
Natural gas (Mmcf)		22,255		21,715		46,687		40,888
Crude oil (MBbls)		722		620		1,440		1,231
Combined equivalent volumes (Mmcfe)		26,587		25,435		55,327		48,274
Average daily combined equivalent volumes (Mmcfe/d)		292		280		306		265
Average prices — as reported(1):
Natural gas (per Mcf)	$	2.95	$	10.22	$	3.41	$	9.11
Crude oil (per Bbl)(2)	$	51.79	$	113.12	$	45.13	$	101.55
Combined equivalent (per Mcfe)	$	3.88	$	11.49	$	4.05	$	10.31
Average prices — including impact of derivative contract settlements:
Natural gas (per Mcf)	$	7.07	$	7.93	$	7.40	$	8.11
Crude oil (per Bbl)(2)	$	56.01	$	99.97	$	49.85	$	93.74
Combined equivalent (per Mcfe)	$	7.44	$	9.21	$	7.54	$	9.26

(1)	Prices represent actual average prices for the periods presented and do not give effect to derivative transactions.
(2)	Includes natural gas liquids.

Exploration and Production Segment — Three months ended June 30, 2009 compared to the three months ended June 30, 2008

Exploration and production segment revenues decreased 64.7% to $103.7 million in the three months ended June 30, 2009 from $293.4 million in the three months ended June 30, 2008, as a result of a 66.2% decrease in the combined average price we received for our natural gas and crude oil production. In the three-month period ended June 30, 2009, we increased natural gas production by 0.5 Bcf to 22.2 Bcf and increased crude oil production by 102 MBbls to 722 MBbls from the comparable period in 2008. The total combined 1.2 Bcfe increase in production was primarily due to an increase in the number of producing wells in which we owned interests as a result of our successful drilling program in the Mid-Continent and West Texas area.

The average price we received for our natural gas production for the three-month period ended June 30, 2009 decreased 71.1%, or $7.27 per Mcf, to $2.95 per Mcf from $10.22 per Mcf in the comparable period in 2008. The average price received for our crude oil production decreased 54.2%, or $61.33 per barrel, to $51.79 per barrel during the three months ended June 30, 2009 from $113.12 per barrel during the same period in 2008. Including the impact of derivative contract settlements, the effective price received for natural gas for the three-month period ended June 30, 2009 was $7.07 per Mcf compared to $7.93 per Mcf during the same period in 2008. Including the impact of derivative contract settlements, the effective price received for crude oil for the three-month period ended June 30, 2009 was $56.01 per Bbl compared to $99.97 per Bbl during the same period in 2008. During 2008 and continuing into 2009, we entered into derivative contracts to mitigate the impact of commodity price fluctuations on our production through 2012. Due to the long-term nature of our investment in the development of the WTO, we enter into natural gas and crude oil swaps and natural gas basis swaps for a portion of our production in order to stabilize future cash inflows for planning purposes. Our derivative contracts are not designated as hedges and, as a

37

result, gains or losses on commodity derivative contracts are recorded as a component of operating expense. Internally, management views the settlement of such derivative contracts as adjustments to the price received for natural gas and crude oil production to determine “effective prices.”

For the three months ended June 30, 2009, we had a $5.2 million operating loss in our exploration and production segment compared to a loss of $6.5 million for the same period in 2008. The operating loss for the three months ended June 30, 2009 is attributable to a $189.7 million decrease in exploration and production revenues, partially offset by a $140.8 million decrease in the net loss on our commodity derivative positions, a $38.0 million decrease in depreciation, depletion and amortization and a $12.9 million decrease in production taxes.

During the three-month period ended June 30, 2009, the exploration and production segment reported a $19.0 million net loss on our commodity derivative positions ($113.7 million unrealized loss and $94.7 million realized gains) compared to a $159.8 million net loss on our commodity derivative positions ($101.8 million unrealized loss and $58.0 million realized losses) in the comparable period in 2008. Unrealized gains or losses on derivative contracts represent the change in fair value of open derivative contracts during the period. The unrealized loss on natural gas and crude oil derivative contracts recorded during the three months ended June 30, 2009 was attributable to an increase in average natural gas and crude oil prices at June 30, 2009 compared to the average natural gas and crude oil prices at March 31, 2009 or the contract price for contracts entered into during the second quarter of 2009.

Exploration and Production Segment — Six months ended June 30, 2009 compared to the six months ended June 30, 2008

Exploration and production segment revenues decreased 54.9% to $225.5 million in the six months ended June 30, 2009 from $500.4 million in the six months ended June 30, 2008, as a result of a 60.7% decrease in the combined average price we received for our natural gas and crude oil production. The decrease in prices received was slightly offset by a 14.6% increase in combined production volumes. In the six-month period ended June 30, 2009, we increased natural gas production by 5.8 Bcf to 46.7 Bcf and increased crude oil production by 209 MBbls to 1,440 MBbls from the comparable period in 2008. The total combined 7.1 Bcfe increase in production was primarily due to an increase in the number of producing wells in which we owned interests as a result of the successful drilling programs in the WTO and the Mid-Continent.

The average price we received for our natural gas production for the six-month period ended June 30, 2009 decreased 62.6%, or $5.70 per Mcf, to $3.41 per Mcf from $9.11 per Mcf in the comparable period in 2008. The average price received for our crude oil production decreased 55.6%, or $56.42 per barrel, to $45.13 per barrel during the six months ended June 30, 2009 from $101.55 per barrel during the same period in 2008. Including the impact of derivative contract settlements, the effective price received for natural gas for the six-month period ended June 30, 2009 was $7.40 per Mcf compared to $8.11 per Mcf during the same period in 2008. Including the impact of derivative contract settlements, the effective price received for crude oil for the six-month period ended June 30, 2009 was $49.85 per Bbl compared to $93.74 per Bbl during the same period in 2008.

For the six months ended June 30, 2009, we had a $1,101.1 million operating loss in our exploration and production segment compared to a loss of $53.9 million for the same period in 2008. The operating loss for the six months ended June 30, 2009 is attributable to a $274.8 million decrease in exploration and production revenues and a first quarter $1,304.4 million full cost ceiling impairment, partially offset by a $187.7 million net gain on our commodity derivative contracts, of which $5.5 million was an unrealized loss, a $42.8 million decrease in depreciation, depletion and amortization and a $20.7 million decrease in production taxes. The full cost ceiling impairment was the result of the decline of the future value of our reserves due to depressed natural gas and crude oil prices at March 31, 2009. No additional full cost ceiling impairment was recognized at June 30, 2009.

During the six-month period ended June 30, 2009, the exploration and production segment reported a $187.7 million net gain on our commodity derivative positions ($5.5 million unrealized loss and $193.2 million realized gains) compared to a $296.6 million net loss on our commodity derivative positions ($245.9 million unrealized loss and $50.7 million realized losses) in the same period in 2008. The unrealized loss on natural gas and crude oil derivative contracts recorded during the six months ended June 30, 2009 was attributable to an increase in average natural gas and crude oil prices at June 30, 2009 compared to the average natural gas and crude oil prices at

38

December 31, 2008 or the contract price for contracts entered into during 2009. The realized gain of $193.2 million for the six months ended June 30, 2009 was primarily due to a decline in natural gas prices at the time of settlement compared to the contract price.

Drilling and Oil Field Services Segment

The financial results of our drilling and oil field services segment depend on many factors, particularly the demand for and the price we can charge for our services. In addition to providing drilling services, our oil field services business also conducts operations that complement our drilling services such as providing pulling units, trucking, rental tools, location and road construction and roustabout services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third party working interests in wells we operate, are included in drilling and services revenue and expense while drilling and oil field service revenues earned and expenses incurred in performing services for our own account are eliminated in consolidation.

As of June 30, 2009, we owned 31 drilling rigs, of which 23 were idle, through Lariat. As Lariat’s rigs are primarily to drill for our account, there is not a significant impact to our consolidated results of operations in having this number of rigs idle. The table below presents information concerning rigs owned by Lariat:

	June 30,
	2009		2008
Rigs working for SandRidge		6		27
Rigs working for third parties		—		2
Idle rigs(1)		23		2
Total operational		29		31
Non-operational rigs		2		1
Total rigs owned		31		32

(1) Includes two rigs receiving stand-by rates from third parties at June 30, 2009.

In addition to the rigs we owned during the quarter ended June 30, 2009, we also indirectly owned eleven operational rigs through our investment in Larclay. Although our ownership in Larclay afforded us access to Larclay’s operational rigs, we did not control Larclay, and, therefore, did not consolidate the results of its operations with ours. Only the activities of our wholly owned drilling and oil field services subsidiaries are included in the financial results of our drilling and oil field services segment. On April 15, 2009, Lariat completed an assignment to CWEI of Lariat’s 50% equity interest in Larclay. Pursuant to the Larclay Assignment, Lariat assigned all of its right, title and interest in and to Larclay to CWEI effective as of April 15, 2009, and CWEI assumed all of the obligations and liabilities of Lariat relating to Larclay from and after April 15, 2009. We fully impaired our investment in and notes receivable due from Larclay at December 31, 2008. There were no additional losses on Larclay during the three or six-month periods ended June 30, 2009 or as a result of the Larclay Assignment.

Drilling and Oil Field Services Segment — Three months ended June 30, 2009 compared to the three months ended June 30, 2008

Drilling and oil field services segment revenues decreased to $5.1 million in the three-month period ended June 30, 2009 from $11.9 million in the three-month period ended June 30, 2008. This resulted in an operating loss of $2.8 million in the three-month period ended June 30, 2009 compared to operating income of $4.6 million for the same period in 2008. The decline in revenues and operating income was primarily attributable to a decrease in the number of our rigs operating and services performed for third parties as well as lower operating margins. All six of our rigs working at June 30, 2009, were working for our account, compared to 27 of our 29 working rigs working for our account at June 30, 2008. Additionally, the average daily rate received per rig working for third parties declined to an average of $9,000 per rig per working day during the three-month period ended June 30, 2009 from an average of $13,932 per rig per working day during the comparable period in 2008. We received reduced, or stand-by, rates on two of our rigs during the three-month period ended June 30, 2009.

39

Drilling and Oil Field Services Segment — Six months ended June 30, 2009 compared to the six months ended June 30, 2008

Drilling and oil field services segment revenues decreased to $11.4 million in the six-month period ended June 30, 2009 from $24.2 million in the six-month period ended June 30, 2008. This resulted in an operating loss of $5.6 million in the three-month period ended June 30, 2009 compared to operating income of $2.5 million in the same period in 2008. The decline in revenues and operating income was primarily attributable to the decrease in the number of our rigs operating and services performed for third parties as well as lower operating margins. During the six-month period ended June 30, 2009, approximately 92.4%, or $138.4 million, of our drilling and oil field service revenues were generated by work performed on our own account and eliminated in consolidation compared to approximately 87.2%, or $164.4 million, for the same period in 2008. The average daily rate received per rig working for third parties declined to an average of $10,264 per rig per working day during the six-month period ended June 30, 2009 from an average of $14,000 per rig per working day during the comparable period in 2008. During the six-month period ended June 30, 2008, one of our rigs working for a third-party was operated under a turnkey contract, while none of our rigs were operated under turnkey contracts during the six-month period ended June 30, 2009. Additionally, we received reduced, or stand-by, rates on two of our rigs during the six-month period ended June 30, 2009.

Midstream Gas Services Segment

Midstream gas services segment revenues consist mostly of gas marketing revenue, one of our largest revenue components; however, gas marketing is a very low-margin business. On a consolidated basis, midstream and marketing revenues represent natural gas sold on behalf of third parties and the fees we charge related to gathering, compressing and treating this gas. Gas marketing operating costs represent payments made to third parties for the proceeds from the sale of gas owned by such parties, net of any applicable margin and actual costs to gather, compress and treat the gas that we charge. The primary factors affecting midstream gas services are the quantity of natural gas we gather, treat and market and the prices we pay and receive for natural gas.

In June 2009, we completed the sale of our gathering and compression assets located in the Piñon Field of the WTO. Net proceeds from the sale were approximately $197.5 million, which resulted in a loss on the sale of $26.5 million. The sale of these assets is not expected to have a significant impact on our future consolidated results of operations. In conjunction with the sale, we entered into a gas gathering agreement and an operations and maintenance agreement. Under the gas gathering agreement, we have dedicated our Piñon Field acreage for priority gathering services for a period of twenty years and we will pay a fee for such services that was negotiated at arms’ length. Pursuant to the operations and maintenance agreement, we will operate and maintain the gathering system assets sold for a period of twenty years unless we or the buyer of the assets chooses to terminate the agreement.

Midstream Gas Services Segment — Three months ended June 30, 2009 compared to the three months ended June 30, 2008

Midstream gas services segment revenues for the three months ended June 30, 2009 were $19.1 million compared to $68.3 million in the comparable period of 2008. The quarterly decrease in midstream gas services revenues was attributable to a 68.3% decrease in natural gas prices received in the three-month period ended June 30, 2009 compared to the same period in 2008. Operating costs decreased in proportion to revenues due to the decrease in natural gas prices paid in the three-month period ended June 30, 2009 compared to the same period in 2008. Profit margin for the three-month period ended June 30, 2009 was 6.1% compared to a profit margin of 6.8% for the same period in 2008. The net loss of $27.8 million for the three months ended June 30, 2009 was primarily attributable to the loss on the sale of our gathering and compression assets in the Piñon Field.

40

Midstream Gas Services Segment — Six months ended June 30, 2009 compared to the six months ended June 30, 2008

Midstream gas services segment revenues for the six months ended June 30, 2009 were $44.5 million compared to $113.4 million in the comparable period of 2008. The decrease in midstream gas services revenues was attributable to a 60.8% decrease in natural gas prices received in the six-month period ended June 30, 2009 compared to the same period in 2008. Midstream operating costs decreased in proportion to revenue based on the decrease in natural gas prices paid in the six-month period ended June 30, 2009 compared to the same period in 2008. Profit margin for the six-month period ended June 30, 2009 was 8.3% compared to a profit margin of 9.3% for the same period in 2008. The net loss of $27.4 million for the six-month period ended June 30, 2009 compared to net income of $7.9 million for the same period in 2008 is primarily attributable to the loss on the sale of our gathering and compression assets in the Piñon Field in 2009.

Results of Operations — Consolidated

Three months ended June 30, 2009 compared to the three months ended June 30, 2008

Revenues.  Total revenues decreased 64.5% to $134.1 million for the three months ended June 30, 2009 from $378.1 million in the same period in 2008. This decrease was primarily due to a $189.1 million decrease in natural gas and crude oil sales combined with decreases in midstream and marketing revenues. The table below presents a comparison of revenues for the three-month periods ended June 30, 2009 and 2008.

	Three Months Ended
	June 30,
	2009		2008		$ Change			% Change
	(In thousands)
Revenues:
Natural gas and crude oil	$	103,039	$	292,134	$	(189,095	)		(64.7	)%
Drilling and services		5,176		11,957		(6,781	)		(56.7	)%
Midstream and marketing		19,642		69,488		(49,846	)		(71.7	)%
Other		6,242		4,471		1,771			39.6	%
Total revenues	$	134,099	$	378,050	$	(243,951	)		(64.5	)%

Total natural gas and crude oil revenues decreased $189.1 million to $103.0 million for the three months ended June 30, 2009 compared to $292.1 million for the same period in 2008. The decrease was primarily attributable to a decrease in prices received for our natural gas and crude oil production. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production decreased 66.2% in the 2009 period to $3.88 per Mcfe compared to $11.49 per Mcfe in 2008.

Drilling and services revenues decreased 56.7% to $5.2 million for the three months ended June 30, 2009 compared to $12.0 million in the same period in 2008. The decline in revenues was due to the decrease in rigs operating for and services provided to third parties combined with the decline in the average daily rate received per rig working for third parties.

Midstream and marketing revenues decreased $49.8 million, or 71.7%, with revenues of $19.6 million in the three-month period ended June 30, 2009 compared to $69.5 million in the three-month period ended June 30, 2008. The quarterly decrease in midstream gas services revenues was primarily attributable to the decrease in natural gas prices for third party volumes we marketed in the three-month period ended June 30, 2009 compared to the same period in 2008.

Other revenue increased to $6.2 million for the three months ended June 30, 2009 from $4.5 million for the same period in 2008 due to higher CO₂ volumes sold to third parties for the three months ended June 30, 2009. Other revenue was generated primarily by our CO₂ gathering and sales operations.

41

Operating Costs and Expenses.  Total operating costs and expenses decreased to $184.1 million for the three months ended June 30, 2009 compared to $389.8 million for the same period in 2008. The decrease was primarily due to decreases in production taxes, midstream and marketing, depreciation, depletion and amortization (“DD&A”) and loss on derivative contracts. The table below presents a comparison of operating costs and expenses for the three-month periods ended June 30, 2009 and 2008.

	Three Months Ended
	June 30,
	2009		2008			$ Change			% Change
	(In thousands)
Operating costs and expenses:
Production	$	41,450	$	40,254		$	1,196			3.0	%
Production taxes		593		13,519			(12,926	)		(95.6	)%
Drilling and services		6,415		5,066			1,349			26.6	%
Midstream and marketing		18,450		64,733			(46,283	)		(71.5	)%
Depreciation, depletion and amortization — natural gas and crude oil		34,350		72,256			(37,906	)		(52.5	)%
Depreciation, depletion and amortization — other		14,034		15,780			(1,746	)		(11.1	)%
General and administrative		23,632		26,203			(2,571	)		(9.8	)%
Loss on derivative contracts		18,992		159,768			(140,776	)		(88.1	)%
Loss (gain) on sale of assets		26,170		(7,734	)		33,904			(438.4	)%
Total operating costs and expenses	$	184,086	$	389,845		$	(205,759	)		(52.8	)%

Production expenses include the costs associated with our exploration and production activities, including, but not limited to, lease operating expenses and treating costs. The increase in production expense is attributable to an increase in the number of wells in which we owned an interest during the quarter and increased production volumes for the quarter. In the three-month period ended June 30, 2009, we increased natural gas production by 0.5 Bcf to 22.2 Bcf and increased crude oil production by 102 MBbls to 722 MBbls from the comparable period in 2008. Production taxes decreased $12.9 million, or 95.6%, to $0.6 million primarily due to severance tax refunds received in 2009 and the decreased prices received for production during the three months ended June 30, 2009.

Drilling and services expenses, which includes operating expenses attributable to the drilling and oil field services segment and our CO₂ services companies, increased 26.6% for the three months ended June 30, 2009 compared to the same period in 2008. The increase was primarily due to less rig activity and lower profit margins in 2009. This resulted in less costs being eliminated by intercompany activity.

Midstream and marketing expenses decreased $46.3 million, or 71.5%, to $18.5 million due to lower natural gas prices paid for natural gas that we sold on behalf of third parties during the three months ended June 30, 2009 than during the comparable period in 2008.

DD&A for our natural gas and crude oil properties decreased to $34.4 million for the three months ended June 30, 2009 from $72.3 million for the same period in 2008. Our DD&A per Mcfe decreased $1.55 to $1.29 in the second quarter of 2009 from $2.84 in the comparable period in 2008 as a result of the cumulative $3,159.4 million full cost ceiling impairment, which reduced the carrying value of our natural gas and crude oil properties. Of the cumulative impairment, $1,855.0 million was incurred at December 31, 2008 and $1,304.4 million was incurred at March 31, 2009. See Note 5 of Notes to the Condensed Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding the full cost ceiling impairment.

DD&A for our other assets consists primarily of depreciation of our drilling rigs, midstream gathering and compression facilities and other equipment. The decrease in DD&A for our other assets was attributable primarily to a change in asset lives of certain of our drilling, oil field services, midstream and other assets to align with

42

industry average lives for similar assets. We calculate depreciation of property and equipment using the straight-line method over the estimated useful lives of the assets, which range from 3 to 39 years.

General and administrative expenses decreased $2.6 million to $23.6 million for the three months ended June 30, 2009 from $26.2 million for the comparable period in 2008. The decrease was principally attributable to higher professional services and fees for the three months ended June 30, 2008 related to audit, consulting and legal fees. General and administrative expenses included non-cash stock compensation expense of $4.6 million, net of amounts capitalized, for the three months ended June 30, 2009 compared to $4.1 million for the comparable period in 2008. Salaries and wages and stock compensation were reduced by $5.4 million in capitalized general and administrative expenses, which included $0.8 million of capitalized stock compensation expense, for the three months ended June 30, 2009 compared to $4.3 million for the three months ended June 30, 2008.

We recorded a net loss of $19.0 million ($113.7 million unrealized loss and $94.7 million realized gains) on our commodity derivative contracts for the three months ended June 30, 2009 compared to a $159.8 million net loss ($101.8 million unrealized loss and $58.0 million realized losses) for the same period in 2008. The unrealized loss recorded in the second quarter of 2009 was attributable to an increase in average natural gas prices at June 30, 2009 compared to average natural gas prices at March 31, 2009 or the contract date for contracts entered into during the second quarter of 2009.

The loss on sale of assets for the three months ended June 30, 2009 was primarily due to the $26.5 million loss on the sale of our gathering and compression assets located in the Piñon Field. For the three months ended June 30, 2008, a gain of approximately $7.5 million was recognized on the sale of our assets located in the Piceance Basin of Colorado.

Other Income (Expense).  Total other expense increased to $41.5 million in the three-month period ended June 30, 2009 from $19.4 million in the three-month period ended June 30, 2008. The increase is reflected in the table below.

	Three Months Ended
	June 30,
	2009			2008			$ Change			% Change
	(In thousands)
Other income (expense):
Interest income	$	188		$	1,333		$	(1,145	)		(85.9	)%
Interest expense		(42,419	)		(22,223	)		(20,196	)		90.9	%
Income from equity investments		200			556			(356	)		(64.0	)%
Other income, net		483			955			(472	)		(49.4	)%
Total other (expense) income		(41,548	)		(19,379	)		(22,169	)		114.4	%
Loss before income tax benefit		(91,535	)		(31,174	)		(60,361	)		193.6	%
Income tax benefit		(365	)		(10,847	)		10,482			(96.6	)%
Net loss	$	(91,170	)	$	(20,327	)	$	(70,843	)		348.5	%

Interest income decreased to $0.2 million for the three months ended June 30, 2009 from $1.3 million for the same period in 2008. This decrease was generally due to lower excess cash levels during the three months ended June 30, 2009 compared to the same period in 2008.

Interest expense increased to $42.4 million for the three months ended June 30, 2009 from $22.2 million for the same period in 2008. This increase was primarily attributable to the higher average debt balances outstanding during the three months ended June 30, 2009, which was slightly offset by the net gain of $2.6 million on our interest rate swap. Also contributing to the increase was a $9.6 million unrealized gain on our interest rate swap which reduced interest expense for the three months ended June 30, 2008.

We reported an income tax benefit of $0.4 million for the three months ended June 30, 2009, compared to a benefit of $10.9 million for the same period in 2008. The current period income tax benefit represents an effective income tax rate of 0.4% compared to an effective income tax rate of 34.8% in the same period in 2008. The lower

43

effective income tax rate associated with the current period loss before income taxes was primarily a result of not recording a tax benefit for the loss due to our full valuation allowance on our net deferred tax asset.

Six months ended June 30, 2009 compared to the six months ended June 30, 2008

Revenues.  Total revenues decreased 54.7% to $293.1 million for the six months ended June 30, 2009 from $647.1 million for the same period in 2008. This decrease was primarily due to a $273.3 million decrease in natural gas and crude oil sales and a decrease in midstream and marketing revenues. The table below presents a comparison of revenues for the six-month periods ended June 30, 2009 and 2008.

	Six Months Ended
	June 30,
	2009		2008		$ Change			% Change
	(In thousands)
Revenues:
Natural gas and crude oil	$	224,280	$	497,621	$	(273,341	)		(54.9	)%
Drilling and services		11,571		24,291		(12,720	)		(52.4	)%
Midstream and marketing		45,598		115,897		(70,299	)		(60.7	)%
Other		11,663		9,327		2,336			25.0	%
Total revenues	$	293,112	$	647,136	$	(354,024	)		(54.7	)%

Natural gas and crude oil revenues decreased $273.3 million to $224.3 million for the six months ended June 30, 2009 compared to $497.6 million for the same period in 2008, primarily as a result of a decrease in prices received for our natural gas and crude oil production, which was slightly offset by an increase in the natural gas and crude oil produced. The average price received, excluding the impact of derivative contracts, for our natural gas and crude oil production decreased 60.7% in the 2009 period to $4.05 per Mcfe compared to $10.31 per Mcfe in 2008. Total natural gas production increased 14.2% to 46.7 Bcf in 2009 compared to 40.9 Bcf in 2008, while crude oil production increased 17.0% to 1,440 MBbls in 2009 from 1,231 MBbls in 2008.

Drilling and services revenues decreased 52.4% to $11.6 million for the six months ended June 30, 2009 compared to $24.3 million for the same period in 2008. The decline in revenues was due to the decrease in rigs operating for and services provided to third parties and the decline in the average daily rate received per rig working for third parties.

Midstream and marketing revenues decreased $70.3 million, or 60.7%, with revenues of $45.6 million in the six-month period ended June 30, 2009 compared to $115.9 million in the six-month period ended June 30, 2008. The decrease was attributable to the decrease in prices for natural gas that we sold on behalf of third parties in the six-month period ended June 30, 2009 compared to the same period in 2008.

Other revenue increased to $11.7 million for the six months ended June 30, 2009 from $9.3 million for the same period in 2008. Other revenue was generated primarily by our CO₂ gathering and sales operations.

Operating Costs and Expenses.  Total operating costs and expenses increased to $1,459.4 million for the six months ended June 30, 2009 compared to $721.7 million for the same period in 2008. The increase was primarily due to a first quarter 2009 full cost ceiling impairment and increases in production and general and administrative expenses. These increases were partially offset by decreases in production taxes, midstream and marketing and

44

DD&A and an increase in realized gains on derivative contracts. The table below presents a comparison of operating costs and expenses for the six-month periods ended June 30, 2009 and 2008.

	Six Months Ended
	June 30,
	2009			2008			$ Change			% Change
	(In thousands)
Operating costs and expenses:
Production	$	87,029		$	74,442		$	12,587			16.9	%
Production taxes		2,084			22,739			(20,655	)		(90.8	)%
Drilling and services		12,021			12,235			(214	)		(1.7	)%
Midstream and marketing		41,812			105,151			(63,339	)		(60.2	)%
Depreciation, depletion, and amortization — natural gas and crude oil		94,443			137,332			(42,889	)		(31.2	)%
Depreciation, depletion and amortization — other		26,760			33,745			(6,985	)		(20.7	)%
Impairment		1,304,418			—			1,304,418			100.0	%
General and administrative		52,117			47,197			4,920			10.4	%
(Gain) loss on derivative contracts		(187,655	)		296,612			(484,267	)		(163.3	)%
Loss (gain) on sale of assets		26,350			(7,711	)		34,061			(441.7	)%
Total operating costs and expenses	$	1,459,379		$	721,742		$	737,637			102.2	%

Production expenses increased $12.6 million primarily due to an increase in the number of wells in which we own an interest and increased production volumes. In the six-month period ended June 30, 2009, we increased natural gas production by 5.8 Bcf to 46.7 Bcf and increased crude oil production by 209 MBbls to 1,440 MBbls from the comparable period in 2008. Production taxes decreased $20.7 million, or 90.8%, to $2.1 million. The decrease was primarily due to severance tax refunds received in 2009 and the decreased prices received for production during the six months ended June 30, 2009.

Midstream and marketing expenses decreased $63.3 million, or 60.2%, to $41.8 million due to lower prices paid for natural gas that we sold on behalf of third parties during the six months ended June 30, 2009 than during the comparable period in 2008.

DD&A for our natural gas and crude oil properties decreased to $94.4 million for the six months ended June 30, 2009 from $137.3 million during the same period in 2008. Our average DD&A per Mcfe decreased $1.14 to $1.71 in the first six months of 2009 from $2.85 for the comparable period in 2008 as a result of the $3,159.4 million cumulative full cost ceiling impairment, which reduced the carrying value of our natural gas and crude oil properties. The effect of the decrease in DD&A per Mcfe was slightly offset by the 14.6% increase in production during the first six months of 2009 compared to the same period in 2008.

DD&A for our other assets consists primarily of depreciation of our drilling rigs, midstream gathering and compression facilities and other equipment. The decrease in DD&A for our other assets was attributable primarily to the change in asset lives of certain of our drilling, oil field services, midstream and other assets to align with industry average lives for similar assets.

General and administrative expenses increased $4.9 million to $52.1 million for the six months ended June 30, 2009 from $47.2 million for the comparable period in 2008. The increase was principally attributable to an increase in corporate salaries and wages, including non-cash stock compensation expense. The increase in corporate salaries was primarily due to the increase in the average number of corporate and support staff employed during the six months ended June 30, 2009 compared to the same period in 2008. General and administrative expenses included non-cash stock compensation expense, net of amounts capitalized, of $9.4 million for the six months ended June 30, 2009 compared to $7.3 million for the comparable period in 2008. The increases in salaries and wages and stock compensation were partially offset by $12.9 million in capitalized general and administrative expenses, which

45

included $2.0 million of capitalized stock compensation expense, for the six months ended June 30, 2009 compared to $7.5 million for the six months ended June 30, 2008.

We recorded a net gain of $187.7 million ($5.5 million unrealized loss and $193.2 million realized gains) on our commodity derivatives contracts for the six months ended June 30, 2009 compared to a $296.6 million net loss ($245.9 million unrealized loss and $50.7 million realized losses) for the same period in 2008. The unrealized loss recorded in 2009 was attributable to an increase in average natural gas prices at June 30, 2009 compared to average natural gas prices at December 31, 2008 or the contract date for contracts entered into during 2009. The realized gains of $193.2 million for the six months ended June 30, 2009 were primarily due to a decline in natural gas prices at the time of settlement compared to the contract price.

The loss on sale of assets for the six months ended June 30, 2009 was primarily due to the $26.5 million loss on the sale of our gathering and compression assets in the Piñon Field. For the six months ended June 30, 2008, the gain on sale of assets of $7.7 million was attributable to the approximately $7.5 million gain on the sale of our assets located in the Piceance Basin of Colorado.

Other Income (Expense).  Total other expense increased to $81.3 million in the six-month period ended June 30, 2009 from $42.9 million in the six-month period ended June 30, 2008. The increase is reflected in the table below.

	Six Months Ended
	June 30,
	2009			2008			$ Change			% Change
	(In thousands)
Other income (expense):
Interest income	$	199		$	2,145		$	(1,946	)		(90.7	)%
Interest expense		(83,167	)		(47,395	)		(35,772	)		75.5	%
Income from equity investments		434			1,415			(981	)		(69.3	)%
Other income, net		1,243			939			304			32.4	%
Total other (expense) income		(81,291	)		(42,896	)		(38,395	)		89.5	%
Loss before income tax benefit		(1,247,558	)		(117,502	)		(1,130,056	)		961.7	%
Income tax benefit		(1,534	)		(41,385	)		39,851			(96.3	)%
Net loss	$	(1,246,024	)	$	(76,117	)	$	(1,169,907	)		1,537.0	%

Interest income decreased to $0.2 million for the six months ended June 30, 2009 from $2.1 million for the same period in 2008. The decrease was generally due to lower excess cash levels during the six months ended June 30, 2009 compared to the same period in 2008.

Interest expense increased to $83.2 million for the six months ended June 30, 2009 from $47.4 million for the same period in 2008. This increase was attributable to the higher average debt balances outstanding during the six months ended June 30, 2009. Also contributing to the increase was a $10.4 million unrealized gain related to our interest rate swap which reduced interest expense for the six months ended June 30, 2008.

We reported an income tax benefit of $1.5 million for the six months ended June 30, 2009, compared to a benefit of $41.4 million for the same period in 2008. The current period income tax benefit represents an effective income tax rate of 0.1% compared to an effective income tax rate of 35.0% for the same period in 2008. The lower effective income tax rate associated with the current period loss before income taxes was primarily a result of not recording a tax benefit for the loss due to our full valuation allowance on our net deferred tax asset.

Liquidity and Capital Resources

We historically have funded our capital requirements through a combination of cash flow generated from operations, borrowings under our senior credit facility, the issuance of equity and debt securities and, to a lesser extent, the sale of assets. During the first six months of 2009, our primary sources of cash were cash flow generated from operations, borrowings under our senior credit facility, proceeds from the issuance of convertible perpetual

46

preferred stock and common stock, proceeds from the issuance of our 9.875% Senior Notes, proceeds from the sale of gathering and compression assets related to our midstream operations in the Piñon Field and proceeds from the sale of our drilling rights in East Texas below the depth of the Cotton Valley formation. Our primary uses of cash during the first six months of 2009 were capital expenditures related to the development of our natural gas and crude oil properties and other fixed assets and the repayment of amounts outstanding on our senior credit facility.

Our cash flows for the six months ended June 30, 2009 and 2008 are presented in the following table and discussed below:

	Six Months Ended
	June 30,
	2009			2008
	(In thousands)
Cash flows provided by operating activities	$	141,982		$	296,834
Cash flows used in investing activities		(270,298	)		(785,891	)
Cash flows provided by financing activities		128,301			701,810
Net (decrease) increase in cash and cash equivalents	$	(15	)	$	212,753

Cash Flows from Operations

Our operating cash flow is mainly influenced by the prices we receive for our natural gas and crude oil production; the quantity of natural gas we produce and, to a lesser extent, the quantity of crude oil we produce; the demand for our drilling rigs and oil field services and the rates we are able to charge for these services; and the margins we obtain from our natural gas and CO₂ gathering and treating contracts.

Net cash provided by operating activities for the six months ended June 30, 2009 and 2008 was $142.0 million and $296.8 million, respectively. The decrease in cash provided by operating activities in 2009 compared to 2008 was primarily due to a 60.7% decrease in the combined average prices we received for our natural gas and crude oil production for the six months ended June 30, 2009. Decreases in midstream and marketing revenues also contributed to the decrease in operating cash flows.

Cash Flows from Investing

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration, development, production and acquisition of natural gas and crude oil reserves. These capital expenditures are necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive natural gas and crude oil industry. Net cash used in investing activities, which included capital expenditures for property, plant and equipment, for the six months ended June 30, 2009 and 2008 was $270.3 million and $785.9 million, respectively.

During the first six months of 2009 and 2008, our capital expenditures, on an accrual basis, by segment were:

	Six Months Ended
	June 30,
	2009		2008
	(In thousands)
Capital Expenditures:
Exploration and production	$	383,231	$	813,900
Drilling and oil field services		2,201		35,791
Midstream gas services		41,288		69,429
Other		17,764		15,181
Total	$	444,484	$	934,301

Capital expenditures decreased $489.8 million to $444.5 million for the six months ended June 30, 2009 compared to $934.3 million for the same period in 2008 due to our decreased drilling activities. Cash outflows from capital expenditures in the first six months of 2009 were partially offset by approximately $254.0 million in

47

combined proceeds from the sale of our gathering and compression assets located in the Piñon Field and our deep drilling rights in East Texas. Cash outflows from capital expenditures in the first six months of 2008 were partially offset by approximately $147.2 million in proceeds from the sale of our assets located in the Piceance Basin of Colorado.

Cash Flows from Financing

Our financing activities provided $128.3 million in cash for the six-month period ended June 30, 2009 compared to $701.8 million for the same period in 2008. Proceeds from borrowings, including the senior notes described below, were $1,431.8 million for the six months ended June 30, 2009 compared to $1,408.0 million for the same period in 2008. Repayments of approximately $1,645.3 million resulted in net repayments during the six-month period ended June 30, 2009 of approximately $213.5 million. Repayments of $665.6 million during the first six months of 2008 resulted in net borrowings during the period of $742.4 million. Additionally, the issuance of our 8.5% convertible perpetual preferred stock and 14,480,000 shares of common stock provided additional net proceeds of $243.3 million and $107.7 million, respectively, during the six months ended June 30, 2009.

Long-Term Debt Issuances and Repayments

Senior Credit Facility.  As a result of net repayments of $555.5 million during the first six months of 2009, we had total outstanding indebtedness of $18.0 million under our senior credit facility as of June 30, 2009. The amount we may borrow under the facility is limited to a borrowing base amount, which is currently $985.4 million, and is subject to periodic redeterminations. The borrowing base is available to be drawn on and repaid so long as we are in compliance with its terms, including certain financial covenants. The borrowing base is determined based upon proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves. Our ability to develop properties and changes in commodity prices may affect the borrowing base of our senior credit facility. Based on the April 2009 redetermination, our borrowing base remained unchanged from the previous determination of $1.1 billion; however, the borrowing base was reduced to $985.4 million as a result of our issuance of the 9.875% Senior Notes in May 2009. The average annual interest rate paid on amounts outstanding under our senior credit facility was 2.28% for the six months ended June 30, 2009. Our senior credit facility matures on November 21, 2011.

9.875% Senior Notes Due 2016.  In May 2009, we completed a private placement of $365.5 million of unsecured 9.875% Senior Notes to qualified institutional investors eligible under Rule 144A of the Securities Act. These notes were issued at a discount which will be amortized into interest expense over the term of the notes. Net proceeds from the offering were approximately $342.2 million after deducting the discount and offering expenses of $7.8 million. We used the net proceeds from the offering to repay outstanding borrowings under our senior credit facility and for general corporate purposes. The notes bear interest at a fixed rate of 9.875% per annum, payable semi-annually, with the principal due on May 15, 2016. We may redeem the notes, in whole or in part, prior to their maturity at specified redemption prices. The notes are jointly and severally, unconditionally guaranteed on an unsecured basis by all of the Company’s wholly owned subsidiaries, except certain minor subsidiaries, and will become freely tradable 180 days after their issuance pursuant to Rule 144 under the Securities Act.

8.0% Senior Notes Due 2018.  In May 2008, we received approximately $735.0 million net proceeds from the issuance of $750.0 million of unsecured 8.0% Senior Notes due 2018. The notes bear interest at a fixed rate of 8.0% per annum, payable semi-annually, with the principal due on June 1, 2018. The notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices. The notes became freely tradable on November 17, 2008, 180 days after their issuance, pursuant to Rule 144 under the Securities Act.

Preferred and Common Stock Issuances

8.5% Convertible Perpetual Preferred Stock.  In January 2009, we completed a private placement of 2,650,000 shares of 8.5% convertible perpetual preferred stock to qualified institutional buyers eligible under Rule 144A under the Securities Act. The offering included 400,000 shares of convertible perpetual preferred stock issued upon the full exercise of the initial purchasers’ option to cover over-allotments. Net proceeds from the offering were approximately $243.3 million after deducting offering expenses of approximately $8.6 million. We

48

used the net proceeds of the offering to repay outstanding borrowings under our senior credit facility and for general corporate purposes.

Each share of 8.5% convertible perpetual preferred stock has a liquidation preference of $100 and is convertible at the holder’s option at any time initially into approximately 12.4805 shares of our common stock, subject to adjustments upon the occurrence of certain events. Each holder of the convertible perpetual preferred stock is entitled to an annual dividend of $8.50 per share to be paid semi-annually in cash, common stock or a combination thereof at our election with the first dividend payment due in February 2010. The convertible perpetual preferred stock is not redeemable by us at any time. After February 20, 2014, we may cause all outstanding shares of the convertible perpetual preferred stock to automatically convert into common stock at the then-prevailing conversion rate if certain conditions are met.

Common Stock.  On April 29, 2009, we completed a registered underwritten offering of 14,480,000 shares of our common stock, including 2,280,000 shares of common stock acquired by the underwriters from us to cover over-allotments. Net proceeds from the offering were approximately $107.7 million after deducting offering expenses of approximately $2.3 million and were used to repay a portion of the amount outstanding under our senior credit facility and for general corporate purposes.

Outlook

We have budgeted a range of $500.0 million to $700.0 million for capital expenditures, excluding acquisitions, for the year ending December 31, 2009. The majority of our planned capital expenditures are discretionary and could be curtailed if our cash flows decline from expected levels or we are unable to obtain capital on attractive terms. We may increase or decrease planned capital expenditures depending on natural gas prices, asset sales and the availability of capital through the issuance of additional long-term debt or equity. Additionally, we have entered into interest rate swaps as well as fixed-price swaps and basis swaps for a portion of our production through 2012 in order to stabilize future cash flows for planning purposes. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk” for additional information regarding our derivative contracts.

As of June 30, 2009, our cash and cash equivalents were $0.6 million and we had approximately $2.2 billion in total debt outstanding. Amounts outstanding under our senior credit facility at June 30, 2009 totaled $18.0 million. As of June 30, 2009, we were in compliance with all of the covenants under all of our senior notes and our senior credit facility. See Note 8 of Notes to the Condensed Consolidated Financial Statements included in “Item 1. Financial Statements” for additional information regarding our long-term debt. As of July 31, 2009, our cash and cash equivalents were approximately $83.2 million, the balance outstanding under our senior credit facility was $124.6 million and we had $30.5 million in outstanding letters of credit.

If future capital expenditures exceed operating cash flow and cash on hand, funds would likely be supplemented as needed by borrowings under our senior credit facility. We may choose to refinance borrowings outstanding under the facility by issuing long-term debt or equity in the public or private markets, or both.

Debt and equity capital markets experienced adverse conditions during the latter part of 2008 and into 2009. Continued volatility in the capital markets may increase costs associated with issuing debt due to increased interest rates, and may affect our ability to access these markets. Currently, we do not believe our liquidity has been, or in the near future will be, materially affected by recent events in the global financial markets. Nevertheless, we continue to monitor events and circumstances surrounding each of the 27 lenders under our senior credit facility. To date, the only disruption to our ability to access the full amounts available under our senior credit facility was the bankruptcy of Lehman Brothers, a lender responsible for 0.29% of the obligations under our senior credit facility. The largest commitment from any lender under the senior credit facility is 6.6% of the total amount available under the facility. We cannot predict with any certainty the impact to us of any further disruptions in the credit markets.

Contractual Obligations

Gas Gathering Agreement.  In conjunction with the sale of our gathering and compression assets located in the Piñon Field of the WTO, we entered into a gas gathering agreement. Under the gas gathering agreement, we

49

have dedicated our Piñon Field acreage for priority gathering services over a period of twenty years and we will pay a fee that was negotiated at arms’ length for such services. Pursuant to the gas gathering agreement, the base fee can be reduced if certain criteria are met. The table below presents our contractual obligations under this agreement.

	Payments Due
	(In thousands)
2009	$	7,584
2010		22,226
2011		33,780
2012		42,814
2013		42,634
After 2013		327,749
	$	476,787

Long-Term Debt.  We issued our 9.875% Senior Notes in May 2009. This debt issuance along with the pay down of the outstanding balance on the senior credit are discussed further under “Long-Term Debt Issuances and Repayments” above.

ITEM 3.   Quantitative and Qualitative Disclosures About Market Risk

General

The discussion in this section provides information about the financial instruments we use to manage commodity prices and interest rate volatility. All contracts are settled in cash and do not require the actual delivery of a commodity at settlement.

Commodity Price Risk.  Our most significant market risk relates to the prices we receive for our natural gas and crude oil production. Due to the historical volatility of these commodities, we periodically have entered into, and expect in the future to enter into, derivative arrangements for the purpose of reducing the variability of natural gas and crude oil prices we receive for our production. From time to time, we enter into commodity pricing derivative contracts for a portion of our anticipated production volumes depending upon management’s view of opportunities under the then current market conditions. We do not intend to enter into derivative contracts that would exceed our expected production volumes for the period covered by the derivative arrangement. Our current credit agreement limits our ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves. Future credit agreements could require a minimum level of commodity price hedging.

