UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2012

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from  to

Commission File Number 001-10924

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	75-2396863
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Six Desta Drive - Suite 6500
Midland, Texas	79705-5510
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code: (432) 682-6324

Not applicable

(Former name, former address and former fiscal year, if changed since last report)

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. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o No

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

There were 12,163,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of November 6, 2012.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

	PART I.  FINANCIAL INFORMATION
		Page
Item 1.	Financial Statements
	Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	3
	Consolidated Statements of Operations and Comprehensive Income (Loss) for the three months and nine months ended September 30, 2012 and 2011	5
	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2012	6
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	41
	PART II. OTHER INFORMATION
Item 1A.	Risk Factors	43
Item 6.	Exhibits	44
	Signatures	45

2

PART I.  FINANCIAL INFORMATION

Item 1 - Financial Statements

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands) ASSETS
	September 30, 2012			December 31, 2011
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	22,694		$	17,525
Accounts receivable:
Oil and gas sales	36,770			41,282
Joint interest and other, net	12,357			14,517
Affiliates	513			990
Inventory	44,272			44,868
Deferred income taxes	8,202			8,948
Fair value of derivatives	945			—
Prepaids and other	5,730			14,813
	131,483			142,943
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,497,466			2,103,085
Natural gas gathering and processing systems	45,477			26,040
Contract drilling equipment	88,570			75,956
Other	20,970			19,134
	2,652,483			2,224,215
Less accumulated depreciation, depletion and amortization	(1,271,601		)	(1,156,664		)
Property and equipment, net	1,380,882			1,067,551
OTHER ASSETS
Debt issue costs, net	10,898			11,644
Fair value of derivatives	7,745			—
Investments and other	15,531			4,133
	34,174			15,777
	$	1,546,539		$	1,226,271
The accompanying notes are an integral part of these consolidated financial statements.

3

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands) LIABILITIES AND STOCKHOLDERS' EQUITY
	September 30, 2012		December 31, 2011
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	76,426	$	98,645
Oil and gas sales	36,129		37,409
Affiliates	123		1,501
Fair value of derivatives	—		5,633
Accrued liabilities and other	21,088		13,042
	133,766		156,230
NON-CURRENT LIABILITIES
Long-term debt	769,572		529,535
Deferred income taxes	152,022		134,209
Fair value of derivatives	—		494
Asset retirement obligations	51,547		40,794
Deferred revenue from volumetric production payment	39,170		—
Accrued compensation under non-equity award plans	22,675		20,757
Other	861		751
	1,035,847		726,540
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; none issued	—		—
Common stock, par value $.10 per share, authorized — 30,000,000 shares: issued and outstanding — 12,163,536 shares at September 30, 2012 and December 31, 2011	1,216		1,216
Additional paid-in capital	152,515		152,515
Retained earnings	223,195		189,770
	376,926		343,501
	$	1,546,539	$	1,226,271

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

4

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Unaudited) (In thousands, except per share)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
REVENUES
Oil and gas sales	$	101,638		$	99,752		$	308,116		$	300,488
Natural gas services	671			334			1,305			1,108
Drilling rig services	5,348			929			11,478			3,614
Gain on sales of assets	106			49			543			14,570
Total revenues	107,763			101,064			321,442			319,780
COSTS AND EXPENSES
Production	32,564			24,284			93,937			75,237
Exploration:
Abandonments and impairments	306			1,256			2,292			2,307
Seismic and other	2,710			1,842			5,445			5,287
Natural gas services	508			233			956			781
Drilling rig services	5,335			1,673			12,164			4,378
Depreciation, depletion and amortization	37,661			25,901			103,486			74,987
Impairment of property and equipment	—			5,035			5,711			9,459
Accretion of asset retirement obligations	1,069			706			2,628			2,077
General and administrative	5,830			7,142			25,133			22,678
Loss on sales of assets and impairment of inventory	207			114			485			417
Total costs and expenses	86,190			68,186			252,237			197,608
Operating income	21,573			32,878			69,205			122,172
OTHER INCOME (EXPENSE)
Interest expense	(9,786		)	(8,717		)	(27,817		)	(24,304		)
Loss on early extinguishment of long-term debt	—			(907		)	—			(5,501		)
Gain (loss) on derivatives	(21,901		)	92,286			9,856			74,128
Other	(559		)	527			739			3,514
Total other income (expense)	(32,246		)	83,189			(17,222		)	47,837
Income (loss) before income taxes	(10,673		)	116,067			51,983			170,009
Income tax (expense) benefit	3,497			(41,544		)	(18,558		)	(60,693		)
NET INCOME (LOSS)	$	(7,176	)	$	74,523		$	33,425		$	109,316
Net income (loss) per common share:
Basic	$	(0.59	)	$	6.13		$	2.75		$	8.99
Diluted	$	(0.59	)	$	6.13		$	2.75		$	8.99
Weighted average common shares outstanding:
Basic	12,164			12,163			12,164			12,160
Diluted	12,164			12,163			12,164			12,161

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

5

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited) (In thousands)
	Common Stock			Additional				Total
	No. of	Par		Paid-In		Retained		Stockholders’
	Shares	Value		Capital		Earnings		Equity
BALANCE,
December 31, 2011	12,164	$	1,216	$	152,515	$	189,770	$	343,501
Net income	—	—		—		33,425		33,425
BALANCE,
September 30, 2012	12,164	$	1,216	$	152,515	$	223,195	$	376,926

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

6

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands)
	Nine Months Ended
	September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	33,425		$	109,316
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	103,486			74,987
Impairment of property and equipment	5,711			9,459
Exploration costs	2,292			2,307
(Gain) loss on sales of assets and impairment of inventory, net	(58		)	(14,153		)
Deferred income tax expense	18,558			60,693
Non-cash employee compensation	2,200			6,104
Unrealized gain on derivatives	(14,817		)	(82,029		)
Accretion of asset retirement obligations	2,628			2,077
Amortization of debt issue costs and original issue discount	1,587			1,623
Loss on early extinguishment of long-term debt	—			5,501
Amortization of deferred revenue from volumetric production payment	(5,862		)	—
Changes in operating working capital:
Accounts receivable	7,150			768
Accounts payable	(5,772		)	(4,456		)
Other	7,355			3,090
Net cash provided by operating activities	157,883			175,287
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(438,482		)	(282,474		)
Proceeds from volumetric production payment	45,032			—
Proceeds from sales of assets	867			12,466
Increase in equipment inventory	64			2,844
Other	(195		)	(133		)
Net cash used in investing activities	(392,714		)	(267,297		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	240,000			445,366
Repayments of long-term debt	—			(323,500		)
Premium on early extinguishment of long-term debt	—			(2,765		)
Proceeds from exercise of stock options	—			213
Net cash provided by financing activities	240,000			119,314
NET INCREASE IN CASH AND CASH EQUIVALENTS	5,169			27,304
CASH AND CASH EQUIVALENTS
Beginning of period	17,525			8,720
End of period	$	22,694		$	36,024
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	19,295		$	8,064

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

7

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2012

(Unaudited)

1. Nature of Operations

Clayton Williams Energy, Inc. (a Delaware corporation),  is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico.  Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.  Approximately 26% of the Company’s outstanding Common Stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board, President and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.

Substantially all of our oil and gas production is sold under short-term contracts, which are market-sensitive.  Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels, and overall domestic and foreign economic conditions.

2. Presentation

The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results could differ materially from those estimates.

The consolidated financial statements include the accounts of CWEI and its wholly-owned subsidiaries.  We account for our undivided interest in oil and gas limited partnerships using the proportionate consolidation method.  Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships.  Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships.  All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.  Certain reclassifications of prior year financial statement amounts have been made to conform to current year presentations.

In the opinion of management, our unaudited consolidated financial statements as of September 30, 2012 and for the interim periods ended September 30, 2012 and 2011 include all adjustments that are necessary for a fair presentation in accordance with GAAP.  These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2012.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).  These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2011.

3. Long-Term Debt

Long-term debt consists of the following:

	September 30, 2012		December 31, 2011
	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $428 at September 30, 2012 and $465 at December 31, 2011	$	349,572	$	349,535
Revolving credit facility, due November 2015	420,000		180,000
	$	769,572	$	529,535

8

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Senior Notes

In July 2005, we issued $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“2013 Senior Notes”).  The 2013 Senior Notes were issued at face value and bore interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.  In March 2011, we redeemed $143.2 million in aggregate principal amount of 2013 Senior Notes in a tender offer and recorded a $4.6 million loss on early extinguishment of long-term debt, consisting of a $2.8 million premium and a $1.8 million write-off of debt issuance costs.  On August 1, 2011, we called at par and redeemed in full the remaining $81.8 million of 2013 Senior Notes and recorded an additional $907,000 loss on early extinguishment of long-term debt related to the write-off of debt issuance costs.

