Southwest Royalties S4 Registration of securities issued in business combination transactions

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INDEX TO FINANCIAL STATEMENTS

As filed with the Securities and Exchange Commission on January 24, 2014

Registration No. 333-

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

FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

CLAYTON WILLIAMS ENERGY, INC.
(AND CERTAIN SUBSIDIARIES OF CLAYTON WILLIAMS ENERGY, INC. IDENTIFIED IN
FOOTNOTE (*) BELOW)
(Exact Name of Registrant as Specified in Its Charter)


Delaware (State or Other Jurisdiction of Incorporation or Organization)		1311 (Primary Standard Industrial Classification Code Number)		75-2396863 (I.R.S. Employer Identification Number)

Six Desta Drive, Suite 6500
Midland, Texas 79705-5510
(432) 682-6324
(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant's Principal Executive Offices)

Michael L. Pollard
Senior Vice President and Chief Financial Officer
Clayton Williams Energy, Inc.
Six Desta Drive, Suite 6500
Midland, Texas 79705-5510
(432) 682-6324
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)


Copies to:
Milam F. Newby Vinson & Elkins L.L.P. 2801 Via Fortuna, Suite 100 Austin, Texas 78746 (512) 542-8400 (512) 542-8612 (fax)

Approximate date of commencement of proposed sale of the securities to the public:
As soon as practicable after the effective date of this Registration Statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

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


Large accelerated filero		Accelerated filerý		Non-accelerated filero (Do not check if a smaller reporting company)		Smaller reporting companyo

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issue Tender Offer)o

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer)o

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to Be Registered	Amount to be Registered	Amount of Registration Fee(1)




7.75% Senior Notes due 2019	$250,000,000	$32,200

Guarantees of 7.75% Senior Notes due 2019(2)		None(3)

(1): Calculated pursuant to Rule 457(f)(2) under the Securities Act of 1933.
(2): Each subsidiary of Clayton Williams Energy, Inc. that is listed on the Table of Additional Registrant Guarantors has guaranteed the notes being registered.
(3): Pursuant to Rule 457(n) of the Securities Act of 1933, no registration fee is required for the Guarantees.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

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TABLE OF ADDITIONAL REGISTRANT GUARANTORS

* The following are co-registrants that guarantee the debt securities:

Exact Name of Registrant Guarantor(1)	State or Other Jurisdiction of Incorporation or Formation

SWR VPP, LLC	Texas	45-4673594
Southwest Royalties, Inc.	Delaware	75-1917432
Warrior Gas Co.	Texas	75-2470747
CWEI Acquisitions, Inc.	Delaware	75-2531463
Romere Pass Acquisition L.L.C.	Delaware	72-1529502
CWEI Romere Pass Acquisition Corp.	Delaware	83-0378927
Blue Heel Company	Delaware	75-2740345
Tex-Hal Partners, Inc.	Delaware	75-2567750
Desta Drilling GP, LLC	Texas	20-4727861
Desta Drilling, L.P.	Texas	20-4728095
West Coast Energy Properties GP, LLC	Texas	30-0371874
Clajon Industrial Gas, Inc.	Texas	75-1712875
Clayton Williams Pipeline Corporation	Delaware	75-2640527

(1): The address for each Registrant Guarantor is Six Desta Drive, Suite 6500, Midland, Texas 79705-5510, and the telephone number for each Registrant Guarantor is (432) 682-6324. The Primary Industrial Classification Code for each Registrant Guarantor is 1311.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to completion, dated January 24, 2014

PROSPECTUS

Clayton Williams Energy, Inc.

Offer to Exchange
Up To $250,000,000 of
7.75% Senior Notes due 2019
That Have Not Been Registered Under
The Securities Act of 1933
For
Up To $250,000,000 of
7.75% Senior Notes due 2019
That Have Been Registered Under
The Securities Act of 1933

Terms of the New 7.75% Senior Notes due 2019 Offered in the Exchange Offer:

•: The terms of the new notes are identical to the terms of the old notes that were issued on October 1, 2013, except that the new notes will be registered under the Securities Act of 1933 (the "Securities Act") and will not contain restrictions on transfer, registration rights or provisions for additional interest.

Terms of the Exchange Offer:

•: We are offering to exchange up to $250,000,000 of our old notes for new notes with materially identical terms that have been registered under the Securities Act and are freely tradable.
•: We will exchange all old notes that you validly tender and do not validly withdraw before the exchange offer expires for an equal principal amount of new notes.
•: The exchange offer expires at 5:00 p.m., New York City time, on , 2014, unless extended.
•: Tenders of old notes may be withdrawn at any time prior to the expiration of the exchange offer, in accordance with the procedures set forth herein.
•: We believe that the exchange of new notes for old notes will not be a taxable event for U.S. federal income tax purposes.
•: Broker-dealers who receive new notes pursuant to the exchange offer acknowledge that they will deliver a prospectus in connection with any resale of such new notes.
•: Broker-dealers who acquired the old notes as a result of market-making or other trading activities may use the prospectus for the exchange offer, as supplemented or amended, in connection with resales of the new notes.

You should carefully consider the risk factors beginning on page 8 of this prospectus before participating in the exchange offer.

We are not asking you for a proxy and you are requested not to send us a proxy.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is , 2014.

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This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than its respective date.

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FORWARD-LOOKING STATEMENTS			ii
PROSPECTUS SUMMARY			1
RISK FACTORS			8
EXCHANGE OFFER			27
USE OF PROCEEDS			34
SUMMARY HISTORICAL CONSOLIDATED FINANCIAL DATA			35
RATIOS OF EARNINGS TO FIXED CHARGES			37
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			38
BUSINESS			68
PROPERTIES			85
MANAGEMENT			96
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			125
DESCRIPTION OF NOTES			129
PLAN OF DISTRIBUTION			181
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES			183
LEGAL MATTERS			183
EXPERTS			183
WHERE YOU CAN FIND MORE INFORMATION			183
INDEX TO FINANCIAL STATEMENTS			F-1
Annex A—Letter of Transmittal			A-1
Annex B—Glossary of Natural Gas and Oil Terms			B-1

This prospectus refers to important business and financial information about Clayton Williams Energy, Inc. that is not included or delivered with this prospectus. Such information is available without charge to holders of old notes upon written or oral request made to the office of Clayton Williams Energy, Inc., Attention: Patti Hollums, Six Desta Drive, Suite 6500, Midland, Texas 79705-5510 (Telephone (432) 682-6324). To obtain timely delivery of any requested information, holders of old notes must make any request no later than five business days prior to the expiration of the exchange offer.

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FORWARD-LOOKING STATEMENTS

This information in this prospectus includes "forward-looking statements" within the meaning of Section 27A of the Securities Act 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 described under the heading "Risk Factors" included in this prospectus. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

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;

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•: 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 this prospectus.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this prospectus, and we undertake no obligation to update this information to reflect events or circumstances after the date of this prospectus, except as required by law. All forward-looking statements, expressed or implied, included in this prospectus and attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

iii

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PROSPECTUS SUMMARY

This summary highlights some of the information contained in this prospectus and does not contain all of the information that may be important to you. You should read this entire prospectus and the documents to which we refer you before making an investment decision. You should carefully consider the information set forth under "Risk Factors" beginning on page 8 of this prospectus and the other cautionary statements described in this prospectus. In addition, certain statements include forward looking information that involves risks and uncertainties. See "Forward-Looking Statements." The information in this prospectus with respect to our estimated proved reserves as of December 31, 2012 has been prepared by our internal reserve engineers and audited by our independent reserve engineering firms.

Unless this prospectus otherwise indicates or the context otherwise requires, the terms the "Company," "we," "our," "us," "Clayton Williams Energy," "CWEI," or other similar terms as used in this prospectus refer to Clayton Williams Energy, Inc. and its consolidated subsidiaries.

In this prospectus we refer to the notes to be issued in the exchange offer as the "new notes" and the notes issued on and October 1, 2013 as the "old notes." We refer to the new notes and the old notes collectively as the "notes."

Clayton Williams Energy, Inc.

We are an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, Louisiana and New Mexico.

Clayton W. Williams, Jr. beneficially owns, either individually or through his affiliates, approximately 25.6% of the outstanding shares of our common stock. In addition, The Williams Children's Partnership, Ltd., a limited partnership of which Mr. Williams' adult children are the limited partners, owns an additional 25% of the outstanding shares of our common stock. Mr. Williams is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations.

Our principal executive offices are located at Six Desta Drive, Suite 6500, Midland, Texas 79705-5510, and our telephone number at our offices is (432) 682-6324.

Risk Factors

Investing in the notes involves substantial risks. You should carefully consider all the information contained in this prospectus prior to participating in the exchange offer. In particular, we urge you to consider carefully the factors set forth under "Risk Factors" beginning on page 8 of this prospectus.

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The Exchange Offer

On October 1, 2013 we completed the private offering of the old notes. We entered into a registration rights agreement with the initial purchasers in the private offering in which we agreed to deliver to you this prospectus and to use our reasonable best efforts to complete the exchange offer within 365 days after the date we first issued the old notes.


Exchange Offer		We are offering to exchange new notes for old notes.
Expiration Date		The exchange offer will expire at 5:00 p.m., New York City time, on , 2014, unless we decide to extend it.
Condition to the Exchange Offer		The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered.
Procedures for Tendering Old Notes		To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company, which we call "DTC," for tendering notes held in book-entry form. These procedures, which we call "ATOP," require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an "agent's message" that is transmitted through DTC's automated tender offer program, and (ii) DTC confirms that:
		• DTC has received your instructions to exchange your notes, and
		• you agree to be bound by the terms of the letter of transmittal.
		For more information on tendering your old notes, please refer to the section in this prospectus entitled "Exchange Offer—Terms of the Exchange Offer," "—Procedures for Tendering," and "Description of Notes—Book Entry; Delivery and Form."
Guaranteed Delivery Procedures		None.
Withdrawal of Tenders		You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled "Exchange Offer—Withdrawal of Tenders."

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Acceptance of Old Notes and Delivery of New Notes		If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer on or before 5:00 p.m., New York City time, on the expiration date. We will return any old notes that we do not accept for exchange to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled "Exchange Offer—Terms of the Exchange Offer."
Fees and Expenses		We will bear the expenses related to the exchange offer. Please refer to the section in this prospectus entitled "Exchange Offer—Fees and Expenses."
Use of Proceeds		The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under our registration rights agreement.
Consequences of Failure to Exchange Old Notes		If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.
U.S. Federal Income Tax Considerations		The exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read "Material United States Federal Income Tax Consequences."
Exchange Agent		We have appointed Wells Fargo Bank, N.A. as exchange agent for the exchange offer. You should direct questions, requests for assistance, requests for additional copies of this prospectus or the letter of transmittal to the exchange agent addressed as follows:
		• by registered or certified mail at Wells Fargo Bank, N.A., MAC—N9303-121, Corporate Trust Operations, P.O. Box 1517, Minneapolis, MN 55480-1517, Attn: Reorg; or
		• by Overnight Delivery or Regular Mail at Wells Fargo Bank, N.A, MAC—N9303-121, Corporate Trust Operations, Sixth Street & Marquette Avenue, Minneapolis, MN 55479, Attn: Reorg;
		Eligible institutions may make requests by facsimile at (612) 667-6282, Attn: Bondholder Communications, and may confirm facsimile delivery by email at bondholdercommunications@wellsfargo.com or by telephone at (800) 344-5128, Attn: Bondholder Communications.

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Terms of the New Notes

The new notes will be identical to the old notes except that the new notes are registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same indenture will govern the new notes and the old notes.

The following summary contains basic information about the new notes and is not intended to be complete. It does not contain all information that is important to you. For a more complete understanding of the new notes, please refer to the section of this document entitled "Description of Notes."


Issuer		Clayton Williams Energy, Inc..
Securities		$250,000,000 aggregate principal amount of 7.75% Senior Notes due 2019.
Maturity		April 1, 2019.
Interest Payment Dates		April 1 and October 1 of each year, commencing on April 1, 2014. Interest on each new note will accrue from the last interest payment date on which interest was paid on the old note tendered in exchange thereof, or, if no interest has been paid on the old note, from the date of the original issue of the old note.
Optional Redemption		The new notes are redeemable at our option, in whole or in part, at any time on or after April 1, 2015 at the redemption prices set forth in this prospectus under the heading "Description of Notes—Optional Redemption" together with accrued and unpaid interest, if any, to the date of redemption.
		In addition, at any time and from time to time prior to April 1, 2014, we may redeem up to 35% of the aggregate principal amount of the notes using the proceeds of one or more equity offerings at a redemption price of 107.750% of the principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption.
		We may redeem some or all of the notes prior to April 1, 2015, at a price equal to 100% of the principal amount of the notes plus a "make-whole" premium together with accrued and unpaid interest, if any, to the date of redemption. See "Description of Notes—Optional Redemption."
Guarantees		The notes are guaranteed by all of our material wholly owned subsidiaries, each of which also guarantees our obligations under our senior secured revolving credit agreement dated November 29, 2010, among us, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto from time to time. In the future, the notes will be guaranteed only by our existing and future restricted subsidiaries that guarantee our other indebtedness. The guarantees are unsecured senior indebtedness of our subsidiary guarantors and have the same ranking with respect to indebtedness of our subsidiary guarantors as the notes have with respect to our indebtedness. See "Description of Notes—Ranking"

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Ranking		The new notes:
		• are general unsecured, senior obligations;
		• rank equally in right of payment to all of our existing and future senior indebtedness without giving effect to collateral agreements;
		• are effectively junior to our secured indebtedness, including amounts that may be borrowed under our revolving credit facility, to the extent of the value of the assets securing such debt;
		• rank senior in right of payment to all our existing and future subordinated indebtedness; and
		• are structurally subordinated to all of the existing and future liabilities (including trade payables) of each of our existing and future subsidiaries that do not guarantee the notes.
		As of September 30, 2013, after giving effect on a pro forma basis to the Notes Offering (as defined below), we and our subsidiary guarantors have total consolidated indebtedness, including discounts and premiums, of $678.6 million, including $79 million of secured indebtedness outstanding under our revolving credit facility (excluding $5.1 million in outstanding letters of credit) and $599.6 million of our 7.75% Senior Notes due 2019, and we would have been able to incur an additional $325.8 million of secured indebtedness under our revolving credit facility. For further discussion, see "Risk Factors—The notes and the guarantees are effectively subordinated to all of our secured debt, and, if a default occurs, we may not have sufficient funds to fulfill our obligations under the notes and the guarantees."
Mandatory Offers to Purchase		The occurrence of a change of control will be a triggering event that may require us to offer to purchase from you all or a portion of your notes at a price equal to 101% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase.
		Certain asset dispositions will be triggering events that may require us to use the proceeds from those asset dispositions to make an offer to purchase the notes at 100% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase if such proceeds are not otherwise used within 365 days to repay certain indebtedness or to invest in assets related to our business.
Certain Covenants		We will issue the new notes under the indenture dated as of March 16, 2011 with Wells Fargo Bank, National Association, as trustee. The indenture, among other things, limits our ability and the ability of our restricted subsidiaries (as defined under "Description of Notes") to:
		• incur, assume or guarantee additional debt;

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		• issue redeemable stock and preferred stock;
		• repurchase capital stock;
		• make other restricted payments, including paying dividends and making investments;
		• create liens without securing the notes;
		• redeem debt that is junior in right of payment to the notes;
		• sell or otherwise dispose of assets, including capital stock of subsidiaries;
		• enter into agreements that restrict dividends from subsidiaries;
		• enter into mergers or consolidations;
		• enter into transactions with affiliates; and
		• enter into new lines of business.
		These covenants are subject to a number of important exceptions and qualifications and many of them will be suspended if the notes achieve an investment grade rating as described in the indenture. For more details, see "Description of Notes."
Transfer Restrictions; Absence of a Public Market for the New Notes		The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development, maintenance or liquidity of any market for the new notes.
		We do not intend to apply for a listing of the new notes on any securities exchange or any automated dealer quotation system.
Risk Factors		Investing in the new notes involves risks. See "Risk Factors" beginning on page 8 for a discussion of certain factors you should consider in evaluating whether or not to tender your old notes.

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Ratios of Earnings to Fixed Charges

The following table sets forth our ratios of consolidated earnings to fixed charges for the periods presented:



	Year Ended December 31,
	2008		2009		2010		2011		2012
Ratio of earnings to fixed charges(a)		5.8x		(b)		2.5x		3.8x		1.9x	(b)

(a): For purposes of calculating the ratios of consolidated earnings to fixed charges, "earnings" consists of income (loss) from continuing operations, plus fixed charges. "Fixed charges" consist of interest and financing expense, amortization of deferred financing costs and the estimated interest factor attributable to rental expense.
(b): We had an earnings to fixed charges deficiency of approximately $116.7 million for the year ended December 31, 2009 and $32.2 million for the nine months ended September 30, 2013.

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RISK FACTORS

This offering involves a high degree of risk. You should carefully consider and evaluate all of the information and data included in this prospectus, including the risks described below, before deciding to participate in the exchange offer. Our business, financial condition and results of operations could be materially adversely affected by any of these risks. The trading price of the new notes could decline, and you may lose all or part of your investment. The risks described below are not the only ones facing our company. Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations.

This prospectus also contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors, including the risks and uncertainties faced by us described below.

Risks Related to our Business

Oil and natural gas prices are volatile. Declines in commodity prices have adversely affected, and in the future may adversely affect, our financial condition, liquidity, results of operations, cash flows, access to the capital markets, and ability to grow.

Our revenues, operating results, liquidity, cash flows, profitability and value of proved reserves depend substantially upon the market prices of oil and natural gas. Commodity prices affect our cash flows available for capital expenditures and our ability to access funds under our revolving credit facility and through the capital markets. The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined at least semi-annually by our lenders taking into account the estimated value of our proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in commodity prices have historically adversely affected the estimated value of our proved reserves and, in turn, the market values used by our lenders in determining our borrowing base. If commodity prices decline in the future, the decline could have adverse effects on our reserves and borrowing base.

The commodity prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:

•: changes in the supply of and demand for oil and natural gas;
•: market uncertainty;
•: the level of consumer product demands;
•: pipeline constraints and sufficient capacity;
•: hurricanes and other weather conditions;
•: domestic governmental regulations and taxes;
•: the price and availability of alternative fuels;
•: political and economic conditions in oil producing countries;
•: the foreign supply of oil and natural gas;
•: the price of oil and natural gas imports; and
•: overall domestic and foreign economic conditions.

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to

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contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.

We may not be able to replace production with new reserves.

In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. In past years, our oil and gas properties have had steep rates of decline and short estimated productive lives.

Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves. Also, we may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot give assurance that our future exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

Our business is capital intensive and requires us to spend substantial amounts of capital for exploration and development activities. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to internally fund our exploration and development activities. If our borrowing base under our revolving facility is redetermined to a lower amount, this could adversely affect our ability to supplement cash flows from operations as a source of funding for these activities. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot give assurance that additional debt or equity financing will be available on terms acceptable to us, or that cash flows provided by operations will be sufficient to meet our capital expenditures requirements.

We have substantial indebtedness. Our leverage and the covenants in our debt agreements could negatively impact our financial condition, liquidity, results of operations and business prospects.

As of September 30, 2013, after giving effect on a pro forma basis to the Notes Offering (as defined below), the principal amount of our outstanding consolidated debt was approximately $678.6 million, which included $79 million outstanding under our revolving credit facility and $599.6 million in outstanding principal amount of our existing notes, net of unamortized discount. Our revolving credit facility and the indenture governing the notes impose significant restrictions on our ability to take certain actions, including our ability to incur additional indebtedness, sell certain assets, merge, make investments or loans, issue redeemable or preferred stock, pay distributions or dividends, create liens, guarantee other indebtedness and enter into new lines of business.

Our level of indebtedness and the restrictive covenants in our debt agreements could have important consequences on our business and operations. Among other things, these may:

•: require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures and other general corporate purposes;
•: adversely affect the credit ratings assigned by third-party rating agencies, which have in the past downgraded, and may in the future downgrade their ratings of our debt and other obligations due to changes in our debt level or our financial condition;
•: limit our access to the capital markets;

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•: increase our borrowing costs and impact the terms, conditions and restrictions contained in our debt agreements, including the addition of more restrictive covenants;
•: limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;
•: place us at a disadvantage compared to similar companies in our industry that have less debt; and
•: make us more vulnerable to economic downturns and adverse developments in our business.

A higher level of debt will increase the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be affected by oil and gas prices, financial, business, domestic and worldwide economic conditions, governmental and environmental regulations and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

The credit risk of financial institutions could adversely affect us.

The credit risk of financial institutions could adversely affect us. We have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies and their affiliates. These transactions expose us to credit risk in the event of default by our counterparty, principally with respect to hedging agreements but also insurance contracts and bank lending commitments. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us.

Our hedging transactions could result in financial losses or could reduce our income. To the extent we have hedged a significant portion of our expected production and actual production is lower than we expected or the costs of goods and services increase, our profitability would be adversely affected.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into and may in the future enter into hedging transactions for a significant portion of our expected oil and gas production. These transactions could result in both realized and unrealized hedging losses.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are primarily based on New York Mercantile Exchange ("NYMEX") futures prices, which may differ significantly from the actual crude oil and gas prices we realize in our operations. Furthermore, we have adopted a policy that requires, and our revolving credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions. If our actual future production is higher than we estimated, we will have greater commodity price exposure than we intended. If our actual future production is lower than the nominal amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in

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reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

In addition, our hedging transactions are subject to the following risks:

•: we may be limited in receiving the full benefit of increases in oil and gas prices as a result of these transactions;
•: a counterparty may not perform its obligation under the applicable derivative instrument or may seek bankruptcy protection;
•: there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
•: the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability and cash flow to be materially different from our estimates.

The accuracy of estimated proved reserves and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn could adversely affect our cash flow, results of operations, financial condition and the availability of capital resources. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Downward adjustments to our estimated proved reserves could require us to impair the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders' equity.

The present value of proved reserves will not necessarily equal the current fair market value of our estimated oil and gas reserves. In accordance with reserve reporting requirements of the SEC, we are required to establish economic production for reserves on an average historical price. Actual future prices and costs may be materially higher or lower than those required by the SEC. The timing of both the production and expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.

The estimated proved reserve information is based upon reserve reports prepared by independent engineers. From time to time, estimates of our reserves are also made by the lenders under our revolving credit facility in establishing the borrowing base under the revolving credit facility and by our engineers for use in developing business plans and making various decisions. Such estimates may vary significantly from those of the independent engineers and have a material effect upon our business decisions and available capital resources.

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Our producing properties are largely concentrated in two major geographic areas, the Permian Basin in West Texas and Southeastern New Mexico and the Giddings Area in East Central Texas. Concentrations of reserves in limited geographic areas may disproportionately expose us to operational, regulatory and geological risks.

Our core producing properties are geographically concentrated in the Permian Basin of West Texas and Southeastern New Mexico and the Giddings Area in East Central Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of oil, natural gas or natural gas liquids.

In addition, as of December 31, 2012, a significant portion of our proved reserves in the Permian Basin were derived from the Wolfberry play in Andrews County, Texas, the Wolfbone play in the Delaware Basin, and the Austin Chalk formation in the Giddings Area. This concentration of assets within a few producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut in all of our wells within a field.

Our proved undeveloped locations are scheduled to be drilled over several years, subjecting us to uncertainties that could materially alter the occurrence or timing of our drilling activities.

We have assigned proved undeveloped reserves to certain of our drilling locations as an estimation of our future multi-year development activities on our existing acreage. These identified locations represent a significant part of our growth strategy. At December 31, 2012, our estimated proved undeveloped reserves were 42% of total estimated proved reserves. Our ability to drill and develop these locations depends on a number of uncertainties, including (1) our ability to timely drill wells on lands subject to complex development terms and circumstances; (2) the availability of capital, equipment, services and personnel; (3) seasonal conditions; (4) regulatory and third party approvals; (5) oil and natural gas prices; and (6) drilling and recompletion costs and results. Because of these uncertainties, we may defer drilling on, or never drill, some or all of these potential locations. If we defer drilling more than five years from the date proved undeveloped reserves were first assigned to a drilling location, we may be required under SEC guidelines to downgrade the category of the applicable reserves from proved undeveloped to probable. Any reclassification of reserves from proved undeveloped to probable could reduce our ability to borrow money and could reduce the value of our debt and equity securities.

Price declines may result in impairments of our asset carrying values.

Commodity prices have a significant impact on the present value of our proved reserves. Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our oil and gas properties in certain situations. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required. Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.

Our exploration activities subject us to greater risks than development activities.

Generally, our oil and gas exploration activities pose a higher economic risk to us than our development activities. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to increasing oil or natural gas production from an area that is known to be productive by drilling additional wells, working over and recompleting existing wells and other production enhancement techniques. Exploration projects are identified through

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subjective analysis of geological and geophysical data, including the use of 3-D seismic and other available technology. By comparison, the identification of development prospects is significantly based upon existing production surrounding or adjacent to the proposed drilling site.

To the extent we engage in exploration activities, we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or natural gas is present or can be produced economically. We cannot assure you that any of our future exploration efforts will be successful. If these activities are unsuccessful, it will have a significant adverse effect on our results of operations, cash flow and capital resources.

Drilling oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter economically productive oil or natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we are often uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•: unexpected drilling conditions;
•: title problems;
•: pressure or irregularities in formations;
•: equipment failures or accidents;
•: adverse weather conditions;
•: compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and
•: costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment and services.

If we do not encounter reserves that can be produced economically or if our drilling operations are curtailed, delayed or cancelled, it could have a significant adverse effect on our results of operations, cash flow and financial condition.

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.

Our on-going business strategy includes growing our reserves and drilling inventory through acquisitions. Acquired properties can be subject to significant unknown liabilities. Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed.

Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write-down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders' equity.

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Our failure to integrate acquired properties successfully into our existing business could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

The process of integrating acquired properties into our existing business may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of our existing business.

We may not be insured against all of the operating hazards to which our business is exposed.

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as windstorms, lightning strikes, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids (including fluids used in hydraulic fracturing activities), fires, severe weather and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations, all of which could result in a substantial loss. We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot give assurance of the continued availability of insurance at premium levels that justify its purchase.

Our business depends on oil and natural gas transportation facilities, most of which are owned by others.

The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems could result in the shut in of producing wells or the delay or discontinuance of drilling plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, maintenance and repair and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Future shortages of available drilling rigs, equipment and personnel may delay or restrict our operations.

The oil and natural gas industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies and personnel. During these periods, the costs and delivery times of drilling rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or personnel may increase drilling costs or delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas processing or transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines and terminal facilities, competition for such facilities and the inability of such facilities to gather, transport or process our production due to shutdowns or curtailments arising from

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mechanical, operational or weather related matters, including hurricanes and other severe weather conditions. Our ability to market our production depends in substantial part on the availability and capacity of gathering and transportation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could adversely affect our business, financial condition and results of operations. We may be required to shut-in or otherwise curtail production from wells due to lack of a market or inadequacy or unavailability of oil, natural gas liquids or natural gas pipeline or gathering, transportation or processing capacity. If that were to occur, then we would be unable to realize revenue from those wells until suitable arrangements were made to market our production.

Our industry is highly competitive.

Competition in all areas of our operations is intense. We experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to increase reserves in the future will depend on our success at selecting and acquiring suitable producing properties and prospects for future development and exploration activities.

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue. The market for our oil, gas and natural gas liquids production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

Our success is highly dependent on our senior management. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

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We are primarily controlled by Clayton W. Williams, Jr. and his children's limited partnership.

Clayton W. Williams, Jr., age 82, beneficially owns, either individually or through his affiliates, approximately 25.6% of the outstanding shares of our common stock. Mr. Williams is also our Chairman of the Board, President and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members, and in all other facets of our business, including both our business strategy and daily operations.

WCPL, a limited partnership in which Mr. Williams' adult children are the limited partners, owns an additional 25% of the outstanding shares of our common stock. Mel G. Riggs, our Executive Vice President and Chief Operating Officer, is the sole general partner of WCPL and has the power to vote or direct the voting of the shares held by WCPL. In voting these shares, Mr. Riggs will not be acting in his capacity as an officer and director of the Company and will consider the interests of WCPL and Mr. Williams' children. They may have interests that differ from the interests of our other shareholders.

The retirement, incapacity or death of Mr. Williams, or any change in the power to vote shares beneficially owned by Mr. Williams or held by WCPL, could result in negative market or industry perception and could have a material adverse effect on our business.

By extending credit to our customers, we are exposed to potential economic loss.

We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. As appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. We cannot give assurance that we will not suffer any economic loss related to credit risks in the future.

Compliance with laws and regulations governing our activities could be costly and could negatively impact production.

Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

All of the states in which we operate generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from our properties.

The Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may

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enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Under the Energy Policy Act of 2005 ("EP Act 2005"), the FERC has civil penalty authority under the federal Natural Gas Act ("NGA") to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our natural gas operations have not been regulated by the FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Our oil and gas exploration and production, and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.

Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate. Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws regardless of fault. Under a number of environmental laws, such liabilities may also be strict, joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs, as well as the issuance of administrative or judicial orders limiting operations or prohibiting certain activities. Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation. Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas. Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants. In addition, claims are sometimes made or threatened against companies engaged in oil and gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired. Compliance

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with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.

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

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic oil and gas production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in the notes.

Climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA's rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring after January 1, 2011.

In addition, the Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

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concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act"), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Colombia in September of 2012 although the CFTC has stated that it will appeal the District Court's decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of "swap," "security-based swap," "swap dealer" and "major swap participant." The Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects.

The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act and regulations is to lower commodity prices. Any of these consequences could have material adverse effect on our financial condition and our results of operations.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain

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hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA's study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

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

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

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from various sources for use in our operations. During 2011, West Texas and Southeastern New Mexico experienced the lowest inflows of water in recent history, and these drought conditions expanded into the southern plains states in 2012. As a

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result of this severe drought, some local water districts may begin restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.

A terrorist attack, anti-terrorist efforts or other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to Exchange Offer

If you do not properly tender your old notes, you will continue to hold unregistered old notes and your ability to transfer old notes will remain restricted and may be adversely affected.

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes.

If you do not exchange your old notes for new notes pursuant to the exchange offer, the old notes you hold will continue to be subject to the existing transfer restrictions. In general, you may not offer or sell the old notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not plan to register old notes under the Securities Act unless our registration rights agreement with the initial purchasers of the old notes require us to do so. Further, if you continue to hold any old notes after the exchange offer is consummated, you may have trouble selling them because there will be fewer of these notes outstanding.

Risks Related to the Notes

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our

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existing or future debt agreements including our revolving credit facility and the indenture governing the notes. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our revolving credit facility and the indenture governing the notes will restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. See "Description of Notes."

If we cannot make scheduled payments on our debt, we will be in default and, as a result:

•: our debt holders could declare all outstanding principal and interest to be due and payable;
•: the lenders under our revolving credit facility could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and
•: we could be forced into bankruptcy or liquidation, which could result in you losing your investment in the notes.

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the notes.

Our high level of indebtedness could have important consequences to you, including the following:

•: it may make it difficult for us to satisfy our obligations under the notes and our other indebtedness and contractual and commercial commitments;
•: prevent us from raising the funds necessary to repurchase notes tendered to us if there is a change of control, which would constitute a default under the indenture governing the notes and our revolving credit facility;
•: require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;
•: adversely affect the credit ratings assigned by third-party rating agencies, which have in the past downgraded, and may in the future downgrade their ratings of our debt and other obligations due to changes in our debt level or our financial condition;
•: limit our access to the capital markets;
•: increase our borrowing costs and impact the terms, conditions and restrictions contained in our debt agreements, including the addition of more restrictive covenants;
•: limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;
•: place us at a disadvantage compared to similar companies in our industry that have less debt; and
•: make us more vulnerable to economic downturns and adverse developments in our business.

Our ability to make payments with respect to the notes and to satisfy our other debt obligations will depend on our future operating performance, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control.

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Despite existing debt levels, we and our subsidiaries may still be able to incur substantially more debt, which would increase the risks associated with our leverage.

Even though we are highly leveraged, we may be able to incur substantial amounts of additional debt in the future, including debt under existing and future credit facilities, which may be secured and therefore effectively senior to the notes. Although the terms of the notes and our revolving credit facility limit our ability to incur additional debt, such terms do not and will not prohibit us from incurring substantial amounts of additional debt for specific purposes or under certain circumstances. If new debt is added to our and our subsidiaries' current debt levels, the related risks that we and they now face could intensify. The incurrence of additional debt could adversely impact our ability to service payments on the notes.

Covenants in our debt agreements restrict our business in many ways.

The indenture governing the notes contains various covenants that limit our ability and/or our restricted subsidiaries' ability to, among other things:

•: incur or assume liens or additional debt or provide guarantees in respect of obligations of other persons;
•: issue redeemable stock and preferred stock;
•: pay dividends or distributions or redeem or repurchase capital stock;
•: prepay, redeem or repurchase debt;
•: make loans, investments and capital expenditures;
•: enter into agreements that restrict distributions from our subsidiaries;
•: sell assets and capital stock of our subsidiaries;
•: enter into certain transactions with affiliates;
•: consolidate or merge with or into, or sell substantially all of our assets to, another person; and
•: enter into new lines of business.

In addition, our revolving credit facility also contains restrictive covenants and requires us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those tests. A breach of any of these covenants could result in a default under our revolving credit facility and/or the indenture governing the notes. Upon the occurrence of an event of default under our revolving credit facility, the lenders could elect to declare all amounts outstanding under our revolving credit facility to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our revolving credit facility could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our revolving credit facility. If the lenders under our revolving credit facility accelerate the repayment of borrowings, we cannot assure you that we will have sufficient assets to repay our revolving credit facility and our other indebtedness, including the notes.

Our borrowings under our revolving credit facility are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

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The notes and the guarantees are effectively subordinated to all of our secured debt, and, if a default occurs, we may not have sufficient funds to fulfill our obligations under the notes and the guarantees.

The notes are general senior unsecured obligations that rank equally in right of payment with all of our existing and future unsubordinated indebtedness. The notes are effectively subordinated to all our and our subsidiary guarantors' secured indebtedness to the extent of the value of the assets securing that indebtedness. As of September 30, 2013, after giving effect on a pro forma basis to the Notes Offering, we and our subsidiary guarantors have total consolidated indebtedness, including discounts and premiums, of $678.6 million, including $79 million of secured indebtedness outstanding under our revolving credit facility (excluding $5.1 million in outstanding letters of credit), $599.6 million of our 7.75% Senior Notes due 2019, and we would have been able to incur an additional $325.8 million of secured indebtedness under our revolving credit facility, subject to the terms thereof, the borrowing of which is not limited by the indenture. All of those borrowings are secured by substantially all of our assets and rank effectively senior to the notes and the guarantees. In addition, the indenture governing the notes, subject to some limitations, permits us to incur additional secured indebtedness and your notes will be effectively junior to any additional secured indebtedness we may incur.