The use of derivative contracts also involves the risk that the counterparties will be unable to meet their obligations under the contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. As of June 30, 2009, we had eighteen approved derivative counterparties, seventeen of which are lenders under our senior credit facility. We currently have derivative contracts outstanding with twelve of these counterparties, including Lehman Brothers. We have no derivative contracts in 2009 and beyond with counterparties other than those that are lenders under our senior credit facility. Lehman Brothers is a counterparty on one of our derivative contracts. Due to the bankruptcy of Lehman Brothers and its parent, Lehman Brothers Holdings Inc., we did not assign any value to this derivative contract (notional amount of 3,680 MMcf) at June 30, 2009.

We use, and may continue to use, a variety of commodity-based derivative contracts, including collars, fixed-price swaps and basis protection swaps. Our fixed price swap transactions are settled based upon NYMEX prices, and our basis protection swap transactions are settled based upon the index price of natural gas at the Waha hub, a West Texas gas marketing and delivery center and the Houston Ship Channel. Settlement for natural gas derivative contracts occurs in the production month.

We have not designated any of our derivative contracts as hedges for accounting purposes. We record all derivative contracts on the balance sheet at fair value, which reflects changes in natural gas and crude oil prices. We establish fair value of our derivative contracts by price quotations obtained from counterparties to the derivative contracts. Changes in fair values of our derivative contracts are recognized as unrealized gains and losses in current

50

period earnings. As a result, our current period earnings may be significantly affected by changes in fair value of our commodities derivative contracts. Changes in fair value are principally measured based on period-end prices compared to the contract price.

At June 30, 2009, our open natural gas and crude oil commodity derivative contracts consisted of the following:

Natural Gas

	Notional		Weighted Avg.
Period and Type of Contract	(MMcf)(1)		Fixed Price
July 2009 — September 2009
Price swap contracts		18,710	$	8.09
Basis swap contracts		15,640	$	(0.74	)
October 2009 — December 2009
Price swap contracts		19,010	$	8.46
Basis swap contracts		15,640	$	(0.74	)
January 2010 — March 2010
Price swap contracts		20,475	$	7.95
Basis swap contracts		20,250	$	(0.74	)
April 2010 — June 2010
Price swap contracts		19,793	$	7.32
Basis swap contracts		20,475	$	(0.74	)
July 2010 — September 2010
Price swap contracts		20,010	$	7.55
Basis swap contracts		20,700	$	(0.74	)
October 2010 — December 2010
Price swap contracts		20,010	$	7.97
Basis swap contracts		20,700	$	(0.74	)
January 2011 — March 2011
Basis swap contracts		25,650	$	(0.47	)
April 2011 — June 2011
Basis swap contracts		25,935	$	(0.47	)
July 2011 — September 2011
Basis swap contracts		26,220	$	(0.47	)
October 2011 — December 2011
Basis swap contracts		26,220	$	(0.47	)
January 2012 — March 2012
Basis swap contracts		20,020	$	(0.54	)
April 2012 — June 2012
Basis swap contracts		20,020	$	(0.54	)
July 2012 — September 2012
Basis swap contracts		20,240	$	(0.54	)
October 2012 — December 2012
Basis swap contracts		20,240	$	(0.54	)

(1) Assumes ratio of 1:1 for Mcf to MMBtu and excludes a total notional of 3,680 MMcf from 2009 contracts for the Lehman Brothers’ basis swap contract.

51

Crude Oil

	Notional		Weighted Avg.
Period and Type of Contract	(in MBbls)		Fixed Price
July 2009 — September 2009
Price swap contracts		46	$	126.61
October 2009 — December 2009
Price swap contracts		46	$	126.51

The following table summarizes the cash settlements and valuation gains and losses on our commodity derivative contracts for the six months ended June 30, 2009 and 2008 (in thousands):

	Six Months Ended
	June 30,
	2009			2008
Realized (gain) loss	$	(193,136	)	$	50,674
Unrealized loss		5,481			245,938
(Gain) loss on derivative contracts	$	(187,655	)	$	296,612

Credit Risk.  A portion of our liquidity is concentrated in derivative contracts that enable us to mitigate a portion of our exposure to natural gas and crude oil prices and interest rate volatility. We periodically review the credit quality of each counterparty to our derivative contracts and the level of financial exposure we have to each counterparty to limit our credit risk exposure with respect to these contracts. Additionally, we apply a credit default risk rating factor for our counterparties in determining the fair value of our derivative contracts.

Our ability to fund our capital expenditure budget is partially dependent upon the availability of funds under our senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in our senior credit facility, our bank group consists of 27 financial institutions with commitments ranging from 0.25% to 6.6%. Lehman Brothers, a lender under our senior credit facility, declared bankruptcy on October 3, 2008. As a result of the bankruptcy of Lehman Brothers and its parent company, Lehman Brothers Holdings Inc., on September 15, 2008, Lehman Brothers elected not to fund its pro rata share, or 0.29%, of borrowings requested by us under the facility. Although we do not currently expect this reduced amount available under the senior credit facility to impact our liquidity or business operations, the inability of one or more of our other lenders to fund their obligations under the facility could have a material adverse effect on our financial condition.

Interest Rate Risk.  We are subject to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that we may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes us to short-term changes in market interest rates as our interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.

In addition to commodity price derivative arrangements, we may enter into derivative transactions to fix the interest we pay on a portion of the money we borrow under our credit agreement. In January 2008, we entered into a $350.0 million notional amount interest rate swap agreement with a financial institution that effectively fixed the interest rate on our variable rate term loan for the period from April 1, 2008 through April 1, 2011. As a result of the exchange of our variable rate term loan to Senior Floating Rate Notes, the interest rate swap is now used to fix the variable LIBOR interest rate on the Senior Floating Rate Notes at 6.26% through April 2011. In May 2009, we entered into a $350.0 million notional amount interest rate swap agreement with a financial institution that effectively fixed the interest rate on our Senior Floating Rate Notes at 6.69% for the period from April 1, 2011 through April 1, 2013. These swaps have not been designated as hedges.

Our interest rate swaps reduce our market risk on our Senior Floating Rate Notes. We use sensitivity analyses to determine the impact that market risk exposures could have on our variable interest rate borrowings if not for our interest rate swaps. Based on the $350.0 million outstanding balance of our Senior Floating Rate Notes at June 30, 2009, a one percent change in the applicable rates, with all other variables held constant, would have resulted in a

52

change in our interest expense of approximately $0.9 million and $1.8 million for the three months and six months ended June 30, 2009, respectively.

Unrealized gains of $3.9 million and $9.6 million were recorded in interest expense in the consolidated statements of operations for the change in fair value of the interest rate swap for the three months ended June 30, 2009 and 2008, respectively. Unrealized gains of $3.7 million and $10.4 million were recorded in interest expense in the consolidated statements of operations for the change in fair value of the interest rate swap for the six months ended June 30, 2009 and 2008, respectively. Realized losses of $1.3 million and $2.3 million were included in interest expense in the condensed consolidated statements of operations for the three and six months ended June 30, 2009, respectively. There were no realized gains or losses recorded on our interest rate swap during the first six months of 2008.

ITEM 4.   Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this Quarterly Report. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2009 to provide reasonable assurance that the information required to be disclosed by us in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

There was no change in our internal control over financial reporting during the quarter ended June 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. Other Information

ITEM 1.   Legal Proceedings

The Company is a defendant in lawsuits from time to time in the normal course of business. In management’s opinion, the Company is not currently involved in any legal proceedings that, individually or in the aggregate, could have a material adverse effect on its results of operations, financial condition or cash flows.

ITEM 1A.   Risk Factors

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

President Obama’s Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. The “American Clean Energy

53

and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA, which was approved for adoption by the U.S. House of Representatives on June 26, 2009, contains provisions that would prohibit private over-the-counter energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

ITEM 2.   Unregistered Sales of Equity Securities and Use of Proceeds

As part of our restricted stock program, we make required tax payments on behalf of employees as their stock awards vest and then withhold a number of vested shares having a value on the date of vesting equal to the tax obligation. The shares withheld are recorded as treasury shares. During the quarter ended June 30, 2009, the following shares were withheld in satisfaction of tax withholding obligations arising from the vesting of restricted stock:

					Total Number of		Maximum Number
					Shares Purchased		of Shares that May
	Total Number		Average		as Part of Publicly		Yet Be Purchased
	of Shares		Price Paid		Announced Plans		Under the Plans
Period	Purchased		per Share		or Programs		or Programs
April 1, 2009 — April 30, 2009		398	$	8.16		N/A		N/A
May 1, 2009 — May 31, 2009		457		10.72		N/A		N/A
June 1, 2009 — June 30, 2009		132		8.47		N/A		N/A

54

ITEM 4.   Submission of Matters to a Vote of Security Holders

(a) Our Annual Meeting of Stockholders was held in Oklahoma City on June 5, 2009.

(b) Proxies for the meeting were solicited pursuant to Regulation 14A under the Exchange Act. There was no solicitation in opposition to the person nominated by our Board of Directors to serve as a Class III director of the Company. The terms of the Company’s Class I directors, William A. Gilliland, D. Dwight Scott and Jeffrey S. Serota, expire at the Company’s Annual Meeting of Stockholders in 2010. The terms of the Company’s Class II directors, Tom L. Ward and Roy T. Oliver, expire at the Company’s Annual Meeting of Stockholders’ in 2011.

(c) A total of 143,687,782 shares of our common stock outstanding and entitled to vote were present at the June 5, 2009 meeting in person or by proxy. Each share of common stock was entitled to one vote. The matters voted upon and results were as follows:

1. Election of one Class III director to serve until the Company’s Annual Meeting of Stockholders in 2012.

Nominee	For		Authority Withheld
Daniel W. Jordan		120,703,644		22,984,139

2. Ratification of PricewaterhouseCoopers LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2009.

FOR:	143,301,476
AGAINST:	333,273
ABSTAIN:	53,033

3. Adoption of the SandRidge Energy, Inc. 2009 Incentive Plan.

FOR:	90,193,905
AGAINST:	15,793,396
ABSTAIN:	101,971

ITEM 6.   Exhibits

See the Exhibit Index accompanying this Quarterly Report.

55

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

SandRidge Energy, Inc.

By:  /s/  Dirk M. Van Doren

Dirk M. Van Doren

Executive Vice President and

Chief Financial Officer

Date: August 6, 2009

EXHIBIT INDEX

				Incorporated by Reference
Exhibit					SEC			Filed
No.			Exhibit Description	Form	File No.	Exhibit	Filing Date	Herewith
	3	.1	Certificate of Incorporation of SandRidge Energy, Inc.	S-1	333-148956	3.1	01/30/2008
	3	.2	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	03/09/2009
	4	.1	Amendment, dated April 23, 2009, to Registration Rights Agreement, dated March 20, 2007, among SandRidge Energy, Inc. and the purchasers named therein	8-K	001-33784	4.1	04/28/2009
	4	.2	Indenture, dated May 14, 2009, among SandRidge Energy, Inc. and the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee	8-K	001-33784	4.1	05/15/2009
	4	.3	Registration Rights Agreement, dated May 14, 2009, among SandRidge Energy, Inc., the several guarantors named therein and Barclays Capital Inc., Banc of America Securities LLC, J.P. Morgan Securities Inc., RBC Capital Markets Corporation and RBS Securities Inc., as representatives of the several initial purchasers	8-K	001-33784	4.2	05/15/2009
	10	.1	Amendment No. 6 to Senior Credit Facility, dated April 17, 2009	8-K	001-33784	10.1	04/21/2009
	10	.2	Underwriting Agreement, dated April 23, 2009, among SandRidge Energy, Inc., Tom L. Ward and Morgan Stanley & Co. Incorporated, as representative of the underwriters named therein	8-K	001-33784	1.1	04/28/2009
	10	.3†	SandRidge Energy, Inc. 2009 Incentive Plan	8-K	001-33784	10.1	06/09/2009
	10	.4	Membership Interest Purchase Agreement, dated June 30, 2009, between SandRidge Midstream, Inc. and TCW Pecos Midstream, L.L.C.					*
	10	.5	Gas Gathering Agreement, dated June 30, 2009, between SandRidge Exploration and Production, LLC and Piñon Gathering Company, LLC. Portions of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted portions have been filed separately with the Securities and Exchange Commission.					*
	10	.6	Operations and Maintenance Agreement, dated June 30, 2009, between SandRidge Midstream, Inc. and Piñon Gathering Company, LLC					*
	31	.1	Section 302 Certification — Chief Executive Officer					*
	31	.2	Section 302 Certification — Chief Financial Officer					*
	32	.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer					*
	101	.INS	XBRL Instance Document					*
	101	.SCH	XBRL Taxonomy Extension Schema Document					*
	101	.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					*
	101	.LAB	XBRL Taxonomy Extension Label Linkbase Document					*
	101	.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					*
	101	.DEF	XBRL Taxonomy Extension Definition Document					*

† Management contract or compensatory plan or arrangement

EX-10.4

Exhibit 10.4

Execution Version

MEMBERSHIP INTEREST PURCHASE AGREEMENT

dated

June 30, 2009

by and between

SANDRIDGE MIDSTREAM, INC.,
a Texas corporation

as Seller

and

TCW PECOS MIDSTREAM, L.L.C.,
a Texas limited liability company

as Buyer

TABLE OF CONTENTS

	Page
ARTICLE 1 DEFINITIONS AND RULES OF CONSTRUCTION		1
Section 1.1 Definitions		1
ARTICLE 2 PURCHASE AND SALE; CLOSING		7
Section 2.1 Sale and Purchase of Membership Interests		7
Section 2.2 Assets		7
Section 2.3 Excluded Assets		8
Section 2.4 Retained Liabilities		9
Section 2.5 Consideration		9
Section 2.6 Allocation of Purchase Price		9
Section 2.7 Other Payments		10
ARTICLE 3 REPRESENTATIONS AND WARRANTIES REGARDING the SELLER Entities		10
Section 3.1 Organization of Seller Entities; Authority		10
Section 3.2 Authorization; Enforceability		10
Section 3.3 No Violation; No Conflict		10
Section 3.4 Consents and Approvals		11
Section 3.5 Litigation		11
Section 3.6 Brokers’ Fees		11
ARTICLE 4 REPRESENTATIONS AND WARRANTIES REGARDING THE COMPANY		11
Section 4.1 Organization of the Company; Authority		11
Section 4.2 Authorization; Enforceability		11
Section 4.3 No Violation; No Conflict		12
Section 4.4 Capitalization of the Company		12
Section 4.5 Conduct of Business		12
Section 4.6 Company Contracts		13
Section 4.7 Litigation		13
Section 4.8 Taxes		13
Section 4.9 Environmental Matters		14
Section 4.10 Compliance with Laws		14
Section 4.11 Permits		15
Section 4.12 Insurance		15
Section 4.13 Title to Assets; Sufficiency		15
Section 4.14 Employees		15
Section 4.15 Books and Records		16
ARTICLE 5 REPRESENTATIONS AND WARRANTIES REGARDING BUYER		16
Section 5.1 Organization of Buyer; Authority		16
Section 5.2 Authorization; Enforceability		16
Section 5.3 No Violation; No Conflict		16
Section 5.4 Consents and Approvals		16
Section 5.5 Litigation		17
Section 5.6 Brokers’ Fees		17
Section 5.7 Financial Ability		17
Section 5.8 Independent Investigation		17

	Page
Section 5.9 Investment Representation		17
Section 5.10 Accredited Investor		17
Section 5.11 Waiver of Other Representations		18
Section 5.12 Nonreportability under the HSR Act		18
ARTICLE 6 COVENANTS		18
Section 6.1 Confidentiality and Disclosure		18
Section 6.2 Approvals		18
Section 6.3 Seller Marks		19
Section 6.4 Books and Records; Access		19
Section 6.5 Permits		19
Section 6.6 Tax Matters		19
Section 6.7 Further Assurances; Duty to Cooperate		20
Section 6.8 Maintenance of Company Existence		21
Section 6.9 Post Closing Date Assignments		21
ARTICLE 7 Deliverables		21
Section 7.1 Seller’s Deliverables		21
Section 7.2 Buyer’s Deliverables		22
ARTICLE 8 INDEMNIFICATION		22
Section 8.1 Survival		22
Section 8.2 Indemnification		22
Section 8.3 Procedures		23
Section 8.4 Exclusive Remedy and Release		24
ARTICLE 9 MISCELLANEOUS		25
Section 9.1 Successors and Assigns		25
Section 9.2 Notices		25
Section 9.3 Counterparts		26
Section 9.4 Rights		26
Section 9.5 Amendments		26
Section 9.6 No Waiver		26
Section 9.7 Governing Law; Jurisdiction		26
Section 9.8 Jury Waiver		26
Section 9.9 Limitation of Liability		26
Section 9.10 No Third Party Beneficiaries		27
Section 9.11 Further Assurances		27
Section 9.12 Expenses		27
Section 9.13 Entire Agreement		27
Section 9.14 Schedules		27
Section 9.15 Publicity		27
Section 9.16 Headings		28
Section 9.17 Rights and Remedies		28
Section 9.18 No Inducements		28
Section 9.19 No Partnership		28
Section 9.20 Rules of Construction		28

LIST OF EXHIBITS
Exhibit A	Form of Assignment of Membership Interests
Exhibit B	Form of Confidentiality and Disclosure Agreement
Exhibit C	Form of Seller Guaranty Agreement
Exhibit D	Form of SR E&P Guaranty Agreement
Exhibit E	Form of SR Energy Company Guaranty Agreement
Exhibit F	Form of SR Energy Buyer Guaranty Agreement
SCHEDULES
Schedule 1.1(a)	Knowledge
Schedule 1.1(b)	Permitted Liens
Schedule 1.1(d)	Transfer Restrictions
Schedule 2.2(a)	Gathering System
Schedule 2.2(b)	Easements
Schedule 2.2(c)	Company Contracts
Schedule 2.2(d)	Permits
Schedule 2.2(e)	Personal Property
Schedule 2.3	Excluded Assets
Schedule 2.3(l)	O&M Permits
Schedule 3.3	Violations; Conflicts
Schedule 3.4	Seller Approvals
Schedule 3.5	Litigation
Schedule 4.3(c)	Violations; Conflicts
Schedule 4.6	Breaches or Violations of Company Contracts
Schedule 4.7	Seller or Company Related Litigation
Schedule 4.8	Taxes
Schedule 4.9	Environmental Matters
Schedule 4.10	Compliance with Laws
Schedule 4.11	Permits
Schedule 4.12	Insurance
Schedule 4.13	Title to Assets; Sufficiency
Schedule 5.3	Violations; Conflicts
Schedule 5.4	Buyer Approvals

MEMBERSHIP INTEREST PURCHASE AGREEMENT

     This Membership Interest Purchase Agreement (this “Agreement”), dated June 30, 2009 (the “Closing Date”) is entered into by and between SandRidge Midstream, Inc., a Texas corporation (“Seller”), and TCW Pecos Midstream, L.L.C., a Texas limited liability company (“Buyer”).

RECITALS

     WHEREAS, (a) Seller has formed, by causing that certain Certificate of Formation, dated as of the Closing Date (the “Certificate of Formation”), to be filed with the Secretary of the State of Delaware, Piñon Gathering Company, LLC, a Delaware limited liability company (the “Company”); (b) Seller and the Company have executed that certain Limited Liability Company Agreement, dated as of the Closing Date (the “LLC Agreement”); and (c) Seller owns all of the issued and outstanding membership interests of the Company (the “Membership Interests”);

     WHEREAS, (a) each of SandRidge Exploration and Production, LLC, a Delaware limited liability company (“SR E&P”) and SandRidge Energy, Inc., a Delaware corporation (“SR Energy”), has transferred, conveyed and assigned to Seller, pursuant to the terms of that certain Assignment, Bill of Sale and Conveyance, dated as of the Closing Date (the “Intercompany Conveyance”), each of SR E&P’s and SR Energy’s respective right, title and interest in and to the Assets owned by it on the Closing Date, free and clear of all Liens (other than Permitted Liens); (b) Seller has transferred, conveyed and assigned to the Company, pursuant to the terms of that certain Assignment, Bill of Sale and Conveyance, dated as of the Closing Date (the “Company Conveyance” and together with the Intercompany Conveyance, the “Asset Conveyances”), all of Seller’s right, title and interest in and to the Assets, free and clear of all Liens (other than Permitted Liens and any encumbrance, mortgage or security interest created in the Company Conveyance); and (c), as a result of the consummation of the transactions described in clauses (a) and (b), the Company owns all of the Assets (as defined below);

     WHEREAS, (a) SR E&P and the Company have entered into that certain Gathering Agreement, dated as of the Closing Date (the “Gathering Agreement”), and (b) Seller and the Company have entered into that certain Operations and Maintenance Agreement, dated as of the Closing Date (the “O&M Agreement”); and

     WHEREAS, Seller desires to sell to Buyer, and Buyer desires to purchase from Seller, all of the Membership Interests, subject to the terms and conditions described in this Agreement.

     NOW, THEREFORE, in consideration of the premises and mutual covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Buyer and Seller agree as follows:

ARTICLE 1
DEFINITIONS AND RULES OF CONSTRUCTION

          Section 1.1 Definitions. As used herein, the following terms shall have the following meanings:

     “Affiliate” means, with respect to any Person, any other Person that, directly or indirectly, controls, is controlled by, or is under common control with, such specified Person through one or more intermediaries or otherwise. For the purposes of this definition, “control” means, where used with respect to any Person, the possession, directly or indirectly, of the power to direct or cause the direction of the

1

management and policies of such Person, whether through the ownership of voting securities or interests, by Contract or otherwise, and the terms “controlling” and “controlled” have correlative meanings.

     “Agreement” has the meaning provided such term in the Preamble.

     “Asset Conveyances” has the meaning provided such term in the Recitals.

     “Assets” has the meaning provided such term in Section 2.2.

     “Assignment of Membership Interests” has the meaning provided such term in Section 7.1(a)(i).

     “Business Day” means any day that is not a Saturday, Sunday or legal holiday in the State of Texas and that is not otherwise a federal holiday in the United States.

     “Buyer” has the meaning provided such term in the Preamble.

     “Buyer Approvals” has the meaning provided such term in Section 5.4(a).

     “Buyer Indemnified Parties” has the meaning provided such term in Section 8.2(a).

     “CERCLA” means the Federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended, 42 U.S.C. § 9601 et seq.

     “Certificate of Formation” has the meaning provided such term in the Recitals.

     “Certification of Non-Foreign Status” has the meaning provided such term in Section 7.1(a)(iii).

     “Claim Notice” has the meaning provided such term in Section 8.3(a).

     “Closing Date” has the meaning provided such term in Preamble.

     “Code” means the Internal Revenue Code of 1986, as amended, and the rules and regulations promulgated thereunder.

     “Company” has the meaning provided such term in the Recitals.

     “Company Contracts” has the meaning provided such term in Section 2.2(c).

     “Company Conveyance” has the meaning provided such term in the Recitals.

     “Confidentiality and Disclosure Agreement” has the meaning provided such term in Section 7.1(a)(ii).

     “Constituents of Concern” means any substance defined as a hazardous substance, hazardous waste, hazardous material, toxic substance, solid waste, pollutant or contaminant by any Environmental Law.

     “Contract” means any legally binding agreement, commitment, lease, license or contract.

     “Dedicated Area” has the meaning provided such term in the Gathering Agreement.

     “Direct Claim” has the meaning provided such term in Section 8.3(d).

2

     “Dollars” and “$” mean the lawful currency of the United States.

     “Easements” has the meaning provided such term in Section 2.2(b).

     “Environmental Law” means all applicable Laws and Environmental Permits of any Governmental Authority relating to the environment, natural resources, or the protection thereof, including: (a) all requirements pertaining to liability for reporting, management, licensing, permitting, investigation, and remediation of emissions, discharges, releases, or threatened releases of a Constituent of Concern; and (b) CERCLA, the Hazardous Materials Transportation Act, 49 U.S.C. § 5101 et. seq., the Federal Clean Water Act, the Federal Clean Air Act, the Federal Solid Waste Disposal Act (which includes the Resource Conservation and Recovery Act), the Federal Toxic Substances Control Act, and the Federal Insecticide, Fungicide and Rodenticide Act, the Oil Pollution Act of 1990, 33 U.S.C. § 2701 et. seq., and the Safe Drinking Water Act, 42 U.S.C. §300f et. seq., and any applicable Law relating to occupational health and safety, the environment, natural resources or the protection thereof, each as amended from time to time, including any regulations promulgated pursuant thereto, and any state or local counterparts.

     “Environmental Permits” all permits, licenses, registrations, authorizations, certificates and approvals, and any other similar items, of Governmental Authorities required by Environmental Laws and necessary for or held in connection with the ownership and/or operation of the Assets.

     “Excluded Assets” has the meaning provided such term in Section 2.3.

     “Expansions” has the meaning provided such term in the Gathering Agreement.

     “FTC” means the Federal Trade Commission.

     “Fundamental Representations and Warranties” means the representations and warranties contained in Sections 3.1, 3.2, 3.3, 3.5, 3.6, 4.1, 4.2, 4.3, 4.4, 4.5, 4.13, 5.1, 5.2, 5.3 and 5.6.

     “GAAP” means generally accepted accounting principles of the United States, consistently applied.

     “Gathering Agreement” has the meaning provided such term in the Recitals.

     “Gathering System” has the meaning provided such term in Section 2.2(a).

     “Governmental Authority” means any federal, state, municipal, local or similar authority, regulatory or administrative agency, court or arbitral body with jurisdiction over the Parties, this Agreement, any of the transactions contemplated hereby, the Assets or the Membership Interests.

     “HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

     “Income Tax” means any Tax based upon, measured by, or calculated with respect to (a) net income, profits or similar measures (including capital gains Taxes and minimum Taxes) or (b) multiple bases if one or more of the bases upon which such Tax is based, measured by or calculated is described in clause (a), in each case together with any interest, penalties, or additions to such Tax, including Texas franchise tax.

     “Indebtedness for Borrowed Money” means, with respect to any Person, at any date, without duplication: (a) all obligations of such Person for borrowed money, including all principal, interest,

3

premiums, fees, expenses, overdrafts and penalties with respect thereto; (b) all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments; (c) all obligations of such Person to pay the deferred purchase price of property, except trade payables incurred in the ordinary course of business; (d) all obligations of such Person to reimburse any bank or other Person in respect of amounts paid or payable under a letter of credit or similar instrument; (e) all capitalized lease obligations; (f) all other obligations of a Person which would be required to be shown as indebtedness on a balance sheet of such Person prepared in accordance with GAAP; and (g) all indebtedness of any other Person of the type referred to in clauses (a) to (f) above, directly or indirectly guaranteed by such Person or secured by any assets of such Person, whether or not such indebtedness has been assumed by such Person.

     “Indemnified Party” has the meaning provided such term in Section 8.3(a).

     “Indemnifying Party” has the meaning provided such term in Section 8.3(a).

     “Intellectual Property” means: (a) trademarks, service marks, trade dress, slogans, logos, and all goodwill associated therewith, and any applications or registrations for any of the foregoing; (b) copyrights and any related applications or registrations; (c) patents and any related applications or registrations; (d) all confidential information, know-how, trade secrets and similar proprietary rights in confidential inventions, discoveries, improvements, processes, techniques, devices, methods, patterns, formulae and specifications; and (e) all other intellectual property rights, statutory or common law, in the United States or worldwide.

     “Intercompany Conveyance” has the meaning provided such term in the Recitals.

     “IRS” means the United States Internal Revenue Service.

     “Knowledge” means: (a) with respect to Seller, the actual knowledge, after due inquiry, of the natural Persons identified in Schedule 1.1(a), as “Seller’s Persons With Knowledge”; and (b) with respect to Buyer, the actual knowledge, after due inquiry, of the natural Persons identified in Schedule 1.1(a) as “Buyer’s Persons With Knowledge”.

     “Law” means any statute, writ, law, common law, rule, regulation, ordinance, order, judgment, injunction, award, determination or decree of a Governmental Authority, or any requirement under the common law, in each case as in effect on and as interpreted on the Closing Date or on and as of the Closing Date, as applicable, unless the context otherwise clearly requires a different date, in which case on and as of such date applicable to the Parties, this Agreement, any of the transactions contemplated hereby, the Assets or the Membership Interest.

     “Lien” means any charge, pledge, option, mortgage, deed of trust, hypothecation, encumbrance or security interest.

     “Line Pack” has the meaning provided such term in the Gathering Agreement.

     “LLC Agreement” has the meaning provided such term in Recitals.

     “Losses” has the meaning provided such term in Section 8.2(a).

     “Membership Interests” has the meaning provided such term in the Recitals.

     “Non-Income Tax” means any Tax other than an Income Tax or a Transfer Tax.

4

     “O&M Agreement” has the meaning provided such term in the Recitals.

     “O&M Assets” means the assets described in clauses (g) and (l) of the definition of Excluded Assets.

     “Organizational Documents” means any charters, articles of incorporation, certificates of incorporation, certificates of formation, articles of association, bylaws, operating agreements, certificates of limited partnership, partnership agreements, limited liability company agreements, regulations, and all other similar documents, instruments or certificates executed, adopted or filed in connection with the creation, formation or organization of any Person, including any amendments thereto.

     “Parties” means, collectively, Seller and Buyer, and “Party” means, individually, either Buyer or Seller.

     “Permits” has the meaning provided such term in Section 2.2(d).

     “Permitted Liens” means the Liens listed on Schedule 1.1(b) and any other: (a) Liens for Taxes and assessments not yet due or delinquent; (b) statutory Liens (including materialmen’s, warehousemen’s, mechanic’s, repairmen’s, landlord’s, and other similar Liens) arising in the ordinary course of business and securing payments not yet due or delinquent; (c) rights of lessors and lessees under leases and rights of third parties under any Company Contract; (d) rights of licensors and licensees under licenses executed in the ordinary course of business; (e) restrictive covenants, easements and defects, imperfections, or irregularities of title or Liens, if any, in each case that are of a nature that do not, or that would not reasonably be expected to, materially and adversely affect the ownership, or adversely affect the use or operation of the Assets; (f) purchase money Liens and Liens securing rental payments under capital lease arrangements set forth on Schedule 2.2(c); (g) restrictions on transfer with respect to which consents or waivers are obtained for the transactions contemplated by this Agreement to the extent disclosed on Schedule 1.1(d); (h) Liens created by Buyer, or its successors and assigns; and (i) terms and conditions of the Permits listed on any of the Schedules.

     “Person” means any individual, firm, corporation, partnership, limited liability company, incorporated or unincorporated association, joint venture, joint stock company, Governmental Authority or other entity of any kind.

     “Personal Property” has the meaning provided such term in Section 2.2(e).

     “Purchase Price” has the meaning provided such term in Section 2.5.

     “Reasonable Efforts” means efforts in accordance with reasonable legal, commercial practice and without the incurrence of any material expense or risk.

     “Records” has the meaning provided such term in Section 2.2(f).

     “Representatives” means a Person’s directors, managers, partners, officers, employees, duly authorized agents, or professional advisors (including attorneys, accountants, consultants, bankers, financial advisors and any representatives of such advisors).

     “Retained Liabilities” has the meaning provided such term in Section 2.4.

     “Schedules” means the schedules attached to this Agreement.

5

     “Seller” has the meaning provided such term in the Preamble.

     “Seller Approvals” has the meaning provided such term in Section 3.4.

     “Seller Entities” means, collectively, SR E&P, Seller and SR Energy, and “Seller Entity” means, individually, any of SR E&P, Seller or SR Energy.

     “Seller Guaranty Agreement” has the meaning provided such term in Section 7.1(a)(iv).

     “Seller Indemnified Parties” has the meaning provided such term in Section 8.2(b).

     “Seller Marks” has the meaning provided such term in Section 6.3.

     “SR E&P” has the meaning provided such term in the Recitals.

     “SR E&P Guaranty Agreement” has the meaning provided such term in Section 7.1(a)(v).

     “SR Energy” has the meaning provided such term in the Recitals.

     “SR Energy Buyer Guaranty Agreement” has the meaning provided such term in Section 7.1(a)(vii).

     “SR Energy Company Guaranty Agreement” has the meaning provided such term in Section 7.1(a)(vi).

     “Straddle Period” has the meaning provided such term in Section 6.6(c).

     “Tax Returns” means any form, report, return, statement, election, document, estimated tax filing, declaration, or other information, filed with or required to be supplied to any Taxing Authority by any Person with respect to Taxes, including any amendments thereof or schedule or attachment thereto, and any documents with respect to or accompanying requests for the extension of time in which to file any such report, return, statement, election, document, declaration or other information.

     “Taxes” means all (a) federal, state, provincial, county, local and foreign taxes, assessments, duties, levies, imposts or other similar charges, including all income, franchise, margin, profits, capital gains, capital stock, transfer, gross receipts, sales, use, service, occupation, ad valorem, property, excise, severance, windfall profit, production, custom, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental, alternative minimum, add-on, value-added, withholding and other taxes, assessments, duties, levies, imposts or other similar charges of any kind, and all estimated taxes, deficiency assessments, additions to tax, penalties and interest, and (b) liability for items within clause (a) of any other Person by Contract, operation of law (including Treasury Regulation section 1.1502-6) or otherwise.

     “Taxing Authority” means, with respect to any Tax, a Governmental Authority that imposes such Tax, and the agency (if any) charged with the collection of such Tax for such entity, including any Governmental Authority that imposes, or is charged with collecting, Social Security or similar charges or premiums.

     “Third Party Claim” has the meaning provided such term in Section 8.3(a).

6

     “Third Party Gathering Agreement” means that certain Gas Gathering Agreement dated June 26, 2009 between Enterprise Products Operating, LLC, as shipper, and SandRidge Midstream, Inc., as gatherer.

     “Transaction Documents” means this Agreement, the Gathering Agreement, the O&M Agreement, the Assignment of Membership Interests, the Asset Conveyances, the Seller Guaranty Agreement, the SR E&P Guaranty Agreement, the SR Energy Company Guaranty Agreement, SR Energy Buyer Guaranty Agreement, the Confidentiality and Disclosure Agreement and the Third Party Gathering Agreement, and any other agreement or document that may be required to be executed to consummate the transactions contemplated hereby or thereby.

     “Transfer Taxes” has the meaning provided in Section 6.6(a).

ARTICLE 2
PURCHASE AND SALE; CLOSING

          Section 2.1 Sale and Purchase of Membership Interests. Upon the terms and subject to the conditions set forth herein, Seller shall sell, assign and transfer to Buyer, and Buyer will purchase, acquire and accept from Seller, the Membership Interests on the Closing Date.

          Section 2.2 Assets. The term “Assets” shall mean, less and except the Excluded Assets (and all other assets of the Seller Entities not described in this Section 2.2), all right, title and interest of the Company in and to the following assets:

          (a) that certain 2” to 20” diameter natural gas pipeline located in Pecos and Terrell Counties, Texas, which is approximately three hundred and seventy (370) miles in length that gathers all of the gas produced by Seller and its Affiliates within the Dedicated Area, including above-ground facilities or structures, compression equipment and facilities, Line Pack, and the valves, machinery, equipment, gauges, meters, fittings, fixtures and improvements related thereto, as more particularly described on Schedule 2.2(a) (the “Gathering System”);

          (b) all rights-of-way, easement rights and surface rights owned or held in connection with the ownership or operation of the Gathering System, together with any and all other rights, tenements, easements, appendages, appurtenant rights, privileges, leases, Contracts and agreements related to real property as may be required in connection with the ownership of the Gathering System, as more particularly described on Schedule 2.2(b) (the “Easements”);

          (c) all Contracts necessary for the ownership or operation of the Gathering System, as more particularly described on Schedule 2.2(c) (the “Company Contracts”);

          (d) all permits necessary in connection with the ownership or operation of the Assets, including the Environmental Permits, licenses, certificates, consents, approvals, waivers, authorizations and registrations issued by a Governmental Authority and necessary in connection with the ownership of the Gathering System, as more particularly described on Schedule 2.2(d) (the “Permits”);

          (e) the items of personal property (tangible or intangible) necessary in connection with the ownership or operation of the Gathering System, as more particularly described on Schedule 2.2(e) (the “Personal Property”); and

          (f) all records, documents, books, supplier lists and work orders necessary to operate the Gathering System, and all other documents and data (including electronic data) relating to the

7

operation of the Assets (including past operations), including all of the foregoing necessary to cause operations to remain in compliance with applicable Law (the “Records”).

          Section 2.3 Excluded Assets. All assets of the Seller Entities listed on Schedule 2.3, and any other assets of the Seller Entities and their Affiliates described below, will be retained by the Seller Entities (or their Affiliates, as applicable) and will not be included in the Assets (the “Excluded Assets”):

          (a) cash;

          (b) accounts receivable (including any imbalance receivables), trade credits, proceeds or revenues accruing for any period prior to the Closing Date;

          (c) all personal property relating to any Seller Entity generally and not involving or relating solely to the Assets or the business related to the Assets, or that may be necessary or useful in such Seller Entity’s (or any of its Affiliates’) development, construction, operation and/or ownership of any Expansions;

          (d) each Seller Entity’s Organizational Documents, duplicate copies of the Records as are necessary to enable the Seller Entities to file Tax Returns and reports, and any other records or materials relating to any Seller Entity generally and not involving or relating solely to the Assets or the business related to the Assets, and any of the foregoing that may be necessary or useful in such Seller Entity’s (or any of its Affiliates’) operation of the Assets pursuant to the O&M Agreement, or development, construction, operation and/or ownership of any Expansions;

          (e) refunds of premiums from any insurance policy of any Seller Entity and any Tax refunds due to any Seller Entity resulting from this Agreement or the transactions contemplated hereby;

          (f) all proceeds, claims and rights under any: (i) insurance policies covering the Assets that relate to any damage or destruction (whether by fire, theft, vandalism or other casualty) that has occurred prior to the Closing Date; and (ii) condemnation or eminent domain awards that relate to any condemnation of any Assets that has occurred prior to the Closing Date;

          (g) all, as relate to the ownership or operation of the Assets: (i) Intellectual Property; (ii) software licenses and software license agreements; (iii) information technology hardware of any kind whatsoever; (iv) office supplies, furniture and equipment, including computers, printers, copiers, personal handheld devices and phones; (v) tools and rolling stock; (vi) SCADA-related licenses, equipment and software; and (vii) FCC permits, licenses, and other similar documents and consents;

          (h) all wellhead separation equipment, meters and flowlines, and any equipment dedicated to the removal of carbon dioxide or other inert gasses or the recovery of any hydrocarbon liquids;

          (i) all rights-of-way, easement rights and surface rights owned or held by the Seller Entities (or their Affiliates, as applicable) for the purposes of the development, construction, operation and/or ownership of any Expansions and the conduct of oil and gas exploration and production activities;

          (j) all Contract rights owned or held by the Seller Entities (or their Affiliates, as applicable) to the extent necessary for the development, construction, operation and/or ownership of any Expansions and the conduct of oil and gas exploration and production activities;

8

          (k) all rights under any permits owned or held by the Seller Entities (or their Affiliates, as applicable) to the extent necessary for the development, construction, operation and/or ownership of any Expansions and the conduct of oil and gas exploration and production activities; and

          (l) all permits that are to be held by Seller under the O&M Agreement as more particularly set forth on Schedule 2.3(l).

          Section 2.4 Retained Liabilities. Upon and after the Closing Date, Seller shall retain and be liable for the following liabilities and obligations (without duplication, the “Retained Liabilities”):

          (a) all liabilities and obligations of any Seller Entity arising out of, or relating to, any Excluded Asset;

          (b) any liabilities of any Seller Entity or the Company resulting from the consummation of the transactions contemplated by this Agreement, including Taxes; and

          (c) all other liabilities of any Seller Entity arising from, based on, related to, or associated with, the formation of the Company, the contribution of the Assets to the Company, or any act, omission, event, condition or circumstance involving or relating to the use, ownership or operation of the Assets occurring or existing before the Closing Date (including accounts payable, Taxes, and wellhead and other imbalances).

          Section 2.5 Consideration. In consideration of the sale and purchase of the Membership Interests as contemplated by Section 2.1, on the Closing Date, Buyer shall pay to Seller an aggregate of two hundred million dollars ($200,000,000.00) in cash by means of a completed wire transfer of immediately available funds to an account designated in writing by Seller (the “Purchase Price”). BUYER AND SELLER ACKNOWLEDGE AND AGREE THAT THE TERMS OF THIS AGREEMENT, INCLUDING THE LIMITATIONS ON, AND DISCLAIMERS OF WARRANTIES AND REPRESENTATIONS OF, SELLER CONTAINED IN THIS AGREEMENT, ARE A BARGAINED FOR AND MATERIAL PART OF THE CONSIDERATION FOR THE MEMBERSHIP INTERESTS.

          Section 2.6 Allocation of Purchase Price. Seller and Buyer recognize that the purchase of the Membership Interests will be treated for federal income tax purposes as the purchase of the Assets of the Company. Seller and Buyer agree to cooperate in good faith to determine a reasonable allocation of the Purchase Price as determined for federal income tax purposes among the Assets in accordance with Section 1060 of the Code and the Treasury regulations thereunder. On or prior to the date ninety (90) days after the Closing Date, Buyer shall provide to Seller Buyer’s proposed allocation of the Purchase Price. Within thirty (30) days after the receipt of such allocation, Seller shall propose to Buyer any changes to such allocation or otherwise shall be deemed to have agreed with such allocation. Seller and Buyer shall cooperate in good faith to attempt to mutually agree to such allocation and shall reduce any such agreement to writing, including jointly and properly completing an IRS Form 8594, and any other forms or statements required by the Code, Treasury regulations or the IRS, together with any and all attachments required to be filed therewith. Seller and Buyer shall file timely any such forms and statements with the IRS. The allocation of the Purchase Price shall be revised to take into account any subsequent adjustments to the Purchase Price in the manner provided by Section 1060 of the Code and the Treasury Regulations thereunder. Seller and Buyer shall not file (and Seller shall cause SR E&P not to file) any Tax Return or other documents or otherwise take any position with respect to Taxes that is inconsistent with any agreed upon allocation of the Purchase Price. Notwithstanding the foregoing, Buyer shall not be required to agree upon the allocation of the Purchase Price for Tax purposes with Seller and, if no agreement is reached, the Parties may report different allocations of the Purchase Price.

9

          Section 2.7 Other Payments. Upon receipt, Buyer shall promptly send to Seller any third party invoices received by Buyer (or its Affiliates) that are attributable to the Retained Liabilities. Upon receipt, Seller shall promptly pay (and cause SR E&P to pay) such invoices directly to the appropriate third party. Upon receipt, Buyer will promptly remit to Seller all amounts received by Buyer that are attributable to the Excluded Assets (including Retained Liabilities) or that are otherwise attributable to periods on or before the Closing Date.

ARTICLE 3
REPRESENTATIONS AND WARRANTIES REGARDING THE SELLER ENTITIES

     Seller hereby represents and warrants to Buyer as follows:

          Section 3.1 Organization of Seller Entities; Authority. SR E&P and SR Energy are duly organized, validly existing and in good standing under the Laws of the State of Delaware and Seller is duly organized, validly existing and in good standing under the Laws of the State of Texas, and each Seller Entity has all requisite power and authority, as applicable, to own, lease and operate its properties and carry on its businesses as now being conducted. Each Seller Entity is duly qualified or licensed to do business as a foreign entity in good standing in every jurisdiction in which such qualification is required.

