CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q

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EX-31.2 - CERTIFICATION OF CFO - CLAYTON WILLIAMS ENERGY INC /DE	mike3313131_2.htm
EX-31.1 - CERTIFICATION OF CEO - CLAYTON WILLIAMS ENERGY INC /DE	clayton3311131_1.htm
EX-32.1 - CERTIFICATION OF CEO & CFO - CLAYTON WILLIAMS ENERGY INC /DE	claytonmike3311132_1.htm

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 March 31, 2011

¨	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		¨ 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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
	¨ Yes		¨ 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 ¨	Accelerated filer x
	Non-accelerated filer ¨	Smaller reporting company ¨

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

There were 12,162,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of May 6, 2011.

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
		Page

Item 1.	Financial Statements

	Consolidated Balance Sheets as of March 31, 2011
	and December 31, 2010	3

	Consolidated Statements of Operations for the three months
	ended March 31, 2011 and 2010	5

	Consolidated Statement of Stockholders’ Equity for the three months
	ended March 31, 2011	6

	Consolidated Statements of Cash Flows for the three months
	ended March 31, 2011 and 2010	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial
	Condition and Results of Operations	19

Item 3.	Quantitative and Qualitative Disclosures About Market Risks	32

Item 4.	Controls and Procedures	34


PART II. OTHER INFORMATION
Item 1A.	Risk Factors	35

Item 6.	Exhibits	35

	Signatures	37

PART I. FINANCIAL INFORMATION

Item 1 - Financial Statements

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS
	March 31,			December 31,
	2011			2010
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	14,512		$	8,720
Accounts receivable:
Oil and gas sales		37,245			35,361
Joint interest and other, net		12,772			9,893
Affiliates		1,754			796
Inventory		30,707			39,218
Deferred income taxes		2,813			5,074
Assets held for sale		-			8,762
Prepaids and other		15,048			5,997
		114,851			113,821
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		1,792,867			1,707,252
Natural gas gathering and processing systems		18,153			18,153
Contract drilling equipment		60,019			58,486
Other		17,637			17,425
		1,888,676			1,801,316
Less accumulated depreciation, depletion and amortization		(1,060,567	)		(1,034,227	)
Property and equipment, net		828,109			767,089

OTHER ASSETS
Debt issue costs, net		12,945			8,323
Other		1,918			1,684
		14,863			10,007
	$	957,823		$	890,917

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS’ EQUITY
	March 31,		December 31,
	2011		2010
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	63,339	$	74,123
Oil and gas sales		31,905		28,920
Affiliates		946		1,251
Fair value of derivatives		36,175		7,224
Accrued liabilities and other		23,728		22,202
		156,093		133,720
NON-CURRENT LIABILITIES
Long-term debt		428,835		385,000
Deferred income taxes		71,515		78,035
Fair value of derivatives		19,085		3,409
Other		40,692		41,301
		560,127		507,745
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 – 12,155,536 shares in 2011
and 12,154,536 shares in 2010		1,215		1,215
Additional paid-in capital		152,316		152,290
Retained earnings		88,072		95,947
		241,603		249,452
	$	957,823	$	890,917

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share)

	Three Months Ended
	March 31,
	2011			2010
REVENUES
Oil and gas sales	$	94,932		$	79,042
Natural gas services		409			503
Drilling rig services		260			-
Gain on sales of assets		13,572			286
Total revenues		109,173			79,831

COSTS AND EXPENSES
Production		24,820			20,927
Exploration:
Abandonments and impairments		877			2,878
Seismic and other		1,278			1,660
Natural gas services		263			348
Drilling rig services		786			662
Depreciation, depletion and amortization		23,744			25,612
Accretion of abandonment obligations		674			647
General and administrative		12,499			6,224
Loss on sales of assets and impairment
of inventory		196			-
Total costs and expenses		65,137			58,958

Operating income		44,036			20,873

OTHER INCOME (EXPENSE)
Interest expense		(6,412	)		(6,109	)
Loss on early extinguishment of long-term debt		(4,594	)		-
Gain (loss) on derivatives		(46,345	)		10,301
Other		1,087			828
Total other income (expense)		(56,264	)		5,020

Income (loss) before income taxes		(12,228	)		25,893
Income tax (expense) benefit		4,353			(9,218	)
NET INCOME (LOSS)	$	(7,875	)	$	16,675

Net income (loss) per common share
Basic	$	(0.65	)	$	1.37
Diluted	$	(0.65	)	$	1.37

Weighted average common shares outstanding:
Basic		12,156			12,146
Diluted		12,156			12,146