In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (“2019 Senior Notes”).  The 2019 Senior Notes were issued at face value and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011.  In April 2011, we issued an additional $50 million aggregate principal amount of 2019 Senior Notes with an original issue discount of 1% or $500,000.  We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing the 2019 Senior Notes contains covenants that restrict our ability to:  (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business.  One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture.  These covenants are subject to a number of important exceptions and qualifications as described in the Indenture.  We were in compliance with these covenants at September 30, 2012.

Revolving Credit Facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $565 million, limited to the amount of a borrowing base as determined by the banks.  The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November.  We or the banks may also request an unscheduled borrowing base redetermination at other times during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.

In May 2012, the banks increased the borrowing base from $475 million to $565 million and increased the maximum credit facility from $500 million to $565 million.  The banks also increased the aggregate commitment from $350 million to $475 million in April 2012 and to $555 million in August 2012. At September 30, 2012, after allowing for outstanding letters of credit totaling $4.1 million, we had $131 million available under the revolving credit facility based on then-existing commitments.  During the first nine months of 2012, we increased indebtedness outstanding under the revolving credit facility by $240 million.

The revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base.  The obligations under the revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries.

At our election, annual interest rates under the revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.75% and 2.75% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.75% and 1.75% per year.  We also pay a commitment fee on the unused portion of the revolving credit facility at a rate between 0.375% and 0.50%.  The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the nine months ended September 30, 2012 was 2.6%.

9

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens.  One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1.  Another financial covenant prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.  The computations of consolidated current assets, current liabilities, EBITDAX and indebtedness are defined in the revolving credit facility.  We were in compliance with all financial and non-financial covenants at September 30, 2012.

4. Acquisition of Southwest Royalties, Inc. Limited Partnerships

On March 14, 2012, Southwest Royalties, Inc. (“SWR”), a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner (“SWR Partnerships”), into SWR, with SWR continuing as the surviving entity in the mergers. At the effective time of the mergers, all of the units representing limited partnership interests in the SWR Partnerships, other than those held by SWR, were converted into the right to receive cash. SWR did not receive any cash payment for its partnership interests in the SWR Partnerships. However, as a result of the mergers, SWR acquired 100% of the assets and liabilities of the SWR Partnerships. SWR paid aggregate merger consideration of $38.6 million in the mergers. Pro forma financial information is not presented as it would not be materially different from the information presented in the consolidated statements of operations and comprehensive income (loss) of CWEI.

To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million.  Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725,000 barrels of oil equivalents (“BOE”) of estimated future oil and gas production from certain properties derived from the mergers.  The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and are to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties.  Once the scheduled volumes have been delivered to the third party, the term overriding royalty interest will terminate.  SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks related to the adequacy of the associated reserves to fully recoup the scheduled volumes and also assumed all risks associated with product prices.  As a result, the VPP has been accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes are produced (see Note 6).

The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

Cash and cash equivalents	$	4,118
Oil and gas properties	41,098
Other non-current assets	210
Total assets acquired	45,426
Asset retirement obligations	(6,864		)
Total liabilities assumed	(6,864		)
Net assets acquired	$	38,562

10

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Asset Retirement Obligations

Changes in asset retirement obligations (“ARO”) are as follows:

	September 30, 2012			December 31, 2011
	(In thousands)
Beginning of period	$	40,794		$	40,444
Additional ARO from new properties	7,687			1,526
Sales or abandonments of properties	(967		)	(4,425		)
Accretion expense	2,628			2,757
Revisions of previous estimates	1,405			492
End of period	$	51,547		$	40,794

Our ARO is measured using primarily Level 3 inputs.  The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life.  The inputs are calculated based on historical data as well as current estimated costs.

6. Deferred Revenue from Volumetric Production Payment

The net proceeds from the VPP discussed in Note 4 are recorded as a non-current liability in the consolidated balance sheets.  Deferred revenue from VPP will be amortized over the life of the VPP and will be recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss).

Changes in deferred revenue from the VPP are as follows:

	September 30, 2012			December 31, 2011
	(In thousands)
Beginning of period	$	—		$	—
Deferred revenue from VPP	45,032			—
Amortization of deferred revenue from VPP	(5,862		)	—
End of period	$	39,170		$	—

Under the terms of the VPP, SWR conveyed to a third party a term overriding royalty interest covering approximately 725,000 BOE of estimated future oil and gas production. As of September 30, 2012, we have a remaining obligation to deliver approximately 642,000 BOE.

7. Compensation Plans

Stock-Based Compensation

We presently have options outstanding under a stock option plan for independent directors covering 6,000 shares of Common Stock.  As of September 30, 2012, the options had a weighted average exercise price of $28.86 per share (ranging from $12.14 per share to $41.74 per share), a weighted average remaining contractual term of 2.8 years, and an aggregate intrinsic value of $138,160 (based on a market price at September 30, 2012 of $51.89 per share).  No options were granted during the nine months ended September 30, 2012 or 2011.

Non-Equity Award Plans

The Compensation Committee of the Board has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs.  The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO

11

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

interest in the production developed, directly or indirectly, by the participants.  The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (“APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas.  Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”).  At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships.  Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan.  We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements.  Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.

The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations.  The wells subject to an APO Reward Plan are not included in the APO Incentive Plan.  Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan.  Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area.  Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan.  To date, we have granted awards under the APO Reward Plan in 13 specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to April 1, 2011.  Of these 13 awards, one award fully vested November 4, 2011, three awards fully vested August 9, 2012, three awards will fully vest on May 5, 2013 and six awards will fully vest on June 1, 2013.

In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the after-payout cash flow from a 22.5% working interest in one well. As of October 25, 2011, the plan was fully vested and 100% of subsequent quarterly bonus amounts are payable to participants.

To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each award.  The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.

We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the vesting periods, which range from two years to five years. We recorded a $2.2 million credit to compensation expense for the three months ended September 30, 2012 and a $1.1 million charge to compensation expense for the three months ended September 30, 2011 in connection with all non-equity award plans. We recorded compensation expense of $2.2 million for the nine months ended September 30, 2012 and $6.1 million for the nine months ended September 30, 2011 in connection with all non-equity award plans. Aggregate compensation under non-equity award plans is reflected on the balance sheet as detailed in the following schedule:

	September 30, 2012		December 31, 2011
	(In thousands)
Current liabilities:
Accrued liabilities and other	$	2,207	$	1,994
Non-current liabilities:
Accrued compensation under non-equity award plans	22,675		20,757
Total accrued compensation under non-equity award plans	$	24,882	$	22,751

12

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Derivatives

Commodity Derivatives

From time to time, we utilize commodity derivatives in the form of swap contracts to attempt to optimize the price received for our oil and gas production.  Under swap contracts, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty.  Commodity derivatives are settled monthly as the contract production periods mature.

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 30, 2012.  The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil			Gas
	Bbls	Price		MMBtu (a)	Price
Production Period:
4th Quarter 2012	702,000	$	90.40	—	$	—
2013	1,913,000	$	97.20	1,480,000	$	3.34
2014	600,000	$	99.30	—	$	—
	3,215,000			1,480,000

(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

Accounting For Derivatives

We did not designate any of our currently open commodity derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in our statements of operations and comprehensive income (loss).

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of September 30, 2012
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	945	Current	$	—
	Non-current	7,745		Non-current	—
Total		$	8,690		$	—

13

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Fair Value of Derivative Instruments as of December 31, 2011
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	—	Current	$	5,633
	Non-current	—		Non-current	494
Total		$	—		$	6,127

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	September 30, 2012
	Assets			Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	18,655		$	9,965
Effects of netting arrangements	(9,965		)	(9,965		)
Fair value of derivatives — net presentation	$	8,690		$	—

	December 31, 2011
	Assets			Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	26		$	6,153
Effects of netting arrangements	(26		)	(26		)
Fair value of derivatives — net presentation	$	—		$	6,127

All of our derivative contracts are with JPMorgan Chase Bank, N.A.  We have elected to net the outstanding positions with this counterparty between current and noncurrent assets or liabilities since we have the right to settle these positions on a net basis.

Effect of Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss)

	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended									Nine Months Ended
Location of Gain or (Loss)	September 30, 2012									September 30, 2012
Recognized in Earnings	Realized			Unrealized			Total			Realized			Unrealized		Total
				(In thousands)									(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives	$	(1,390	)	$	(20,511	)	$	(21,901	)	$	(4,961	)	$	14,817	$	9,856
Total	$	(1,390	)	$	(20,511	)	$	(21,901	)	$	(4,961	)	$	14,817	$	9,856

14

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended						Nine Months Ended
Location of Gain or (Loss)	September 30, 2011						September 30, 2011
Recognized in Earnings	Realized		Unrealized		Total		Realized			Unrealized		Total
			(In thousands)							(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives	$	1,188	$	91,098	$	92,286	$	(7,901	)	$	82,029	$	74,128
Total	$	1,188	$	91,098	$	92,286	$	(7,901	)	$	82,029	$	74,128

9. Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments.  Indebtedness under our revolving credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive.