          Section 3.2 Authorization; Enforceability. Each Seller Entity has the requisite corporate or limited liability company power, as applicable, to execute and deliver the Transaction Documents to which it is a party and to perform all obligations to be performed by it under the Transaction Documents to which it is a party. The execution and delivery by each Seller Entity of the Transaction Documents to which it is a party and the consummation of the transactions contemplated thereby have been duly and validly authorized and approved by all requisite corporate or limited liability company action, as applicable, on part of such Seller Entity. Each Transaction Document (a) has been duly and validly executed and delivered by each Seller Entity that is a party thereto and (b) constitutes a valid and binding obligation of each Seller Entity that is a party thereto, enforceable against each such Seller Entity in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and similar Laws affecting creditors’ rights generally and subject, as to enforceability, to general principles of equity.

          Section 3.3 No Violation; No Conflict. Except as disclosed on Schedule 3.3, the execution and delivery of each Transaction Document by the Seller Entities party thereto and the consummation of the transactions contemplated thereby by the Seller Entities (assuming all of the Seller Approvals have been made, given or obtained, other than those that are customarily made, given or obtained after the Closing Date) do not and shall not:

          (a) violate or conflict with any Law applicable to any Seller Entity;

          (b) violate or conflict with any Organizational Document of any Seller Entity; or

          (c) (i) violate, conflict with, result in a breach of any provision of, constitute a default (or an event that, with notice or lapse of time, or both, would constitute a default) under, or result in the termination of or a right of termination, cancellation, acceleration or amendment under, any of the terms, conditions or provisions of any Contract to which any Seller Entity is a party or by which its assets or properties may be bound; or (ii) result in the creation of any Lien on the Membership Interests or the Assets (other than a Permitted Lien or any encumbrance, mortgage or security interest created in the Company Conveyance or the Assignment of Membership Interests).

10

          Section 3.4 Consents and Approvals. No filing or registration with, declaration or notification to, or order, authorization, consent or approval of, any Governmental Authority or any other Person is required in connection with the execution and delivery of any Transaction Document by the Seller Entities party thereto and the consummation of the transactions contemplated thereby by the Seller Entities party thereto, except for the required filings, consents, approvals, registrations, declarations, orders, authorizations and notices set forth on Schedule 3.4 (the “Seller Approvals”).

          Section 3.5 Litigation. Except as set forth on Schedule 3.5 (and except for Taxes, Environmental Matters and Permits, which are addressed in Sections 4.8, 4.9 and 4.11, respectively), as of the Closing Date: (a) there are no lawsuits, claims, proceedings, investigations, reviews, audits or other actions before any Governmental Authority pending or, to the Knowledge of Seller, threatened in writing by any Person against any Seller Entity that would reasonably be expected to have, individually or in the aggregate, an adverse effect on the Seller Entities’ ability to perform their respective obligations under the Transaction Documents to which they are a party, including their obligations to consummate any transactions contemplated thereby; and (b) there is no order or unsatisfied judgment from any Governmental Authority that would reasonably be expected to have, individually or in the aggregate, an adverse effect on the Seller Entities’ ability to perform their respective obligations under the Transaction Documents to which they are a party, including their obligations to consummate any transactions contemplated thereby.

          Section 3.6 Brokers’ Fees. No broker, finder, investment banker or other Person is entitled to any brokerage fee, finders’ fee or other commission in connection with the transactions contemplated by this Agreement based upon arrangements made by any Seller Entity or any of their respective Affiliates or Representatives.

ARTICLE 4
REPRESENTATIONS AND WARRANTIES REGARDING THE COMPANY

      Seller hereby represents and warrants to Buyer as follows:

          Section 4.1 Organization of the Company; Authority.

          (a) The Company is a limited liability company, duly organized, validly existing and in good standing 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 and carry on its business as now being conducted.

          (b) The Company is duly qualified as a foreign limited liability company and is in good standing in the State of Texas.

          (c) Seller has made available to Buyer true and complete copies of all existing Organizational Documents of the Company.

          Section 4.2 Authorization; Enforceability. The Company has the requisite limited liability company power to execute and deliver the Transaction Documents to which it is a party and to perform all obligations to be performed by it thereunder. The execution and delivery by the Company of the Transaction Documents to which it is a party and the consummation of the transactions contemplated thereby have been duly and validly authorized and approved by all requisite limited liability company action on the part of the Company. Each Transaction Document to which the Company is a party (a) has been duly and validly executed and delivered by the Company, and (b) constitutes a valid and binding obligation of the Company, enforceable against the Company in accordance with its terms, subject to

11

applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and similar Laws affecting creditors’ rights generally and subject, as to enforceability, to general principles of equity.

          Section 4.3 No Violation; No Conflict. The execution and delivery of this Agreement by Seller and the consummation of the transactions contemplated hereby (including the Asset Conveyances) by the Seller Entities (assuming all of Seller Approvals have been made, given or obtained, other than those that are customarily made, given or obtained after the Closing Date) do not and shall not:

          (a) violate or conflict with any Organizational Document of the Company;

          (b) violate or conflict with any Law applicable to the Company; or

          (c) other than as set forth on Schedule 4.3(c), violate, conflict with, result in a breach of any provision of, constitute a default (or an event that, with notice or lapse of time, or both, would constitute a default) under, or result in the termination of or a right of termination, cancellation or amendment under, accelerate the performance required by, or result in the creation of any Lien (other than a Permitted Lien or any encumbrance, mortgage or security interest created in the Company Conveyance) upon any of the Assets under, or result in the acceleration or trigger of any payment or time of payment, pursuant to any of the terms, conditions or provisions of any Company Contract.

          Section 4.4 Capitalization of the Company.

          (a) Seller is the sole member of the Company, the Membership Interests held by Seller constitute all of the issued and outstanding membership interests of the Company, no membership interests of the Company are held in the treasury of the Company, and no membership interests of the Company have been reserved for issuance upon the exercise of outstanding options, warrants, rights or otherwise.

          (b) The Membership Interests have been duly authorized and are validly issued, fully paid and non-assessable and have not been issued in violation of any preemptive or other similar right.

          (c) Seller has good and valid title to, holds of record and owns beneficially, the Membership Interests, free and clear of any Lien (other than any transfer restrictions imposed on equity securities by applicable federal and state securities Laws).

          (d) The Company has no issued or outstanding Indebtedness for Borrowed Money.

          (e) There are no outstanding subscriptions, options, warrants, rights, calls, commitments, or other securities convertible into, or exchangeable or exercisable for, equity securities, or agreements of any character providing for the purchase or issuance of any membership interest, or any other equity security or equity interests of the Company or any securities or other instruments representing the right to purchase or otherwise receive any membership interests or any other equity security interest of the Company, and there are no agreements of any kind that may obligate the Company to issue, purchase, redeem or otherwise acquire any membership interest or any other equity security or equity interest of the Company. There are no voting agreements, proxies or other similar agreements or understandings with respect to the Membership Interests.

          Section 4.5 Conduct of Business. Since the date of its formation: (a) the Company has conducted no business other than the ownership and operation of the Assets; (b) the Company has not owned or operated any properties or assets other than the Assets; (c) the business of the Company has been conducted only in the ordinary course of business; and (d) the Company has incurred no liabilities,

12

except for any liabilities arising under the Company Contracts or as otherwise would constitute a part of the Retained Liabilities.

          Section 4.6 Company Contracts.

          (a) Schedule 2.2(c) contains a true and complete list of the Company Contracts in effect on the Closing Date.

          (b) Except as set forth on Schedule 4.6:

          (i) each Company Contract is valid and binding, in full force and effect and enforceable against the Company, and, to the Knowledge of Seller, each other party thereto, in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and similar Laws affecting creditors’ rights generally and subject, as to enforceability, to general principles of equity;

          (ii) the Seller Entities and the Company have performed all obligations required to be performed by them to date under each Company Contract;

          (iii) no event or condition exists or has occurred that violates, results in a breach of any provision of or the loss of any benefit under, or constitutes a default (or an event that, with notice or lapse of time, or both, would constitute a default) on the part of any Seller Entity or the Company, or, to the Knowledge of Seller, any other party under, or results or will result in the creation of any Lien (other than a Permitted Lien) upon any of the Assets or the Membership Interests under, any of the terms, conditions or provisions of any Company Contract; and

          (iv) true and complete copies of all Company Contracts have been made available to Buyer or its Representatives.

          Section 4.7 Litigation. Except as set forth on Schedule 4.7 (and except for Taxes, Environmental Matters, and Permits, which are addressed in Sections 4.8, 4.9 and 4.11, respectively), as of the Closing Date: (a) there are no lawsuits, claims, proceedings, investigations, reviews, audits or actions before any Governmental Authority pending or, to the Knowledge of Seller, threatened in writing by any Person against the Company or any Seller Entity that relates to the Assets, the O&M Assets, or the Company’s ability to perform its obligations under the Transaction Documents to which it is a party, including its obligations to consummate any transactions contemplated thereby; and (b) there is no order or unsatisfied judgment from any Governmental Authority relates to the Company, the Assets, the O&M Assets, or the Company’s ability to perform its obligations under the Transaction Documents to which it is a party, including its obligations to consummate any transactions contemplated thereby.

          Section 4.8 Taxes. Except as set forth on Schedule 4.8: (a) all Tax Returns required to be filed with respect to the Company, the Assets, the O&M Assets and the Membership Interests have been timely filed; (b) all Taxes due with respect to the Company, the Assets, the O&M Assets and the Membership Interests have been paid; (c) there are no Liens (other than Permitted Liens) on the Company, any of the Assets, the O&M Assets or the Membership Interests that arose in connection with any failure to pay any Tax; (d) there is no claim pending by any Taxing Authority in connection with any Tax related to the Company, the Assets, the O&M Assets or the Membership Interests; (e) no audit, proceeding, investigation or other examination is pending or in progress, or, to the Knowledge of Seller, threatened in writing with respect to any Tax Return or Taxes of or relating to the Company, the Assets, the O&M Assets or the Membership Interests; (f) there are no agreements or waivers currently in effect

13

that provide for an extension of time with respect to the filing of any Tax Return related to the Company, the Assets, the O&M Assets or the Membership Interests or the assessment or collection of any Tax related to the Company, the Assets, the O&M Assets or the Membership Interests; (g) no written claim has been made by any Taxing Authority in a jurisdiction where any Seller Entity or the Company does not file a Tax Return that any such Seller Entity or the Company is or may be subject to taxation in that jurisdiction; (h) none of the Assets or the O&M Assets currently is “tax-exempt use property” (within the meaning of Section 168(h) of the Code) or “tax-exempt bond financed property” (within the meaning of Section 168(g)(5) of the Code); (i) the Assets and the O&M Assets have been properly listed and described on the current property Tax rolls for the Tax jurisdictions in which they are located and no portion of the Assets or the O&M Assets currently constitutes omitted property for property Tax purposes; (j) no agreement, consent, clearance, or other Tax ruling or agreement has been executed or entered into relating to Taxes arising in connection with the Company, the Assets, the O&M Assets or the Membership Interests, including any IRS private letter rulings or comparable rulings of any Taxing Authority and closing agreements pursuant to Section 7121 of the Code or any similar Law; (k) the Company has not engaged in any reportable transaction as defined in Treasury Regulation section 1.6011-4; and (l) the Company has been properly classified for federal income tax purposes as an entity disregarded as separate from its owner, Seller, a Texas corporation, since the date of its formation.

          Section 4.9 Environmental Matters. Except as set forth on Schedule 4.9:

          (a) the Assets and the O&M Assets and operation of the Assets and the O&M Assets, to the extent conducted by the Seller Entities or the Company prior to the Closing Date, are in compliance with all Environmental Laws and Environmental Permits. No Seller Entity has received any written communication, whether from a Governmental Authority, citizens group, employee or otherwise, that has not been resolved and that alleges that the Assets are not in such compliance or that any Seller Entity has any liability under an Environmental Law. To the Knowledge of Seller, there are no present or past actions, activities, circumstances, conditions, events or incidents that may reasonably be expected to prevent or interfere with such compliance or give rise to such liability in the future;

          (b) (i) the Company possess all Environmental Permits required under Environmental Laws for the Company to own and operate the Assets and (ii) the Seller Entities possess all Environmental Permits required under Environmental Laws for the Seller Entities to own and operate the O&M Assets, in each case, as currently conducted, and all such Environmental Permits are in full force and effect and there are no lawsuits or other proceedings pending or, to the Knowledge of Seller, threatened in writing, before any Governmental Authority that seek the revocation, cancellation, suspension or adverse modification of such Environmental Permits;

          (c) Seller has delivered to or otherwise made available for inspection by Buyer (or its Representatives) true, complete and correct copies of any reports, studies, analyses, tests, or monitoring data possessed by the Seller Entities pertaining to the Assets’ compliance with Environmental Laws or to Constituents of Concern, in, on, beneath or adjacent to any property currently or formerly owned, operated or leased by the Company, or regarding the Assets’ compliance with applicable Environmental Laws; and

          (d) to the Knowledge of Seller, there are and have been no actions, activities, circumstances, conditions, events, or incidents involving the Assets that may reasonably be expected to give rise to any liability under Environmental Law.

          Section 4.10 Compliance with Laws. Except with respect to matters set forth in Schedule 4.10 (and except for Laws relating to Taxes, Environmental Matters and Permits, which are addressed in Sections 4.8, 4.9 and 4.11, respectively), (a) the Company is in compliance with all Laws in

14

connection with the ownership and operation of the Assets and (b) the Seller Entities are in compliance with all Laws in connection with the ownership and operation of the O&M Assets.

          Section 4.11 Permits. Except with respect to Environmental Permits (as to which certain representations and warranties are made pursuant to Section 4.9) and except as set forth on Schedule 4.11: (a) the Company is (and, to Seller’s Knowledge, the Seller Entities have been) in compliance with all Permits related to the Assets and the O&M Assets; (b) all such Permits are, to Seller’s Knowledge, in full force and effect; (c) there are no lawsuits or other proceedings pending, or, to Seller’s Knowledge, threatened in writing before any Governmental Authority that seeks the revocation, cancellation, suspension or adverse modification of any Permit of the Company or any Seller Entity; and (d) the Company possesses, and the Assets include, all Permits necessary for it to own and operate the Assets as currently conducted. Schedule 4.11 sets forth a true and complete list of all such Permits.

          Section 4.12 Insurance. Schedule 4.12 contains a summary description of all policies of property, fire and casualty, product liability, and other insurance held by or for the benefit of the Company and that relate to the ownership or operation of the Assets as of the Closing Date. Except as set forth on Schedule 4.12, no Seller Entity has received any notice from the insurer under any insurance policy relating to the Assets or the O&M Assets disclaiming coverage, reserving rights with respect to a particular claim or such policy in general, or canceling or materially amending any such policy. Except as set forth on Schedule 4.12, there is no claim, suit or other matter currently pending, in respect of which any Seller Entity has received such a notice. All premiums due and payable for such insurance policies have been duly paid, and such insurance policies or extensions or renewals thereof in the amounts described are outstanding and duly in full force.

          Section 4.13 Title to Assets; Sufficiency.

          (a) The Company owns (i) a good and valid leasehold or a good and defensible easement interest in all of the real property related to the ownership or operation of the Assets, and (ii) good and valid title to (or good and valid leases with respect to) all of its personal property used in the ownership and operation of the Assets, free and clear of all Liens (other than Permitted Liens and any encumbrance, mortgage or security interest created in the Company Conveyance). Except as set forth on Schedule 4.13, the Assets, together with the rights under the Transaction Documents, are sufficient to permit Buyer to conduct the business related to the operation of the Assets as required under the Gathering Agreement and the Third Party Gathering Agreement. The business of each Seller Entity related to the Assets has and is being operated, and the Asset Conveyances have been done, in a manner that does not violate the terms of any Easements. Except as set forth on Schedule 4.13, all Easements are valid and enforceable, except as the enforceability thereof may be affected by bankruptcy, insolvency or other laws of general applicability affecting the rights of creditors generally or principles of equity, and grant the rights purported to be granted thereby and all rights necessary thereunder for the current operation of the Assets. Except as set forth on Schedule 4.13, there are no gaps in the Easements and no part of the tangible Assets is located on property that is not subject to an Easement.

          (b) All of the plants, facilities and other tangible assets owned, leased or used by the Seller Entities in the ownership or operation of the Assets are to the Knowledge of Seller: (i) structurally sound with no known defects, (ii) in good operating condition and repair, subject to ordinary wear and tear, and (iii) not in need of maintenance or repair except for ordinary, routine maintenance and repair.

          Section 4.14 Employees. The Company does not have, and has never had, any employees.

15

          Section 4.15 Books and Records. The books of account, minute books, membership interest records books and other records of Seller relating to the Company are complete and correct and have been maintained in accordance with practices that are generally applicable to Seller.

ARTICLE 5
REPRESENTATIONS AND WARRANTIES REGARDING BUYER

     Buyer hereby represents and warrants to Seller as follows:

          Section 5.1 Organization of Buyer; Authority. Buyer is a limited liability company, duly organized, validly existing and in good standing under the Laws of the State of Texas and has all requisite power and authority to own, lease and operate its properties and to carry on its business as now being conducted. Buyer is duly qualified or licensed to do business as a foreign entity in good standing in every jurisdiction in which such qualification is required, except where the failure to be so duly qualified or licensed would not have, or be reasonably expected to have, in the aggregate, a material adverse effect on Buyer’s ability to perform its obligations under the Transaction Documents to which it is a party, including its obligation to consummate the transactions contemplated thereby.

          Section 5.2 Authorization; Enforceability. Buyer has the requisite limited liability company power to execute and deliver the Transaction Documents to which it is a party and to perform all obligations to be performed by it thereunder. The execution and delivery by Buyer of the Transaction Documents to which it is a party and the consummation of the transactions contemplated thereby have been duly and validly authorized and approved by all requisite limited liability company action on the part of Buyer. Each Transaction Document to which Buyer is a party (a) has been duly and validly executed and delivered by Buyer, and (b) constitutes a valid and binding obligation of Buyer, enforceable against Buyer in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and similar Laws affecting creditors’ rights generally and subject, as to enforceability, to general principles of equity.

          Section 5.3 No Violation; No Conflict. Except as would not reasonably be expected to have a material adverse effect on Buyer’s ability to perform its obligations under the Transaction Documents to which it is a party, including its obligation to consummate the transactions contemplated thereby, and except as set forth on Schedule 5.3, the execution and delivery by Buyer of the Transaction Documents to which it is a party and the consummation of the transactions contemplated thereby by Buyer, do not and shall not:

          (a) violate or conflict with any Law applicable to Buyer;

          (b) violate or conflict with any Organizational Document of Buyer; or

          (c) violate, conflict with, result in a breach of any provision of, constitute a default (or an event that, with notice or lapse of time, or both, would constitute a default) under, or result in the termination of or a right of termination, cancellation or amendment under, any of the terms, conditions or provisions of any Contract to which Buyer is a party or by which it or any of its respective assets or properties may be bound.

          Section 5.4 Consents and Approvals. No material filing or registration with, declaration or notification to, or order, authorization, consent or approval of, any Governmental Authority or any other Person is required in connection with the execution and delivery by Buyer of any Transaction Document to which it is a party and the consummation of the transactions contemplated thereby, except for: (a) the required filings, consents, approvals, registrations, declarations, orders, authorizations and

16

notices set forth on Schedule 5.4 (the “Buyer Approvals”); and (b) such consents, approvals, orders, authorizations, notifications, registrations, declarations and filings the failure of which to be obtained or made would not reasonably be expected to have, individually or in the aggregate, a material adverse effect on Buyer’s ability to perform its obligations under the Transaction Documents to which it is a party, including its obligation to consummate the transactions contemplated thereby.

          Section 5.5 Litigation. As of the Closing Date, there are no lawsuits, claims, proceedings, investigations, reviews, audits or other actions before any Governmental Authority pending or, to the Knowledge of Buyer, threatened in writing by any Person against Buyer that would reasonably be expected to have, individually or in the aggregate, a material adverse effect on Buyer’s ability to perform its obligations under the Transaction Documents to which it is a party, including its obligation to consummate the transactions contemplated thereby; and (b) there is no order or unsatisfied judgment from any Governmental Authority that would reasonably be expected to have, individually or in the aggregate, a material adverse effect on Buyer’s ability to perform its obligations under the Transaction Documents to which it is a party, including its obligation to consummate the transactions contemplated thereby.

          Section 5.6 Brokers’ Fees. No broker, finder, investment banker or other Person is entitled to any brokerage fee, finders’ fee or other commission in connection with the transactions contemplated by this Agreement based upon arrangements made by Buyer or any of its Affiliates or Representatives.

          Section 5.7 Financial Ability. Buyer will have, as of the Closing Date, sufficient funds to pay the Purchase Price (in Dollars) and otherwise fund (in Dollars) the consummation of the transactions contemplated by this Agreement and satisfy (in Dollars) all other costs, expenses and obligations arising in connection with this Agreement and the transactions contemplated hereby.

          Section 5.8 Independent Investigation. Buyer is an experienced and knowledgeable investor in the oil and gas business and can bear the economic risk of its investment in the Membership Interests pursuant to this Agreement and the transactions contemplated hereby. Prior to entering into this Agreement and the transactions contemplated hereby, Buyer was advised by and has relied solely on its own legal, tax and other professional counsel concerning this Agreement and the values of the Membership Interests and the Assets. In making the decision to enter into and consummate this Agreement and the transactions contemplated hereby, Buyer has relied solely on the basis of its own independent valuation and due diligence investigation of the Membership Interests and the Assets.

          Section 5.9 Investment Representation. Buyer is purchasing the Membership Interests for its own account with the present intention of holding the Membership Interests for investment purposes and not with a view to or for sale in connection with any public distribution of the Membership Interests in violation of any federal or state securities Laws. Buyer acknowledges that the Membership Interests have not been registered under applicable federal and state securities Laws and that the Membership Interests may not be sold, transferred, offered for sale, pledged, hypothecated or otherwise disposed of unless such transfer, sale, assignment, pledge, hypothecation or other disposition is registered under the applicable federal and state securities Laws or pursuant to an exemption from registration under applicable federal and state securities Laws.

          Section 5.10 Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended. Buyer has such knowledge and experience in financial and business matters that it is capable of evaluating the merits and risks of an investment in the Membership Interests.

17

          Section 5.11 Waiver of Other Representations.

          (a) BUYER ACKNOWLEDGES AND AGREES THAT:

          (i) EXCEPT FOR THOSE REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS AGREEMENT OR THE OTHER TRANSACTION DOCUMENTS, NEITHER SELLER NOR ANY OF ITS AFFILIATES (INCLUDING THE COMPANY) OR REPRESENTATIVES HAS MADE OR IS MAKING ANY REPRESENTATION OR WARRANTY WHATSOEVER, EXPRESS OR IMPLIED, AT LAW OR IN EQUITY, IN RESPECT OF SELLER (OR THE COMPANY), ITS BUSINESS, OR ANY OF ITS ASSETS, THE MEMBERSHIP INTERESTS, LIABILITIES OR OPERATIONS, INCLUDING WITH RESPECT TO MERCHANTABILITY, FITNESS FOR ANY PARTICULAR PURPOSE, OR ANY FINANCIAL PROJECTIONS OR FORECASTS RELATING TO SELLER, ITS AFFILIATES (INCLUDING THE COMPANY), AND ANY SUCH OTHER REPRESENTATIONS AND WARRANTIES ARE HEREBY DISCLAIMED; AND

          (ii) EXCEPT AS OTHERWISE EXPRESSLY PROVIDED HEREIN OR IN THE OTHER TRANSACTION DOCUMENTS, SELLER’S (AND, IF APPLICABLE, ITS AFFILIATES’) INTERESTS IN THE MEMBERSHIP INTERESTS AND ITS INDIRECT INTEREST IN THE ASSETS ARE BEING TRANSFERRED “AS IS,” “WHERE IS,” AND “WITH ALL FAULTS,” AND SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATIONS OR WARRANTIES OF ANY KIND OR NATURE, EXPRESS OR IMPLIED, AS TO THE CONDITION, VALUE OR QUALITY OF THE COMPANY, THE ASSETS, THE MEMBERSHIP INTERESTS, OR THE PROSPECTS (FINANCIAL OR OTHERWISE), RISKS AND OTHER INCIDENTS OF THE MEMBERSHIP INTERESTS, THE COMPANY AND THE ASSETS.

          (b) BUYER HAS NOT RELIED ON ANY REPRESENTATION OR WARRANTY FROM SELLER OR ANY OF ITS AFFILIATES OR REPRESENTATIVES EXCEPT AS SET FORTH IN THIS AGREEMENT OR THE OTHER TRANSACTION DOCUMENTS.

          (c) SELLER AND BUYER AGREE THAT THE DISCLAIMERS OF CERTAIN WARRANTIES CONTAINED IN THIS SECTION 5.11 ARE “CONSPICUOUS” DISCLAIMERS FOR THE PURPOSES OF ANY APPLICABLE LAW, RULE OR ORDER.

          Section 5.12 Nonreportability under the HSR Act. Buyer represents that (a) it is its own “ultimate parent entity” for purposes of regulations set forth at 16 C.F.R. §801.1(a)(3), and (b) it does not meet the size of person test set forth in 15 U.S.C. §18a(a)(2)(B) of the HSR Act.

ARTICLE 6
COVENANTS

          Section 6.1 Confidentiality and Disclosure. Buyer and Seller acknowledge that their respective confidentiality and disclosure rights and obligations are established and governed by and subject to the terms of the Confidentiality and Disclosure Agreement.

          Section 6.2 Approvals. Without limiting the generality of the foregoing, the Parties shall (and shall use Reasonable Efforts to cause their respective Representatives and Affiliates to) consult and cooperate with and provide reasonable assistance to each other in: (a) obtaining, giving, and making any Seller Approvals and Buyer Approvals required to be obtained after (or otherwise impracticable to be obtained prior to) the Closing Date; and (b) in general, consummating and making effective this

18

Agreement and the transactions contemplated hereby; provided, however, that in order to obtain any consent, license, permit, qualification, or other permission or action, neither Party shall be required to pay any material consideration, to divest itself of any of, or otherwise rearrange the composition of, its assets or to agree to any conditions or requirements that would, individually or in the aggregate, reasonably be expected to have a material adverse effect on such Party.

          Section 6.3 Seller Marks. Buyer shall obtain no right, title, interest, license or any other right whatsoever to use the word “SandRidge” or any trademarks containing or comprising the foregoing, or any trademark confusingly similar thereto or dilutive thereof (collectively, the “Seller Marks”). From and after the Closing Date, Buyer agrees that it shall: (a) cease using Seller Marks in any manner, directly or indirectly, except for such limited uses as cannot be promptly terminated (e.g., signage, e-mail addresses, and as a referral or pointer to any acquired website), and to cease such limited usage of Seller Marks as promptly as possible after the Closing Date and in any event within ninety (90) days following the Closing Date; and (b) remove, strike over or otherwise obliterate all Seller Marks from all Assets and all other materials owned, possessed or used by the Seller Entities or their Affiliates. The Parties agree, because damages would be an inadequate remedy, that the Seller Entities shall be entitled to seek specific performance and injunctive relief as remedies for any breach of this Section 6.3 in addition to other remedies available at law or in equity. This covenant shall survive indefinitely, including following the termination of the Transaction Documents, without limitation as to time.

          Section 6.4 Books and Records; Access. From and after the Closing Date:

          (a) Seller and its respective Affiliates may retain a copy of any or all of the due diligence materials and other books and records relating to the Membership Interests, the Assets or the business or operation of the Assets, as applicable, prior to the Closing Date.

          (b) Buyer shall preserve and keep a copy of all books and records of the Seller Entities that relate to the use or ownership of the Membership Interests or the Assets on or before the Closing Date in Buyer’s possession for a period of at least seven (7) years after the Closing Date. After such seven (7) year period, before Buyer shall dispose of any such books and records, Buyer shall give Seller at least ninety (90) days’ prior written notice to such effect, and Seller shall be given an opportunity, at its own cost and expense, to remove and retain all or any part of such books and records as Seller may select.

          Section 6.5 Permits. Seller shall provide all notices and otherwise take all actions required to transfer or reissue any Permits as may be necessary as a result of or in furtherance of the transactions contemplated by the Transaction Documents. Seller shall use (and cause SR E&P to use) Reasonable Efforts to cooperate with Buyer to provide information necessary to apply for such Permits.

          Section 6.6 Tax Matters.

          (a) Transfer Taxes. Seller shall be responsible for any sales, use, transfer, documentary, registration, stamp, real property transfer, recording, gains, stock transfer, value-added and other similar Taxes and fees (“Transfer Taxes”), if any, arising out of or in connection with the transactions described in this Agreement, including the Asset Conveyances.

          (b) Tax Returns. Tax Returns that must be filed in connection with the Transfer Taxes described in Section 6.6(a) shall be prepared and filed by Seller. All other Tax Returns related to the Company, the Assets or the Membership Interests shall be prepared and filed by, and the Taxes due with respect to such Tax Returns shall be paid by, the Party responsible therefor under applicable Law. However, if any Non-Income Tax Return to be filed by a Party reflects a Non-Income Tax for which the

19

other Party is responsible pursuant to Section 6.6(c), the Party preparing such Tax Return shall furnish a draft thereof to the other Party at least thirty (30) days prior to the due date of such Tax Return for such other Party’s review and approval (which shall not be unreasonably withheld or delayed). Notwithstanding anything to the contrary in this Section 6.6(b), Buyer shall be responsible for all Texas franchise tax liability of the Company for periods beginning on or after the Closing Date.

          (c) Responsibility for Non-Income Taxes. As between the Parties, Seller shall be responsible for all Non-Income Taxes related to the Company, the Assets or the Membership Interests for periods prior to and including the Closing Date, and Buyer shall be responsible for all Non-Income Taxes related to the Company, the Assets or the Membership Interests for periods beginning after the Closing Date. For this purpose, Non-Income Taxes for any Tax year or period with respect to the Company, the Assets or the Membership Interests that includes the Closing Date (a “Straddle Period”) shall be allocated (i) to the period prior to the end of the Closing Date by multiplying the amount of such Taxes for the entire Straddle Period by a fraction the numerator of which is the number of days in the Straddle Period up to and including the Closing Date and the denominator of which is the number of days in the entire Straddle Period, and (ii) to the period beginning after the Closing Date by multiplying the amount of such Taxes for the entire Straddle Period by a fraction the numerator of which is the number of days in the Straddle Period beginning after the Closing Date and the denominator or which is the number of days in the entire Straddle Period. If a Party has paid a Non-Income Tax pursuant to Section 6.6(b) for which the other Party is responsible pursuant to this Section 6.6(c), the responsible Party shall reimburse the paying Party for the amount of such Tax promptly upon receipt of evidence of the payment of such Tax.

          (d) Cooperation. In connection with the preparation of Non-Income Tax Returns and audit examinations or administrative or judicial proceedings regarding Non-Income Tax liabilities related to the Company, the Membership Interests, or the Assets, Buyer and Seller shall use their Reasonable Efforts to cooperate fully with each other, including with respect to the furnishing or making available during normal business hours of records, personnel (as reasonably required), books of account, powers of attorney or other materials necessary or helpful for the preparation of such Tax Returns, the conduct of such audit examinations or the defense of such claims by Taxing Authorities as to the imposition of such Taxes.

          (e) Tax Characterization. Seller and Buyer recognize and intend that the transactions contemplated by this Agreement and the other Transaction Documents will result, for federal income tax purposes, in the transfer of the tax ownership of the Assets from Seller to Buyer, and neither Seller nor Buyer shall file (and Seller shall cause SR E&P not to file) any federal Tax Return or other federal Tax related documents or otherwise take any position with respect to federal income Taxes that is inconsistent with such characterization.

          Section 6.7 Further Assurances; Duty to Cooperate. Subject to the terms and conditions of this Agreement, at any time or from time to time after the Closing Date, at any Party’s request and without further consideration, the other Party shall execute and deliver (and, (i) in the case of Seller, Seller shall cause SR E&P to execute and deliver and (ii) in the case of Buyer, Buyer will cause the Company to execute and deliver) to such Party such other instruments of sale, transfer, conveyance, assignment and confirmation, provide such materials and information and take such other actions and execute and deliver such other documents as such Party may reasonably request in order to consummate the transactions contemplated by this Agreement. Seller and Buyer agree to, and to cause their Affiliates (including, in the case of Seller, SR E&P and, in the case of Buyer, the Company) and Representatives to, use their Reasonable Efforts to cooperate with each other after the Closing Date in connection with the transactions contemplated by this Agreement.

20

          Section 6.8 Maintenance of Company Existence. Until the first anniversary of the Closing Date, Buyer shall cause the legal existence of the Company to be maintained and shall not allow the Company to be dissolved or liquidated or merged into another entity.

          Section 6.9 Post Closing Date Assignments. At any time and from time to time after the Closing Date, Buyer and the Company shall have the right to request from Seller assignments of additional easements and rights-of-way that Buyer or the Company deems necessary for the purpose of constructing expansions of the Gathering System. Seller will promptly assign (and will cause SR Energy and SR E&P to assign) any such easement or right-of-way to the Company, at no additional cost to the Company or Buyer (other than the Purchase Price paid on the Closing Date); provided that Seller shall be obligated to make any such assignment only if: (a) Seller or any of its Affiliates owns such easement or right-of-way, (b) there are no restrictions prohibiting the assignment of such easement or right-of-way to the Company, and (c) assignment of such easement or right-of-way would not limit the ability of Seller or its Affiliates to construct, own or operate any Expansions or to conduct exploration and production activities.

ARTICLE 7
DELIVERABLES

          Section 7.1 Seller’s Deliverables.

          (a) Prior to or contemporaneously with the execution of this Agreement, Seller shall deliver (or, as applicable, cause SR Energy or SR E&P to deliver) the following documents and other items to Buyer:

          (i) an executed counterpart of the Assignment of Membership Interests, dated as of the Closing Date, in the form of Exhibit A (the “Assignment of Membership Interests”);

          (ii) an executed counterpart of the Confidentiality and Disclosure Agreement, dated as of the Closing Date, in the form of Exhibit B (the “Confidentiality and Disclosure Agreement”);

          (iii) an executed certification of non-foreign status of Seller in the form prescribed by Treasury Regulation § 1.1445-2(b)(2) (the “Certification of Non-Foreign Status”);

          (iv) an executed Guaranty Agreement, dated as of the Closing Date, in the form of Exhibit C (the “Seller Guaranty Agreement”);

          (v) an executed Guaranty Agreement, dated as of the Closing Date, in the form of Exhibit D (the “SR E&P Guaranty Agreement”);

          (vi) an executed Guaranty Agreement, dated as of the Closing Date, in the form of Exhibit E (the “SR Energy Company Guaranty Agreement”); and

          (vii) an executed Guaranty Agreement, dated as of the Closing Date, in the form of Exhibit F (the “SR Energy Buyer Guaranty Agreement”).

          (b) As soon as reasonably practicable after the execution of this Agreement, but, in any case no later than sixty (60) days after the Closing Date, Seller shall deliver (or, as applicable, cause SR Energy or SR E&P to deliver) the following documents and other items to Buyer:

21

          (i) originals of all documents relating to the Easements, Company Contracts and Records;

          (ii) originals of all of the books and records relating to the Membership Interests, the Assets or the business or operation of the Assets, prior to the Closing Date, as more fully described in Section 6.4(a); and

          (iii) original, executed copies of the Gathering Agreement, the O&M Agreement, the Certificate of Formation, the LLC Agreement and the Third Party Gathering Agreement.

          Section 7.2 Buyer’s Deliverables. Prior to or contemporaneously with the execution of this Agreement, Buyer shall deliver the following documents and other items to Seller:

          (a) an executed counterpart of the Assignment of Membership Interests; and

          (b) an executed counterpart of the Confidentiality and Disclosure Agreement.

ARTICLE 8
INDEMNIFICATION

          Section 8.1 Survival. All representations and warranties contained in this Agreement shall survive for twelve (12) months after the Closing Date, except that: (a) the representations and warranties contained in Section 4.9 and the Fundamental Representations and Warranties shall survive indefinitely; and (b) the representations and warranties in Section 4.8 shall survive until thirty (30) days after the expiration of the applicable statute of limitations with respect thereto. Notwithstanding the preceding sentence, any representation or warranty in respect of which indemnity may be sought under this Agreement will survive the time at which it would otherwise terminate pursuant to the preceding sentence if written notice of the inaccuracy or breach of such representation or warranty giving rise to such indemnity right has been given to the Party from whom such indemnification may be sought prior to the time such representation or warranty would have expired; provided that such right of indemnity shall continue to survive and shall remain a basis for indemnification hereunder only until the related claim for indemnification is resolved or disposed of in accordance with the terms of this Article 8.

          Section 8.2 Indemnification.

          (a) Notwithstanding any investigation made by Buyer or on behalf of Buyer, from and after the Closing Date, Seller will indemnify, defend and hold harmless Buyer and its officers, members, directors, employees and Affiliates (the “Buyer Indemnified Parties”) against any loss, cost, expense, liability, damage, sanction, judgment, fine, or penalty, including reasonable attorney’s and consultant’s fees and expenses (“Losses”) incurred or suffered as a result of, relating to or arising out of: (i) any failure of any representation or warranty made by Seller in this Agreement to be true and correct; (ii) the breach of any covenant or agreement made or to be performed by Seller pursuant to this Agreement; (iii) any noncompliance or liability relating to the Assets and arising under or in connection with any Environmental Law or Constituents of Concern, provided that such noncompliance occurred or such liability arose prior to the Closing Date; and (iv) any failure by Seller to pay, perform or otherwise discharge any of the Retained Liabilities. Notwithstanding anything herein to the contrary, Seller shall not be liable under Section 8.2(a)(i), (A) except to the extent the aggregate amount of Losses exceeds one hundred thousand Dollars ($100,000.00), or (B) for Losses in excess of one hundred million Dollars ($100,000,000.00); provided, however, that the limitation in clause (A) shall not apply to any breach of representation or warranty set forth in Section 4.8 or to the Fundamental Representations and Warranties

22

other than the representation and warranty contained in Section 4.13(b), and the limitation in clause (B) shall not apply to any breach of representation or warranty set forth in Sections 4.8 or 4.9 or to the Fundamental Representations and Warranties; provided, further, that in no event shall Seller be liable under Section 8.2(a)(i) for Losses in excess of two hundred million Dollars ($200,000,000) other than for breaches of the representations and warranties contained in Section 3.1, 3.2, 3.3, 3.5, 4.1, 4.2, 4.3 or 4.4.

          (b) Notwithstanding any investigation made by Seller or on behalf of Seller, from and after the Closing Date, Buyer will indemnify, defend and hold harmless each Seller Entity and its officers, shareholders, directors, employees and Affiliates (the “Seller Indemnified Parties”) against any and all Losses incurred or suffered as a result of, relating to, or arising out of: (i) any failure of any representation or warranty made by Buyer in this Agreement to be true and correct; (ii) the breach of any covenant or agreement made or to be performed by Buyer pursuant to this Agreement; and (iii) the operation of the Assets after the Closing Date to the extent such Losses are not incurred or suffered as a result of any act or omission of any Seller Entity or any of their respective Affiliates.

          (c) THE INDEMNIFICATION PROVISIONS IN THIS ARTICLE 8 SHALL BE ENFORCEABLE REGARDLESS OF WHETHER ANY PERSON (INCLUDING THE PERSON FROM WHOM INDEMNIFICATION IS SOUGHT) ALLEGES OR PROVES THE SOLE, CONCURRENT, CONTRIBUTORY OR COMPARATIVE NEGLIGENCE OF THE PERSON SEEKING INDEMNIFICATION OR THE SOLE OR CONCURRENT STRICT LIABILITY IMPOSED UPON THE PERSON SEEKING INDEMNIFICATION.

          Section 8.3 Procedures. Claims for indemnification under this Agreement shall be asserted and resolved as follows:

          (a) If any Person who or that is entitled to seek indemnification under Section 8.2 (an “Indemnified Party”) receives notice of the assertion or commencement of any claim asserted against such Indemnified Party by a third party (a “Third Party Claim”) in respect of any matter that is subject to indemnification under Section 8.2, the Indemnified Party shall promptly: (i) notify the Party from whom indemnification is sought (the “Indemnifying Party”) of the Third Party Claim; and (ii) transmit to the Indemnifying Party a written notice (a “Claim Notice”) describing in reasonable detail the nature of the Third Party Claim, a copy of all papers served with respect to such Third Party Claim (if any), the Indemnified Party’s best estimate of the amount of Losses attributable to the Third Party Claim, and the basis of the Indemnified Party’s request for indemnification under this Agreement. Failure to timely provide such Claim Notice shall not affect the right of the Indemnified Party’s indemnification hereunder, except to the extent the Indemnifying Party is prejudiced by such delay or omission.

          (b) The Indemnifying Party shall have the right to defend the Indemnified Party against such Third Party Claim. If the Indemnifying Party notifies the Indemnified Party that the Indemnifying Party elects to assume the defense of the Third Party Claim (which such election shall be without prejudice to the right of the Indemnified Party to dispute whether such claim is an indemnifiable Loss under this Article 8), then the Indemnifying Party shall have the right to defend such Third Party Claim with counsel selected by such Indemnifying Party, and by all appropriate proceedings, to a final conclusion or settlement at the sole and absolute discretion of the Indemnifying Party. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof; provided that the Indemnifying Party shall not enter into any settlement agreement without the written consent of the Indemnified Party (which consent shall not be unreasonably withheld, conditioned or delayed); provided, further, that such consent shall not be required if the settlement agreement: (i) contains a complete and unconditional general release by the Person asserting the Third Party Claim to all Indemnified Parties affected by the claim; (ii) does not contain any sanction or restriction upon the conduct of any business by the Indemnified Party or its Affiliates; and (iii) does not have a material

23

adverse Tax consequence with respect to the Company, the Assets or the Membership Interests after the Closing Date. If requested by the Indemnifying Party, the Indemnified Party agrees, at the sole cost and expense of the Indemnifying Party, to cooperate with the Indemnifying Party and its counsel in contesting any Third Party Claim that the Indemnifying Party elects to contest, including the making of any related counterclaim against the Person asserting the Third Party Claim or any cross complaint against any Person (other than the Indemnifying Party or any of its Affiliates or otherwise related parties). The Indemnified Party may participate in (but in no case control) any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 8.3(b); provided that, the Indemnified Party shall bear its own costs and expenses with respect to any such participation.

          (c) If the Indemnifying Party does not notify the Indemnified Party that the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 8.3(b), then the Indemnified Party shall have the right to defend, and be reimbursed for its reasonable cost and expense (but only if the Indemnified Party is actually entitled to indemnification under this Article 8) in regard to the Third Party Claim, with counsel selected by the Indemnified Party (who shall be reasonably satisfactory to the Indemnifying Party), and by all appropriate proceedings (which proceedings shall be prosecuted diligently by the Indemnified Party). In such circumstances, the Indemnified Party shall defend any such Third Party Claim in good faith and have full control of such defense and proceedings; provided, however, that the Indemnified Party may not enter into any compromise or settlement of such Third Party Claim if indemnification is to be sought under this Article 8 without the Indemnifying Party’s consent (which consent shall not be unreasonably withheld, conditioned or delayed). The Indemnifying Party may participate in, but not control, any defense or settlement controlled by the Indemnified Party pursuant to this Section 8.3(c), and the Indemnifying Party shall bear its own costs and expenses with respect to any such participation.