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Common Stock				Additional
	No. of		Par		Paid-In		Retained
	Shares		Value		Capital		Earnings
BALANCE,
December 31, 2010		12,155	$	1,215	$	152,290	$	95,947
Net loss		-		-		-		(7,875	)
Issuance of stock through
compensation plans, including
income tax benefits		1		-		26		-
BALANCE,
March 31, 2011		12,156	$	1,215	$	152,316	$	88,072

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

CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Three Months Ended
	March 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(7,875	)	$	16,675
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization		23,744			25,612
Exploration costs		877			2,878
Gain on sales of assets and impairment of inventory, net		(13,376	)		(286	)
Deferred income tax expense (benefit)		(4,353	)		9,218
Non-cash employee compensation		7,401			2,010
Unrealized (gain) loss on derivatives		44,627			(8,602	)
Accretion of abandonment obligations		674			647
Amortization of debt issue costs		568			335
Loss on early extinguishment of long-term debt		4,594			-

Changes in operating working capital:
Accounts receivable		(5,721	)		(1,468	)
Accounts payable		(11,954	)		(8,989	)
Other		(5,915	)		(7,654	)
Net cash provided by operating activities		33,291			30,376

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(82,993	)		(58,276	)
Proceeds from sales of assets		11,002			479
Change in equipment inventory		10,516			2,452
Other		(120	)		(95	)
Net cash used in investing activities		(61,595	)		(55,440	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		293,000			26,000
Repayments of long-term debt		(256,165	)		-
Premium on early extinguishment of long-term debt		(2,765	)		-
Proceeds from exercise of stock options		26			-
Net cash provided by financing activities		34,096			26,000

NET INCREASE IN CASH AND CASH EQUIVALENTS		5,792			936

CASH AND CASH EQUIVALENTS
Beginning of period		8,720			14,013
End of period	$	14,512		$	14,949

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	1,061		$	10,134

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2011

(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 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 also account for our undivided interests 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 these 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.

In the opinion of management, our unaudited consolidated financial statements as of March 31, 2011 and for the interim periods ended March 31, 2011 and 2010 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, 2011.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States 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, 2010.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3.	Long-Term Debt

Long-term debt consists of the following:

	March 31,		December 31,
	2011		2010
	(In thousands)
7.75% Senior Notes due 2019	$	300,000	$	-
7¾% Senior Notes due 2013		81,835		225,000
Revolving credit facility, due November 2015		47,000		160,000
	$	428,835	$	385,000

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 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. The remaining $81.8 million of 2013 Senior Notes are callable at par on August 1, 2011.

In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (“2019 Senior Notes”, and together with the 2013 Senior Notes, the “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 (see Note 14). We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on April 1, 2015, and 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 Indentures governing the 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 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 Indentures) does not exceed certain ratios specified in the Indentures governing the Senior Notes. These covenants are subject to a number of important exceptions and qualifications as described in the Indentures. We were in compliance with these covenants at March 31, 2011.

Revolving Credit Facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $500 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. The borrowing base was $350 million at March 31,2011.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

After allowing for outstanding letters of credit totaling $2 million, we had $301 million available under the revolving credit facility at March 31, 2011.

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 2% and 3% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 1% and 2%. We also pay a commitment fee on the unused portion of the revolving credit facility at a flat rate of 0.5%. 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 three months ended March 31, 2011 was 2.9%.

The revolving credit facility also contains various covenants and restrictive provisions which 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 loan agreement. We were in compliance with all financial and non-financial covenants at March 31, 2011.

4.	Other Non-Current Liabilities

Other non-current liabilities consist of the following:

	March 31,		December 31,
	2011		2010
	(In thousands)
Abandonment obligations	$	39,846	$	40,444
Other		846		857
	$	40,692	$	41,301

Changes in abandonment obligations for the three months ended March 31, 2011 and 2010 are as follows:

	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
Beginning of period	$	40,444		$	38,412
Additional abandonment obligations from new properties		618			646
Sales or abandonments of properties		(1,890	)		(173	)
Accretion expense		674			647
End of period	$	39,846		$	39,532

Our asset retirement obligation 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.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5.	Compensation Plans

Stock-Based Compensation

We presently have options outstanding under a stock option plan for independent directors covering 14,000 shares of common stock. As of March 31, 2011, the options had a weighted average exercise price of $26.61 per share (ranging from $12.14 per share to $41.74 per share), a weighted average remaining contractual term of 3.8 years, and an aggregate intrinsic value of $1.1 million (based on a market price at March 31, 2011 of $105.70 per share). No options were granted during the three months ended March 31, 2011 or 2010, and options to purchase 1,000 shares of common stock were exercised during the three months ended March 31, 2011 (with an intrinsic value of $56,970).