In the event of our bankruptcy, liquidation, reorganization or other winding up, our assets that secure our secured indebtedness will be available to pay obligations on the notes only after all secured indebtedness, together with accrued interest, has been repaid in full from our assets. Likewise, because our revolving credit facility is a secured obligation, our failure to comply with the terms of our revolving credit facility would entitle those lenders to declare all the funds borrowed thereunder, together with accrued interest, immediately due and payable. If we were unable to repay such indebtedness, the lenders could foreclose on substantially all of our assets that serve as collateral. In this event, our secured lenders would be entitled to be repaid in full from the proceeds of the liquidation of those assets before those assets would be available for distribution to other creditors, including holders of the notes. Holders of the notes will participate in our remaining assets ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as the notes, and potentially with all of our other general creditors. We advise you that there may not be sufficient assets remaining to pay amounts due on any or all the notes then outstanding. The guarantees of the notes will have a similar ranking with respect to secured and unsecured senior indebtedness of the subsidiary guarantors as the notes do with respect to our secured and unsecured senior indebtedness, as well as with respect to any unsecured obligations expressly subordinated in right of payment to the guarantees.

The notes are structurally subordinated to all indebtedness of our subsidiaries that do not guarantee the notes.

The notes are not guaranteed by our unrestricted subsidiary. You will not have any claim as a creditor against any of our existing and future subsidiaries that are not or do not become guarantors of the notes or that are no longer guarantors of the notes. Indebtedness and other liabilities, including trade payables, whether secured or unsecured, of those subsidiaries will be effectively senior to your claims against those subsidiaries. In addition, the indenture governing the notes, subject to some limitations, permits these subsidiaries to incur additional indebtedness and does not contain any limitation on the amount of other liabilities, such as trade payables, that may be incurred by these subsidiaries. As of September 30, 2013, our non-Guarantor Subsidiaries accounted for approximately 1.1% of our consolidated assets and none of our consolidated liabilities.

We may not be able to repurchase the notes upon a change of control.

Upon the occurrence of specific change of control events, we may be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest. We may not be able to repurchase the notes upon a change of control because we may not have sufficient funds at such time. Further, we may be contractually restricted under the terms of our

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revolving credit facility or other future senior indebtedness from repurchasing all of the notes tendered by holders upon a change of control. Accordingly, we may not be able to satisfy our obligations to purchase your notes unless we are able to refinance or obtain waivers under our revolving credit facility. Our failure to repurchase the notes upon a change of control would cause a default under the indenture and a cross default under our revolving credit facility. Our revolving credit facility also provides that a change of control, as defined therein, will be a default that permits lenders to accelerate the maturity of borrowings thereunder and, if such debt is not paid, to enforce security interests in the collateral securing such debt, thereby limiting our ability to raise cash to purchase the notes and reducing the practical benefit of the offer-to-purchase provisions to the holders of the notes. Any of our future debt agreements may contain similar provisions.

In addition, the change of control provisions in the indenture may not protect you from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction, unless such transaction constitutes a "Change of Control" under the indenture. Such a transaction may not involve a change in voting power or beneficial ownership or, even if it does, may not involve a change that constitutes a "Change of Control" as defined in the indenture that would trigger our obligation to repurchase the notes. Therefore, if an event occurs that does not constitute a "Change of Control" as defined in the indenture, we will not be required to make an offer to repurchase the notes and you may be required to continue to hold your notes despite the event. See "Description of Notes—Change of Control."

The trading prices for the notes may be affected by our credit rating.

Credit rating agencies continually revise their ratings for companies that they follow, including us. Any ratings downgrade could adversely affect the trading price of the notes or the trading market for the notes to the extent a trading market for the notes develops. The condition of the financial and credit markets and prevailing interest rates have fluctuated in the past and are likely to fluctuate in the future.

Many of the covenants contained in the indenture will be suspended if the notes are rated investment grade by both Standard & Poor's and Moody's and no default or event of default has occurred and is continuing.

Many of the covenants in the indenture governing the notes will be suspended if the notes are rated investment grade by both Standard & Poor's and Moody's and no default or event of default has occurred and is continuing. These covenants restrict, among other things, our ability to make certain payments, incur debt and enter into certain other transactions. Suspension of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force. See "Description of Notes—Certain Covenants—Suspended Covenants."

Federal and state fraudulent transfer laws permit a court to void the notes and the guarantees, and, if that occurs, you may not receive any payments on the notes.

The issuance of the notes and the guarantees may be subject to review under federal and state fraudulent transfer and conveyance statutes. While the relevant laws may vary from state to state, under such laws the payment of consideration will be a fraudulent conveyance if (1) we paid the consideration with the intent of hindering, delaying or defrauding creditors or (2) we or any of our subsidiary guarantors, as applicable, received less than reasonably equivalent value or fair consideration in return for issuing either the notes or a guarantee, and, in the case of (2) only, one of the following is also true:

•: we or any of our subsidiary guarantors were or was insolvent or rendered insolvent by reason of the incurrence of the indebtedness;

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•: payment of the consideration left us or any of our subsidiary guarantors with an unreasonably small amount of capital to carry on the business; or
•: we or any of our subsidiary guarantors intended to, or believed that we or it would, incur debts beyond our or its ability to pay as they mature.

If a court were to find that the issuance of the notes or a guarantee was a fraudulent conveyance, the court could void the payment obligations under the notes or such guarantee or subordinate the notes or such guarantee to presently existing and future indebtedness of ours or such subsidiary guarantor, or require the holders of the notes to repay any amounts received with respect to the notes or such guarantee. In the event of a finding that a fraudulent conveyance occurred, you may not receive any repayment on the notes. Further, the voidance of the notes could result in an event of default with respect to our other debt and that of our subsidiary guarantors that could result in acceleration of such debt.

Generally, an entity would be considered insolvent if, at the time it incurred indebtedness:

•: the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;
•: the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts and liabilities, including contingent liabilities, as they become absolute and mature; or
•: it could not pay its debts as they become due.

We cannot be certain as to the standards a court would use to determine whether or not we or the subsidiary guarantors were solvent at the relevant time or, regardless of the standard that a court uses, that the issuance of the notes and the guarantees would not be subordinated to our or any subsidiary guarantor's other debt.

If the guarantees were legally challenged, any guarantee could also be subject to the claim that, since the guarantee was incurred for our benefit, and only indirectly for the benefit of the subsidiary guarantor, the obligations of the applicable subsidiary guarantor were incurred for less than fair consideration. A court could thus void the obligations under the guarantees, subordinate them to the applicable subsidiary guarantor's other debt or take other action detrimental to the holders of the notes.

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

The old notes have not been registered under the Securities Act, and may not be resold by purchasers thereof unless the old notes are subsequently registered or an exemption from the registration requirements of the Securities Act is available. However, we cannot assure you that, even following registration or exchange of the old notes for new notes, that an active trading market for the old notes or the new notes will exist, and we will have no obligation to create such a market. At the time of the private placement of the old notes, the initial purchasers advised us that they intended to make a market in the old notes and, if issued, the new notes. The initial purchasers are not obligated, however, to make a market in the old notes or the new notes and any market-making may be discontinued at any time at their sole discretion. No assurance can be given as to the liquidity of or trading market for the old notes or the new notes.

The liquidity of any trading market for the notes and the market price quoted for the notes will depend upon the number of holders of the notes, the overall market for high yield securities, our financial performance or prospects or the prospects for companies in our industry generally, the interest of securities dealers in making a market in the notes and other factors.

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EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

At the closing of the offering of the old notes, we entered into a registration rights agreement with the initial purchasers pursuant to which we agreed, for the benefit of the holders of the old notes, at our cost, to do the following:

•: file an exchange offer registration statement with the SEC with respect to the exchange offer for the new notes, and
•: use commercially reasonable efforts to have the exchange offer completed by the 365th day following the date of the initial issuance of the notes (October 1, 2014).

Upon the SEC's declaring the exchange offer registration statement effective, we agreed to offer the new notes in exchange for surrender of the old notes. We agreed to use reasonable best efforts to cause the exchange offer registration statement to be effective continuously, to keep the exchange offer open for a period of not less than 20 business days and to use reasonable best efforts to cause the exchange offer to be consummated promptly after the exchange offer registration statement is declared effective by the SEC.

For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date on which interest was paid on the surrendered old note or, if no interest has been paid on such old note, from October 1, 2013. The registration rights agreement also obligates us to include in the prospectus for the exchange offer certain information necessary to allow a broker-dealer who holds old notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of new notes received by such broker-dealer in the exchange offer. We agreed to amend or supplement the prospectus contained in the exchange offer registration statement for a period of 180 days after the last exchange date, which period may be extended under certain circumstances.

The preceding agreement is needed because any broker-dealer who acquires old notes for its own account as a result of market-making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This prospectus covers the offer and sale of the new notes pursuant to the exchange offer and the resale of new notes received in the exchange offer by any broker-dealer who held old notes acquired for its own account as a result of market-making activities or other trading activities other than old notes acquired directly from us or one of our affiliates.

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the exchange offer would in general be freely tradable after the exchange offer without further registration under the Securities Act. However, any purchaser of old notes who is an "affiliate" of ours or who intends to participate in the exchange offer for the purpose of distributing the related new notes:

•: will not be able to rely on the interpretation of the staff of the SEC,
•: will not be able to tender its old notes in the exchange offer, and
•: must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the old notes unless such sale or transfer is made pursuant to an exemption from such requirements.

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Each holder of the old notes (other than certain specified holders) who desires to exchange old notes for the new notes in the exchange offer will be required to make the representations described below under "—Procedures for Tendering—Your Representations to Us."

We further agreed to file with the SEC a shelf registration statement to register for public resale of old notes held by any holder who provides us with certain information for inclusion in the shelf registration statement if:

•: the exchange offer is not available or may not be completed as soon as practicable after the last exchange date because it would violate any applicable law or applicable interpretation of the staff of the SEC, or
•: upon completion of the exchange offer, any initial purchaser shall so request, no later than the 90th day after the completion of the exchange offer (provided that such date occurs prior to October 1, 2014), in connection with any offering or sale of notes.

We have agreed to use reasonable best efforts to keep the shelf registration statement continuously effective until the earlier of October 1, 2014 and such time as all notes covered by the shelf registration statement have been sold. We refer to this period as the "shelf effectiveness period."

The registration rights agreement provides that, in the event that either the exchange offer is not completed by October 1, 2014, or the shelf registration statement, if required, is not declared effective within 60 days after such shelf registration statement is required to be filed, the interest rate on the old notes will be increased by (i) 0.25% per annum for the first 90-day period that such condition is not satisfied and (ii) an additional 0.25% per annum with respect to each successive 90-day period during which the condition is not satisfied, up to a maximum additional interest of 0.50% per annum of additional interest until the exchange offer is completed or the shelf registration statement, if required, is declared effective by the SEC or is no longer required to be effective.

If the shelf registration statement, if required, has been declared effective and thereafter either ceases to be effective or the prospectus contained therein ceases to be usable at any time during the shelf effectiveness period, and such failure to remain effective or usable exists for more than 30 days (whether or not consecutive) in the shelf effectiveness period, then the interest rate on the old notes will be increased by (i) 0.25% per annum for the first 90-day period that such condition is not satisfied and (ii) an additional 0.25% per annum with respect to each successive 90-day period during which the condition is not satisfied, up to a maximum additional interest of 0.50% per annum of additional interest, commencing on the 31st day in the shelf effectiveness period and ending on the earlier of (a) such date that the shelf registration statement has again been declared effective or the prospectus again becomes usable, or (b) the date on which the shelf registration statement is no longer required to be effective.

Holders of the old notes will be required to make certain representations to us (as described in the registration rights agreement) in order to participate in the exchange offer and may be required to deliver information to be used in connection with the shelf registration statement and to provide comments on the shelf registration statement within the time periods set forth in the registration rights agreement in order to have their old notes included in the shelf registration statement.

If we effect the registered exchange offer, we will be entitled to close the registered exchange offer 20 business days after its commencement as long as we have accepted all old notes validly tendered in accordance with the terms of the exchange offer and no brokers or dealers continue to hold any old notes.

This summary of the material provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the

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registration rights agreement, copies of which are filed as exhibits to the registration statement which includes this prospectus.

Except as set forth above, after consummation of the exchange offer, holders of old notes which are the subject of the exchange offer have no registration or exchange rights under the registration rights agreement. See "—Consequences of Failure to Exchange."

Terms of the Exchange Offer

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this prospectus, $250,000,000 in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934 and the rules and regulations of the SEC. Old notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes and the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender old notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important that you read the section labeled "—Fees and Expenses" for more details regarding fees and expenses incurred in the exchange offer.

We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offer.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on , 2014, unless, in our sole discretion, we extend it.

Extensions, Delays in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

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In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

If any of the conditions described below under "—Conditions to the Exchange Offer" have not been satisfied, we reserve the right, in our sole discretion:

•: to delay accepting for exchange any old notes,
•: to extend the exchange offer, or
•: to terminate the exchange offer,

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

Any such delay in acceptance, extension, termination or amendment will be followed promptly by oral or written notice thereof to the registered holders of old notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the exchange offer. In the event of a material change in the exchange offer, including the waiver by us of a material condition, we will extend the exchange offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

Conditions to the Exchange Offer

We will not be required to accept for exchange, or exchange any new notes for, any old notes if the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under "—Purpose and Effect of the Exchange Offer," "—Procedures for Tendering" and "Plan of Distribution" and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give prompt oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

In addition, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

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Procedures for Tendering

In order to participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

If you have any questions or need help in exchanging your notes, please call the exchange agent, whose address and phone number are set forth in "Prospectus Summary—The Exchange Offer—Exchange Agent."

All of the old notes were issued in book-entry form, and all of the old notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the old notes may be tendered using the Automated Tender Offer Program ("ATOP") instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an "agent's message" to the exchange agent. The agent's message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

There is no procedure for guaranteed late delivery of the notes.

Determinations Under the Exchange Offer

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

When We Will Issue New Notes

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

•: a book-entry confirmation of such old notes into the exchange agent's account at DTC; and
•: a properly transmitted agent's message.

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Return of Old Notes Not Accepted or Exchanged

If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

Your Representations to Us

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

•: any new notes that you receive will be acquired in the ordinary course of your business;
•: you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes;
•: you are not our "affiliate," as defined in Rule 405 of the Securities Act; and
•: if you are a broker-dealer that will receive new notes for your own account in exchange for old notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus (or to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the expiration date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC's ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any old notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under "—Procedures for Tendering" above at any time prior to 5:00 p.m., New York City time, on the expiration date.

Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by facsimile, telephone, electronic mail or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

•: all registration and filing fees and expenses;

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•: all fees and expenses of compliance with federal securities and state "blue sky" or securities laws;
•: accounting and legal fees, disbursements and printing, messenger and delivery services, and telephone costs; and
•: related fees and expenses.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

Consequences of Failure to Exchange

If you do not exchange new notes for your old notes under the exchange offer, you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the offer or sale is either registered under the Securities Act or exempt from the registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Other

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

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USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in outstanding indebtedness.

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SUMMARY HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table sets forth selected consolidated financial data for CWEI as of the dates and for the periods indicated. The consolidated financial data for each of the years in the five-year period ended December 31, 2012 was derived from our audited consolidated financial statements. The consolidated financial data for the nine month periods ended September 30 of 2012 and 2013 was derived from our unaudited consolidated financial statements. The data set forth in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes contained herein.

	Year Ended December 31,															Nine Months Ended September 30,

	2012			2011			2010			2009			2008			2013			2012
	(In thousands, except per share)
																(unaudited)
Statement of Operations Data:
Revenues:
Oil and gas sales	$	403,143		$	405,216		$	326,320		$	242,338		$	463,964		$	296,146		$	308,116
Midstream services		1,974			1,408			1,631			6,146			10,926			3,373			1,305
Drilling rig services		15,858			4,060			—			6,681			46,124			12,896			11,478
Other operating revenues		2,077			15,744			3,680			796			44,503			4,533			543


Total revenues		423,052			426,428			331,631			255,961			565,517			316,948			321,442


Costs and expenses:
Production		124,950			101,099			83,146			76,288			89,054			83,254			93,937
Exploration:
Abandonment and impairments		4,222			20,840			9,074			78,798			80,112			2,980			2,292
Seismic and other		11,591			5,363			6,046			8,189			22,685			3,541			5,445
Midstream services		1,228			1,039			1,209			5,348			10,060			1,318			956
Drilling rig services		17,423			5,064			1,198			10,848			37,789			12,704			12,164
Depreciation, depletion and amortization		142,687			104,880			101,145			129,658			120,542			109,863			103,486
Impairment of property and equipment		5,944			10,355			11,908			59,140			12,882			89,811			5,711
Accretion of asset retirement obligations		3,696			2,757			2,623			3,120			2,355			3,169			2,628
General and administrative		30,485			41,560			35,588			20,715			25,635			20,401			25,133
Other operating expenses		1,033			1,666			1,750			5,282			2,122			1,869			485


Total costs and expenses		343,259			294,623			253,687			397,386			403,236			328,910			252,237


Operating income (loss)		79,793			131,805			77,944			(141,425	)		162,281			(11,962	)		69,205


Other income (expense):
Interest expense		(38,664	)		(32,919	)		(24,402	)		(23,758	)		(24,994	)		(30,106	)		(27,817	)
Loss on early extinguishment of long-term debt		—			(5,501	)		—			—			—			—			—
Gain (loss) on derivatives		14,448			47,027			722			(17,416	)		74,743			(9,919	)		9,856
Other income		1,534			5,553			3,308			2,543			6,539			2,007			739


Total other income (expense)		(22,682	)		14,160			(20,372	)		(38,631	)		56,288			(38,018	)		(17,222	)


Income (loss) before income taxes		57,111			145,965			57,572			(180,056	)		218,569			(49,980	)		51,983
Income tax (expense) benefit		(22,008	)		(52,142	)		(20,634	)		64,096			(77,327	)		18,693			(18,558	)


NET INCOME (LOSS)		35,103			93,823			36,938			(115,960	)		141,242			(31,287	)		33,425


Less income attributable to noncontrolling interest, net of tax		—			—			—			(1,455	)		(708	)		—			—


NET INCOME (LOSS) attributable to Clayton Williams Energy, Inc.	$	35,103		$	93,823		$	36,938		$	(117,415	)	$	140,534		$	(31,287	)	$	33,425




Net income (loss) per common share attributable to Clayton Williams Energy, Inc. stockholders:
Basic	$	2.89		$	7.72		$	3.04		$	(9.67	)	$	11.78		$	(2.57	)	$	2.75




Diluted	$	2.89		$	7.71		$	3.04		$	(9.67	)	$	11.67		$	(2.57	)	$	2.75




Weighted average common shares outstanding:
Basic		12,164			12,161			12,148			12,138			11,932			12,165			12,164




Diluted		12,164			12,162			12,148			12,138			12,039			12,165			12,164




Other Data:
Net cash provided by operating activities	$	189,222		$	280,047		$	208,251		$	104,711		$	381,980		$	153,881		$	157,883

(continued)

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	December 31,												Nine Months Ended September 30,

	2012		2011			2010			2009		2008		2013		2012
	(In thousands)
													(unaudited)
Balance Sheet Data:
Working capital (deficit)	$	3,556	$	(13,287	)	$	(19,899	)	$	19,324	$	2,607	$	31,423	$	(2,283	)
Total assets		1,574,584		1,226,271			890,917			784,604		943,409		1,379,710		1,546,539
Long-term debt		809,585		529,535			385,000			395,000		347,225		672,625		769,572
Stockholders' equity		378,616		343,501			249,452			212,275		320,276		347,329		376,926

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RATIOS OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratios of consolidated earnings to fixed charges for the periods presented:

	Year Ended December 31,

	Year Ended December 31,										Nine Months Ended September 30, 2013
	2008		2009		2010		2011		2012		Nine Months Ended September 30, 2013
Ratio of earnings to fixed charges(a)		5.8x		(b)		2.5x		3.8x		1.9x		(b)

(a): For purposes of calculating the ratios of consolidated earnings to fixed charges, "earnings" consists of income (loss) from continuing operations, plus fixed charges. "Fixed charges" consist of interest and financing expense, amortization of deferred financing costs and the estimated interest factor attributable to rental expense.
(b): We had an earnings to fixed charges deficiency of approximately $116.7 million for the year ended December 31, 2009 and $32.2 million for the nine months ended September 30, 2013.

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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 prospectus. 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.

Overview

We are engaged in developmental drilling in two primary oil-prone regions, the Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities. One core area of the Permian Basin is our Bone Springs/Wolfcamp play ("Wolfbone") located in the Delaware Basin on the western edge of the Permian Basin. We are also continuing to exploit Eagle Ford Shale drilling opportunities on our extensive acreage position in the Giddings Area of East Central Texas. During the nine months ended September 30, 2013, we spent $197.6 million on exploration and development activities.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the third quarter of 2013 and the outlook for the remainder of 2013.

•: In April 2013, we sold 95% of our Wolfberry oil and gas reserves, leasehold interests and facilities located in Andrews County, Texas for $215.2 million, subject to customary closing adjustments, with $25.9 million remaining in escrow pending resolution of certain title requirements that we believe will be cured. As a result, reported oil and gas production, revenues and operating costs for the quarter and nine months ended September 30, 2013 are not comparable to reported amounts for periods in 2012.
•: Our oil and gas sales, excluding amortized deferred revenues, increased $2.7 million, or 3%, from the third quarter 2012. Price variances accounted for a $13.3 million increase and production variances accounted for a $10.6 million decrease. Average realized oil prices were $103.75 per barrel in the third quarter of 2013 versus $89.48 per barrel in the third quarter 2012, and average realized gas prices were $3.49 per Mcf in 2013 versus $3.29 per Mcf in 2012. In addition, oil and gas sales for the third quarter of 2013 includes $2.2 million of amortized deferred revenue attributable to the volumetric production payment ("VPP") versus $2.5 million for the third quarter of 2012. Reported production and related average realized sales prices exclude volumes associated with the VPP.
•: Our oil, gas and natural gas liquids ("NGL") production per barrel of oil equivalent ("BOE") declined 12% compared to the third quarter 2012, with oil production decreasing 10% to 9,674 barrels per day, gas production decreasing 24% to 16,598 Mcf per day and NGL production increasing 9% to 1,359 barrels per day. Oil and NGL production accounted for approximately 80% of our total BOE production in the third quarter of 2013 versus 77% in the third quarter of 2012. Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible, resulting in a reduction in natural gas volumes and an increase in extracted NGL volumes. Periods for 2012 have not been adjusted to conform to the 2013 presentation.

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•: After giving effect to the Andrews sale discussed above, oil and gas production on a BOE basis increased 4% for the third quarter of 2013 as compared to the third quarter of 2012, with oil production increasing 587 barrels per day, gas production decreasing 3,511 Mcf per day and NGL production increasing 500 barrels per day.
•: Production costs decreased 21% or $6.9 million for the third quarter of 2013 compared to the third quarter of 2012. After giving effect to the Andrews sale, production costs declined $1.8 million, or 6%, due primarily to lower salt water disposal costs and other cost savings resulting from infrastructure improvements in the Reeves County Wolfbone area.
•: We recorded an $8.3 million net loss on derivatives in the third quarter of 2013, consisting of a $7.8 million unrealized loss for changes in mark-to-market valuations and a $455,000 realized loss on settled contracts. For the same period in 2012, we recorded a $21.9 million net loss on derivatives, consisting of a $20.5 million unrealized loss for changes in mark-to-market valuations and a $1.4 million realized loss on settled contracts. 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.
•: General and administrative ("G&A") expenses were $10 million in the third quarter of 2013 compared to $5.8 million in the third quarter of 2012. G&A expenses in the third quarter of 2012 related to accrued compensation expense from our APO reward plans included a non-cash reversal of previously accrued compensation expense totaling $2.2 million as compared to a charge of $1.2 million in the third quarter of 2013.

Proved Oil and Gas Reserves

The following table summarizes changes in our estimated proved reserves during 2012.



As of December 31, 2011	64,349
Extensions and discoveries	20,443
Purchases of minerals-in-place	3,504
Revisions	(6,615	)
Sales of minerals-in-place	(725	)
Production	(5,599	)


As of December 31, 2012	75,357

Extensions and discoveries. Extensions and discoveries in 2012 added 20,443 MBOE of proved reserves, replacing 365% of our 2012 production. These additions resulted primarily from our Reeves County and Andrews County drilling programs in the Permian Basin. Of the total reserve additions, proved developed reserves accounted for 5,975 MBOE, while the remaining 14,468 MBOE were proved undeveloped reserves.

Purchases of minerals-in-place. In March 2012, we added 3,504 MBOE of proved reserves with the completion of the SWR Mergers.

Revisions. Net downward revisions of 6,615 MBOE consisted of downward revisions of 4,339 MBOE related to performance and downward revisions of 2,276 MBOE related to pricing. Downward price revisions of 2,276 MBOE were attributable to the effects of lower product prices on the estimated quantities of proved reserves. Substantially all of the downward performance revisions were attributable to the Company's Andrews County Wolfberry drilling program.

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Sales of minerals-in-place. In March 2012, SWR entered into a VPP with a third party and conveyed a term overriding royalty interest covering 725 MBOE of estimated future oil and gas production from certain properties to obtain funds to finance the SWR Mergers.

The following table summarizes changes in our estimated proved undeveloped reserves during 2012.



As of December 31, 2011	25,085
Extensions and discoveries	14,468
Purchases of minerals-in-place	1,089
Revisions	(4,644	)
Reclassified to proved developed	(3,994	)


As of December 31, 2012	32,004

We added 14,468 MBOE of proved undeveloped reserves from extensions and discoveries related to Permian Basin and Giddings Area drilling locations, including 1,207 MBOE of upgrades from probable to proved undeveloped. We had purchases of minerals-in-place of 1,089 MBOE in connection with the completion of the SWR Mergers. Downward revisions of 4,644 MBOE resulted primarily from performance revisions of 3,351 MBOE and pricing revisions of 1,293 MBOE. We also converted 3,994 MBOE of proved undeveloped reserves at December 31, 2012 to proved developed reserves during 2012 at a cost of approximately $126.4 million. We expect to develop approximately 6.5% of our proved undeveloped reserves in 2013 at a cost of approximately $41.3 million.

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Supplemental Information—Interim Periods Ended September 30, 2013 and 2012

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

	Three Months Ended September 30,

	2013			2012
Oil and Gas Production Data:
Oil (MBbls)		890			993
Gas (MMcf)		1,527			2,010
Natural gas liquids (MBbls)		125			115
Total (MBOE)		1,270			1,443
Average Realized Prices(a)(b):
Oil ($/Bbl)	$	103.75		$	89.48




Gas ($/Mcf)	$	3.49		$	3.29




Natural gas liquids ($/Bbl)	$	33.47		$	31.37




Loss on Settled Derivative Contracts(b):
($ in thousands, except per unit)
Oil: Net realized loss	$	(367	)	$	(1,390	)
Per unit produced ($/Bbl)	$	(0.41	)	$	(1.40	)
Gas: Net realized loss	$	(88	)	$	—
Per unit produced ($/Mcf)	$	(0.06	)	$	—
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin		1,934			2,018
Other		3,476			5,247
Austin Chalk/Eagle Ford Shale		3,889			3,199
Other(c)		375			329


Total		9,674			10,793




Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin		1,695			1,449
Other(c)(d)		7,569			12,246
Austin Chalk/Eagle Ford Shale		2,051			1,793
Other		5,283			6,360


Total		16,598			21,848




Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin		348			257
Other(c)(d)		718			711
Austin Chalk/Eagle Ford Shale		274			232
Other		19			50


Total		1,359			1,250

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	Three Months Ended September 30,

	2013		2012
Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	—	$	32
Permian Basin		39		53
Deep Bossier		—		111
Other		570		110


Total		609		306


Seismic and other		177		2,710


Total exploration costs	$	786	$	3,016




Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	31,641	$	35,145
Contract drilling depreciation		2,696		2,082
Other depreciation		591		434


Total depreciation, depletion, and amortization	$	34,928	$	37,661




Oil and Gas Costs ($/BOE Produced):
Production costs	$	20.20	$	22.57
Production costs (excluding production taxes)	$	15.98	$	18.99
Oil and gas depletion	$	24.91	$	24.36
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	8,826	$	8,024
Non-cash employee compensation(e)		1,204		(2,194	)


Total	$	10,030	$	5,830




Net Wells Drilled(f):
Exploratory Wells		1.2		0.5
Developmental Wells		14.1		23.9

	Nine Months Ended September 30,

	2013			2012
Oil and Gas Production Data:
Oil (MBbls)		2,695			2,889
Gas (MMcf)		4,753			6,154
Natural gas liquids (MBbls)		399			304
Total (MBOE)		3,886			4,219
Average Realized Prices(a)(b):
Oil ($/Bbl)	$	96.16		$	92.62




Gas ($/Mcf)	$	3.56		$	3.46




Natural gas liquids ($/Bbl)	$	32.44		$	40.05




Loss on Settled Derivative Contracts(b):
($ in thousands, except per unit)
Oil: Net realized loss	$	(981	)	$	(4,961	)
Per unit produced ($/Bbl)	$	(0.36	)	$	(1.72	)
Gas: Net realized loss	$	(383	)	$	—
Per unit produced ($/Mcf)	$	(0.08	)	$	—

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	Nine Months Ended September 30,

	2013		2012
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin		1,886		1,575
Other(c)		3,983		5,473
Austin Chalk/Eagle Ford Shale		3,708		3,115
Other		295		378


Total		9,872		10,541




Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin		1,582		780
Other(c)(d)		8,229		12,797
Austin Chalk/Eagle Ford Shale		2,113		1,997
Other		5,486		6,881


Total		17,410		22,455




Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin		299		117
Other(c)(d)		905		687
Austin Chalk/Eagle Ford Shale		240		241
Other		18		63


Total		1,462		1,108




Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	1,000	$	344
Permian Basin		43		349
Deep Bossier		—		1,322
Other		1,937		277


Total		2,980		2,292


Seismic and other		3,541		5,445


Total exploration costs	$	6,521	$	7,737




Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	99,269	$	97,698
Contract drilling depreciation		8,861		4,781
Other depreciation		1,733		1,007


Total depreciation, depletion, and amortization	$	109,863	$	103,486




Oil and Gas Costs ($/BOE Produced):
Production costs	$	21.42	$	22.27
Production costs (excluding production taxes)	$	17.57	$	18.55
Oil and gas depletion	$	25.55	$	23.16

(continued)

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	Nine Months Ended September 30,

	2013			2012
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	26,298		$	22,933
Non-cash employee compensation(e)		(5,897	)		2,200


Total	$	20,401		$	25,133




Net Wells Drilled(f):
Exploratory Wells		2.7			3.8
Developmental Wells		38.8			76.1

(a): Oil and gas sales includes $2.2 million for the three months ended September 30, 2013, $2.5 million for the three months ended September 30, 2012, $6.6 million for the nine months ended September 30, 2013, and $5.9 million for the nine months ended September 30, 2012 of amortized deferred revenue attributable to a volumetric production payment ("VPP") transaction effective March 1, 2012. The calculation of average realized sales prices excludes production of 28,793 barrels of oil and 8,550 Mcf of gas for the three months ended September 30, 2013, 32,788 barrels of oil and 14,826 Mcf of gas for the three months ended September 30, 2012, 88,897 barrels of oil and 23,589 Mcf of gas for the nine months ended September 30, 2013 and 77,755 barrels of oil and 32,000 Mcf of gas for the nine months ended September 30, 2012 associated with the VPP.
(b): No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in other income (expense)—gain (loss) on derivatives.
(c): In April 2013, we sold 95% of our interest in certain properties in Andrews County, Texas. The following is a summary of the average daily production related to the sold interest for periods prior to April 1, 2013.

			Nine Months Ended September 30,

	Three Months Ended September 30, 2013		Nine Months Ended September 30,
	Three Months Ended September 30, 2013		2013		2012
Average Daily Production:
Oil (Bbls)		1,707		538		1,974
Natural gas (Mcf)		1,739		597		1,595
NGL (Bbls)		391		117		394
Total (Boe)		2,388		755		2,634

(d): Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible. Had these incremental NGL volumes been reported separately during the three months and nine months ended September 30, 2012, we estimate that our reported natural gas volumes would have decreased by 2,200 Mcf/day and that our reported NGL volumes would have increased by 600 BOE/day during each of the 2012 periods.
(e): Non-cash employee compensation relates to our non-equity award plans.
(f): Excludes wells being drilled or completed at the end of each period.

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Operating Results—Three-Month Periods

The following discussion compares our results for the three months ended September 30, 2013 to the comparative period in 2012. Unless otherwise indicated, references to 2013 and 2012 within this section refer to the three months ended September 30, 2013 and 2012, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, increased $2.7 million, or 3% in 2013, from 2012. Price variances accounted for a $13.3 million increase, and production variances accounted for a $10.6 million decrease. Oil and gas sales in 2013 also include $2.2 million of amortized deferred revenue versus $2.5 million in 2012 attributable to a VPP. Combined oil, gas and NGL production in 2013 (on a BOE basis) declined 12% compared to 2012. Our production mix increased from 77% oil and NGL in 2012 to approximately 80% in 2013. Oil production decreased 10% in 2013 from 2012. NGL production increased 9% while gas production decreased 24% in 2013 from 2012. Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible. Had these incremental NGL volumes been reported separately during 2012, we estimate that our natural gas volumes would have decreased by approximately 2,200 Mcf per day related to plant shrinkage and that NGL volumes would have increased by approximately 600 BOE per day. Periods for 2012 have not been adjusted to conform to the 2013 presentation. In 2013, our realized oil price was 16% higher than 2012, and our realized gas price was 6% higher. 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, decreased 21% to $25.7 million in 2013 as compared to $32.6 million in 2012. After giving effect to the Andrews sale, production costs declined $1.8 million, or 6%, due primarily to lower salt water disposal costs and other cost savings resulting from infrastructure improvements in the Reeves County Wolfbone area.

Oil and gas depletion expense decreased $3.5 million from 2012 to 2013 due to a $4.2 million decrease related to production variances and a $708,000 increase due to rate variances. On a BOE basis, depletion expense increased 2% to $24.91 per BOE in 2013 from $24.36 per BOE in 2012. Most of the decrease in depletion expense related to a decrease in production related to the sale of our Andrews County assets offset by an increase in production in the Giddings area and increases in rate variances in the Wolfbone area. 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.