          (d) Any claim by an Indemnified Party on account of Losses that does not result from a Third Party Claim (a “Direct Claim”) will be asserted by giving the Indemnifying Party reasonably prompt written notice thereof, but in any event not later than thirty (30) days after the Indemnified Party becomes aware, or should have become aware through the exercise of reasonable and diligent inquiry, of such Direct Claim. Such notice by the Indemnified Party shall describe the Direct Claim in reasonable detail, include copies of all available material written evidence thereof, and indicate the estimated amount, if reasonably practicable, of damages that have been sustained by the Indemnified Party. The Indemnifying Party will have a period of five (5) Business Days to respond in writing to such Direct Claim. If the Indemnifying Party does not so respond within such five (5) Business Day period, the Indemnifying Party will be deemed to have rejected such Direct Claim, in which event the Indemnified Party will be free to pursue such remedies as may be available to the Indemnified Party under the terms and subject to the provisions of this Agreement.

          (e) Any indemnification payment made pursuant to this Agreement shall be net of any insurance proceeds realized by and paid to the Indemnified Party in respect of such claim, and the amount of any Loss shall take into account any Tax or other benefits attributable to the circumstance or event giving rise to such Loss, assuming for such purpose that any Tax loss, deduction or similar item is utilized at a thirty six percent (36%) effective Tax rate and that any Tax credit offsets Tax liability on a Dollar-for-Dollar basis.

          Section 8.4 Exclusive Remedy and Release. The indemnification and remedies set forth in this Article 8 shall, from and after the Closing Date, constitute the sole and exclusive remedies of the Parties with respect to any breach of representation or warranty or non-performance, partial or total, of any covenant or agreement contained in this Agreement; provided, however, that nothing in this Section 8.4 shall prevent either Party from seeking injunctive or equitable relief in pursuit of its indemnification claims under this Article 8.

24

ARTICLE 9
MISCELLANEOUS

          Section 9.1 Successors and Assigns. This Agreement (and all covenants, rights, obligations, and agreements created hereunder) shall be binding upon, and inure to the benefit of, the Parties and their respective successors and permitted assigns. Neither Party shall assign this Agreement or any part hereof without the prior written consent of the other Party.

          Section 9.2 Notices. All notices, requests and other communications hereunder must be in writing and will be deemed to have been duly given only if delivered personally, by facsimile transmission, by reputable national overnight courier service or by registered or certified mail (postage prepaid) to the Parties at the following addresses (or facsimile numbers), as applicable:

If to Buyer, to:	TCW Pecos Midstream, L.L.C.
	c/o TCW Asset Management Company
	333 Clay Street, Suite 4150
	Houston, Texas 77002
	Telephone No.: 713.615.7423
	Facsimile No.: 713.615.7460
	Attention: Clayton R. Taylor
with a copy to:	TCW Asset Management Company
	865 South Figueroa Street, Suite 1800
	Los Angeles, California 90017
	Telephone No. 213.244.0044
	Facsimile No.: 213.244.0604
	Attention: R. Blair Thomas
If to Seller, to:	SandRidge Midstream, Inc.
	123 Robert S. Kerr Avenue
	Oklahoma City, Oklahoma 73102
	Telephone No.: 405.429.5500
	Facsimile No.: 405.429.5988
	Attention: President
with a copy to:	General Counsel
	SandRidge Energy, Inc.
	123 Robert S. Kerr Avenue
	Oklahoma City, Oklahoma 73102
	Telephone No.: 405.429.5500
	Facsimile No.: 405.429.5983

or to such other address or addresses (or facsimile numbers) as the Parties may from time to time designate in writing.

25

          Section 9.3 Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument.

          Section 9.4 Rights. The failure of either Party to exercise any right granted hereunder shall not impair nor be deemed a waiver of that Party’s privilege of exercising that right at any subsequent time or times.

          Section 9.5 Amendments. This Agreement may not be amended or modified in any manner except by a written document signed by the Parties that expressly amends this Agreement.

          Section 9.6 No Waiver. No waiver by either Party of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless expressly provided. No waiver shall be effective unless made in writing and signed by the Party to be charged with such waiver.

          Section 9.7 Governing Law; Jurisdiction.

          (a) This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Texas, without regard to choice of law principles that would require the application of the laws of any other jurisdiction.

          (b) Each Party agrees that the appropriate, exclusive and convenient forum for any disputes between any of the Parties arising out of this Agreement or the transactions contemplated hereby shall be in any state or federal court in Houston or Dallas, Texas, and each of the Parties irrevocably submits to the jurisdiction of such courts solely in respect of any legal proceeding arising out of or related to this Agreement or the transactions contemplated hereby. The Parties further agree that the Parties shall not bring suit with respect to any disputes arising out of this Agreement or the transactions contemplated hereby in any court or jurisdiction other than the above specified courts.

          (c) To the extent that any Party has or hereafter may acquire any immunity from jurisdiction of any court or from any legal process (whether through service or notice, attachment prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, each such Party hereby irrevocably (i) waives such immunity in respect of its obligations with respect to this Agreement, and (ii) submits to the personal jurisdiction of any court described in Section 9.7(b).

          (d) Each Party hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby in any court referred to in Section 9.7(b). Each of the Parties hereby irrevocably waives, to the fullest extent permitted by applicable Law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

          Section 9.8 Jury Waiver. THE PARTIES HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE, TO THE FULLEST EXTENT THEY MAY LEGALLY AND EFFECTIVELY DO SO, THE RIGHT TO A JURY IN ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

          Section 9.9 Limitation of Liability. NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY, NEITHER PARTY SHALL BE LIABLE TO THE

26

OTHER PARTY FOR SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE OR EXEMPLARY DAMAGES SUFFERED BY SUCH PARTY RESULTING FROM OR ARISING OUT OF THIS AGREEMENT OR THE BREACH HEREOF OR UNDER ANY OTHER THEORY OF LIABILITY, WHETHER TORT, NEGLIGENCE, STRICT LIABILITY, BREACH OF CONTRACT, WARRANTY, INDEMNITY, OR OTHERWISE, INCLUDING, LOSS OF USE, INCREASED COST OF OPERATIONS, LOSS OF PROFIT OR REVENUE, OR BUSINESS INTERRUPTIONS. IN FURTHERANCE OF THE FOREGOING, EACH PARTY RELEASES THE OTHER PARTY AND WAIVES ANY RIGHT OF RECOVERY FOR SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, OR EXEMPLARY DAMAGES SUFFERED BY SUCH PARTY REGARDLESS OF WHETHER ANY SUCH DAMAGES ARE CAUSED BY THE OTHER PARTY’S NEGLIGENCE (AND REGARDLESS OF WHETHER SUCH NEGLIGENCE IS SOLE, JOINT, CONCURRENT, ACTIVE, PASSIVE, OR GROSS NEGLIGENCE), FAULT, OR LIABILITY WITHOUT FAULT; PROVIDED, HOWEVER, THE FOREGOING SHALL NOT BE CONSTRUED AS LIMITING AN OBLIGATION OF A PARTY HEREUNDER TO INDEMNIFY, DEFEND, AND HOLD HARMLESS THE OTHER PARTY AGAINST CLAIMS ASSERTED BY UNAFFILIATED THIRD PARTIES, INCLUDING, BUT NOT LIMITED TO, THIRD PARTY CLAIMS FOR SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, OR EXEMPLARY DAMAGES.

          Section 9.10 No Third Party Beneficiaries. Except for the Persons indemnified hereunder, this Agreement is for the sole benefit of the Parties and shall not inure to the benefit of any other Person whomsoever or whatsoever, it being the intention of the Parties that no third Person shall be deemed a third party beneficiary to this Agreement.

          Section 9.11 Further Assurances. Subject to the terms and conditions set forth in this Agreement, each Party shall take such acts and execute and deliver such documents as may be reasonably required to effectuate the purposes of this Agreement.

          Section 9.12 Expenses. Except as otherwise expressly provided herein, each Party shall bear its own expenses incurred in connection with this Agreement and the transactions contemplated hereby whether or not such transactions shall be consummated, including all fees of its legal counsel, financial advisers, accountants and other Representatives.

          Section 9.13 Entire Agreement. This Agreement (together with the schedules and exhibits), the Confidentiality and Disclosure Agreement, and the other Transaction Documents, constitute the entire agreement among the Parties and supersede any other agreements, whether written or oral, that may have been made or entered into by the Parties or any of their respective Affiliates relating to the transactions contemplated hereby and thereby.

          Section 9.14 Schedules.

          (a) Unless the context otherwise requires, all capitalized terms used on the Schedules shall have the respective meanings assigned in this Agreement. No reference to or disclosure of any item or other matter on the Schedules shall be construed as an admission, acknowledgment, or indication that such item or other matter is material or that such item or other matter is required to be referred to or disclosed on the Schedules. No disclosure on the Schedules relating to any possible breach or violation of any agreement, Law, or Permit shall be construed as an admission or indication that any such breach or violation exists or has actually occurred.

          Section 9.15 Publicity. All press releases or other public communications of any nature whatsoever relating to the transactions contemplated by this Agreement (and the execution of this

27

Agreement) shall be subject to the prior written consent of both Buyer and Seller, which consent shall not be unreasonably withheld, conditioned or delayed; provided, however, that nothing herein shall prevent a Party from publishing such press releases or other public communications as is necessary to satisfy such Party’s obligations under applicable Law or under the rules of any listing authority or stock exchange.

          Section 9.16 Headings. The headings and captions in this Agreement have been inserted for convenience of reference only and shall not define or limit any of the terms and provisions hereof.

          Section 9.17 Rights and Remedies. Except as otherwise provided in this Agreement, each Party reserves to itself all rights, counterclaims, other remedies, and defenses to which such Party is or may be entitled arising from or out of this Agreement or as otherwise provided by Law.

          Section 9.18 No Inducements. No director, employee, or agent of any Party shall give or receive any commission, fee, rebate, gift or entertainment of significant cost or value in connection with this Agreement.

          Section 9.19 No Partnership. Nothing contained in this Agreement shall be construed to create an association, trust, partnership or joint venture or impose a trust, fiduciary, or partnership duty, obligation, or liability on or with regard to either Party.

          Section 9.20 Rules of Construction. In construing this Agreement, the following principles shall be followed:

          (a) no consideration shall be given to the fact or presumption that one Party had a greater or lesser hand in drafting this Agreement;

          (b) examples shall not be construed to limit, expressly or by implication, the matter they illustrate;

          (c) the word “includes” and its syntactical variants mean “includes, but is not limited to” and corresponding syntactical variant expressions; and

          (d) the plural shall be deemed to include the singular and vice versa, as applicable.

[Signature Page Follows]

28

     IN WITNESS WHEREOF this Agreement has been duly executed and delivered by each Party as of the date first above written.

SELLER: SANDRIDGE MIDSTREAM, INC.
By:	/s/ Richard J. Gognat
Name:	Richard J. Gognat
Title:	Senior Vice President

BUYER: TCW PECOS MIDSTREAM, L.L.C. By:  TCW Asset Management Company, its Manager:
By:	/s/ Clayton R. Taylor
	Clayton R. Taylor
	Vice President
By:	/s/ Kurt A. Talbot
	Kurt A. Talbot
	Managing Director

Signature Page to
Membership Interest Purchase Agreement

EX-10.5

Exhibit 10.5

Specific terms in this exhibit have been redacted, as marked with three asterisks (***), because confidential treatment for those terms has been requested. The redacted material has been separately filed with the Securities and Exchange Commission.

GAS GATHERING AGREEMENT

BY AND BETWEEN

PIÑON GATHERING COMPANY, LLC

AND

SANDRIDGE EXPLORATION AND PRODUCTION, LLC

DATED

JUNE 30, 2009

TABLE OF CONTENTS

	Page
Article 1 DEFINITIONS		1
Article 2 DEDICATION AND SERVICES		14
Section 2.1 Dedication		14
Section 2.2 Shipper’s Right To Deliver Other Gas		15
Section 2.3 Covenant Running with the Land		15
Section 2.4 Services		15
Section 2.5 Operation and Maintenance of Gathering System		15
Section 2.6 Priority of Services; Curtailment		16
Section 2.7 Third Party Gas		16
Section 2.8 Release of Dedicated Gas		16
Section 2.9 Maintenance of System Capacity		18
Section 2.10 Memorandum of Agreement		18
Section 2.11 No Breach		18
Article 3 MONTHLY SHORTFALL PAYMENTS		18
Section 3.1 Deliveries in Excess of the Base Volume		18
Section 3.2 Deliveries Less Than the Base Volume		18
Section 3.3 Force Majeure Volumes		19
Section 3.4 Monthly Shortfall Payments Offset Against Future Fees		19
Section 3.5 Example of Operation of Monthly Excess Bank		19
Section 3.6 Adjustment to Account for Released Gas		19
Article 4 WELL CONNECTIONS AND EXPANSIONS		20
Section 4.1 Well Connection and Timing		20
Section 4.2 System Expansions		20
Section 4.3 Gatherer’s Purchase of Expansions		21
Article 5 TERM		21
Section 5.1 Term		21
Section 5.2 Obligations Upon Termination		21
Article 6 SERVICE FEES AND FL&U		21
Section 6.1 Gathering Fee		21
Section 6.2 Commodity Fee		22
Section 6.3 Adjustment to Base Fee and Commodity Fee after Trigger Event		22
Section 6.4 Condensate		22
Section 6.5 Modifications to Determination of Operations Fee		23
Section 6.6 Operating Expense Budget Process		23
Article 7 ALLOCATIONS		24
Section 7.1 Fuel, Lost and Unaccounted for Gas Allocation Procedures		24
Section 7.2 Modifications to Allocation Procedures		24
Article 8 SHIPPER COMMITMENTS AND RIGHTS		25
Section 8.1 Conveyance of Rights to Gatherer		25
Section 8.2 Shipper Compression		25
Section 8.3 Gas for Lease Operations		25
Section 8.4 Pooling or Units		26
Section 8.5 Operational Control of Shipper’s Wells		26
Section 8.6 Access to Facilities		26
Section 8.7 Line Pack		26
Section 8.8 Cholla Gathering Agreement		26
Article 9 MAINTENANCE AND MARKETING OF CONDENSATE		26

TABLE OF CONTENTS

	Page
Section 9.1 Maintenance		26
Section 9.2 Marketing of Condensate		26
Article 10 RECEIPT POINTS, DELIVERY POINTS, AND PRESSURES		27
Section 10.1 Receipt Points		27
Section 10.2 Delivery Points		27
Section 10.3 Uniform Deliveries		27
Section 10.4 Pressure at Receipt Points		27
Section 10.5 Pressure at Delivery Points		28
Section 10.6 Arrangements Prior to Receipt and After Redelivery		28
Article 11 NOMINATION AND BALANCING PROCEDURES		29
Section 11.1 Notice of Available Capacity		29
Section 11.2 Nomination Procedures		29
Section 11.3 Gas Balancing		30
Section 11.4 Imbalances		30
Section 11.5 Maintenance		31
Section 11.6 Unscheduled Capacity Allocations		32
Section 11.7 Modifications to Nomination and Balancing Procedures		32
Article 12 GAS QUALITY		32
Section 12.1 Receipt Point Gas Quality Specifications		32
Section 12.2 Non-Conforming Gas		32
Section 12.3 Off-Specification Receipts		33
Section 12.4 Reimbursement and Shipper Indemnity		33
Section 12.5 Delivery Point Gas Quality Specifications		33
Section 12.6 Gatherer Indemnity		33
Article 13 MEASUREMENT EQUIPMENT AND PROCEDURES		33
Section 13.1 Equipment and Specifications		33
Section 13.2 Gas Meter Standards		33
Section 13.3 Notice of Measurement Equipment Inspection and Calibration		34
Section 13.4 Measurement Accuracy Verification		34
Section 13.5 Special Tests		35
Section 13.6 Metered Flow Rates in Error		35
Section 13.7 Record Retention		35
Section 13.8 Correction Factors for Volume Measurement		35
Section 13.9 Exception to Gas Measurement Basis		36
Section 13.10 Gas Sampling		36
Section 13.11 Modifications to Measurement Procedures		37
Section 13.12 Measurement Disputes		37
Article 14 NOTICES		37
Article 15 PAYMENTS		38
Section 15.1 Payments and Invoices		38
Section 15.2 Audit Rights		38
Section 15.3 Right to Suspend on Failure to Pay		39
Section 15.4 Creditworthiness		39
Section 15.5 Payment Disputes		39
Section 15.6 Interest on Late Payments		40
Article 16 FORCE MAJEURE		40
Section 16.1 Suspension of Obligations		40
Section 16.2 Definition of Force Majeure		40

TABLE OF CONTENTS

	Page
Section 16.3 Non-Gatherer Force Majeure Events		41
Article 17 INDEMNIFICATION		41
Section 17.1 Gatherer		41
Section 17.2 Shipper		42
Article 18 CUSTODY AND TITLE		42
Section 18.1 Shipper Custody		42
Section 18.2 Gatherer Custody		42
Section 18.3 Shipper Warranty		42
Section 18.4 Title		43
Section 18.5 Carbon Dioxide		43
Article 19 ROYALTY AND TAXES		43
Section 19.1 Proceeds of Production		43
Section 19.2 Production Taxes		43
Section 19.3 Indemnification		43
Article 20 DISPUTE RESOLUTION		43
Section 20.1 Negotiation		43
Section 20.2 Jurisdiction and Venue		44
Section 20.3 Jury Waiver		44
Section 20.4 Costs and Expenses		44
Article 21 MISCELLANEOUS		44
Section 21.1 Rights		44
Section 21.2 Applicable Laws		44
Section 21.3 Governing Law		44
Section 21.4 Assignments		45
Section 21.5 Set-off		46
Section 21.6 Published Indices		46
Section 21.7 Exhibits		46
Section 21.8 Entire Agreement, Amendments		47
Section 21.9 Waivers		47
Section 21.10 Limitation of Liability		47
Section 21.11 Headings		48
Section 21.12 Rights and Remedies		48
Section 21.13 No Partnership		48
Section 21.14 Rules of Construction		48
Section 21.15 No Third Party Beneficiaries		48
Section 21.16 Further Assurances		48
Section 21.17 No Inducements		48
Section 21.18 Counterpart Execution		48

TABLE OF EXHIBITS

EXHIBITS

Exhibit A — Map of Dedicated Area
Exhibit B — Dedicated Area Description
Exhibit C — Base Volumes
Exhibit D — Wellhead Meters
Exhibit E — Delivery Points
Exhibit F — Sub-Systems
Exhibit G — Trigger Event Example
Exhibit H — Gas Quality Specifications
Exhibit I — Monthly Average Receipt Point Pressure Example
Exhibit J — Gathering System
Exhibit K — Monthly Excess Bank Example
Exhibit L — Memorandum of Gas Gathering Agreement

GAS GATHERING AGREEMENT

     This Gas Gathering Agreement (as amended, restated or otherwise modified from time to time, the “Agreement”) is made and entered into this 30th day of June, 2009 (the “Effective Date”), by and between SANDRIDGE EXPLORATION AND PRODUCTION, LLC, a Delaware limited liability company (together with its Affiliates, successors and their respective Affiliates, “Shipper”), and PIÑON GATHERING COMPANY, LLC, a Delaware limited liability company (together with its successors and permitted assigns, “Gatherer”). Shipper and Gatherer may be referred to herein individually as “Party,” or collectively as the “Parties.”

RECITALS

     A. Gatherer owns and operates the Gathering System (as defined in Article 1 below).

     B. Shipper owns or controls Shipper’s Gas (as defined in Article 1 below) produced from wells connected to, or that in the future may be connected to, the Gathering System.

     C. Subject to the terms and conditions of this Agreement, Shipper desires, and has the capability, to deliver to Gatherer, and Gatherer desires to receive from Shipper, Shipper’s Gas, at the Receipt Points for Gathering on the Gathering System.

     D. In accordance with the terms and conditions of this Agreement, Gatherer will provide the Services with respect to Shipper’s Gas delivered to Gatherer hereunder.

     NOW THEREFORE, in consideration of the premises and mutual covenants set forth in this Agreement, the Parties agree as follows:

ARTICLE 1
DEFINITIONS

     Capitalized terms used in this Agreement shall have the following meanings:

     1.1 Accounting Arbitrator. The first of the following firms (or successor thereof) that has not been engaged by either of the Parties at any time during the one (1) year period immediately prior to the time of selection: Ernst & Young, KPMG, Deloitte, PricewaterhouseCoopers, Grant Thornton. If all of such firms (or their successors) have been engaged by either one or both of the Parties during such one (1) year period, then the Parties shall in good faith mutually agree on one of such firms (or their successors) or another accounting firm which has not been engaged by either of the Parties during such one (1) year period to serve as the Accounting Arbitrator.

     1.2 Adjusted Force Majeure Volumes. As defined in Section 3.3 of this Agreement.

     1.3 Affiliate. With respect to any Person, any other Person that, directly or indirectly, controls, is controlled by, or is under common control with, such specified Person through one or more intermediaries or otherwise. For the purposes of this definition, “control” means, where used with respect to any Person, 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 interests, by contract or otherwise, and the terms “controlling” and “controlled” have correlative meanings.

     1.4 Agreement. As defined in the preamble of this Agreement.

     1.5 Alternate Delivery Points. Those points of delivery not identified as Delivery Points on Exhibit E, but which are agreed to by the Parties from time to time to act as Delivery Points hereunder.

     1.6 Base Fee. Subject to adjustment in accordance with Section 6.3, with respect to any Month, the sum of (i) *** and (ii) ***.

     1.7 Base Volume. With respect to any Month during the Term, the Volume of Gas set forth in Exhibit C applicable to such Month, prorated for any partial Month and as adjusted pursuant to Section 3.3; provided, that if at any time Dedicated Gas is permanently released from the Dedicated Area pursuant to the terms hereof, the Volumes of Gas set forth in Exhibit C shall be reduced in accordance with Section 3.6.

     1.8 Base Volume Monthly Gas Receipt. With respect to any Month, the total actual Volume of Gas received into the Gathering System during such Month that, without duplication, is (i) produced from a well located on lands within the Dedicated Area or on lands pooled or unitized therewith, (ii) produced from a well operated by Shipper and located on lands outside of the Dedicated Area or lands pooled or unitized therewith, or (iii) Shipper’s Gas.

     1.9 Btu or British Thermal Unit. The amount of heat required to raise the temperature of one (1) pound of water from fifty-nine degrees Fahrenheit (59ºF) to sixty degrees Fahrenheit (60ºF) at a constant pressure of fourteen and sixty-five hundredths (14.65) psia.

     1.10 Business Day. Any calendar day, other than a Saturday or Sunday, on which commercial banks in Dallas, Texas are open for business.

     1.11 Calendar Quarter or Quarterly. The quarterly periods of (i) January 1st through March 31st, (ii) April 1st through June 30th, (iii) July 1st through September 30th, and (iv) October 1st through December 31st.

     1.12 Calendar Year. The time period from January 1st through December 31st of the same calendar year.

     1.13 Central Clock Time. Central Standard time throughout the year, as adjusted for Central Daylight time.

     1.14 Century Plant. The CO2 gas treating and delivery plant under construction and owned by OXY USA, Inc. located in Section 68, Block 101, T.C. RR Company Survey, Pecos County, Texas.

     1.15 Cholla Gathering Agreement. That certain Gas Gathering Agreement dated June 30, 2009, between Cholla Pipeline, L.P. and SandRidge Exploration and Production, LLC relating to Gas being shipped on the Cholla gathering system.

2

     1.16 Claim. Any lawsuit, claim, proceeding, investigation, review, audit or other cause of action of any kind.

     1.17 Commodity Fee. As defined in Section 6.2 of this Agreement.

     1.18 Company Conveyance. That certain Assignment of Membership Interests dated as of June 30, 2009, between SandRidge Midstream, Inc. and TCW Pecos Midstream, LLC, together with all amendments, modifications or waivers thereto.

     1.19 Condensate. Hydrocarbons that have condensed from Gas downstream of a Receipt Point and are collected as a liquid in the Gathering System.

     1.20 Condensate Purchase Price. As defined in Section 6.4 of this Agreement.

     1.21 Confidentiality and Disclosure Agreement. That certain Confidentiality and Disclosure Agreement dated as of June 30, 2009, between SandRidge Energy, Inc., TCW Asset Management Company, and Piñon Gathering Company, LLC, together with all amendments, modifications or waivers thereto.

     1.22 CPI Index. The Consumer Price Index — All Urban Consumers (Series ID CUUR0000SA0), Not Seasonally Adjusted, U.S. city average, All items (Base Period 1982-84=100), as published by the United States Department of Labor, Bureau of Labor Statistics.

     1.23 Cubic Foot of Gas. The volume of Gas occupying one (1) cubic foot of space when such Gas is at a base pressure of fourteen and sixty-five hundredths (14.65) psia and at a base temperature of sixty degrees Fahrenheit (60ºF). Whenever the conditions of pressure and temperature differ from the foregoing standard, conversion from the foregoing standard conditions shall be made in accordance with the Ideal Gas Laws.

     1.24 Day or Daily. A period of time commencing at 6:00 A.M., Central Clock Time, on a calendar day and ending at 6:00 A.M., Central Clock Time, on the next succeeding calendar day.

     1.25 Dedicated Area. The lands identified on the map attached hereto as Exhibit A and more particularly described on Exhibit B.

     1.26 Dedicated Gas. As defined in Section 2.1 of this Agreement.

     1.27 Dedication. As defined in Section 2.1 of this Agreement.

     1.28 Dehydration. The removal of water in its vapor phase from Gas, such that the Gas contains seven (7) pounds of water or less per MMcf.

     1.29 Delivery Point Gas. As defined in Section 2.4(c) of this Agreement.

     1.30 Delivery Point Gas Quality Specifications. As set forth in Exhibit H attached hereto.

3

     1.31 Delivery Points. The points of delivery identified in Exhibit E attached hereto and the Alternate Delivery Points.

     1.32 Effective Date. As defined in the preamble of this Agreement.

     1.33 Expansion Period. As defined in Section 4.2 of this Agreement.

     1.34 Expansions. As defined in Section 4.2 of this Agreement.

     1.35 Field Fuel. With respect to each Month and each Sub-System, the measured Quantity of Gas actually used and consumed in the operation of such Sub-System during such Month, including, but not limited to, compressor fuel, Dehydration fuel, and instrument Gas; provided, however, (i) if Other Shippers use Shipper Compression, then the Gas used and consumed in the operation of Shipper Compression shall also be included in Field Fuel for the applicable Sub-System, and (ii) for each Month following the first anniversary of the end of the Month in which the Expansion Period ends, Field Fuel for each Sub-System shall be limited to no more than one hundred ten percent (110%) of the average Monthly Field Fuel measured for such Sub-System during the twelve (12) Months immediately following the Month in which the Expansion Period ends.

     1.36 Firm Basis. The provision of Services hereunder, which may only be interrupted or curtailed by Gatherer as a result of a Force Majeure event or Maintenance.

     1.37 Force Majeure. As defined in Section 16.2 of this Agreement.

     1.38 Force Majeure Volumes. With respect to any Month, the Volumes of Gas that Shipper is not able to deliver into the Gathering System during such Month due to Force Majeure.

     1.39 Fuel, Lost and Unaccounted for Gas or FL&U. With respect to each Month and each of the Sweet Gas Gathering System and the Sour Gas Gathering System, the Thermal Content of Gas necessarily flared or vented on such system during such Month, Field Fuel for such system for such Month, and Gas that otherwise cannot be sufficiently accounted for in such system for such Month.

     1.40 G&A Expenses. All (i) costs, fees and expenses incurred by Gatherer in connection with any management, administration, marketing and other services necessary or advisable to run Gatherer’s business of owning and operating the Gathering System, including, without limitation, any fees of attorneys, consultants, Tax or financial accountants, auditors, experts or advisors, and (ii) other general or administrative expenses of Gatherer, to the extent, and only to the extent, that each of the foregoing is (x) not duplicative of any costs, fees or expenses included in the definition of Operating Expenses, (y) reasonably incurred in accordance with this Agreement, and (z) reasonably allocated to the Gathering System.

     1.41 GAAP. Generally accepted accounting principles, consistently applied.

     1.42 Gallon. One (1) U.S. gallon.

4

     1.43 Gas. Any mixture of hydrocarbons or of hydrocarbons and non-combustible gases produced from wells.

     1.44 Gatherer. As defined in the preamble of this Agreement.

     1.45 Gatherer Controlled Event. As defined in Section 2.8(c) of this Agreement.

     1.46 Gatherer Force Majeure Event. As defined in Section 2.8(b) of this Agreement.

     1.47 Gatherer Indemnified Parties. Gatherer, its successors and permitted assigns, and their respective Affiliates, shareholders, members, partners, officers, directors, employees, and agents.

     1.48 Gathering or Gather. The receipt of Gas by Gatherer at the Receipt Points for transportation, compression and/or Dehydration, and the delivery of Delivery Point Gas to the Delivery Points.

     1.49 Gathering Fees. As defined in Section 6.1 of this Agreement.

     1.50 Gathering System. The “Gathering System” as defined in the Membership Interest Purchase Agreement, as such gathering system is more particularly described in Exhibit J attached hereto, together with the facilities acquired by Gatherer in each Subsequent Acquisition, including all additions and alterations made to any of the foregoing by Gatherer from time to time.

     1.51 Governmental Authority. Any federal, state, municipal, local or similar governmental authority, regulatory or administrative agency, court or arbitral body with jurisdiction over the Parties, this Agreement, any of the transactions contemplated hereby or the facilities utilized under this Agreement.

     1.52 Gross Heating Value. The number of Btus produced by the complete combustion in air, at a constant pressure, of one Cubic Foot of Gas when the products of combustion are cooled to the initial temperature of the Gas and air and all water formed by combustion is condensed to the liquid state. The resultant number of Btus determined above shall be adjusted to reflect the actual water content of the Gas at the Delivery Points except that Gas containing seven (7) pounds of water or less per MMcf shall be considered dry for purposes of this adjustment.

     1.53 Guaranty Agreements. Collectively, that certain (a) Guaranty Agreement dated as of June 30, 2009, by SandRidge Energy, Inc. in favor of TCW Pecos Midstream, LLC, (b) Guaranty Agreement dated as of June 30, 2009, by SandRidge Energy, Inc. in favor of Gatherer, (c) Guaranty Agreement dated as of June 30, 2009, by SandRidge Exploration and Production, LLC in favor of Gatherer, and (d) Guaranty Agreement dated as of June 30, 2009, by SandRidge Midstream, Inc. in favor of Gatherer, in each case, together with all amendments, modifications or waivers thereto.

5

     1.54 High-Pressure Sour Sub-System. That portion of the Gathering System that typically operates at pressures at or above seven hundred fifty (750) psig, and delivers Gas to a treating and/or processing plant for removal of carbon dioxide and other contaminants.

     1.55 High-Pressure Sweet Sub-System. That portion of the Gathering System that typically operates at pressures at or above seven hundred fifty (750) psig, and delivers such Gas to third-party pipelines.

     1.56 Ideal Gas Laws. The thermodynamic laws applying to perfect gases.

     1.57 Imbalance Cash-Out Price. For each Month, (i) the average of the daily “Midpoint” prices for that Month as reported in the Platt’s Gas Daily table entitled “Daily price survey ($/MMBtu)” under the heading “Permian Basin Area” in the row labeled “Waha,” minus (ii) the price per MMBtu to transport Gas from the applicable Delivery Point to Waha.

     1.58 Imbalance Gas. As defined in Section 11.4(a) of this Agreement.

     1.59 Initial Excess Pressure Period. As defined in Section 10.4(c) of this Agreement.

     1.60 Initial Force Majeure Period. As defined in Section 2.8(b) of this Agreement.

     1.61 Initial Purchase Price. The Purchase Price as defined in and paid by Gatherer pursuant to the Membership Interest Purchase Agreement.

     1.62 Initial Service Interruption Period. As defined in Section 2.8(c) of this Agreement.

     1.63 Intercompany Conveyance. That certain Assignment, Bill of Sale and Conveyance dated as of June 30, 2009, between SandRidge Midstream, Inc. and Piñon Gathering Company, LLC, together with all amendments, modifications or waivers thereto.

     1.64 Interests. Any right, title, or interest in lands and the right to produce oil and/or Gas therefrom, whether arising from fee ownership, working interest ownership, mineral ownership, leasehold ownership, farmout or other contractual arrangement or arising from any pooling, unitization, or communitization of any of the foregoing rights.

     1.65 L&U Percentage. With respect to each Month and each of the Sweet Gas Gathering System and the Sour Gas Gathering System, the percentage obtained by dividing (i) the sum of the Quantity of Gas necessarily flared or vented during such Month plus the Quantity of Gas that cannot be sufficiently accounted for in such system during such Month into (ii) the total Quantity of Gas received into such system during such Month.

     1.66 Line Pack. A Volume and Quantity of Gas equal to the Volume and Quantity of Gas in the Gathering System as of the Effective Date and from time to time thereafter.

     1.67 LLC Agreement. That certain Amended and Restated Limited Liability Company Agreement of Piñon Gathering Company, LLC, together with all amendments, modifications or waivers thereto.

6

     1.68 Loss. Any loss, cost, expense, liability, damage, sanction, judgment, lien, fine, or penalty, including attorney’s fees, incurred, suffered or paid by, or resulting to, the applicable indemnified Persons on account of (i) injuries (including death) to any Person or damage to or destruction of any property, sustained or alleged to have been sustained in connection with or arising out of the matters for which the indemnifying Party has indemnified the applicable indemnified Persons, (ii) any failure of any representation or warranty made by Shipper in this Agreement to be true and correct when made, or (iii) the breach of any covenant or agreement made or to be performed by the indemnifying Party pursuant to this Agreement.

     1.69 Lost and Unaccounted for Gas. With respect to each Month and each of the Sweet Gas Gathering System and the Sour Gas Gathering System, FL&U less Field Fuel; provided, however, for each Month, Lost and Unaccounted for Gas shall be limited to the product of (i) the Quantity of Gas received into such system during such Month and (ii) the lesser of (a) one and one-half percent (1.5%) or (b) two hundred percent (200%) of the average L&U Percentage for such system for the twelve (12) Months immediately preceding such Month.

     1.70 Low-Pressure Sour Sub-System. That portion of the Gathering System that typically operates at pressures below two hundred fifty (250) psig, and delivers Gas to a treating and/or processing plant for removal of carbon dioxide and other contaminants.

     1.71 Low-Pressure Sweet Sub-System. That portion of the Gathering System that typically operates at pressures below two hundred fifty (250) psig, and delivers Gas to third-party pipelines.

     1.72 Maintenance. As defined in Section 9.1 of this Agreement.

     1.73 Material Error. As defined in Section 13.4 of this Agreement.

     1.74 Mcf. One thousand (1,000) Cubic Feet of Gas.

     1.75 Measurement Dispute. As defined in Section 13.12 of this Agreement.

     1.76 Measurement Expert. As defined in Section 13.12 of this Agreement.

     1.77 Measurement Meter. Any meter used to determine the Volume and Quantity of Shipper’s Gas delivered into the Gathering System hereunder at the Receipt Points, which meters shall be Shipper’s wellhead meters.

     1.78 Membership Interest Purchase Agreement. That certain Membership Interest Purchase Agreement dated as of June 30, 2009, by and between SandRidge Midstream, Inc. and TCW Pecos Midstream, LLC, together with all amendments, modifications or waivers thereto.

     1.79 Memorandum. As defined in Section 2.10 of this Agreement.

     1.80 Mid-Pressure Sour Sub-System. That portion of the Gathering System that typically operates at pressures at or above two hundred fifty (250) psig and below seven hundred fifty (750) psig, and delivers Gas to a treating and/or processing plant for removal of carbon dioxide and other contaminants.

7

     1.81 Mid-Pressure Sweet Sub-System. That portion of the Gathering System that typically operates at pressures at or above two hundred fifty (250) psig and below seven hundred fifty (750) psig, and delivers such Gas to third-party pipelines.

     1.82 MMBtu. One million (1,000,000) Btus.

     1.83 MMcf. One million (1,000,000) Cubic Feet of Gas.

     1.84 MMcf/D. One million (1,000,000) Cubic Feet of Gas per Day.

     1.85 Month or Monthly. A period commencing at 6:00 A.M., Central Clock Time, on the first day of a calendar month and extending until 6:00 A.M., Central Clock Time, on the first day of the next succeeding calendar month.

     1.86 Monthly Average Receipt Point Pressure. With respect to each Sub-System, each Month, the Volume-weighted average pressure (in psig) measured at the downstream static pressure tap of each Measurement Meter at or near each Receipt Point delivering into such Sub-System, which shall be calculated by multiplying (i) the total Daily Volume for each Day during such Month at each such point by (ii) the average pressure (in psig) for such Day at such point; summing the resulting products for all such Days and points; and then dividing the resulting sum by the sum of such Daily Volumes, and rounding the quotient to the nearest whole number; provided, however, if Shipper Compression is installed on such Sub-System, the point at which pressure shall be measured shall be downstream of the discharge of such Shipper Compression, and the individual Receipt Points upstream of such Shipper Compression shall not be included. In the calculation of Monthly Average Receipt Point Pressure, Gatherer may exclude any Day when any of the following conditions occur: (i) Force Majeure, (ii) Maintenance, not to exceed one hundred (100) hours per Calendar Year, or (iii) when Shipper’s Gas on such Sub-System exceeds the Sub-System Capacity for such Sub-System, not to exceed five (5) Days in any Month and not to exceed thirty (30) Days in any Calendar Year. In order for any Day to qualify for exclusion because of Force Majeure or Maintenance, Gatherer must give Shipper written notice within three (3) Business Days after the occurrence of such event. Gatherer shall provide Shipper with the calculation of the Monthly Average Receipt Point Pressure for each Sub-System within thirty (30) Days following the end of each Month. An example calculation of the Monthly Average Receipt Point Pressure is set forth in Exhibit I attached hereto.

     1.87 Monthly Excess Bank. As defined in Section 3.1 of this Agreement.

     1.88 Monthly Excess Volumes. As defined in Section 3.1 of this Agreement.

     1.89 Monthly Gas Receipt. With respect to any Month, the actual Volume of Gas delivered by Shipper to Gatherer at the Receipt Points during such Month pursuant to this Agreement, as measured at the Measurement Meters, less and except any Gas brought into the Gathering System solely for Field Fuel or that is recirculated in the Gathering System.

     1.90 Monthly Shortfall. As defined in Section 3.2 of this Agreement.

     1.91 Monthly Shortfall Offset Amount. As defined in Section 3.2(b) of this Agreement.

8

     1.92 Monthly Shortfall Payment. As defined in Section 3.2 of this Agreement.

     1.93 Monthly Waha Index Price. The first of the month “Index” price for Gas published in Platt’s Inside FERC’s Gas Market Report in the table entitled “Market Center Spot Gas Prices” under the heading “West Texas” in the row entitled “Waha” for the applicable Month.

     1.94 Negative Shipper Monthly Imbalance Quantity. With respect to any Month, the amount, if any, by which (i) the Quantity of Delivery Point Gas delivered by Gatherer for Shipper’s account at the Delivery Points during such Month exceeds (ii) the Quantity of the Monthly Gas Receipt for such Month, less the Quantity Reductions.

     1.95 Net Condensate Proceeds. With respect to each Month and each Sub-System, the gross proceeds received by Gatherer (in U.S. Dollars) for the sale of Condensate collected on such Sub-System during such Month, net of transportation, storage, and/or similar charges or costs incurred by Gatherer in connection with the sale of such Condensate.

     1.96 Non-Dedicated Area Connected Wells. As defined in Section 2.1(c) of this Agreement.

     1.97 Non-Gatherer Force Majeure Event. Any Force Majeure event that does not constitute a Gatherer Force Majeure event.

     1.98 O&M Agreement. That certain Operations and Maintenance Agreement dated as of the Effective Date, by and between SandRidge Midstream, Inc. and Gatherer, as amended, restated or otherwise modified from time to time, wherein Gatherer has appointed SandRidge Midstream, Inc. to operate the Gathering System on behalf of Gatherer.

     1.99 Off-Specification Receipts. As defined in Section 12.2 of this Agreement.

     1.100 Operated Gas. Shipper’s Gas and any other Gas produced from wells operated by Shipper and delivered to the Gathering System.

     1.101 Operating Expenses. With respect to each Sub-System, each Month, without duplication, the sum of, in each case as reasonably allocated to the Gathering System and as further reasonably allocated to such Sub-System and not to exceed cost and expense that would be incurred by a reasonably prudent operator of unregulated natural gas gathering pipelines, ***.

     1.102 Operations Fee. Subject to Section 10.4, with respect to each Sub-System, each Month, the quotient of (i) the Operating Expenses for such Sub-System for such Month, divided by (ii) the greater of (x) total Volume of Gas delivered into such Sub-System during such Month or (y) one (1) Mcf.

     1.103 Other Shipper. Any Person other than Shipper for whom Gatherer provides gathering, compression, Dehydration, and/or measurement services on the Gathering System.

     1.104 Parties. As defined in the preamble of this Agreement.

9

     1.105 Party. As defined in the preamble of this Agreement.

     1.106 Person. An individual, a corporation, a partnership, a limited partnership, a limited liability company, an association, a joint venture, a trust, an unincorporated organization, or any other entity or organization, including a government or political subdivision or an agency or instrumentality thereof.

     1.107 Positive Shipper Monthly Imbalance Quantity. With respect to any Month, the amount, if any, by which (i) the Quantity of the Monthly Gas Receipt for such Month, less the Quantity Reductions, exceeds (ii) the Quantity of Delivery Point Gas delivered by Gatherer for Shipper’s account at the Delivery Points during such Month.

     1.108 Prior Dedications. (i) As to the Interests owned by Shipper within the Dedicated Area as of the Effective Date, all dedications or commitments for gathering services burdening such Interests as of the Effective Date, (ii) as to any Interests acquired by Shipper within the Dedicated Area after the Effective Date, any dedication or commitment for gathering services burdening such Interests which is existing as of the time of any such acquisition, and (iii) as to any Interests acquired by any successor of Shipper within the Dedicated Area, all dedications or commitments for gathering services burdening such Interests, which are existing as of the time of any such acquisition or that are placed on such Interests prior to any such successor becoming a successor of Shipper; provided that such dedication or commitment was not incurred in anticipation of such acquisition.

     1.109 Production Taxes. All gross production, severance, conservation, and similar or other Taxes now existing or in the future imposed and measured by or based upon production, together with all Taxes on the right or privilege of ownership of Shipper’s Gas, or upon the Services.

     1.110 Proposed Operating Expense Budget. As defined in Section 6.6(b) of this Agreement.

     1.111 psia. Pressure expressed in pounds per square inch absolute.

     1.112 psig. Pressure expressed in pounds per square inch gauge.

     1.113 Quantity. Gas as measured on an MMBtu basis.

     1.114 Quantity Reductions. With respect to each Month, the total Quantity of (i) Shipper’s Gas measured at the Measurement Meters and used by Shipper pursuant to Section 8.3 during such Month, (ii) Shipper’s Pro Rata Share of Field Fuel for such Month, (iii) Shipper’s Pro Rata Share of Lost and Unaccounted for Gas for such Month and (iv) the Thermal Content of Shipper’s Pro Rata Share of Condensate for such Month.