Non-Equity Award Plans

The Compensation Committee of the Board of Directors 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 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 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 seven specified areas, each of which established a quarterly bonus amount equal to 7% 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 August 9, 2010. Under these seven awards, the full vesting dates for future amounts payable under the plan for one award is November 4, 2011, three awards are August 9, 2012, and three awards are May 5, 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. Under the plan, two-thirds of the quarterly bonus amount is payable to the participants until the full vesting date of October 25, 2011. After the full vesting date, the deferred portion of the quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all subsequent quarterly bonus amounts, are payable to participants.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 plan. 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 compensation expense of $7.4 million for the three months ended March 31, 2011 and $2 million for the three months ended March 31, 2010 in connection with all non-equity award plans.

6.	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 March 31, 2011. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil				Gas
	Bbls		Price		MMBtu (a)		Price
Production Period:
2nd Quarter 2011		632,000	$	83.71		1,650,000	$	7.07
3rd Quarter 2011		547,000	$	83.78		1,560,000	$	7.07
4th Quarter 2011		540,000	$	83.78		1,500,000	$	7.07
2012		1,864,000	$	93.65		-	$	-
2013		480,000	$	96.70		-	$	-
		4,063,000				4,710,000

(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. For the three months ended March 31, 2011, we reported a $46.3 million net loss on derivatives, consisting of a $44.6 million non-cash loss related to changes in mark-to-market valuations and a $1.7 million realized loss for settled contracts. For the three months ended March 31, 2010, we reported a $10.3 million net gain on derivatives, consisting of an $8.6 million non-cash gain related to changes in mark-to-market valuations and a $1.7 million realized gain for settled contracts.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of March 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	$	36,175
	Non-current		-	Non-current		19,085
Total		$	-		$	55,260

	Fair Value of Derivative Instruments as of December 31, 2010
	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	$	7,224
	Non-current		-	Non-current		3,409
Total		$	-		$	10,633

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	March 31, 2011
	Assets			Liabilities
	(In thousands)
Fair value of derivatives – gross presentation	$	11,704		$	66,964
Effects of netting arrangements		(11,704	)		(11,704	)
Fair value of derivatives – net presentation	$	-		$	55,260

	December 31, 2010
	Assets			Liabilities
	(In thousands)
Fair value of derivatives – gross presentation	$	16,051		$	26,684
Effects of netting arrangements		(16,051	)		(16,051	)
Fair value of derivatives – net presentation	$	-		$	10,633

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 non-current assets or liabilities.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on the Consolidated Statements of Operations

	Amount of Gain or (Loss) Recognized in Earnings
		Three Months Ended
	Location of Gain or (Loss)	March 31,
	Recognized in Earnings	2011	2010
		(In thousands)
Derivatives not designated as
hedging instruments:

Commodity derivatives	Other income (expense) -
	Gain (loss) on derivatives	$ (46,345)	$ 10,301
Total		$ (46,345)	$ 10,301

7.	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. At March 31, 2011, our fixed rate debt maturing 2013 had a carrying value of $81.8 million and an approximate fair value of $81.4 million, based on current market quotes. Our fixed rate debt maturing 2019 had a carrying value of $300 million and an approximate fair value of $297.8 million. At December 31, 2010, our fixed rate debt maturing 2013 had a fair market value of approximately $226 million.

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.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The only financial liabilities measured on a recurring basis at March 31, 2011 and December 31, 2010 were commodity derivatives. Information regarding these liabilities is summarized below:

	March 31,		December 31,
	2011		2010
	Significant Other		Significant Other
	Observable Inputs		Observable Inputs
Description	(Level 2)		(Level 2)
	(In thousands)
Liabilities:
Fair value of commodity derivatives	$	55,260	$	10,633
Total liabilities	$	55,260	$	10,633

8.	Income Taxes

Our effective federal and state income tax expense rate for the three months ended March 31, 2011 of 35.6% 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 2006 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time.

9.	Sales of Assets and Impairments of Inventory

Net gain on sales of assets and impairment of inventory for the three months ended March 31, 2011 and March 31, 2010 are as follows:

	Three Months Ended
	March 31,
	2011			2010
	(In thousands)

Gain on sales of assets	$	13,572		$	286

Loss on sales of assets and impairment
of inventory:
Loss on sales of assets		(3	)		-
Impairment of inventory		(193	)		-
		(196	)		-

Net gain	$	13,376		$	286

In February 2011, we sold two 2,000 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 due August 2011.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

10.	Oil and Gas Properties

The following sets forth the net capitalized costs for oil and gas properties as of March 31, 2011 and December 31, 2010.