Fair Value Measurements

We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements.  Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.  We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value.

Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows:

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

Level 2 - Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level 3 - Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

15

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The financial assets and liabilities measured on a recurring basis at September 30, 2012 and December 31, 2011 were commodity derivatives.  The fair value of all derivative contracts is reflected on the balance sheet as detailed in the following schedule:

	September 30, 2012		December 31, 2011
	Significant Other		Significant Other
	Observable Inputs		Observable Inputs
Description	(Level 2)		(Level 2)
	(In thousands)
Assets:
Fair value of commodity derivatives	$	8,690	$	—
Total assets	$	8,690	$	—
Liabilities:
Fair value of commodity derivatives	$	—	$	6,127
Total liabilities	$	—	$	6,127

Fair Value of Other Financial Instruments

We estimate the fair value of our 2019 Senior Notes using quoted market prices (Level 1 inputs). Fair value is compared to the carrying value in the table below:

	September 30, 2012				December 31, 2011
	Carrying		Estimated		Carrying		Estimated
Description	Amount		Fair Value		Amount		Fair Value
	(In thousands)
7.75% Senior Notes due 2019	$	349,572	$	350,900	$	349,535	$	334,300

10. Income Taxes

Our effective federal and state income tax expense rate for the nine months ended September 30, 2012 of 35.7% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

We file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions.  Our tax returns for fiscal years after 2009 currently remain subject to examination by appropriate taxing authorities.  None of our income tax returns are under examination at this time.

16

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Sales of Assets and Impairments of Inventory

Net gain (loss) on sales of assets and impairment of inventory for the three months and nine months ended September 30, 2012 and September 30, 2011 are as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(In thousands)						(In thousands)
Gain on sales of assets	$	106		$	49		$	543		$	14,570
Loss on sales of assets and impairment of inventory:
Loss on sales of assets	(38		)	(20		)	(38		)	(138		)
Impairment of inventory	(169		)	(94		)	(447		)	(279		)
	(207		)	(114		)	(485		)	(417		)
Net gain (loss)	$	(101	)	$	(65	)	$	58		$	14,153

In February 2011, we sold two2,000 horsepower drilling rigs and related equipment for $22 million of total consideration.  In connection with the sale, we recorded a gain of $13.2 million during the first quarter of 2011.  Proceeds from the sale consisted of $11 million cash and an $11 million promissory note that was subsequently exchanged for a membership interest in Dalea Investment Group, LLC in June 2012 (see Note 12).

We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities.  Inventory is carried at the lower of average cost or estimated fair market value.  We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards.  To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment.  We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory.  If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.

12. Investment in Dalea Investment Group, LLC

In June 2012, we cancelled an $11 million note receivable (see Note 11) in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC (“Dalea”), an international oilfield services company formed in March 2012.  Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea is carried at cost of $11 million.   We have not estimated the fair value of our investment in Dalea because there have been no identified events or changes in circumstances that may have had a significant effect on its carrying value and because it is not practicable to estimate its fair value at this time.

17

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Costs of Oil and Gas Properties

The following sets forth the net capitalized costs for oil and gas properties as of September 30, 2012 and December 31, 2011.

	September 30, 2012			December 31, 2011
	(In thousands)
Proved properties	$	2,410,409		$	2,021,181
Unproved properties	87,057			81,904
Total capitalized costs	2,497,466			2,103,085
Accumulated depletion	(1,198,605		)	(1,095,197		)
Net capitalized costs	$	1,298,861		$	1,007,888

14. Impairment of Property and Equipment

We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value.  The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset.  We categorize the measurement of fair value of these assets as Level 3 inputs.  We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: discounted cash flow method, flowing daily production method and proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances.  There were no provisions for impairment of proved properties for the three months ended September 30, 2012, and we recorded provisions for impairment of proved properties of $5.7 million for the nine months ended September 30, 2012, $5 million for the three months ended September 30, 2011, and $9.5 million for the nine months ended September 30, 2011.  These impairments were related to non-core areas in the Permian Basin to reduce the carrying values of those properties to their estimated fair value for the three months and nine months ended September 30, 2012 and 2011, respectively.

Unproved properties are nonproducing and do not have estimable cash flow streams. Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to the proximity of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors. Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects. Based on the assessments previously discussed, we will impair our unproved oil and gas properties when we determine that a prospect’s carrying value exceeds its estimated fair value. We categorize the measurement of fair value of unproved properties as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $187,000 for the three months ended September 30, 2012, $711,000 for the nine months ended September 30, 2012, $832,000 for the three months ended September 30, 2011 and $1.1 million for the nine months ended September 30, 2011, and charged these impairments to exploration costs in the accompanying statements of operations and comprehensive income (loss).

18

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. Segment Information

We have two reportable operating segments, which are oil and gas exploration and production and contract drilling services.

The following tables present selected financial information regarding our operating segments for the three-month and nine-month periods ended September 30, 2012 and 2011.

For the Three Months Ended
September 30, 2012
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	102,415		$	14,869		$	(9,521	)	$	107,763
Depreciation, depletion and amortization (a)	35,580			3,666			(1,585		)	37,661
Other operating expenses (b)	43,117			13,169			(7,757		)	48,529
Interest expense	9,786			—			—			9,786
Other (income) expense	22,463			(3		)	—			22,460
Income (loss) before income taxes	(8,531		)	(1,963		)	(179		)	(10,673		)
Income tax (expense) benefit	2,810			687			—			3,497
Net income (loss)	$	(5,721	)	$	(1,276	)	$	(179	)	$	(7,176	)
Total assets	$	1,504,338		$	63,731		$	(21,530	)	$	1,546,539
Additions to property and equipment	$	107,178		$	3,023		$	(179	)	$	110,022

For the Nine Months Ended
September 30, 2012
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	309,964		$	46,134		$	(34,656	)	$	321,442
Depreciation, depletion and amortization (a)	104,416			10,703			(5,922		)	109,197
Other operating expenses (b)	130,668			40,963			(28,591		)	143,040
Interest expense	27,817			—			—			27,817
Other (income) expense	(10,592		)	(3		)	—			(10,595		)
Income (loss) before income taxes	57,655			(5,529		)	(143		)	51,983
Income tax (expense) benefit	(20,493		)	1,935			—			(18,558		)
Net income (loss)	$	37,162		$	(3,594	)	$	(143	)	$	33,425
Total assets	$	1,504,338		$	63,731		$	(21,530	)	$	1,546,539
Additions to property and equipment	$	419,094		$	12,614		$	(143	)	$	431,565

19

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For the Three Months Ended
September 30, 2011
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	100,135		$	13,979		$	(13,050	)	$	101,064
Depreciation, depletion and amortization (a)	30,267			3,285			(2,616		)	30,936
Other operating expenses (b)	35,513			11,639			(9,902		)	37,250
Interest expense	8,717			—			—			8,717
Other (income) expense	(91,579		)	(327		)	—			(91,906		)
Income (loss) before income taxes	117,217			(618		)	(532		)	116,067
Income tax (expense) benefit	(41,760		)	216			—			(41,544		)
Net income (loss)	$	75,457		$	(402	)	$	(532	)	$	74,523
Total assets	$	1,166,492		$	59,997		$	(11,167	)	$	1,215,322
Additions to property and equipment	$	127,252		$	6,999		$	(532	)	$	133,719

For the Nine Months Ended
September 30, 2011
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	316,166		$	38,772		$	(35,158	)	$	319,780
Depreciation, depletion and amortization (a)	82,832			9,107			(7,493		)	84,446
Other operating expenses (b)	108,577			31,823			(27,238		)	113,162
Interest expense	24,304			—			—			24,304
Other (income) expense	(58,592		)	(13,549		)	—			(72,141		)
Income (loss) before income taxes	159,045			11,391			(427		)	170,009
Income tax (expense) benefit	(56,706		)	(3,987		)	—			(60,693		)
Net income (loss)	$	102,339		$	7,404		$	(427	)	$	109,316
Total assets	$	1,166,492		$	59,997		$	(11,167	)	$	1,215,322
Additions to property and equipment	$	303,537		$	13,563		$	(427	)	$	316,673

(a) Includes impairment of property and equipment.

(b) Includes the following expenses: production, exploration, natural gas services, drilling rig services, accretion of asset retirement obligations, general and administrative and loss on sales of assets and impairment of inventory.

20

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Guarantor Financial Information

In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes (see Note 3).  Presented below is condensed consolidated financial information of CWEI (“Issuer”) and the Issuer’s material wholly owned subsidiaries, all of which have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes and are referred to as “Guarantor Subsidiaries” in the following condensed consolidating financial statements.  We have reclassified amounts in the previously reported condensed consolidating financial statements in this Note 16 between the Issuer and the Guarantor Subsidiaries to conform to the current year presentation, which includes applying equity-method accounting for the investment in subsidiaries at the Issuer, and allocating appropriate income taxes to the Guarantor Subsidiaries.