     1.115 Receipt Point Gas Quality Specifications. As set forth on Exhibit H attached hereto.

     1.116 Receipt Points. The points of interconnection between the Gathering System and other facilities where Gas is delivered into the Gathering System, including, without limitation,

10

the points identified on Exhibit D. Exhibit D shall be amended by the Parties from time to time to reflect the addition of new Receipt Points.

     1.117 Released Gas. Gas that would have been Dedicated Gas hereunder but was permanently released from the Dedication and this Agreement pursuant to the terms hereof.

     1.118 Scheduled Nomination. As defined in Section 11.2(b) of this Agreement.

     1.119 Services. As defined in Section 2.4 of this Agreement.

     1.120 Shipper. As defined in the preamble of this Agreement.

     1.121 Shipper Compression. Collectively, any facilities installed by Shipper under Section 8.2.

     1.122 Shipper Indemnified Parties. Shipper, its permitted assigns, and their respective Affiliates, shareholders, members, partners, officers, directors, employees, and agents.

     1.123 Shipper Volume Forecast. As defined in Section 6.6(a) of this Agreement.

     1.124 Shipper’s Gas. All Gas now or hereafter owned or controlled by Shipper and delivered to the Gathering System pursuant to the terms of this Agreement.

     1.125 Shipper’s Pro Rata Share. With respect to a Sub-System, the Sweet Gas Gathering System or the Sour Gas Gathering System, each Month, a percentage, expressed in decimal form, calculated by dividing (i) the total Quantity of that portion of the Monthly Gas Receipt delivered into such Sub-System, the Sweet Gas Gathering System or the Sour Gas Gathering System, as the case may be, during such Month, by (ii) the total Quantity of Gas received into such Sub-System, the Sweet Gas Gathering System or the Sour Gas Gathering System, as the case may be, during such Month; provided, however, with respect to allocation of Field Fuel on the Low-Pressure Sour Sub-System, the Mid-Pressure Sour Sub-System, the High-Pressure Sour Sub-System or the Sour Gas Gathering System, such percentage shall be calculated by dividing (i) the total Volume of that portion of the Monthly Gas Receipt delivered into the Low-Pressure Sour Sub-System, the Mid-Pressure Sour Sub-System, the High-Pressure Sour Sub-System or the Sour Gas Gathering System, as the case may be, during such Month, by (ii) the total Volume of Gas received into the Low-Pressure Sour Sub-System, the Mid-Pressure Sour Sub-System, the High-Pressure Sour Sub-System or the Sour Gas Gathering System, as the case may be, during such Month.

     1.126 Similarly Situated Shipper. Any Other Shipper that is similarly situated to Shipper, as determined by applying the criteria set forth in Rule 2.1(b)(16) of Chapter 2 of Part 1 of Title 16 of the Texas Administrative Code or any successor or replacement rule.

     1.127 Sour Gas Gathering System. That portion of the Gathering System comprised of the Low-Pressure Sour Sub-System, the Mid-Pressure Sour Sub-System, and the High-Pressure Sour Sub-System.

     1.128 Subsequent Acquisition. As defined in Section 4.3 of this Agreement.

11

     1.129 Subsequent Acquisition Purchase Price. As defined in Section 4.3 of this Agreement.

     1.130 Sub-System. The integrated portions of the Gathering System described on Exhibit F attached hereto.

     1.131 Sub-System Capacity. Individually for each Sub-System, the Mcf per Day Volume shown on Exhibit F attached hereto, as such capacity may be increased from time to time as a result of any Subsequent Acquisitions.

     1.132 Sub-System Turnover Average Receipt Point Pressure. With respect to each Sub-System, one hundred and five percent (105%) of the average of the Monthly Average Receipt Point Pressure for the lesser of (x) twelve (12) Months, but excluding the three (3) highest pressure Months and the three (3) lowest pressure Months, or (y) if the last capital project occurred less than twelve (12) months prior to the calculation date, the number of Months since the last capital project (including, without limitation, Expansions) was performed that reduced the pressure on such Sub-System, in each case, immediately preceding the Month following the one (1) year anniversary of the end of the Expansion Period.

     1.133 Surface Use Agreement. That certain Amended Surface Use and Damages Agreement dated September 21, 2007, between Longfellow Ranch Partners, LP and SandRidge Energy, Inc. covering lands in Pecos, Terrell, and Brewster Counties, Texas.

     1.134 Sweet Gas Gathering System. That portion of the Gathering System comprised of the Low-Pressure Sweet Sub-System, the Mid-Pressure Sweet Sub-System, and the High Pressure Sweet Sub-System.

     1.135 System Capacity. The Gathering System throughput capacity as it exists on the Effective Date, as increased from time to time as a result of any Subsequent Acquisitions.

     1.136 Tax or Taxes. Any (i) federal, state, provincial, county, local or foreign taxes, charges, fees, levies or other assessments, including all sales and use, goods and services, ad valorem, transfer, gains, profits, excise, franchise, real and personal property, gross receipt, value added, capital stock, production, business and occupation, disability, employment, payroll, license, estimated, stamp, custom duties, severance, unemployment, social security, Medicare, alternative minimum or withholding taxes or charges imposed by any Governmental Authority, and including any interest and penalties (civil or criminal) on or additions to any such taxes, but expressly excluding any income tax or tax based on income, such as, without limitation, the franchise tax set forth in V.T.C.A. Tax Code Section 171.0001 et. seq., as the same may be amended or recodified from time to time, and (ii) liability for items in (i) of any other Person by contract, operation of Law (including Treasury Regulation 1.1502-6) or otherwise.

     1.137 Term. As defined in Article 5 of this Agreement.

     1.138 Termination Event. As defined in the Intercompany Conveyance.

     1.139 Thermal Content. With respect to Gas, the product of (i) a volume of Gas and (ii) the Gross Heating Value of such Gas, adjusted to a same pressure base of fourteen and sixty-

12

five hundredths (14.65) psia, expressed in MMBtus; and with respect to Condensate, the product of (i) a volume of Condensate and the (ii) Gross Heating Value of such Condensate, expressed in MMBtus.

     1.140 Thermally Equivalent. An equal number of MMBtus.

     1.141 Third Party Gas. Gas other than Shipper’s Gas.

     1.142 Third Party Receipt Point Gas Quality Specifications. The Receipt Point Gas Quality Specifications for Third Party Gas set forth on Exhibit H attached hereto.

     1.143 Third Party Shipper. Enterprise Products Operating, LLC, to the extent it delivers Third Party Shipper Gas.

     1.144 Third Party Shipper Gas. Gas delivered to the Gathering System by Third Party Shipper pursuant to that certain Gathering Agreement dated June 26, 2009, between Enterprise Products Operating, LLC, as shipper, and SandRidge Midstream, Inc.

     1.145 Transaction Documents. Collectively, this Agreement, the O&M Agreement, the Membership Interest Purchase Agreement, the Intercompany Conveyance, the Company Conveyance, the Guaranty Agreements, the Confidentiality and Disclosure Agreement, and the LLC Agreement.

     1.146 Trigger Event. The date on which the stream of cash flows consisting of the Base Fee, the Commodity Fee, the Monthly Shortfall Payments, and all amounts (or the value of non-cash consideration) paid by third parties for services on the Gathering System with respect to Operated Gas (exclusive of amounts attributable to the reimbursement of Gatherer for Operating Expenses), when discounted back to the Effective Date from each date of receipt by Gatherer of such amounts, first results in an internal rate of return to Gatherer, as calculated in accordance with Microsoft’s Excel’s internal rate of return function, of *** on the sum of (i) ***, (ii) ***, and (iii) ***. An example of how the Trigger Event is to be calculated is included in Exhibit G.

     1.147 Volume. Gas as measured on an Mcf basis.

     1.148 Voting Securities. As it relates to a Person, securities of any class of such Person entitling the holders thereof to vote in the election of, or to appoint, members of the board of directors or other similar governing body of the Person; provided that if such Person is a limited partnership, Voting Securities of such Person shall be the general partner interest in such Person.

     1.149 Year. A period of three hundred sixty-five (365) consecutive Days; provided, however, any year that contains the date of February 29 shall consist of three hundred sixty-six (366) consecutive Days.

13

ARTICLE 2
DEDICATION AND SERVICES

     Section 2.1 Dedication. Shipper hereby dedicates for Gathering under this Agreement and, subject to the other terms and conditions hereof, shall deliver, or cause to be delivered, hereunder to Gatherer at the Receipt Points, the following (the “Dedication,” and the Gas that is the subject of the Dedication being herein referred to as the “Dedicated Gas”):

     (a) all Gas produced and saved from wells now or hereafter located within the Dedicated Area or on lands pooled or unitized therewith, to the extent such Gas is attributable to Interests within the Dedicated Area now owned or hereafter acquired by Shipper and not delivered or used as permitted pursuant to Section 8.3;

     (b) with respect to wells now or hereafter located within the Dedicated Area or on lands pooled or unitized therewith for which Shipper is the operator, Gas produced from such wells which is attributable to Interests in such wells owned by other working interest owners and royalty owners which is not (i) taken “in-kind” by such working interest owners and royalty owners or (ii) delivered or used as permitted pursuant to Section 8.3, and for which Shipper has the right or obligation to gather such Gas, but only for the period that Shipper has such right or obligation;

     (c) all Gas produced and saved from wells that are located outside of the Dedicated Area but are connected to the Gathering System as of the Effective Date (“Non-Dedicated Area Connected Wells”), to the extent such Gas is attributable to Interests now owned or hereafter acquired by Shipper and not delivered or used as permitted pursuant to Section 8.3; and

     (d) with respect to Non-Dedicated Area Connected Wells for which Shipper is the operator, Gas produced from such Non-Dedicated Area Connected Wells which is attributable to Interests in such Non-Dedicated Area Connected Wells owned by other working interest owners and royalty owners which is not (i) taken “in-kind” by such working interest owners and royalty owners or (ii) delivered or used as permitted pursuant to Section 8.3, and for which Shipper has the right or obligation to gather such Gas, but only for the period that Shipper has such right or obligation;

provided, however, with respect to Dedicated Gas that is subject to a Prior Dedication, such Gas shall not be subject to the Dedication during the existence of such Prior Dedication. In the event that any such Prior Dedication expires or terminates, then the Gas subject to such Prior Dedication shall automatically be included within the Dedication and subject to this Agreement without any further actions by Shipper. In the event that at any time in the future Shipper has the right or ability to terminate any such Prior Dedication, then Shipper shall terminate such Prior Dedication, and upon such termination, the Gas subject to such Prior Dedication shall automatically be included within the Dedication and subject to this Agreement without any further actions by the Parties. Nothing herein shall obligate Shipper to terminate any Prior Dedication to the extent that such termination would require Shipper to file suit, bring any arbitral or mediation proceeding, incur any cost, or pay any termination fee or penalty. Shipper (but excluding any successors and assigns) represents to Gatherer, that, as of the Effective Date,

14

Shipper (but excluding any successors and assigns) is not subject to any Prior Dedications, other than the Cholla Gathering Agreement and the agreement between Shipper and Third Party Shipper transferring the Third Party Shipper Gas to Third Party Shipper.

     Section 2.2 Shipper’s Right To Deliver Other Gas. Subject to the other terms and conditions hereof, Shipper shall have the continuing right to deliver Gas (other than Dedicated Gas) to Gatherer at the Receipt Points, and Gatherer shall provide Services for such Gas on the Gathering System.

     Section 2.3 Covenant Running with the Land. This Agreement shall (i) be a covenant running with (x) the Gathering System, (y) the Interests now owned or hereafter acquired by Shipper and its assigns within the Dedicated Area and (z) the Non-Dedicated Area Connected Wells, (ii) be binding on and enforceable by Gatherer against Shipper and its assigns, and (iii) be binding on and enforceable by Shipper against Gatherer. In the event Shipper sells, transfers, conveys, assigns, grants or otherwise disposes of all or any Interests in the Dedicated Area or the Non-Dedicated Area Connected Wells, then any such sale, transfer, conveyance, assignment or other disposition shall be expressly subject to this Agreement and state such in any instrument of conveyance. In the event Gatherer sells, transfers, conveys, assigns, grants or otherwise disposes of all or any interest in the Gathering System, then any such sale, transfer, conveyance, assignment or other disposition shall be expressly subject to this Agreement and state such in any instrument of conveyance.

     Section 2.4 Services. Subject to the terms and conditions of this Agreement, Gatherer agrees, during each Month of the Term, to provide the following services, each on a Firm Basis, (collectively, the “Services”):

     (a) receive, or cause to be received, from Shipper, Shipper’s Gas at the Receipt Points;

     (b) gather, Dehydrate, and compress Gas received from Shipper hereunder; and

     (c) deliver, or cause to be delivered, to Shipper, and Shipper shall accept, or cause to be accepted, at the Delivery Points, each Month, a Volume and Quantity of Gas that is equal to the Volume of, and Thermally Equivalent to the Quantity of, the Monthly Gas Receipt for such Month, less the Quantity Reductions for such Month (such Gas delivered to Shipper hereunder at the Delivery Points being herein referred to as the “Delivery Point Gas”).

     Section 2.5 Operation and Maintenance of Gathering System. Gatherer shall (i) be entitled to complete operational control of the Gathering System, (ii) operate and maintain the Gathering System in accordance in all material respects with all applicable laws, rules and regulations, as a prudent operator in accordance with good practices in the unregulated natural gas gathering industry and in a cost efficient and effective manner for Shipper, including, without limitation, (x) minimizing recycle volumes and other practices that would result in excessive Field Fuel, (y) using electric compression or Gas compression where appropriate and (z) using owned or leased compression facilities where appropriate, and (iii) operate and

15

maintain the Sweet Gas Gathering System and the Sour Gas Gathering System as separate systems and shall not commingle the Gas streams between such systems, without Shipper’s prior written consent; provided that Gatherer shall have the unqualified right to commingle Shipper’s Gas with other Gas within each such system; provided that such other Gas meets the Third Party Receipt Point Gas Quality Specifications.

     Section 2.6 Priority of Services; Curtailment. Gatherer agrees not to provide services for Third Party Gas on the Gathering System on a basis that has a priority higher than Shipper is entitled to under this Agreement. If for any reason (including, without limitation, Force Majeure, Maintenance, or constraints at the Delivery Points) Gatherer needs to curtail receipt, gathering or delivery of Gas on the Gathering System, the following procedures shall be followed:

     (a) First, Gas deliveries from all Persons other than Shipper and Similarly Situated Shippers shall be curtailed prior to any curtailment or interruption of Shipper’s Gas or Gas from Similarly Situated Shippers; and

     (b) Second, if additional curtailments are required beyond Section 2.6(a) above, Gatherer shall curtail Shipper’s Gas and Gas from Similarly Situated Shippers, and allocate the capacity of the Gathering System, at the affected point on a pro rata basis based upon Shipper’s and other Similarly Situated Shippers’ last confirmed nominations through the affected point prior to the event causing the curtailment.

Notwithstanding anything to the contrary herein contained, to the extent Gas deliveries from Persons other than Shipper or Similarly Situated Shippers causes or would reasonably be expected to cause a reduction in the production of any of Shipper’s Gas or Similarly Situated Shippers’ Gas, Gatherer shall curtail receipts of Gas deliveries from such Persons into the Gathering System.

     Section 2.7 Third Party Gas. Gatherer agrees that Third Party Gas delivered into the Gathering System shall meet the Third Party Receipt Point Gas Quality Specifications; provided, however, Shipper may, at its option, agree to allow Gatherer to accept Third Party Gas that does not meet the Third Party Receipt Point Gas Quality Specifications on an interruptible basis; provided, however, any incremental FL&U and costs incurred by Shipper as a result of such non-conforming Third Party Gas shall be borne by Gatherer and reimbursed to Shipper.

     Section 2.8 Release of Dedicated Gas.

     (a) Temporary Release. If (i) Gatherer is unable to provide Services with respect to all or any Volume of the Dedicated Gas that Shipper is ready, willing, and able to deliver, or cause to be delivered, in accordance with the terms of this Agreement, and (ii) no event has occurred or condition exists that constitutes a material breach or violation of, or a failure to comply with, this Agreement or the O&M Agreement on the part of Shipper which remains uncured, then (y) Shipper, at its option, may elect to temporarily release the Volume of Dedicated Gas for which Gatherer is unable to provide Services from this Agreement by delivering written notice thereof to Gatherer, and (z)

16

during such period of time, Shipper shall have the right to deliver such volume of Dedicated Gas to alternative facilities for the provision of services. Upon the resumption of Gatherer’s ability to provide Services, Gatherer shall provide written notice thereof to Shipper, such temporary release shall end and Shipper shall resume the delivery of all Dedicated Gas to Gatherer no later than the first Day of the second Month immediately following Gatherer’s ability to provide Services. Nothing herein shall relieve Gatherer of any liability for failure to provide Services pursuant to, and in accordance with, the terms of this Agreement.

     (b) Permanent Release on Account of Force Majeure. If (i) Gatherer because of Force Majeure is unable to provide Services, for (A) a period of one hundred eighty (180) Days or more during any Year or (B) a continuous period of ninety (90) Days or more, at any Receipt Point (the “Initial Force Majeure Period”), for all or any Volume of Dedicated Gas that Shipper is ready, willing, and able to deliver to such Receipt Point in accordance with the terms of this Agreement, and (ii) no event has occurred or condition exists that constitutes a material breach or violation of, or a failure to comply with, this Agreement or the O&M Agreement on the part of Shipper which remains uncured, then (y) Shipper, at its option, may elect to permanently release the Dedicated Gas produced from the wells delivering to such Receipt Point from the Dedication and this Agreement by delivering written notice thereof to Gatherer, and (z) if Shipper exercises such option, Shipper and Gatherer shall acknowledge in writing the wells and Dedicated Gas that have been released from the Dedication and this Agreement. Notwithstanding anything herein to the contrary, no Dedicated Gas shall be released pursuant to this paragraph (b) prior to the occurrence of the Trigger Event, unless (i) the applicable Force Majeure event is a condition or circumstance that may be remedied by Gatherer (a “Gatherer Force Majeure Event”) and (ii) at any time after the end of the Initial Force Majeure Period, Gatherer is not using commercially reasonable efforts to remedy the situation with all reasonable dispatch; provided, however, that with respect to any Gatherer Force Majeure Event, if after an additional ninety (90) Days after the end of the Initial Force Majeure Period, Gatherer has failed to remedy such Gatherer Force Majeure Event, then Shipper, at its option, may elect to permanently release the Dedicated Gas produced from the wells delivering to such Receipt Point as provided above.

     (c) Permanent Release for Other Reasons. If (i) Gatherer, for any reason other than Force Majeure, is unable to provide Services, for (A) a period of one hundred eighty (180) Days or more during any Year or (B) a continuous period of ninety (90) Days or more, at any Receipt Point (the “Initial Service Interruption Period”), at any Receipt Point, for all or any Volume of Dedicated Gas that Shipper is ready, willing, and able to deliver to such Receipt Point in accordance with the terms of this Agreement, and (ii) no event has occurred or condition exists that constitutes a material breach or violation of, or a failure to comply with, this Agreement or the O&M Agreement on the part of Shipper which remains uncured, then (y) Shipper, at its option, may elect to permanently release the Dedicated Gas produced from the wells delivering to such Receipt Point from the Dedication and this Agreement by delivering written notice thereof to Gatherer, and (z) if Shipper exercises such option, Shipper and Gatherer shall acknowledge in writing the wells and Dedicated Gas that have been released from the

17

Dedication and this Agreement. Notwithstanding anything herein to the contrary, no Dedicated Gas shall be released pursuant to this paragraph (c) prior to the occurrence of the Trigger Event, unless (i) the applicable condition or circumstance can be remedied by Gatherer (a “Gatherer Controlled Event”) and (ii) at any time after the end of the Initial Service Interruption Period, Gatherer is not using commercially reasonable efforts to remedy the situation with all reasonable dispatch; provided, however, that with respect to any Gatherer Controlled Event, if after an additional ninety (90) Days after the end of the Initial Service Interruption Period, Gatherer has failed to remedy the Gatherer Controlled Event, then Shipper, at its option, may elect to permanently release the Dedicated Gas produced from the wells delivering to such Receipt Point as provided above. Nothing herein shall relieve Gatherer of any liability for failure to provide Services pursuant to, and in accordance with, the terms of this Agreement.

     Section 2.9 Maintenance of System Capacity. After expiration of the Expansion Period, Gatherer shall maintain the System Capacity and each Sub-System Capacity and shall not take, without Shipper’s prior written consent, any action that could cause the System Capacity or any Sub-System Capacity to be reduced or Shipper’s ability to deliver Gas to any Receipt Point to be reduced, including, without limitation, the removal of owned or leased compression facilities on the Gathering System or the implementation of pipeline modifications.

     Section 2.10 Memorandum of Agreement. Contemporaneously with the execution of this Agreement, the Parties shall execute, acknowledge, deliver and record a “short form” memorandum of this Agreement in the form of Exhibit L attached hereto (the “Memorandum”) which shall be placed of record in the counties in which the Dedicated Area is located.

     Section 2.11 No Breach. No violation of any of the terms or conditions of this Agreement or failure to provide Services hereunder shall be deemed a breach of this Agreement by Gatherer if and to the extent such violation or failure results, directly or indirectly, from a breach of the O&M Agreement by Shipper.

ARTICLE 3
MONTHLY SHORTFALL PAYMENTS

     Section 3.1 Deliveries in Excess of the Base Volume. If, during any Month up to and including the Month in which the Trigger Event occurs, (i) the Base Volume Monthly Gas Receipt for such Month is greater than (ii) the Base Volume for such Month (the volume difference being “Monthly Excess Volumes”), Shipper shall add such Monthly Excess Volumes to a notional account (the “Monthly Excess Bank”). The balance in the Monthly Excess Bank shall be (x) reduced each Month by the Monthly Shortfall Offset Amount (hereinafter defined), if any, and (y) increased as provided in Section 3.6(b).

     Section 3.2 Deliveries Less Than the Base Volume. If, during any Month up to and including the Month in which the Trigger Event occurs, (i) the Base Volume Monthly Gas Receipt for such Month is less than (ii) the Base Volume for such Month, as reduced by the Volume of Gas that Shipper is ready, willing, and able to deliver during such Month pursuant to and in accordance with the terms of this Agreement but is not received by Gatherer due to

18

Gatherer’s failure to receive Shipper’s Gas in material breach of the terms of this Agreement (such amount by which (i) above is less than (ii) above, being the “Monthly Shortfall”), then Shipper shall pay to Gatherer an amount (the “Monthly Shortfall Payment”) equal to the product of the following:

          (a) the Base Fee applicable to such Month; and

          (b) the Monthly Shortfall minus the lesser of (1) the balance in the Monthly Excess Bank as of the beginning of such Month or (2) the Monthly Shortfall (such lesser amount being the “Monthly Shortfall Offset Amount”).

     Section 3.3 Force Majeure Volumes. During any Month in which there are Force Majeure Volumes, the Volume of Gas set forth in Exhibit C for such Month shall be reduced by such Force Majeure Volumes, and such Force Majeure Volumes shall be deducted from the balance in the Monthly Excess Bank. If there are Force Majeure Volumes remaining after such deduction (“Adjusted Force Majeure Volumes”), the Volume of Gas set forth in Exhibit C for each subsequent Month during which there are no Force Majeure Volumes shall equal the greater of (A) one hundred ten percent (110%) of such Volume and (B) the total Base Volume Monthly Gas Receipt for such Month until such time as the Base Fee has been paid with respect to Volumes in excess of the Volumes set forth in Exhibit C equal to the Adjusted Force Majeure Volumes. Notwithstanding anything herein to the contrary, the Volume of Gas set forth in Exhibit C shall not be reduced for a period longer than six (6) Months after the first Month in which there are Force Majeure Volumes unless such Force Majeure Volumes are due to a Gatherer Force Majeure Event.

     Section 3.4 Monthly Shortfall Payments Offset Against Future Fees. The Monthly Shortfall Payments shall be used to offset any Base Fees due hereunder with respect to any Monthly Excess Volumes in any subsequent Month; provided, however, in such event, the balance in the Monthly Excess Bank shall be reduced by the Monthly Excess Volumes for which Base Fees due thereon were offset by such Monthly Shortfall Payments.

     Section 3.5 Example of Operation of Monthly Excess Bank. An example of the operation of the Monthly Excess Bank, including the calculation of Monthly Excess Volumes, Monthly Shortfalls, Monthly Shortfall Payments and Monthly Shortfall Offset Amounts is set forth on Exhibit K attached hereto.

     Section 3.6 Adjustment to Account for Released Gas.

          (a) If at any time Dedicated Gas is permanently released from the Dedication and this Agreement pursuant to the terms hereof, Gatherer and Shipper shall negotiate in good faith a mutually agreeable reduction in the Base Volumes in order to account for the Released Gas. In the event that the Parties cannot agree on such reduction in the Base Volumes within thirty (30) days after the date on which such permanent release becomes effective, then the Accounting Arbitrator shall settle the dispute. In settling the dispute, the Accounting Arbitrator (a) shall determine the Volumes of Released Gas and the likely production curve based upon the then proved producing reserves of the wells delivering to the applicable Receipt Point and such Volumes shall be deducted from the Base Volumes and (b) shall be permitted to engage

19

technical consultants, including independent engineering firms, as necessary. Within ten (10) days after the selection of the Accounting Arbitrator, each of the Parties shall summarize and submit its position with regard to the dispute to the Accounting Arbitrator. Within ten (10) Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision with respect to the dispute. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on the Parties and will be enforceable against the Parties in any court of competent jurisdiction. The costs of the Accounting Arbitrator shall be borne one-half by Shipper and one-half by Gatherer.

          (b) Additions to Monthly Excess Bank. If (i) there are deductions to the Monthly Excess Bank for Force Majeure Volumes pursuant to this Article, and (ii) the wells and/or Receipt Points attributable to such Force Majeure Volumes are thereafter permanently released from the Dedication and this Agreement pursuant to the terms hereof, then such Force Majeure Volumes shall be added back to the Monthly Excess Bank.

ARTICLE 4
WELL CONNECTIONS AND EXPANSIONS

     Section 4.1 Well Connection and Timing. Subject to the provisions of Section 4.2, Shipper shall (i) connect any well that is drilled within the Dedicated Area or on lands pooled or unitized therewith that will produce Dedicated Gas to the Gathering System, (ii) have the option, at Shipper’s sole election, to connect any well drilled outside the Dedicated Area and lands pooled or unitized therewith to the Gathering System, and (iii) pay all connection costs associated therewith, including, but not limited to, costs for well tie lines, taps into the Gathering System, measurement facilities, right-of-way acquisition, and all requisite permits and licenses. With respect to any well that Shipper desires to connect to the Gathering System, Shipper shall provide written notice thereof to Gatherer, which notice shall include the well name, Shipper’s working interest in such well, a well location survey plat, the legal location of such well, the actual spud date or the estimated spud date if not yet spud, the completion date or the estimated completion date if not yet completed, Shipper’s best estimate of the well’s deliverability, the approximate location on the Gathering System where Shipper desires to connect such well and the estimated date on which Shipper anticipates that it will make such connection.

     Section 4.2 System Expansions. Shipper shall expand the Gathering System by installing and/or acquiring such facilities as are reasonably necessary to handle the delivery of Dedicated Gas to the Gathering System, which facilities may include, without limitation, the installation of compression on the Gathering System and/or the looping of Gathering System pipelines (the real and personal property rights included with each such expansion are referred to herein as “Expansions”). Shipper shall construct sufficient Expansions within five (5) Years following the Effective Date (the “Expansion Period”), such that the Gathering System will have a total throughput capacity sufficient to Gather the Base Volumes during each of the applicable periods. All such Expansions shall be owned and operated by Shipper unless and until such time as such Expansions are acquired by Gatherer pursuant to a Subsequent Acquisition, in which case and at which time, such Expansions shall be owned by Gatherer and such Expansions will become a part of the Gathering System. Gatherer shall reasonably cooperate with Shipper in connection with Shipper’s installation of Expansions, which

20

cooperation shall include, without limitation, the granting by Gatherer to Shipper of easements and other real property rights as reasonably required by Shipper in connection with the installation of any such Expansions.

     Section 4.3 Gatherer’s Purchase of Expansions. For thirty (30) Days following each of the first, second, and third anniversaries of the Effective Date, Shipper shall have the right to offer to Gatherer, and, if offered, Gatherer shall have the right, for a period of sixty (60) Days after receipt of such offer, to acquire the Expansions constructed during the one Year period immediately preceding such anniversary date for a purchase price equal to the greater of (i) the fair market value of such Expansions constructed during such one Year period or (ii) the actual costs and expenses incurred by for such Expansions constructed during such one Year period (each such consummated purchase is referred to herein as a “Subsequent Acquisition” and the corresponding purchase price is referred to herein as the “Subsequent Acquisition Purchase Price”).

ARTICLE 5
TERM

     Section 5.1 Term. This Agreement shall become effective on the Effective Date and shall continue in full force and effect until the earlier of (A) twenty (20) years after the Effective Date or (B) the later of (i) one year after the wells located on lands within the Dedicated Area or on land pooled or unitized therewith in which Shipper owns an Interest cease to be capable of production of hydrocarbons in paying quantities or (ii) one year after the Non-Dedicated Area Wells cease to be capable of production of hydrocarbons in paying quantities (the “Term”).

     Section 5.2 Obligations Upon Termination. Upon termination of this Agreement, the Parties shall reasonably cooperate with each other in (i) disconnecting their respective facilities from each other’s facilities and (ii) to the extent that one Party has facilities located on the other Party’s property, allowing such Party to remove its facilities from such other Party’s property.

ARTICLE 6
SERVICE FEES AND FL&U

     Section 6.1 Gathering Fee. Shipper shall pay Gatherer, each Month, subject to adjustment in accordance with Section 6.3, the following fees for the Services (collectively, the “Gathering Fees”):

     (a) Operations Fee. With respect to each Sub-System each Month, Shipper shall pay Gatherer a fee equal to the product of (i) the greater of (A) the Volume of the Monthly Gas Receipt delivered into such Sub-System during such Month and (B) one (1) Mcf, and (ii) the Operations Fee applicable to such Sub-System for such Month.

     (b) Base Fee. Shipper shall pay to Gatherer, each Month, a fee equal to the product of (i) the Monthly Gas Receipt for such Month and (ii) the Base Fee applicable to such Month.

21

     Section 6.2 Commodity Fee. Shipper shall pay Gatherer, each Month, subject to adjustment in accordance with Section 6.3, the following variable fee (the “Commodity Fee”) for each Mcf of the total Monthly Gas Receipts for such Month:

     (a) $*** per Mcf if the Monthly Waha Index Price for such Month is less than $***;

     (b) $*** per Mcf if the Monthly Waha Index Price for such Month is equal to or greater than $***, but less than $***;

     (c) $*** per Mcf if the Monthly Waha Index Price for such Month is equal to or greater than $***, but less than $***;

     (d) $*** per Mcf if the Monthly Waha Index Price for such Month is equal to or greater than $***, but less than $***;

     (e) $***per Mcf if the Monthly Waha Index Price for such Month is equal to or greater than $***, but less than $***; and

     (f) $0*** per Mcf if the Monthly Waha Index Price for such Month is equal to or greater than $***.

     Section 6.3 Adjustment to Base Fee and Commodity Fee after Trigger Event. After the occurrence of the Trigger Event, each of the Base Fee and the Commodity Fee shall each be reduced to an amount equal to the product of (A) the applicable fee and (B) a percentage, expressed in decimal form, equal to the sum of (i) *** and (ii) an amount equal to the product of (x) *** and (y) the total of all Subsequent Acquisition Purchase Prices paid hereunder prior to the Trigger Event. For example, if the Initial Purchase Price is $200,000,000 and Gatherer purchased three (3) Subsequent Acquisitions, each with a Subsequent Acquisition Purchase Price of $100,000,000, then the Base Fee at such time would be $***. Upon the occurrence of the Trigger Event, the Base Fee would be adjusted to $*** and each of the per Mcf Commodity Fee figures would be adjusted by multiplying each such figure by ***.

     Section 6.4 Condensate. Gatherer shall pay Shipper, each Month, for the value of Shipper’s Pro Rata Share of Condensate retained by Gatherer, an amount equal to the sum of the Condensate Purchase Price for each Sub-System during such Month. The term “Condensate Purchase Price” as used herein means, with respect to each Sub-System, each Month, an amount equal to Shipper’s Pro Rata Share of the Net Condensate Proceeds for such Sub-System for such Month. Gatherer shall retain and own all such Condensate and, subject to the payment obligation described above, shall retain any and all revenues from the sale thereof. Title to Shipper’s Pro Rata Share of Condensate shall pass from Shipper to Gatherer upon the delivery of Shipper’s Gas at the Receipt Points. In the event that the methodology used to allocate Condensate becomes inequitable in any respect, including, without limitation, due to any Other Shipper having Gas that has a liquids content significantly different than Shipper’s Gas, such methodology shall be modified from time to time in order to remove any such inequities; provided, however, such methodology shall be consistently applied to Shipper and all Other Shippers utilizing the Gathering System.

22

     Section 6.5 Modifications to Determination of Operations Fee. In the event that the allocation of Operating Expenses to the Gathering System, to the various Sub-Systems and to Shipper and the Other Shippers becomes inequitable in any respect, including, without limitation, due to a Person being burdened by a lesser or greater portion of certain Operating Expenses than such Person should reasonably share because of the benefit derived by such Person from such Operating Expenses, the applicable provisions hereof shall be modified from time to time in order to remove any such inequities; provided, however, such modifications shall be consistently applied to Shipper and all Other Shippers utilizing the Gathering System.

     Section 6.6 Operating Expense Budget Process.

     (a) Shipper’s Production Estimate. No later than (i) March 1^st of each Calendar Year, Shipper shall provide to Gatherer a forecast of the Volumes of Shipper’s Gas (by Sub-System) that Shipper in good faith estimates that it will deliver into the Gathering System during the third (3^rd) and fourth (4^th) Calendar Quarters of such Calendar Year and (ii) September 1^st of each Calendar Year, Shipper shall provide to Gatherer a forecast of the Volumes of Shipper’s Gas (by Sub-System) that Shipper in good faith estimates that it will deliver into the Gathering System during the first (1^st) and second (2^nd) Calendar Quarters of the following Calendar Year (each, a “Shipper Volume Forecast”).

     (b) Gathering System Throughput and Operating Expense Budget. No later than (A) April 1^st of each Calendar Year with respect to the third (3^rd) and fourth (4^th) Calendar Quarters of such Calendar Year and (B) October 1^st of each Calendar Year with respect to the first (1^st) and second (2^nd) Calendar Quarters of the following Calendar Year, Gatherer shall provide to Shipper, a forecast of Gatherer’s good faith estimate of (i) the total Gas throughput for each Sub-System during the applicable period, such estimate to based on the Shipper Volume Forecast and Gatherer’s good faith estimate of the Volumes that Other Shippers will deliver into each Sub-System during such period, (ii) the total Operating Expenses to be incurred for each Sub-System during such period, such estimate to be based on the prior period’s budgeted Operating Expenses and actual Operating Expenses, as reasonably adjusted for anticipated operating conditions during such period, and (iii) the Operations Fee per Mcf for each Sub-System for such period, which estimate of the Operations Fee shall be determined by dividing (x) the estimate of the Operating Expenses to be incurred for each Sub-System during such period by (y) the estimate of the total Gas throughput in Mcf for such Sub-System for such period (collectively, the “Proposed Operating Expense Budget”).

     (c) Review of Proposed Operating Expense Budget. On or before (A) May 1^st of each Calendar Year with respect to the third (3^rd) and fourth (4^th) Calendar Quarters of such Calendar Year and (B) November 1^st of each Calendar Year with respect to the first (1^st) and second (2^nd) Calendar Quarters of the following Calendar, Gatherer shall meet with Shipper to review the Proposed Operating Expense Budget and seek Shipper’s input with respect thereto; provided, however, any such review and input by Shipper shall not be construed as (i) Shipper’s approval of any cost or expense contained in the Proposed Operating Expense Budget or (ii) any cost or expense incurred in connection with the

23

Proposed Operating Expense Budget being deemed to have been incurred in accordance with the terms and conditions of this Agreement.

     (d) Accounting Arbitrator. If, at any time within twenty-four (24) Months after the Month in which any Operations Fee was paid by Shipper hereunder, Shipper believes that any cost or expense charged by Gatherer as an Operating Expense and included in the determination of such Operations Fee was not incurred in accordance with the terms and conditions of this Agreement, including, without limitation, Section 2.5, Shipper shall have the right to submit the issue to the Accounting Arbitrator for resolution. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on the Parties and will be enforceable against the Parties in any court of competent jurisdiction. If the Accounting Arbitrator decides that any such cost or expense was not incurred in accordance with the terms and conditions of this Agreement, including, without limitation, Section 2.5, then, within thirty (30) days after the determination thereof by the Accounting Arbitrator, Gatherer shall refund to Shipper any such costs and expenses paid by Shipper to Gatherer hereunder. The costs of the Accounting Arbitrator shall be borne one-half by Shipper and one-half by Gatherer. The Parties’ respective rights and obligations under this Section 6.6 shall be in addition to and not limited by Section 15.2 hereof.

ARTICLE 7
ALLOCATIONS

     Section 7.1 Fuel, Lost and Unaccounted for Gas Allocation Procedures. Shipper shall bear Shipper’s Pro Rata Share of FL&U in accordance with the following:

     (a) Field Fuel Allocation for Sub-Systems. That portion of the Monthly Gas Receipt delivered into each Sub-System shall be allocated, each Month, Shipper’s Pro Rata Share of Field Fuel for the applicable Sub-System for such Month; provided that Shipper shall provide one hundred percent (100%) of the Field Fuel consumed in the operation of any Shipper Compression unless Other Shippers also utilize Shipper Compression.

     (b) Lost and Unaccounted for Gas Allocation for Sweet Gas Gathering System. That portion of the Monthly Gas Receipt delivered into the Sweet Gas Gathering System shall be allocated, each Month, Shipper’s Pro Rata Share of Lost and Unaccounted for Gas calculated for the Sweet Gas Gathering System for such Month.

     (c) Lost and Unaccounted for Gas Allocation for Sour Gas Gathering System. That portion of the Monthly Gas Receipt delivered into the Sour Gas Gathering System shall be allocated, each Month, Shipper’s Pro Rata Share of Lost and Unaccounted for Gas calculated for the Sour Gas Gathering System for such Month.

     Section 7.2 Modifications to Allocation Procedures. In the event that the allocation procedures herein shall cease to be reflective of actual operations or become inequitable in any respect, such allocation procedures shall be modified, including, without limitation, the determination of Shipper’s Pro Rata Share, from time to time in order to reflect actual

24

operations and to remove any such inequities; provided, however, such allocation procedures shall be consistently applied to Shipper and all Other Shippers utilizing the Gathering System.

ARTICLE 8
SHIPPER COMMITMENTS AND RIGHTS

     Section 8.1 Conveyance of Rights to Gatherer. Subject to Shipper’s obligations under the Prior Dedications and the other terms and conditions of this Agreement, Shipper hereby grants, sells, transfers, conveys, and assigns to Gatherer (i) the exclusive right to provide Services for the Dedicated Gas, (ii) all right, title, interest and/or ownership in all Condensate recovered from Shipper’s Gas, and (iii) the right to consume Shipper’s Gas as Field Fuel in connection with the provision of the Services hereunder.

     Section 8.2 Shipper Compression.

     (a) Shipper shall have the right, at its own expense, to install compression facilities and plunger lifts upstream of the Receipt Points. Any such facilities installed by Shipper shall be installed, operated, and maintained in a manner that does not adversely affect (i) Gatherer’s dehydration, measurement, gathering or other facilities, (ii) the operation of the Gathering System, or (iii) any contractual obligations of Gatherer.

     (b) If, from time to time, Shipper desires to have lower pressures on all or any portion of a Sub-System, Gatherer and Shipper shall negotiate in good faith for Gatherer to install compression to lower pressures. If Gatherer and Shipper are unable to agree upon terms under which Gatherer would install such compression, then Gatherer shall allow Shipper to install, own and operate such compression facilities on the Gathering System as reasonably determined by Shipper.

     (c) Shipper shall provide the Field Fuel consumed in the operation of any Shipper Compression, unless Other Shippers also utilize Shipper Compression.

     (d) If Shipper installs Shipper Compression, Shipper shall indemnify, defend, and hold harmless the Gatherer Indemnified Parties from and against all Claims and Losses arising out of, or resulting from, the installation, operation, maintenance, or removal of such Shipper Compression, unless such claims were the result of negligence, gross negligence or willful misconduct of any of the Gatherer Indemnified Parties.

     Section 8.3 Gas for Lease Operations. Shipper shall have the right to utilize Dedicated Gas and other Gas from the Gathering System as may be required to be delivered to lessors under the terms of any leases or as required for Shipper’s operations within the Dedicated Area or lands pooled or unitized therewith, as determined by Shipper in its sole discretion. In connection therewith, Gatherer shall provide Shipper, at Shipper’s sole cost and expense, such taps on the Gathering System as may be reasonably required by Shipper for such purposes. Shipper shall estimate the Volume and Quantity of such Gas so used and report such estimate to Gatherer on or before the fifth (5^th) Day of the Month following the Month of such usage.

25

     Section 8.4 Pooling or Units. Shipper may form, dissolve, and/or participate in pooling agreements or units encompassing all or any portions of the Dedicated Area, as determined by Shipper in its sole discretion.

     Section 8.5 Operational Control of Shipper’s Wells. Shipper reserves the right to operate its leases and wells in any manner that it desires, free of any control by Gatherer, as determined by Shipper in its sole discretion, including without limitation, (i) shutting-in, cleaning out, reworking, modifying, deepening, or abandoning any such wells, (ii) using any efficient, modern, or improved method for the production of its wells and (iii) surrendering, releasing, or terminating its leases or Interests at any time; provided that before any well is taken out of service for any reason, Shipper shall first shut-off the well’s connection to the Receipt Point.

     Section 8.6 Access to Facilities. Subject to Shipper’s safety rules, regulations and procedures, (i) Shipper shall provide Gatherer such access to Shipper’s facilities as necessary and convenient to perform Gatherer’s obligations under this Agreement and (ii) insofar as it has the right to do so, Shipper grants Gatherer the use of all easements and rights-of-way held by Shipper that are necessary and convenient for Gatherer to perform its obligations under this Agreement. Shipper shall be responsible for maintaining such rights of access, easements and rights-of-way at its sole cost and expense.

     Section 8.7 Line Pack. The Parties acknowledge and agree that Line Pack shall be owned as provided for in the Intercompany Conveyance.

     Section 8.8 Cholla Gathering Agreement. Shipper shall not (a) cancel or terminate the Cholla Gathering Agreement (or consent or accept any cancellation or termination thereof) prior to June 30, 2029 or (b) enter into or permit any material modification of, or waive any material right or obligation of any Person under, the Cholla Gathering Agreement.

ARTICLE 9
MAINTENANCE AND MARKETING OF CONDENSATE

     Section 9.1 Maintenance. Gatherer shall be entitled to interrupt its performance hereunder to perform necessary or desirable inspections, pigging, maintenance, testing, alterations, modifications, expansions, connections, repairs, or replacements to the Gathering System (“Maintenance”), with notice as provided herein to Shipper, except in cases of emergency where such notice is impracticable or in cases where the operations of Shipper will not be affected. Before the beginning of each Calendar Year, Gatherer shall provide Shipper in writing with an estimated schedule of the Maintenance to be performed during the Calendar Year and the anticipated dates of such Maintenance. In performing Maintenance, Gatherer shall coordinate its activities with Shipper and perform such Maintenance is such a manner so as to minimize downtime, shutting-in of Shipper’s production and interference with Shipper’s operations.