	March 31,			December 31,
	2011			2010
	(In thousands)
Proved properties	$	1,738,033		$	1,655,217
Unproved properties		54,834			52,035
Total capitalized costs		1,792,867			1,707,252
Accumulated depreciation, depletion and amortization		(1,006,411	)		(983,119	)
Net capitalized costs	$	786,456		$	724,133

11.	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. We did not record a provision for impairment of proved properties during the three months ended March 31, 2011 or 2010.

We 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 these assets as Level 3 inputs. 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 location 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. We recorded provisions for impairment of unproved properties aggregating $227,000 in 2011 and $2.6 million in 2010, respectively, and charged these impairments to exploration costs in the accompanying statements of operations.

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12.	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 periods ended March 31, 2011 and 2010.

For the Three Months Ended
March 31, 2011
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	108,913		$	12,159		$	(11,899	)	$	109,173
Depreciation, depletion and amortization (a)		23,484			2,855			(2,595	)		23,744
Other operating expenses (b)		40,533			9,409			(8,549	)		41,393
Interest expense		6,412			-			-			6,412
Other (income) expense		63,074			(13,222	)		-			49,852
Income (loss) before income taxes		(24,590	)		13,117			(755	)		(12,228	)

Income tax (expense) benefit		8,680			(4,327	)		-			4,353

Net income (loss)	$	(15,910	)	$	8,790		$	(755	)	$	(7,875	)

Total assets	$	909,159		$	49,419		$	(755	)	$	957,823
Additions to property and equipment	$	86,687		$	1,553		$	-		$	88,240

For the Three Months Ended
March 31, 2010
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total

Revenues	$	79,831		$	5,973		$	(5,973	)	$	79,831
Depreciation, depletion and amortization (a)		24,760			2,338			(1,486	)		25,612
Other operating expenses (b)		32,863			4,606			(4,123	)		33,346
Interest expense		6,109			-			-			6,109
Other (income) expense		(11,129	)		-			-			(11,129	)
Income (loss) before income taxes		27,228			(971	)		(364	)		25,893

Income tax (expense) benefit		(9,558	)		340			-			(9,218	)

Net income (loss)	$	17,670		$	(631	)	$	(364	)	$	16,675

Total assets	$	798,012		$	37,464		$	-		$	835,476
Additions to property and equipment	$	55,094		$	3,558		$	-		$	58,652

(a) Includes impairment of property and equipment.

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

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13.	Commitments

In March 2011, we entered into an agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”) where we can earn a 75% interest in leases held by Chesapeake under approximately 75,000 net acres in southern Reeves County, Texas. We have a one-year commitment to drill 20 wells prior to March 1, 2012. If we fail to do so, the agreement will terminate, and we will be required to pay Chesapeake an aggregate amount equal to $15 million less $750,000 for each well drilled in compliance with the agreement. Following satisfaction of our initial drilling obligations, we have the right, but not the obligation to drill at least 20 additional wells each year during the remaining four years of the term of the agreement. If we fail to drill 20 wells during any year after expiration of the initial drilling period, the agreement will terminate without any liability to us. Excess wells drilled during any year may be applied towards our drilling obligations in the next year. Costs of drilling and completing subsequent wells drilled shall be borne 75% by us and 25% by Chesapeake.

As of March 31, 2011, we had $9.7 million remaining in non-cancellable orders for tubular goods. In April 2011, we committed to purchase two drilling rigs for our Desta Drilling fleet at a cost of approximately $15.3 million.

14.	Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of March 31, 2011. In April 2011, we issued an additional $50 million aggregate principal amount of 2019 Senior Notes. We did not have any other subsequent events that would require recognition in the financial statements or disclosures in these notes to the consolidated financial statements.

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, 2010. 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, 2010 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;

•

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 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, 2010 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, 2010 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 have been 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 Wolfberry drilling program. Also included in the Permian Basin is our emerging Bone Springs/Wolfcamp play (“Wolfbone”) located in the Delaware Basin on the western edge of the Permian Basin where we are beginning a drilling program in the second quarter of 2011. We are also continuing to exploit our extensive acreage position in the Giddings Area of East Central Texas.

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 first quarter of 2011 and the outlook for the remainder of 2011.

·	Our oil and gas sales increased $15.9 million, or 20%, from 2010. Price variances accounted for an increase of $10.7 million while, production variances accounted for the remaining $5.2 million increase.

Our combined oil and gas production for the first quarter of 2011 was 2% lower on a barrel of oil equivalent (“BOE”) basis than in the comparable period in 2010. Our oil production increased 20% compared to 2010 while gas production declined 37%. On a comparable basis, after giving effect to the sale of properties in North Louisiana in June 2010, total oil and gas production in 2011 (on a BOE basis) was 9% higher than 2010.

In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (“2019 Senior Notes”) and redeemed $143.2 million in aggregate principal amount of 7¾% Senior Notes due 2013 (“2013 Senior Notes”). We recorded a $4.6 million loss on early extinguishment of long-term debt during the first quarter of 2011.