We recorded a provision for impairment of property and equipment of $709,000 in 2013 and none in 2012. The 2013 impairment was to write down the carrying value of certain non-core Permian Basin properties to their estimated fair value. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value.

Exploration costs

We follow the successful efforts method of accounting, therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2013, we charged to expense $786,000 of exploration costs, as compared to $3 million in 2012.

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Contract drilling services

We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development activities. Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss). Drilling rig services revenue related to external customers was $4 million in 2013 compared to $5.3 million in 2012. Drilling service costs related to external customers and idle rig charges were $3.2 million in 2013 and $5.3 million in 2012. Contract drilling depreciation for 2013 was $2.7 million compared to $2.1 million in 2012.

General and Administrative

G&A expenses increased $4.2 million from $5.8 million in 2012 to $10 million in 2013. G&A expenses for the three months ended September 30, 2012 related to accrued compensation expense from our APO reward plans included a non-cash reversal of previously accrued compensation expense of $2.2 million as compared to a charge of $1.2 million for the three months ended September 30, 2013. Credits to employee compensation expense from incentive compensation plans result from reversals of previously accrued compensation expense due to a combination of actual payments to plan participants and changes in estimated future compensation expense based on commodity prices and production forecasts.

Gain/loss on derivatives

We did not designate any derivative contracts in 2013 or 2012 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the three months ended September 30, 2013, we reported an $8.3 million net loss on derivatives, consisting of a $7.8 million non-cash unrealized loss to mark our derivative positions to their fair value at September 30, 2013 and a $455,000 realized loss on settled contracts. For the three months ended September 30, 2012, we reported a $21.9 million net loss on derivatives, consisting of a $20.5 million non-cash unrealized loss to mark our derivative positions to their fair value at September 30, 2012 and a $1.4 million realized loss on settled contracts. 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 $1.8 million on sales of assets and impairment of inventory in 2013 compared to a net loss of $101,000 in 2012. The 2013 gain related primarily to the sale of our Wash McAdams properties in Walker County, Texas. The 2012 loss related primarily to the write-down of inventory to its estimated market value at September 30, 2012. Gain on sales of assets is included in other operating revenues and loss on sales of assets and impairment of inventory is included in other operating expenses in our consolidated statements of operations and comprehensive income (loss).

Income taxes

Our estimated federal and state effective income tax rate in 2013 of 35% was equal to the statutory federal rate of 35%.

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Operating Results—Nine-Month Periods

The following discussion compares our results for the nine months ended September 30, 2013 to the comparative period in 2012. Unless otherwise indicated, references to 2013 and 2012 within this section refer to the nine months ended September 30, 2013 and 2012, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $12.7 million, or 4% in 2013, from 2012. Production variances accounted for a $19.7 million decrease and price variances accounted for a $7 million increase. Oil and gas sales in 2013 also include $6.6 million of amortized deferred revenue versus $5.9 million in 2012 attributable to a VPP. Combined oil, gas and NGL production in 2013 (on a BOE basis) declined 8% compared to 2012. Our production mix increased from 76% oil and NGL in 2012 to approximately 80% in 2013. Oil production decreased 7% in 2013 from 2012. NGL production increased 31% while gas production decreased 23% in 2013 from 2012. Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible. Had these incremental NGL volumes been reported separately during 2012, we estimate that our natural gas volumes would have decreased by approximately 2,200 Mcf per day related to plant shrinkage and that our NGL volumes would have increased by approximately 600 BOE per day. Periods for 2012 have not been adjusted to conform to the 2013 presentation. In 2013, our realized oil price was 4% higher than 2012, and our realized gas price was 3% higher. 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, decreased 11% to $83.3 million in 2013 as compared to $93.9 million in 2012. After giving effect to the Andrews sale, production costs increased $430,000, or 1%, due primarily to a combination of more producing wells and rising costs of field services, which was offset in part by cost savings resulting from infrastructure improvements in the Reeves County Wolfbone area.

Oil and gas depletion expense increased $1.6 million from 2012 to 2013 due to a $9.3 million increase related to rate variances and a $7.7 million decrease due to production variances. On a BOE basis, depletion expense increased 10% to $25.55 per BOE in 2013 from $23.16 per BOE in 2012. 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.

We recorded a provision for impairment of property and equipment of $89.8 million in 2013 and $5.7 million in 2012. The 2013 impairment was related to the write down of our Andrews County Wolfberry assets and certain non-core Permian Basin properties to their estimated fair value. The impairments for 2012 related to non-core areas in the Permian Basin to reduce the carrying values of those properties to their estimated fair value. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value.

Exploration costs

We follow the successful efforts method of accounting, therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2013, we charged to expense $6.5 million of exploration costs, as compared to $7.7 million in 2012.

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Contract drilling services

We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development activities. Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss). Drilling rig services revenue related to external customers was $12.9 million in 2013 compared to $11.5 million in 2012. Drilling service costs related to external customers and idle rig charges were $12.7 million in 2013 compared to $12.2 million in 2012. Contract drilling depreciation for 2013 was $8.9 million compared to $4.8 million in 2012.

General and Administrative

G&A expenses decreased $4.7 million from $25.1 million in 2012 to $20.4 million in 2013. Most of the decrease was attributable to non-cash reversals of previously accrued compensation expense from our APO reward plans in 2013. The 2013 credits to G&A expense were offset by cash payments to participants in plans associated with the Andrews County properties. Credits to employee compensation expense from incentive compensation plans result from reversals of previously accrued compensation expense due to a combination of actual payments to plan participants and changes in estimated future compensation expense based on commodity prices and production forecasts.

Gain/loss on derivatives

We did not designate any derivative contracts in 2013 or 2012 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the nine months ended September 30, 2013, we reported a $9.9 million net loss on derivatives, consisting of an $8.5 million non-cash unrealized loss to mark our derivative positions to their fair value at September 30, 2013 and a $1.4 million realized loss on settled contracts. For the nine months ended September 30, 2012, we reported a $9.9 million net gain on derivatives, consisting of a $14.8 million non-cash unrealized gain to mark our derivative positions to their fair value at September 30, 2012 and a $4.9 million realized loss on settled contracts. 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 $1.5 million on sales of assets and impairment of inventory in 2013 compared to a net gain of $58,000 in 2012. The 2013 gain related primarily to the sale of our Andrews County, Texas properties and the Wash McAdams properties in Walker County, Texas. Gain on sales of assets are included in other operating revenues and loss on sales of assets and impairment of inventory are included in other operating expenses in our consolidated statements of operations and comprehensive income (loss).

Income taxes

Our estimated federal and state effective income tax rate in 2013 of 37.4% 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.

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Supplemental Information—Annual Periods 2012, 2011 and 2010

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

	As of or for the Year Ended December 31,

	2012			2011		2010
Oil and Gas Production Data:
Oil (MBbls)		3,821			3,727		3,375
Gas (MMcf)		8,072			8,594		10,750
Natural gas liquids (MBbls)		433			275		292
Total (MBOE)		5,599			5,434		5,459
Average Realized Prices(a)(b):
Oil ($/Bbl)	$	90.97		$	92.43	$	76.44




Gas ($/Mcf)	$	3.59		$	5.30	$	5.17




Natural gas liquids ($/Bbl)	$	38.95		$	53.37	$	42.47




Gain (Loss) on Settled Derivative Contracts(b):
($ in thousands, except per unit)
Oil: Net realized gain (loss)	$	(3,410	)	$	23,354	$	(7,685	)
Per unit produced ($/Bbl)	$	(0.89	)	$	6.27	$	(2.28	)
Gas: Net realized gain	$	—		$	19,167	$	17,560
Per unit produced ($/Mcf)	$	—		$	2.23	$	1.63
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin		1,656			202		—
Other		5,369			6,060		5,601
Austin Chalk/Eagle Ford Shale		3,074			3,477		2,944
Other		341			472		702


Total		10,440			10,211		9,247




Gas (Mcf):
Permian Basin Area:
Delaware Basin		910			—		—
Other		12,560			12,304		13,668
Austin Chalk/Eagle Ford Shale		2,034			2,142		2,179
Other		6,551			9,099		13,605


Total		22,055			23,545		29,452




Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin		168			—		—
Other		693			461		440
Austin Chalk/Eagle Ford Shale		267			212		237
Other		55			80		123


Total		1,183			753		800




Total Proved Reserves:
Oil (MBbls)		49,119			44,919		34,379
Natural gas liquids (MBbls)		9,182			4,617		3,436
Gas (MMcf)		102,336			88,876		79,497
Total (MBOE)		75,357			64,349		51,065
Standardized measure of discounted future net cash flows	$	939,831		$	938,513	$	684,438
Total Proved Reserves by Area:
Oil (MBbls):
Permian Basin Area:
Delaware Basin		14,618			7,519		—
Other		25,955			28,226		24,769
Austin Chalk/Eagle Ford Shale		8,039			8,669		9,031
Other		507			505		579


Total		49,119			44,919		34,379

(continued)

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	As of or for the Year Ended December 31,

	2012			2011		2010
Natural Gas Liquids (MBbls):
Permian Basin Area:
Delaware Basin		4,249			—		—
Other		4,345			4,016		2,859
Austin Chalk/Eagle Ford Shale		572			545		521
Other		16			56		56


Total		9,182			4,617		3,436




Gas (MMcf):
Permian Basin Area:
Delaware Basin		20,651			6,887		—
Other		64,727			62,549		59,549
Austin Chalk/Eagle Ford Shale		6,130			6,271		5,620
Other		10,828			13,169		14,328


Total		102,336			88,876		79,497




Total Oil Equivalent (MBOE):
Permian Basin Area:
Delaware Basin		22,309			8,667		—
Other		41,087			42,667		37,553
Austin Chalk/Eagle Ford Shale		9,633			10,259		10,489
Other		2,328			2,756		3,023


Total		75,357			64,349		51,065




Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	1,918		$	2,105	$	1,261
Permian Basin		453			673		18
Deep Bossier		1,323			16,771		2,522
Other		528			1,291		5,273


Total		4,222			20,840		9,074


Seismic and other		11,591			5,363		6,046


Total exploration costs	$	15,813		$	26,203	$	15,120




Oil and Gas Costs ($/BOE Produced):
Production costs	$	22.32		$	18.60	$	15.23
Production costs (excluding production taxes)	$	18.70		$	14.79	$	12.03
Oil and gas depletion	$	23.84		$	18.72	$	18.09
General and Administrative Expenses (in thousands):
Excluding non-cash employee compensation	$	30,889		$	28,694	$	21,690
Non-cash employee compensation(c)		(404	)		12,866		13,898


Total	$	30,485		$	41,560	$	35,588




Net Wells Drilled(d):
Developmental wells		92.3			111.8		112.5
Exploratory wells		4.3			3.6		2.5

(a): Oil and gas sales for 2012 includes $8.3 million for the year ended December 31, 2012 of amortized deferred revenue attributable to the VPP granted effective March 1, 2012. The calculation of average realized sales prices for 2012 excludes production of 109,733 barrels of oil and 49,558 Mcf of gas for the year ended December 31, 2012 associated with the VPP.
(b): No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in other income (expense)—gain (loss) on derivatives.
(c): Non-cash employee compensation relates to the Company's non-equity award plans.
(d): Excludes wells being drilled or completed at the end of each period.

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Operating Results—2012 Compared to 2011

The following discussion compares our results for the year ended December 31, 2012 to the year ended December 31, 2011. Unless otherwise indicated, references to 2012 and 2011 within this section refer to the respective annual periods.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $10.4 million, or 3% in 2012, from 2011. Price variances accounted for $25.6 million of the decrease and production variances accounted for a $15.2 million increase. Oil and gas sales in 2012 also includes $8.3 million of amortized deferred revenue attributable to the VPP granted effective March 1, 2012 in connection with the SWR Mergers. Combined oil and gas production in 2012 (on a BOE basis) increased 3% compared to 2011. Our production mix continued to move favorably from 74% oil and NGL in 2011 to 76% in 2012. Oil production increased 3% in 2012 from 2011 while gas production decreased 6% in 2012 from 2011. Most of the decrease in gas production from 2011 levels was attributed to normal production declines from existing wells. In 2012, our realized oil price was 2% lower than 2011, and our realized gas price was 32% 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 24% to $125 million in 2012 as compared to $101.1 million in 2011. The increase in production costs was due to a combination of an increase in the number of producing wells, higher costs of field services, including salt water disposal costs, and higher property taxes on Texas properties resulting from rising appraisal values.

Oil and gas depletion expense increased $31.8 million from 2011 to 2012 due to a $28.7 million increase related to rate variances and a $3.1 million increase due to production variances. Most of the increase in the depletion rate related to downward revisions in proved reserves in our Andrews County Wolfberry play. On a BOE basis, depletion expense increased 27% to $23.84 per BOE in 2012 from $18.72 per BOE in 2011. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

We recorded a provision for impairment of property and equipment of $5.9 million during 2012 for certain non-core oil and gas properties in the Permian Basin and other non-core areas to reduce the carrying value of those properties to their estimated fair value. During 2011, we recorded a $10.4 million impairment of property and equipment for certain non-core oil and gas properties in the Permian Basin and other non-core areas to reduce the carrying value of those properties to their estimated fair value.

Exploration costs

We follow the successful efforts method of accounting; therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2012, we charged to expense $15.8 million of exploration costs, as compared to $26.2 million in 2011.

Contract drilling services

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in our consolidated statements of operations and comprehensive income (loss). Drilling services costs related to external customers were $17.4 million in 2012 compared to $5.1 million in 2011.

General and Administrative

G&A expenses decreased $11.1 million from $41.6 million in 2011 to $30.5 million in 2012. Non-cash employee compensation expense related to non-equity incentive plans was a credit to expense of $404,000 in 2012 compared to $12.9 million expense in 2011. Lower commodity prices in 2012 resulted in a decrease in estimated future compensation expense from these plans, causing a partial reversal of previously accrued compensation expense. Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $28.7 million in 2011 to $30.9 million in 2012. The 2012 period included $2 million of non-recurring donations to charitable and 527 organizations.

Interest expense

Interest expense increased 17% from $32.9 million in 2011 to $38.7 million in 2012. Interest expense associated with our revolving credit facility increased by $6.3 million due primarily to an increase in borrowings, which increased from an average daily principal balance of $113.4 million in 2011 compared to $349.1 million in 2012.

Loss on early extinguishment of long-term debt

In 2011, we redeemed $225 million in aggregate principal amount of 7.75% Senior Notes due 2013 (the "2013 Senior Notes") in a tender offer and recorded a $5.5 million loss on early extinguishment of long-term debt consisting of a $2.8 million premium and a $2.7 million write-off of debt issuance costs.

Gain/loss on derivatives

We did not designate any derivative contracts in 2012 or 2011 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. In 2012, we reported a $14.4 million net gain on derivatives, consisting of a $17.8 million non-cash unrealized gain to mark our derivative positions to their fair value at December 31, 2012 and a $3.4 million realized loss on settled contracts. In 2011, we reported a $47 million net gain on derivatives, consisting of a $4.5 million non-cash unrealized gain to mark our derivative positions to their fair value at December 31, 2011 and a $42.5 million realized gain on settled contracts. Cash settlements in 2011 included $50 million from the early termination of contracts covering oil production for 2012 and 2013. 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 $463,000 on sales of assets and impairment of inventory in 2012 compared to a net gain of $14.1 million in 2011. The 2011 gain related primarily to the sale of our two 2,000 horsepower drilling rigs and related equipment for a $13.2 million gain.

Income tax expense

Our estimated effective income tax rate in 2012 of 38.5% 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.

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Operating Results—2011 Compared to 2010

The following discussion compares our results for the year ended December 31, 2011 to the year ended December 31, 2010. Unless otherwise indicated, references to 2011 and 2010 within this section refer to the respective annual periods.

Oil and gas operating results

Oil and gas sales in 2011 increased $78.9 million, or 24%, from 2010. Price variances accounted for an increase of $63.8 million while production variances accounted for the remaining $15.1 million increase. Although production in 2011 (on a BOE basis) remained constant compared to 2010 our production mix continued to move favorably from 67% oil and NGL in 2010 to 74% in 2011. Oil production increased 10% in 2011 from 2010 while gas production decreased 20% 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. In 2011, our realized oil price was 21% higher than 2010, and our realized gas price was 3% higher. 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 22% to $101.1 million in 2011 as compared to $83.1 million in 2010. Production costs (excluding production taxes), referred to as lifting costs, accounted for $14.7 million of the increase due to a combination of more producing wells and rising costs of field services, and production taxes accounted for the remaining $3.3 million of the increase due to higher oil and gas sales.

Oil and gas depletion expense increased $3 million from 2010 to 2011 due to a $3.4 million increase related to rate variances and a $400,000 decrease due to production variances. On a BOE basis, depletion expense increased 3% to $18.72 per BOE in 2011 from $18.09 per BOE in 2010. 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.

We recorded a provision for impairment of property and equipment of $10.4 million during 2011 for certain non-core oil and gas properties in the Permian Basin and other non-core areas to reduce the carrying value of those properties to their estimated fair value. During 2010, we recorded a $11.9 million impairment of property and equipment for certain non-core oil and gas properties in the Permian Basin and for certain non-operated wells in Wyoming to reduce the carrying value of those properties to their estimated fair value.

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 $26.2 million of exploration costs, as compared to $15.1 million in 2010.

Contract drilling services

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

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General and Administrative

G&A expenses increased $6 million from $35.6 million in 2010 to $41.6 million in 2011. Non-cash employee compensation expense related to non-equity incentive plans was $12.9 million in 2011 compared to $13.9 million in 2010. Excluding employee compensation related to non-equity incentive plans, G&A expenses increased from $21.7 million in 2010 to $28.7 million in 2011 due to a combination of factors including higher personnel costs and costs associated with the proposed merger with affiliated partnerships.

Interest expense

Interest expense increased 35% from $24.4 million in 2010 to $32.9 million in 2011 primarily due to a $21.6 million increase in interest expense related to the issuances in March and April 2011 of $350 million of our 2019 Senior Notes, which was partially offset by a $12.1 million decrease as a result of our redemption of $143.2 million of our 2013 Senior Notes in March 2011 and the remaining $81.8 million of 2013 Senior Notes in August 2011. Interest expense associated with our revolving credit facility declined by $2 million due primarily to decreased borrowings, which declined from an average daily principal balance of $171.3 million in 2010 compared to $113.4 million in 2011.

Loss on early extinguishment of long-term debt

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

Gain/loss on derivatives

We did not designate any derivative contracts in 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. In 2011, we reported a $47 million net gain on derivatives, consisting of a $42.5 million realized gain on settled contracts and a $4.5 million non-cash unrealized gain to mark our derivative positions to their fair value at December 31, 2011. In 2010, we reported a $722,000 net gain on derivatives, consisting of a $9.9 million realized gain on settled contracts and a $9.2 million non-cash unrealized loss to mark our derivative positions to their fair value at December 31, 2010. 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 $14.1 million on sales of assets and impairment of inventory compared to a net gain of $1.9 million 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 primarily to the sale of our interest in a non-operated well and related leasehold interests in North Louisiana, offset in part by the loss recorded on the sale of our interests in 22 operated and 76 non-operated producing wells in North Louisiana in June 2010.

Income tax expense

Our estimated effective income tax rate in 2011 of 35.7% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

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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 our 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, we may mitigate the effects of product prices on cash flow through the use of commodity derivatives.

At December 31, 2012, we had $460 million of borrowings outstanding under our revolving credit facility, leaving $121 million available under the facility after allowing for outstanding letters of credit totaling $4.1 million. This level of liquidity did not permit us to continue capital spending at the same level we experienced in 2012. As a result, during 2013, we took steps to reduce debt and increase liquidity through a combination of lower capital spending, sales of certain producing properties and issuances of long-term debt to achieve what we believe is a sustainable balance between our future capital commitments and our expected financial resources. These actions include the following:

Reduce capital spending

We currently expect to spend $270 million in 2013 on exploration and development activities, representing a 38% reduction from 2012 spending levels. These lower spending levels, combined with proceeds from the sale of our Andrews County Wolfberry assets discussed below, are expected to permit us to reduce the outstanding balance on our revolving credit facility by more than $125 million.

Sale of Wolfberry Assets

On April 24, 2013 we closed a transaction to monetize a substantial portion of our Andrews County Wolfberry oil and gas reserves, leasehold interests and facilities (the "Assets"). The Assets accounted for approximately 20% of our total proved reserves at December 31, 2012. At closing, we contributed 5% of the Assets to a newly formed limited partnership in exchange for a 5% general partner interest, and a unit of GE Energy Financial Services contributed cash of $215.2 million to the limited partnership in exchange for a 95% limited partnership interest. The limited partnership then purchased 95% of the Assets from us for $215.2 million, subject to customary closing adjustments, with $25.9 million remaining in escrow pending resolution of certain title requirements. All title requirements were subsequently satisfied, and all proceeds in escrow were released.

Effective with the closing, the aggregate commitment and borrowing base under our credit facility was reduced from $585 million to $470 million to account for the release of collateral.

Also in April 2013, we sold a 75% interest in our rights to the base of the Delaware formation in approximately 12,000 net undeveloped acres in Loving County, Texas to a third party for $6.8 million in cash. Under the terms of the agreement, the third party is required to carry us for all drilling and completion costs on six wells attributable to our retained 25% working interest. We retained all rights to intervals below the Delaware formation, including the Bone Springs and Wolfcamp formations.

Throughout the year, we will also consider other asset sales and/or monetization transactions that enhance shareholder value and meet strategic operating and financial objectives.

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Joint Venture Reeves County Wolfbone Assets

We plan to seek a joint venture partner for a portion of our net interest in Reeves County Wolfbone assets through a joint venture arrangement in which we would expect to receive a combination of an upfront cash payment and a drilling carry. If acceptable terms to a joint venture arrangement are achieved, we anticipate closing the transaction during the fourth quarter of 2013 or the first quarter of 2014. However, we cannot make any assurances that we will be able to consummate any such transaction on terms acceptable to us.

Issuances of Long-Term Debt

On October 1, 2013, we used the net proceeds from our issuance of an additional $250 million aggregate principal amount of 2019 Senior Notes to repay outstanding indebtedness under our revolving credit facility. After giving pro forma effect to the application of net proceeds from the issuance of the additional 2019 Senior Notes and the reduction in borrowing base, we increased our availability under our revolving credit facility to $323.4 million as of September 30, 2013.

Capital expenditures

The following table summarizes, by area, our actual expenditures for exploration and development activities for the nine months of 2013 and our planned expenditures for the year ending December 31, 2013.

	Actual Expenditures Nine Months Ended September 30, 2013		Planned Expenditures Year Ending December 31, 2013

	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	67,800	$	106,900	39	%
Other		32,400		37,800	14	%
Austin Chalk/Eagle Ford Shale		50,300		67,000	25	%
Other		8,200		9,900	4	%


		158,700		221,600	82	%
Leasing and seismic		38,900		48,400	18	%


Exploration and development	$	197,600	$	270,000	100	%

Our expenditures for exploration and development activities for the nine months ended September 30, 2013 totaled $197.6 million. We financed these expenditures for the nine months of 2013 with cash flow from operating activities and $43.7 million of advances under our revolving credit facility. We currently plan to spend approximately $270 million on exploration and development activities during fiscal 2013. Our actual expenditures during 2013 may vary significantly from these estimates since our plans for exploration and development activities may change during the remainder of the year. Factors, such as drilling results, changes in operating margins, and the availability of capital resources and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2013.

Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow, combined with funds available to us under our revolving credit facility, will be sufficient to finance our planned exploration and development activities through 2013. Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base may under our credit facility be less than expected, cash

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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 2013, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.

Cash flow provided by operating activities

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

Cash flow provided by operating activities for the nine months ended September 30, 2013 decreased $4 million, or 2.5%, as compared to the corresponding period in 2012 due primarily to the sale of our Andrews County properties.

Senior Notes

In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes. The 2019 Senior Notes were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011. In April 2011, we issued an additional $50 million aggregate principal amount of 2019 Senior Notes with an original issue discount of 1% or $500,000. In October 2013, we issued an additional $250 million aggregate principal amount of 2019 Senior Notes at par. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

The Indenture contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture. These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at September 30, 2013 and December 31, 2012.

Revolving credit facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $470 million, limited to the amount of a borrowing base as determined by the banks. We have historically relied on our 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 our 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 our 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

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not more than five equal monthly installments plus accrued interest. In April 2013, the banks decreased the aggregate commitment and borrowing base under our revolving credit facility from $585 million to $470 million and decreased the maximum credit facility from $585 million to $470 million. During the nine month period ended September 30, 2013, we decreased indebtedness outstanding under our revolving credit facility by $137 million, effective with the closing of the transaction to monetize our Wolfberry oil and gas reserves, leasehold interests and facilities in Andrews County, Texas for $215.2 million, of which $25.9 million is in escrow pending resolution of certain title requirements that we expect to resolve timely and apply the proceeds to further reduce our outstanding balance during the fourth quarter of 2013. On October 1, 2013, we used the net proceeds from our issuance of an additional $250 million aggregate principal amount of 2019 Senior Notes to repay outstanding indebtedness under our revolving credit facility. In connection with the issuance of the additional 2019 Senior Notes, borrowing base was reduced to $407.5 million.

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

At our election, annual interest rates under our revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.75% and 2.75% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.75% and 1.75% per year. We also pay a commitment fee on the unused portion of our revolving credit facility at a rate between 0.375% and 0.50%. The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under our revolving credit facility, excluding bank fees and amortization of debt issue costs, for the nine months ended September 30, 2013 was 2.7%.

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

Working capital computed for loan compliance purposes differs from our working capital computed in accordance with accounting principles generally accepted in the United States ("GAAP"). Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under our 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 was $31.4 million at September 30, 2013 compared to $3.6 million at December 31, 2012. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $171.2 million at September 30, 2013, as compared to $117 million at December 31, 2012.

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The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at September 30, 2013 and December 31, 2012.

	September 30, 2013			December 31, 2012

	(In thousands)
Working capital per GAAP	$	31,423		$	3,556
Add funds available under our revolving credit facility		141,947			120,950
Exclude fair value of derivatives classified as current assets or current liabilities		(2,139	)		(7,495	)


Working capital per loan covenant	$	171,231		$	117,011

Our revolving credit facility also prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (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. In connection with the issuance of additional Senior Notes due 2019 effective October 1, 2013, the consolidated funded indebtedness ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014.

We were in compliance with all financial and non-financial covenants at September 30, 2013 and December 31, 2012. However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend our 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 our revolving credit facility includes the following institutions: JPMorgan Chase Bank, N.A., Union Bank, N.A., Wells Fargo Bank, N.A., The Royal Bank of Scotland plc, Compass Bank, Frost Bank, Natixis, KeyBank, N.A., UBS Loan Finance, LLC, Fifth Third Bank, US Bank, N.A., and Whitney Bank.

From time to time, we engage in other transactions with lenders under our revolving credit facility. Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of September 30, 2013, 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 our revolving credit facility.

At September 30, 2013, we had $323 million of borrowings outstanding under our revolving credit facility, leaving $141.9 million available under the facility after allowing for outstanding letters of credit totaling $5.1 million. After giving pro forma effect to the application of net proceeds from the issuance of the additional 2019 Senior Notes and the reduction in borrowing base, we had $323.4 million available as of September 30, 2013. Our revolving credit facility matures in November 2015.

Alternative capital resources

We have reduced our capital spending levels for fiscal 2013 to the extent necessary to be fully funded through a combination of operating cash flow, proceeds from asset sales and the issuance of debt.

We may also use other capital resources, such as entering into joint venture participation agreements with other industry or financial partners and issuing additional debt or equity securities in private or public offerings, in order to finance a portion of our capital spending in fiscal 2013 and subsequent periods. 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.

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Contractual obligations and contingent commitments

The following table summarizes our contractual obligations as of December 31, 2012 by payment due date.

	Payments Due by Period

	Total		2013		2014 to 2015		2016 to 2017		Thereafter
	(In thousands)
Contractual obligations:
Revolving credit facility, due November 2015(a)	$	460,000	$	—	$	460,000	$	—	$	—
7.75% Senior Notes, due 2019, net of discount of $415,000(a)		349,585		—		—		—		349,585
Lease obligations(b)		17,388		5,043		8,480		3,865		—
Other(c)		98		98		—		—		—


Total contractual obligations	$	827,071	$	5,141	$	468,480	$	3,865	$	349,585

(a): In addition to the principal payments presented, we expect to make annual interest payments of $27.4 million on the 2019 Senior Notes and approximately $12.4 million on our revolving credit facility (based on the balances and interest rates at December 31, 2012).
(b): Amount includes lease payments for two drilling rigs.
(c): Amount relates to non-cancellable orders placed for tubular goods at December 31, 2012.

Off-balance sheet arrangements

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

Known Trends and Uncertainties

Operating Margins

We analyze, on a BOE produced basis, those revenues and expenses that have a significant impact on our oil and gas operating margins. Our weighted average oil and gas sales per BOE have fluctuated from $59.78 per BOE in 2010, to $74.57 per BOE in 2011 and to $72.00 per BOE in 2012. Our expenses per BOE were on an upward trend through 2012 resulting in our operating margins being less favorable in 2012. Our oil and gas DD&A per BOE was $18.09 per BOE in 2010, $18.72 per BOE in 2011 and $23.84 per BOE in 2012. An upward trend in DD&A per BOE indicates that our cost to find and/or acquire reserves is increasing at a faster rate than the reserves we are adding. Although we replaced 365% of our production in 2012, commodity prices were lower and our costs to find those reserves were significantly higher than our historical combined rate. Also affecting our operating margins is the cost of producing our reserves. Our production costs per BOE have increased from $15.23 per BOE in 2010, to $18.60 per BOE in 2011, to $22.32 per BOE in 2012. The increase in operating costs per BOE in 2012 was due a combination of an increase in the number of producing wells, higher costs of field services, including salt water disposal costs, and higher property taxes on Texas properties resulting from rising appraisal values.

Oil and Gas Production

As with all companies engaged in oil and gas exploration and production, we face the challenge of natural production decline because oil and gas reserves are a depletable resource. With each unit of oil and gas we produce, we are depleting our proved reserve base, so we must be able to conduct successful exploration and development activities or acquire properties with proved reserves in order to

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grow our reserve base. Although our production remained relatively constant in 2011 over 2010 levels, our production in 2012 increased 3% to 5.6 MMBOE compared to 5.4 MMBOE in 2011, and we replaced 365% of our 2012 oil and gas production through extensions and discoveries. While these 2012 reserve additions will contribute favorably to our production in 2013, we do not expect this production to be sufficient to fully offset the natural production declines from our existing base of oil and gas reserves.

We currently plan to decrease capital spending during 2013 to $270 million on exploration and development activities compared to $436.8 million in 2012. A decrease in spending levels will make it more difficult for us to grow our production and reserves. Failure to maintain or grow our oil and gas reserves may result in lower production and may adversely affect our financial condition, results of operations, and cash flow.

Application of Critical Accounting Policies and Estimates

Summary

In this section, we will identify the critical accounting policies we follow in preparing our consolidated financial statements and disclosures. Many of these policies require us to make difficult, subjective and complex judgments in the course of making estimates of matters that are inherently imprecise. We explain the nature of these estimates, assumptions and judgments, and the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions.

The following table lists our critical accounting policies, the estimates and assumptions that can have a significant impact on the application of these accounting policies and the financial statement accounts affected by these estimates and assumptions.

Accounting Policies	Estimates or Assumptions	Accounts Affected

Successful efforts accounting for oil and gas properties	• Reserve estimates • Valuation of unproved properties • Judgment regarding status of in progress exploratory wells	• Oil and gas properties • Accumulated DD&A • Provision for DD&A • Impairment of unproved properties • Abandonment costs (dry hole costs)

Impairment of proved properties and long-lived assets	• Reserve estimates and related present value of future net revenues (proved properties) • Estimates of future undiscounted cash flows (long-lived assets)	• Oil and gas properties • Contract drilling equipment • Accumulated DD&A • Impairment of proved properties and long-lived assets

Asset retirement obligations	• Estimates of the present value of future abandonment costs	• Asset retirement obligations (non-current liability) • Oil and gas properties • Accretion of discount expense

Inventory stated at the lower of average cost or estimated market value	• Estimates of market value of tubular goods and other well equipment	• Impairment of inventory

Derivatives mark-to-market	• Estimates of the fair value of derivatives	• Fair value of derivatives • Other income (expense): Gain (loss) on derivatives

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Significant Estimates and Assumptions

Oil and gas reserves

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of a reserve estimate depends on the quality of available geological and engineering data, the precision of and the interpretation of that data, and judgment based on experience and training. Annually, we engage independent petroleum engineering firms to evaluate our oil and gas reserves. As a part of this process, our internal reservoir engineer and the independent engineers exchange information and attempt to reconcile any material differences in estimates and assumptions.

The techniques used in estimating reserves usually depend on the nature and extent of available data, and the accuracy of the estimates may vary accordingly. As a general rule, the degree of accuracy of reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table.

Type of Reserves	Nature of Available Data	Degree of Precision

Proved undeveloped	Data from offsetting wells, seismic data	Least precise
Proved developed non-producing	Logs, core samples, well tests, pressure data	More precise
Proved developed producing	Production history, pressure data over time	Most precise

Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable reserves exceed the projected revenues from the reserves). But more significantly, the standardized measure of discounted future net cash flows is extremely sensitive to prices and costs, and may vary materially based on different assumptions. Current SEC financial accounting and reporting standards require that pricing parameters be the arithmetic average of the first-day-of-the-month price for the 12-month period preceding the effective date of the reserve report. Varying pricing can result in significant changes in reserves and standardized measure of discounted future net cash flows from period to period, as illustrated in the following table.

													Standardized Measure of Discounted Future Net Cash Flows

	Proved Reserves						Average Price
	Oil (MMBbls)		Natural Gas Liquids (MMBbls)		Gas (Bcf)		Oil ($/Bbl)		Natural Gas Liquids ($/Bbl)		Gas ($/Mcf)
													(In millions)
As of December 31:
2012		49.1		9.2		102.3	$	90.45	$	43.74	$	3.70	$	939.8
2011		44.9		4.6		88.9	$	91.35	$	51.19	$	5.31	$	938.5
2010		34.4		3.4		79.5	$	75.40	$	41.94	$	5.44	$	684.4

Valuation of unproved properties

Estimating fair market value of unproved properties (also known as prospects) is very subjective since there is no quoted market for undeveloped exploratory prospects. The negotiated price of any prospect between a willing seller and willing buyer depends on the specific facts regarding the prospect, including:

•: the location of the prospect in relation to known fields and reservoirs, available markets and transportation systems for oil and gas production in the vicinity and other critical services;

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•: the nature and extent of geological and geophysical data on the prospect;
•: the terms of the leases holding the acreage in the prospect, such as ownership interests, expiration terms, delay rental obligations, depth limitations, drilling and marketing restrictions and similar terms;
•: the prospect's risk-adjusted potential for return on investment, giving effect to such factors as potential reserves to be discovered, drilling and completion costs, prevailing commodity prices and other economic factors; and
•: the results of drilling activity in close proximity to the prospect that could either enhance or condemn the prospect's chances of success.