     Section 9.2 Marketing of Condensate. Gatherer shall market Condensate to a Person not Affiliated with Gatherer, upon terms which, in Gatherer’s good faith judgment, are reasonable terms in light of market conditions existing at that time.

26

ARTICLE 10
RECEIPT POINTS, DELIVERY POINTS, AND PRESSURES

     Section 10.1 Receipt Points. Shipper shall deliver Shipper’s Gas to Gatherer hereunder at the Receipt Points.

     Section 10.2 Delivery Points. Gatherer shall deliver Delivery Point Gas hereunder to the Delivery Points as nominated by Shipper pursuant to this Agreement.

     Section 10.3 Uniform Deliveries. Shipper shall deliver Shipper’s Gas at the Receipt Points and Gatherer will receive and redeliver Delivery Point Gas to the Delivery Points as nearly as practicable at uniform hourly and daily rates of flow.

     Section 10.4 Pressure at Receipt Points. Shipper shall cause Shipper’s Gas to be delivered to the Receipt Points at a pressure sufficient to enter the Gathering System, but shall not be delivered at pressures in excess of the maximum allowable operating pressure at the Receipt Points, as such pressure may exist from time to time; provided, however, the following shall apply:

     (a) Required Pressure. From and after the one (1) year anniversary of the end of the Expansion Period, Gatherer shall be responsible, at its sole cost and expense, to maintain pressures on each Sub-System (other than the High-Pressure Sweet Sub-System and the High Pressure Sour Sub-System) at or below the Sub-System Turnover Average Receipt Point Pressure applicable to such Sub-System.

     (b) Operations Fee Reduction. If the Monthly Average Receipt Point Pressure exceeds the applicable Sub-System Turnover Average Receipt Point Pressure for any Sub-System (other than the High-Pressure Sweet Sub-System and the High Pressure Sour Sub-System) during any Month after the one (1) year anniversary of the end of the Expansion Period, then for each Receipt Point on such Sub-System that exceeds the Sub-System Turnover Average Receipt Point Pressure for the Sub-System to which such Receipt Point is connected, the Operations Fees for such Month applicable to such Receipt Point shall be reduced by an amount equal to the product of (i) such Operations Fee and (ii) two percent (2%) for each one percent (1%) that such Monthly Average Receipt Point Pressure exceeds the applicable the Sub-System Turnover Average Receipt Point Pressure. For example, if during the applicable Month, the applicable Operations Fee is $0.10 per Mcf and the applicable the Sub-System Turnover Average Receipt Point Pressure is one hundred (100) psig, but during such Month, the Monthly Average Receipt Point Pressure was one hundred ten (110) psig, then the Operations Fee would be reduced to $0.08 per Mcf. Nothing herein shall relieve Gatherer of any liability for failure to provide Services pursuant to, and in accordance with, the terms of this Agreement. Notwithstanding anything contained in this Section 10.4(b), there will be no reduction in the Operations Fee for any Receipt Point that is first established or re-connected to the Gathering System after the one (1) year anniversary of the end of the Expansion Period, which has, during the first thirty (30) days of production, a weighted average pressure above the Sub-System Turnover Average Receipt Point Pressure for the Sub-System to which such Receipt Point is connected.

27

     (c) Release. If (i) after the one (1) year anniversary of the end of the Expansion Period, the Monthly Average Receipt Point Pressure for any Sub-System (other than the High-Pressure Sweet Sub-System and the High Pressure Sour Sub-System) is greater than the applicable Sub-System Turnover Average Receipt Point Pressure for (A) a period of one hundred twenty (120) Days or more during any Year or (B) a continuous period of sixty (60) Days or more (the “Initial Excess Pressure Period”), and (ii) no event has occurred or condition exists that constitutes a material breach or violation of, or a failure to comply with, this Agreement or the O&M Agreement on the part of Shipper which remains uncured, then (y) Shipper, at its option, may elect to permanently release the Dedicated Gas produced from wells delivering to each Receipt Point on such Sub-System that exceeds the Sub-System Turnover Average Receipt Point Pressure for the Sub-System to which such Receipt Point is connected by delivering written notice thereof to Gatherer, and (z) if Shipper exercises such option, Shipper and Gatherer shall acknowledge in writing the wells and Dedicated Gas that have been released from the Dedication and this Agreement. Notwithstanding anything herein to the contrary, no Dedicated Gas shall be released pursuant to this paragraph (c) prior to the occurrence of the Trigger Event, unless, at any time after the end of the Initial Excess Pressure Period, Gatherer is not using commercially reasonable efforts to remedy the situation with all reasonable dispatch; provided, however, if after an additional ninety (90) Days after the Initial Excess Pressure Period, Gatherer has failed to remedy such situation, then Shipper, at its option, may elect to permanently release the Dedicated Gas produced from the wells delivering to such Sub-System or such Receipt Point as provided above. Nothing herein shall relieve Gatherer of any liability for failure to provide Services pursuant to, and in accordance with, the terms of this Agreement.

     (d) Excessive Shipper Volumes. If (i) Gatherer is unable to comply with the obligations set forth in Section 10.4(a) due solely to deliveries or attempted deliveries of Shipper’s Gas and (ii) no event has occurred or condition exists that constitutes a material breach or violation of, or a failure to comply with, this Agreement or the O&M Agreement on the part of Gatherer which remains uncured, then Gatherer shall be relieved of its obligations under this Section 10.4 with respect to such Day.

     Section 10.5 Pressure at Delivery Points. Gatherer shall deliver Delivery Point Gas to the Delivery Points at a pressure sufficient to enter the receiving facilities at each such Delivery Point but shall not deliver the Delivery Point Gas at pressures in excess of the maximum allowable operating pressure of the receiving facilities at the Delivery Point, as such pressure may exist from time to time. The minimum pressures for each Delivery Point are specified in Exhibit E attached hereto.

     Section 10.6 Arrangements Prior to Receipt and After Redelivery. It shall be Shipper’s obligation to make any required arrangements with other parties for delivery of Shipper’s Gas into the Gathering System at the Receipt Points and following redelivery at the Delivery Points.

28

ARTICLE 11
NOMINATION AND BALANCING PROCEDURES

     Section 11.1 Notice of Available Capacity. On or before the 20^th day of each Month, Gatherer shall provide written notice to Shipper of Gatherer’s good faith estimate of any capacity allocations or curtailments, if any, that, based on then currently available information, Gatherer anticipates will be required or necessary during the next succeeding Month. In the event that the 20^th day of the Month is a weekend or holiday, such notice will be provided on the last Business Day preceding the 20^th day of such Month.

     Section 11.2 Nomination Procedures. Pursuant to the terms of this Agreement, the nomination procedures detailed in this Section will be utilized by the Parties with respect to the Services provided hereunder. All nominations must be made by Shipper or Shipper’s designee. For the purposes of this Article 11, Shipper’s Gas shall include Third Party Shipper Gas.

     (a) Shipper and Similarly Situated Shippers shall have priority service over all Other Shippers and Shipper’s and Similarly Situated Shippers’ nominations to the Delivery Points shall be placed in advance of all Other Shippers. To the extent a Delivery Point does not have capacity for the cumulative volumes from Shipper and Other Shippers’ nominations, Gatherer will advise each Other Shipper to reduce its nominations to ensure that Shipper’s Gas and Similarly Situated Shippers’ Gas receive priority service.

     (b) Shipper’s nominations hereunder shall be accepted and scheduled for delivery by Gatherer to the extent (i) Shipper’s Gas (including any Imbalance Gas) hereunder is sufficient to support such nominations, (ii) available capacity exists to provide Services with respect to such Gas (which capacity shall be allocated to Shipper in accordance with Section 2.6), and (iii) the party receiving Gas at each Delivery Point accepts Shipper’s nominations. Upon being scheduled for delivery, Gatherer’s dispatcher shall thereupon advise Shipper in writing, via fax, e-mail, or web-based nomination process of the quantity scheduled for Services hereunder (a “Scheduled Nomination”) and the reason for any failure to schedule any of Shipper’s Gas nominated by Shipper.

     (c) Each nomination shall be made in conformance with the North American Energy Standards Board nominations timeline, which may change from time to time.

     (d) Shipper shall provide to Gatherer’s dispatcher in writing, via fax, e-mail, or web-based nomination process the actual daily nominations of the quantities to be delivered hereunder by Gatherer for Shipper’s account at each Delivery Point in accordance with Gatherer’s requirements. Such nominations shall include the information requested by Gatherer, and Gatherer shall maintain a record of such nominations.

     (e) Gatherer shall have the right to refuse receipt of volumes of Shipper’s Gas from Shipper to the extent they exceed Scheduled Nominations provided that Gatherer gives Shipper notice of such refusal. In that regard, Gatherer may require that Shipper cease or curtail deliveries of Shipper’s Gas to match production with Scheduled

29

Nominations; provided, however, that to the extent available capacity exists, Gatherer shall accept any increase in Shipper’s Scheduled Nominations made by Shipper or its designee to match the delivered Volumes to receive such Gas so that Shipper does not have to cease or curtail deliveries.

     (f) Gatherer shall accept any revisions to a prior Scheduled Nomination which result in an increase in volume of Gas Shipper desires to deliver to the Delivery Point that is supported by corresponding increases in physical volume available at the Receipt Point.

     Section 11.3 Gas Balancing. It shall be Gatherer’s responsibility to maintain balance on the Gathering System with Shipper and all Other Shippers. Gatherer and Shipper shall resolve an over-delivery or under-delivery of Shipper’s Gas each Month in accordance with this Article 11 on an MMBtu basis.

     Section 11.4 Imbalances.

     (a) Imbalance Gas. Shipper intends for the Quantity of Gas actually delivered at each Delivery Point to equal the Scheduled Nominations for each such Delivery Point and will use reasonable efforts to nominate Gas in such manner. Shipper will use its best efforts to base Scheduled Nominations on the forecasted quantity of Shipper’s Gas less any deductions provided for herein. Any difference between the actual physical flow of Gas at the Delivery Points and the Scheduled Nominations shall be deemed “Imbalance Gas” at such Delivery Point. In that regard, Gatherer shall provide Shipper (i) a Daily balancing statement and (ii) a Monthly balancing statement by the tenth (10^th) Day of each Month of the difference, if any, between the Quantity of Gas nominated by Shipper at each Delivery Point during the immediately preceding Month and the Quantity of Shipper’s Gas allocated at each Delivery Point during such Month. Such difference, positive or negative, shall be deemed the Imbalance Gas with positive amounts being the Quantity of Gas due Shipper and negative amounts being the Quantity due Gatherer. The Imbalance Gas shall be eliminated over time through the nomination and delivery process by Shipper nominating less Gas than is actually delivered if the Imbalance Gas account is negative and by Shipper nominating more Gas than is actually delivered if the Imbalance Gas account is positive.

     (b) Imbalance Accounts. Gatherer shall (i) enter into agreements containing similar balancing provisions to those contained herein with all Other Shippers and (ii) maintain similar imbalance Gas accounts with, and shall provide similar balancing statements to, all Other Shippers at each Delivery Point on an MMBtu basis. Gatherer shall diligently coordinate with Shipper to resolve any imbalances each Month under the premise that Shipper and Similarly Situated Shippers have priority service and any Shipper imbalances will not be greater from a percentage standpoint than any Other Shipper imbalances. In that regard, Gatherer shall require Other Shippers to adjust their nominations throughout the Month so as to minimize imbalances and to achieve balance on the Gathering System. Either Party shall have the option to exercise a cash-out for any Positive Shipper Monthly Imbalance Quantity or Negative Shipper Monthly Imbalance Quantity pursuant to Section 11.4(c) below.

30

     (c) Cash-Out of Shipper Monthly Imbalances. If either Party elects to cash-out pursuant to Section 11.3(b), for each MMBtu of Positive Shipper Monthly Imbalance Quantity or Negative Shipper Monthly Imbalance Quantity, as the case may be, calculated at the end of each Month that falls within each range set forth below, Shipper shall pay to Gatherer, or Gatherer shall pay to Shipper, as applicable, the product of (i) the Cash-Out Value Percentage attributable to such Gas, as set forth below, multiplied by (ii) the Imbalance Cash-Out Price for such Month. Such amounts shall be included on and paid in accordance with Gatherer’s next ensuing Monthly invoice.

Monthly Imbalance Percentage
([Positive or Negative Shipper Monthly
Imbalance Quantity] Divided by [the
Quantity of the Monthly Gas Receipt for
such Month less Quantity Reductions for
such Month])	Cash-out Value Percentage
less than 5%		100	%
5% up to 10%		105	%
greater than 10%		110	%

For example, if the Quantity of the Monthly Gas Receipt for such Month less the Quantity Reductions equaled one hundred (100) MMBtu, the Negative Shipper Monthly Imbalance Quantity for such Month was twelve (12) MMBtu, and the Imbalance Cash-Out Price for such Month was $5.00, then Gatherer would pay to Shipper $5.00 for the first five (5) MMBtu, $5.25 for the next five (5) MMBtu, and $5.50 for the remaining two (2) MMBtu.

     (d) Imbalance Penalties. If either Party incurs any costs or fees (including, without limitation, transportation costs, charges or penalties) from Persons receiving Gas at the Delivery Points as a result of the other Party’s actions or negligence in maintaining balance on the Gathering System, such other Party shall reimburse the first Party for such costs and fees. The Party requesting such reimbursement shall provide the other Party with all the documentation and statements justifying the claim for its review and to contest should it not agree with the requesting Party.

     Section 11.5 Maintenance.

     (a) Monthly Maintenance schedules shall be sent via email to Shipper by the 20^th day of each Month setting forth the Maintenance that is to be performed during the next Month; provided, however, in the event the 20^th day of the Month is a weekend or holiday, monthly Maintenance schedules will be provided no later than the last Business Day preceding the 20^th day of the Month.

     (b) Maintenance schedules will include by compressor station a description of each Maintenance project at the compressor stations and an estimate of capacity curtailment and duration for each project.

31

     (c) No later than forty-eight (48) hours prior to the beginning of the Day of each Maintenance project, a volume curtailment allocation will be sent to Shipper if capacity allocations are determined to be necessary by Gatherer.

     Section 11.6 Unscheduled Capacity Allocations.

     (a) Gatherer shall use reasonable efforts to provide timely notification to Shipper by telephone, with subsequent e-mail notification, of the potential size and duration of any unscheduled capacity disruption. If Shipper does not make necessary adjustments to its nominations within four (4) hours, Gatherer may adjust Shipper’s nominations and/or not confirm additional nominations requested by Shipper.

     (b) Gatherer also may request that Shipper curtail production to match production with nominations of Shipper’s Gas. In such event, if Shipper does not adjust its nomination as reasonably directed by Gatherer, and such failure to adjust nominations materially impacts operations on the Gathering System, Gatherer may curtail or shut in Gas for a reasonable period of time to match Shipper’s production with Shipper’s nominations. Gatherer shall not be liable for Losses caused by any such curtailment under this Section 11.6(b) unless such curtailment is due to the negligence of Gatherer.

     Section 11.7 Modifications to Nomination and Balancing Procedures. In the event that the nomination and balancing procedures herein shall cease to be reflective of actual operations or become inequitable in any respect, such nomination and balancing procedures shall be modified from time to time in order to reflect actual operations and to remove any such inequities; provided, however, such nomination and balancing procedures shall be consistently applied to Shipper and all Other Shippers utilizing the Gathering System.

ARTICLE 12
GAS QUALITY

     Section 12.1 Receipt Point Gas Quality Specifications. Shipper’s Gas delivered to the Receipt Points shall meet the applicable Receipt Point Gas Quality Specifications.

     Section 12.2 Non-Conforming Gas. If at any time Gatherer becomes aware that Shipper’s Gas at the Receipt Points fails to conform to the applicable Receipt Point Gas Quality Specifications (“Off-Specification Receipts”), then (i) Gatherer shall give Shipper written notice of the deficiency and Shipper shall take steps to remedy the deficiency and (ii) Gatherer may take any combination of the following actions:

     (a) take receipt of the non-conforming Shipper’s Gas and that receipt shall not be construed as a waiver or change of standards for future volumes; or

     (b) after providing notice as provided above in this Section 12.2, immediately cease receiving the non-conforming Shipper’s Gas by shutting in the sources of such non-conforming Shipper’s Gas or by other appropriate means and shall notify Shipper that Gatherer has ceased, or will cease, receiving the non-conforming Shipper’s Gas.

32

Notwithstanding anything to the contrary herein, the fact that Dedicated Gas may not meet the Receipt Point Gas Specifications shall not operate to release such Dedicated Gas from the Dedication.

     Section 12.3 Off-Specification Receipts. Notwithstanding Section 12.2, Gatherer shall accept Off-Specification Receipts; provided that Gatherer shall have the right to cease receiving such Off-Specification Receipts if Gatherer determines in good faith that the blended Gas stream in the applicable Sub-System would not meet the Delivery Point Gas Quality Specifications or the receiving party at the Delivery Point would not agree to accept such Off-Specification Receipts.

     Section 12.4 Reimbursement and Shipper Indemnity. Any damages caused by Off-Specification Receipts from Shipper to the Gathering System or the Gas therein shall be remedied by Shipper through a reimbursement of the costs incurred by Gatherer to mitigate or remedy the damages. In addition, Shipper agrees to defend, indemnify, and hold harmless Gatherer from and against all Claims and Losses arising out of, resulting from, or caused by Shipper delivering Gas to Gatherer at the Receipt Points that does not conform to the applicable Receipt Point Gas Quality Specifications.

     Section 12.5 Delivery Point Gas Quality Specifications. The Delivery Point Gas delivered by Gatherer to Shipper at the Delivery Points shall meet the Delivery Point Gas Quality Specifications, except to the extent that the delivery of non-conforming Gas is caused by the receipt of Off-Specification Receipts from Shipper at the Receipt Points.

     Section 12.6 Gatherer Indemnity. Gatherer agrees to defend, indemnify, and hold harmless Shipper from and against all Claims and Losses arising out of, resulting from, or caused by Gatherer delivering Gas to Shipper at the Delivery Points that does not conform to the applicable Delivery Point Gas Quality Specifications, except to the extent that the delivery of such non-conforming Gas is caused by the receipt of Off-Specification Receipts from Shipper at the Receipt Points.

ARTICLE 13
MEASUREMENT EQUIPMENT AND PROCEDURES

     Section 13.1 Equipment and Specifications. For measurement purposes under this Agreement, Shipper’s Gas delivered into the Gathering System shall be measured at the Measurement Meters and the Delivery Point Gas shall be measured at the meters at the Delivery Points. Measurement and appurtenant facilities shall be installed, operated, and maintained by the measuring party in accurate working order and condition to measure Gas at all applicable measurement points in accordance with the provisions hereof.

     Section 13.2 Gas Meter Standards. Orifice meters installed in such measuring stations shall be constructed and operated in accordance with ANSI/API 2530 API 14.3, AGA Report No. 3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, as it is now and from time to time may be revised, amended, or supplemented and shall include the use of flange connections and, where necessary, straightening vanes, flow conditioners and/or pulsation dampening equipment. Ultrasonic meters installed in such measuring stations shall be

33

constructed and operated in accordance with AGA Report No. 9, Measurement of Gas by Ultrasonic Meters, First Edition, and any subsequent modification and amendment thereof generally accepted within the Gas industry. Electronic flow computers shall be used and the Gas shall have its volume, mass, and/or heat content computed in accordance with the applicable AGA standards including, but not limited to, AGA Report Nos. 3, 5, 6, 7, 8 and API 21.1 “Flow Measurement Using Electronic Metering Systems” and any subsequent modifications and amendments thereof generally accepted within the Gas industry. When Gas chromatographs are used they shall be installed, operated, maintained, and verified according to industry standards (GPA 2261, GPA 2145, GPA 2172, and GPA 2177).

     Section 13.3 Notice of Measurement Equipment Inspection and Calibration. Each Party shall give reasonable notice to the other Party in order that the other Party may, at its option, have representatives present to observe any reading, inspecting, testing, calibrating, or adjusting of measuring equipment used in measuring or checking the measurement of receipts or deliveries of Gas under this Agreement. The official electronic data from such measuring equipment shall remain the property of the measuring equipment owner, but copies of such records shall, upon written request, be submitted, together with calculations and flow computer configurations therefrom, to the requesting Party for inspection and verification.

     Section 13.4 Measurement Accuracy Verification. Each Party shall verify the accuracy of all transmitters, flow computers, and other equipment used in the measurement of the Gas hereunder at intervals not to exceed one hundred eighty (180) Days and cause such equipment to be adjusted or calibrated as necessary. Testing frequency will be based upon each well or station’s flow rate (Mcf/Day). Any flow rate greater than or equal to 5,000 Mcf/Day shall be tested monthly. Any flow rate that is greater than or equal to 1,000 Mcf/Day, but less than 5,000 Mcf/Day, shall be tested semi-annually. Neither Party shall be required to cause adjustment or calibration of such equipment more frequently than once every Month, unless a special test is requested pursuant to Section 13.5 of this Agreement. If, upon test, (i) no adjustment or calibration error is found that results in an incremental adjustment to the calculated flow rate through each meter run in excess of one percent (1%) of the adjusted flow rate (whether positive or negative and using the adjusted flow rate as the percent error equation denominator) or (ii) any quantity error is not greater than two hundred fifty (250) Mcf per Month, then any previous recordings of such equipment shall be considered accurate in computing deliveries but such equipment shall be adjusted or calibrated at once. If, during any test of the measuring equipment, an adjustment or calibration error is found that results in (i) an incremental adjustment to the calculated flow rate through each meter run in excess of one percent (1%) of the adjusted flow rate (whether positive or negative and using the adjusted flow rate as the percent error equation denominator) and (ii) a quantity error greater than two hundred fifty (250) Mcf per Month (“Material Error”), then any previous recordings of such equipment shall be corrected to zero error for any period during which the error existed (and which is either known definitely or agreed to by the Parties) and the total flow for such period shall be determined in accordance with the provisions of Section 13.6 of this Agreement. If the period of error condition cannot be determined or agreed upon between the Parties, such correction shall be for a period extending over the last one half (1/2) of the time elapsed since the date of the last test.

34

     Section 13.5 Special Tests. In the event a Party desires a special test (a test not scheduled by a Party under the provisions of Section 13.4 of this Agreement) of any measuring equipment, seventy-two (72) hours advance notice shall be given to the other Party and, after providing such notice, such test shall be promptly performed. If no Material Error is found, the Party requesting the test shall pay the costs of such special test including any labor and transportation costs pertaining thereto. If a Material Error is determined to exist, the Party responsible for such measurement shall pay such costs and perform any corrections required under Section 13.4 of this Agreement.

     Section 13.6 Metered Flow Rates in Error. If, for any reason, any measurement equipment is (i) out of adjustment, (ii) out of service, or (iii) out of repair, and, in each case, a Material Error exists as a result thereof, the total quantity of Gas delivered shall be determined in accordance with the first of the following methods which is feasible:

     (a) by using the registration of any mutually agreeable check metering facility, if installed and accurately registering (subject to testing as provided for in Section 13.4 of this Agreement);

     (b) where multiple meter runs exist in series, by calculation using the registration of such meter run equipment; provided that they are measuring Gas from upstream and downstream headers in common with the faulty metering equipment, are not controlled by separate regulators, and are accurately registering;

     (c) by estimating the quantity, based upon deliveries made during periods of similar conditions when the meter was registering accurately.

     Section 13.7 Record Retention. The Party owning the measurement equipment shall retain and preserve all test data, charts, and similar records for any calendar year for a period of at least sixty (60) Months following the end of such calendar year unless applicable law or regulation requires a longer time period or the Party has received written notification of a dispute involving such records, in which case records shall be retained until the related issue is resolved.

     Section 13.8 Correction Factors for Volume Measurement. The computations of the volumes of Gas measured shall be made as follows:

     (a) The hourly orifice coefficient for each meter shall be calculated at the base pressure of fourteen and sixty-five hundredths (14.65) psia and the base temperature of sixty (60) degrees Fahrenheit. All Gas volume measurements shall be based on an local atmospheric pressure assumed to be thirteen and two-tenths (13.2) psia.

     (b) The flowing temperature of the Gas shall be continuously measured. In the case of electronic metering, such temperature measurement shall be used as continuous input to the flow computer for calculation of Gas volume, mass and/or energy content in accordance with the applicable AGA or API 21.1 standards including, but not limited to, AGA Report Nos. 3, 5, 6, 7 and 8 and any subsequent modification and amendments thereof generally accepted within the Gas industry.

35

     (c) Measurements of inside diameters of pipe runs and orifices shall be obtained by means of a micrometer to the nearest one-thousandth of an inch, and such measurements shall be used in computations of coefficients.

     (d) In determining the volume of Gas, when electronic transducers and flow computers are used, the Gas shall have its volume, mass and/or energy content continuously integrated in accordance with the applicable AGA standards including, but not limited to, AGA report Nos. 3, 5, 6, 7 and 8 and any subsequent modification and amendments thereof generally accepted within the Gas industry.

     (e) In calculating the volume of Gas, deviation from Boyle’s Law at the pressure, specific gravity, and temperature for each measurement shall be determined by use of AGA Report No. 8, Compressibility Factors for Natural Gas and Other Related Hydrocarbon Gases, published by the AGA in conjunction with Gas Measurement Committee Report No. 3 and amendments thereto generally accepted within the Gas industry.

     (f) Whenever the conditions of pressure and temperature differ from the standards described herein, conversion of the volume from these conditions to the standard conditions shall be made in accordance with the Ideal Gas Laws, corrected for deviation by the methods set forth in the AGA Gas Measurement Committee Report No. 3, as said report may be amended from time to time.

     Section 13.9 Exception to Gas Measurement Basis. If at any time the basis of measurement set out in this Agreement should conflict with rules, regulations, or orders of any state or federal regulatory body having jurisdiction, then the basis of measurement provided for in such rules, regulations, or orders shall govern measurements hereunder.

     Section 13.10 Gas Sampling. The frequency of sampling will be at the same interval as the calibration for all meters. New wells or wells that have been changed due to a work over or other well bore alteration that could alter the Gas composition shall be sampled monthly until the analyses demonstrate reasonable consistency. After such time said meters will then be sampled at the stated calibration frequency.

     (a) The C₆+ composition, specific gravity and Gross Heating Value of Gas will be determined by the measuring party taking a sample at the same frequency as the meter calibration test. The sample will be acquired through a spot, composite, or on-line Gas chromatograph. The analytical results shall be applied at the beginning of the Month the sample is taken until a subsequent representative sample is applied.

     (b) The specific gravity of Gas at all applicable measurement points shall be determined by a Gas chromatographic component analysis to the nearest one thousandth (0.001) of the samples of the Gas taken for test purposes as provided above, or by such other method as shall be mutually agreed upon.

     (c) The Gross Heating Value shall be measured by Gas chromatographic analysis component analysis of the samples of the Gas taken for test purposes as provided above, or by such other method as shall be mutually agreed upon.

36

     Section 13.11 Modifications to Measurement Procedures. In the event that the measurement procedures herein shall cease to be reflective of actual operations or become inequitable in any respect, such measurement procedures shall be modified from time to time in order to reflect actual operations and to remove any such inequities; provided, however, such measurement procedures shall be consistently applied to Shipper and all Other Shippers utilizing the Gathering System.

     Section 13.12 Measurement Disputes. Any dispute, controversy, or claim arising out of or in connection with this Article 13 (a “Measurement Dispute”), which the Parties are unable to resolve shall be referred to and determined by a mutually agreeable measurement expert (the “Measurement Expert”), as the sole and exclusive remedy of the Parties as to the Measurement Dispute. Prior to retention of a Measurement Expert, the Parties will collectively approach and negotiate fees with such Measurement Expert. Before any material information pertaining to the Measurement Dispute is presented to the Measurement Expert, the Measurement Expert must agree in writing to maintain the confidentiality of all information provided to the Measurement Expert by either Party. All Party communications with the Measurement Expert prior to and after retention, including explanations of the dispute, data submissions, and data reviews, must be attended by representatives of the other Party or its designees. The decision of the Measurement Expert shall be final and binding upon the Parties.

ARTICLE 14
NOTICES

     Except as specifically provided otherwise herein, any notice, claim, or other communication provided for in this Agreement or any notice that either Party may desire to give to the other shall be in writing and shall be: (i) sent by facsimile transmission; (ii) delivered by hand; (iii) sent by United States mail with all postage fully prepaid; or (iv) delivered by courier with charges paid in accordance with the customary arrangements established by such courier, in each of the foregoing cases addressed to the Party at the following addresses:

Gatherer:	Piñon Gathering Company, LLC
	c/o TCW Asset Management Company
	333 Clay Street, Suite 4150
	Houston, Texas 77002
	Attention: Clay Taylor
	Fax Number: 713.615.7460
with a copy to:	TCW Asset Management Company
	865 South Figueroa Street, Suite 1800
	Los Angeles, California 90017
	Attention: R. Blair Thomas
	Fax Number: 213.244.0604
Shipper:	SandRidge Exploration and Production, LLC
	123 Robert S. Kerr Avenue
	Oklahoma City, Oklahoma 73102-6406
	Attention: Midstream — Manager of Administration
	Fax Number: 405.429.5990

37

or at such other address as either Party may at any time designate by giving written notice to the other Party. Such notices, invoices, allocation statements, claims, or other communications shall be deemed received as follows: (i) if delivered personally, upon delivery; (ii) if sent by United States mail, whether by express mail, registered mail, certified mail or regular mail, the notice shall be deemed to have been received on the day receipt is refused or is confirmed orally or in writing by the receiving Party; (iii) if sent by a courier service, upon delivery; or (iv) if sent by facsimile, the Business Day following the day on which it was transmitted and confirmed by transmission report or such earlier time as confirmed orally or in writing by the receiving Party.

ARTICLE 15
PAYMENTS

     Section 15.1 Payments and Invoices. Not later than the fifteenth (15^th) day of the Month immediately following the Month for which the consideration is due, Shipper shall pay to Gatherer the Gathering Fees and the Commodity Fee for the Base Volumes for the Month for which the consideration is due. Gatherer shall provide Shipper with a detailed statement and supporting documentation for the net amount of all consideration due (including deductions) under the terms of this Agreement (including amounts due or deductions for monthly imbalances pursuant to Section 11.3), not later than the last day of the Month immediately following the Month for which the consideration is due. In the event Shipper disputes any portion of the net amount set out in Gatherer’s statement, Shipper shall provide Gatherer with a detailed accounting of the disputed amounts and its basis for the dispute and shall make payment to Gatherer of the net amount due and not in dispute within fifteen (15) days after receipt of Gatherer’s statement. Such payment shall be made by wire transfer pursuant to wire transfer instructions delivered by Gatherer to Shipper in writing from time to time; provided that upon the request of Gatherer, Shipper shall make payment of the Operations Fee directly to Operator. Any amounts owing by Gatherer to Shipper shall be deducted from amounts otherwise due Gatherer in the next ensuing Monthly invoice. Notwithstanding anything herein to the contrary, any indemnification payments required to be made by a Party hereunder shall be made to the indemnified Party upon receipt by the indemnifying Party of written demand therefor from the indemnified Party.

     Section 15.2 Audit Rights. Each Party, on not less than thirty (30) Days’ prior written notice to the other Party, shall have the right at its expense, at reasonable times during normal business hours, to audit the books and records of the other Party to the extent necessary to verify the accuracy of any statement, allocation, measurement, computation, charge, or payment made under or pursuant to this Agreement. The scope of any audit shall be limited to transactions affecting the Gas delivered or Services provided hereunder and shall be limited to the twenty-four (24) month period immediately prior to the Month in which the notice requesting an audit was given. However, no audit may include any time period for which a prior audit hereunder was conducted, and no audit may occur more frequently than once each twelve (12) Months. All statements, allocations, measurements, computations, charges, or payments made hereunder shall be conclusively deemed true and correct and shall be final for all purposes, unless a specific written claim detailing the amounts in question is made on or before the end of the twenty-fourth (24^th) Month after the Month in which such statement,

38

allocation, measurement, computation, charge or payment was made; provided, however, if any such statement, allocation, measurement, computation, charge or payment is the subject of an audit requested within the time periods provided herein, then the Party conducting such audit shall have ninety (90) Days after the date on which such audit is requested to make such specific written claim detailing the amounts in question. To the extent the foregoing varies from any applicable statute of limitation, the Parties expressly waive all such statutes of limitation.

     Section 15.3 Right to Suspend on Failure to Pay. If any undisputed amount due hereunder remains unpaid for the longer of (i) twenty (20) days after the due date, or (ii) ten (10) days after delivery of notice of non-payment, Gatherer shall have the right to suspend or discontinue services hereunder until any such past due amount is paid. Each Party agrees to pay all costs incurred by the prevailing Party in connection with the collection of, or attempt to collect, any amounts due hereunder, including, without limitation, reasonable attorney’s fees and court costs.

     Section 15.4 Creditworthiness.

     (a) Gatherer shall not be required to commence or to continue Services hereunder on behalf of Shipper if Shipper (i) is or has become insolvent or (ii) at Gatherer’ request, fails, within a reasonable period of time of not less than ten (10) days, to demonstrate creditworthiness as reasonably determined by Gatherer. Notwithstanding the foregoing, Gatherer shall provide Services to Shipper hereunder if Shipper (x) prepays for such Services or (y) furnishes good and sufficient security, as determined by Gatherer in its reasonable discretion, in an amount equal to the estimated cost of Services for a three (3) Month period. Gatherer may reassess the creditworthiness of and performance by Shipper from time to time.

     (b) The insolvency of Shipper shall be evidenced by the filing by Shipper or its parent entity of a voluntary petition in bankruptcy or the entry of a decree or order by a court having jurisdiction in the premises adjudging Shipper or its parent entity as bankrupt or insolvent, or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of Shipper or its parent entity under the Federal Bankruptcy Act or any other applicable federal or state law, or appointing a receiver, liquidator, assignee, trustee, sequestrator (or other similar official) of Shipper, its parent entity or of any substantial part of their respective property, or the ordering of the winding-up or liquidation of Shipper’s or its parent entity’s affairs, with said order or decree continuing unstayed and in effect for a period of sixty (60) consecutive days. Notwithstanding anything herein to the contrary, if Shipper is or has become insolvent, Gatherer shall not suspend service in a manner that is inconsistent with the Federal Bankruptcy Code.

     Section 15.5 Payment Disputes. In the event Shipper disputes any payment hereunder, Shipper shall make timely payment of all undisputed amounts and Shipper and Gatherer will use good-faith efforts to resolve the disputed amounts within sixty (60) Days following the original due date. Any amounts subsequently resolved shall be due and payable within ten (10) Days of such resolution.

39

     Section 15.6 Interest on Late Payments. In the event Shipper shall fail to make timely payment of any sums, except those in a good-faith dispute, when due under this Agreement, interest will accrue at an annual rate equal to the lower of the prime rate as published in the “Money Rates” section of The Wall Street Journal plus two percent (2%) and the maximum lawful rate of interest from the date payment is due until the date payment is made.

ARTICLE 16
FORCE MAJEURE

     Section 16.1 Suspension of Obligations. In the event a Party is rendered unable, wholly or in part, by Force Majeure to carry out its obligations under this Agreement, other than the obligation to indemnify and make payments then or thereafter due hereunder, and such Party promptly gives notice and full particulars of such Force Majeure in writing to the other Party promptly after the occurrence of the cause relied on, then the obligations of the Party giving such notice, so far as and to the extent they are affected by such Force Majeure, shall be suspended during the continuance of any inability so caused, but for no longer period, and such cause shall so far as possible be remedied with all reasonable dispatch by the Party claiming Force Majeure. A Force Majeure event affecting the performance by either Party shall not relieve it of liability in the event of its negligence, where such negligence was a cause of the Force Majeure event, or in the event of its failure to use commercially reasonable efforts to remedy the situation and remove the cause with all reasonable dispatch.

     Section 16.2 Definition of Force Majeure. The term “Force Majeure” as used in this Agreement shall mean any cause or causes not reasonably within the control of the Party claiming suspension and which, by the exercise of reasonable diligence, such Party is unable to prevent or overcome, including, without limitation, acts of God, acts, omissions to act, and/or delays in action of federal, state, or local government or any agency thereof, strikes, lockouts, work stoppages, or other industrial disturbances, acts of a public enemy, sabotage, wars, blockades, insurrections, riots, acts of terror, epidemics, landslides, lightning, earthquakes, fires, storms, storm warnings, floods, washouts, extreme cold or freezing weather, arrests and restraints of governments and people, civil or criminal disturbances, interruptions by governmental or court orders, present and future valid orders of any regulatory body having jurisdiction, explosions, mechanical failures, breakage, or accident to equipment installations, machinery, compressors, or lines of pipe, and associated repairs, freezing of wells or lines of pipe, partial or entire failure of wells, pipes, facilities, or equipment, electric power unavailability or shortages, failure of pipelines or carriers to transport, partial or entire failure or refusal of operators of upstream or downstream pipelines or facilities to receive Gas, governmental regulations, and inability to obtain or timely obtain, or obtain at a reasonable cost, after exercise of reasonable diligence, pipe, materials, equipment, rights-of-way, servitudes, governmental approvals, or labor, including those necessary for the facilities provided for in this Agreement. It is understood and agreed that the settlement of strikes or lockouts shall be entirely within the discretion of the Party having the difficulty, and that the above requirement that any Force Majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes or lockouts by acceding to the demands of the opposing party when such course is inadvisable in the sole discretion of the Party having the difficulty.

40

     Section 16.3 Non-Gatherer Force Majeure Events. Notwithstanding anything herein to the contrary, the following events shall constitute Non-Gatherer Force Majeure Events:

     (a) the termination or failure of the Surface Use Agreement for any reason other than an act or omission of Gatherer; and

     (b) any failure of the Century Plant or any other CO2 plant to accept Shipper’s Gas for any reason other than the failure of Gatherer to perform its obligations hereunder.

ARTICLE 17
INDEMNIFICATION

     Section 17.1 Gatherer. Subject to the terms of this Agreement, including, without limitation, Section 21.10 of this Agreement, Gatherer shall indemnify, defend, and hold harmless the Shipper Indemnified Parties from and against all Claims and Losses arising out of or relating to (i) the operations conducted hereunder or in connection herewith by Gatherer to the extent resulting from the negligence, gross negligence, or willful misconduct of Gatherer, except to the extent such Claims or Losses are attributable to the negligence, gross negligence, or willful misconduct of any of the Shipper Indemnified Parties, (ii) any breach of this Agreement by Gatherer, and (iii) a breach by Gatherer under this Agreement that results in the non-performance by Gatherer of substantially all of its obligations thereunder, including a rejection of this Agreement under any bankruptcy case or similar proceeding under any applicable federal, state or other law. To secure the obligation of Gatherer to pay under and perform the indemnity provided in Section 17.1(iii) (the “Gatherer Secured Obligations”), Gatherer (i) grants, bargains, sells, assigns, mortgages, transfers, and conveys unto Richard Gognat, as trustee for the benefit of the Shipper Indemnified Persons (the “Shipper Trustee”), the Assets (as defined in the Gathering Agreement) and all proceeds, products, renewals, increases, profits, substitutions, replacements, additions, amendments, appurtenances and accessions of the Assets (the “Shipper Collateral”), to have and to hold the Shipper Collateral unto the Shipper Trustee and his successors or substitutes in this trust forever, and (ii) grants to Shipper, for the benefit of the Shipper Indemnified Persons, a security interest in all of Gatherer’s right, title and interest, now existing or hereafter arising, in the Shipper Collateral. Upon the failure of Gatherer to timely pay or perform any Gatherer Secured Obligation, the Shipper Trustee shall have the right and power to sell, as the Shipper Trustee may elect, all or a portion of the Shipper Collateral at one or more sales, as an entirety or in parcels, in accordance with Section 51.002 of the Texas Property Code. Gatherer hereby designates as Gatherer’s address for the purpose of notice the address set forth in Article 14. Any purchaser or purchasers will be provided with a general warranty conveyance binding Gatherer and Gatherer’s successors and assigns. Sale of part of the Shipper Collateral will not exhaust the power of sale, and sales may be made from time to time until all of the Shipper Collateral is sold or all of the obligations under the indemnity provided in Section 17.1(iii) are paid in full. The Shipper Trustee will have the authority to appoint an attorney-in-fact to act as trustee in conducting the foreclosure sale and executing a deed to the purchaser or purchasers. The Shipper Trustee may resign in writing addressed to Shipper or be removed at any time with or without cause by an instrument in writing duly executed by Shipper. In case of the death, resignation or removal of the Shipper Trustee, a successor trustee may be appointed by Shipper

41

by instrument of substitution complying with any applicable requirements of law, and in the absence of any requirement, without formality other than an appointment and designation in writing. The appointment and designation will vest in the named successor trustee all the estate and title of the Shipper Trustee in all of the Shipper Collateral and all of the rights, powers, privileges, immunities and duties hereby conferred upon the Shipper Trustee. All references herein to the Shipper Trustee will be deemed to refer to any successor trustee from time to time acting hereunder. Notwithstanding anything herein to the contrary, upon the occurrence of a Termination Event, the lien and security interest described in this Section 17.1 shall be deemed to be released, terminated and void without further action by either Party.

     Section 17.2 Shipper. Subject to the terms of this Agreement, including, without limitation, Section 21.10 of this Agreement, Shipper shall indemnify, defend, and hold harmless the Gatherer Indemnified Parties from and against all Claims and Losses arising out of or relating to (i) the operations conducted hereunder or in connection herewith by Shipper to the extent resulting from the negligence, gross negligence, or willful misconduct of Shipper, except to the extent such Claims or Losses are attributable to the negligence, gross negligence, or willful misconduct of any of the Gatherer Indemnified Parties, (ii) any breach of this Agreement by Shipper, and (iii) the provision of Services in accordance with this Agreement if the provision of such Services is not permitted under applicable law.

ARTICLE 18
CUSTODY AND TITLE

     Section 18.1 Shipper Custody. As among the Parties, Shipper and any of its designees shall be in custody, control, and possession of (i) Shipper’s Gas hereunder until Shipper’s Gas is delivered to the Receipt Points and (ii) the Delivery Point Gas after it is delivered to Shipper at the Delivery Points.

     Section 18.2 Gatherer Custody. As among the Parties, Gatherer shall be in custody, control, and possession of Shipper’s Gas delivered hereunder, including any portion thereof which accumulates as liquids, after Shipper’s Gas is delivered at the Receipt Points and until the Delivery Point Gas is delivered to Shipper at the Delivery Points.

     Section 18.3 Shipper Warranty. Shipper represents and warrants that it (i) has the right to dedicate all Dedicated Gas and (ii) owns, or has the right to deliver, Shipper’s Gas to the Receipt Points for the purposes of this Agreement, free and clear of all liens, encumbrances, and adverse claims. If the title to Shipper’s Gas delivered hereunder is disputed or is involved in any legal action, Gatherer shall have the right to withhold payment (without interest), or cease receiving such Gas, to the extent of the interest disputed or involved in legal action, during the pendency of the action or until title is freed from the dispute or until Shipper furnishes, or causes to be furnished, indemnification to save Gatherer harmless from all Losses arising out of the dispute or action, with surety reasonably acceptable to Gatherer. Subject to Section 21.10, Shipper agrees to indemnify and hold harmless the Gatherer Indemnified Parties from and against all Claims or Losses suffered by the Gatherer Indemnified Parties, where such Claims or Losses arise, directly or indirectly, out of, or are related to, any breach of the foregoing representation and warranty.