·	We recorded a gain of $13.2 million in the first quarter of 2011 on the sale of our two 2,000 horsepower rigs and related equipment for total consideration of $22 million, consisting of $11 million cash and a promissory note of $11 million.

We recorded a $46.3 million net loss on derivatives in the first quarter of 2011, consisting of a $44.6 million non-cash loss for changes in mark-to-market valuations and a $1.7 million realized loss on settled contracts. For fiscal 2010, we reported a $10.3 million net gain on derivatives consisting of an $8.6 million non-cash gain for changes in mark-to-market valuations and a $1.7 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.

·	Production costs (excluding production taxes) increased 18% or $3 million for the first quarter of 2011 compared to the first quarter of 2010 due to a combination of more producing wells and overall price increases from certain vendors for field services.

·	Through our subsidiary, Desta Drilling, we own and operate 12 drilling rigs which provide us with increased operating efficiencies and cost control.

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 Austin Chalk. We currently plan to spend approximately $409.9 million on exploration and development activities during fiscal 2011. Approximately 95% of the estimated expenditures for fiscal 2011 are expected to be spent on developmental drilling. We may increase or decrease our planned activities, depending upon drilling results, operating margins, the availability of capital resources, and other factors affecting the economic viability of such activities.

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 $55 million in the Permian Basin during the first quarter of 2011 on drilling and completion activities and $13.5 million on seismic and leasing activities. We drilled and completed 24 gross (18.8 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during fiscal 2011. We currently plan to spend approximately $337.9 million on drilling and leasing activities in this area during fiscal 2011. Following is a discussion of our principal assets in the Permian Basin.

Wolfbone

We are actively growing our 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. We spent approximately $12.1 million for leasing activities in the Wolfbone play during the first three months of 2011. To date, we have accumulated approximately 19,000 net acres. In March 2011, we entered into a farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”) covering approximately 75,000 net acres in southern Reeves County, Texas. For each well that we drill in the farm-in area that meets certain specified requirements (each, a ‘‘carried well’’), Chesapeake 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 (each, an ‘‘earned area’’). If we drill 100 wells in the farm-in area during the five-year term, we will earn an undivided 75% interest in the entire farm-in area that has not otherwise been assigned to us during the term of the farm-in agreement. Under the farm-in agreement, we are obligated to drill or commence drilling operations on at least 20 carried wells prior to March 1, 2012. If we fail to do so, the farm-in agreement will terminate, and we will be required to pay Chesapeake an aggregate amount equal to $15 million less $750,000 for each carried well we drilled in compliance with the farm-in agreement prior to March 1, 2012. Following satisfaction of our initial drilling obligations, we have the right, but not the obligation, to drill at least 20 additional carried wells each year during the remainder of the term of the farm-in agreement. If we fail to drill at least 20 carried wells during any year after expiration of the initial drilling period, the farm-in agreement will terminate without any liability to us. Excess wells drilled during any year may be applied towards our drilling obligations in the next year. We began a drilling program in April 2011 and currently plan to spend approximately $178.3 million on leasing, drilling and completion activities in the Wolfbone play during fiscal 2011.

Wolfberry

One of our primary objectives 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 from 7,500 to 10,500 feet. These formations are comprised of a sequence of basinal, interbedded shales and carbonates. We spent approximately $47.6 million on Wolfberry drilling and completion activities and approximately $1.4 million on seismic and leasing activities during the first quarter of 2011, and currently plan to spend approximately $146.5 million, net to our working interest, in this area during fiscal 2011.

Fuhrman-Mascho Field

We also resumed a drilling program in the Fuhrman-Mascho Field in Andrews County, Texas beginning in July 2009. Wells in the Fuhrman-Mascho Field produce from the San Andres formation, a reservoir comprised of fractured carbonate sediments found at a depth of approximately 4,300 feet. We currently plan to drill eight wells during fiscal 2011.

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. Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale and Taylor. During the first quarter of 2011, we spent approximately $14.4 million in the Giddings area on drilling and leasing activities and currently plan to spend approximately $64 million on similar drilling activities in this area during fiscal 2011. 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 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 plan to initiate a water frac program on certain wells beginning in June 2011 to enhance productivity on certain wells. We are currently working two of our drilling rigs in the Giddings Area to drill dual opposed or dual stacked lateral horizontal wells in the Austin Chalk.