The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated.

Condensed Consolidating Balance Sheet September 30, 2012 (Unaudited) (Dollars in thousands)
	Issuer		Guarantor Subsidiaries		Adjustments/ Eliminations			Consolidated
Current assets	$	139,981	$	216,612	$	(225,110	)	$	131,483
Property and equipment, net	1,011,179		369,703		—			1,380,882
Investments in subsidiaries	298,527		—		(298,527		)	—
Fair value of derivatives	7,745		—		—			7,745
Other assets	12,877		13,552		—			26,429
Total assets	$	1,470,309	$	599,867	$	(523,637	)	$	1,546,539
Current liabilities	$	245,366	$	113,510	$	(225,110	)	$	133,766
Non-current liabilities:
Long-term debt	769,572		—		—			769,572
Deferred income taxes	144,074		117,139		(109,191		)	152,022
Other	43,562		70,691		—			114,253
	957,208		187,830		(109,191		)	1,035,847
Equity	267,735		298,527		(189,336		)	376,926
Total liabilities and equity	$	1,470,309	$	599,867	$	(523,637	)	$	1,546,539

21

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet December 31, 2011 (Dollars in thousands)
	Issuer		Guarantor Subsidiaries		Adjustments/ Eliminations			Consolidated
Current assets	$	142,102	$	164,515	$	(163,674	)	$	142,943
Property and equipment, net	737,562		329,989		—			1,067,551
Investments in subsidiaries	271,342		—		(271,342		)	—
Other assets	13,538		2,239		—			15,777
Total assets	$	1,164,544	$	496,743	$	(435,016	)	$	1,226,271
Current liabilities	$	233,729	$	86,175	$	(163,674	)	$	156,230
Non-current liabilities:
Long-term debt	529,535		—		—			529,535
Fair value of derivatives	494		—		—			494
Deferred income taxes	141,923		111,662		(119,376		)	134,209
Other	34,738		27,564		—			62,302
	706,690		139,226		(119,376		)	726,540
Equity	224,125		271,342		(151,966		)	343,501
Total liabilities and equity	$	1,164,544	$	496,743	$	(435,016	)	$	1,226,271

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended September 30, 2012 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated
Total revenue	$	74,129		$	34,065		$	(431	)	$	107,763
Costs and expenses	57,952			28,669			(431		)	86,190
Operating income (loss)	16,177			5,396			—			21,573
Other income (expense)	(32,431		)	185			—			(32,246		)
Equity in earnings of subsidiaries	3,628			—			(3,628		)	—
Income tax (expense) benefit	5,450			(1,953		)	—			3,497
Net income (loss)	$	(7,176	)	$	3,628		$	(3,628	)	$	(7,176	)

22

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2012 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated
Total revenue	$	222,570		$	99,896		$	(1,024	)	$	321,442
Costs and expenses	166,584			86,677			(1,024		)	252,237
Operating income (loss)	55,986			13,219			—			69,205
Other income (expense)	(19,672		)	2,450			—			(17,222		)
Equity in earnings of subsidiaries	10,185			—			(10,185		)	—
Income tax (expense) benefit	(13,074		)	(5,484		)	—			(18,558		)
Net income (loss)	$	33,425		$	10,185		$	(10,185	)	$	33,425

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended September 30, 2011 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated
Total revenue	$	68,727		$	32,561		$	(224	)	$	101,064
Costs and expenses	44,290			24,120			(224		)	68,186
Operating income (loss)	24,437			8,441			—			32,878
Other income (expense)	81,512			1,677			—			83,189
Equity in earnings of subsidiaries	6,576			—			(6,576		)	—
Income tax (expense) benefit	(38,002		)	(3,542		)	—			(41,544		)
Net income (loss)	$	74,523		$	6,576		$	(6,576	)	$	74,523

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2011 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated
Total revenue	$	205,173		$	115,301		$	(694	)	$	319,780
Costs and expenses	127,475			70,827			(694		)	197,608
Operating income (loss)	77,698			44,474			—			122,172
Other income (expense)	42,789			5,048			—			47,837
Equity in earnings of subsidiaries	32,189			—			(32,189		)	—
Income tax (expense) benefit	(43,360		)	(17,333		)	—			(60,693		)
Net income (loss)	$	109,316		$	32,189		$	(32,189	)	$	109,316

23

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2012 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated
Operating activities	$	78,864		$	73,097		$	5,922		$	157,883
Investing activities	(359,332		)	(27,460		)	(5,922		)	(392,714		)
Financing activities	286,360			(46,360		)	—			240,000
Net increase (decrease) in cash and cash equivalents	5,892			(723		)	—			5,169
Cash at beginning of period	12,853			4,672			—			17,525
Cash at end of period	$	18,745		$	3,949		$	—		$	22,694

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2011 (Unaudited) (Dollars in thousands)
	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated
Operating activities	$	115,607		$	52,187		$	7,493		$	175,287
Investing activities	(262,938		)	3,134			(7,493		)	(267,297		)
Financing activities	172,452			(53,138		)	—			119,314
Net increase (decrease) in cash and cash equivalents	25,121			2,183			—			27,304
Cash at beginning of period	5,040			3,680			—			8,720
Cash at end of period	$	30,161		$	5,863		$	—		$	36,024

17. Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of September 30, 2012 and have determined that no events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

24

Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2011.  Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.

Forward-Looking Statements

The information in this Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should, could or may occur in the future are forward-looking statements.  These forward-looking statements are based on management’s current expectations and belief, based on currently available information, as to the outcome and timing of future events and their effect on us.  While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate.  All statements concerning our expectations for future operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions.  Our forward-looking statements involve significant risks and uncertainties, many of which are beyond our control, and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our Form 10-K for the year ended December 31, 2011 and in this Form 10-Q.

Forward-looking statements appear in a number of places and include statements with respect to, among other things:

•  estimates of our oil and gas reserves;

• estimates of our future oil and gas production, including estimates of any increases or decreases in production;

• planned capital expenditures and the availability of capital resources to fund those expenditures;

• our outlook on oil and gas prices;

• our outlook on domestic and worldwide economic conditions;

• our access to capital and our anticipated liquidity;

• our future business strategy and other plans and objectives for future operations;

• the impact of political and regulatory developments;

• our assessment of counterparty risks and the ability of our counterparties to perform their future obligations;

• estimates of the impact of new accounting pronouncements on earnings in future periods; and

• our future financial condition or results of operations and our future revenues and expenses.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, incident to the exploration for and development, production and marketing of oil and gas.  These risks include, but are not limited to:

• the possibility of unsuccessful exploration and development drilling activities;

• our ability to replace and sustain production;

• commodity price volatility;

• domestic and worldwide economic conditions;

25

• the availability of capital on economic terms to fund our capital expenditures and acquisitions;

• our level of indebtedness;

• the impact of the past or future economic recessions on our business operations, financial condition and ability to raise capital;

• declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our revolving credit facility and impairments;

• the ability of financial counterparties to perform or fulfill their obligations under existing agreements;

• the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures;

• drilling and other operating risks;

• hurricanes and other weather conditions;

• lack of availability of goods and services;

• regulatory and environmental risks associated with drilling and production activities;

• the adverse effects of changes in applicable tax, environmental and other regulatory legislation; and

• the other risks described in our Form 10-K for the year ended December 31, 2011 and in this Form 10-Q.

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way.  The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.  If significant, these revisions would change the schedule of any further production and development drilling.  Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered.

As previously discussed, should one or more of the risks or uncertainties described above or elsewhere in the Form 10-K for the year ended December 31, 2011 and in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof.  We specifically disclaim all responsibility to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety after the date made, whether as a result of new information, future events or otherwise, except as required by law.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

Overview

We are engaged in developmental drilling in two primary oil-prone regions, the Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities.  One core area of the Permian Basin is our Bone Springs/Wolfcamp play (“Wolfbone”) located in the Delaware Basin on the western edge of the Permian Basin.  Also included in the Permian Basin is our Wolfberry drilling program. We are also continuing to exploit Eagle Ford Shale drilling opportunities on our extensive acreage position in the Giddings Area of East Central Texas. During the nine months ended September 30, 2012, we spent $359.1 million on exploration and development activities.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the third quarter of 2012 and the outlook for the remainder of 2012.

26

• Our oil and gas sales increased $1.9 million, or 2%, from the third quarter2011.  Production variances accounted for $6.3 million of the increase and price variances accounted for a $6.9 million decrease. In addition, oil and gas sales includes $2.5 million of amortized deferred revenue attributable to the volumetric production payment (“VPP”) granted March 1, 2012 to finance the merger consideration payable in connection with the mergers of each of 24 limited partnerships of which Southwest Royalties, Inc. (“SWR”) was the general partner into SWR (“SWR Mergers”).