Asset Retirement Obligations

We estimate the present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We compute our liability for asset retirement obligations by calculating the present value of estimated future cash flows related to each property. This requires us to use significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations.

Effects of Estimates and Assumptions on Financial Statements

GAAP does not require, or even permit, the restatement of previously issued financial statements due to changes in estimates unless such estimates were unreasonable or did not comply with applicable SEC accounting rules. We are required to use our best judgment in making estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate. At each accounting period, we make a new estimate using new data, and continue the cycle. You should be aware that estimates prepared at various times may be substantially different due to new or additional data. While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available data or assumptions. In this section, we will discuss the effects of different estimates on our financial statements.

Provision for DD&A

We compute our provision for DD&A on a unit-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for each of our producing properties (or appropriate groups of properties based on geographical and geological similarities):

•: DD&A Rate = Unamortized Cost / Beginning of Period Reserves
•: Provision for DD&A = DD&A Rate × Current Period Production

Reserve estimates have a significant impact on the DD&A rate. If reserve estimates for a property or group of properties are revised downward in future periods, the DD&A rate for that property or group of properties will increase as a result of the revision. Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease.

Impairment of Unproved Properties

Each quarter, we review our unproved oil and gas properties to determine if there has been, in our judgment, an impairment in value of each prospect that we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimated value, we make a provision for impairment of unproved properties and record the provision as abandonments and impairments within

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exploration costs on our consolidated statements of operations and comprehensive income (loss). If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the prospect at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period.

Impairment of Proved Properties and Long-Lived Assets

Each quarter, we assess our producing properties for impairment. If we determine there has been an impairment in any of our producing properties (or appropriate groups of properties based on geographical and geological similarities), we will estimate the value of each affected property. In accordance with GAAP, the value for this purpose is a fair value using Level 3 inputs instead of a standardized reserve value as prescribed by the SEC. We attempt to value each property using reserve classifications and pricing parameters similar to what a willing seller and willing buyer might use. These parameters may include escalations of prices instead of constant pricing, and they may also include the risk-adjusted value of reserves. To the extent that the carrying cost for the affected property exceeds its estimated fair value, we make a provision for impairment of proved properties. If the fair value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the property at a net cost that is lower than its estimated fair value. If the fair value is revised downward in a future period, an additional provision for impairment is made in that period. Accordingly, the carrying costs of producing properties on our balance sheet will vary from (and often will be less than) the present value of proved reserves for these properties.

Judgment Regarding Status of In-Progress Wells

On a quarterly basis, we review the status of each in-progress well to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress wells remain capitalized until their productive status becomes known. If an in-progress exploratory well is found to be unsuccessful (often referred to as a dry hole) prior to the issuance of our financial statements, we write-off all costs incurred through the balance sheet date to abandonments and impairments expense, a component of exploration costs. Costs incurred on that dry hole after the balance sheet date are charged to exploration costs in the period incurred.

Occasionally, we are unable to make a final determination about the productive status of a well prior to issuance of our financial statements. In these cases, we leave the well classified as in-progress until we have had sufficient time to conduct additional completion or testing operations and to evaluate the pertinent geological and geophysical and engineering data obtained. At the time when we are able to make a final determination of a well's productive status, the well is removed from the in-progress status and the proper accounting treatment is recorded.

Asset Retirement Obligations

Our asset retirement obligation is recorded as a liability at its estimated present value as of the asset's inception, with an offsetting increase to oil and gas properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the consolidated statements of operations and comprehensive income (loss). During 2012, we had an upward revision of our estimated asset retirement obligations of $1.3 million based on a review of current plugging and abandonment costs. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to DD&A expense and accretion expense. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

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Recent Accounting Pronouncements

In December 2011, the FASB issued ASU No. 2011-11, "Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities" ("ASU 2011-11"). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of the ASU is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. At that time we will make the necessary disclosures. The adoption of ASU 2011-11 will not impact the Company's future financial position, results of operation or liquidity.

Quantitative and Qualitative Disclosures About Market Risk

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

Oil and Gas Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market commodity prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, many of which are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas commodity prices with any degree of certainty. Sustained weakness in oil and gas commodity prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to commodity price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas commodity prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2012 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 2012 would reduce our gross revenues for the year ending December 31, 2013 by $8.9 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. We do not enter into commodity derivatives for trading purposes. When using swaps to hedge our oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. When purchasing floors, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

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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.

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 30, 2013. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

	Oil				Gas

	Bbls		Price		MMBtu(a)		Price
Production Period:
4th Quarter 2013		300,000	$	104.60		330,000	$	3.34
2014		2,200,000	$	96.83		—	$	—


		2,500,000				330,000

(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. As of September 30, 2013, 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 $1 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At September 30, 2013, our fixed rate debt maturing 2019 had a carrying value of $349.6 million and an approximate fair value of $348.3 million, based on current market quotes. We estimate that a hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $15.3 million. Based on our outstanding variable rate indebtedness at September 30, 2013 of $323 million, a change in interest rates of 100-basis points would affect annual interest payments by $3.2 million.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Controls and Procedures

Disclosure Controls and Procedures

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

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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 as of September 30, 2013 these disclosure controls and procedures are effective at the reasonable assurance level 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 nine months ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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BUSINESS

General

We are an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, New Mexico and Louisiana. On December 31, 2012, our estimated proved reserves were 75,357 MBOE, of which 58% were proved developed. Our portfolio of oil and natural gas reserves is weighted in favor of oil, with approximately 77% of our proved reserves at December 31, 2012 consisting of oil and natural gas liquids ("NGLs") and approximately 23% consisting of natural gas. During 2012, we added proved reserves of 20,443 MBOE through extensions and discoveries, had downward revisions of 6,615 MBOE, had purchases of minerals-in-place of 3,504 MBOE and had sales of minerals-in-place of 725 MBOE. We also had average net production of 15.3 MBOE per day in 2012, which implies a reserve life of approximately 13.5 years. CWEI held interests in 3,031 gross (1,749 net) producing oil and gas wells and owned leasehold interests in approximately 951,000 gross (471,000 net) undeveloped acres at December 31, 2012.

Clayton W. Williams, Jr. beneficially owns, either individually or through his affiliates, approximately 25.6% of the outstanding shares of our Common Stock. In addition, The Williams Children's Partnership, Ltd. ("WCPL"), a limited partnership of which Mr. Williams' adult children are the limited partners, owns an additional 25% of the outstanding shares of our Common Stock. Mr. Williams is also Chairman of our Board of Directors (the "Board"), President and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations.

Business Strategy

Our goal is to grow oil and gas reserves and increase shareholder value utilizing a flexible, opportunity-driven business strategy. We do not adhere to rigid guidelines for resource allocations, risk profiles, product mixes, financial measurements or other operating parameters. Instead, we try to identify exploratory and developmental projects that offer us the best possible opportunities for growth in oil and gas reserves and allocate our available resources to those projects. Our direction is heavily influenced by Mr. Williams, who has over 55 years of experience and leadership in the oil and gas industry. Strategically, we are currently focused on the development of oil reserves over gas reserves. We have significant holdings in oil-prone regions in the Permian Basin and the Giddings Area that we believe offer us attractive opportunities for growth in oil reserves, and we currently plan to exploit these resources as long as our margins between oil prices and the costs of drilling, completion and other field services remain acceptable. In addition to our developmental drilling, we also remain committed to exploring for oil and gas reserves in areas that we believe offer us exceptional opportunities for reserve growth, and we continue to search for possible proved property acquisitions. From year to year, our allocation of investment capital may vary between exploratory and developmental activities depending on our analysis of all available growth opportunities, but our long-term focus on growing oil and gas reserves is consistent with our goal of value enhancement for our shareholders.

Liquidity and Capital Expenditures Outlook

Over the past two years, we have invested more than $800 million in the Permian Basin and the Giddings Area. We have assembled large acreage positions in two of the most active resource plays in the nation, but we will need significant amounts of capital to optimize the value of these assets. To achieve what we believe will be a sustainable balance between our future capital commitments and our expected financial resources, we took steps in 2013 to decrease outstanding balances on our revolving

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credit facility and increase liquidity through a combination of divestitures of certain producing properties and streamlined capital spending. These strategic actions include the following:

Senior Notes Offering

On October 1, 2013, we completed a private placement of $250 million in aggregate principal amount of our 7.75% Senior Notes due 2019 (the "Notes Offering"). The Notes are part of the same class as the $300 million aggregate principal amount of 7.75% Senior Notes due 2019 the Company issued in March 2011 and the $50 million aggregate principal amount of 7.75% Senior Notes due 2019 the Company issued in April 2011. We received aggregate net proceeds of approximately $244 million, which we used to repay indebtedness outstanding under our revolving credit facility.

Sale of Assets

Joint Venture Reeves County Wolfbone Assets

We plan to seek a joint venture partner for a portion of our net interest in Reeves County Wolfbone assets through a joint venture arrangement in which we would expect to receive a combination of an upfront cash payment and a drilling carry. If acceptable terms to a joint venture arrangement are achieved, we anticipate closing the transaction during the fourth quarter of 2013 or the first quarter of 2014. However, we cannot make assurances that we will be able to consummate any such transaction on terms acceptable to us.

Alternative Capital Resources

We have in the past, and we believe we might in the future, obtain capital through other sources, such as issuances of subordinated debt in public or private placements, sales or monetizations of assets, some of which may be significant and may include the formation of a master limited partnership, or vendor financing arrangements. We might also issue common stock or preferred stock in public or private placements if we choose to seek funds through the equity markets. While we believe we would be able to obtain funds through one or more of these alternatives there can be no assurance that these capital resources would be available on terms acceptable to us.

Capital Expenditure Budget

We currently plan to spend approximately $270 million on exploration and development activities in fiscal 2013. To date, we have financed these expenditures with cash flow from operating activities and advances under our revolving credit facility. Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow, combined with funds available to us under our revolving credit facility, will be sufficient to finance a large portion of our exploration and development activities for the remainder of 2013. Although we believe the assumptions and estimates

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made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base under our revolving credit facility may be less than expected, cash flow may be less than expected, or capital expenditures may be more than expected.

The following table summarizes, by area, our planned expenditures for exploration and development activities during 2013, as compared to our actual expenditures in 2012.

	Actual Expenditures Year Ended December 31, 2012		Planned Expenditures Year Ending December 31, 2013

	(In thousands)
Drilling and Completion:
Permian Basin Area:
Delaware Basin	$	227,900	$	106,900	39	%
Other		87,200		37,800	14	%
Austin Chalk/Eagle Ford Shale		27,400		67,000	25	%
Other		11,900		9,900	4	%


		354,400		221,600	82	%
Leasing and seismic		82,400		48,400	18	%


Exploration and Development	$	436,800	$	270,000	100	%

Our actual expenditures during fiscal 2013 may vary significantly from these estimates if our plans for exploration and development activities change during the year. Factors, such as drilling results, changes in operating margins and the availability of capital resources, could increase or decrease our ultimate level of expenditures during fiscal 2013.

Domestic Operations

We conduct all of our drilling, exploration and production activities in the United States. All of our oil and gas assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.

Development Program

Our current focus is on developmental drilling. A developmental well is a well drilled within the proved area of an oil and gas reservoir to a horizon known to be productive. We have an inventory of developmental projects available for drilling in the future, most of which are located in the oil-prone regions of the Permian Basin and the Giddings Area. In many cases, our leasehold interests in developmental projects are held by the continuous production of other wells, meaning that our rights to drill these projects are not subject to near-term expiration. This provides us with a high degree of flexibility in the timing of developing these reserves.

Exploration Program

To a much lesser degree, we are also engaged in finding reserves through exploratory drilling. Our exploration program consists of generating exploratory prospects, leasing the acreage related to the prospects, drilling exploratory wells on these prospects to determine if recoverable oil and gas reserves exist, drilling developmental wells on prospects, and producing and selling any resulting oil and gas production.

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Acquisition and Divestitures of Proved Properties

In addition to our exploration and development activities, we watch for opportunities to acquire proved reserves that could complement our current operations and enhance shareholder value. However, competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it difficult for us to acquire reserves without assuming significant price and production risks.

In March 2012, our wholly owned subsidiary, Southwest Royalties, Inc. ("SWR"), completed the merger of each of the 24 limited partnerships of which SWR was the general partner (the "SWR Partnerships"), into SWR, with SWR continuing as the surviving entity in the mergers. As a result of the mergers, SWR acquired approximately 3.5 million BOE of proved reserves for aggregate merger consideration of $38.6 million.

From time to time, we sell certain of our proved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them. We consider many factors in deciding to sell properties, including the need for liquidity, the risks associated with continuing to own the properties, our expectations for future development on the properties, the fairness of the price offered, and other factors related to the condition and location of the properties. As described under "Recent Developments," we sold 95% of our Andrews County Wolfberry assets in a monetization transaction in April 2013 and are currently seeking a joint venture partner for a portion of our Reeves County Wolfbone assets. In addition, we may consider selling certain other producing properties and undeveloped acreage, including our East Permian Basin Cline Shale/Wolfberry assets in Glasscock and Sterling Counties.

Exploration and Development Activities

Overview

Since 2009, we have been primarily committed to drilling developmental oil wells in the Permian Basin and the Giddings Area. We spent $197.6 million during the nine month period ended September 30, 2013 on exploration and development activities and currently plan to spend approximately $72.4 million on similar activities for the remainder of 2013. Our actual expenditures during 2013 may vary significantly from these estimates since our plans for exploration and development activities may change during the remainder of the year. Factors such as drilling results, changes in operating margins, and the availability of capital resources and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2013.

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 oil 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 $100.2 million in the Permian Basin during the nine month period ended September 30, 2013 on drilling and completion activities and $9.1 million on leasing and seismic activities. We drilled

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and completed 33 gross (23.7 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during the nine month period ended September 30, 2013. We currently plan to spend approximately $47.7 million on drilling and leasing activities in this area during the remainder of 2013. Following is a discussion of our principal assets in the Permian Basin.

Delaware Basin

We currently hold approximately 91,000 net acres in the active Wolfbone resource play in the Delaware Basin in Reeves, Loving, Ward and Winkler Counties, Texas and may earn up to 10,000 additional acres through future drilling commitments under an existing farm-in arrangement. A Wolfbone well is a well that commingles production from the Bone Spring 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 composed of limestone and sandstone. Geology in the Delaware Basin consists of multiple stacked pay zones with both over-pressured and normal-pressured intervals. To date, we have focused on the over-pressured intervals, having drilled 90 wells in the area: 70 vertical Wolfbone wells and 20 horizontal wells targeting multiple Bone Springs/Wolfcamp intervals.

A significant portion of our current and future holdings in this area are associated with a farm-in agreement we entered into in March 2011 with Chesapeake in southern Reeves County, Texas with a term of five years. Chesapeake's position in the agreement is now held by Shell. For each carried well, Shell, or its successors to this agreement, will retain a 25% carried interest, bearing none of the costs to drill and complete a carried well, and we will earn an undivided 75% interest in 640 net acres within the farm-in area. Under the farm-in agreement, we are obligated to drill or commence drilling operations on at least 20 carried wells each year during the term of the agreement to a maximum of 100 carried wells. Excess wells drilled during any year may be applied towards our drilling obligations in the next year. To date, we have been credited for 45 carried wells under this agreement.

We own oil, gas and water disposal pipelines in Reeves County, consisting of 71 miles of oil pipelines with a design capacity of 18,000 barrels of oil per day, 70 miles of gas pipelines with a design capacity of 25,000 Mcf of natural gas per day and 65 miles of salt water disposal pipelines with a design capacity of 20,000 barrels of produced water per day. These facilities may be expanded to accommodate new wells as we continue our development in the area.

We spent approximately $67.8 million on drilling and completion activities and $8.2 million for leasing activities in the Wolfbone play during the nine month period ended September 30, 2013. We plan to spend approximately $42.4 million on similar drilling and leasing activities in the Wolfbone play for the remainder of 2013. We currently plan to utilize three rigs in this area during the remainder of 2013.

East Permian Basin

We have approximately 36,000 net acres in the emerging Cline Shale play in Glasscock and Sterling Counties, Texas, which was originally leased as a Wolfberry prospect. In 2012, we drilled a horizontal Cline Shale well. Although results from this well were disappointing, we believe that intervening operational factors may have contributed to the lower than anticipated production performance to date. We spent $6.4 million in the East Permian Basin during the nine month period ended September 30, 2013 on drilling and leasing activities primarily on non-operated wells.

Giddings Area

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area. Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas. Hydrocarbons are also encountered in the Giddings Area from other

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formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale, and Taylor formations. Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

Most of our existing production in the Giddings Area is derived from 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 in East Central Texas.

Eagle Ford Shale

The Eagle Ford Shale formation lies immediately beneath the Austin Chalk formation where we have approximately 177,000 net acres in production. We believe that more than 100,000 net acres in this area may also be prospective for economic Eagle Ford Shale production. Since July 2011, we have drilled 12 horizontal Eagle Ford Shale wells. Each of these wells has been or will be completed by multi-stage hydraulic fracturing processes using about five million pounds of proppant and 100,000 barrels of water. We are currently using one of our drilling rigs in the Giddings Area to drill horizontal wells in the Eagle Ford Shale formation. During the nine month period ended September 30, 2013, we spent approximately $50.3 million on drilling and completion activities and $22.4 million for leasing activities in the Eagle Ford Shale Area, and we currently plan to spend approximately $22.7 million on similar drilling and leasing activities in this area during the remainder of 2013.

Other

We spent $15.6 million during the nine months ended September 30, 2013 on exploration and development activities in other regions, including South Louisiana, Oklahoma and California and we currently plan to spend $2 million for the remainder of 2013.

South Louisiana

During the first quarter of 2013, we completed the Christian #1, an exploratory well in Jefferson Parish. During the second quarter we drilled the Macon Springer Heirs #1, an exploratory well in Terrebonne Parish, resulting in a dry hole. During the nine month period ended September 30, 2013, we spent $6.5 million on drilling and leasing activities in South Louisiana.

Oklahoma

We began drilling operations in 2013 on certain exploratory prospects in Oklahoma. These prospects were generated over the past two years using data obtained through proprietary 3D seismic shoots and target multiple conventional oil-prone formations encountered above a vertical depth of 6,000 feet. To date, we have drilled three exploratory wells, resulting in dry holes and have completed two development wells as producers. We are currently waiting on completion of the Brown 1-26 and the Mosetta 1-7. During the nine month period ended September 30, 2013, we spent $5.6 million on seismic, leasing and drilling activities in this area and we currently plan to spend approximately $1.4 million on similar drilling and leasing activities during the remainder of 2013.

California

We plan to begin limited drilling operations in 2014 on a 1,300 acre lease acquired from the city of Whittier. Based on production history from more than 400 wells in the area, we are targeting multiple

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oil-bearing Miocene sands first encountered at depths above 1,500 feet which we plan to directionally drill in order to maximize exposure to each target sand. We own a 70% working interest in the lease. During the nine month period ended September 30, 2013, we spent $1.8 million on leasing activities in this area.

Pipelines and Other Midstream Facilities

We own an interest in and operate oil, natural gas and water service facilities in the states of Texas and Louisiana. These midstream facilities consist of interests in approximately 314 miles of pipeline, four treating plants, one dehydration facility, and seven wellhead type treating and/or compression stations. Most of our operated gas gathering and treating activities facilitate the transportation and marketing of our operated oil and gas production.

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. ("Desta Drilling"), we operate 14 drilling rigs, 12 of which we own, and two of which we lease under long-term contracts. We believe that owning and operating our own rigs helps us control our cost structure while providing us flexibility to take advantage of drilling opportunities on a timely basis. The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties. As of October 29, 2013, we were using seven of our rigs to drill wells in our developmental drilling programs, one rig was working for a third party and the remaining six rigs were idle.

Known Trends and Uncertainties

We have an extensive acreage position within the Permian Basin and Giddings Area with a large portion of that acreage currently held by production that will require significant capital to fully develop. Through asset sales and joint venture arrangements, we expect to achieve a sustainable balance between our future drilling commitments and our anticipated financial resources. We are unable to give assurance that our drilling results, or the term of any sale or joint venture arrangement would be acceptable to us or provide sufficient capital to meet future drilling commitments.

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 and complete new wells. If any combination of falling oil prices and rising costs of drilling, completion and other field services occur in future periods, we may discontinue a program until margins return to acceptable levels.

Marketing Arrangements

Oil

Most of our oil production is sold based on the NYMEX futures market for West Texas Intermediate light sweet crude oil (referred to as WTI and traded in the NYMEX futures market under the symbol CL). Cushing, Oklahoma is a major trading hub for crude oil and is the price settlement point for WTI. As a result, basis differentials exist between the NYMEX price and the price we receive for our oil production depending on the proximity of our properties to the ultimate market for that production. Basis differentials are market-based and can be adversely affected by logistical factors such as pipeline constraints and inadequate storage capacities.

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Natural Gas

Natural gas is generally sold based on the NYMEX futures market for natural gas (traded in the NYMEX futures market under the symbol NG). Since the delivery point for NYMEX traded natural gas is the distribution hub on a natural gas pipeline system in Erath, Louisiana, referred to as Henry Hub, basis differentials exist between the NYMEX price and the price we receive for our gas production depending on the proximity of our properties to the ultimate market for that production. Basis differentials are market-based and can be adversely affected by logistical factors such as pipeline constraints and inadequate storage capacities.

Natural Gas Liquids

A portion of our casinghead gas production is processed under contracts where the purchaser pays us a percentage of the value of the NGL extracted. The price we receive for NGL is generally based on the spot liquids price for the various NGL products sold at Mont Belvieu, Texas and reported by Oil Price Information Service. We compute the price differential for NGL based on the NYMEX benchmark for oil, but the NGL components are subject to their own supply and demand factors, not all of which vary in correlation with changes in oil prices.

Pipelines and Other Midstream Facilities

We own an interest in and operate oil, natural gas and water service facilities in the states of Texas and Louisiana. These midstream facilities consist of interests in approximately 301 miles of pipeline, two treating plants, one dehydration facility and six wellhead type treating and/or compression stations. Most of our operated gas gathering and treating activities facilitate the transportation and marketing of our operated oil and gas production.

Competition and Markets

The market for our oil, gas and natural gas liquids production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

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Regulation

Generally

Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

Regulations Affecting Production

All of the states in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.

In the event we conduct operations on federal, state or Indian oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management or other relevant federal or state agencies.

Regulations Affecting Sales

The sales prices of oil, natural gas liquids and natural gas are not presently regulated, but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

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The FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially different from other natural gas producers in our areas of operation.

The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. Interstate transportation rates for oil, natural gas liquids and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Market Manipulation and Market Transparency Regulations

Under the EP Act 2005, the FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by "any entity" in order to enforce the anti-market manipulation provisions in the EP Act 2005. The Federal Trade Commission ("FTC") has similar regulatory oversight of oil markets in order to prevent market manipulation. The Commodity Futures Trading Commission ("CFTC") also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas, natural gas liquids and crude oil, our gathering of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC, the FTC, and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

The FERC has issued certain market transparency rules for the natural gas industry pursuant to its EP Act 2005 authority, which may affect some or all of our operations. The FERC issued a final rule in 2007, as amended by subsequent orders on rehearing ("Order 704"), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas producers, gatherers, processors and marketers, to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices, as explained in Order 704. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. The FERC has issued a Notice of Inquiry in Docket No. RM13 1-000 seeking comments from the industry regarding whether it should require more detailed information from sellers of natural gas. It is unclear what action, if any, will result and whether our reporting burden will increase or decrease.

Gathering Regulations

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own certain natural gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline's status as a gatherer not subject to the FERC jurisdiction.

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The distinction between the FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, on-going litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint based rate regulation. Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner materially differently than other companies in our areas of operation.

Environmental Matters

Our operations pertaining to oil and gas exploration, production and related activities are subject to numerous and constantly changing federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits prior to commencing certain activities or in connection with our operations; restrict or prohibit the types, quantities and concentration of substances that we can release into the environment; restrict or prohibit activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources; require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells; and impose substantial liabilities for pollution resulting from our operations. Such laws and regulations may substantially increase the cost of our operations and may prevent or delay the commencement or continuation of a given project and thus generally could have an adverse effect upon our capital expenditures, earnings, or competitive position. Violation of these laws and regulations could result in significant fines or penalties. We have experienced accidental spills, leaks and other discharges of contaminants at some of our properties, as have other similarly situated oil and gas companies, and some of the properties that we have acquired, operated or sold, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible. Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas. Some of our properties are located in areas particularly susceptible to hurricanes and other destructive storms, which may damage facilities and cause the release of pollutants. Our environmental insurance coverage may not fully insure all of these risks. Although the costs of remedying such conditions may be significant, we do not believe these costs would have a material adverse impact on our financial condition and operations.

We believe that we are in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2013. We do not believe that we will be required to incur material capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on our operations, as well as the oil and gas industry in general. For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements could have an adverse impact on our operations.

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Hazardous Substances

The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

Waste Handling

The Resource Conservation and Recovery Act ("RCRA"), and analogous state laws, impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency ("EPA") or state agencies as solid wastes. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

Air Emissions

The federal Clean Air Act and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits, or utilize specific emission control technologies to limit emissions. In August 2012, the EPA adopted new rules that impose additional air emission control standards on well completion activities and certain production equipment, such as glycol dehydrators and storage vessels. Some of these new rules, such as a requirement for flaring of gas not sent to a gathering line, became effective in October 2012, but the most significant rule, requiring the use of "green completions" emission control technology to reduce air emissions during well completions, does not become effective until January 1, 2015. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by us. We do not believe that our operations will be materially adversely affected by any such requirements.

Water Discharges

The Federal Water Pollution Control Act ("Clean Water Act") and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of

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oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the United States Oil Pollution Act of 1990 ("OPA") and similar legislation enacted in Texas, Louisiana and other coastal states impose oil spill prevention and control requirements and significantly expand liability for damages resulting from oil spills. OPA imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil spill response and removal costs and a variety of public and private damages.

Global Warming and Climate Change

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. Based on these findings, the EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA's rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring after January 2011. We believe that we are in compliance with all greenhouse gas emissions reporting requirements applicable to our operations.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Hydraulic fracturing

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surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA's study includes 18 separate research projects addressing topics such as water acquisitions, chemical mixing, well injection, flowback and produced water, and wastewater treatment and waste disposal. The EPA has indicated that it expects to issue its study report in late 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Endangered species

The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our well drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas.

Pipeline Safety

Some of our pipelines are subject to regulation by the U.S. Department of Transportation ("DOT") under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by

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the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and further amended by the Pipeline Safety, Regulation Certainty, and Job Creation Act of 2011 ("2011 Pipeline Safety Act amendments"). The DOT, through the Pipeline and Hazardous Materials Safety Administration, has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL, oil and condensate transmission pipelines that, in the event of a failure, could affect "high consequence areas." "High consequence areas" are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas, and commercially navigable waterways. Under the DOT's regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and recordkeeping. These regulatory requirements may be expanded in the future upon completion of studies required by the 2011 Pipeline Safety Act Amendments.

OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Claims are sometimes made or threatened against companies engaged in oil and gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, in other jurisdictions in which we operate, courts have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.

Title to Properties

As is customary in the oil and gas industry, we perform a minimal title investigation before acquiring undeveloped properties. A title opinion is obtained prior to the commencement of drilling operations on such properties. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. These title investigations and title opinions, while consistent with industry standards, may not reveal existing or potential title defects, encumbrances or adverse claims as we are subject from time to time to claims or disputes regarding title to properties. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our oil and gas properties are currently mortgaged to secure borrowings under our revolving credit facility and may be mortgaged under any future credit facilities entered into by us.

Operational Hazards and Insurance

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe

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damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.

We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

Operating Segments

For financial information about our operating segments, see Note 17 to the accompanying consolidated financial statements.

Employees

At December 31, 2013, we had 466 full-time employees, of which 216 were employed by Desta Drilling. None of our employees are subject to a collective bargaining agreement. In our opinion, relations with employees are good.

Legal Proceedings

SWR is a defendant in a suit in Union County, Arkansas where the plaintiffs are suing for the costs of remediation to a lease on which operations were commenced in the 1930's. The plaintiffs are seeking in excess of $8 million. In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $750,000, of which SWR would pay $710,000. To accomplish the settlement, the case would be converted to a class action, and each member of the class would be offered the right to either participate or opt out of the class and continue a separate action for damages. If more than 25% of the plaintiffs opt out of the settlement, SWR will have the right to terminate the settlement. Any plaintiffs opting out would be subject to all previous rulings of the court, including an order dismissing a significant number of plaintiffs' claims on the basis that such claims were time barred. SWR believes that the judge will approve the settlement and the number of plaintiffs opting out of the settlement, if any, will be insignificant. We recorded a loss on settlement of $710,000 for the nine months ended September 30, 2013 in connection with this proposed settlement. We are now awaiting finalization of the settlement by the court.

We have been named a defendant in three lawsuits filed in Louisiana by two parishes and a regional Levee Authority in coastal Louisiana, each alleging that historical industry operations have significantly damaged coastal marsh lands.

In July 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority—East filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against us, and approximately one hundred energy companies, alleging that defendants' drilling, dredging, pipeline and industrial operations over the past 100 years have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. Plaintiff asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract without making specific allegations against any company. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline

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protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana.

In November 2013, we were served with two separate suits filed by Plaquemines Parish in the 25^th Judicial District Court of Plaquemines Parish, Louisiana (Designated Case No. 61-002 and 60-982). Multiple defendants are named in each suit, and each suit involves a different area of operation within Plaquemines Parish. Except as to the named defendants and area of operations, the suits are identical. Plaintiff alleges that defendants' oil and gas operations violated certain laws relating to the coastal zone management including failure to obtain permits, violation of permits, use of unlined waste pits, discharge of oil field wastes including naturally occurring radioactive material, and that dredging operations exceeded unspecified permit limitations. Plaintiff makes no specific allegations against any individual defendant, and seeks unspecified monetary damages and declaratory relief, as well as restoration, costs of remediation and attorney fees. The cases were removed to the U.S. District Court for the Eastern District of Louisiana.

Our overall exposure to these suits is not currently determinable. We intend to vigorously defend these cases.

We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.

Website Address

We maintain an Internet website at www.claytonwilliams.com. We make available, free of charge, on our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. The information contained in or incorporated in our website is not part of this report.

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PROPERTIES

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. At December 31, 2012, we had interests in 3,031 gross (1,749 net) oil and gas wells and owned leasehold interests in approximately 951,000 gross (471,000 net) undeveloped acres.

Reserves

The following table sets forth our estimated quantities of proved reserves as of December 31, 2012, all of which are located within the United States.

	Proved Reserves(a)

Reserve Category	Oil (MBbls)		Natural Gas Liquids (MBbls)		Natural Gas (MMcf)		Total Oil Equivalents(b) (MBOE)
Developed		27,641		5,044		64,013		43,354
Undeveloped		21,478		4,138		38,323		32,003


Total Proved		49,119		9,182		102,336		75,357

(a): None of our oil and gas reserves are derived from non-traditional sources.
(b): Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.

The present value of future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% ("PV-10"), totaled $1.3 billion at December 31, 2012. The commodity prices used to estimate proved reserves and their related PV-10 at December 31, 2012 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 2012 through December 2012. The benchmark averages for 2012 were $94.71 per barrel of oil and NGL and $2.75 per MMBtu of natural gas. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $90.45 per barrel of oil, $43.74 per barrel of NGL and $3.70 per Mcf of natural gas over the remaining life of our proved reserves. Operating costs were not escalated.

Adjustments to benchmark prices, which are generally referred to as price differentials, were computed on a property-by-property basis by comparing historical first-day-of-the-month benchmark prices for oil and gas to the historical prices for oil, NGL and gas actually received by us. Historical price differentials vary by property based on each property's production and marketing situation and include:

•: area-specific market adjustments, referred to as basis differentials, for oil, NGL and natural gas as discussed under "Marketing Arrangements;"
•: gravity, H2S content and other quality characteristics of produced oil;
•: the volume of processed NGL derived from our natural gas production, including the mix of the NGL components between ethane, propane, butane, and natural gasoline;
•: the Btu content of natural gas production and the value of any imbedded NGL components that are reported as natural gas sales; and

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•: the amount of transportation and marketing fees levied on oil, NGL and gas production, which vary based on factors such as the distance of a property from its delivery point, available markets and other pricing adjustments that vary from contract to contract.

Price differentials per barrel of oil and NGL and per Mcf of natural gas are subject to change and may vary materially in the future from the computed price differentials at December 31, 2012. Adverse changes in our price differentials could reduce our cash flow from operations and the PV-10 of our proved reserves.

PV-10 is not a generally accepted accounting principle ("GAAP") financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our consolidated financial statements. To compute our standardized measure of discounted future net cash flows at December 31, 2012, we began with the PV-10 of our proved reserves and deducted the present value of estimated future income taxes of $330.8 million and net abandonment costs of $38.8 million, discounted at 10%. At December 31, 2012, our standardized measure of discounted future net cash flows totaled $939.8 million. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each company, the PV-10 of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis.

The following table summarizes certain information as of December 31, 2012 regarding our estimated proved reserves in each of our principal producing areas.

	Proved Reserves

	Oil (MBbls)		Natural Gas Liquids (MBbls)		Natural Gas (MMcf)		Total Oil Equivalents(a) (MBOE)		Percent of Total Oil Equivalent			PV-10 of Proved Reserves		PV-10 as a Percentage of Proved Reserves
												(In thousands)
Permian Basin Area:
Delaware Basin		14,618		4,249		20,651		22,309		29.6	%	$	325,810		24.9	%
Other		25,955		4,345		64,727		41,087		54.5	%		643,909		49.2	%
Austin Chalk/Eagle Ford Shale		8,039		572		6,130		9,633		12.8	%		301,140		23.0	%
Other		507		16		10,828		2,328		3.1	%		38,556		2.9	%


Total		49,119		9,182		102,336		75,357		100.0	%	$	1,309,415		100.0	%

(a): Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.

The following table summarizes changes in our estimated proved reserves during 2012.