42

     Section 18.4 Title. Title to Shipper’s Gas delivered under this Agreement, including all constituents thereof, shall remain with and in Shipper or its designee at all times; provided, however, (i) title to Condensate shall pass from Shipper to Gatherer immediately downstream of the Receipt Points and (ii) title to FL&U shall pass from Shipper to Gatherer immediately downstream of the Receipt Points.

     Section 18.5 Carbon Dioxide. Shipper shall retain title to all CO2 contained in Shipper’s Gas tendered by Shipper under this Agreement.

ARTICLE 19
ROYALTY AND TAXES

     Section 19.1 Proceeds of Production. Shipper shall have the sole and exclusive obligation and liability for the payment of all Persons due any proceeds derived by Shipper from Shipper’s Gas (including all constituents and products thereof) delivered under this Agreement, including, without limitation, royalties, overriding royalties, and similar interests, in accordance with the provisions of the leases or agreements creating those rights to such proceeds.

     Section 19.2 Production Taxes. Shipper shall pay and be responsible for all Production Taxes levied against or with respect to Shipper’s Gas delivered or Services provided under this Agreement. Gatherer shall not become liable for such Production Taxes, unless designated to remit those Production Taxes on behalf of Shipper by any duly constituted jurisdictional agency having authority to impose such obligations on Gatherer, in which event the amount of such Taxes remitted on Shipper’s behalf shall be (i) reimbursed by Shipper upon receipt of invoice, with corresponding documentation from Gatherer setting forth such payments, or (ii) deducted from amounts otherwise due Shipper under this Agreement.

     Section 19.3 Indemnification. Shipper hereby agrees to defend and indemnify and hold Gatherer harmless from and against any and all Claims and Losses, arising from the payments made by Shipper in accordance with Section 19.1 and Section 19.2, above, including, without limitation, Claims and Losses arising from claims for the nonpayment, mispayment, or wrongful calculation of those payments.

ARTICLE 20
DISPUTE RESOLUTION

     Section 20.1 Negotiation. Prior to submitting any dispute for resolution by a court, a Party shall provide written notice to the other of the occurrence of such dispute. If the Parties have failed to resolve the dispute within fifteen (15) Business Days after such notice was given, the Parties shall seek to resolve the dispute by negotiation between senior management personnel of each Party. Such personnel shall endeavor to meet and attempt to amicably resolve the dispute. If the Parties are unable to resolve the dispute for any reason within thirty (30) Business Days after the original notice of dispute was given, then either Party shall be entitled to pursue any remedies available at law or in equity; provided, however, this Section 20.1 shall not limit a Party’s right to initiate litigation prior to the expiration of the time periods set forth in this Section 20.1 if application of such limitations would prevent a Party from filing

43

a lawsuit or claim within the applicable period for filing lawsuits (e.g. statutes of limitation, prescription, etc.).

     Section 20.2 Jurisdiction and Venue.

     (a) Each Party agrees that the appropriate, exclusive and convenient forum for any disputes between any of the Parties arising out of this Agreement or the transactions contemplated hereby shall be in any state or federal court in Houston or Dallas, Texas, and each of the Parties irrevocably submits to the jurisdiction of such courts solely in respect of any legal proceeding arising out of or related to this Agreement or the transactions contemplated hereby. The Parties further agree that the Parties shall not bring suit with respect to any disputes arising out of this Agreement or the transactions contemplated hereby in any court or jurisdiction other than the above specified courts.

     (b) Each Party hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby in any court referred to in paragraph (a) above. Each of the Parties hereby irrevocably waives, to the fullest extent permitted by applicable law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

     Section 20.3 Jury Waiver. THE PARTIES HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE, TO THE FULLEST EXTENT THEY MAY LEGALLY AND EFFECTIVELY DO SO, THE RIGHT TO A JURY IN ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

     Section 20.4 Costs and Expenses. The prevailing Party in any litigation pertaining to any dispute hereunder shall be entitled to recover its reasonable costs, expenses, and attorney’s fees in connection with such litigation.

ARTICLE 21
MISCELLANEOUS

     Section 21.1 Rights. The failure of either Party to exercise any right granted hereunder shall not impair nor be deemed a waiver of that Party’s privilege of exercising that right at any subsequent time or times.

     Section 21.2 Applicable Laws. This Agreement is subject to all valid present and future laws, regulations, rules, and orders of Governmental Authorities now or hereafter having jurisdiction over the Parties, this Agreement, or the Services performed or the facilities utilized under this Agreement.

     Section 21.3 Governing Law. This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Texas, without regard to choice of law principles that would require the application of the laws of any other jurisdiction.

44

     Section 21.4 Assignments.

     (a) Shipper shall not make any assignment of all or any part of this Agreement or any of the rights or obligations hereunder unless there first shall have been obtained the written consent thereto of Gatherer, which consent shall not be unreasonably withheld, conditioned, or delayed. In connection with any proposed assignment, Shipper shall deliver to Gatherer a written proposal detailing (i) the manner in which Shipper proposes to allocate the Base Volumes and any balance then existing in the Monthly Excess Bank between Shipper and the prospective assignee and (ii) a proposed crediting mechanism for adding Monthly Excess Volumes to the Monthly Excess Bank. In the event Gatherer consents to the proposed assignment and the proposed allocation of the Base Volumes and any balance then existing in the Monthly Excess Bank, (i) the Parties shall sign an amendment to this Agreement that adjusts the Base Volumes and the balance of the Monthly Excess Bank, and (ii) Gatherer and the permitted assignee shall enter into a separate gathering agreement in a form substantially similar to this Agreement (rather than having a portion of this Agreement assigned to such permitted assignee) with the effective date of such gathering agreement being the date of execution thereof. Any permitted assignee of Shipper that executes a separate gathering agreement described in (ii) above shall not be subject to this Agreement.

     (b) Prior to the occurrence of a Termination Event, Gatherer shall neither (i) convey all or any part of the Gathering System nor assign all or any part of this Agreement to any Person (or an Affiliate or relative of such Person) that owns, or has a leasehold interest in, surface or minerals located within the Dedicated Area as of the Effective Date, or (ii) enter into any other transaction pursuant to which control over all or any part of the Gathering System is transferred to any Person (or an Affiliate or relative of such Person) that owns, or has a leasehold interest in, surface or minerals located within the Dedicated Area as of the Effective Date.

     (c) Subject to the other subsections of this Section 21.4, this Agreement shall be binding upon and inure to the benefit of the successors and assigns of the Parties, and shall be binding upon any purchaser of the Gathering System and upon any purchaser of Shipper’s Interests in the Dedicated Area or of Shipper’s Interests in the Non-Dedicated Area Connected Wells. Any assignment or sublease by Shipper of any of Shipper’s Interests in the Dedicated Area, or of Shipper’s Interests in the Non-Dedicated Area Connected Wells shall be completed in accordance with the obligations set forth in this Section 21.4 and Section 2.3 of this Agreement. Any assignment or sublease by Gatherer of any of interest in the Gathering System shall be completed in accordance with the obligations set forth in Section 2.3 of this Agreement. Any attempted assignment of this Agreement in violation of this Section 21.4 shall be null and void.

     (d) Gatherer shall maintain uniformity of interest across the entire Gathering System such that any Person that owns an interest in the Gathering System has a uniform interest across the entire Gathering System. In furtherance thereof, any assignment by Gatherer of any interest in the Gathering System must include a uniform undivided interest in the entire Gathering System.

45

     (e) Upon the assignment by Shipper of any interest in this Agreement, any of Shipper’s Interests in the Dedicated Area or any of Shipper’s Interests in the Non-Dedicated Area Connected Wells, Shipper (but not its assignee) shall be released from liability hereunder for obligations, accruing hereunder after the effective date of such assignment, with respect to the interests assigned, except for the obligation to make Monthly Shortfall Payments hereunder. Upon the assignment by Gatherer of all of its rights and obligations hereunder, Gatherer (but not its assignee) shall be released from liability hereunder for obligations accruing hereunder after the effective date of such assignment. Upon the assignment by Gatherer of less than all of its rights and obligations hereunder, Gatherer shall not be released from any liability hereunder.

       Section 21.5 Set-off.

     (a) All payments required to be made hereunder by Shipper shall be (i) absolute and unconditional, (ii) calculated without reference to any netting, set-off, counterclaim or other right which Shipper may have against Gatherer, including, without limitation, any right to set-off against any amounts owed by Gatherer under this Agreement or any other Transaction Document, and (iii) made free and clear of and without any deduction for or on account of any such netting, set-off or counterclaim.

     (b) Gatherer is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to net, set-off and apply any payments owing to Gatherer against any and all of the obligations of Shipper under this Agreement or any other Transaction Document. Gatherer agrees to promptly notify Shipper after any such netting, set-off or application is made; provided that the failure to give such notice shall not affect the validity of such netting, set-off or application.

     Section 21.6 Published Indices. Unless expressly provided otherwise herein, in the event any published price index referred to in this Agreement fails (whether due to market disruption events or otherwise) or ceases to publish the applicable prices, rates or other information referred to in this Agreement, changes the heading or format under which such information is published, changes the source of information which it publishes under such heading or format, or ceases publication altogether, then (i) Gatherer and Shipper shall for thirty (30) Days thereafter diligently attempt to designate a mutually acceptable comparable alternative source for the same or equivalent information, whereupon the Parties will thereafter use such designated alternative source, and (ii) if no such mutually acceptable comparable alternative source is agreed upon within such thirty (30) Days, Gatherer will designate a comparable and reasonable alternative source for the same or equivalent information, whereupon the Parties will thereafter use such designated alternative source.

     Section 21.7 Exhibits. The following Exhibits are attached to this Agreement and are incorporated herein by this reference:

Exhibit A — Map of Dedicated Area
Exhibit B — Dedicated Area Description
Exhibit C — Base Volumes
Exhibit D — Wellhead Meters

46

Exhibit E — Delivery Points
Exhibit F — Sub-Systems
Exhibit G — Trigger Event Example
Exhibit H — Gas Quality Specifications
Exhibit I — Monthly Average Receipt Point Pressure Example
Exhibit J — Gathering System
Exhibit K — Monthly Excess Bank Example
Exhibit L — Memorandum of Gas Gathering Agreement

     Section 21.8 Entire Agreement, Amendments. This Agreement, including, without limitation, all exhibits hereto, and the other Transaction Documents integrate the entire understanding between the Parties with respect to the subject matter covered and supersede all prior understandings, drafts, discussions, or statements, whether oral or in writing, expressed or implied, dealing with the same subject matter. This Agreement may not be amended or modified in any manner except by a written document signed by the Parties that expressly amends this Agreement.

     Section 21.9 Waivers. No waiver by either Party of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless expressly provided. No waiver shall be effective unless made in writing and signed by the Party to be charged with such waiver.

     Section 21.10 Limitation of Liability. NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY, NEITHER PARTY SHALL BE LIABLE TO THE OTHER PARTY FOR SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, OR EXEMPLARY DAMAGES SUFFERED BY SUCH PARTY RESULTING FROM OR ARISING OUT OF THIS AGREEMENT OR THE BREACH THEREOF OR UNDER ANY OTHER THEORY OF LIABILITY, WHETHER TORT, NEGLIGENCE, STRICT LIABILITY, BREACH OF CONTRACT, WARRANTY, INDEMNITY, OR OTHERWISE, INCLUDING, WITHOUT LIMITATION, LOSS OF USE, INCREASED COST OF OPERATIONS, LOSS OF PROFIT OR REVENUE, OR BUSINESS INTERRUPTIONS; PROVIDED, HOWEVER, FOR THE AVOIDANCE OF DOUBT, LOST PRODUCTION, DELAYED PRODUCTION OF HYDROCARBONS AND LOST OPPORTUNITY TO RECEIVE GATHERING FEES AND COMMODITY FEES THROUGHOUT THE TERM SHALL BE CONSIDERED A DIRECT DAMAGE. IN FURTHERANCE OF THE FOREGOING, EACH PARTY RELEASES THE OTHER PARTY AND WAIVES ANY RIGHT OF RECOVERY FOR SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, OR EXEMPLARY DAMAGES SUFFERED BY SUCH PARTY REGARDLESS OF WHETHER ANY SUCH DAMAGES ARE CAUSED BY THE OTHER PARTY’S NEGLIGENCE (AND REGARDLESS OF WHETHER SUCH NEGLIGENCE IS SOLE, JOINT, CONCURRENT, ACTIVE, PASSIVE, OR GROSS NEGLIGENCE), FAULT, OR LIABILITY WITHOUT FAULT; PROVIDED, HOWEVER, THE FOREGOING SHALL NOT BE CONSTRUED AS LIMITING AN OBLIGATION OF A PARTY HEREUNDER TO INDEMNIFY, DEFEND, AND HOLD HARMLESS THE OTHER PARTY AGAINST CLAIMS ASSERTED BY UNAFFILIATED THIRD PARTIES, INCLUDING, BUT NOT LIMITED TO, THIRD-

47

PARTY CLAIMS FOR SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, OR EXEMPLARY DAMAGES.

     Section 21.11 Headings. The headings and captions in this Agreement have been inserted for convenience of reference only and shall not define or limit any of the terms and provisions hereof.

     Section 21.12 Rights and Remedies. Except as otherwise provided in this Agreement, each Party reserves to itself all rights, counterclaims, other remedies, and defenses to which such Party is or may be entitled arising from or out of this Agreement or as otherwise provided by law.

     Section 21.13 No Partnership. Nothing contained in this Agreement shall be construed to create an association, trust, partnership, or joint venture or impose a trust, fiduciary, or partnership duty, obligation, or liability on or with regard to either Party.

     Section 21.14 Rules of Construction. In construing this Agreement, the following principles shall be followed:

     (a) no consideration shall be given to the fact or presumption that one Party had a greater or lesser hand in drafting this Agreement;

     (b) examples shall not be construed to limit, expressly or by implication, the matter they illustrate;

     (c) the word “includes” and its syntactical variants mean “includes, but is not limited to” and corresponding syntactical variant expressions; and

     (d) the plural shall be deemed to include the singular and vice versa, as applicable.

     Section 21.15 No Third Party Beneficiaries. Except for parties indemnified hereunder, this Agreement is for the sole benefit of the Parties and their respective successors and permitted assigns, and shall not inure to the benefit of any other Person whomsoever or whatsoever, it being the intention of the Parties that no third Person shall be deemed a third-party beneficiary of this Agreement.

     Section 21.16 Further Assurances. Each Party shall take such acts and execute and deliver such documents as may be reasonably required to effectuate the purposes of this Agreement.

     Section 21.17 No Inducements. No director, employee, or agent of any Party shall give or receive any commission, fee, rebate, gift, or entertainment of significant cost or value in connection with this Agreement.

     Section 21.18 Counterpart Execution. This Agreement may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument.

48

     IN WITNESS WHEREOF, the Parties have executed this Agreement to be effective on the date first set forth above.

GATHERER: PIÑON GATHERING COMPANY, LLC
By:	TCW Asset Management Company, its Manager:
By:	/s/ Clayton R. Taylor
	Clayton R. Taylor
	Vice President
By:	/s/ Kurt A. Talbot
	Kurt A. Talbot
	Managing Director
SHIPPER: SANDRIDGE EXPLORATION AND PRODUCTION, LLC
By:	/s/ Richard J. Gognat
	Richard J. Gognat
	Senior Vice President

49

EXHIBIT A

DEDICATED AREA

EXHIBIT A — Page 1

EXHIBIT B

DEDICATED AREA

SECTION		BLK		SURVEY	RRD		COUNTY	STATE	Approx. Acres
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	29		138	T&STL RR CO		8	Pecos	Texas		627.07
	33		138	T&STL RR CO		8	Pecos	Texas		660.31
	12		108	EL&RR RR CO		8	Pecos	Texas		320.98
	26		2	TC RR CO		8	Pecos	Texas		648.81
	41		2	TC RR CO		8	Pecos	Texas		637.43
	42		2	TC RR CO		8	Pecos	Texas		634.06
	43		2	TC RR CO		8	Pecos	Texas		647.15
	44		2	TC RR CO		8	Pecos	Texas		644.17
	48		2	TC RR CO		8	Pecos	Texas		644.84
	20		138	T&STL RR CO		8	Pecos	Texas		642.87
	22		138	T&STL RR CO		8	Pecos	Texas		646.55
	23		138	T&STL RR CO		8	Pecos	Texas		648.90
	27		138	T&STL RR CO		8	Pecos	Texas		625.40
	28		138	T&STL RR CO		8	Pecos	Texas		629.63
	30		138	T&STL RR CO		8	Pecos	Texas		631.48
	31		138	T&STL RR CO		8	Pecos	Texas		655.78
	32		138	T&STL RR CO		8	Pecos	Texas		656.45
	34		138	T&STL RR CO		8	Pecos	Texas		660.82
	35		138	T&STL RR CO		8	Pecos	Texas		663.67
	19		2	TC RR CO		8	Pecos	Texas		654.46
	20		2	TC RR CO		8	Pecos	Texas		658.82
	22		2	TC RR CO		8	Pecos	Texas		650.57
	23		2	TC RR CO		8	Pecos	Texas		638.27
	45		2	TC RR CO		8	Pecos	Texas		639.36
	46		2	TC RR CO		8	Pecos	Texas		643.62
	47		2	TC RR CO		8	Pecos	Texas		641.39
	50		2	TC RR CO		8	Pecos	Texas		634.19
	51		2	TC RR CO		8	Pecos	Texas		635.03
	24		2	TC RR CO		8	Pecos	Texas		637.71
	25		2	TC RR CO		8	Pecos	Texas		650.96
	27		2	TC RR CO		8	Pecos	Texas		650.08
	28		2	TC RR CO		8	Pecos	Texas		648.97
	29		2	TC RR CO		8	Pecos	Texas		643.17
	7		600	JM HOLBROOK		8	Pecos	Texas		1,172.48
	6		600	ELIJAH ROBERTS		8	Pecos	Texas		1,179.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	5		600	FRANCISCO PINA		8	Pecos	Texas		1,184.01
	19		138	T&STL RR CO		8	Pecos	Texas		644.55
	71		2	TC RR CO		8	Pecos	Texas		640.77
	1		159	GH&SA RR CO		8	Pecos	Texas		638.19
	3		159	GH&SA RR CO		8	Pecos	Texas		640.26
	4		159	GH&SA RR CO		8	Pecos	Texas		673.67
	18		2	H&TC RR CO		8	Pecos	Texas		1,296.48
	2		168	MRS J P MULLINS		8	Pecos	Texas		1,263.35
	2		4	H&TC RR CO		8	Pecos	Texas		302.08
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	21		2	TC RR CO		8	Pecos	Texas		650.55
	21		138	T&STL RR CO		8	Pecos	Texas		649.84

EXHIBIT B - Page 1

EXHIBIT B

DEDICATED AREA

SECTION		BLK		SURVEY	RRD		COUNTY	STATE	Approx. Acres
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	25		138	T&STL RR CO		8	Pecos	Texas		627.96
	4		110	D&SE RR CO		8	Pecos	Texas		300.93
	11		108	EL&RR RR CO		8	Pecos	Texas		316.91
	12		108	EL&RR RR CO		8	Pecos	Texas		320.98
	8		110A	BS&F		8	Pecos	Texas		641.42
	52		2	TC RR CO		8	Pecos	Texas		646.05
	56		2	TC RR CO		8	Pecos	Texas		643.10
	67		2	TC RR CO		8	Pecos	Texas		631.09
	70		2	TC RR CO		8	Pecos	Texas		646.89
	4		600	J N SIMS		8	Pecos	Texas		1,257.16
	2		600	JA DECKIE		8	Pecos	Texas		1,214.05
	2		600	JA DECKIE		8	Pecos	Texas		1,214.05
	22		138	T&STL RR CO		8	Pecos	Texas		646.55
	22		138	T&STL RR CO		8	Pecos	Texas		646.55
	24		138	T&STL RR CO		8	Pecos	Texas		648.66
	26		138	T&STL RR CO		8	Pecos	Texas		623.91
	27		138	T&STL RR CO		8	Pecos	Texas		625.40
	27		138	T&STL RR CO		8	Pecos	Texas		625.40
	19		139	T&STL RR CO		8	Pecos	Texas		650.61
	30		139	T&STL RR CO		8	Pecos	Texas		634.38
	31		139	T&STL RR CO		8	Pecos	Texas		666.78
	39		2	TC RR CO		8	Pecos	Texas		642.43
	40		2	TC RR CO		8	Pecos	Texas		631.14
	46		2	TC RR CO		8	Pecos	Texas		643.62
	46		2	TC RR CO		8	Pecos	Texas		643.62
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	53		2	TC RR CO		8	Pecos	Texas		646.29
	24		2	TC RR CO		8	Pecos	Texas		637.71
	24		2	TC RR CO		8	Pecos	Texas		637.71
	24		2	TC RR CO		8	Pecos	Texas		637.71
	24		2	TC RR CO		8	Pecos	Texas		637.71
	28		2	TC RR CO		8	Pecos	Texas		648.97

EXHIBITS - Page 2

EXHIBIT B

DEDICATED AREA

SECTION		BLK		SURVEY	RRD		COUNTY	STATE	Approx. Acres
	28		2	TC RR CO		8	Pecos	Texas		648.97
	28		2	TC RR CO		8	Pecos	Texas		648.97
	29		2	TC RR CO		8	Pecos	Texas		643.17
	29		2	TC RR CO		8	Pecos	Texas		643.17
	29		2	TC RR CO		8	Pecos	Texas		643.17
	29		2	TC RR CO		8	Pecos	Texas		643.17
	6		600	ELIJAH ROBERTS		8	Pecos	Texas		1,179.18
	6		600	ELIJAH ROBERTS		8	Pecos	Texas		1,179.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	1		182	TC RR CO		8	Pecos	Texas		603.11
	36		138	T&STL RR CO		8	Pecos	Texas		664.64
	36		138	T&STL RR CO		8	Pecos	Texas		664.64
	54		2	TC RR CO		8	Pecos	Texas		637.41
	55		2	TC RR CO		8	Pecos	Texas		632.55
	57		2	TC RR CO		8	Pecos	Texas		638.58
	65		2	TC RR CO		8	Pecos	Texas		635.79
	66		2	TC RR CO		8	Pecos	Texas		644.73
	68		2	TC RR CO		8	Pecos	Texas		642.36
	69		2	TC RR CO		8	Pecos	Texas		648.55
	71		2	TC RR CO		8	Pecos	Texas		640.77
	71		2	TC RR CO		8	Pecos	Texas		640.77
	1		159	GH&SA RR CO		8	Pecos	Texas		638.19
	1		159	GH&SA RR CO		8	Pecos	Texas		638.19
	3		159	GH&SA RR CO		8	Pecos	Texas		640.26
	3		159	GH&SA RR CO		8	Pecos	Texas		640.26
	4		159	GH&SA RR CO		8	Pecos	Texas		673.67
	4		159	GH&SA RR CO		8	Pecos	Texas		673.67
	4		159	GH&SA RR CO		8	Pecos	Texas		673.67
	3		600	H C KINGSTON		8	Pecos	Texas		1,204.08
	10		110A	BS&F		8	Pecos	Texas		652.51
	7		110A	BS&F		8	Pecos	Texas		646.72
	9		110A	BS&F		8	Pecos	Texas		638.47
	18		2	H&TC RR CO		8	Pecos	Texas		1,296.48
	18		2	H&TC RR CO		8	Pecos	Texas		1,296.48
	18		2	H&TC RR CO		8	Pecos	Texas		1,296.48
	18		2	H&TC RR CO		8	Pecos	Texas		1,296.48
	1		4	H&TC RR CO		8	Pecos	Texas		300.79
	1		4	H&TC RR CO		8	Pecos	Texas		300.79
	2		4	H&TC RR CO		8	Pecos	Texas		302.08
	2		4	H&TC RR CO		8	Pecos	Texas		302.08
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	5		4	H&TC RR CO		8	Pecos	Texas		317.38

EXHIBIT B - Page 3

EXHIBIT B

DEDICATED AREA

SECTION		BLK		SURVEY	RRD		COUNTY	STATE	Approx. Acres
	5		4	H&TC RR CO		8	Pecos	Texas		317.38
	6		4	H&TC RR CO		8	Pecos	Texas		316.50
	6		4	H&TC RR CO		8	Pecos	Texas		316.50
	6		4	H&TC RR CO		8	Pecos	Texas		316.50
	6		4	H&TC RR CO		8	Pecos	Texas		316.50
	2		108	HANNAH DONAHUE ALIAS ALEXANDER		8	Pecos	Texas		1,133.75
	6		2	H&TC RR CO		8	Pecos	Texas		648.09
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	7		2	H&TC RR CO		8	Pecos	Texas		1,298.18
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	4		4	H&TC RR CO		8	Pecos	Texas		317.69
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	9		600	MA CLAY		8	Pecos	Texas		1,178.00
	4		110	D&SE RR CO		8	Pecos	Texas		300.93
	4		110	D&SE RR CO		8	Pecos	Texas		300.93
	22		138	T&STL RR CO		8	Pecos	Texas		646.55
	22		138	T&STL RR CO		8	Pecos	Texas		646.55
	27		138	T&STL RR CO		8	Pecos	Texas		625.40
	27		138	T&STL RR CO		8	Pecos	Texas		625.40
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	51		2	TC RR CO		8	Pecos	Texas		635.03
	24		2	TC RR CO		8	Pecos	Texas		637.71
	24		2	TC RR CO		8	Pecos	Texas		637.71
	28		2	TC RR CO		8	Pecos	Texas		648.97
	28		2	TC RR CO		8	Pecos	Texas		648.97
	28		2	TC RR CO		8	Pecos	Texas		648.97
	28		2	TC RR CO		8	Pecos	Texas		648.97
	28		2	TC RR CO		8	Pecos	Texas		648.97
	28		2	TC RR CO		8	Pecos	Texas		648.97
	28		2	TC RR CO		8	Pecos	Texas		648.97
	28		2	TC RR CO		8	Pecos	Texas		648.97

EXHIBIT B - Page 4

EXHIBIT B

DEDICATED AREA

SECTION		BLK		SURVEY	RRD		COUNTY	STATE	Approx. Acres
	29		2	TC RR CO		8	Pecos	Texas		643.17
	29		2	TC RR CO		8	Pecos	Texas		643.17
	29		2	TC RR CO		8	Pecos	Texas		643.17
	29		2	TC RR CO		8	Pecos	Texas		643.17
	29		2	TC RR CO		8	Pecos	Texas		643.17
	29		2	TC RR CO		8	Pecos	Texas		643.17
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	8		600	SS STUBBLEFIELD		8	Pecos	Texas		1,167.18
	71		2	TC RR CO		8	Pecos	Texas		640.77
	71		2	TC RR CO		8	Pecos	Texas		640.77
	1		159	GH&SA RR CO		8	Pecos	Texas		638.19
	1		159	GH&SA RR CO		8	Pecos	Texas		638.19
	3		159	GH&SA RR CO		8	Pecos	Texas		640.26
	3		159	GH&SA RR CO		8	Pecos	Texas		640.26
	18		2	H&TC RR CO		8	Pecos	Texas		1,296.48
	18		2	H&TC RR CO		8	Pecos	Texas		1,296.48
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	3		4	H&TC RR CO		8	Pecos	Texas		304.65
	5		4	H&TC RR CO		8	Pecos	Texas		317.38
	5		4	H&TC RR CO		8	Pecos	Texas		317.38
	6		4	H&TC RR CO		8	Pecos	Texas		316.50
	6		4	H&TC RR CO		8	Pecos	Texas		316.50
	6		4	H&TC RR CO		8	Pecos	Texas		316.50
	6		4	H&TC RR CO		8	Pecos	Texas		316.50

EXHIBIT B - Page 5

EXHIBIT C

BASE VOLUMES

***

EXHIBIT C — Page 1

EX-10.6

Exhibit 10.6

OPERATIONS AND MAINTENANCE AGREEMENT

Between

Piñon Gathering Company, LLC

And

SandRidge Midstream, Inc.

TABLE OF CONTENTS

	PAGE
ARTICLE I DEFINITIONS		1
ARTICLE II ENGAGEMENT OF OPERATOR		6
2.1 Engagement		6
2.2 Independent Contractor		6
2.3 Owner Cooperation		6
ARTICLE III TERM; RESIGNATION OR REMOVAL OF OPERATOR		7
3.1 Term		7
3.2 Owner Default		7
3.3 Operator Default		7
3.4 Cooperation with Owner or Successor Operator		8
3.5 Effect of Termination		8
3.6 No Breach		8
ARTICLE IV DUTIES AS OPERATOR		9
4.1 Duties as Operator		9
4.1.1 Operation and Maintenance of the Gathering System		9
4.1.2 Purchase of Material and Supplies		9
4.1.3 Personnel		9
4.1.4 Payment of Operating Expenses		9
4.1.5 Proposed Operating Expense Budget		10
4.1.6 Capital Projects		10
4.1.7 Emergencies		11
4.1.8 Reporting By Operator		11
4.1.9 Commercial Activities		12
4.1.10 Regulatory Affairs		12
4.1.11 Devotion of Time		12
4.2 Standard of Care		12
4.3 Limitation of Authority		13
4.3.1 Binding Owner		13
4.3.2 Asset Sales		13
4.3.3 Material Alteration of Owner’s Business		13
4.3.4 Debt 13
ARTICLE V COST REIMBURSEMENT		13
5.1 Responsibility for Costs and Expenses		13
5.2 Procedure		13

i

TABLE OF CONTENTS

	PAGE
5.2.1 Invoicing and Payment		13
5.2.2 Disputes		14
5.3 Setoff		14
ARTICLE VI ACCOUNTING; REPORTS; RECORDS		14
6.1 Accounting Methods		14
6.2 Financial Statements		14
6.3 Accounting and Taxation		15
6.3.1 Maintenance of Accounts		15
6.3.2 Preparation of Tax Returns		15
6.3.3 Owner to Supply Information		16
6.4 Banking		16
6.5 Independent Audits		16
6.6 Credit Inquiries		17
ARTICLE VII FORCE MAJEURE		18
7.1 Procedure		18
7.2 Strikes		18
ARTICLE VIII INSURANCE AND INDEMNIFICATION		18
8.1 Operator Insurance		18
8.2 Contractors		19
8.3 Notice of Claims		20
8.4 Mutual Release and Indemnification		20
8.4.1 Owner’s Indemnification		20
8.4.2 Operator’s Indemnification		20
ARTICLE IX GENERAL PROVISIONS		21
9.1 Notices		21
9.2 Rights		21
9.3 Applicable Laws		22
9.4 Rules of Construction		22
9.5 Governing Law		22
9.6 Dispute Resolution		22
9.6.1 Negotiation		22
9.6.2 Jurisdiction and Venue		22
9.6.3 Jury Waiver		23
9.6.4 Costs and Expenses		23
9.7 Limitation of Liability		23

ii

TABLE OF CONTENTS

	PAGE
9.8 Entirety of Agreement, Amendments		23
9.9 Waivers		24
9.10 Exhibits		24
9.11 Headings		24
9.12 Assignment		24
9.13 Rights and Remedies		24
9.14 Counterparts		24
9.15 No Third Party Beneficiary		24
9.16 Further Assurances		25

EXHIBITS:

     EXHIBIT A — DUTIES AND RESPONSIBILITIES OF OPERATOR

     EXHIBIT B — FORM OF MONTHLY OPERATING AND FINANCIAL REPORT

iii

OPERATIONS AND MAINTENANCE AGREEMENT

     This OPERATIONS AND MAINTENANCE AGREEMENT dated June 30, 2009 (the “Effective Date”), is made and entered into by and between Piñon Gathering Company, LLC, a Delaware limited liability company (“Owner”), with offices at 333 Clay Street, Suite 4150, Houston, Texas 77002, and SandRidge Midstream, Inc., a Texas corporation (“Operator”), with offices at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102.

RECITALS

     A. Pursuant to that certain Membership Interest Purchase Agreement between Operator and TCW Pecos Midstream, L.L.C., a Texas limited liability company (“TCW Pecos Midstream”) dated as of even date herewith (the “Membership Interest Purchase Agreement”), TCW Pecos Midstream has purchased from Operator all issued and outstanding membership interests in Owner, which owns the Gathering System (as hereinafter defined).

     B. Owner wishes to retain Operator to maintain and operate the Gathering System and advance the commercial interests of Owner through the negotiation and execution of agreements relative to the commercial offerings provided by Owner, as well as administering the business and regulatory affairs of Owner relating to the Gathering System, all in accordance with the terms and conditions set forth below.

     NOW, THEREFORE, in consideration of the premises and of the mutual covenants and agreements contained herein, Operator and Owner hereby agree as follows:

ARTICLE I
DEFINITIONS

     Except as otherwise defined in this Article I, capitalized terms used in this Agreement shall have the meanings assigned to them in the Gathering Agreement.

     “Adjustment Claims” shall have the meaning set forth in Section 6.5.

     “Affiliate” means, with respect to any Person, any other Person that, directly or indirectly, controls, is controlled by, or is under common control with, such specified Person through one or more intermediaries or otherwise. For the purposes of this definition, “control” means, where used with respect to any Person, 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 interests, by contract or otherwise, and the terms “controlling” and “controlled” have correlative meanings.

     “Agreement” means this Operations and Maintenance Agreement (including all exhibits), as amended from time to time in accordance with the terms hereof.

     “Audit Costs” shall have the meaning set forth in Section 6.5.

     “Business Day” means any calendar day, other than a Saturday or Sunday, on which commercial banks in Dallas, Texas are open for business.

     “Calendar Year” means the time period from January 1 through December 31 of the same calendar year.

     “Capital Project” means any capital expenditure to repair, maintain, construct, expand, or modify the Gathering System.

     “Capital Project Proposal” shall have the meaning set forth in Section 4.1.6.

     “Claim” means any lawsuit, claim, proceeding, investigation, review, audit or other cause of action of any kind.

     “Company Conveyance” means that certain Assignment of Membership Interests dated as of June 30, 2009, between Operator and TCW Pecos Midstream, together with all amendments, modifications or waivers thereto.

     “Confidentiality and Disclosure Agreement” means that certain Confidentiality and Disclosure Agreement dated as of June 30, 2009, between SandRidge Energy, Inc., TCW Asset Management Company, and Piñon Gathering Company, LLC, together with all amendments, modifications or waivers thereto.

     “Constituent of Concern” means any substance defined as a hazardous substance, hazardous waste, hazardous material, toxic substance, solid waste, pollutant or contaminant by an Environmental Law.

     “Dedicated Gas” shall have the meaning ascribed to such term in the Gathering Agreement.

     “Effective Date” shall have the meaning set forth in the preamble to this Agreement.

     “Emergency” means a sudden or unexpected event that causes, or risks causing, imminent material damage to the Gathering System, death or injury to any Person, or material damage to property or the environment.

     “Emergency Work” shall have the meaning set forth in Section 4.1.7.

     “Enterprise Gathering Agreement” means that certain Gas Gathering Agreement dated as of June 26, 2009, between Enterprise Products Operating, LLC and Operator, together with all amendments, modifications or waivers thereto.

     “Environmental Law” means all applicable Laws and Environmental Permits of any Governmental Authority relating to the environment, natural resources, or the protection thereof, including, without limitation: (a) all requirements pertaining to liability for reporting, management, licensing, permitting, investigation, and remediation of emissions, discharges, releases, or threatened releases of a Constituent of Concern; and (b) CERCLA, the Hazardous Materials Transportation Act, 49 U.S.C. § 5101 et seq. the Federal Clean Water Act, the Federal

2

Clean Air Act, the Federal Solid Waste Disposal Act (which includes the Resource Conservation and Recovery Act), the Federal Toxic Substances Control Act, and the Federal Insecticide, Fungicide and Rodenticide Act, the Oil Pollution Act of 1990, 33 U.S.C. § 2701 et seq., and the Safe Drinking Water Act, 42 U.S.C. § 300f et seq. and any applicable Law relating to health, safety, the environment, natural resources or the protection thereof, each as amended from time to time, including any regulations promulgated pursuant thereto, and any state or local counterparts.

     “Environmental Permits” all permits, licenses, registrations, authorizations, certificates and approvals, and any other similar items, of Governmental Authorities required by Environmental Laws and necessary for or held in connection with the ownership and/or operation the Gathering System or any of the transactions contemplated hereby.

     “Force Majeure” means any cause or causes not reasonably within the control of the Party claiming suspension and which, by the exercise of reasonable diligence, such Party is unable to prevent or overcome, including, without limitation, acts of God, acts, omissions to act, and/or delays in action of federal, state, or local government or any agency thereof, strikes, lockouts, work stoppages, or other industrial disturbances, acts of a public enemy, sabotage, wars, blockades, insurrections, riots, acts of terror, epidemics, landslides, lightning, earthquakes, fires, storms, storm warnings, floods, washouts, extreme cold or freezing weather, arrests and restraints of governments and people, civil or criminal disturbances, interruptions by governmental or court orders, present and future valid orders of any regulatory body having jurisdiction, explosions, mechanical failures, breakage, or accident to equipment installations, machinery, compressors, or lines of pipe, and associated repairs, freezing of wells or lines of pipe, partial or entire failure of wells, pipes, facilities, or equipment, electric power unavailability or shortages, failure of pipelines or carriers to transport, partial or entire failure or refusal of operators of upstream or downstream pipelines or facilities to receive gas, governmental regulations, and inability to obtain or timely obtain, or obtain at a reasonable cost, after exercise of reasonable diligence, pipe, materials, equipment, rights-of-way, servitudes, governmental approvals, or labor, including those necessary for the facilities provided for in this Agreement.

     “GAAP” means generally accepted accounting principles, consistently applied.

     “Gathering Agreement” means that certain Gas Gathering Agreement dated as of even date herewith by and between SandRidge Exploration and Production, LLC, as “Shipper,” and Owner, as “Gatherer,” as amended, restated or otherwise modified from time to time.

     “Gathering System” shall have the meaning ascribed to such term in the Gathering Agreement.

     “Governmental Authority” means any federal, state, municipal, local or similar governmental authority, regulatory or administrative agency, court or arbitral body with jurisdiction over the Parties, this Agreement, any of the transactions contemplated hereby or the Gathering System.

     “Guaranty Agreements” means, collectively, that certain (a) Guaranty Agreement dated as of June 30, 2009, by SandRidge Energy, Inc. in favor of TCW Pecos Midstream, (b) Guaranty

3

Agreement dated as of June 30, 2009, by SandRidge Energy, Inc. in favor of Owner, (c) Guaranty Agreement dated as of June 30, 2009, by SandRidge Exploration and Production, LLC in favor of Owner, and (d) Guaranty Agreement dated as of June 30, 2009, by Operator in favor of Owner, in each case, together with all amendments, modifications or waivers thereto.

     “Intercompany Conveyance” means that certain Assignment, Bill of Sale and Conveyance dated as of June 30, 2009, between Operator and Owner, together with all amendments, modifications or waivers thereto.

     “Law” means any statute, writ, law, common law, rule, regulation, ordinance, order, judgment, injunction, award, determination or decree of a Governmental Authority, or any requirement under the common law.

     “LLC Agreement” means that certain Amended and Restated Limited Liability Company Agreement of Piñon Gathering Company, LLC, together with all amendments, modifications or waivers thereto.

     “Liability Claim” means a Claim arising out of the administration, operation, or maintenance of the Gathering System, or arising out of or incidental to the activities carried on or work performed or required by this Agreement.

     “Loss” means any loss, cost, expense, liability, damage, sanction, judgment, lien, fine, or penalty, including reasonable attorney’s and consultant’s fees and expenses, incurred, suffered or paid by, or resulting to, the applicable indemnified Persons on account of (i) injuries (including death) to any Person or damage to or destruction of any property, sustained or alleged to have been sustained in connection with or arising out of the matters for which the indemnifying Party has indemnified the applicable indemnified Persons, (ii) any failure of any representation or warranty made by Operator in this Agreement to be true and correct when made, or (iii) the breach of any covenant or agreement made or to be performed by the indemnifying Party pursuant to this Agreement.

     “Material Overpayment” shall have the meaning set forth in Section 6.5.

     “Membership Interest Purchase Agreement” shall have the meaning set forth in the first recital of this Agreement.

     “Operator” shall have the meaning set forth in the preamble to this Agreement.

     “Operator Change of Control” means the occurrence of an event where upon (i) at least seventy-five percent (75%) of the equity interests in Operator and (ii) at least seventy-five percent (75%) of the monthly volumes of Dedicated Gas projected to be produced during the period extending from the date of calculation to the estimated date of the Trigger Event shall cease to be owned, directly or indirectly, by the same Person.

     “Operator Indemnified Parties” means, collectively, Operator, its successors and permitted assigns, and their respective Affiliates, shareholders, members, partners, officers, directors, employees, and agents.

4

     “Operator Parties” means, collectively, Operator, Operator’s Affiliates, and their respective successors and assigns; “Operator Party” means any such Person individually.

     “Owner” shall have the meaning set forth in the preamble to this Agreement.

     “Owner Indemnified Parties” means, collectively, Owner, its successors and permitted assigns, and their respective Affiliates, shareholders, members, partners, officers, directors, employees, and agents.

     “Owner Operating Expense Account” means the bank account designed by Owner as its operating expense account.

     “Owner Revenue Account” means the bank account designed by Owner as its revenue account.

     “Party” means either Owner or Operator, as applicable, and “Parties” means both Owner and Operator.

     “Person” means an individual, a corporation, a partnership, a limited partnership, a limited liability company, an association, a joint venture, a trust, an unincorporated organization, or any other entity or organization, including a government or political subdivision or an agency or instrumentality thereof.

     “Preventing Factors” shall have the meaning set forth in Section 6.3.1.

     “Proposed Operating Expense Budget” means, with respect to each period, the Proposed Operating Expense Budget established pursuant to the Gathering Agreement for such period.

     “Shipper” shall have the meaning set forth in the Gathering Agreement.

     “Subject Gathering Agreements” means, collectively, the Gathering Agreement, the Enterprise Gathering Agreement and any gathering agreements entered into in accordance with Section 4.1.9.

     “Tax” or “Taxes” means any (i) federal, state, provincial, county, local or foreign taxes, charges, fees, levies or other assessments, including all sales and use, goods and services, ad valorem, transfer, gains, profits, excise, franchise, real and personal property, gross receipt, value added, capital stock, production, business and occupation, disability, employment, payroll, license, estimated, stamp, custom duties, severance, unemployment, social security, Medicare, alternative minimum or withholding taxes or charges imposed by any Governmental Authority, and including any interest and penalties (civil or criminal) on or additions to any such taxes, but expressly excluding any income tax or tax based on income, such as, without limitation, the franchise tax set forth in V.T.C.A. Tax Code Section 171.0001 et. seq., as the same may be amended or recodified from time to time, and (ii) liability for items in (i) of any other Person by contract, operation of Law (including Treasury Regulation 1.1502-6) or otherwise.

5

     “Tax Returns” means any return, report, election, declaration, statement, notice, information return, schedule, or other document (including any related or supporting information) filed or required to be filed with any Governmental Authority in connection with the determination, assessment, collection or administration of any Taxes or any income tax or tax based on income, such as, without limitation, the franchise tax set forth in V.T.C.A. Tax Code Section 171.0001 et. seq., as the same may be amended or recodified from time to time, or the administration of any laws, regulations or administrative requirements relating to any Taxes or any amendment thereof.