• Our oil production increased 5% compared to the third quarter2011 while gas production declined 8%.  Our combined oil and gas production for the third quarter of 2012 increased 5% on a barrels of oil equivalent (“BOE”) basis compared to the same period in 2011. The increase in oil production and the decline in gas production are indicative of our current emphasis on the development of oil reserves in the Permian Basin.

• Production costs increased 34% or $8.3 million for the third quarter of 2012 compared to the third quarter of 2011 due primarily to a combination of more producing wells and rising costs of field services, including salt water disposal costs.

• We recorded a $21.9 million net loss on derivatives in the third quarter of 2012, consisting of a $20.5 million unrealized loss for changes in mark-to-market valuations and a $1.4 million realized loss on settled contracts.  For the same period in 2011, we recorded a $92.3 million net gain on derivatives, consisting of a $91.1 million unrealized gain for changes in mark-to-market valuations and a $1.2 million realized gain on settled contracts.  Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

• Depreciation, depletion and amortization expense increased 45% to $37.7 million in the third quarter of 2012 versus $25.9 million in the third quarter of 2011 due primarily to a 33% increase in the average depletion rate per BOE of production.  Most of the increase related to the Company’s Wolfbone play in Reeves County, Texas.

• General and administrative (“G&A”) expenses were $5.8 million in the third quarter of 2012 compared to $7.1 million in the third quarter of 2011.  Non-cash employee compensation expense from incentive compensation plans accounted for a credit to expense of $2.2 million in the third quarter of 2012 versus $1.1 million expense in the third quarter of 2011.  G&A expenses, excluding non-cash employee compensation expense, increased to $8 million in the third quarter of 2012 from $6 million in the third quarter of 2011 due primarily to higher personnel costs and a $1 million contribution to a 527 organization.

Recent Exploration and Development Activities

Overview

Since the second quarter of 2009, we have been primarily committed to drilling developmental oil wells in the Permian Basin and the Giddings Area.  We currently plan to spend approximately $428.9 million on exploration and development activities during fiscal 2012, excluding expenditures for mid-stream facilities.  Our actual expenditures during 2012 may vary significantly from these estimates since our plans for exploration and development activities may change during the remainder of the year.  Factors, such as drilling results, changes in operating margins, and the availability of capital resources and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2012.

Core Areas

Permian Basin

The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period.  The Permian Basin covers an area approximately 250 miles wide and 350 miles long and contains commercial accumulations of oil and gas in multiple stratigraphic horizons at depths ranging from 1,000 feet to over 25,000 feet.  The Permian Basin is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons and enhanced recovery potential.  Although many fields in the Permian Basin have been heavily exploited in the past, higher product prices and improved technology (including deep horizontal drilling) continue to attract high levels of drilling and recompletion activities.  We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc.  This acquisition provided us with an inventory of potential drilling and recompletion activities.

We spent $260.8 million in the Permian Basin during the first nine months of 2012 on drilling and completion activities and $48.6 million on leasing and seismic activities.  We drilled and completed 71 gross (65.2 net) operated wells in the Permian

27

Basin and conducted various remedial operations on other wells during the first nine months of 2012.  We currently plan to spend approximately $362.7 million on drilling and leasing activities in this area during fiscal 2012.  Following is a discussion of our principal assets in the Permian Basin.

Wolfbone

We have a significant acreage position in the Wolfbone play located in the Delaware Basin on the western edge of the Permian Basin.  A Wolfbone well is a well that commingles production from the Bone Springs and Wolfcamp formations which are typically encountered at depths of 8,000 to 13,000 feet.  These Permian aged formations in the Delaware Basin are comprised of limestone and sandstone.  In March 2011, we entered into a farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”) in southern Reeves County, Texas with a term of five years.  For each well that we drill in the farm-in area that meets certain specified requirements (each, a “carried well”), Chesapeake, or its successors to this agreement, will retain a 25% carried interest, bearing none of the costs to drill and complete a carried well, and we will earn an undivided 75% interest in 640 net acres within the farm-in area.  Under the farm-in agreement, we are obligated to drill or commence drilling operations on at least 20 carried wells each year during the term of the agreement to a maximum of 100 carried wells.  Excess wells drilled during any year may be applied towards our drilling obligations in the next year.  To date, we have drilled 44 carried wells under this agreement.

We spent approximately $183.6 million on drilling and completion activities and $37.1 million for leasing activities in the Wolfbone play during the first nine months of 2012.  To date, we have accumulated more than 60,000 net acres in Reeves County through a combination of acreage earned from the Chesapeake farm-in and direct leasing activities and have commenced drilling operations on 64 vertical and 11 horizontal wells.  We plan to spend approximately $217.8 million on drilling and completion activities and $43.1 million on leasing activities in the Wolfbone play during 2012.  We are currently utilizing four rigs in this area and plan to reduce the rig count to two through the remainder of 2012.

Wolfberry

Another focal point in the Permian Basin is the drilling of Wolfberry wells in the Midland Basin.  Wolfberry is a term applied to the combined production from the Spraberry and Wolfcamp formations, which are generally found at depths of 7,500 to 10,500 feet.  These formations are comprised of a sequence of basinal, interbedded shales and carbonates.  We spent approximately $53.5 million on Wolfberry drilling and completion activities and approximately $900,000 on leasing activities during the first nine months of 2012.  We currently have one of our rigs drilling Wolfberry wells and plan to spend approximately $59.9 million during 2012 for drilling, completion and leasing activities.

East Permian Basin

We have approximately 40,000 net acres in Glasscock and Sterling Counties, Texas that are prospective for horizontal drilling to the Cline Shale formation. Initially leased as a Wolfberry play, we have drilled and completed 12 vertical Wolfberry wells to date and plan to drill additional wells in selected areas of the field. In October 2012, we completed the Foster 240H, a horizontal Cline Shale well in Glasscock County. We are currently evaluating the initial flow rates from this well to determine the if this acreage block will be prospective for a Cline Shale developmental drilling program.

Giddings Area

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area.  Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas.  Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale, and Taylor formations. During the first nine months of 2012, we spent approximately $31.7 million in the Giddings Area on drilling and leasing activities and currently plan to spend approximately $39.2 million on similar drilling activities in this area during 2012.  Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

We have concentrated our recent drilling activities in the Giddings Area on the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana.  The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet.  Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity by intersecting multiple

28

zones.  Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations.  The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling.  These in-fill wells are considered lower risk as compared to exploratory wells.  We initiated a water fracturing program on certain wells in June 2011 to enhance productivity on certain wells.  We are currently evaluating further opportunities for Austin Chalk production in the Giddings Area.

Eagle Ford Shale

The Eagle Ford Shale is a formation immediately beneath the Austin Chalk formation.  In 2010, we drilled and completed four producing wells in Burleson and Lee Counties, Texas using various low-cost fracturing techniques. Production from these wells did not meet our expectations for a successful developmental drilling program. We then drilled and completed two wells in Wilson County, the Hosek #1 in the fourth quarter of 2011 and the Ortmann Unit #1 in the second quarter of 2012. We completed the Wilson County wells utilizing a cemented liner and a large, multi-stage fracturing technique and achieved significantly improved results. In the third quarter of 2012, we completed the Balcar Unit #1 in Lee County in a similar manner to the Wilson County wells. We are currently evaluating the production rates from the Balcar Unit #1 to assess the economic viability of a multiple well Eagle Ford Shale drilling program across our significant acreage position in Robertson, Burleson and Lee Counties.

South Louisiana

In the first nine months of 2012, we drilled and completed the Hassinger ETAL #1, an exploratory well in Jefferson Parish, Louisiana which is currently producing.  Storm damage repairs from Hurricane Issac are progressing and should be completed mid-November. We plan to spend $9.9 million for 2012 in connection with drilling and leasing activities in South Louisiana.

Facilities

We have completed construction on the core sections of our gas pipeline, oil pipeline and salt water disposal systems in Reeves County, Texas. Most of our wells in this area are currently connected to the gas pipeline and salt water disposal system, and we expect to activate the oil pipeline late in the fourth quarter of 2012. These facilities will be expanded to accommodate new wells as we continue our development in the area. We spent $21.9 million in the first nine months of 2012 and expect to spend $24.5 million during 2012 on these systems.

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we operate 14 drilling rigs, 12 of which we own, and two of which we lease under long-term contracts.  We believe that owning our own rigs helps control our cost structure and provides us flexibility to take advantage of drilling opportunities on a timely basis.  The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties from time to time.  We were using five of our rigs to drill wells in our developmental drilling programs, three rigs were working for third parties and the remaining six rigs were in the yard as of October 26, 2012.  We currently plan to spend $15.1 million in 2012 to refurbish rigs and upgrade our drilling equipment.

Known Trends and Uncertainties

We have an extensive acreage position within the Permian Basin with a large portion of that acreage currently held by production.  We are continuously seeking other opportunities for growth in the Permian Basin, and believe that our holdings in this region provide us with many viable possibilities for exploration and development activities beyond our current drilling programs.