As of December 31, 2011	64,349
Extensions and discoveries	20,443
Purchases of minerals-in-place	3,504
Revisions	(6,615	)
Sales of minerals-in-place	(725	)
Production	(5,599	)


As of December 31, 2012	75,357

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Purchases of minerals-in-place. In March 2012, we added 3,504 MBOE of proved reserves with the completion of the SWR Mergers.

The following table summarizes changes in our estimated proved undeveloped reserves during 2012.



As of December 31, 2011	25,085
Extensions and discoveries	14,468
Purchases of minerals-in-place	1,089
Revisions	(4,644	)
Reclassified to proved developed	(3,994	)


As of December 31, 2012	32,004

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Alternative pricing cases

In addition to the estimated proved reserves disclosed above in accordance with the commodities pricing required by the reserves rule ("SEC Case"), the following table compares certain information regarding our SEC proved reserves to a Futures Pricing Case.

	Proved Reserves

Pricing Cases	Oil (MBbls)		Natural Gas Liquids (MBbls)		Natural Gas (MMcf)		Total Oil Equivalents(a) (MBOE)		PV-10
									(In thousands)
SEC Case		49,119		9,182		102,336		75,357	$	1,309,415
Futures Pricing Case		45,632		8,673		101,845		71,279	$	1,208,122

(a): Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.

Futures Pricing Case. The Futures Pricing Case discloses our estimated proved reserves using future market-based commodities prices instead of the average historical prices used in the SEC Case. Under the Futures Pricing Case, we used futures prices, as quoted on the NYMEX on December 31, 2012, as benchmark prices for 2013 through 2017, and continued to use the 2017 futures price for all subsequent years. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $84.23 per Bbl of oil, $40.68 per Bbl of NGL and $5.97 per Mcf of natural gas over the remaining life of the proved reserves.

Reserve estimation procedures

Overview

We have established a system of internal controls over our reserve estimation process, which we believe provides us reasonable assurance that reserve estimates have been prepared in accordance with SEC and Financial Accounting Standards Board ("FASB") standards. These controls include oversight by trained technical personnel employed by us and by the use of qualified independent petroleum engineers to evaluate our proved reserves on an annual basis. Substantially all of our estimated proved reserves as of December 31, 2012 were derived from engineering evaluation reports prepared by Williamson Petroleum Consultants, Inc. ("Williamson") and Ryder Scott Company, L.P. ("Ryder Scott"). Of our total SEC Case estimated proved reserves, Williamson evaluated 71.9% and Ryder Scott evaluated 28% on a BOE basis.

Qualifications of technical manager and consultants

Ronald D. Gasser, our Vice President—Engineering, is the person within our Company who is primarily responsible for overseeing the preparation of the reserve estimates. Mr. Gasser joined our Company in 2002 as a Senior Engineer working on acquisitions/divestitures and special projects, became Engineering Manager in 2006 and was promoted to his current position as Vice President—Engineering in October 2012. Mr. Gasser has 30 years experience as a petroleum engineer, including 27 years directly involved in the estimation and evaluation of oil and gas reserves. Mr. Gasser holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University. He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.

Williamson is an independent petroleum engineering consulting firm registered in the State of Texas, and John D. Savage, Executive Vice President—Engineering Manager of Williamson, is the technical person primarily responsible for evaluating the proved reserves covered by its report.

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Mr. Savage has 31 years experience in evaluating oil and gas reserves, including 29 years experience as a consulting reservoir engineer. Mr. Savage holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers and the Society of Independent Professional Earth Scientists.

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 70 years. William K. Fry, Vice President of Ryder Scott, is the technical person primarily responsible for evaluating the proved reserves covered by its report. Mr. Fry has over 30 years of experience in the estimation and evaluation of petroleum reserves. Mr. Fry holds a Bachelor of Science degree in Mechanical Engineering from Kansas State University. He is a Registered Professional Engineer in the State of Texas.

Technology used to establish proved reserves

Under current SEC standards, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and governmental regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. "Reliable technology" is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability. The technological data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Generally, oil and gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations. Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technological data to assess the reservoir continuity. In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities. Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data. When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of oil and gas derived through volumetric calculations.

Virtually all of our additions to proved reserves in 2012 were derived from wells drilled in the Permian Basin and the Giddings Area. A significant amount of technological data is available in these areas, which allows us to estimate with reasonable certainty the proved reserves and production decline rates attributable to most of our reserve additions through analogy to historical performance from wells in the same reservoirs. None of our additions to proved reserves for 2012 were estimated solely on volumetric calculations.

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Processes and controls

Mr. Gasser and his engineering staff maintain a reserves database covering substantially all of our oil and gas properties utilizing AriesTM, a widely used reserves and economics software package licensed by a unit of Halliburton Company. Some of our properties are not evaluated since they are individually and collectively insignificant to our total proved reserves and related PV-10. Our engineering staff assimilates all technological and operational data necessary to evaluate our reserves and updates the reserves database throughout the year. Technological data is described above under "Technology used to establish proved reserves." Operational data includes ownership interests, product prices, operating expenses and future development costs.

Using the most appropriate method available, Mr. Gasser applies his professional judgment, based on his training and experience, to project a production profile for each evaluated property. Mr. Gasser consults with other engineers and geoscientists within our company as needed to validate the accuracy and completeness of his estimates and to determine if any of the technological data upon which his estimates were based are incorrect or outdated.

The engineering staff consults with our accounting department to validate the accuracy and completeness of certain operational data maintained in the reserves database, including ownership interests, average commodity prices, price differentials, and operating costs.

Although we believe that the estimates of reserves prepared by our engineering staff have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage independent petroleum engineering consultants to prepare annual evaluations of our estimated reserves. After Mr. Gasser and our engineering staff have made an internal evaluation of our estimated reserves, we provide copies of the Aries™ reserves database to Ryder Scott as it relates to properties owned by SWR, one of our wholly owned subsidiaries, and to Williamson as it relates to properties owned by CWEI and Warrior Gas Company, another of our wholly owned subsidiaries. In addition, we provide to the consultants for their analysis all pertinent data needed to properly evaluate our reserves. The services provided by Williamson and Ryder Scott are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about the evaluations performed by Williamson and Ryder Scott, see copies of their respective reports filed as exhibits to our Annual Report on Form 10-K for the year ended December 31, 2012.

Both Williamson and Ryder Scott use the Aries™ reserves database that we provide to them as a starting point for their evaluations. This process reduces the risk of errors that can result from data input and also results in significant cost savings to us. The petroleum engineering consultants generally rely on the technical and operational data provided to them without independent verification; however, in the course of their evaluation, if any issue comes to their attention that questions the validity or sufficiency of that data, the consultants will not rely on the questionable data until they have resolved the issue to their satisfaction. The consultants analyze each production decline curve to determine if they agree with our interpretation of the underlying technical data. If they arrive at a different conclusion, the consultants revise the estimates in the database to reflect their own interpretations.

After Williamson and Ryder Scott complete their respective evaluations, they return a modified Aries™ reserves database to our engineering staff for review. Mr. Gasser identifies all material variances between our initial estimates and those of the consultants and discusses the variances with Williamson or Ryder Scott, as applicable, in order to resolve the discrepancies. If any variances relate to inaccurate or incomplete data, corrected or additional data is provided to the consultants and the related estimates are revised. When variances are caused solely by judgment differences between Mr. Gasser and the consultants, we accept the estimates of the consultants.

The final reserve estimates are then analyzed by our financial accounting group under the direction of Michael L. Pollard, our Senior Vice President and Chief Financial Officer. The group

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reconciles changes in reserve estimates during the year by source, consisting of changes due to extensions and discoveries, purchases/sales of minerals-in-place, revisions of previous estimates and production. Revisions of previous estimates are further analyzed by changes related to pricing and changes related to performance. All material fluctuations in reserve quantities identified through this analysis are discussed with Mr. Gasser. Although unlikely, if an error in the estimated reserves is discovered through this review process, Mr. Gasser will submit the facts related to the error to the appropriate consultant for correction prior to the public release of the estimated reserves.

Other information concerning our proved reserves

The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and PV-10 are based on various assumptions and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Since January 1, 2009, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.

Delivery Commitments

As of December 31, 2012, we had no commitments to provide fixed and determinable quantities of oil or natural gas in the near future under contracts or agreements, other than through customary marketing arrangements which require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.

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Exploration and Development Activities

We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.

	Year Ended December 31,

	2012				2011				2010
	Gross		Net		Gross		Net		Gross		Net
	(Excludes wells in progress at the end of any period)
Development Wells:
Oil		135		87.3		156		111.6		136		110.7
Gas		—		—		3		0.2		1		0.5
Dry		5		5.0		—		—		3		1.3


Total		140		92.3		159		111.8		140		112.5




Exploratory Wells:
Oil		5		3.8		5		1.4		2		2.0
Gas		—		—		2		0.7		—		—
Dry		1		0.5		3		1.5		2		0.5


Total		6		4.3		10		3.6		4		2.5




Total Wells:
Oil		140		91.1		161		113.0		138		112.7
Gas		—		—		5		0.9		1		0.5
Dry		6		5.5		3		1.5		5		1.8


Total		146		96.6		169		115.4		144		115.0

The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.

Productive Well Summary

The following table sets forth certain information regarding our ownership, as of December 31, 2012, of productive wells in the areas indicated.

	Oil				Gas				Total

	Gross		Net		Gross		Net		Gross		Net
Permian Basin Area:
Delaware Basin		76		63.3		—		—		76		63.3
Other		2,350		1,270.5		148		79.1		2,498		1,349.6
Austin Chalk/Eagle Ford Shale		349		282.4		21		12.4		370		294.8
Other		32		12.7		55		28.6		87		41.3


Total		2,807		1,628.9		224		120.1		3,031		1,749.0

Volumes, Prices and Production Costs

All of our oil and gas properties are located in one geographical area, specifically the United States. The following table sets forth certain information regarding the production volumes of, average

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sales prices received from, and average production costs associated with all of our sales of oil and gas production for the periods indicated.

	Year Ended December 31,

	2012		2011		2010
Oil and Gas Production Data:
Oil (MBbls)		3,821		3,727		3,375
Gas (MMcf)		8,072		8,594		10,750
Natural gas liquids (MBbls)		433		275		292
Total (MBOE)		5,599		5,434		5,459
Average Realized Prices(a):
Oil ($/Bbl)	$	90.97	$	92.43	$	76.44
Gas ($/Mcf)	$	3.59	$	5.30	$	5.17
Natural gas liquids ($/Bbl)	$	38.95	$	53.37	$	42.47
Average Production Costs:
Production ($/MBOE)(b)	$	16.69	$	13.07	$	10.71

(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): Excludes property taxes and severance taxes.

Only two fields, the Spraberry Trend field and the Wolfbone Trend field in the Permian Basin, accounted for 15% or more of our total proved reserves (on a BOE basis) as of December 31, 2012. The following table discloses our oil, gas and natural gas liquids production from these fields for the periods indicated.

	Year Ended December 31,

	2012		2011		2010
Oil and Gas Production Data:
Spraberry Trend Field
Oil (MBbls)		814		972		671
Gas (MMcf)		746		355		304
Natural gas liquids (MBbls)		162		97		94
Total (MBOE)		1,100		1,128		816
Wolfbone Trend Field
Oil (MBbls)		610		83		—
Gas (MMcf)		334		16		8
Natural gas liquids (MBbls)		63		—		—
Total (MBOE)		729		86		1

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Development, Exploration and Acquisition Expenditures

The following table sets forth certain information regarding the costs we incurred in our development, exploration and acquisition activities during the periods indicated.

	Year Ended December 31,

	2012		2011		2010
	(In thousands)
Property Acquisitions:
Proved	$	41,098	$	—	$	9,556
Unproved		72,235		61,236		29,680
Developmental Costs		349,972		328,418		238,197
Exploratory Costs		10,898		27,425		7,528


Total	$	474,203	$	417,079	$	284,961

Acreage

The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2012 in the areas indicated. This table excludes options to acquire leases and acreage in which our interest is limited to royalty, overriding royalty and similar interests.

	Developed				Undeveloped				Total

	Gross		Net		Gross		Net		Gross		Net
Permian Basin		141,888		70,642		523,244		208,434		665,132		279,076
Giddings Area		153,361		137,114		128,096		108,271		281,457		245,385
Other(a)		19,448		9,155		299,888		154,657		319,336		163,812


Total		314,697		216,911		951,228		471,362		1,265,925		688,273

(a): Net undeveloped acres are attributable to the following areas: Utah—44,850; Colorado—29,804; Alabama—17,155; Louisiana—11,503; Oklahoma—8,962; Nevada—8,535; Mississippi—6,347; and Other—27,501.

The following table sets forth expiration dates of the leases of our gross and net undeveloped acres as of December 31, 2012.

	Acres Expiring(a)

	2013				2014				2015
	Gross		Net		Gross		Net		Gross		Net
Permian Basin		39,766		28,177		58,175		31,734		45,227		19,821
Giddings Area		43,702		40,069		28,841		27,404		17,716		15,303
Other		21,942		13,280		20,255		11,012		37,777		17,661


		105,410		81,526		107,271		70,150		100,720		52,785

(a): Acres expiring are based on contractual lease maturities. We may extend the leases prior to their expiration based upon planned activities or for other business activities.

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Desta Drilling

Through Desta Drilling, we currently operate 14 drilling rigs, two of which we lease under long-term contracts. The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties from time to time. As of February 25, 2013, we were using four of our rigs to drill wells in our developmental drilling programs, four rigs were working for third parties and the remaining six rigs were idle.

Offices

We lease from a related partnership approximately 89,000 square feet of office space in Midland, Texas for our corporate headquarters. We also lease approximately 7,600 square feet of office space in Houston, Texas and 1,400 square feet in College Station, Texas from unaffiliated third parties.

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MANAGEMENT

Officers and Directors

The following table sets forth names, ages and titles of our officers and directors as of January 14, 2014.

Name		Title

Clayton W. Williams, Jr.	82	Chairman of the Board, President and Chief Executive Officer
Davis L. Ford(1)	76	Director
Robert L. Parker(1)	90	Director
Jordan R. Smith(1)	79	Director
Ted Gray, Jr.(1)	63	Director
Mel G. Riggs	59	Director, Executive Vice President and Chief Operating Officer
Michael L. Pollard	63	Senior Vice President—Finance and Chief Financial Officer
Ronald D. Gasser	55	Vice President—Engineering
John F. Kennedy	49	Vice President—Operations
Robert C. Lyon	77	Vice President—Gas Gathering and Marketing
Samuel L. Lyssy, Jr.	51	Vice President—Exploration
Patrick C. Reesby	61	Vice President—New Ventures
Robert L. Thomas	57	Vice President—Accounting and Principal Accounting Officer
T. Mark Tisdale	57	Vice President and General Counsel
Gregory S. Welborn	40	Vice President—Land

(1): Member of the Audit, Compensation and Nominating and Governance Committees of the Board.

Our Board of directors currently consists of six members who have been appointed into their respective classes in accordance with our bylaws. The Board is composed of three classes of directors. One class of directors is elected each year to hold office for a three-year term and until successors of such class are duly elected and qualified. Mr. Williams and Mr. Riggs are executive officers of the Company and, therefore, are not independent directors under regulations of the SEC or under the corporate governance listing standards of the New York Stock Exchange ("NYSE").

Information is provided below for each of the directors regarding their positions with the Company or other principal occupations for the past five years, other directorships held during the past five years, and the year initially elected a director of the Company. The biographies of directors below contain, among other things, information regarding the experiences, qualifications, attributes or skills that led the Nominating and Governance Committee and the Board to the conclusion that such individual should serve as a director for the Company. For information concerning the ownership of Company common stock by each director, see "Security Ownership of Certain Beneficial Owners and Management." There are no family relationships among the directors or officers of the Company, except that Mr. Williams is the father-in-law of Gregory S. Welborn, Vice President—Land.

CLAYTON W. WILLIAMS, JR. is Chairman of the Board, President, Chief Executive Officer and a director of the Company, having served in such capacities since September 1991. For more than the past five years, Mr. Williams has also been the chief executive officer and a director of certain entities that are controlled directly or indirectly by Mr. Williams, referred to as the Williams Entities. See "—Certain Transactions and Relationships." Mr. Williams beneficially owns, either individually or through his affiliates, approximately 25.6% of the outstanding shares of the Company's common stock. See "Security Ownership of Certain Beneficial Owners and Management." Mr. Williams has extensive knowledge of the oil and gas industry, as well as relationships with chief executives and other senior management of oil and gas companies and oilfield service companies throughout the United States. He

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is the principal stockholder of the Company, actively participates in all facets of the Company's business, and has a significant impact on both its business strategy and daily operations.

DAVIS L. FORD is a director of the Company and a member of the Audit, Compensation and Nominating and Governance Committees of the Board. Dr. Ford has served as a director of the Company since February 2004. Dr. Ford has been president of Davis L. Ford & Associates, an environmental engineering and consulting firm, for more than the past five years and is also an adjunct professor at The University of Texas at Austin. Dr. Ford is a distinguished engineering graduate of both Texas A&M University and The University of Texas at Austin and is also a member of the National Academy of Engineering. Dr. Ford's extensive experience as an environmental engineer specializing in matters pertaining to the oil and gas industry provides us with valuable insight into environmental risks and associated regulations. In addition, Dr. Ford's years of experience in business and his educational background provide us with sound advice in the conduct of the business.

ROBERT L. PARKER is a director of the Company and a member of the Audit, Compensation and Nominating and Governance Committees of the Board. Mr. Parker has served as a director of the Company since May 1993. Mr. Parker is retired. Until his retirement in April 2006, he was the Chairman of the Board of Parker Drilling, a publicly owned corporation providing contract drilling services, a position he held since 1969. Mr. Parker has vast experience in leading a publicly owned corporation for over 50 years, having served in a combination of leadership roles including president, chief executive officer and chairman of the board of Parker Drilling. Mr. Parker is also a leading spokesperson for the oil and gas industry at the national level and provides us with valuable insight into legislative matters involving the business.

JORDAN R. SMITH is a director of the Company and a member of the Audit, Compensation and Nominating and Governance Committees of the Board. Mr. Smith has served as a director of the Company since July 2000. Mr. Smith is President of Ramshorn Investments, Inc., a wholly owned subsidiary of Nabors Industries, having served in such capacity for more than the past five years. Mr. Smith is an experienced geologist with a high level of technical expertise in the oil and gas industry. In addition, Mr. Smith's leadership experience with publicly owned companies and overall business background provides us with valuable judgment in the conduct of the business. Mr. Smith has also served on the Board of the University of Wyoming Foundation and the Board of the Domestic Petroleum Council.

TED GRAY, JR. is a director of the Company and a member of the Audit, Compensation and Nominating and Governance Committees of the Board. Mr. Gray is a Vice President at UBS Financial Services, Inc. in Austin, Texas where he is a member of a team managing portfolios for high net worth individuals and foundations. Prior to joining UBS Financial Services, Inc. in December 2008, Mr. Gray was an investment advisor with Morgan Stanley in Austin, Texas for eight years and has been involved in banking and investment activities since 1972. Mr. Gray's extensive knowledge related to investments and other financial matters provides us with valuable insight into domestic and global financial markets and sound advice on matters affecting the business.

MEL G. RIGGS is Executive Vice President and Chief Operating Officer of the Company, having served in such capacities since December 2010. Mr. Riggs was previously Senior Vice President and Chief Financial Officer of the Company, having served in that capacity since September 1991. Mr. Riggs has served as a director of the Company since May 1994. Mr. Riggs is the sole general partner of The Williams Children's Partnership, Ltd., referred to as WCPL, a limited partnership in which the adult children of Clayton W. Williams, Jr. are the limited partners. WCPL holds approximately 25% of the outstanding shares of the Company's common stock. As the sole general partner, Mr. Riggs has the power to vote or direct the voting of the shares of the Company's common stock held by WCPL. See "Security Ownership of Certain Beneficial Owners and Management." Mr. Riggs also serves as an officer and director of certain of the Williams Entities. Since July 2009,

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Mr. Riggs has also served as a director of TransAtlantic Petroleum Ltd, a publicly owned company engaged internationally in the acquisition, development, exploration and production of crude oil and natural gas. Mr. Riggs has served in a leadership position in the Company from its inception and has demonstrated his value as a proven leader. Mr. Riggs has extensive knowledge in strategic planning, is an expert in financial matters and is highly qualified to make strategic and operational decisions on behalf of the Company.

Non-Director Executive Officers

MICHAEL L. POLLARD is Senior Vice President—Finance and Chief Financial Officer of the Company, having served in such capacities since January 2011. Prior to that, Mr. Pollard had served as Vice President—Accounting of CWEI since 2003.

RONALD D. GASSER is Vice President—Engineering of the Company, having served in such capacity since October 2012. Prior to that, Mr. Gasser had served as Engineering Manager of the Company since 2006.

JOHN F. KENNEDY is Vice President—Drilling of the Company, having served in such capacity since October 2012. Prior to that, Mr. Kennedy had served as Drilling Manager of the Company since 1998.

ROBERT C. LYON is Vice President—Gas Gathering and Marketing of the Company, having served in such capacity since 1993.

SAMUEL L. LYSSY, Jr. is Vice President—Exploration of the Company, having served in such capacity since October 2012. Prior to that, Mr. Lyssy had served as Exploration Manager of the Company since 1995.

PATRICK C. REESBY is Vice President—New Ventures of the Company, having served in such capacity since 1993.

ROBERT L. THOMAS is Vice President—Accounting and Principal Accounting Officer of the Company, having served in such capacity since January 2011. Prior to that, Mr. Thomas had served as General Accounting Manager of the Company since 2003.

T. MARK TISDALE is Vice President and General Counsel of the Company, having served in such capacity since 1993.

GREGORY S. WELBORN is Vice President—Land of the Company, having served in such capacity since 2006. Mr. Welborn is the son-in-law of Clayton W. Williams, Jr.

Executive Compensation

Compensation Discussion and Analysis

General

The Compensation Committee consists of Messrs. Gray, Ford, Parker and Smith, all of whom are independent directors under current federal securities laws and NYSE corporate governance listing standards and are "outside directors" for purposes of Section 162(m) of the Tax Code. The Compensation Committee establishes the salaries of all corporate officers, including the named executive officers set forth in the Summary Compensation Table below, and directs and administers the Company's incentive compensation plans. The Compensation Committee also reviews with the Board its recommendations relating to the future direction of corporate compensation practices and benefit programs.

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Throughout this proxy statement, the following individuals are referred to as the named executive officers:

•: Clayton W. Williams, Jr., Chairman of the Board, President and Chief Executive Officer
•: Mel G. Riggs, Executive Vice President and Chief Operating Officer
•: Michael L. Pollard, Senior Vice President—Finance and Chief Financial Officer
•: Ronald D. Gasser, Vice President—Engineering
•: Samuel L. Lyssy, Jr., Vice President—Exploration

Compensation Philosophy and Principles

The Compensation Committee recognizes that the oil and gas exploration and production industry is highly competitive and that experienced professionals have significant career mobility. The Company competes for executive talent with a large number of exploration and production companies, some of which have significantly larger market capitalization than the Company. Comparatively, the Company is a smaller company in a highly competitive industry, and its ability to attract, retain and reward its executive officers and other key employees is essential to maintaining an advantageous position in the oil and gas business. The Company's comparatively smaller size within its industry and its relatively small executive management team provide unique challenges in this industry, and therefore, are substantial factors in the design of the executive compensation program. The Compensation Committee's goal is to maintain compensation programs that are effective in attracting and retaining talented individuals within the independent oil and gas industry. Each year, the Compensation Committee reviews the executive compensation program to assess whether the program remains comparable with those of similar companies, considers the program's effectiveness in creating adequate incentives for executives to find, acquire, develop and produce oil and gas reserves in a cost-effective manner, and determines what changes, if any, are appropriate.

The Compensation Committee has adopted a compensation policy that it believes to be a balance between fair and reasonable cash compensation and incentives linked to the Company's performance, taking into consideration compensation of individuals with similar duties who are employed by its peers in the industry. The policy takes into account the cyclical nature of the oil and gas business, which may result in traditional performance standards being skewed due to erratic commodity prices. An analysis of the Company's goals has resulted in a policy that places an emphasis on increasing the Company's proved oil and gas reserves and production, coupled with maintaining an acceptable balance between its overhead and profit margin. As described more fully below, the Compensation Committee may, in addition to base salaries, award bonuses and direct participation incentives in exploration and production projects based upon the performance of the Company and the efforts of individual executives and key employees.

In determining the form and amount of compensation payable to the Company's executive officers, the Compensation Committee is guided by the following objectives and principles:

•: Compensation levels should be sufficiently competitive to attract, motivate and retain key executives. The Compensation Committee aims to ensure that the Company's executive compensation program attracts, motivates and retains outstanding talent and rewards that talent to the extent the Company achieves and maintains a competitive position in its industry. Total compensation (i.e., maximum achievable compensation) should increase with position and responsibility.
•: Compensation should relate directly to performance and incentive compensation should constitute a substantial portion of total compensation. The Compensation Committee aims to foster a pay-for-performance culture, with a significant portion of total compensation being contingent, directly or indirectly, on Company or individual performance. Accordingly, a substantial portion

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of total compensation should be tied to and vary with the Company's financial, operational and strategic performance, as well as individual performance. Executives with greater roles in particular projects and the ability to directly impact the Company's strategic goals and long-term results should bear a greater proportion of the risk if these goals and results are not achieved, and be rewarded if the Company's goals and results are achieved or exceeded.

•: Long-term incentive compensation should align the interests of executives with the Company's shareholders. Awards of long-term incentive compensation encourage executives to focus on the Company's long-term strategic growth and prospects and incentivize executives to manage the Company from the perspective of its shareholders.
•: Retirement benefits should comprise an element of executive compensation. The Company does not offer retirement benefits to its executive officers other than through its tax-qualified 401(k) plan. Therefore, the Compensation Committee has designed the Company's long-term incentive compensation to also provide a competitive level of replacement income upon retirement.

The Company's executive compensation program is designed to reward the achievement of objectives regarding Company growth and productivity, but it also takes into consideration the role and responsibilities of individual executive officers within the Company and internal pay equity. Therefore, the Company's executive compensation is designed:

•: To encourage the Company's executive officers to maintain a thorough and dynamic understanding of the competitive environment and to position the Company as a respected force within its industry;
•: To incentivize the Company's executive officers to develop strategic opportunities that benefit the Company and its shareholders;
•: To sustain an internal culture focused on performance and the development of the Company's assets into producing properties;
•: To require the Company's executive officers and other key employees to share the risks facing its shareholders, and to enable them to share in the rewards associated with the successful development of the Company's assets into producing properties; and
•: To implement a culture of compliance and unwavering commitment to operate the Company's business with the highest standards of professional conduct and compliance.

Setting Executive Compensation

Management's Role in Setting Executive Compensation

Mr. Williams evaluates all executive officers, including the named executive officers other than himself, and makes recommendations to the Compensation Committee regarding base salary levels and the amounts of any incentive bonus payments and long-term incentive awards to be granted to all executive officers. The Company's Chief Operating Officer and Chief Financial Officer assist Mr. Williams in his evaluation and the preparation of compensation recommendations, except with respect to their own compensation. Additionally, Mr. Williams and the Company's Chief Operating Officer and Chief Financial Officer regularly attend Compensation Committee meetings. These recommendations are given significant weight by the Compensation Committee but are not necessarily determinative of the compensation decisions made by the Compensation Committee. These recommendations are used as points of reference, not as a replacement for the Compensation Committee's own judgment of internal pay equity or the individual performance of an executive that the Compensation Committee also considers when making compensation decisions. While the input of management was integral to decisions made by the Compensation Committee with respect to discretionary bonuses paid in 2013, market comparison data compiled by Longnecker and Associates,

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or L&A, independent consultant to the Compensation Committee, was primarily utilized for purposes of making adjustments to the base salaries of the Company's named executive officers in 2013.

Use of Independent Consultants

The Compensation Committee Charter provides the Compensation Committee with the authority to retain and terminate any compensation consulting firm or other adviser it deems appropriate.

In March 2009, the Compensation Committee first engaged L&A to conduct a market compensation analysis and to provide recommendations regarding the total direct compensation packages of the Company's named executive officers and L&A continued to provide services through 2013. In May 2013, L&A was again engaged to conduct a review of the compensation of the Company's executives and directors. L&A presented its findings (described in detail below) with respect to its 2013 review to the Compensation Committee in June 2013.

In selecting L&A as its compensation consultant, the Compensation Committee assessed the independence of L&A pursuant to SEC rules and considered, among other things, whether L&A provides any other services to the Company, fees paid to L&A as a percentage of its revenue, the policies of L&A that are designed to prevent any conflict of interest between L&A, the Compensation Committee and the Company, any personal or business relationship between L&A and a member of the Compensation Committee or one of the Company's executive officers and whether L&A owned any shares of the Company's common stock. In addition to the foregoing, the Compensation Committee received documentation from L&A addressing the firm's independence. L&A was engaged directly by the Compensation Committee, reports exclusively to the Compensation Committee and does not provide any additional services to the Company. The Compensation Committee has concluded that L&A is independent and does not have any conflicts of interest. While management did cooperate with L&A in collecting data with respect to the Company's compensation programs, the Compensation Committee determined that management had not attempted to influence L&A's review or recommendations.

Market Compensation Analysis

In June 2013, the Compensation Committee reviewed a comparative analysis of the compensation paid to the Company's Chief Executive Officer and other executive officers to compensation data for a peer group of independent exploration and production companies compiled and presented by L&A. The peer group reviewed in 2013 (described below) was the same peer group reviewed in 2012 with the exception of:

•: The addition of Bonanza Creek Energy, Inc., Forest Oil Corporation, Kodiak Oil & Gas Corp. and Resolute Energy Corporation; and
•: The removal of Concho Resources Inc., Continental Resources, Inc., Venoco, Inc. and Whiting Petroleum Corporation.

Venoco, Inc. was removed from the peer group because they are no longer a publicly-held company. The other changes to the peer group were intended to create a mix of competitor companies in our 2013 peer group that are closer in size to the Company with respect to certain metrics, including oil and gas production and oil and gas sales.

The information reviewed by the Compensation Committee included both data gathered from proxy statements of the peer group identified below as well as market data procured by L&A from published survey sources providing information with respect to companies that operate in the oil and gas exploration and production industry with comparable revenues to the Company. Base salary data compiled from proxy statements reflected 2012 compensation and was therefore increased by 4.0% to reflect salary increases as reported for the energy industry in published survey data. The data presented

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to the Compensation Committee was equally weighted 50% from the peer group, when available, and 50% from published survey sources.

The Company's compensation peer group was determined by senior management with assistance from L&A. The Compensation Committee concluded that the group of companies selected was an appropriate peer group for the comparison of salary and other compensation payable to the Company's Chief Executive Officer and its other named executive officers. The peer companies represented a wide range of independent exploration and production companies of similar size to the Company that operate in some of the same geographical areas as the Company.

The 2013 peer group was comprised of the following companies:

•

Bill Barrett Corporation

•

Oasis Petroleum Inc.

•

Bonanza Creek Energy, Inc.

•

Petroquest Energy, Inc.

•

Comstock Resources, Inc.

•

Quicksilver Resources Inc.

•

Forest Oil Corporation

•

Resolute Energy Corporation

•

Goodrich Petroleum Corporation

•

Rosetta Resources Inc.

•

Gulfport Energy Corporation

•

Stone Energy Corporation

•

Kodiak Oil & Gas Corp.

•

Swift Energy Company

•

Legacy Reserves, LP

The objective of the Compensation Committee in reviewing market pay levels within the peer group is to ensure that compensation payable to its executive officers is competitive and not out of market. As noted, however, market pay levels are only one factor considered, with pay decisions ultimately reflecting an evaluation of individual contributions of an executive officer and the executive's value to the Company.

The comparative compensation data provided by L&A revealed the following with respect to the compensation provided by the Company to its named executive officers:

•: Base salaries for named executive officers, on average, are aligned with the 75th percentile of the comparative compensation data (specifically 101% of the 75th percentile).
•: Targeted total annual cash (including base salary and the average of the last three years of annual discretionary incentive bonuses to the Company's named executive officers) was below the 50th percentile of the comparative compensation data (specifically 88% of the 50th percentile).
•: The annual long term incentive compensation paid by the Company to the named executive officers, based on three-year historical data, continues to be well below the 50th percentile of the comparative compensation data (specifically 16% of the 50th percentile), and, based on the average of three-year historical and projected payments over the next three years, is 29% of the 50th percentile of the comparative compensation data.
•: Total annual direct compensation paid to the Company's named executive officers continues to be below the 50th percentile of the comparative compensation data, both with respect to historic and average comparisons (specifically 46% and 61% of historical and average total direct compensation, respectively, of the 50th percentile).

The Compensation Committee does not believe that it is appropriate to establish compensation levels based exclusively or primarily on benchmarking to the Company's peers. The Compensation Committee looks to external market data only as a reference point in reviewing and establishing individual pay components and total compensation and ensuring that the Company's executive compensation is competitive in the marketplace. The Compensation Committee does not attempt to set total compensation or any component of compensation within a specific percentile of the Company's

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peer group. However, the Compensation Committee recognizes the competitive market for hiring and retaining oil and gas executives in the Permian Basin area and the consequent need to provide compensation to the Company's executives that is competitive with the 50th percentile of market compensation in order to retain and attract talented and experienced employees. Therefore, the reports provided by L&A were instructive to the Compensation Committee insofar as they enabled the Compensation Committee to (1) verify that base salaries are competitive, (2) recognize that historic incentive payments have been considerably below market, and (3) recognize that total direct compensation continues to be slightly below market.

Determining Compensation Levels

The Compensation Committee annually determines the individual pay components of the Company's executive officers. In making such determinations in 2013, the Compensation Committee reviewed and considered (1) the market compensation analysis referred to above prepared by L&A, (2) recommendations of the Company's Chief Executive Officer, based on individual responsibilities and performance, (3) historical compensation levels for each executive officer, (4) industry conditions and the Company's future objectives and challenges, (5) the overall effectiveness of the executive compensation program, and (6) the overwhelming support expressed by shareholders in the 2011 advisory vote on executive compensation.

Historically, the base salary of the Company's named executive officers has been approximately 40% of the total compensation of the named executive officers, with the bulk of the remainder of compensation consisting of discretionary bonuses and long-term incentives, and with other annual compensation consisting of less than 5% of the total compensation This is not due to any specific policy, practice or formula regarding the proper allocation between different elements of total compensation, but does reflect the desire of the Compensation Committee to emphasize variable components of compensation to foster a pay-for-performance culture. In 2013 base salary was on average 37% of the total compensation of the Company's named executive officers, ranging between 29% and 47% of total compensation as reported in the Summary Compensation Table below.