Deep Bossier

We have an extensive acreage position in the Giddings Area that is also prospective for Deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet. Exploration for Deep Bossier gas sands in this area involves a high degree of risk. The geological structures are complex, very little subsurface control exists, and wells are expensive to drill. Although seismic data is helpful in identifying possible sand accumulations, the only way to determine whether the Deep Bossier sand will be commercially productive is to drill wells to the targeted structures. In fiscal year 2011, we currently plan to drill the Hamill #1, an exploratory well which is an offset to our previously drilled Big Bill Simpson #1 at an estimated cost of $14 million. We believe that the reserve potential from this well justifies the exploration risks despite current price levels of natural gas.

South Louisiana

In the first quarter of 2011, we drilled the State Lease 19924#1, an exploratory well in St. Mary Parish, Louisiana which was a dry hole. We plan to spend $4.2 million in fiscal 2011 in connection with drilling and leasing activities in South Louisiana.

Desta Drilling

We currently own and operate 12 drilling rigs that primarily work for us. We believe that owning our own rigs provides us with the ability to help control our cost structure and enables us the flexibility we need to take advantage of drilling opportunities as they become known on a timely basis. All 12 of our rigs are suitable for use in our developmental drilling programs. We have committed to add two more rigs to our fleet in 2011.

Known Trends and Uncertainties

We have drilled several commercial step-out wells in Lee County, Texas to determine the viability of expanding our Austin Chalk developmental drilling program to the southwest of our core properties where the number of drilling locations was limited. Based on our current evaluation of these wells, we believe that we will be able to extend our Austin Chalk drilling program through the remainder of 2011. In addition, we are continuing efforts to identify other opportunities for growth in the Austin Chalk area, including the addition of reserves and production through improved technology, acquisitions of proved reserves, and participation agreements with industry partners.

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.

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
	March 31,
	2011			2010
Oil and Gas Production Data:
Oil (MBbls)		899			752
Gas (MMcf)		2,113			3,328
Natural gas liquids (MBbls)		83			57
Total (MBOE)		1,334			1,364

Average Realized Prices (a):
Oil ($/Bbl)	$	88.93		$	76.00
Gas ($/Mcf)	$	5.24		$	5.76
Natural gas liquids ($/Bbl)	$	48.34		$	46.18

Gain (Loss) on Settled Derivative Contracts (a):
($ in thousands, except per unit)
Oil: Net realized loss	$	(6,778	)	$	(1,621	)
Per unit produced ($/Bbl)	$	(7.54	)	$	(2.16	)
Gas: Net realized gain	$	5,060		$	3,320
Per unit produced ($/Mcf)	$	2.39		$	1.00

Average Daily Production:
Oil (Bbls):
Permian Basin		6,177			4,909
Austin Chalk/Eagle Ford Shale		3,329			2,595
South Louisiana		414			627
Other(b)		69			225
Total		9,989			8,356

Gas (Mcf):
Permian Basin		13,920			13,911
Giddings Area:
Austin Chalk/Eagle Ford Shale		1,940			2,531
Cotton Valley Reef Complex		2,953			3,529
South Louisiana		3,149			7,513
Other(b)		1,516			9,494
Total		23,478			36,978

Natural Gas Liquids (Bbls):
Permian Basin		618			272
Austin Chalk/Eagle Ford Shale		226			271
South Louisiana		44			79
Other(b)		34			11
Total		922			633

(Continued)

	Three Months Ended
	March 31,
	2011		2010
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	532	$	-
Permian Basin		-		13
Deep Bossier		-		1,513
Other		345		1,352
Total		877		2,878

Seismic and other		1,278		1,660
Total exploration costs	$	2,155	$	4,538

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	23,291	$	24,589
Contract drilling depreciation		260		852
Other depreciation		193		171
Total DD&A	$	23,744	$	25,612

Oil and Gas Costs ($/BOE Produced):
Production costs	$	18.61	$	15.34
Production costs (excluding production taxes)	$	14.67	$	12.18
Oil and gas depletion	$	17.46	$	18.03

General and Administrative Expenses:
Excluding non-cash employee compensation	$	5,098	$	4,214
Non-cash employee compensation(c)		7,401		2,010
Total	$	12,499	$	6,224

Net Wells Drilled (d):
Exploratory Wells		0.5		1.1
Developmental Wells		27.1		26.3

(a) 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.
(b) Other for 2010 includes production attributable to sold properties in North Louisiana as follows: Oil 148, Gas 8,718, NGL 5.
(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 March 31, 2011 to the comparative period in 2010. Unless otherwise indicated, references to 2011 and 2010 within this section refer to the respective quarterly period.