Our developmental drilling programs are very sensitive to oil prices and drilling costs.  We attempt to control costs through drilling efficiencies by the use of our own rigs, purchasing casing and tubing at periods when we believe prices are suitable and working with service providers to receive acceptable unit costs.  We plan to continue these programs as long as oil prices remain favorable.  In order to continue drilling in these areas, we must be able to realize an acceptable margin between our expected cash flow from new production and our cost to drill new wells.  If any combination of falling oil prices and rising drilling costs occur in future periods, we may discontinue a program until margins return to acceptable levels.

29

Supplemental Information

The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-Q with data that is not readily available from those statements.

	Three Months Ended September 30,
	2012			2011
Oil and Gas Production Data:
Oil (MBbls)	993			945
Gas (MMcf)	2,010			2,195
Natural gas liquids (MBbls)	115			61
Total (MBOE)	1,443			1,372
Average Realized Prices (a) (b):
Oil ($/Bbl)	$	89.48		$	89.36
Gas ($/Mcf)	$	3.29		$	5.46
Natural gas liquids ($/Bbl)	$	31.37		$	54.36
Gain (Loss) on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil: Net realized loss	$	(1,390	)	$	(3,292	)
Per unit produced ($/Bbl)	$	(1.40	)	$	(3.48	)
Gas: Net realized gain	$	—		$	4,481
Per unit produced ($/Mcf)	$	—		$	2.04
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	2,018			170
Other	5,247			6,152
Austin Chalk/Eagle Ford Shale	3,199			3,458
Other	329			492
Total	10,793			10,272
Gas (Mcf):
Permian Basin Area:
Delaware Basin	1,449			27
Other	12,246			12,885
Austin Chalk/Eagle Ford Shale	1,793			1,958
Other	6,360			8,989
Total	21,848			23,859
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	257			—
Other	711			366
Austin Chalk/Eagle Ford Shale	232			215
Other	50			82
Total	1,250			663
(Continued)

30

	Three Months Ended September 30,
	2012			2011
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	32		$	16
Deep Bossier	111			—
Permian Basin	53			642
Other	110			598
Total	306			1,256
Seismic and other	2,710			1,842
Total exploration costs	$	3,016		$	3,098
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	35,145		$	25,042
Contract drilling depreciation	2,082			669
Other depreciation	434			190
Total depreciation, depletion, and amortization	$	37,661		$	25,901
Oil and Gas Costs ($/BOE Produced):
Production costs	$	22.57		$	17.70
Production costs (excluding production taxes)	$	18.99		$	13.84
Oil and gas depletion	$	24.36		$	18.25
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	8,024		$	6,001
Non-cash employee compensation (c)	(2,194		)	1,141
Total	$	5,830		$	7,142
Net Wells Drilled (d):
Exploratory Wells	0.5			1.0
Developmental Wells	23.9			25.9
(Continued)

31

	Nine Months Ended September 30,
	2012			2011
Oil and Gas Production Data:
Oil (MBbls)	2,889			2,730
Gas (MMcf)	6,154			6,569
Natural gas liquids (MBbls)	304			217
Total (MBOE)	4,219			4,042
Average Realized Prices (a) (b):
Oil ($/Bbl)	$	92.62		$	92.70
Gas ($/Mcf)	$	3.46		$	5.42
Natural gas liquids ($/Bbl)	$	40.05		$	53.00
Gain (Loss) on Settled Derivative Contracts (b):
($ in thousands, except per unit)
Oil: Net realized loss	$	(4,961	)	$	(21,989	)
Per unit produced ($/Bbl)	$	(1.72	)	$	(8.05	)
Gas: Net realized gain	$	—		$	14,088
Per unit produced ($/Mcf)	$	—		$	2.14
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	1,575			61
Other	5,473			6,003
Austin Chalk/Eagle Ford Shale	3,115			3,418
Other	378			518
Total	10,541			10,000
Gas (Mcf):
Permian Basin Area:
Delaware Basin	780			20
Other	12,797			12,991
Austin Chalk/Eagle Ford Shale	1,997			2,029
Other	6,881			9,022
Total	22,455			24,062
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	117			—
Other	687			500
Austin Chalk/Eagle Ford Shale	241			208
Other	63			87
Total	1,108			795
(Continued)

32

	Nine Months Ended September 30,
	2012		2011
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	344	$	722
Deep Bossier	1,322		—
Permian Basin	349		642
Other	277		943
Total	2,292		2,307
Seismic and other	5,445		5,287
Total exploration costs	$	7,737	$	7,594
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	97,698	$	72,797
Contract drilling depreciation	4,781		1,614
Other depreciation	1,007		576
Total depreciation, depletion, and amortization	$	103,486	$	74,987
Oil and Gas Costs ($/BOE Produced):
Production costs	$	22.27	$	18.61
Production costs (excluding production taxes)	$	18.55	$	14.77
Oil and gas depletion	$	23.16	$	18.01
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	22,933	$	16,574
Non-cash employee compensation (c)	2,200		6,104
Total	$	25,133	$	22,678
Net Wells Drilled (d):
Exploratory Wells	3.8		1.5
Developmental Wells	76.1		75.7
________

(a) Oil and gas sales for 2012 includes $2.5 million for the three months ended September 30, 2012 and $5.9 million for the nine months ended September 30, 2012 of amortized deferred revenue attributable to the volumetric production payment (“VPP”) effective March 1, 2012. The calculation of average realized sales prices for 2012 excludes production of 32,788 barrels of oil and 14,826 Mcf of gas for the three months ended September 30, 2012 and 77,755 barrels of oil and 32,000 Mcf of gas for the nine months ended September 30, 2012 associated with the VPP.

(b) No derivatives were designated as cash flow hedges in the table above.  All gains or losses on settled derivatives were included in other income (expense) - gain (loss) on derivatives.

(c) Non-cash employee compensation relates to the Company’s non-equity award plans.

(d) Excludes wells being drilled or completed at the end of each period.

Operating Results — Three-Month Periods

The following discussion compares our results for the three months ended September 30, 2012 to the comparative period in 2011.  Unless otherwise indicated, references to 2012 and 2011 within this section refer to the respective quarterly period.

33

Oil and gas operating results

Oil and gas sales in 2012 increased $1.9 million, or 2%, from 2011.  Production variances accounted for a $6.3 million increase and price variances accounted for a $6.9 million decrease.  In addition, oil and gas sales in 2012 includes $2.5 million of amortized deferred revenue attributable to the VPP granted effective March 1, 2012 in connection with the SWR Mergers.  Production in 2012 (on a BOE basis) increased 5% compared to 2011.  Oil production increased 5% in 2012 from 2011 while gas production decreased 8% in 2012 from 2011.  Most of the decrease in gas production from 2011 levels was attributed to normal production declines from existing wells.  In 2012, our realized oil price was less than 1% higher than 2011, and our realized gas price was 40% lower.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 34% to $32.6 million in 2012 as compared to $24.3 million in 2011.  Production costs, excluding production taxes, accounted for an $8.4 million increase due primarily to a combination of more producing wells and rising costs of field services, including salt water disposal costs.

Oil and gas depletion expense increased $10.1 million from 2011 to 2012 due to an $8.8 million increase related to rate variances and a $1.3 million increase due to production variances.  On a BOE basis, depletion expense increased 33% to $24.36 per BOE in 2012 from $18.25 per BOE in 2011.  Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.  We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

Exploration costs

We follow the successful efforts method of accounting, therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed.  In 2012, we charged to expense $3 million of exploration costs, as compared to $3.1 million in 2011.

Contract Drilling Services

We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development activities.  Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI have been eliminated in our consolidated statements of operations and comprehensive income (loss).  Drilling service costs related to external customers were $5.3 million in 2012 compared to $1.7 million in 2011.

General and Administrative

G&A expenses decreased $1.3 million from $7.1 million in 2011 to $5.8 million in 2012.  Non-cash employee compensation expense related to non-equity incentive plans was a credit to expense of $2.2 million in 2012 compared to $1.1 million expense in 2011.  Lower commodity prices in the third quarter of 2012 resulted in a decrease in estimated future compensation expense from these plans, causing a partial reversal of previously accrued compensation expense.  Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $6 million in 2011 to $8 million in 2012 due primarily to higher personnel costs and a $1 million contribution to a 527 organization.  Higher cash bonuses paid to participants in APO reward plans contributed to the increase in personnel costs.

Interest expense

Interest expense increased 12% from $8.7 million in 2011 to $9.8 million in 2012.  Interest expense associated with our revolving credit facility increased by $2 million due primarily to an increase in borrowings which increased from an average daily principal balance of $101.1 million in 2011 compared to $394.7 million in 2012.  Interest expense decreased by $386,000 as a result of our redemption of $81.8 million of our 7¾% Senior Notes (“2013 Senior Notes”) in August 2011.