The components of compensation paid to executive officers in 2013 were:

•: Base salary;
•: Discretionary bonus;
•: Long-term incentive awards; and
•: Other annual compensation.

Compensation of executive officers has generally consisted of these elements since 2001.

The Compensation Committee has reviewed all components of the compensation of the Chief Executive Officer and the other named executive officers, including salary, bonus and long-term compensation, the dollar value to the executive and the cost to the Company of all perquisites and other personal benefits, and the projected future payouts under non-equity long term incentive awards described below. In addition, as described above, the Compensation Committee has reviewed the compensation of executive officers set forth in comparative compensation data. The Compensation Committee has reviewed the compensation policies of the Company and discussed the increased competition encountered by the Company in attracting and retaining qualified employees.

Based upon data provided by L&A and recommendations provided by Messrs. Williams, Riggs and Pollard, and upon its own judgment, the Compensation Committee approved the base salary, discretionary bonus, long-term incentive awards and other annual compensation of each of the Company's executive officers in 2013. The Compensation Committee believes these approved forms and levels of compensation are reasonable, appropriate and consistent with the Company's compensation

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philosophy and principles. Further, the Compensation Committee believes the Company's executive compensation program is effective because (1) the Company has retained its executive team in a competitive industry, and (2) the Company has demonstrated its ability to find, acquire, develop and produce oil and gas reserves in a cost-effective manner.

Base Salary

Base salary is set by the Compensation Committee at a level based on each executive officer's position, level of responsibility, and individual performance. While it is the general intent of the Compensation Committee that a significant portion of the total compensation paid to the executive officers be attributable to variable compensation, either in the form of discretionary bonuses or long-term incentive awards, when base salaries of executives are set by the Compensation Committee, it cannot be certain of the amount of total variable compensation that will be paid due to the nature of the Company's long-term incentive compensation program discussed in greater detail below. The Compensation Committee believes that its reliance on variable compensation fosters a pay-for-performance culture by tailoring annual compensation to the success of projects in which an executive officer is involved, while ensuring that the executive will continue to receive a consistent base amount of compensation.

Due to continued competition from local and regional competitors in the Permian Basin area with respect to hiring and retaining qualified employees, the Compensation Committee met on July 24, 2013, to discuss base salary increases for the executive officers of the Company in order to ensure the retention of those individuals. At the meeting, management recommended, and the Compensation Committee approved, base salary increases, effective August 1, 2013 for all of the named executive officers.

The table below sets forth a comparison of the annual base salary rates applicable to each named executive officer as of the end of fiscal years 2012 and 2013.

	Annual Base Salary Rate as of

Name	December 31, 2012		December 31, 2013		% Increase
Clayton W. Williams, Jr.	$	750,000	$	810,000		8	%
Mel G. Riggs	$	450,000	$	486,000		8	%
Michael L. Pollard	$	350,000	$	424,000		21	%
Ronald D. Gasser	$	400,000	$	432,000		8	%
Samuel L. Lyssy, Jr.	$	450,000	$	486,000		8	%

Although the Compensation Committee did not explicitly benchmark the base salaries of the named executive officers to the comparative compensation data, it reviewed the information provided by L&A which showed that, following the increase in base salaries, its executive officers as a group were aligned with the 75th percentile of the comparative compensation data. However, Mr. Pollard's base salary was 89% of the 75th percentile of the comparative compensation data which precipitated his larger percentage increase to align his base salary slightly above the 75th percentile. Upon reviewing the comparative compensation data the Compensation Committee determined that base salaries, as adjusted in 2013, appropriately addressed the retention concerns of the Compensation Committee.

Bonus

Bonuses are discretionary and are paid if and when the Compensation Committee determines they are appropriate to reward exceptional individual performance and to encourage loyalty to the Company and the interests of its shareholders. The Compensation Committee believes that such bonuses serve both as a reward for performance and an incentive for future extraordinary performance in anticipation of such recognition.

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Executive officers of the Company, including Messrs. Williams, Riggs and Pollard, may recommend bonuses to the Compensation Committee for their approval to reward individual performance. Annual bonuses may also be used to compensate particular executives and key employees who the Compensation Committee determines are less than fully compensated at a particular point in time due to the failure of the long-term incentive awards granted to the employee to result in payment. As is described in greater detail below, the nature of the Company's long-term incentive award program is such that an award could fail to ever result in payment through no lack of effort by the executive and in circumstances where the performance of the Company as a whole is very good. Although as a general policy, the Compensation Committee believes that executives should share the risks and rewards of the Company's shareholders, if over a period of time an executive is undercompensated due to the nature of the Company's long-term incentive program, the Compensation Committee will consider paying additional cash bonuses to the executive.

In 2013 bonuses paid to the Company's executive officers were generally based on management recommendations to award the named executive officers for their individual performance. Bonuses were not paid pursuant to pre-established performance criteria communicated to the executives. Instead, bonuses were paid periodically throughout the year upon completion of various projects to the executives involved in such projects, as recommended by management and approved by the Compensation Committee.

The Company paid incentives of $50,000, $100,000, $75,000 and $75,000 to Messrs. Williams, Riggs, Pollard and Gasser, respectively, for services performed with respect to the sale of land and mineral interests in Andrews County, Texas that occurred during 2013. In addition, the Company paid incentives of $150,000, $100,000 and $50,000 to Messrs. Riggs, Pollard and Gasser, respectively, in the fourth quarter of 2013 in connection with their efforts in the successful completion of the Company's bond offering. Messrs. Riggs, Pollard and Lyssy also received small bonuses in recognition of their years of service with the Company consistent with Company policy.

Finally, the Company has historically paid Christmas bonuses to all employees, including executive officers, in amounts ranging from one-third to one-half of a month's base salary. In 2013, the named executive officers received Christmas bonuses equal to approximately one-half of a month's base salary. The discretionary bonuses paid to each of the named executive officers in 2013 is quantified below in the section titled "—Summary Compensation Table."

Long-Term Incentive Compensation

Long-term incentive compensation available to the Company's executive officers has historically consisted of both equity-based awards and non-equity awards. However, in 2009, the Company discontinued its equity compensation plan and currently none of the named executive officers hold any outstanding equity awards. Since that time, long-term incentive compensation consisted exclusively of non-equity incentive awards. Following is a discussion of each of the long-term incentive awards in effect during 2013.

APO Plans

The executive officers, key employees and consultants of the Company participate in an after-payout, referred to as APO, incentive plan, referred to as the APO Incentive Plan. The APO Incentive Plan was created to incentivize the Company's executives to find, acquire, develop and produce oil and gas reserves in a cost-effective manner, and to reward those executives for the successful management of projects that produce value to the Company's shareholders. The APO Incentive Plan provides for the creation of a series of partnerships (either limited partnerships or tax partnerships) through which the Company contributes a portion of its working interests in wells drilled or acquired within certain geographical areas. Under the APO Incentive Plan, the Company pays all costs and receives all

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revenues relative to the contributed working interests until it achieves "Payout," which is generally the return of its costs, plus interest. After Payout, the officers, key employees and consultants who were granted the right to participate in the partnership receive at least 99% of the partnership's subsequent revenues and pay at least 99% of its subsequent expenses. The Compensation Committee believes that aligning a portion of the executive officers' long-term compensation to the performance of the Company's exploration, development and acquisition programs is both a reward for the acquisition and development of such properties and an incentive to manage the properties in a manner that will maximize the long-term success for both the Company and themselves.

From 2002 through 2005, APO Incentive Plan awards were structured as limited partner interests in Texas limited partnerships. Since 2006, the APO Incentive Plan awards have been structured as participation agreements that are intended by the participants to be treated as partnerships solely for federal and state income tax purposes. Although the economics of the APO Incentive Plan awards in the Texas limited partnership structure and the participation agreement structure have remained unchanged, the current practice of utilizing participation agreements is preferable to, and is less burdensome for the Company to administer than, the limited partnership structure.

Although the percentage of the Company's contributed working interests varies from partnership to partnership, contributions under the APO Incentive Plan currently range from 5% to 7.5% of the Company's working interests in the applicable wells, depending on the nature of the underlying project. The percentage of working interests contributed is determined in the discretion of the Compensation Committee after considering recommendations made by Mr. Williams.

At the time APO Incentive Plan awards are granted, the ultimate amount payable to the participants under the award is not determinable. Each APO Incentive Plan award represents a potential working interest in one or more wells in a limited geographic area. Potentially, the award may never become payable, or it may become payable at an indeterminable future date. The participants who receive specific APO Incentive Plan awards, and the size of the APO Incentive Plan award granted to each participant, are determined at the discretion of the Compensation Committee after considering recommendations made by Mr. Williams. Generally, each particular working interest in a geographic area is awarded to the executive officers and key employees primarily responsible for that project. The size of the APO Incentive Plan award granted to each participant out of that particular working interest is generally determined based upon his or her potential individual impact on the success of the project.

Once granted, an APO Incentive Plan award is fully vested and is not forfeitable, except in circumstances of fraud against the Company by a participant. However, the Company retains the right to grant new APO Incentive Plan awards in the same geographic area. This allows the Company to effectively limit a participant's award to the then-existing wells, without preserving a participant's future interest in further drilling activity in that same geographic area.

No awards were made under the APO Incentive Plan in 2013. A detailed description of all amounts paid to the named executive officers in 2013 pursuant to existing APO Incentive Plan awards can be found under "—Summary Compensation Table," "—Supplemental Information About the APO Plan" and"—Narrative Disclosure to Summary Compensation Table."

In 2008, the Compensation Committee authorized the formation of the APO Reward Plan to reward eligible executive officers, key employees and consultants for continued quality service to the Company, and to encourage retention of those employees and service providers by providing them the opportunity to receive bonus payments that are based on certain profits derived from a portion of the Company's working interest in specified areas where the Company is conducting drilling and production enhancement operations. Since 2010, the APO Reward Plan has been the Company's principal vehicle for providing new long-term incentive compensation awards to the Company's executives.

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The wells subject to the APO Reward Plan are mutually exclusive from any wells subject to a participation agreement created under the APO Incentive Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan pursuant to which the Company pays participants a bonus equal to a portion of APO cash flows received by the Company pursuant to its working interest. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the Plan, increasing the retention value of the APO Reward Plan to the Company. Participants are entitled to receive distributions with respect to awards under the APO Reward Plan from and after the date of grant; however, in the event a participant terminates employment with the Company prior to the vesting date, the award will be forfeited to the Company and the participant will not be entitled to participate in future distributions.

In 2013, the CWEI Austin Chalk II and the CWEI Austin Chalk III Reward Plans were amended to exclude the Eagle Ford Shale formation in order to create a new APO Reward Plan specific to the Eagle Ford Shale. In 2013 the Compensation Committee authorized the granting of awards under the CWEI Eagle Ford I, CWEI East Permian, the CWEI Oklahoma 3D Phase 1, and the CWEI Oklahoma 3D Phase 2 Reward Plans. The vesting date for the CWEI Oklahoma 3D Phase 1 and CWEI Oklahoma 3D Phase 2 Reward Plans is May 1, 2013 and the vesting date for the CWEI Eagle Ford I and East Permian Reward Plans is August 1, 2013. Each reward plan provides for the payment of bonuses to participants equal to 10% of the Company's after-Payout working interests in wells drilled by the Company after the effective date of the award. Each of the named executive officers is a participant in the four new bonus plans. A detailed description of all awards made under the APO Reward Plan and amounts paid to the named executive officers in 2013 pursuant to APO Reward Plan awards can be found under"—Summary Compensation Table," "—Supplemental Information About the APO Incentive Plan and the APO Reward Plan," "—Grants of Plan-Based Awards" and "—Narrative Disclosure to Summary Compensation Table."

The Compensation Committee believes that the structure of the APO Plans satisfies several important compensatory objectives.

•: It aligns the interests of the Company's executive officers and key employees with those of its shareholders by conditioning payment under the APO Incentive Plan awards upon Payout and positive cash flows into the Company.
•: It encourages the Company's executive officers and key employees to find, acquire, develop and produce oil and gas reserves for the Company in a cost-effective manner.
•: Previously granted APO Plan awards provide current income to the Company's executive officers and key employees.
•: APO Plan awards potentially provide future income to the Company's executive officers and key employees that will be available to them in their retirement. Hence, the APO Plan provides both current incentives and potential retirement income to the Company's executive officers.

Beginning in 2008, Mr. Williams has also participated in the APO Plans. The Compensation Committee established the following parameters in connection with Mr. Williams' participation in the APO Plans:

•: Mr. Williams will continue to recommend to the Compensation Committee the percentage of the Company's working interest that will be assigned to each APO Plan, as well as the unit allocation of that working interest among the participants, other than Mr. Williams.
•: In each APO Plan authorized by the Compensation Committee, Mr. Williams will be granted an interest equal to 40% of the working interest being allocated among all other participants,

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except that Mr. Williams' interest will be reduced as needed to limit the total working interest being assigned to any APO Plan to 10% of the Company's working interest.

•: All other provisions of the APO Plan will be uniformly applied to all participants, including Mr. Williams.

The Compensation Committee believes that allowing Mr. Williams to participate in the APO Plans is an effective component of the overall compensation package for Mr. Williams. These plans create additional incentives for Mr. Williams to find, acquire, develop and produce oil and gas reserves in a cost-effective manner by restricting payments to him under an APO Plan to a portion of the after-Payout cash flow of specified exploration, development and acquisition projects of the Company. The Compensation Committee further believes that his participation in the APO Plans will provide Mr. Williams with current cash flow and will be a potential source of post-retirement income.

APO Working Interest Grant

In May 2003, the Compensation Committee approved the grant of 5% of the Company's after-Payout working interests in certain acreage in New Mexico to key employees, other than Mr. Williams, who contributed to the success of that project. In connection with the grant, the participants received a cash payment equal to the net revenues attributable to the distributed interests from the date Payout status was achieved (May 2002) through June 2003, and received an assignment of their proportionate share of the working interests in the acreage effective July 1, 2003. The working interests conveyed were and are fully vested and non-forfeitable. All net revenues, consisting of oil and gas sales, net of production taxes and other expenses, attributable to the distributed interests are paid to the participants in proportion to each participant's ownership interest in the grant. Messrs. Riggs and Pollard received payments in 2013 from the APO Working Interest Grant as described in the footnotes under "—Summary Compensation Table."

APO Working Interest Trusts

In 2001, prior to adopting the current structure of the APO Incentive Plan, the Compensation Committee approved the creation of six trusts through which the Company's executive officers and key employees, excluding Mr. Williams, received after-Payout working interests in wells drilled by the Company. These trusts were structured so that the participants were beneficiaries of the assigned working interest once Payout was achieved. The working interests conveyed were and are fully vested and non-forfeitable. Upon dissolution, each trust distributed to the beneficiaries a fractional direct ownership in the working interests held by the trust. Two of the trusts achieved Payout status and have been dissolved. Four of the trusts did not achieve Payout status and have been dissolved, with the working interests being reassigned to the Company. Messrs. Riggs, Pollard and Lyssy received payments in 2013 from the APO Working Interest Trusts as described in the footnotes under "—Summary Compensation Table."

Other Compensation

The Company's executive officers also participate in the employee benefit programs that are provided to its full-time employees generally, including its group health plan, group life insurance program, and its 401(k) Plan & Trust, which provides for matching contributions equal to 100% of participant deferrals up to 6% of compensation for purposes of the plan. In addition, certain of the Company's executive officers receive a monthly automobile allowance, and the Company pays various club membership dues and personal expenses on behalf of certain executive officers.

The named executive officers and other management employees are provided use of charter aircraft for business purposes. From time to time, a portion of a business trip will constitute "commuting" with respect to an executive officer. This portion of the business trip is treated as

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"personal use" of the aircraft by the Company and the taxable value of such use is imputed as income to the named executive officer. The methodology used to determine the Company's incremental cost for personal aircraft usage is described in footnote 1 of the "—Perquisites and other Personal Benefits" table below.

Employment Agreements

The Company has entered into employment agreements with certain of its senior executives, including each of the named executive officers. The employment agreements are effective for an initial term of three years, and will be automatically extended for an additional one year period on the third anniversary date of the effective date of the agreement (and on the fourth and fifth anniversary dates of the effective date), unless, at least 90 days prior to any such anniversary date, either party gives notice of non-renewal.

The employment agreements grant specified benefits to the executives upon certain changes in their employment status and in the event of a change in control. The agreements also provide that the executives will maintain confidentiality of non-public and proprietary information of the Company and, except for Mr. Williams, will not compete with the Company for a period of one year after a termination for which benefits are received. Mr. Williams' covenants regarding competition with the Company are governed by a pre-existing agreement described in more detail under "—Potential Payments Upon Termination or Change in Control."

The Compensation Committee believes that it is in the Company's best interests as well as the best interests of its shareholders to offer such benefits to these senior executives. The Company competes for executive talent in a highly competitive market in which peers routinely offer similar benefits to senior executives. The Compensation Committee believes that providing change of employment and change in control benefits to senior executives eliminates, or at least reduces, any reluctance of senior management to pursue potential change in control transactions that may be in the best interests of shareholders. In addition, the income security provided by the competitive change in control arrangements helps eliminate any distraction caused by uncertain personal financial circumstances during the negotiations of a potential change in control transaction, a period during which the Company will require focused and thoughtful leadership to ensure a successful outcome.

Deductibility of Executive Compensation

Section 162(m) of the Tax Code places a limit of $1,000,000 on the amount of compensation the Company may deduct for federal income tax purposes in any one year with respect to the Company's Chief Executive Officer and the next three most highly compensated officers (other than the Chief Financial Officer). However, performance-based compensation that meets certain requirements is excluded from this $1,000,000 limitation.

In reviewing the effectiveness of the executive compensation program, the Compensation Committee considers the anticipated tax treatment to the Company and to the named executive officers of various payments and benefits. However, the deductibility of certain compensation payments depends upon the timing of payments under long-term incentive awards, as well as interpretations and changes in the tax laws and other factors beyond the Compensation Committee's control. For these and other reasons, including to maintain flexibility in compensating the named executive officers in a manner designed to promote varying corporate goals, the Committee will not necessarily, or in all circumstances, limit executive compensation to that which is deductible under Section 162(m) of the Tax Code and has not adopted a policy requiring all compensation to be deductible. In addition, base salaries and bonuses paid to the Company's named executive officers do not comply with the performance-based compensation exclusion under Section 162(m) of the Tax Code and are subject to the $1,000,000 limitation on deductibility.

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The Compensation Committee will consider various alternatives to preserving the deductibility of compensation payments and benefits to the extent reasonably practicable and to the extent consistent with its other compensation objectives.

Summary Compensation Table

The following table summarizes, with respect to the named executive officers, information relating to the compensation earned for services rendered in all capacities during fiscal years 2013, 2012 and 2011. Columns (e), (f) and (h) have been deleted from the SEC-prescribed tabular format because the Company (1) no longer grants stock options (2) does not grant stock awards, and (3) does not sponsor a pension plan.

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SUMMARY COMPENSATION TABLE

Name and Principal Position		Salary ($)		Bonus ($)		Non-Equity Incentive Plan Compensation ($)(1)		All Other Compensation ($)(2)		Total ($)

Clayton W. Williams, Jr.	2013	$	775,000	$	83,750	$	1,779,730	$	51,011	$	2,689,491
Chairman of the Board, President and	2012	$	716,667	$	31,250	$	629,689	$	54,584	$	1,432,190
Chief Executive Officer	2011	$	695,282	$	2,154,167	$	590,619	$	58,251	$	3,498,319
Mel G. Riggs	2013	$	465,000	$	274,242	$	387,106	$	44,342	$	1,170,690
Executive Vice President and	2012	$	428,974	$	162,189	$	142,527	$	43,734	$	777,424
Chief Operating Officer	2011	$	395,771	$	520,338	$	160,509	$	39,081	$	1,115,699
Michael L. Pollard	2013	$	380,833	$	195,420	$	205,120	$	34,200	$	815,573
Senior Vice President—Finance and	2012	$	324,239	$	192,585	$	61,578	$	33,900	$	612,302
Chief Financial Officer	2011	$	295,769	$	112,500	$	62,281	$	33,600	$	504,150
Ronald D. Gasser	2013	$	413,333	$	163,000	$	342,261	$	23,084	$	941,678
Vice President—Engineering	2012	$	350,000	$	24,667	$	71,277	$	22,146	$	468,090
Samuel L. Lyssy, Jr.	2013	$	465,000	$	23,416	$	515,359	$	41,607	$	1,045,382
Vice President—Exploration	2012	$	416,667	$	21,741	$	262,133	$	40,996	$	741,537

(1): Amounts shown as Non-Equity Incentive Plan Compensation in the Summary Compensation Table for 2013 include compensation derived from various non-equity awards described under "—Compensation Discussion and Analysis—Long-Term Incentive Compensation—Non-Equity Awards" and, in the case of Mr. Lyssy, payments from overriding royalty interests and selected working interests granted prior to the Company's initial public offering in 1993 (identified in the table below as "Other"). See "—Supplemental Information About the APO Plan" and "—Pension Benefits and Nonqualified Deferred Compensation" below for additional information. Following is a summary of amounts earned in 2013 by source:

Source	Williams		Riggs		Pollard		Gasser		Lyssy

APO Incentive Plan	$	12,445	$	2,589	$	1,101	$	933	$	3,801
APO Reward Plan		1,767,285		351,315		195,562		341,328		490,285
APO Working Interest Grant		—		27,692		6,924		—		—
APO Working Interest Trusts		—		5,510		1,533		—		8,821
Other		—		—		—		—		12,452


	$	1,779,730	$	387,106	$	205,120	$	342,261	$	515,359

(2): This column includes compensation derived from, among other things, Company contributions to the Company's 401(k) plan and executive perquisites consisting of an auto allowance, social club dues, and personal use of charter aircraft. For more information on this compensation, see"—All Other Compensation from Summary Compensation Table" and"—Perquisites and Other Personal Benefits" below.

Narrative Disclosure to Summary Compensation Table

As a percentage of Mr. Williams' total compensation for the year ended December 31, 2013, his base salary accounted for 29%, his incentive compensation (including discretionary bonuses) accounted for 69%, and all other forms of compensation accounted for 2%. Until 2006, most of Mr. Williams' incentive compensation was paid in the form of stock options; however, no stock options have been granted to Mr. Williams since 2007. As discussed above, in 2009 the Company discontinued its equity compensation plan. The Compensation Committee currently has no intention of granting stock options to employees in the future. All stock options previously granted under the 1993 Stock Compensation Plan have been exercised.

Components of compensation as a percentage of total compensation (base salary, incentive compensation and other, respectively) for all other named executive officers for 2013 were:

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Mr. Riggs—40%, 56% and 4%; Mr. Pollard—47%, 49% and 4%; Mr. Gasser—44%, 54% and 2%; and Mr. Lyssy—44%, 52% and 4%.

Supplemental Information About the APO Plans

The following table sets forth certain information regarding all active APO Plans as of December 31, 2013.

Name				Area of Interest

APO Incentive Plan:
West Coast Energy Properties PA	2006	20	100.00	West Coast Properties—California and Texas	7.50	%
CWEI RMS/Warwink PA	2007	23	100.00	RMS/Warwink area in West Texas	5.00	%
CWEI South Louisiana VI PA	2008	34	100.00	South Louisiana	7.00	%
CWEI Andrews PA	2008	33	100.00	Specified leases in Andrews Co., TX	7.00	%
CWEI Crockett County PA	2008	33	100.00	Crockett Co., TX	7.00	%
CWEI Utah PA	2008	30	100.00	Utah	5.60	%
CWEI Sacramento Basin I PA	2008	9	100.00	California, Counties of Colusa, Sutter, Yolo, Solano and Sacramento	7.00	%
APO Reward Plan:
CWEI Amacker Tippett Reward Plan	2008	33	100.00	Amacker Tippett Area in Upton Co., TX	7.00	%
CWEI Austin Chalk Reward Plan	2008	28	100.00	Robertson, Burleson, Milam and Lee Co., TX	7.00	%
CWEI Barstow Area Reward Plan	2008	34	100.00	Ward Co., TX	7.00	%
CWEI Fuhrman-Mascho Reward Plan	2009	34	100.00	Kuykendall lease in Andrews Co., TX	7.00	%
CWEI Andrews Fee Reward Plan	2010	37	100.00	Fees leases in Andrews Co., TX	7.00	%
CWEI Austin Chalk Reward Plan II	2010	32	100.00	Robertson, Burleson, Milam and Lee Co., TX (excluding Eagle Ford Shale formation)	7.00	%
CWEI Andrews Samson Reward Plan	2010	37	100.00	Samson leases in Andrews Co., TX	7.00	%
CWEI Andrews Fee Reward Plan II	2011	38	100.00	Fees leases in Andrews Co., TX	10.00	%
CWEI Andrews Samson Reward Plan II	2011	38	100.00	Samson leases in Andrews Co., TX	10.00	%
CWEI Austin Chalk Reward Plan III	2011	33	100.00	Robertson, Burleson, Milam and Lee Co., TX (excluding Eagle Ford Shale formation)	10.00	%
CWEI Andrews University Reward Plan	2011	38	100.00	University leases in Andrews Co., TX	10.00	%
CWEI South Louisiana Reward Plan	2011	34	100.00	Specified leases in South Louisiana	10.00	%
CWEI Delaware Basin Reward Plan	2011	40	100.00	Specified leases in Delaware Basin	10.00	%
CWEI Oklahoma 3D Phase 1 Reward Plan	2013	32	100.00	Slick and Wilzetta, OK	10.00	%
CWEI Oklahoma 3D Phase 2 Reward Plan	2013	32	100.00	Shawnee and Shark, OK	10.00	%
CWEI Eagle Ford I Reward Plan	2013	30	100.00	Robertson, Burleson, Milam, Lee, Brazos and Wilson Co., TX (limited to Eagle Ford Shale formation)	10.00	%
CWEI East Permian Reward Plan	2013	30	100.00	Glasscock and Sterling Co., TX	10.00	%

(1): Ownership interests in participation agreements, which are usually stated in percentages, have been converted to equivalent units on the basis of 1% equals 1 unit.

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The following table sets forth the number of units awarded to named executive officers under each active APO Plan as of December 31, 2013. Each unit represents 1% of the working interest assigned with respect to each plan.

	Units Awarded to Named Executive Officers

Name	Clayton W. Williams, Jr.		Mel G. Riggs		Michael L. Pollard		Ronald D. Gasser(3)		Samuel L. Lyssy, Jr.(3)
APO Incentive Plan(1):
West Coast Energy Properties PA		—		20.00		2.50		3.00		—
CWEI RMS/Warwink PA		—		15.00		2.75		5.75		5.00
CWEI South Louisiana VI PA		28.57		3.57		2.14		2.86		1.43
CWEI Andrews PA		28.57		5.18		2.25		2.14		6.43
CWEI Crockett County PA		28.57		5.18		2.25		2.14		6.43
CWEI Utah PA		28.57		3.57		3.57		2.14		14.29
CWEI Sacramento Basin I PA		28.57		25.73		3.57		—		—
APO Reward Plan(2):
CWEI Amacker Tippett Reward Plan		28.57		7.14		2.25		3.57		6.43
CWEI Austin Chalk Reward Plan		28.57		3.57		2.25		2.86		13.57
CWEI Barstow Area Reward Plan		28.57		5.36		2.25		2.86		6.43
CWEI Fuhrman-Mascho Reward Plan		28.57		5.00		2.25		4.29		2.86
CWEI Andrews Fee Reward Plan		28.57		5.36		2.32		3.57		6.43
CWEI Austin Chalk Reward Plan II		28.57		4.29		2.32		3.93		8.93
CWEI Andrews Samson Reward Plan		28.57		5.36		2.32		5.71		6.43
CWEI Andrews Fee Reward Plan II		25.00		6.56		4.31		4.13		5.81
CWEI Andrews Samson Reward Plan II		25.00		6.45		4.20		7.50		5.70
CWEI Austin Chalk Reward Plan III		25.00		5.25		3.00		4.13		9.38
CWEI Andrews University Reward Plan		25.00		6.56		4.31		4.31		5.81
CWEI South Louisiana Reward Plan		25.00		3.75		3.00		3.00		1.50
CWEI Delaware Basin Reward Plan		25.00		5.81		3.56		4.50		7.50
CWEI Oklahoma 3D Phase 1 Reward Plan		25.00		4.20		3.30		1.50		1.50
CWEI Oklahoma 3D Phase 2 Reward Plan		25.00		4.20		3.30		1.50		1.50
CWEI Eagle Ford I Reward Plan		25.00		6.30		4.20		5.81		9.19
CWEI East Permian Reward Plan		25.00		6.81		4.44		6.38		7.67

(1): Under the terms of the APO Incentive Plan, units are fully vested when awarded.
(2): Awards under the APO Reward Plan become 100% vested on the following dates: (a) May 1, 2015, with respect to the CWEI Oklahoma 3D Phase 1 Reward Plan and the CWEI Oklahoma 3D Phase 2 Reward Plan; and (b) August 1, 2015, with respect to the CWEI Eagle Ford I Reward Plan and the CWEI East Permian Reward Plan. Awards will be forfeited upon any termination by the Company for cause or resignation without good reason prior to such vesting date. "Cause" and "good reason" are defined below under "—Potential Payments Upon Termination or Change in Control." All other APO Reward Plans were fully vested as of December 31, 2013.
(3): Messrs. Gasser and Lyssy became executive officers in 2012.

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The following table sets forth estimated future payouts to named executive officers under the APO Plans, as well as other non-equity award plans.

Name	Estimated Future Payouts to Named Executive Officers ($)(1)

Clayton W. Williams, Jr.	$	8,856,874
Mel G. Riggs	$	2,288,142
Michael L. Pollard	$	1,207,069
Ronald D. Gasser	$	1,626,919
Samuel L. Lyssy, Jr.	$	3,021,967

(1): Estimated future payouts have been computed based on the future net revenues from proved oil and gas reserves attributable to interests held by the named executive officers at December 31, 2013. These reserve estimates were made using guidelines established by the SEC, except that the estimated future net revenues are derived using a five-year NYMEX forward curve pricing model and the resulting cash flows are undiscounted. The prices used in this case averaged $85.70 per barrel of oil, $47.13 per barrel of NGL and $4.16 per Mcf of natural gas. Because of the uncertainties inherent in estimating quantities of proved reserves and future product prices and costs, it is not possible to predict estimated future payouts with any degree of certainty.

All Other Compensation from Summary Compensation Table

The following table contains a breakdown of the compensation and benefits included under the "All Other Compensation" column in the Summary Compensation Table for 2013.

ALL OTHER COMPENSATION

Name	Perquisites and Other Personal Benefits ($)(1)		Company Contributions to Retirement and 401(k) Plans ($)(2)		Total ($)

Clayton W. Williams, Jr.	$	35,711	$	15,300	$	51,011
Mel G. Riggs	$	29,042	$	15,300	$	44,342
Michael L. Pollard	$	18,900	$	15,300	$	34,200
Ronald D. Gasser	$	7,784	$	15,300	$	23,084
Samuel L. Lyssy, Jr.	$	26,307	$	15,300	$	41,607

(1): See "—Perquisites and Other Personal Benefits" below for further detail on these amounts.
(2): Constitutes a matching contribution equal to 100% of a participant's deferrals up to 6% of the participant's compensation for purposes of the Company's 401(k) plan.

Perquisites and Other Personal Benefits

The following table contains a breakdown of the perquisites and other personal benefits included in the "All Other Compensation" supplemental table above for 2013.

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PERQUISITES AND OTHER PERSONAL BENEFITS

Name	Automobile Allowance ($)		Personal Use of Charter Aircraft ($)(1)		Social Club Dues ($)		Total Perquisites and Other Personal Benefits ($)

Clayton W. Williams, Jr.	$	18,900	$	2,068	$	14,743	$	35,711
Mel G. Riggs	$	18,900	$	—	$	10,142	$	29,042
Michael L. Pollard	$	18,900	$	—	$	—	$	18,900
Ronald D. Gasser	$	—	$	—	$	7,784	$	7,784
Samuel L. Lyssy, Jr.	$	18,900	$	—	$	7,407	$	26,307

(1): The personal use of charter aircraft is measured by the incremental cost to the Company based on the personal portion of flight hours associated with any charter flight that is predominately used for a business purpose. Incremental costs include aggregate variable (rather than fixed) costs associated with the personal portion of the flight hours, including fuel costs, landing fees, catering charges, pilot overnight expenses and other similar charges incurred by the Company. Generally, the Company does not provide any officer with the use of charter aircraft for trips that are not primarily related to Company business.

Grants of Plan-Based Awards

	Non-Equity Incentive Plan Awards (Units)(1)

Name	Eagle Ford I Reward Plan		East Permian Reward Plan		Oklahoma 3D Phase 1 Reward Plan		Oklahoma 3D Phase 2 Reward Plan
Clayton W. Williams, Jr.		25.00		25.00		25.00		25.00
Mel G. Riggs		6.30		6.81		4.20		4.20
Michael L. Pollard		4.20		4.44		3.30		3.30
Ronald D. Gasser		5.81		6.38		1.50		1.50
Samuel L. Lyssy, Jr.		9.19		7.67		1.50		1.50

(1): As indicated above, 100 units were conveyed to employees pursuant to each of the above APO Reward Plans. The 100 units each represent 10% of the working interest in the specified area.

Outstanding Equity Awards at Fiscal Year-End, Option Exercises and Stock Vested

None of the named executive officers held any vested or unvested equity awards as of December 31, 2013 or at any time during 2013.

Pension Benefits and Nonqualified Deferred Compensation

The Company does not sponsor or maintain either a defined benefit pension plan or a traditional nonqualified deferred compensation plan for the benefit of the Company's employees.

Potential Payments Upon Termination or Change in Control

The Company has entered into employment agreements with each of the named executive officers. Under the agreements, the Company is required to provide compensation to these officers in the event the executive's employment is terminated under certain circumstances. The agreements provide the named executive officers with minimum base salaries and certain other compensation and benefits. Under the agreements, the minimum base salary of each named executive officer is automatically

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increased by the amount of any increases in base salary approved by the Compensation Committee. The employment agreements are effective for an initial term of three years, and will be automatically extended for an additional one year period on the third anniversary date of the effective date of the agreement (and on the fourth and fifth anniversary dates of the effective date), unless, at least 90 days prior to any such anniversary date, either party gives notice of non-renewal.