     “Transaction Documents” means, collectively, this Agreement, the Gathering Agreement, the Membership Interest Purchase Agreement, the Intercompany Conveyance, the Company Conveyance, the Guaranty Agreements, the Confidentiality and Disclosure Agreement and the LLC Agreement.

     “Trigger Event” shall have the meaning ascribed to such term in the Gathering Agreement.

     “Voting Securities” means, as it relates to a Person, securities of any class of such Person entitling the holders thereof to vote in the election of, or to appoint, members of the board of directors or other similar governing body of the Person; provided that if such Person is a limited partnership, Voting Securities of such Person shall be the general partner interest in such Person.

ARTICLE II
ENGAGEMENT OF OPERATOR

2.1 Engagement.

     Owner hereby appoints and retains Operator to manage, operate, and maintain the Gathering System and to administer the business and regulatory affairs of Owner relating to the Gathering System in accordance with the terms and conditions set forth herein, and Operator hereby accepts such appointment.

2.2 Independent Contractor.

     The Parties expressly understand and agree that Operator is acting and shall perform and execute the provisions of this Agreement as an independent contractor unrelated to Owner or any Owner Affiliate, and the work performed by Operator hereunder shall be subject to Owner’s general right of inspection and approval. Nothing in this Agreement is intended to create a relationship, expressed or implied, of employer-employee or principal-agent between Owner and Operator or between Owner and any individual employed or provided to work hereunder by Operator.

2.3 Owner Cooperation.

     Owner shall cooperate with Operator and provide Operator with such information as Operator may reasonably request from time to time in connection with the performance of Operator’s duties hereunder.

6

ARTICLE III
TERM; RESIGNATION OR REMOVAL OF OPERATOR

3.1 Term.

     This Agreement shall commence on the Effective Date and, unless terminated earlier pursuant to Section 3.2 or 3.3 of this Agreement, shall continue until the twentieth (20^th) anniversary of the Effective Date; provided, however, (i) Operator shall have the right to terminate this Agreement at any time upon no less than 120 days prior written notice to Owner, if Operator provides a substitute operator acceptable to Owner, as determined in its reasonable discretion, who (A) has experience operating similar assets, (B) has the ability to provide at least the same quality of service as Operator, (C) has the financial ability to perform the obligations hereunder, and (D) is ready, willing and able to execute an operation and maintenance agreement substantially similar to this Agreement and acceptable to Owner, as determined in its reasonable discretion, and (ii) Owner shall have the right to terminate this Agreement at any time upon no less than 120 days prior written notice to Operator.

3.2 Owner Default.

     Operator may terminate this Agreement at any time upon the occurrence of any of the following:

(a)	the dissolution or bankruptcy of Owner;
(b)	Owner fails to pay when due any amount due and payable hereunder, including, without limitation, any interest, fees, reimbursements or indemnifications, and such failure shall continue for a period of 15 days after the due date thereof; or
(c)	other than as set forth in clause (b) above, Owner breaches or fails to observe or perform any material term, condition, or obligation contained in this Agreement and fails to correct, or fails to diligently pursue correction of, such breach within 60 days after receipt of written notice from Operator of any such breach.

If any of the above occurs and Operator elects to terminate this Agreement, then Operator may give a written notice of termination to Owner, which termination shall be effective on the date specified by Operator in such notice, provided that such termination date shall be within 60 days of the date such notice is delivered to Owner. Operator’s notice of breach to Owner under Section 3.2(b) or (c) shall state with particularity the breach alleged by Operator. To the extent Owner disputes the basis for Operator’s notice of breach, then the matter shall be addressed under Section 9.6. Nothing in this Section 3.2 shall be construed to limit or preclude any remedy Operator may have at law or in equity with respect to any material breach by Owner.

3.3 Operator Default.

     Owner may terminate this Agreement at any time upon the occurrence of any of the following:

(a) the dissolution or bankruptcy of Operator;

7

(b)	an Operator Change of Control;
(c)	Operator fails to pay when due any amount due and payable hereunder, including, without limitation, any interest, fees, reimbursements or indemnifications, and such failure shall continue for a period of 15 days after the due date thereof; or
(d)	other than as set forth in clause (c) above, Operator breaches or fails to observe or perform any material term, condition, or obligation contained in this Agreement and fails to correct, or fails to diligently pursue correction of, such breach within 60 days after receipt of written notice from Owner of any such breach.

If any of the above occurs and Owner elects to terminate this Agreement, then Owner may give a written notice of termination to Operator, which termination shall be effective on the date specified by Owner in the notice, provided that such termination date shall be within 60 days of the date the notice is delivered to Operator. Owner’s notice of breach to Operator under Section 3.3(c) or (d) shall state with particularity the breach alleged by Owner. To the extent Operator disputes the basis for Owner’s notice of breach, then the matter shall be addressed under Section 9.6. Nothing in this Section 3.3 shall be construed to limit or preclude any remedy Owner may have at law or in equity with respect to any material breach by Operator.

3.4 Cooperation with Owner or Successor Operator.

     Upon the termination of this Agreement, Operator shall cooperate in the transition of operations to Owner or a successor operator and upon Owner’s request, will promptly deliver all books and records and other property (including, without limitation, intellectual property) of Owner to Owner or the successor operator, as applicable.

3.5 Effect of Termination.

     Any termination of this Agreement pursuant to this Article III will release Operator from, and Owner agrees to indemnify Operator against any liability accruing or accrued hereunder after the effective date of termination, except with respect to the obligations and liabilities of Operator that survive termination. Termination of this Agreement shall not relieve the Parties from any liability or obligation accruing or accrued prior to the date of such termination or deprive a Party not in breach (other than a breach which occurs because such Party is rightfully withholding performance in response to a breach by the other Party) of its right to any remedy otherwise available to such Party.

3.6 No Breach.

     No violation of any of the terms or conditions of this Agreement shall be deemed a breach of this Agreement by Owner if and to the extent such violation or failure results, directly or indirectly, from a breach of the Gathering Agreement by Shipper.

8

ARTICLE IV
DUTIES AS OPERATOR

4.1 Duties as Operator.

     Operator shall be responsible for (1) administering the regulatory, business, and financial affairs of Owner; (2) maintaining the financial and product accounting records of Owner; (3) preparing and distributing financial statements; (4) complying with any and all instructions it receives from Owner with respect to the operation and maintenance of the Gathering System, provided that such instructions are consistent with applicable Laws; (5) performing the requirements and obligations of Owner set forth in the Subject Gathering Agreements; and (6) taking any actions necessary to avoid any exercise of remedies by any shipper under any Subject Gathering Agreement.

     4.1.1 Operation and Maintenance of the Gathering System.

     4.1.1.1 Operation of the Gathering System. Operator shall manage and operate the Gathering System, supervise the operation and maintenance of the Gathering System and the construction and future modifications to the Gathering System, negotiate agreements in Owner’s name with third parties related to the operation of Owner’s business (provided that (i) Owner shall have the right to approve or disapprove any such agreements, and (ii) if approved, except as provided in Section 4.1.2, Owner, and not Operator, shall execute all such agreements), comply with any instructions it receives from Owner with respect to the operation and maintenance of the Gathering System, provided that such instructions are consistent with applicable Laws, and perform all other services and functions related thereto, including, but not limited to, those services and functions listed on Exhibit A, subject to the limits, requirements, and restrictions otherwise set forth in this Agreement.

     4.1.1.2 Maintenance Authority. Subject to the terms, conditions and limitations set forth in this Agreement, Owner hereby authorizes and empowers Operator, and Operator agrees, in the name of and on behalf of Owner, to do and perform any and all acts reasonably necessary for the prudent operation and maintenance of the Gathering System.

     4.1.1.3 Operator Recommendations. In the event that Operator makes a good-faith recommendation in writing regarding an operational issue to Owner, and Owner does not, for any reason whatsoever, approve such recommendation, then Operator shall not be liable and Owner hereby releases and shall indemnify, defend and hold Operator harmless from and against any Claim or Loss that arises from, or is attributable to, the failure to implement such recommendation.

     4.1.1.4 Compliance With Owner Instructions. Notwithstanding anything to the contrary in this Agreement, in the event that Owner instructs Operator to take any action or refrain from taking any action in connection with the operation or maintenance of the Gathering System and Operator in good faith

9

disagrees with Owner because, among other reasons, it is not consistent with prudent operating standards, then Operator shall notify Owner of such disagreement in writing, and Owner hereby releases and shall indemnify, defend and hold Operator harmless from and against any Claim or Loss that arises from, or is attributable to, Operator’s compliance with Owner’s instructions.

     4.1.1.5 Environmental Laws. Operator shall comply in all respects with all Environmental Laws and all Environmental Permits.

     4.1.2 Purchase of Services, Materials and Supplies. Except as otherwise provided below and subject to the limitations herein, Operator shall, on Owner’s behalf and as its agent, purchase or cause to be purchased necessary services, materials and supplies and incur such expenses and enter into such commitments as may be necessary to operate and maintain the Gathering System, including, but not limited to, (i) contracts for the maintenance, repair and replacement of the Gathering System and, if requested by Owner, constructions of additions to the Gathering System; and (ii) contracts for power, fuel, other utilities, and communication facilities as may be necessary in connection with proper operation and maintenance of the Gathering System and for providing adjustments and replacements thereto.

     4.1.3 Personnel. Except as otherwise provided below and subject to the limitations herein, Operator, in its reasonable judgment, shall employ such personnel, with Operator or an Affiliate as their employer, as it may deem necessary to operate and maintain the Gathering System and to provide adjustments and replacements thereto and to perform its other obligations hereunder. In addition to Operator’s or Operator’s Affiliates’ employees who are either full-time or part-time dedicated to operating and maintaining the Gathering System, Operator may: (i) utilize from time to time its other employees or the employees of Operator’s Affiliates in services in connection therewith at a usual and customary rate of compensation; and/or (ii) engage the services of third-party contractors in the performance of such functions.

     4.1.4 Payment of Operating Expenses. Operator shall promptly pay all costs and expenses incurred in operating and maintaining the Gathering System as they become due, and Owner shall reimburse Operator for such costs and expenses in accordance with, and to the extent provided in, Section 5.1.

     4.1.5 Proposed Operating Expense Budget. Operator shall (i) administer and otherwise comply with the budget process set forth in Section 6.6 of the Gathering Agreement and (ii) operate and maintain the Gathering System in compliance with the Proposed Operating Expense Budget established for the Gathering System; provided, however, if Owner instructs Operator to perform any services outside of the scope of the services contemplated in the Proposed Operating Expense Budget, then Owner shall reimburse Operator for the costs and expenses associated therewith.

     4.1.6 Capital Projects. Operator may propose an unbudgeted Capital Project at any time by giving notice to Owner. The notice (the “Capital Project Proposal”) must specifically describe the proposed Capital Project and shall include the following:

10

     (1) a good-faith estimate of the total cost of engineering, construction, operation, and maintenance of the proposed Capital Project, and preliminary engineering designs and plans, and

     (2) general requirements or provisions for the Capital Project, including construction of the Capital Project and insurance coverage.

Owner shall approve or reject the proposed Capital Project set forth in the applicable Capital Project Proposal within 30 days from the date of receipt of the same, such approval not to be unreasonably withheld, conditioned or delayed. If Owner approves the applicable Capital Project, then Operator shall have the right and authority with respect to the approved Capital Project to make expenditures, or enter into contracts to incur expenditures, without further authorization by Owner, up to the cost approved by Owner with respect to the applicable Capital Project.

     4.1.7 Emergencies. Notwithstanding any provision of this Agreement, in the event of an Emergency, Operator shall proceed with maintenance or repair work or with any other action when necessary to minimize damage and to end the Emergency (“Emergency Work”), without regard to the limits set forth in this Article IV. Operator shall, as soon as reasonably practicable, notify Owner of the existence or occurrence of the Emergency, setting forth the nature of the emergency, the corrective action taken or proposed to be taken, and the actual or estimated cost of such corrective action. Emergency Work shall include only such work as is necessary to immediately address the Emergency and does not include any work necessary to restore the Gathering System or improve the Gathering System in order to permit continued operations.

     4.1.8 Reporting By Operator. Operator shall (by either (i) submitting written reports or (ii) providing Owner with access to Operator’s internet website containing the relevant information, at Operator’s discretion) provide to Owner the following reports, based on the best data available at the time of preparation and subject to revision based on acquisition of more accurate data:

     (1) a daily report of the prior day’s 24 hour volume of natural gas throughput on the Gathering System;

     (2) as soon as available, and in any event within 30 days after the end of each calendar month, a report of environmental, health, or safety incidents that are material or potentially material, including year-to-date data, for such month;

     (3) as soon as available, and in any event within 30 days after the end of each calendar month, a report concerning any government agency inspections, inquiries, citations, or other actions for such month;

     (4) as soon as available, and in any event within 30 days after the end of each calendar month, an operational report on major repairs and other operational details materially affecting the operations of the Gathering System during such month;

11

     (5) promptly after the sending thereof, all notices and information sent to Shipper (as defined in the Gathering Agreement) under the Gathering Agreement or to any other shipper under any gathering agreement;

     (6) as soon as available, and in any event within 30 days after the end of each calendar month, a monthly operating and financial report which shall be substantially in the form of Exhibit B and shall include such information as reasonably requested by Owner;

     (7) as soon as available, and in any event within 30 days after the end of each Calendar Year, a certificate from the president or chief executive officer of Operator stating that no event or condition exists or has occurred that violates, results in a breach of, or constitutes a default on the part of any Operator Party under, any of the terms, conditions or provisions of any Transaction Document; and

     (8) such other information regarding the Gathering System or the operation and maintenance of the Gathering System as Owner may from time to time reasonably request.

     4.1.9 Commercial Activities. Operator shall negotiate on behalf of Owner all agreements for gathering services provided by Owner; provided that (i) Owner shall have the right to approve or disapprove any such agreements, and (ii) if approved, Owner, and not Operator, shall execute all such agreements. When Operator receives payments or remittances from customers of Owner, Operator shall deposit and promptly forward all such payments or remittances to Owner. Operator shall make no allowances or adjustments in accounts, unless given specific advance authorization by Owner.

     4.1.10 Regulatory Affairs. Operator shall be responsible for preparing and submitting all regulatory filings pertaining to the Gathering System required by any Governmental Authority.

     4.1.11 Devotion of Time. The employees of Operator designated to perform the functions under this Agreement shall devote such time to Owner’s business as necessary to accomplish the responsibilities of Operator as set forth in this Article IV. Owner recognizes that the employees of Operator shall not be obligated to devote full time to Owner’s business and that such employees of Operator may act on behalf of Operator or its Affiliates in activities not associated with this Agreement.

4.2 Standard of Care.

     Operator shall perform its duties and obligations hereunder and its responsibilities as Operator of the Gathering System, (i) in a good and workmanlike manner, (ii) in conformity with the good practices in the natural gas gathering industry, (iii) in accordance with all valid and applicable Laws, including, without limitation, all Environmental Laws and Environmental Permits, (iv) in accordance with the Subject Gathering Agreements, and (v) in accordance with the Proposed Operating Expense Budget.

12

4.3 Limitation of Authority.

     Notwithstanding anything in this Agreement, Operator shall seek prior approval of Owner prior to taking the following actions:

     4.3.1 Binding Owner. Endorsing the name of Owner on any contract, commercial paper, or instruments of any nature or otherwise creating any obligation binding upon Owner except as expressly permitted under this Agreement.

     4.3.2 Asset Sales. Acquiring or disposing of any assets of Owner in a single transaction or in a series of related transactions, with a fair market value exceeding $100,000, provided, however that Operator is expressly permitted to terminate leases or other contracts in respect of rental equipment regardless of value.

     4.3.3 Material Alteration of Owner’s Business. Altering Owner’s business in a material manner.

     4.3.4 Debt. Incurring any indebtedness on behalf of Owner, except for trade credit incurred by Operator in the ordinary course of business or within its expenditure authority set forth in this Agreement.

ARTICLE V
COST REIMBURSEMENT

5.1 Responsibility for Costs and Expenses.

     Owner shall reimburse Operator for all costs and expenses incurred by Operator relating to the operation and maintenance of the Gathering System incurred in accordance with the terms hereof.

5.2 Procedure.

     5.2.1 Invoicing and Payment. Operator shall invoice Owner, monthly, for all costs and expenses incurred hereunder during the immediately preceding month and, without duplication, in any prior month. Owner shall pay all such amounts prior to the later of (a) 50 days after the end of the month in which the expenses were incurred or (b) 10 days after the date of receipt of each invoice. Invoices received after 1:00 pm local time will be deemed received on the next Business Day. If the day on which any payment is due is not a Business Day, then the relevant payment shall be due upon the immediately succeeding Business Day. Any amounts which remain due and owing after the due date shall bear interest at the lower of the prime rate as published in the “Money Rates” section of The Wall Street Journal plus two percent (2%) per annum and the maximum lawful rate of interest, compounded daily from the date such payment is due until such payment is made. Notwithstanding anything herein to the contrary, any indemnification payments required to be made by a Party hereunder shall be made to the indemnified Party upon receipt by the indemnifying Party of written demand therefor from the indemnified Party.

13

     5.2.2 Disputes. If a good faith dispute arises as to the amount payable under any invoice issued by Operator, Owner shall pay the amount not in dispute on or before the due date, and if Owner elects to withhold any portion of a payment which otherwise would be due if not for such dispute, Owner shall provide Operator a written notice of such dispute on or before the date such payment is due setting forth, in reasonable detail, its reasons for withholding the disputed amount. If it is subsequently determined, whether by mutual agreement of the Parties or otherwise, that Owner is required to pay all or any portion of the disputed and withheld amounts, then in addition to paying such amounts, Owner shall pay interest accrued on such amounts (including amounts withheld) at the default interest rate described in Section 5.2.1 from the original due date until paid in full.

5.3 Setoff.

     5.3.1 All payments required to be made hereunder by Operator shall be (i) absolute and unconditional, (ii) calculated without reference to any netting, set-off, counterclaim or other right which Operator may have against Owner, including, without limitation, any right to set-off against any amounts owed by Owner under this Agreement or any other Transaction Document, and (iii) made free and clear of and without any deduction for or on account of any such netting, set-off or counterclaim.

     5.3.2 Owner is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to net, set-off and apply any payments owing to Owner against any and all of the obligations of any Operator Party under this Agreement or any other Transaction Document. Owner agrees to promptly notify Operator after any such netting, set-off or application is made; provided that the failure to give such notice shall not affect the validity of such netting, set-off or application.

ARTICLE VI
ACCOUNTING; REPORTS; RECORDS

6.1 Accounting Methods.

     Operator shall keep proper and complete records and books of account, which shall fully and accurately reflect all transactions and other matters relative to Owner’s business as are usually entered into records and books of account, and the same shall be supported by purchase orders, invoices, payrolls or other customary or necessary records pertaining thereto. Owner’s financial books and records shall be kept in accordance with GAAP and shall be maintained on an accrual basis, and Owner shall provide Operator with the applicable income tax provisions. The costs of any audit of Owner’s books or records shall be borne by Owner.

6.2 Financial Statements.

     Operator shall deliver to Owner the financial statements of Owner prepared, in each case, in accordance with GAAP (and subject, where applicable, to normal year-end adjustments) as follows:

(a) promptly upon availability, and in any event within 30 days after the end of each

14

	month, (i) an unaudited balance sheet as of the end of such month; and (ii) an unaudited statement of income or loss for the interim period through such month end;
(b)	promptly upon availability, and in any event within 45 days after the end of each of the first three quarterly periods of each fiscal year, Owner’s balance sheet as of the end of such quarterly period and statements of Owner’s earnings and cash flows for the period from the beginning of the then current fiscal year to the end of such quarterly period; and
(c)	promptly upon availability and in any event within 90 days after the end of each fiscal year, complete financial statements of Owner, together with all notes thereto, prepared in reasonable detail in accordance with GAAP, together with an unqualified opinion, based on an audit using generally accepted auditing standards, by an independent certified public accounting firm selected by Owner, stating that such financial statements have been so prepared. These financial statements shall contain a balance sheet as of the end of such fiscal year and statements of earnings, of cash flows, and of changes in Owner’s equity for such fiscal year, each setting forth in comparative form the corresponding figures for the preceding fiscal year. Owner shall engage an auditor for this purpose no later than 45 days after the end of each fiscal year.

6.3 Accounting and Taxation.

     6.3.1 Maintenance of Accounts. Operator shall perform Owner’s Tax and financial accounting with respect to the Gathering System, except to the extent that Operator is prohibited or prevented from doing so by Law, or by the administrative practice of any taxing office, or by the fact that to do so requires information that is in the possession of Owner, but not of Operator and that Owner cannot legally furnish to Operator (all of which are herein called “Preventing Factors”).

     6.3.2 Preparation of Tax Returns.

     6.3.2.1 Income Tax Returns. Unless otherwise instructed by Owner, Operator shall, on behalf of Owner, (i) provide all the necessary financial and other data for a tax preparer (appointed by Owner) to prepare all Tax Returns for taxes measured or based on income required to be filed by Owner in connection with its ownership and operation of the Gathering System no later than 75 days prior to the filing date for the relevant Tax Return (taking into account all valid extensions approved by Owner prior to filing), (ii) cooperate with Owner and its accountants in their preparation of such Tax Returns and review all modifications to such Tax Returns indicated by Owner, and (iii) help facilitate completion of such Tax Returns by no later than 45 days prior to the filing date for the relevant Tax Return.

     6.3.2.2 Other Tax Returns. Unless otherwise instructed by Owner, Operator shall, on behalf of Owner, (i) prepare and file all Tax Returns and all

15

other regulatory or state filings required to be filed by Owner in connection with its ownership and operation of the Gathering System other than those Tax Returns described in Section 6.3.2.1 no later than the filing date for the relevant Tax Return or other filing (taking into account all valid extensions approved by Owner prior to filing).

     6.3.3 Owner to Supply Information. Upon the request of Operator, Owner shall (except to the extent it is prohibited by Law from doing so) promptly (i) furnish Operator with any information needed by Operator in order to carry out its obligations under Section 6.3, (ii) cooperate with Operator in minimizing Taxes and (iii) execute such agency, power-of-attorney or other similar documents reasonably required by Operator in order to carry out its duties under this Section 6.3. If, at any time, Operator determines that because of one or more Preventing Factors it cannot perform its obligations under Section 6.3, then Operator shall notify Owner in writing, specifying the Preventing Factors concerned and the Taxes and the Governmental Authorities to which such Preventing Factors apply. Any incremental Tax or penalty resulting from Owner’s failure to comply with this Section 6.3.3 shall be the responsibility of Owner.

6.4 Banking.

     6.4.1 Except as provided in Section 6.4.2, all revenues and other funds of Owner shall be deposited in its name in the Owner Revenue Account. Withdrawals from the Owner Revenue Account will be made only by Owner or Persons designated by Owner from time to time. Operator shall have view only access to the Owner Revenue Account. Owner will provide the Operator with copies of reconciled bank statements on a monthly basis, for accounting and audit purposes.

     6.4.2 All Operations Fees (as defined in the Gathering Agreement) shall be deposited in the name of Owner in the Owner Operating Expense Account. Withdrawals from the Owner Operating Expense Account will be made only by Owner, Operator or other Persons designated by Owner from time to time.

     6.4.3 Notwithstanding the foregoing, all funds of Owner will be used solely for the business of Owner. All interest and other benefits pertaining to the Owner Revenue Account and the Owner Operating Expense Account belong to Owner. At no time may Operator commingle the funds in the Owner Revenue Account, the Owner Operating Expense Account or any other bank account of Owner with Operator’s funds or the funds of any other Person, nor may such funds be subject to liens or Claims of any kind in favor of Operator or its creditors.

6.5 Independent Audits.

     Upon reasonable prior written notice to Operator, Owner shall have the right during normal business hours to audit or examine all books and records of Operator to the extent they relate to Operator’s performance hereunder as well as the relevant books of account of Operator’s contractors, relating to the performance of Operator’s obligations under this Agreement. Operator shall cooperate with Owner’s auditors by (i) making the applicable books

16

and records available for inspection by Owner’s auditors, and (ii) making such copies of books and records as may be reasonably requested by such auditors. In no event shall Owner’s audits unreasonably interfere with Operator’s operations. Owner will be responsible for all costs of any such audit; provided that if, in any audit, Owner discovers overpayments by Owner of at least $250,000 in the aggregate (“Material Overpayment”), Operator will reimburse Owner for such Material Overpayment and all reasonable costs incurred by Owner in connection with such audit (“Audit Costs”). Owner shall have up until two years after the close of a Calendar Year in which to make an audit of Operator’s records for such Calendar Year. Except for any bill or statement with respect to which an Adjustment Claim is made within the two-year audit period, the bills and statements rendered for the Calendar Year prior to such two-year audit period shall be conclusively established as correct. An “Adjustment Claim” shall mean a written claim by Owner to Operator requesting a refund or other financial adjustment in respect of any overpayment by Owner (including in the case of a Material Overpayment, all Audit Costs) and setting forth in reasonable detail the basis for such claim. Operator shall, within 10 days of receipt of an Adjustment Claim, provide Owner with the requested refund or other financial adjustment; provided that if Operator shall dispute in good faith some or all of the amounts set forth in such Adjustment Claim, Operator may elect to withhold any disputed amounts, pending resolution of the dispute. If the Parties shall fail to resolve their dispute with respect to the remaining Adjustment Claim amount within 15 Business Days, Owner may, at its sole option, refer such dispute for resolution in accordance with the terms of Section 9.6. Unless otherwise resolved by the Parties, any bill or statement that is the subject of an Adjustment Claim shall be conclusively established as correct if dispute resolution procedures have not been initiated under Section 9.6 of this Agreement within 180 days of the submission of an Adjustment Claim. Any and all information pertaining to Operator and its business that is disclosed to Owner or discovered by Owner in connection with any audit hereunder shall be subject to the Confidentiality and Disclosure Agreement without regard to whether it has been designated as such and Owner shall be subject to the same restrictions and standard of care set forth therein with respect to Operator’s confidential information.

6.6 Credit Inquiries.

     If a customer, vendor, or other Person requests financial information concerning Owner, Operator may provide such customer, vendor, or Person a certificate or affidavit, on behalf of Owner, to the effect that Owner owns the Gathering System, free and clear of any mortgage or other liens or encumbrances except for (1) encumbrances consisting of zoning or planning restrictions, servitudes, permits, and other restrictions or limitations on the use of immovable property that do not materially detract from the value of, or impair the use of, the Gathering System by Owner in the operation of its business, (2) liens arising by operation of law in the ordinary course of business and in an aggregate amount that is not material in relation to the value of the Gathering System, (3) liens for current taxes, assessments, or governmental charges or levies, and (4) such other liens or encumbrances, if any, of which Operator has actual knowledge at the time.

17

ARTICLE VII
FORCE MAJEURE

7.1 Procedure.

     If either Party is rendered unable, wholly or in part, by Force Majeure to carry out its obligations under this Agreement, other than the obligation to indemnify and to make payments then or thereafter due hereunder, upon such Party giving notice and full particulars of such Force Majeure in writing to the other Party as soon as reasonably possible after the occurrence of the cause relied on, then the obligations of the Party giving such notice, so far as they are affected by such Force Majeure, will be suspended during the continuance of any inability so caused but for no longer period, and such cause must as far as possible be remedied with all reasonable and diligent dispatch by the Party claiming such in order to put itself in a position to carry out its obligations under this Agreement. Such notifying Party must also provide notice of the date of termination of such Force Majeure event. A Force Majeure event affecting the performance by either Party shall not relieve it of liability in the event of its negligence, where such negligence was a cause of the Force Majeure event, or in the event of its failure to use commercially reasonable efforts to remedy the situation and remove the cause with all reasonable dispatch.

7.2 Strikes.

     It is understood and agreed that the settlement of strikes or lockouts is entirely within the discretion of the Party directly involved in the strike or lockout, and that the above requirement that any Force Majeure must be remedied with all reasonable dispatch will not require the settlement of strikes or lockouts by acceding to the demands of the opposing party when such course is inadvisable in the discretion of the Party having the difficulty.

ARTICLE VIII
INSURANCE AND INDEMNIFICATION

8.1 Operator Insurance.

     8.1.1 Operator, with respect to Operator’s activities provided for under this Agreement, shall maintain the following insurance coverage with responsible insurance carriers and/or through a program of self-insurance:

(a)

Workers’ Compensation. Operator shall maintain statutory worker’s compensation insurance, covering all of its and its Affiliates’ employees and statutory employees, in accordance with the benefits afforded by the statutory Worker’s Compensation Acts applicable to the state, territory, or district of hire, supervision, or place of accident. In addition, Operator shall maintain employer’s liability insurance with a limit of not less than one million dollars ($1,000,000) each accident, one million dollars ($1,000,000) disease each employee, and one million dollars ($1,000,000) disease policy limit. Where not prohibited by law, Operator shall waive its right of subrogation against Owner.

(b)

Commercial General Liability Insurance. Operator shall maintain Commercial General Liability Insurance covering its operations under this Agreement

18

	including, without limitation, bodily injury, death, property damage, independent contractors, products/completed operations, contractual, and personal injury liability, with a limit of not less than one million dollars ($1,000,000) per occurrence and two million dollars ($2,000,000) in the annual aggregate.
(c)	Commercial Automobile Insurance. Operator shall maintain Commercial Automobile Insurance coverage, including, without limitation, bodily injury and property damage for owned, hired, rented, and non-owned automotive equipment with a limit of not less than one million dollars ($1,000,000) per accident.
(d)	Umbrella Liability Insurance. Operator shall maintain Umbrella Liability Insurance coverage covering in excess of (a), (b), and (c) above, excluding Worker’s Compensation, in the amount of ten million dollars ($10,000,000).

     8.1.2 To the extent of the liabilities assumed by Operator in this Agreement, Operator shall name Owner Indemnified Parties as additional insured on all insurance policies, except Workers’ Compensation. The Owner Indemnified Parties’ additional insured status will not limit the application of insurance protection as required by this Agreement which arises out of the Operator’s indemnity obligations. These policies shall provide primary coverage for claims in which Operator has agreed to hold harmless and/or to indemnify the Owner Indemnified Parties. No “other insurance” clause may be invoked by any insurer. This coverage shall apply whether or not the indemnification is valid. Operator shall have its insurer(s) waive its right of subrogation against Owner Indemnified Parties on all insurance carried. Unless expressly stated to the contrary elsewhere in this Agreement or prohibited by applicable law or legal statute, Operator’s indemnification obligations under this Agreement shall not be limited by amount or in scope to coverage provided by insurance which is required under this Agreement.

     8.1.3 Upon request, Operator agrees to furnish to Owner certificates of insurance or other evidence satisfactory to Owner to demonstrate that the required insurance has been procured and is in force. The certificate shall accurately reflect the required insurance coverages and shall provide that in the event of modification, expiration, cancellation or material change in a policy affecting the certificate holder, thirty days prior written notice shall be given to the certificate holder. Operator waives all rights against Owner for recovery of damages to the extent such damages are covered by the insurance maintained in accordance with this Section 8.1.

8.2 Contractors.

     Operator shall attempt to obtain reasonable indemnification and insurance protection from contractors performing services for Owner to protect Owner and Operator. Operator shall require each of its contractors to carry insurance coverage substantially equivalent to the insurance required of Operator above, and to include provisions for its contractors to name Owner and Operator as additional insureds, with the exception of Workers’ Compensation Insurance, and state that such policies will be primary to and non-contributory with any other insurance maintained by Operator and Owner. With respect to Workers’ Compensation

19

Insurance, the applicable contractor shall be required to cause its insurers to wave all rights of recovery or subrogation against Owner and Operator, where not prohibited by law.

8.3 Notice of Claims.

     In the event that Operator receives notice, either in writing or orally, of an asserted or threatened Liability Claim against Operator or Owner, Operator shall provide Owner within 10 days of receipt of such Liability Claim a copy of any demand letter, petition, or similar documentation of the Liability Claim.

8.4 Mutual Release and Indemnification.

     8.4.1 Owner’s Indemnification. Subject to the terms of this Agreement, including, without limitation, Section 9.7 of this Agreement, Owner shall indemnify, defend, and hold harmless the Operator Indemnified Parties from and against all Claims and Losses arising out of or relating to (i) allegations of death or bodily injury or damage to property, to the extent arising out of or resulting from the negligence, gross negligence or willful misconduct of Owner, its Affiliates or its or their respective officers, directors, employees, or contractors in connection with this Agreement or the performance hereof; provided that Owner shall not be required to indemnify the Operator Indemnified Parties against such Claims and Losses to the extent such Claims and Losses are attributable to the acts or omissions of any Operator Indemnified Parties, (ii) any breach of this Agreement by Owner, and (iii) any agreements relating to the Gathering System between Owner and third parties not affiliated with the Operator Parties. The duty to indemnify, defend and hold harmless under this Section 8.4.1 shall continue in full force and effect, notwithstanding the expiration or early termination of this Agreement, with respect to any Claims or Losses based on facts or conditions that occurred prior to such expiration or termination.

     8.4.2 Operator’s Indemnification. Subject to the terms of this Agreement, including, without limitation, Section 9.7 of this Agreement, Operator shall indemnify, defend, and hold harmless the Owner Indemnified Parties from and against all Claims and Losses arising out of or relating to (i) allegations of death or bodily injury or damage to property, to the extent arising out of or resulting from the negligence, gross negligence or willful misconduct of Operator, its Affiliates or its or their respective officers, directors, employees, or contractors in connection with this Agreement or the performance hereof; provided that Operator shall not be required to indemnify the Owner Indemnified Parties against such Claims or Losses to the extent such Claims or Losses are attributable to the acts or omissions of any Owner Indemnified Party, and (ii) any breach of this Agreement by Operator. The duty to indemnify, defend and hold harmless under this Section 8.4.2 shall continue in full force and effect, notwithstanding the expiration or early termination of this Agreement, with respect to any Claims or Losses based on facts or conditions that occurred prior to such expiration or termination.

20

ARTICLE IX
GENERAL PROVISIONS

9.1 Notices.

     Except as specifically provided otherwise herein, any notice, claim, or other communication provided for in this Agreement or any notice that either Party may desire to give to the other shall be in writing and shall be: (i) sent by facsimile transmission; (ii) delivered by hand; (iii) sent by United States mail with all postage fully prepaid; or (iv) delivered by courier with charges paid in accordance with the customary arrangements established by such courier, in each of the foregoing cases addressed to the Party at the following addresses:

To Owner:	Piñon Gathering Company, LLC
	c/o TCW Asset Management Company
	333 Clay Street, Suite 4150
	Houston, Texas 77002
	Attention: Clay Taylor
	Fax Number: 713.615.7460
with a copy to:	TCW Asset Management Company
	865 South Figueroa Street, Suite 1800
	Los Angeles, California 90017
	Attention: R. Blair Thomas
	Fax Number: 213.244.0604
To Operator:	SandRidge Midstream, Inc.
	123 Robert S. Kerr Avenue
	Oklahoma City, Oklahoma 73102-6406
	Attention: Midstream — Manager of Administration
	Fax Number: 405.429.5990

or at such other address as either Party may at any time designate by giving written notice to the other Party. Such notices, invoices, allocation statements, claims, or other communications shall be deemed received as follows: (i) if delivered personally, upon delivery; (ii) if sent by United States mail, whether by express mail, registered mail, certified mail or regular mail, the notice shall be deemed to have been received on the day receipt is refused or is confirmed orally or in writing by the receiving Party; (iii) if sent by a courier service, upon delivery; or (iv) if sent by facsimile, the Business Day following the day on which it was transmitted and confirmed by transmission report or such earlier time as confirmed orally or in writing by the receiving Party.

9.2 Rights.

     The failure of either Party to exercise any right granted hereunder shall not impair nor be deemed a waiver of that Party’s privilege of exercising that right at any subsequent time or times.

21

9.3 Applicable Laws.

     This Agreement is subject to all valid present and future laws, regulations, rules, and orders of governmental authorities now or hereafter having jurisdiction over the Parties, this Agreement, any of the transactions contemplated hereby or the Gathering System.

9.4 Rules of Construction.

     In construing this Agreement, the following principles shall be followed:

     9.4.1 no consideration shall be given to the fact or presumption that one Party had a greater or lesser hand in drafting this Agreement;

     9.4.2 examples shall not be construed to limit, expressly or by implication, the matter they illustrate;

     9.4.3 the word “includes” and its syntactical variants mean “includes, but is not limited to” and corresponding syntactical variant expressions; and

     9.4.4 the plural shall be deemed to include the singular and vice versa, as applicable.

9.5 Governing Law.

     This Agreement shall be governed by, construed, and enforced in accordance with the laws of the State of Texas, without regard to choice of law principles that would require the application of the laws of any other jurisdiction.

9.6 Dispute Resolution.

     9.6.1 Negotiation. Prior to submitting any dispute for resolution by a court, a Party shall provide written notice to the other of the occurrence of such dispute. If the Parties have failed to resolve the dispute within 15 Business Days after such notice was given, the Parties shall seek to resolve the dispute by negotiation between senior management personnel of each Party. Such personnel shall endeavor to meet and attempt to amicably resolve the dispute. If the Parties are unable to resolve the dispute for any reason within 30 Business Days after the original notice of dispute was given, then either Party shall be entitled to pursue any remedies available at law or in equity; provided, however, this Section 9.6.1 shall not limit a Party’s right to initiate litigation prior to the expiration of the time periods set forth herein of such limitations would prevent a Party from filing a lawsuit or claim within the applicable period for filing lawsuits (e.g. statutes of limitation, prescription, etc.).

     9.6.2 Jurisdiction and Venue.

     9.6.2.1 Each Party agrees that the appropriate, exclusive and convenient forum for any disputes between any of the Parties arising out of this Agreement or the transactions contemplated hereby shall be in any state or federal court in

22

Houston or Dallas, Texas, and each of the Parties irrevocably submits to the jurisdiction of such courts solely in respect of any legal proceeding arising out of or related to this Agreement or the transactions contemplated hereby. The Parties further agree that the Parties shall not bring suit with respect to any disputes arising out of this Agreement or the transactions contemplated hereby in any court or jurisdiction other than the above specified courts.

     9.6.2.2 Each Party hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby in any court referred to in paragraph (a) above. Each of the Parties hereby irrevocably waives, to the fullest extent permitted by applicable law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

     9.6.3 Jury Waiver. THE PARTIES HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE, TO THE FULLEST EXTENT THEY MAY LEGALLY AND EFFECTIVELY DO SO, THE RIGHT TO A JURY IN ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

     9.6.4 Costs and Expenses. The prevailing Party in any litigation pertaining to any dispute hereunder shall be entitled to recover its reasonable costs, expenses, and attorney’s fees in connection with such litigation.

9.7 Limitation of Liability.

     Notwithstanding anything in this agreement to the contrary, neither Party shall be liable to the other Party for special, indirect, consequential, punitive, or exemplary damages suffered by such Party resulting from or arising out of this Agreement or the breach thereof or under any other theory of liability, whether tort, negligence, strict liability, breach of contract, warranty, indemnity, or otherwise, including, without limitation, loss of use, increased cost of operations, loss of profit or revenue, or business interruptions. In furtherance of the foregoing, each Party releases the other Party and waives any right of recovery for special, indirect, consequential, punitive, or exemplary damages suffered by such Party regardless of whether any such damages are caused by the other Party’s negligence (and regardless of whether such negligence is sole, joint, concurrent, active, passive, or gross negligence), fault, or liability without fault.

9.8 Entirety of Agreement, Amendments.

     This Agreement, including, without limitation, all exhibits hereto, and the other Transaction Documents integrate the entire understanding between the Parties with respect to the subject matter covered and supersede all prior understandings, drafts, discussions, or statements,

23

whether oral or in writing, expressed or implied, dealing with the same subject matter. This Agreement may not be amended or modified in any manner except by a written document signed by the Parties that expressly amends this Agreement.

9.9 Waivers.

     No waiver by either Party of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless expressly provided. No waiver shall be effective unless made in writing and signed by the Party to be charged with such waiver.

9.10 Exhibits.

     Exhibits A and B are made a part of this Agreement and incorporated herein by this reference.

9.11 Headings.

     The headings and captions in this Agreement have been inserted for convenience of reference only and shall not define or limit any of the terms and provisions hereof.

9.12 Rights and Remedies.

     Except as otherwise provided in this Agreement, each Party reserves to itself all rights, counterclaims, other remedies, and defenses to which such Party is or may be entitled arising from or out of this Agreement or as otherwise provided by law.

9.13 Assignment.

     Operator shall not make any assignment of all or any part of this Agreement or any of the rights or obligations hereunder unless there first shall have been obtained the written consent thereto of Owner, which consent shall not be unreasonably withheld, conditioned, or delayed. Owner shall not make any assignment of all or any part of this Agreement or any of the rights or obligations hereunder except in connection with the sale or conveyance of all or any part of the Gathering System. This Agreement shall be binding upon and inure to the benefit of the successors and assigns of the Parties. Any attempted assignment of this Agreement in violation of this Section 9.13 shall be null and void.

9.14 Counterparts.

     This Agreement may be executed in one or more counterparts (including by facsimile), each of which shall be deemed an original, and all of which shall be deemed one and the same Agreement.

9.15 No Third Party Beneficiary.

     Except for parties indemnified hereunder, this Agreement is for the sole benefit of the Parties and their respective successors and permitted assigns, and shall not inure to the benefit of

24

any other Person whomsoever or whatsoever, it being the intention of the Parties that no third Person shall be deemed a third-party beneficiary of this Agreement.

9.16 Further Assurances.

     Each Party shall take such acts and execute and deliver such documents as may be reasonably required to effectuate the purposes of this Agreement.

     IN WITNESS WHEREOF, authorized representatives of the Parties have executed this Agreement to be effective on the Effective Date.

OPERATOR: SANDRIDGE MIDSTREAM, INC.
By:	/s/ Richard J. Gognat
	Richard J. Gognat
	Senior Vice President
OWNER: PIÑON GATHERING COMPANY, LLC
By:	TCW Asset Management Company, its Manager:
By:	/s/ Clayton R. Taylor
	Clayton R. Taylor
	Vice President
By:	/s/ Kurt A. Talbot
	Kurt A. Talbot
	Managing Director

25

EX-31.1

Exhibit 31.1

Certification of the Company’s Chief Executive Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

I, Tom L. Ward, certify that:

     1. I have reviewed this quarterly report on Form 10-Q of SandRidge Energy, Inc.;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

     (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Tom L. Ward  

Tom L. Ward 

President, Chief Executive Officer and
Chairman of the Board 

Date: August 6, 2009

EX-31.2

Exhibit 31.2

Certification of the Company’s Chief Financial Officer Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

I, Dirk M. Van Doren, certify that:

     1. I have reviewed this quarterly report on Form 10-Q of SandRidge Energy, Inc.;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

     (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

     (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

     (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

     (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

     (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

     (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Dirk M. Van Doren  

Dirk M. Van Doren 

Executive Vice President and Chief Financial Officer 

Date: August 6, 2009

EX-32.1

Exhibit 32.1

Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

     Pursuant to 18 U.S.C. § 1350, the undersigned officers of SandRidge Energy, Inc. (the “Company”), hereby certify that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2009 (the “Report”), fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Tom L. Ward  

Tom L. Ward 

President, Chief Executive Officer and
Chairman of the Board 

August 6, 2009

/s/ Dirk M. Van Doren  

Dirk M. Van Doren 

Executive Vice President and Chief Financial Officer 

August 6, 2009