Loss on early extinguishment of long-term debt

In September 2011, we recorded a $907,000 loss on early extinguishment of long-term debt consisting of the write-off of debt issuance costs related to the remaining $81.8 million in aggregate principal amount of 2013 Senior Notes we redeemed in August 2011.

34

Gain/loss on derivatives

We did not designate any derivative contracts in 2012 or 2011 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  For the three months ended September 30, 2012, we reported a $21.9 million net loss on derivatives, consisting of a $20.5 million non-cash unrealized loss to mark our derivative positions to their fair value at September 30, 2012 and a $1.4 million realized loss on settled contracts.  For the three months ended September 30, 2011, we reported a $92.3 million net gain on derivatives, consisting of a $91.1 million non-cash unrealized gain to mark our derivative positions to their fair value at September 30, 2011 and a $1.2 million realized gain on settled contracts.  Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net loss of $101,000 on sales of assets and impairment of inventory in 2012 compared to a net loss of $65,000 in 2011.  The 2012 loss related primarily to the the write-down of inventory to its estimated market value at September 30, 2012.  The 2011 loss related primarily to the write-down of inventory to its estimated market value at September 30, 2011.

Income tax expense

Our estimated effective income tax benefit rate in 2012 of 32.8% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

Operating Results — Nine-Month Periods

The following discussion compares our results for the nine months ended September 30, 2012 to the comparative period in 2011.  Unless otherwise indicated, references to 2012 and 2011 within this section refer to the respective nine-month period.

Oil and gas operating results

Oil and gas sales in 2012 increased $7.6 million, or 3%, from 2011.  Production variances accounted for an $18.3 million increase while price variances accounted for a decrease of $16.2 million.  In addition, oil and gas sales in 2012 includes $5.9million of amortized deferred revenue attributable to the VPP granted effective March 1, 2012 in connection with the SWR Mergers.  Production in 2012 (on a BOE basis) increased 4% compared to 2011.  Oil production increased 6% in 2012 from 2011 while gas production decreased 6% in 2012 from 2011.  Most of the decrease in gas production from 2011 levels was attributed to normal production declines from existing wells.  In 2012, our realized oil price was less than 1% lower than 2011, and our realized gas price was 36% lower.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 25% to $93.9 million in 2012 as compared to $75.2 million in 2011.  Production costs, excluding production taxes, accounted for $18.6 million of the increase due to a combination of more producing wells and rising costs of field services, including salt water disposal costs.

Oil and gas depletion expense increased $24.9 million from 2011 to 2012 due to a $21.7 million increase related to rate variances and a $3.2 million increase due to production variances.  On a BOE basis, depletion expense increased 29% to $23.16 per BOE in 2012 from $18.01 per BOE in 2011.  Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.  We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

Exploration costs

We follow the successful efforts method of accounting, therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed.  In 2012, we charged to expense $7.7 million of exploration costs, as compared to $7.6 million in 2011.

Contract Drilling Services

We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development

35

activities.  Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI have been eliminated in our consolidated statements of operations and comprehensive income (loss).  Drilling service costs related to external customers were $12.2 million in 2012 compared to $4.4 million in 2011.

General and Administrative

G&A expenses increased $2.5 million from $22.7 million in 2011 to $25.1 million in 2012.  Non-cash employee compensation expense related to non-equity incentive plans was $2.2 million in 2012 compared to $6.1 million in 2011.  Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $16.6 million in 2011 to $22.9 million in 2012 due to a combination of factors including higher personnel costs, $2.2 million associated with the SWR Mergers, charitable contributions of $1 million and a $1 million contribution to a 527 organization.  Higher cash bonuses paid to participants in APO reward plans contributed to the increase in personnel costs.

Interest expense

Interest expense increased 14% from $24.3 million in 2011 to $27.8 million in 2012.  Interest expense associated with our revolving credit facility increased by $4.1 million due primarily to an increase in borrowings which increased from an average daily principal balance of $97.8 million in 2011 compared to $315.6 million in 2012.  Interest expense related to our 2019 Senior Notes increased $6.3 million related to the issuances in March and April 2011 of $350 million, which was offset by a $6.4 million decrease as a result of our redemption of $225 million 2013 Senior Notes in March and August 2011.

Loss on early extinguishment of long-term debt

In March and August 2011, we redeemed $225 million in aggregate principal amount of 2013 Senior Notes in a tender offer and recorded a $5.5 million loss on early extinguishment of long-term debt consisting of a $2.8 million premium and a $2.7 million write-off of debt issuance costs.

Gain/loss on derivatives

We did not designate any derivative contracts in 2012 or 2011 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  For the nine months ended September 30, 2012, we reported a $9.9 million net gain on derivatives, consisting of a $14.8 million non-cash unrealized gain to mark our derivative positions to their fair value at September 30, 2012 and a $4.9 million realized loss on settled contracts.  For the nine months ended September 30, 2011, we reported a $74.1 million net gain on derivatives, consisting of an $82 million non-cash unrealized gain to mark our derivative positions to their fair value at September 30, 2011 and a $7.9 million realized loss on settled contracts.  Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $58,000 on sales of assets and impairment of inventory in 2012 compared to a net gain of $14.2 million in 2011.  The 2011 gain related primarily to the sale of our two 2,000 horsepower drilling rigs and related equipment for a $13.2 million gain.

Income tax expense

Our estimated effective income tax rate in 2012 of 35.7% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

Liquidity and Capital Resources

Overview

Our primary financial resource is our base of oil and gas reserves.  We pledge our producing oil and gas properties to a syndicate of banks led by JPMorgan Chase Bank, N.A. to secure our revolving credit facility.  The banks establish a borrowing base, in part, by making an estimate of the collateral value of our oil and gas properties.  We borrow funds on the revolving credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program.  Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program

36

in replacing our existing oil and gas reserves.  If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program.  However, we may mitigate the effects of product prices on cash flow through the use of commodity derivatives.

We expect our capital spending in fiscal 2012 to exceed our operating cash flows for fiscal 2012 by approximately $280 million. As a result, the level of funds available under the revolving credit facility may not be sufficient to continue our capital spending in fiscal 2013 at the same pace as we experienced in fiscal 2012. We currently plan to reduce leverage and increase liquidity in fiscal 2013 through a combination of reduced capital spending and divestitures of certain producing properties. See “Alternative capital resources.”

Capital expenditures

The following table summarizes, by area, our actual expenditures for exploration and development activities for the first nine months of 2012 and our planned expenditures for the year ending December 31, 2012.

	Actual Expenditures Nine Months Ended September 30, 2012		Planned Expenditures Year Ended December 31, 2012		2012 Percentage of Total
	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	183,600	$	217,800	51	%
Other	77,200		89,700		21	%
Austin Chalk/Eagle Ford Shale	22,300		26,800		6	%
Other	8,600		10,700		2	%
	291,700		345,000		80	%
Leasing and seismic	67,400		83,900		20	%
Exploration and development	$	359,100	$	428,900	100	%

Our expenditures for exploration and development activities for the nine months ended September 30, 2012 totaled $359.1 million.  We financed these expenditures for the first nine months of 2012 with cash flow from operating activities and $240 million of advances under the revolving credit facility.  We currently plan to spend approximately $428.9 million on exploration and development activities during fiscal 2012 as compared to our previous estimate of $429.3 million. Our actual expenditures during 2012 may vary significantly from these estimates since our plans for exploration and development activities may change during the remainder of the year.  Factors, such as drilling results, changes in operating margins, and the availability of capital resources and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2012.

Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow, combined with funds available to us on the revolving credit facility, will be sufficient to finance our exploration and development activities through 2012.  Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base may be less than expected, cash flow may be less than expected, or capital expenditures may be more than expected.  In the event we lack adequate liquidity to finance our expenditures through 2012, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.

Cash flow provided by operating activities

Substantially all of our cash flow from operating activities is derived from the production of our oil and gas reserves.  We use this cash flow to fund our on-going exploration and development activities in search of new oil and gas reserves.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Cash flow provided by operating activities for the nine months ended September 30, 2012 decreased $17.4 million, or 9.9%, as compared to the corresponding period in 2011 due primarily to a 25% increase in production costs.

37

Revolving credit facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $565 million, limited to the amount of a borrowing base as determined by the banks.  We have historically relied on the revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs.  As long as we have sufficient availability under the revolving credit facility to meet our obligations as they become due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November.  We or the banks may also request an unscheduled borrowing base redetermination at other times during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment to eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.  In May 2012, the banks increased the borrowing base from $475 million to $565 million and increased the maximum credit facility from $500 million to $565 million. The banks also increased the aggregate commitment from $350 million to $475 million in April 2012 and to $555 million in August 2012.

The revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base.  The obligations under the revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries.

At our election, annual interest rates under the revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.75% and 2.75% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.75% and 1.75% per year.  We also pay a commitment fee on the unused portion of the revolving credit facility at a rate between 0.375% and 0.50%.  The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the nine months ended September 30, 2012 was 2.6%.