If a named executive officer becomes disabled or dies, the agreements provide for a lump sum payment of 18 months of base salary, payable within 90 days of termination or by March 15 of the year following termination, if earlier, and 12 months of continued health benefits. If a named executive officer's employment is terminated by the Company without cause or by the executive for good reason, or if the Company gives a notice of non-renewal to the executive, the executive will receive a lump sum payment equal to either 200% (for Messrs. Williams, Riggs and Pollard) or 150% (for Messrs. Gasser and Lyssy) of his annualized compensation, consisting of base salary, average bonus for the most recent three years, automobile allowance, and 401(k) matching contributions, payable within 90 days of termination or by March 15 of the year following termination, if earlier, plus 18 months of continued health benefits. If a named executive officer's employment is terminated by the Company without cause or by the executive for good reason, or if the Company gives notice of non-renewal to the executive, in each case, within 24 months from a change in control, the executive will receive a lump sum payment equal to either 300% (for Messrs. Williams, Riggs and Pollard) or 200% (for Messrs. Gasser and Lyssy) of his annualized compensation, consisting of base salary, average bonus for the most recent three years, automobile allowance, and 401(k) matching contributions, payable within 90 days of termination or by March 15 of the year following termination, if earlier, plus 18 months of continued health benefits. The named executive officers are also entitled to accelerated vesting of equity and non-equity incentive awards (except that awards under the APO Incentive Plan are still subject to forfeiture in the event of fraud against the Company by a participant) if they are terminated due to death or disability, or by the Company without cause, by the executive for good reason, or pursuant to a non-renewal notice given by the Company (including such a termination occurring within 24 months of a change in control).

For purposes of the employment agreements, the terms listed below have been given the following meanings:

(a) "cause" means the executive (1) has been convicted of a misdemeanor involving intentionally dishonest behavior or that the Company determines will have a material adverse effect on the Company's reputation or any felony, (2) has engaged in conduct that is materially injurious to the Company or its affiliates, (3) has engaged in gross negligence or willful misconduct in performing his duties, (4) has willfully refused without proper legal reason to perform his duties, (5) has breached a material provision of the employment agreement or another agreement with the Company, or (6) has breached a material corporate policy of the Company. If any act described in clause (4), (5) or (6) could be cured, the Company will give the executive written notice of such act and will give the executive 10 days to cure.

(b) "change in control" encompasses certain events including (1) a change in the majority of the board of directors serving on the board as of July 20, 2005 unless such change was authorized by a majority of the directors in place on that date (or approved by the majority of the directors in place on that date), (2) a third party, including a group of third parties acting together, acquires more than 35%, and Mr. Williams, his affiliates and certain other related persons own less than 25%, of the total voting power of Company's voting stock, (3) the sale of all or substantially all of the Company's assets, and (4) the adoption of a plan or a proposal for the liquidation or dissolution of the Company. Except in the case of Mr. Williams' employment agreement, "change in control" also includes the resignation or removal for any reason of Mr. Williams as the Company's Chairman of the Board and Chief Executive Officer, including by reason of the death or disability of Mr. Williams.

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(c) "disability" means disability (as defined in a long-term disability plan sponsored by the Company) for purposes of determining a participant's eligibility for benefits and, if multiple definitions exist, will refer to the definition of disability that would, if the participant so qualified, provide coverage for the longest period of time. If the executive is not covered by a long-term disability plan sponsored by the Company, "disability" will mean a "permanent and total disability" as defined in section 22(e)(3) of the Internal Revenue Code, as certified by a physician acceptable to both the Company and the executive.

(d) "good reason" means, without the express written consent of the executive, (1) a material breach by the Company of the employment agreement, (2) a material reduction in the executive's base salary, (3) a material diminution in the executive's authority, duties or responsibilities or the assignment of duties to the executive that are not materially commensurate with the executive's position, or (4) a material change in the geographic location at which the executive must normally perform services. The executive must give the Company notice of any alleged good reason event within 60 days and the Company shall have 30 days to remedy such event.

The employment agreements contain confidentiality provisions, as well as covenants not to compete, during the employment term and continuing until the first anniversary of the date of termination, and not to solicit, during the employment term and continuing until the second anniversary of the date of termination, subject to some limited exceptions. The non-competition covenant does not apply if an executive is terminated for cause by the Company or voluntarily without good reason by the executive, unless the Company continues to pay the executive his base salary for a period of 12 months. Mr. Williams' non-competition and non-solicitation obligations are governed by the Consolidation Agreement entered into with Mr. Williams and certain Williams Entities in May 1993. Termination of any of the named executive officers' employment due to a breach of one of these provisions would constitute a termination for cause. The employment agreements do not prohibit the waiver of a breach of these covenants. In addition, the employment agreements also condition payment of severance payments and health care continuation coverage upon the named executive officer's execution of a release within forty-five days of termination of employment (and nonrevocation thereafter).

The following table quantifies compensation and/or other benefits that would become payable under the employment agreements and other arrangements if the employment of each named executive officer had terminated on December 31, 2013, and/or in the event the Company were to undergo a

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change in control on December 31, 2013. Due to the number of factors that affect the amount of any benefits provided upon the events discussed below, actual amounts paid or distributed may be different.

Name	Salary		Bonus		Auto Allowance		401(k) Match		Continuation of Health Benefits(1)		Long-Term Incentive Plans(2)		Total

Death or disability:
Clayton W. Williams, Jr.	$	1,215,000	$	—	$	—	$	—	$	22,272	$	4,418,907	$	5,656,179
Mel G. Riggs	$	729,000	$	—	$	—	$	—	$	22,272	$	1,113,912	$	1,865,184
Michael L. Pollard	$	636,000	$	—	$	—	$	—	$	22,272	$	743,322	$	1,401,594
Ronald D. Gasser	$	648,000	$	—	$	—	$	—	$	22,272	$	1,013,670	$	1,683,942
Samuel L. Lyssy, Jr.	$	729,000	$	—	$	—	$	—	$	22,272	$	1,523,070	$	2,274,342
Termination by the Company without cause, by the executive for good reason, or due to non-renewal by the Company:
Clayton W. Williams, Jr.	$	1,620,000	$	1,512,778	$	37,800	$	30,600	$	33,408	$	4,418,907	$	7,653,493
Mel G. Riggs	$	972,000	$	637,846	$	37,800	$	30,600	$	33,408	$	1,113,912	$	2,825,566
Michael L. Pollard	$	848,000	$	333,670	$	37,800	$	30,600	$	33,408	$	743,322	$	2,026,800
Ronald D. Gasser	$	648,000	$	111,333	$	—	$	22,950	$	33,408	$	1,013,670	$	1,829,361
Samuel L. Lyssy, Jr.	$	729,000	$	36,246	$	28,350	$	22,950	$	33,408	$	1,523,070	$	2,373,024
Termination associated with a change in control:
Clayton W. Williams, Jr.	$	2,430,000	$	2,269,167	$	56,700	$	45,900	$	33,408	$	4,418,907	$	9,254,082
Mel G. Riggs	$	1,458,000	$	956,769	$	56,700	$	45,900	$	33,408	$	1,113,912	$	3,664,689
Michael L. Pollard	$	1,272,000	$	500,505	$	56,700	$	45,900	$	33,408	$	743,322	$	2,651,835
Ronald D. Gasser	$	864,000	$	148,444	$	—	$	30,600	$	33,408	$	1,013,670	$	2,090,122
Samuel L. Lyssy, Jr.	$	972,000	$	48,327	$	37,800	$	30,600	$	33,408	$	1,523,070	$	2,645,205

(1): Represents an amount equal to the monthly premium payable pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (i.e., COBRA) for group health plan continuation multiplied by (a) twelve (in the event of a termination due to death or disability) or (b) eighteen (in the event of a termination by the Company without cause, by the executive for good reason, due to non-renewal by the Company, or associated with a change in control).
(2): This column represents estimated future payments from non-equity incentive plans which would become fully vested upon each specified termination event, specifically awards under the APO Reward Plan. As indicated above, all awards granted pursuant to the APO Incentive Plan, the SWR Reward Plan, the APO Working Interest Grant and the APO Working Interest Trust are already 100% vested. Estimated future payouts have been computed based on the future net revenues from proved oil and gas reserves attributable to the interests held by the named executive officers at December 31, 2013. These reserve estimates were made using guidelines established by the SEC, except that the estimated future net revenues are derived using a five-year NYMEX forward curve pricing model and the resulting cash flows are undiscounted. The prices used in this case averaged $85.70 per barrel of oil, $47.13 per barrel of NGL and $4.16 per Mcf of natural gas. Because of the uncertainties inherent in estimating quantities of proved reserves and future product prices and costs, it is not possible to predict estimated future payouts with any degree of certainty.

Director Compensation

Retainer and Fees

During 2013, compensation for non-employee directors consisted of an annual retainer fee of $45,000 plus a $7,500 fee for each Board meeting attended and a $1,000 fee for attending a committee meeting held on a day other than the same day of a Board meeting. The chairmen of the Audit,

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Compensation and Nominating and Governance Committees each receive additional retainers of $15,000, $10,000 and $8,500 respectively.

Compensation for non-employee directors is reviewed annually by the Compensation Committee.

Stock Option Awards

Prior to 2009, the Company has sponsored an Outside Directors Stock Option Plan in which only outside directors who are not employed by the Company or any of its affiliates were eligible to participate. In December 2009, the Board amended the plan to reduce the number of shares available for grant to zero, leaving only a sufficient number of authorized shares to cover outstanding grants, which totaled 5,000 shares at December 31, 2013.

Director Compensation Table

The table below summarizes the compensation paid to the Company's non-employee directors for the fiscal year ended December 31, 2013. Columns (c) through (g) have been deleted from the SEC-prescribed tabular format because the Company did not provide compensation to its directors in 2013 other than fees.

DIRECTOR COMPENSATION TABLE

Name	Fees Earned or Paid in Cash ($)		Total ($)

Ted Gray, Jr.	$	87,000	$	87,000
Davis L. Ford	$	77,000	$	77,000
Robert L. Parker	$	92,000	$	92,000
Jordan R. Smith	$	85,500	$	85,500

Narrative Disclosure of Compensation Policies and Practices as they Relate to Risk Management

In accordance with the requirements of Regulation S-K, Item 402(s), to the extent that risks may arise from the Company's compensation policies and practices that are reasonably likely to have a material adverse effect on the Company, we are required to discuss those policies and practices for compensating the employees of the Company (including employees that are not named executive officers) as they relate to the Company's risk management practices and the possibility of incentivizing risk-taking. The Company has determined that the compensation policies and practices established with respect to the Company's employees are not reasonably likely to have a material adverse effect on the Company and, therefore, no such disclosure is necessary. The Compensation Committee and the Board are aware of the need to routinely assess the Company's compensation policies and practices and will make a determination as to the necessity of this particular disclosure on an annual basis.

Corporate Governance

Role of the Board

The business and affairs of the Company are managed under the direction of the Board. The Board has responsibility for establishing broad corporate policies and for overall performance and direction of the Company. Members of the Board stay informed of the Company's business by participating in Board and committee meetings, by reviewing analyses and reports sent to them regularly, and through discussions with the Chief Executive Officer and other officers.

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Board Structure

The Board is composed of three classes of members. One class of directors is elected each year to hold office for a three-year term and until successors of such class are duly elected and qualified. The Board currently consists of six directors and it currently has one vacancy on the Board. The directors serving on the Board for 2013 were Clayton W. Williams, Jr., Mel G. Riggs, Davis L. Ford, Robert L. Parker, Jordan R. Smith, and Ted Gray, Jr.

Board Leadership Structure; Role in Risk Oversight

Clayton W. Williams, Jr. serves as the Chairman of the Board and Chief Executive Officer. Mr. Williams is the founder of the Company and is the Company's largest shareholder. As he has done since founding the Company in 1991, Mr. Williams actively participates in all facets of the business and has a significant impact on both business strategy and daily operations. It is Mr. Williams' view that a controlling shareholder who is active in the business should serve as both Chairman of the Board and Chief Executive Officer. The Board concurs in this view and has not directed that these roles be separated or that the Board name a lead independent director.

The full Board is responsible for general oversight of risks inherent in the business. Each quarter, the Board receives reports from Mr. Williams and other members of senior management that help the Board assess the risks the Company faces in the conduct of the business. Members of the Company's senior technical staff frequently make presentations to the Board about current and planned exploration and development activities that may subject the Company to operational and financial risks. Also, the Audit Committee reviews at least annually with consultants and independent accountants the effectiveness of internal controls over financial reporting, which controls are designed to address risks specific to financial reporting.

Director Independence

A majority of the directors serving on the Board qualify as independent directors under regulations of the SEC, and under the corporate governance listing standards of the NYSE, and also qualify as "outside directors" for purposes of Section 162(m) of the Internal Revenue Code, referred to as the Tax Code. In determining independence, each year the Audit Committee affirmatively determines, among other things, whether the directors have any relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director pursuant to federal securities laws and the NYSE corporate governance listing standards. When determining if such a relationship exists, the Audit Committee considers all relevant facts and circumstances, not merely from the director's standpoint, but from that of the persons or organizations with which the director has an affiliation, and, if applicable, the frequency or regularity of the services, whether the services are being carried out at arm's length in the ordinary course of business, and whether the services are being provided substantially on the same terms to the Company as those prevailing at the time from unrelated parties for comparable transactions. Such relationships can include commercial, banking, industrial, consulting, legal, accounting, charitable and familial relationships.

From time to time, Parker Drilling Company, referred to as Parker Drilling, has performed contract drilling services for the Company. Robert L. Parker is a director of the Company and also holds the title of Chairman Emeritus of Parker Drilling. Mr. Parker's son, Robert L. Parker, Jr., is the Executive Chairman of Parker Drilling. Parker Drilling Company did not perform any contract drilling services for the Company in 2013, 2012 or 2011. The Audit Committee determined that the relationships between Mr. Parker and his son and with Parker Drilling would not interfere with Mr. Parker's exercise of independent judgment in carrying out the responsibilities of a director of the Company.

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Additionally, Ted Gray, Jr. manages a portion of the investment assets of Mr. and Mrs. Williams. The Board determined that the relationship between Mr. Gray and Mr. and Mrs. Williams would not interfere with Mr. Gray's exercise of independent judgment in carrying out the responsibilities of a director of the Company. Applying the independence standards described above, the Audit Committee has determined that Messrs. Gray, Ford, Parker and Smith are all independent directors.

Financial Code of Ethics

The Company has adopted a Financial Code of Ethics that contains the ethical principles by which the Chief Executive Officer, Chief Financial Officer (or other principal financial officer), Vice President—Accounting or Chief Accounting Officer (or other principal accounting officer) and other senior financial officers, collectively referred to as the Senior Officers, are expected to conduct themselves when carrying out their duties and responsibilities. Senior Officers must also comply with the Company's other ethics policies, including any amendments or supplements thereto, including the Company's Code of Conduct and Ethics. The Financial Code of Ethics is designed to deter wrongdoing and to promote, among other things: honest and ethical conduct, ethical handling of actual or apparent conflicts of interest; full, fair, accurate and timely disclosure in filings with the SEC and in other public disclosures; compliance with applicable law; and prompt internal reporting of violations of the Financial Code of Ethics.

The Financial Code of Ethics is available on the Company's website atwww.claytonwilliams.com under "Investor Relations/Governance/Documentation." The Company will provide the Financial Code of Ethics in print, free of charge, to shareholders who request it. Any waiver of the Financial Code of Ethics with respect to executive officers or directors may be made only by the Board or a Board committee and will be promptly disclosed to shareholders on the Company's website, as will any amendments to the Financial Code of Ethics.

Communications with the Board

Communications by shareholders or by other parties may be sent to the Board by mail or overnight delivery and should be addressed to the Board c/o Secretary, Clayton Williams Energy, Inc., Six Desta Drive, Suite 6500, Midland, Texas 79705. Communications directed to the Board, or one or more Board members, will be forwarded directly to the designated member or members and may be made anonymously.

Identification of Director Candidates

The Company's Nominating and Governance Committee identifies and reviews director candidates to determine whether they qualify for and should be considered for membership on the Board. If any vacancies on the Board arise, the Nominating and Governance Committee may consider potential candidates that come to the attention of the Committee through current members of the Board, management of the Company, shareholders or other persons. Candidates for nomination to the Board, whether recommended to the Nominating and Governance Committee by other members of the Board, management, shareholders or otherwise, are evaluated with the intention of achieving a balance of knowledge, experience and capability on the Board and in light of the membership criteria established by the Nominating and Governance Committee which are as follows:

•: High professional and personal ethics and values;
•: Broad experience in management, policy-making and/or finance;
•: Commitment to enhancing shareholder value and to representing the interests of shareholders;
•: Sufficient time to carry out their duties; and

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•: Experience adequate to provide insight and practical wisdom.

The Board does not have a policy regarding the consideration of diversity in identifying nominees for election as directors. The Nominating and Governance Committee seeks to identify individuals who meet the criteria listed above.

Consideration of Director Nominees

The policy of the Nominating and Governance Committee is to consider properly submitted shareholder nominations for candidates for Board membership as described above. Any shareholder nominations proposed for consideration by the Nominating and Governance Committee should include the nominee's name and qualifications for Board membership and should be addressed to: Secretary, Clayton Williams Energy, Inc., Six Desta Drive, Suite 6500, Midland, Texas 79705.

2013 Board Meetings and Annual Meeting

The Board met four times in 2013 and took action by unanimous written consent one time. Each of the directors attended 100% of the meetings in 2013 except Dr. Ford who attended 75% of the meetings. Each of the directors attended 100% of the meetings of the committees of the Board on which he served, except that Mr. Gray attended 86% and 80% of Compensation Committee and Audit Committee meetings respectively, and Dr. Ford attended 50% of Nominating and Governance Committee meetings. All directors, except for Mr. Gray and Dr. Ford, attended the 2013 annual meeting of shareholders. The Company encourages all Board members to attend its annual meeting.

Board Committees

The Board has three standing committees: Compensation, Nominating and Governance, and Audit. The Audit Committee of the Board has determined that each member of these committees is independent consistent with federal securities laws and the NYSE corporate governance listing standards.

Compensation Committee

The Compensation Committee held six meetings during 2013 and took action by unanimous written consent twice. Directors Gray (Chairman), Ford, Parker and Smith currently serve on the Compensation Committee. The purposes of the Compensation Committee are:

•: To review, evaluate, and approve the agreements, plans, policies and programs of the Company to compensate its officers;
•: To review the Compensation Discussion and Analysis prepared by management and proposed for inclusion in the Company's Proxy Statement for its annual meeting of shareholders and to determine whether to recommend to the Board that the Compensation Discussion and Analysis be included in such proxy statement;
•: To provide assistance to the Board in discharging its responsibilities relating to the compensation of the Chief Executive Officer and other executive officers of the Company; and
•: To perform such other functions as the Board may assign to the Committee from time to time.

The specific responsibilities of the Compensation Committee are identified in the Compensation Committee's charter, which is available on the Company's website atwww.claytonwilliams.com under "Investor Relations/ Governance/Documentation."

Pursuant to its charter, the Compensation Committee may appoint subcommittees for any purpose that the Compensation Committee deems appropriate and delegate to these subcommittees any power

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and authority the Compensation Committee deems appropriate. Historically the Compensation Committee has not delegated any of its powers and authority and, at this time, the Compensation Committee does not intend to delegate its powers and authority to any subcommittee.

Agendas for meetings of the Compensation Committee are generally prepared by the Company's Chief Executive Officer and Chief Operating Officer, in consultation with the Chairman of the Compensation Committee. Compensation Committee meetings are regularly attended by several of the Company's officers, including the Chairman of the Board, President and Chief Executive Officer, the Executive Vice President and Chief Operating Officer, and the Senior Vice President—Finance and Chief Financial Officer. The Compensation Committee also regularly meets in executive session without the Company's officers. The Compensation Committee has the authority to secure the services of independent consultants and advisors and the Company's legal, accounting and human resources departments to support the Compensation Committee in fulfilling its responsibilities. The Compensation Committee has authority under its Charter to retain, approve fees for, and terminate independent consultants and advisors as it deems necessary to assist in the fulfillment of its responsibilities. As described in more detail under "Executive Compensation—Compensation Discussion and Analysis—Setting Executive Compensation—Use of Independent Consultants," the Compensation Committee engaged Longnecker and Associates, or L&A, to conduct a market compensation analysis and to provide recommendations regarding the total direct compensation packages of the Company's named executive officers. The Compensation Committee assessed the independence of L&A pursuant to the SEC rules, and the findings of the Compensation Committee as to L&A's independence are described in more detail under "Executive Compensation—Compensation Discussion and Analysis—Setting Executive Compensation—Use of Independent Consultants." A detailed description of the processes and procedures of the Compensation Committee for the consideration and determination of executive and director compensation can be found under "Executive Compensation—Compensation Discussion and Analysis."

None of the individuals serving on the Compensation Committee has ever been an officer or employee of the Company. The Audit Committee has determined that all of the members of the Compensation Committee satisfy the independence requirements of federal securities laws and the NYSE corporate governance listing standards. Additionally, all of the members of the Compensation Committee qualify as "non-employee directors" for purposes of SEC requirements, and as "outside directors" for purposes of Section 162(m) of the Tax Code.

Nominating and Governance Committee

The Nominating and Governance Committee met two times in 2013. Directors Smith (Chairman), Ford, Gray and Parker currently serve on the Nominating and Governance Committee. The purposes of the Nominating and Governance Committee are:

•: To identify individuals qualified to become Board members, and to select the director nominees for election at the annual meetings of shareholders or for appointment to fill vacancies;
•: To recommend to the Board director nominees for each committee of the Board;
•: To advise the Board about appropriate composition of the Board and its committees;
•: To advise the Board about and recommend to the Board appropriate corporate governance practices and to assist the Board in implementing those practices;
•: To lead the Board in its annual review of the performance of the Board and its committees; and
•: To perform such other functions as the Board may assign to the Committee from time to time.

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The specific responsibilities of the Nominating and Governance Committee are identified in the Nominating and Governance Committee's charter, which is available on the Company's website atwww.claytonwilliams.com under "Investor Relations/Governance/Documentation."

Audit Committee

The Audit Committee held five meetings during 2013 and took action by unanimous written consent one time. Directors Parker (Chairman), Ford, Gray, and Smith currently serve on the Audit Committee. Each of the members of the Audit Committee qualifies as an independent director under the federal securities laws and the NYSE corporate governance listing standards. The Board has determined that no member of the Audit Committee meets all of the criteria needed to qualify as an "audit committee financial expert" as defined by SEC regulations. The Board believes that each of the current members of the Audit Committee has sufficient knowledge and experience in financial matters to perform his duties on the Audit Committee. In addition, the Audit Committee has engaged, at the Company's expense, Davis Kinard & Co., certified public accountants, as a financial accounting consultant to independently advise the Audit Committee in the area of technical accounting issues and to assist the Audit Committee in fully understanding any matters that may come before the Audit Committee, including matters related to:

•: Generally accepted accounting principles and the application of such principles in connection with accounting for estimates, accruals and reserves;
•: Internal controls and procedures for financial reporting; and
•: Other Audit Committee functions.

The specific responsibilities of the Audit Committee are identified in the Audit Committee's charter, which is available on the Company's website atwww.claytonwilliams.com under "Investor Relations/Governance/ Documentation." The Audit Committee serves as an independent and objective party to oversee the accounting and financial reporting practices of the Company, and the audits of its financial statements. The Audit Committee has the sole authority and responsibility with respect to the selection, engagement, compensation, oversight, evaluation and, where appropriate, dismissal of the independent auditors and any other public accounting firm engaged by the Company. The independent auditors, and any other public accounting firm engaged by the Company, report directly to the Audit Committee.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the beneficial ownership of the Company's common stock based upon 12,165,536 shares outstanding as of January 20, 2014, by:

•: Each person who is the beneficial owner of 5% or more of the outstanding common stock (based upon copies of all Schedule 13Gs and 13Ds provided to the Company);
•: Each director of the Company;
•: The named executive officers; and
•: All officers and directors of the Company as a group.

Beneficial ownership is determined in accordance with the regulations of the SEC. Under SEC regulations, persons who have power to vote or dispose of shares of common stock, either alone or jointly with others, are deemed to be beneficial owners. Because the voting or dispositive power of certain shares listed in the following table is shared, the same securities in such cases are listed opposite more than one name in the table and the sharing of voting or dispositive power is described in the referenced footnote. The total number of shares of common stock of the Company listed below for directors and executive officers as a group eliminates such duplication. Unless otherwise noted, the persons and entities named below have sole voting and investment power with respect to the shares listed opposite each of their names.

Name

The Williams Children's Partnership, Ltd.(1)	3,041,412		25.0	%
CWPLCO, Inc.(1)	1,247,488		10.3	%
Clayton W. Williams, Jr.(1)	3,109,751	(2)	25.6	%
T. Rowe Price Associates, Inc.	1,119,810	(3)	9.2	%
100 E. Pratt Street
Baltimore, MD 21202
Mel G. Riggs	3,055,917	(4)	25.1	%
Michael L. Pollard	8,093	(5)	*
Ronald D. Gasser	3,474	(6)	*
Samuel L. Lyssy, Jr.	4,393	(7)	*
Davis L. Ford	19,681		*
Robert L. Parker	29,217	(8)	*
Jordan R. Smith	400		*
Ted Gray, Jr.	—		*
All officers and directors as a group (15 persons)	6,279,683	(8)	51.6	%

*: Less than 1 percent of the shares outstanding.
(1): The mailing address of The Williams Children's Partnership, Ltd., CWPLCO, Inc. and Mr. Williams is Six Desta Drive, Suite 3000, Midland, Texas 79705. The Williams Children's Partnership, Ltd. is a family partnership comprised of Mr. Williams' five adult children. CWPLCO, Inc. is a wholly-owned subsidiary of a holding company owned 100% by Mr. Williams. Mr. Williams holds voting and investment power over the shares held by CWPLCO, Inc.
(2): Consists of (a) an aggregate of 1,247,488 shares owned by CWPLCO, Inc. and beneficially owned by Mr. Williams due to Mr. Williams' control of CWPLCO, Inc., (b) 1,771,219 shares owned by CW Stock Holdco, L.P. and beneficially owned by Mr. Williams due to Mr. Williams' control of CW Stock Holdco, L.P., (c) 11,044 shares owned by Mr. Williams' wife, (d) 588 shares owned by a trust of which Mrs. Williams is the trustee, (e) 17,063 shares held in the Company's 401(k) Plan & Trust

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over which Mr. Williams exercises investment control, (f) 49,179 shares in trusts of which Mr. Williams is the Trustee, (g) 5,749 shares in a trust for the benefit of Mr. Williams of which Mrs. Williams is the Trustee, and (h) 7,421 shares owned by Mr. Williams' grandchildren for which Mrs. Williams is custodian.

(3): Represents shares owned by clients of T. Rowe Price Associates, Inc. T. Rowe Price Associates, Inc. disclaims beneficial ownership of all such shares.
(4): Includes (a) 2,535 shares held in the Company's 401(k) Plan & Trust over which Mr. Riggs exercises investment control, (b) 1,382 shares over which Mr. Riggs exercises control under a Power of Attorney, and (c) 3,041,412 shares owned by The Williams Children's Partnership, Ltd. over which Mr. Riggs exercises investment control. Mr. Riggs is the sole member of LPL/Williams GP, LLC, which is the general partner of The Williams Children's Partnership, Ltd. Mr. Riggs has a pecuniary interest in only 0.002% of the stock held by The Williams Children's Partnership, Ltd. and disclaims beneficial ownership of the remaining 99.998% of the stock.
(5): Consists of 8,093 shares held in the Company's 401(k) Plan & Trust over which Mr. Pollard exercises investment control.
(6): Consists of 3,474 shares held in the Company's 401(k) Plan & Trust over which Mr. Gasser exercises investment control.
(7): Consists of 4,393 shares held primarily in the Company's 401(k) Plan & Trust over which Mr. Lyssy exercises investment control.
(8): Includes the rights of Mr. Parker to acquire beneficial ownership through options currently exercisable within 60 days to purchase 5,000 shares of common stock granted under the Outside Directors Stock Option Plan.

Section 16(a) Beneficial Ownership Reporting Compliance

Based solely upon a review of Forms 3, 4 and 5 and amendments thereto furnished to the Company pursuant to the rules and regulations promulgated under Section 16(a) of the Securities Exchange Act of 1934, or the Exchange Act, during and with respect to the Company's last fiscal year and upon certain written representations received by the Company, the Company believes that all filing requirements applicable to officers, directors and 10% beneficial owners under Section 16(a) were satisfied.

Certain Transactions and Relationships

The Audit Committee reviews, approves and monitors all transactions involving the Company and "related persons" (directors and executive officers or their immediate family members, or shareholders owning 5% or greater of the Company's outstanding stock) in which the amount exceeds $120,000 and in which the related person has a direct or indirect material interest. The Audit Committee will approve the transaction only if they determine that it is in the best interest of the Company. While the Audit Committee has not adopted a formal written policy for reviewing related party transactions, in considering the transaction, the Audit Committee will consider all relevant factors, including as applicable:

•: The Company's business rationale for entering into the transaction;
•: The alternatives to entering into a related party transaction;
•: Whether the transaction is on terms comparable to those available to third parties;
•: The potential for the transaction to lead to an actual or apparent conflict of interest and any safeguards imposed to prevent such actual or apparent conflicts; and

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•: The overall fairness of the transaction to the Company.

The Audit Committee will periodically monitor the transaction to ensure that there are no changed circumstances that would render it advisable for the Company to amend or terminate the transaction.

In the event a transaction arises that would require the review of the Audit Committee, management or the affected director or executive officer will bring the matter to the attention of the Chairman of the Audit Committee. If a member of the Audit Committee is involved in the transaction, he will be recused from all discussions and decisions about the transaction. Any such transaction must be approved in advance wherever practicable, and if not practicable, it must be ratified as promptly as practicable. The Audit Committee will review the transactions annually to determine whether they continue to be in the Company's best interest.

The Company and the Williams Entities are parties to an agreement, which the Company refers to as the Service Agreement, pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, the Company provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services and general accounting services to the Williams Entities, as well as technical services with respect to the operation of certain oil and gas properties owned by the Williams Entities. The Williams Entities provide business entertainment to or for the benefit of the Company. The following table summarizes the charges to and from the Williams Entities for the year ended December 31, 2013.

	2013

	(In thousands)
Amounts received from the Williams Entities:
Service Agreement:
Services	$	742
Insurance premiums and benefits		837
Reimbursed expenses		427


	$	2,006




Amounts paid to the Williams Entities:
Rent(1)	$	1,560
Service Agreement:
Business entertainment(2)		116
Reimbursed expenses		216


	$	1,892

(1): Rent amounts were paid to ClayDesta Buildings, L.P., a Texas limited partnership referred to as CDBLP, of which the Company owns 31.9% and affiliates of the Company own 25.8%. A Williams Entity provides property management services to the buildings owned and operated by CDBLP.
(2): Consists of hunting and fishing rights pertaining to land owned by affiliates of Mr. Williams.

Certain of the Company's employees and vendors are "immediate family members" (as defined under SEC regulations) of Clayton W. Williams, Jr., Chairman of the Board, President and Chief Executive Officer or Patrick C. Reesby, Vice President—New Ventures. As a result, compensation paid to such employees and payments made to such vendors may be deemed to be transactions by the Company with a related person. Following is a summary of each relationship and transaction or series of similar transactions for which the amount involved exceeded $120,000 for the year ended December 31, 2013.

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•: Gregory S. Welborn serves as Vice President—Land for the Company and is the son-in-law of Mr. Williams. For the year ended December 31, 2013, Gregory S. Welborn received compensation from the Company aggregating $696,587.
•: M. Patrick Reesby owns a fifty percent equity stake in R & O Energy, LLC., a vendor that provides contract title research and oil, gas and mineral lease acquisition services to the Company. M. Patrick Reesby is the son of Patrick C. Reesby. For the year ended December 31, 2013, R & O Energy, LLC received $524,200 from the Company in payment for services of $453,312 and reimbursed expenses of $70,888.
•: Clayton Wade Williams serves as Field Technician for the Company and is the son of Mr. Williams. For the year ended December 31, 2013, Clayton Wade Williams received $154,969 from the Company which included compensation of $146,061 and reimbursed expenses of $8,908.
•: Erin Williams is a vendor who provides contract title research and oil, gas and mineral lease acquisition services to the Company and is the daughter-in-law of Mr. Williams. For the year ended December 31, 2013, Erin Williams received $129,513 from the Company in payment for services of $106,625 and reimbursed expenses of $22,888.

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DESCRIPTION OF NOTES

The Company issued the notes under the Indenture dated March 16, 2011 (the "Indenture") among itself, the Subsidiary Guarantors and Wells Fargo Bank, National Association, as trustee (the "Trustee"). The terms of the notes include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act"). The Indenture is unlimited in aggregate principal amount. On March 16, 2011, April 26, 2011 and October 1, 2013, we issued $300 million, $50 million and $250 million, respectively, in aggregate principal amount of notes under the Indenture. References to the "Notes" in this section of this prospectus include both the existing notes and the notes offered hereby. We may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes (the "Additional Notes"). We will only be permitted to issue such Additional Notes if at the time of such issuance, we were in compliance with the covenants contained in the Indenture. Any Additional Notes will be part of the same issue as the Notes and will vote on all matters with the holders of the Notes.

This Description of Notes is intended to be a useful overview of the material provisions of the Notes and the Indenture. Since this Description of Notes is only a summary, you should refer to the Indenture for a complete description of the obligations of the Company and your rights.

You will find the definitions of capitalized terms used in this Description of Notes under the heading "Certain Definitions." For purposes of this description, references to "the Company," "we," "our" and "us" refer only to Clayton Williams Energy, Inc. and not to its subsidiaries.

General

The Notes. The Notes:

•: are general unsecured, senior obligations of the Company;
•: will mature on April 1, 2019;
•: will be issued in denominations of $2,000 and integral multiples of $1,000 in excess thereof;
•: will be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form. See "—Book-Entry, Delivery and Form;"
•: rank senior in right of payment to all existing and future subordinated Indebtedness of the Company;
•: rank equally in right of payment to any existing and future senior Indebtedness of the Company, without giving effect to collateral arrangements;
•: effectively rank junior to any existing and future secured Indebtedness of the Company, including amounts that may be borrowed under our senior revolving credit facility, to the extent of the value of the collateral securing such Indebtedness; and
•: are unconditionally guaranteed on a senior basis by all of the Company's material wholly owned Subsidiaries. See "—Subsidiary Guarantees."

Interest. Interest on the Notes will compound semi-annually and:

•: accrue at the rate of 7.75% per annum;
•: accrue from March 16, 2011 or, if interest has already been paid, from the most recent interest payment date;
•: be payable in cash semi-annually in arrears on April 1 and October 1, commencing on October 1, 2011;

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•: be payable to the holders of record on the March 15 and September 15 immediately preceding the related interest payment dates; and
•: be computed on the basis of a 360-day year comprised of twelve 30-day months.