Oil and gas operating results

Oil and gas sales in 2011 increased $15.9 million, or 20%, from 2010. Price variances accounted for an increase of $10.7 million while production variances accounted for the remaining $5.2 million increase. Production in 2011 (on a BOE basis) was 2% lower than 2010. Oil production increased 20% in 2011 from 2010 while gas production decreased 37% in 2011 from 2010. Most of the decrease in gas production from 2010 levels was attributed to a combination of normal production declines from existing wells and the loss of production related to the sale of certain properties in North Louisiana in June 2010. During 2010, the sold wells produced 148 barrels of oil per day and 8,718 Mcf of gas per day. On a comparable basis, after giving effect to the sale of these properties, oil production in 2011 was 22% higher than 2010 and total production was 9% higher (on a BOE basis). In 2011, our realized oil price was 17% higher than 2010, and our realized gas price was 9% 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 19% in 2011 as compared to 2010 due to a combination of more producing wells, rising costs of field services and increased production taxes on higher oil and gas sales. Production costs (excluding production taxes), referred to as lifting costs, increased 18% in 2011 as compared to 2010. After giving effect to a 2% decrease in total oil and gas production on a BOE basis, lifting costs per BOE increased 20% from $12.18 per BOE in 2010 to $14.67 per BOE in 2011.

Oil and gas depletion expense decreased $1.3 million from 2010 to 2011, of which rate variances accounted for an $800,000 decrease, and production variances accounted for the remaining $500,000 decrease. On a BOE basis, depletion expense decreased 3% from $18.03 per BOE in 2010 to $17.46 per BOE in 2011. The 2011 depletion rate per BOE dropped from 2010 due primarily to higher estimated reserve quantities 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

Since we follow the successful efforts method of accounting, 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 2011, we charged to expense $2.2 million of exploration costs, as compared to $4.5 million in 2010.

Contract Drilling Services

We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities. All drilling services revenues received by Desta Drilling, along with the related drilling services costs and pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations.

General and Administrative

General and administrative (“G&A”) expenses increased $6.3 million from $6.2 million in 2010 to $12.5 million in 2011. Employee compensation expense related to non-equity incentive plans was $7.4 million in 2011 compared to $2 million in 2010. Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $4.2 million in 2010 to $5.1 million in 2011 due primarily to higher personnel costs.

Interest expense

Interest expense increased 5% from $6.1 million in 2010 to $6.4 million in 2011 due to a combination of factors including an increase of $969,000 for the 2019 Senior Notes, offset in part by higher capitalized interest. The average daily principal balance outstanding under our revolving credit facility for 2011 was $159.1 million compared to $192.5 million for 2010. Decreased borrowings on our revolving credit facility accounted for a $254,000 decrease in interest expense, and lower interest rates and fees resulted in a decrease of $67,000. In addition, capitalized interest was $415,000 in 2011 compared to $142,000 in 2010.

Loss on early extinguishment of long-term debt

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.

Gain/loss on derivatives

We did not designate any derivative contracts in 2011 or 2010 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 March 31, 2011, we reported a $46.3 million net loss on derivatives, consisting of a $44.6 million non-cash loss to mark our derivative positions to their fair value at March 31, 2011 and a $1.7 million realized loss on settled contracts. For the three months ended March 31, 2010, we reported a $10.3 million net gain on derivatives, consisting of an $8.6 million non-cash gain to mark our derivative positions to their fair value at March 31, 2010 and a $1.7 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 gain of $13.4 million on sales of assets and impairment of inventory compared to a net gain of $286,000 in 2010. 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. The 2010 gain related to the sale of a prospect in South Louisiana.

Income tax expense

Our estimated effective income tax rate in 2011 of 35.6% 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 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, the effects of product prices on cash flow can be mitigated through the use of commodity derivatives.

The Indentures governing the issuance of our Senior Notes contain covenants that restrict our ability to incur indebtedness. We currently have, and expect to have in 2011, the ability under the Indentures to incur indebtedness as needed in 2011 to fund our exploration and development activities.

Capital expenditures

We incurred expenditures for exploration and development activities of $87.8 million during the first three months of 2011 and we currently plan to spend $409.9 million for fiscal 2011. The following table summarizes, by area, our actual expenditures for exploration and development activities for the first three months of 2011 and our planned expenditures for the year ending December 31, 2011.

	Actual		Planned
	Expenditures		Expenditures		2011
	Three Months Ended		Year Ended		Percentage
	March 31, 2011		December 31, 2011		of Total
	(In thousands)
Permian Basin	$	68,500	$	337,900		83	%
Giddings Area:
Austin Chalk/Eagle Ford Shale		14,200		50,100		12	%
Deep Bossier		200		13,900		3	%
South Louisiana		1,800		4,200		1	%
Other		3,100		3,800		1	%
	$	87,800	$	409,900		100	%

Our actual expenditures during fiscal 2011 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the remainder of the year. Factors, such as changes in operating margins and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during the remainder of fiscal 2011.