The revolving credit facility contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens.  One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities (“Consolidated Current Ratio”) of at least 1 to 1.  In computing the Consolidated Current Ratio at any balance sheet date, we must (1) include the amount of funds available under this facility as a current asset, (2) exclude current assets and liabilities related to the fair value of derivatives (non-cash assets or liabilities), and (3) exclude current assets and liabilities attributable to vendor financing transactions, if any.

Working capital computed for loan compliance purposes differs from our working capital computed in accordance with accounting principles generally accepted in the United States (“GAAP”).  Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives.  Our GAAP reported working capital deficit was $2.3 million at September 30, 2012 compared to a deficit of $13.3 million at December 31, 2011.  After giving effect to the adjustments, our working capital computed for loan compliance purposes was $127.7 million at September 30, 2012, as compared to $158.3 million at December 31, 2011.  The following table reconciles our GAAP working capital (deficit) to the working capital computed for loan compliance purposes at September 30, 2012 and December 31, 2011.

	September 30, 2012			December 31, 2011
	(In thousands)
Working capital (deficit) per GAAP	$	(2,283	)	$	(13,287	)
Add funds available under the revolving credit facility	130,950			165,950
Exclude fair value of derivatives classified as current assets or current liabilities	(945		)	5,633
Working capital per loan covenant	$	127,722		$	158,296

38

The revolving credit facility provides that the ratio of our consolidated funded indebtedness to consolidated EBITDAX (the “Leverage Ratio”) (determined as of the last end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.

We were in compliance with all financial and non-financial covenants at September 30, 2012.  However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future.  If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend the revolving credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means.  If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The lending group under the revolving credit facility includes the following institutions:  JPMorgan Chase Bank, N.A., Bank of Scotland plc, Union Bank, N.A., Wells Fargo Bank, N.A., The Royal Bank of Scotland plc, Compass Bank, The Frost National Bank, Natixis, Keybank, N.A. and UBS Loan Finance, LLC.

From time to time, we engage in other transactions with lenders under the revolving credit facility.  Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of September 30, 2012, JPMorgan Chase Bank, N.A. was the only counterparty to our commodity derivative agreements.  Our obligations under existing derivative agreements with our lenders are secured by the security documents executed by the parties under the revolving credit facility.

During the first nine months of 2012, we increased indebtedness outstanding under the revolving credit facility by $240 million.  At September 30, 2012, we had $420 million of borrowings outstanding under the revolving credit facility, leaving $131 million available on the facility after allowing for outstanding letters of credit totaling $4.1 million.  The revolving credit facility matures in November 2015.

Senior Notes

In July 2005, we issued $225 million of aggregate principal amount of 2013 Senior Notes.  The 2013 Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.  In March 2011, we redeemed $143.2 million in aggregate principal amount of 2013 Senior Notes in a tender offer and recorded a $4.6 million loss on early extinguishment of long-term debt consisting of a $2.8 million premium and a $1.8 million write-off of debt issuance costs.  On August 1, 2011, we called at par and redeemed in full the remaining $81.8 million of 2013 Senior Notes and recorded an additional $907,000 loss on early extinguishment of long-term debt related to the write-off of debt issuance costs.

In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes.  The 2019 Senior Notes were issued at face value and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011.  In April 2011, we issued an additional $50 million aggregate principal amount of 2019 Senior Notes with an original issue discount of 1% or $500,000.  We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture governing our 2019 Senior Notes contains covenants that restrict our ability to:  (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business.  One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture.  These covenants are subject to a number of important exceptions and qualifications as described in the Indenture.  We were in compliance with these covenants at September 30, 2012.

Alternative capital resources

We currently expect to reduce our capital spending levels for fiscal 2013 to the extent necessary to be fully funded through a combination of operating cash flow and proceeds from asset sales. Any excess operating cash flow or proceeds from asset sales are expected to be used to reduce the balance on our revolving credit facility.

39

We may also use other capital resources, such as entering into joint venture participation agreements with other industry or financial partners and issuing debt or equity securities in private or public offerings, in order to finance a portion of our capital spending in fiscal 2013. While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

Item 3 - Quantitative and Qualitative Disclosures About Market Risk

Our business is impacted by fluctuations in commodity prices and interest rates.  The following discussion is intended to identify the nature of these market risks, describe our strategy for managing such risks, and to quantify the potential effect of market volatility on our financial condition and results of operations.

Oil and Gas Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market commodity prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, many of which are beyond our control.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.  We cannot predict future oil and gas commodity prices with any degree of certainty.  Sustained weakness in oil and gas commodity prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically.  Any reduction in reserves, including reductions due to commodity price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities.  Similarly, any improvements in oil and gas commodity prices can have a favorable impact on our financial condition, results of operations and capital resources.  Based on December 31, 2011 reserve estimates, we project that a $1 decline in the price per Bbl of oil and a $.50 decline in the price per Mcf of gas from year end 2011 would reduce our gross revenues for the year ending December 31, 2012 by $9.2 million.

From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production.  We do not enter into commodity derivatives for trading purposes.  When using swaps to hedge our oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty.  When purchasing floors, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity.  If the market price is greater than the put strike price, no payments are due from either party.  Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price).  If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price.  If the market price is between the call and the put strike prices, no payments are due from either party.  The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products.  In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements.  We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge.  If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received.  If we terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.

40

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 30, 2012. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil			Gas
	Bbls	Price		MMBtu (a)	Price
Production Period:
4th Quarter 2012	702,000	$	90.40	—	$	—
2013	1,913,000	$	97.20	1,480,000	$	3.34
2014	600,000	$	99.30	—	$	—
	3,215,000			1,480,000

(a) One MMBtu equals one Mcf at a Btu factor of 1,000.

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives.  A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our commodity derivatives by approximately $3.9 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate.  At September 30, 2012, our fixed rate debt maturing 2019 had a carrying value of $349.6 million and an approximate fair value of $350.9 million, based on current market quotes.  We estimate that a hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $17.4 million.  Based on our outstanding variable rate indebtedness at September 30, 2012 of $420 million, a change in interest rates of 100-basis points would affect annual interest payments by $4.2 million.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

In September 2002, our Board adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that our management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the SEC and other communications with our stockholders.  Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

With respect to our disclosure controls and procedures:

• management has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;

• this evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and

• it is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

41

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

42

PART II.  OTHER INFORMATION

Item 1A - Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements.  Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2011, as filed with the U.S. Securities and Exchange Commission on March 5, 2012, and available at www.sec.gov.  Following is an additional risk factor that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements.

Recently approved final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On August 16, 2012, the EPA adopted final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities.  The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015.  For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions.  These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment.  We are currently reviewing this new rule and assessing its potential impacts.  Compliance with these requirements could increase our costs of development and production, though we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

43

Item 6 - Exhibits

Exhibits
**3.1	Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441
**3.2	Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††
**3.3	Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††
**4.1	Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††
**4.2	Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††
**4.3	Registration Rights Agreement, dated March 16, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††
**4.4	Registration Rights Agreement, dated April 29, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on April 29, 2011††
*10.1	Fifth Amendment to Second Amended and Restated Credit Agreement dated August 30, 2012
*31.1	Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
*31.2	Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
***32.1	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*101.INS	XBRL Instance Document
*101.SCH	XBRL Schema Document
*101.CAL	XBRL Calculation Linkbase Document
*101.DEF	XBRL Definition Linkbase Document
*101.LAB	XBRL Labels Linkbase Document
*101.PRE	XBRL Presentation Linkbase Document

* Filed herewith

** Incorporated by reference to the filing indicated

*** Furnished herewith

† Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement

†† Filed under our Commission File No. 001-10924

44

CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

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 thereto duly authorized.

		CLAYTON WILLIAMS ENERGY, INC.
Date:	November 6, 2012	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief Operating Officer
Date:	November 6, 2012	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President and Chief Financial Officer

45

INDEX TO EXHIBITS

Exhibit No.	Description
**3.1	Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441
**3.2	Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††
**3.3	Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††
**4.1	Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††
**4.2	Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††
**4.3	Registration Rights Agreement, dated March 16, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††
**4.4	Registration Rights Agreement, dated April 29, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on April 29, 2011††
*10.1	Fifth Amendment to Second Amended and Restated Credit Agreement dated August 30, 2012
*31.1	Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
*31.2	Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
***32.1	Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*101.INS	XBRL Instance Document
*101.SCH	XBRL Schema Document
*101.CAL	XBRL Calculation Linkbase Document
*101.DEF	XBRL Definition Linkbase Document
*101.LAB	XBRL Labels Linkbase Document
*101.PRE	XBRL Presentation Linkbase Document

* Filed herewith

** Incorporated by reference to the filing indicated

*** Furnished herewith

† Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement

†† Filed under our Commission File No. 001-10924

46