Our expenditures for exploration and development activities for the three months ended March 31, 2011 totaled $87.8 million, of which approximately 95% was on developmental drilling. We financed these expenditures with cash flow from operating activities and advances under the revolving credit facility. Based on preliminary estimates, our internal cash flow forecasts indicate that the amount of funds available to us under our revolving credit facility, when combined with our anticipated operating cash flow, will be sufficient to finance our exploration and development activities and provide us with adequate liquidity through 2011. 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 2011, 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 three months ended March 31, 2011 increased $2.9 million, or 9.6%, as compared to the corresponding period in 2010 due primarily to a 20% increase in oil and gas sales caused by higher commodity prices.

Revolving credit facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $500 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. The borrowing base was $350 million at March 31, 2011.

The revolving credit facility contains various covenants and restrictive provisions which 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 (the “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 in accordance with 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 increased from $19.9 million at December 31, 2010 to a deficit of $41.2 million at March 31, 2011. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $295.9 million at March 31, 2011, as compared to $175.3 million at December 31, 2010. The following table reconciles our GAAP working capital deficit to the working capital computed for loan compliance purposes at March 31, 2011 and December 31, 2010.

	March 31,			December 31,
	2011			2010
	(In thousands)
Working capital (deficit) per GAAP	$	(41,242	)	$	(19,899	)
Add funds available under the revolving credit facility		300,975			187,975
Exclude fair value of derivatives classified as current assets or current liabilities		36,175			7,224
Working capital per loan covenant	$	295,908		$	175,300

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 March 31, 2011. 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, Union Bank, N.A., BNP Paribas, Natixis, Compass Bank, The Frost National Bank, Bank of Texas, N.A., Keybank, N.A., UBS Loan Finance, LLC, The Royal Bank of Scotland plc, and Societe Generale.

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 March 31, 2011, 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 three months of 2011, we decreased indebtedness outstanding under the revolving credit facility by $113 million. At March 31, 2011, we had $47 million of borrowings outstanding under the revolving credit facility, leaving $301 million available on the facility after allowing for outstanding letters of credit totaling $2 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. The remaining $81.8 million of 2013 Senior Notes are callable at par on August 1, 2011.

In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes (2019 Senior Notes and together with the 2013 Senior Notes, the “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 (see Note 14). We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on April 1, 2015, and 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.

Alternative capital resources

Although our base of oil and gas reserves, as collateral for our revolving credit facility, has historically been our primary capital resource, we have in the past, and we believe we could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or public or private issuances of common stock. We could also issue senior or subordinated debt or preferred stock in a public or a private placement if we choose to raise capital through either of these markets. 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 Risks

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 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 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 prices with any degree of certainty. Sustained weakness in oil and gas 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 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 prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2010 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 2010 would reduce our gross revenues for the year ending December 31, 2011 by $9.9 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. 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. We do not enter into commodity derivatives for trading purposes. 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.

Swaps:

	Oil				Gas
	Bbls		Price		MMBtu (a)		Price
Production Period:
2nd Quarter 2011		632,000	$	83.71		1,650,000	$	7.07
3rd Quarter 2011		547,000	$	83.78		1,560,000	$	7.07
4th Quarter 2011		540,000	$	83.78		1,500,000	$	7.07
2012		1,864,000	$	93.65		-	$	-
2013		480,000	$	96.70		-	$	-
		4,063,000				4,710,000

(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 $6.1 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At March 31, 2011, our fixed rate debt maturing 2013 had a carrying value of $81.8 million and an approximate fair value of $81.4 million, based on current market quotes. Our fixed rate debt maturing 2019 had a carrying value of $300 million and an approximate fair value of $297.8 million. We estimate that the hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $18.9 million. Based on our outstanding variable rate indebtedness at March 31, 2011 of $47 million, a change in interest rates of 100-basis points would affect annual interest payments by $470,000.

Item 4 - Controls and Procedures

Disclosure Controls and Procedures

In September 2002, our Board of Directors 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.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the quarter ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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, 2010, as filed with the U.S. Securities and Exchange Commission on March 1, 2011, and available at www.sec.gov.

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		Indenture, dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on July 22, 2005††

**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 as of March 16, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the 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 as of April 29, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the 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		First Amendment to Second Amended and Restated Credit Agreement dated March 3, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 7, 2011††

*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

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

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:	May 9, 2011	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief
			Operating Officer

Date:	May 9, 2011	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President and Chief Financial
			Officer

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		Indenture, dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on July 22, 2005††

**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 as of March 16, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the 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 as of April 29, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the 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		First Amendment to Second Amended and Restated Credit Agreement dated March 3, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 7, 2011††

*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

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

Attached files

CLAYTON WILLIAMS ENERGY INC /DE Reports

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