We also will pay additional interest to holders of the Notes if we fail to complete the Exchange Offer described in the Registration Rights Agreements within specified time periods.

Payments on the Notes; Paying Agent and Registrar

We will pay principal of, premium, if any, and interest on the Notes at the office or agency designated by the Company, except that we may, at our option, pay interest on the Notes by check mailed to holders of the Notes at their registered address as it appears in the registrar's books. We have initially designated the corporate trust office of the Trustee to act as our paying agent and registrar. We may, however, change the paying agent or registrar without prior notice to the holders of the Notes, and the Company or any of its Restricted Subsidiaries may act as paying agent or registrar.

We will pay principal of, premium, if any, and interest on, Notes in global form registered in the name of or held by The Depository Trust Company or its nominee in immediately available funds to The Depository Trust Company or its nominee, as the case may be, as the registered holder of such global Note.

Transfer and Exchange

A holder may transfer or exchange Notes in accordance with the Indenture. The registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents. No service charge will be imposed by the Company, the Trustee or the registrar for any registration of transfer or exchange of Notes, but the Company may require a holder to pay a sum sufficient to cover any transfer tax or other governmental taxes and fees required by law or permitted by the Indenture. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days before the mailing of a notice of redemption of Notes to be redeemed.

The registered holder of a Note will be treated as the owner of it for all purposes.

Optional Redemption

Except as described below, the Notes are not redeemable until April 1, 2015. On and after April 1, 2015, the Company may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days' written notice, at the following redemption prices (expressed as a percentage of principal amount) plus accrued and unpaid interest on the Notes, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning on April 1 of the years indicated below:

Year

2015	103.875	%
2016	101.938	%
2017 and thereafter	100.000	%

Prior to April 1, 2014, the Company may on any one or more occasions redeem up to 35% of the original principal amount of the Notes with the Net Cash Proceeds of one or more Equity Offerings at a redemption price of 107.750% of the principal amount thereof, plus accrued and unpaid interest, if

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any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date);provided that

(1): at least 65% of the original principal amount of the Notes remains outstanding after each such redemption; and
(2): the redemption occurs within 90 days after the closing of such Equity Offering.

In addition, before April 1, 2015, the Company may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days' written notice, at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

"Applicable Premium" means, with respect to a Note at any redemption date, the greater of (i) 1.0% of the principal amount of such Note and (ii) the excess of (A) the present value at such time of (1) the redemption price, excluding accrued interest, of such Note at April 1, 2015 (such redemption price being described above) plus (2) all required interest payments, excluding accrued interest, due on such Note through April 1, 2015, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of such Note.

"Treasury Rate" means the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to April 1, 2015;provided,however, that if the period from the redemption date to April 1, 2015 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to April 1, 2015 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

If the optional redemption date is on or after an interest record date and on or before the related interest payment date, the accrued and unpaid interest, if any, will be paid to the Person in whose name the Note is registered at the close of business, on such record date, and no additional interest will be payable to holders whose Notes will be subject to redemption by the Company.

In the case of any partial redemption, selection of the Notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not listed, then on a pro rata basis, by lot or by such other method as the Trustee in its sole discretion will deem to be fair and appropriate and in accordance with the procedures of The Depository Trust Company, although no Note of $1,000 in original principal amount or less will be redeemed in part. If any Note is to be redeemed in part only, the notice of redemption relating to such Note will state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original Note.

The Company may acquire Notes by means other than a redemption, whether by tender offer, open market purchases, negotiated transactions or otherwise, in accordance with applicable securities laws, so long as such acquisition does not otherwise violate the terms of the Indenture.

The Company is not required to make mandatory redemption payments or sinking fund payments with respect to the Notes.

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Ranking

The Notes are general unsecured obligations of the Company that rank senior in right of payment to all existing and future Indebtedness that is expressly subordinated in right of payment to the Notes. The Notes rank equally in right of payment with all existing and future liabilities of the Company that are not so subordinated and will be effectively subordinated to all of our secured Indebtedness (to the extent of the value of the collateral securing such Indebtedness) and liabilities of our Subsidiaries that do not guarantee the Notes. In the event of bankruptcy, liquidation, reorganization or other winding up of the Company or its Subsidiary Guarantors or upon a default in payment with respect to, or the acceleration of, any Indebtedness under the Senior Secured Credit Agreement or other secured Indebtedness, the assets of the Company and its Subsidiary Guarantors that secure secured Indebtedness will be available to pay obligations on the Notes and the Subsidiary Guarantees only after all Indebtedness under such credit facility and other secured Indebtedness has been repaid in full from such assets. We advise you that there may not be sufficient assets remaining to pay amounts due on any or all the Notes and the Subsidiary Guarantees then outstanding.

As of September 30, 2013:

•: we and our subsidiary guarantors had $323 million in secured indebtedness outstanding under our revolving credit facility; and
•: we had total availability under our revolving credit facility of approximately $325.8 million, subject to the terms thereof.

Subsidiary Guarantees

The Subsidiary Guarantors have, jointly and severally, unconditionally guaranteed on a senior basis the Company's obligations under the Notes and all obligations under the Indenture. The obligations of Subsidiary Guarantors under the Subsidiary Guarantees rank equally in right of payment with other Indebtedness of such Subsidiary Guarantor, except to the extent such other Indebtedness is expressly subordinate to the obligations arising under the Subsidiary Guarantee.

Although the Indenture limits the amount of indebtedness that Restricted Subsidiaries may Incur, such indebtedness may be substantial.

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee are limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law.

In the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its Capital Stock or the sale of all or substantially all of its assets (other than by lease) and whether or not the Subsidiary Guarantor is the surviving corporation in such transaction) to a Person which is not the Company or a Restricted Subsidiary of the Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenant described under "—Limitation on Sales of Assets and Subsidiary Stock."

In addition, a Subsidiary Guarantor will be released from its obligations under the Indenture, its Subsidiary Guarantee and the Registration Rights Agreements if (i) the Company designates such Subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the Indenture, (ii) such Subsidiary Guarantor is dissolved or liquidated, (iii) in connection with any legal or covenant defeasance of the Notes in accordance with the terms of the Indenture, or (iv) if such Subsidiary Guarantor ceases to be a Restricted Subsidiary.

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Change of Control

If a Change of Control occurs, unless the Company has exercised its right to redeem all of the Notes as described under "Optional Redemption," each holder will have the right to require the Company to repurchase all or any part (equal to $1,000 or an integral multiple thereof) of such holder's Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Within 30 days following any Change of Control, unless the Company has exercised its right to redeem all of the Notes as described under "Optional Redemption," the Company will send a notice (the "Change of Control Offer") to each holder, with a copy to the Trustee, stating:

(1) that a Change of Control has occurred and that such holder has the right to require the Company to purchase such holder's Notes at a purchase price in cash equal to 101% of the principal amount of such Notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date) (the "Change of Control Payment");

(2) the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is sent) (the "Change of Control Payment Date"); and

(3) the procedures determined by the Company, consistent with the Indenture, that a holder must follow in order to have its Notes repurchased.

On the Change of Control Payment Date, the Company will, to the extent lawful:

(1) accept for payment all Notes or portions of Notes (in integral multiples of $1,000) properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes so tendered; and

(3) deliver or cause to be delivered to the Trustee the Notes so accepted together with an Officers' Certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by the Company.

The paying agent will promptly send to each holder of Notes so tendered the Change of Control Payment for such Notes, and the Trustee will promptly authenticate and send (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each such new Note will be in a principal amount of $1,000 or an integral multiple thereof.

If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest, if any, will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender pursuant to the Change of Control Offer.

The Change of Control provisions described above will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the holders to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

Prior to sending a Change of Control Offer, and as a condition to such sending (i) the requisite holders of each issue of Indebtedness issued under an indenture or other agreement that may be violated by such payment shall have consented to such Change of Control Offer being made and waived the event of default, if any, caused by the Change of Control or (ii) the Company will repay all

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outstanding Indebtedness issued under an indenture or other agreement that may be violated by a payment to the holders of Notes under a Change of Control Offer or (iii) the Company must offer to repay all such Indebtedness, and make payment to the holders of such Indebtedness that accept such offer, and obtain waivers of any event of default from the remaining holders of such Indebtedness. The Company covenants to effect such repayment or obtain such consent within 30 days following any Change of Control, it being a default of the Change of Control provisions if the Company fails to comply with such covenant. A default under the Indenture will result in a cross-default under the Senior Secured Credit Agreement.

The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Company and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to this covenant. To the extent that the provisions of any securities laws or regulations conflict with provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations described in the Indenture by virtue of the conflict.

The Company's ability to repurchase Notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of certain of the events that constitute a Change of Control would constitute a default under the Senior Secured Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Secured Credit Agreement and cause a default under those agreements may not constitute a Change of Control under the Indenture. Future Indebtedness of the Company and its Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Company to repurchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. Finally, the Company's ability to pay cash to the holders upon a repurchase may be limited by the Company's then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

Even if sufficient funds were otherwise available, the terms of the Senior Secured Credit Agreement will (and other Indebtedness may) prohibit the Company's prepayment of Notes before their scheduled maturity. Consequently, if the Company is not able to prepay the Indebtedness under the Senior Secured Credit Agreement and any such other Indebtedness containing similar restrictions or obtain requisite consents, as described above, the Company will be unable to fulfill its repurchase obligations if holders of Notes exercise their repurchase rights following a Change of Control, resulting in a default under the Indenture. A default under the Indenture may result in a cross-default under the Senior Secured Credit Agreement.

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Company by increasing the capital required to effectuate such transactions. The definition of "Change of Control" includes a disposition of all or substantially all of the property and assets of the Company and its Restricted Subsidiaries taken as a whole to any Person other than a Permitted Holder. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of "all or substantially all" of the property or assets of a Person.

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As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of Notes may require the Company to make an offer to repurchase the Notes as described above.

Certain Covenants

As of the date of this description of the Notes, all of the Company's Subsidiaries are "Restricted Subsidiaries" except CWEI Andrews Properties GP, LLC and its Subsidiaries, which are "Unrestricted Subsidiaries." Under the circumstances described in the definition of Unrestricted Subsidiary, the Company may be permitted to designate additional Subsidiaries as "Unrestricted Subsidiaries." Unrestricted Subsidiaries generally will not be subject to any of the restrictive covenants in the Indenture and will not guarantee the Notes.

Suspended Covenants

During any period when the Company has an Investment Grade Rating and no Default has occurred and is continuing under the Indenture (the "Covenant Suspension Period"), the Company and its Restricted Subsidiaries will not be subject to the provisions of the Indenture described below under the following headings:

•: "—Limitation on Indebtedness,"
•: "—Limitation on Restricted Payments,"
•: "—Limitation on Restrictions on Distributions from Restricted Subsidiaries,"
•: "—Limitation on Sales of Assets and Subsidiary Stock,"
•: "—Limitation on Affiliate Transactions,"
•: Clause (3) of the covenant under "—Merger and Consolidation," and
•: "—Limitation on Lines of Business"

(collectively, the "Suspended Covenants"); provided that if the Company and the Restricted Subsidiaries are not subject to the Suspended Covenants for any period of time as a result of the preceding portion of this sentence and, subsequently, either of the Rating Agencies withdraws its ratings or downgrades the ratings below the Investment Grade Ratings, or a Default (other than with respect to the Suspended Covenants) occurs and is continuing, the Issuer and the Restricted Subsidiaries will thereafter again be subject to the Suspended Covenants, subject to the terms, conditions and obligations set forth in the Indenture (each such date of reinstatement being the "Reinstatement Date"). As a result, during any Covenant Suspension Period, the Notes will be entitled to substantially reduced covenant protection. Compliance with the Suspended Covenants with respect to Restricted Payments made after the Reinstatement Date will be calculated in accordance with the terms of the covenant described under "—Limitation on Restricted Payments" as though such covenant had been in effect during the entire period of time from which the Notes are issued. However, all Restricted Payments made, Indebtedness incurred and other actions effected during any period in which covenants are suspended will not cause a default under the Indenture on any Reinstatement Date.

The Company will provide the Trustee with prompt written notice upon the commencement of a Covenant Suspension Period and of the occurrence of a Reinstatement Date. In addition, during any period when the Suspended Covenants are suspended the Company will not be permitted to designate or redesignate any of its Subsidiaries pursuant to the definition of "Unrestricted Subsidiary."

Set forth below are summaries of certain covenants that are contained in the Indenture.

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Limitation on Indebtedness

The Company will not, and will not permit any of its Restricted Subsidiaries to, Incur any Indebtedness (including Acquired Indebtedness); provided, however, that the Company and the Restricted Subsidiaries may Incur Indebtedness if on the date thereof:

(1) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.25 to 1.00; and

(2) no Default or Event of Default will have occurred and be continuing or would occur as a consequence of Incurring the Indebtedness or transactions relating to such Incurrence.

The first paragraph of this covenant will not prohibit the Incurrence of the following Indebtedness:

(1) Indebtedness of the Company or a Restricted Subsidiary Incurred pursuant to a Credit Facility in an aggregate principal amount at any time outstanding not to exceed the greater of (a) $500.0 million and (b) 30% of Adjusted Consolidated Net Tangible Assets;

(2) Guarantees by the Company or Subsidiary Guarantors of Indebtedness Incurred in accordance with the provisions of the Indenture;

(3) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any Restricted Subsidiary; provided, however,

(a) any subsequent issuance or transfer of Capital Stock or any other event which results in any such Indebtedness being beneficially held by a Person other than the Company or a Restricted Subsidiary of the Company; and

(b) any sale or other transfer of any such Indebtedness to a Person other than the Company or a Restricted Subsidiary of the Company shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Subsidiary, as the case may be.

(4) Indebtedness represented by (a) the Notes issued on the Issue Date, the Subsidiary Guarantees and the related exchange notes and exchange guarantees issued in a registered exchange offer pursuant to the Registration Rights Agreements, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (2), (3), (6), (8), (9) and (10)) outstanding on the Issue Date and (c) any Refinancing Indebtedness Incurred in respect of any Indebtedness described in this clause (4), clause (5) or clause (11) or Incurred pursuant to the first paragraph of this covenant;

(5) Permitted Acquisition Indebtedness;

(6) Indebtedness under Hedging Obligations that are Incurred in the ordinary course of business (and not for speculative purposes) (1) for the purpose of fixing or hedging interest rate risk with respect to any Indebtedness Incurred without violation of the Indenture; (2) for the purpose of fixing or hedging currency exchange rate risk with respect to any currency exchanges; or (3) for the purpose of fixing or hedging commodity price risk with respect to any commodities;

(7) the Incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capitalized Lease Obligations, mortgage financings or purchase money obligations or other Indebtedness, in each case Incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvements of property used in the business of the Company or such Restricted Subsidiary, and Attributable Indebtedness, in an aggregate principal amount not to exceed $20.0 million at any time outstanding;

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(8) Indebtedness Incurred in respect of workers' compensation claims, self-insurance obligations, performance, surety and similar bonds and completion guarantees provided by the Company or a Restricted Subsidiary in the ordinary course of business;

(9) Indebtedness arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, adjustment of purchase price or similar obligations, in each case, Incurred or assumed in connection with the disposition of any business, assets or Capital Stock of a Restricted Subsidiary,provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by the Company and its Restricted Subsidiaries in connection with such disposition;

(10) Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business,provided,however, that such Indebtedness is extinguished within five business days of Incurrence; and

(11) in addition to the items referred to in clauses (1) through (10) above, Indebtedness of the Company and its Restricted Subsidiaries in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (11) (including any Refinancing Indebtedness incurred under clause (4) above with respect to such Indebtedness) and then outstanding, will not exceed $50.0 million at any time outstanding.

For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness Incurred pursuant to and in compliance with, this covenant:

(1) in the event that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will classify such item of Indebtedness on the date of Incurrence and, subject to clause (2) below, may later classify such item of Indebtedness in any manner that complies with this covenant and only be required to include the amount and type of such Indebtedness in one of such clauses;

(2) all Indebtedness outstanding on the date of the Indenture under the Senior Secured Credit Agreement shall be deemed initially Incurred on the Issue Date under clause (1) of the second paragraph of this covenant and not the first paragraph or clause (4) of the second paragraph of this covenant;

(3) Guarantees of, or obligations in respect of letters of credit relating to, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;

(4) if obligations in respect of letters of credit are Incurred pursuant to a Credit Facility and are being treated as Incurred pursuant to clause (1) of the second paragraph above and the letters of credit relate to other Indebtedness, then such other Indebtedness shall not be included;

(5) the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, will be equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(6) Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness; and

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(7) the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the accretion of accreted value, the payment of interest in the form of additional Indebtedness and the payment of dividends in the form of additional shares of Preferred Stock or Disqualified Stock will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant.

In addition, the Company will not permit any of its Unrestricted Subsidiaries to Incur any Indebtedness other than Non-Recourse Debt. If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this "Limitation on Indebtedness" covenant, the Company shall be in Default of this covenant).

For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-dominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-dominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may Incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Indebtedness Incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

Limitation on Restricted Payments

The Company will not, and will not permit any Restricted Subsidiaries, directly or indirectly, to:

(1) declare or pay any dividend or make any distribution (whether made in cash, securities or other property) on or in respect of its Capital Stock (including any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a) dividends or distributions payable in Capital Stock of the Company (other than Disqualified Stock) or in options, warrants or other rights to purchase such Capital Stock of the Company; and

(b) dividends or distributions payable to the Company or a Restricted Subsidiary (and if such Restricted Subsidiary is not a Wholly-Owned Subsidiary, to its other holders of Capital Stock on a pro rata basis);

(2) purchase, redeem, retire or otherwise acquire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Restricted Subsidiary (other than in exchange for Capital Stock of the Company (other than Disqualified Stock));

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(3) purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations or Guarantor Subordinated Obligations (other than (x) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any other Restricted Subsidiary permitted under clause (3) of the second paragraph of the covenant "—Limitation on Indebtedness" or (y) the purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase, redemption, defeasance or other acquisition or retirement); or

(4) make any Restricted Investment in any Person;

(any such dividend, distribution, purchase, redemption, repurchase, defeasance, other acquisition, retirement or Restricted Investment referred to in clauses (1) through (4) shall be referred to herein as a "Restricted Payment"), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(a) a Default shall have occurred and be continuing (or would result therefrom); or

(b) the Company is not able to Incur an additional $1.00 of Indebtedness pursuant to the first paragraph under the "Limitation on Indebtedness" covenant after giving effect, on a pro forma basis, to such Restricted Payment; or

(c) the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to July 20, 2005 would exceed the sum of:

(i) 50% of Consolidated Net Income for the period (treated as one accounting period) from July 1, 2005 to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii) 100% of the aggregate Net Cash Proceeds and the fair market value of property or securities other than cash (including Capital Stock of Persons engaged primarily in the Oil and Gas Business or assets used in the Oil and Gas Business), in each case received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or other capital contributions subsequent July 20, 2005 (other than Net Cash Proceeds received from an issuance or sale of such Capital Stock to a Subsidiary of the Company or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination);

(iii) the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company's balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to July 20, 2005 of any Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the fair market value of any other property, distributed by the Company upon such conversion or exchange); and

(iv) the amount equal to the net reduction in Restricted Investments made by the Company or any of its Restricted Subsidiaries in any Person resulting from:

(A) repurchases or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investment to an unaffiliated purchaser, repayments of loans or advances or other transfers of assets (including by way of dividend or distribution) by such Person to the Company or any Restricted Subsidiary; or

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(B) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of "Investment") not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary,

which amount in each case under this clause (iv) was included in the calculation of the amount of Restricted Payments; provided, however, that no amount will be included under this clause (iv) to the extent it is already included in Consolidated Net Income.

The provisions of the preceding paragraph will not prohibit:

(1) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Capital Stock, Disqualified Stock or Subordinated Obligations of the Company or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary or an employee stock ownership plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination); provided, however, that (a) such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments and (b) the Net Cash Proceeds from such sale of Capital Stock will be excluded from clause (c)(ii) of the preceding paragraph;

(2) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of the Company or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Subordinated Obligations of the Company or any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Guarantor Subordinated Obligations made by exchange for or out of the proceeds of the substantially concurrent sale of Guarantor Subordinated Obligations that, in each case, is permitted to be Incurred pursuant to the covenant described under "Limitation on Indebtedness" and that in each case constitutes Refinancing Indebtedness; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(3) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Disqualified Stock of the Company or a Restricted Subsidiary made by exchange for or out of the proceeds of the substantially concurrent sale of Disqualified Stock of the Company or such Restricted Subsidiary, as the case may be, that, in each case, is permitted to be Incurred pursuant to the covenant described under "Limitation on Indebtedness" and that in each case constitutes Refinancing Indebtedness; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(4) so long as no Default or Event of Default has occurred and is continuing, any purchase or redemption of Subordinated Obligations or Guarantor Subordinated Obligations of a Subsidiary Guarantor from Net Available Cash to the extent permitted under "—Limitation on Sales of Assets and Subsidiary Stock" below; provided, however, that such purchase or redemption will be excluded from subsequent calculations of the amount of Restricted Payments;

(5) dividends paid within 60 days after the date of declaration if at such date of declaration such dividend would have complied with this provision; provided, however, that such dividends will be included in subsequent calculations of the amount of Restricted Payments;

(6) so long as no Default or Event of Default has occurred and is continuing,

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(a) the purchase, redemption or other acquisition, cancellation or retirement for value of Capital Stock, or options, warrants, equity appreciation rights or other rights to purchase or acquire Capital Stock of the Company or any Restricted Subsidiary or any parent of the Company held by any existing or former employees or directors of the Company or any Subsidiary of the Company or their assigns, estates or heirs, in each case in connection with the repurchase provisions under employee stock option or stock purchase agreements or other agreements to compensate employees or directors; provided that such purchase, redemption, acquisition, cancellation or retirement pursuant to this clause will not exceed $5.0 million in the aggregate during any calendar year; provided, however, that the amount of any such purchase, redemption, acquisition, cancellation or retirement will be excluded from subsequent calculations of the amount of Restricted Payments; and

(b) loans or advances to employees or directors of the Company or any Subsidiary of the Company the proceeds of which are used to purchase Capital Stock of the Company, in an aggregate amount not in excess of $5.0 million at any one time outstanding; provided, however, that the Company and its Subsidiaries shall comply in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith in connection with such loans or advances as if the Company had filed a registration statement with the SEC; provided, further, that the amount of such loans and advances will be included in subsequent calculations of the amount of Restricted Payments;

(7) so long as no Default or Event of Default has occurred and is continuing, the declaration and payment of dividends to holders of any class or series of Disqualified Stock of the Company, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, issued in accordance with the terms of the Indenture to the extent such dividends are included in the definition of "Consolidated Interest Expense;" provided that the payment of such dividends will be excluded from subsequent calculations of the amount of Restricted Payments;

(8) repurchases of Capital Stock deemed to occur upon the exercise of stock options, warrants or other convertible securities if such Capital Stock represents a portion of the exercise price thereof; provided, however, that such repurchases will be excluded from subsequent calculations of the amount of Restricted Payments;

(9) the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Obligation (i) at a purchase price not greater than 101% of the principal amount of such Subordinated Obligation in the event of a Change of Control in accordance with provisions similar to the "—Change of Control" covenant or (ii) at a purchase price not greater than 100% of the principal amount thereof in accordance with provisions similar to the "—Limitation on Sales of Assets and Subsidiary Stock" covenant; provided that, prior to or simultaneously with such purchase, repurchase, redemption, defeasance or other acquisition or retirement, the Company has made the Change of Control Offer or Asset Disposition Offer, as applicable, as provided in such covenant with respect to the Notes and has completed the repurchase or redemption of all Notes validly tendered for payment in connection with such Change of Control Offer or Asset Disposition Offer; provided, further, that any such purchase, repurchase, redemption, defeasance or other acquisition will be excluded from subsequent calculations of the amount of Restricted Payments;

(10) distributions by Employee Partnerships or the SWR Partnerships to the limited partners thereof; provided that such distributions will be excluded from subsequent calculations of the amount of Restricted Payments;

(11) the payment of dividends on the Company's common equity (or the payment of dividends or distributions to a direct or indirect company of the Company to fund the payment by such

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parent company of dividends or distributions on its common equity) of up to 6.0% per calendar year of the net proceeds received by the Company from any public Equity Offering or contributed to the Company by a direct or indirect parent company of the Company from any public Equity Offering; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will be excluded from clause (c)(ii) of the preceding paragraph; and

(12) Restricted Payments in an amount not to exceed $20.0 million; provided that the amount of such Restricted Payments will be excluded from subsequent calculations of the amount of Restricted Payments.

The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of such Restricted Payment of the asset(s) or securities proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment. The fair market value of any cash Restricted Payment shall be its face amount and any non-cash Restricted Payment shall be determined conclusively by the Board of Directors of the Company acting in good faith.

As of the date hereof, the amount available for additional Restricted Payments, pursuant to clause (c) of the first paragraph of this covenant is approximately $141.0 million.

Limitation on Liens

The Company will not, and will not permit any Subsidiary Guarantor to, directly or indirectly, create, Incur or suffer to exist any Lien (other than Permitted Liens) upon any of its property or assets (including Capital Stock of Restricted Subsidiaries), whether owned on the date of the Indenture or acquired after that date, which Lien is securing any Indebtedness, unless contemporaneously with the Incurrence of such Liens effective provision is made to secure the Indebtedness due under the Indenture and the Notes or, in respect of Liens on any Subsidiary Guarantor's property or assets, any Subsidiary Guarantee of such Subsidiary Guarantor, equally and ratably with (or senior in priority to in the case of Liens with respect to Subordinated Obligations or Guarantor Subordinated Obligations, as the case may be) the Indebtedness secured by such Lien for so long as such Indebtedness is so secured.

Limitation on Restrictions on Distributions from Restricted Subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any Restricted Subsidiary (it being understood that the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on Common Stock shall not be deemed a restriction on the ability to make distributions on Capital Stock);

(2) make any loans or advances to the Company or any Restricted Subsidiary (it being understood that the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness Incurred by the Company or any Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

(3) transfer any of its property or assets to the Company or any Restricted Subsidiary.

The preceding provisions will not prohibit:

(i) any encumbrance or restriction pursuant to an agreement in effect at or entered into on the date of the Indenture, including, without limitation, the Indenture, the Notes, the exchange

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notes, the Subsidiary Guarantees and the Senior Secured Credit Agreement (and related documentation) in effect on such date;

(ii) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement relating to any Capital Stock or Indebtedness Incurred by a Restricted Subsidiary on or before the date on which such Restricted Subsidiary was acquired by the Company or a Restricted Subsidiary (other than Capital Stock or Indebtedness Incurred as consideration in, or to provide all or any portion of the funds utilized to consummate, the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was acquired by the Company or in contemplation of the transaction) and outstanding on such date provided, that any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(iii) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred pursuant to an agreement referred to in clause (i) or (ii) of this paragraph or this clause (iii) or contained in any amendment, restatement, modification, renewal, supplement, refunding, replacement or refinancing of an agreement referred to in clause (i) or (ii) of this paragraph or this clause (iii); provided, however, that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement are no less favorable in any material respect, taken as a whole, to the holders of the Notes, in the reasonable judgment of the Company's Board of Directors or senior management, than the encumbrances and restrictions contained in such agreements referred to in clauses (i) or (ii) of this paragraph on the Issue Date or the date such Restricted Subsidiary became a Restricted Subsidiary or was merged into a Restricted Subsidiary, whichever is applicable;

(iv) in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(a) that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease, license or similar contract, or the assignment or transfer of any such lease, license or other contract;

(b) contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements; or

(c) pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

(v) (a) purchase money obligations for property acquired in the ordinary course of business and (b) Capitalized Lease Obligations permitted under the Indenture, in each case, that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property so acquired;

(vi) any restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or disposition of all or substantially all the Capital Stock or assets of such Restricted Subsidiary (or the property or assets that are subject to such restriction) pending the closing of such sale or disposition;

(vii) any customary encumbrances or restrictions imposed pursuant to any agreement referred to in the definition of "Permitted Business Investment" or in Employee Partnerships;

(viii) net worth provisions in leases and other agreements entered into by the Company or any Restricted Subsidiary in the ordinary course of business;

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(ix) encumbrances or restrictions arising or existing by reason of applicable law or any applicable rule, regulation or order; and

(x) encumbrances or restrictions contained in indentures or debt instruments or other debt arrangements Incurred by Subsidiary Guarantors in accordance with "—Limitation on Indebtedness," that are not more restrictive, taken as a whole, than those applicable to the Company in either the Indenture or the Senior Secured Credit Agreement on the Issue Date (which results in encumbrances or restrictions comparable to those applicable to the Company at a Restricted Subsidiary level).

Limitation on Sales of Assets and Subsidiary Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless:

(1) the Company or such Restricted Subsidiary, as the case may be, receives consideration at least equal to the fair market value (such fair market value to be determined on the date of contractually agreeing to such Asset Disposition), as determined in good faith by the Board of Directors (including as to the value of all non-cash consideration), of the shares and assets subject to such Asset Disposition; and

(2) at least 75% of the aggregate consideration received by the Company or such Restricted Subsidiary, as the case may be, from such Asset Disposition and all other Asset Dispositions since the Issue Date, on a cumulative basis, is in the form of cash or Cash Equivalents or Additional Assets, or any combination thereof.

Within 365 days of completion of an Asset Disposition, the Company or a Restricted Subsidiary may apply any Net Available Cash from such Asset Disposition:

(a) to repay, redeem or purchase Indebtedness of the Company (other than any Disqualified Stock or Subordinated Obligations) or Indebtedness of a Restricted Subsidiary (other than any Disqualified Stock or Guarantor Subordinated Obligation of a Subsidiary Guarantor) (in each case other than Indebtedness owed to the Company or a Restricted Subsidiary); or

(b) to invest in or acquire Additional Assets.

Pending the final application of any such Net Available Cash in accordance with clause (a) or clause (b) above, the Company and its Restricted Subsidiaries may temporarily reduce Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that are not applied or invested as provided in the preceding paragraph will be deemed to constitute "Excess Proceeds." Not later than the 366th day after the later of the date of an Asset Disposition or the receipt of such Net Available Cash, if the aggregate amount of Excess Proceeds exceeds $20.0 million, the Company will be required to make an offer ("Asset Disposition Offer") to all holders of Notes and to the extent required by the terms of other Pari Passu Indebtedness, to all holders of other Pari Passu Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Pari Passu Indebtedness with the proceeds from any Asset Disposition ("Pari Passu Notes"), to purchase the maximum principal amount of Notes and any such Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount of the Notes and Pari Passu Notes plus accrued and unpaid interest to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable, in each case in integral multiples of $1,000. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and

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not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company may use any remaining Excess Proceeds for general corporate purposes, subject to other covenants contained in the Indenture. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes for which it is Trustee and the Company shall select any other Pari Passu Notes to be purchased on a pro rata basis on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the "Asset Disposition Offer Period"). No later than five Business Days after the termination of the Asset Disposition Offer Period (the "Asset Disposition Purchase Date"), the Company will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to this covenant (the "Asset Disposition Offer Amount") or, if less than the Asset Disposition Offer Amount has been so validly tendered, all Notes and Pari Passu Notes validly tendered in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no additional interest will be payable to holders who tender Notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Company will, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to the Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so validly tendered and not properly withdrawn, in each case in integral multiples of $1,000. The Company will deliver to the Trustee an Officers' Certificate stating that such Notes or portions thereof were accepted for payment by the Company in accordance with the terms of this covenant and, in addition, the Company will deliver all certificates and notes required, if any, by the agreements governing the Pari Passu Notes. The Company will promptly (but in any case not later than five Business Days after termination of the Asset Disposition Offer Period) mail or deliver to each tendering holder of Notes or holder or lender of Pari Passu Notes, as the case may be, an amount equal to the purchase price of the Notes or Pari Passu Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company will promptly issue a new Note, and the Trustee, upon delivery of an Officers' Certificate from the Company, will authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered; provided that each such new Note will be in a principal amount of $2,000 or an integral multiple of $1,000. In addition, the Company will take any and all other actions required by the agreements governing the Pari Passu Notes. Any Note not so accepted will be promptly mailed or delivered by the Company to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

For the purposes of clause (2) of the first paragraph of this covenant, the following will be deemed to be cash:

(1) the assumption by the transferee of Indebtedness (other than Subordinated Obligations or Disqualified Stock) of the Company or Indebtedness of a Restricted Subsidiary (other than Guarantor Subordinated Obligations or Disqualified Stock of any Wholly-Owned Subsidiary that is a Subsidiary Guarantor) and the release of the Company or such Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition (in which case the

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Company will, without further action, be deemed to have applied such deemed cash to Indebtedness in accordance with clause (a) above); and

(2) securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that are promptly converted by the Company or such Restricted Subsidiary into cash.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes pursuant to the Indenture. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Indenture by virtue of any conflict.

Limitation on Affiliate Transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into or conduct any transaction (including the purchase, sale, lease or exchange of any property or the rendering of any service) with any Affiliate of the Company (an "Affiliate Transaction") unless:

(1) the terms of such Affiliate Transaction are not materially less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could be reasonably be expected to be obtained in a comparable transaction at the time of such transaction in arm's-length dealings with a Person who is not such an Affiliate;

(2) in the event such Affiliate Transaction involves an aggregate consideration in excess of $20.0 million, the terms of such transaction have been approved by a majority of the members of the Board of Directors of the Company having no personal pecuniary interest in such transaction; and

(3) in the event such Affiliate Transaction involves an aggregate consideration in excess of $50.0 million, the Company has received a written opinion from an independent investment banking, accounting or appraisal firm of recognized standing (as determined in good faith by the Board of Directors of the Company) that such Affiliate Transaction is either (a) fair from a financial point of view to the Company and its Restricted Subsidiaries or (b) not materially less favorable than those that might reasonably have been obtained in a comparable transaction at such time on an arm's-length basis from a Person that is not an Affiliate.

The preceding paragraph will not apply to:

(1) any Restricted Payment permitted to be made pursuant to the covenant described under "Limitation on Restricted Payments" or Permitted Investments;

(2) any issuance of securities, or other payments, awards or grants in cash, securities or otherwise pursuant to, or the funding of, employment agreements and other compensation arrangements, options to purchase Capital Stock of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans, bonus plans, Employee Partnerships or similar employee benefits plans and/or indemnity provided on behalf of officers and employees approved by the Board of Directors of the Company;

(3) loans or advances to employees, officers or directors in the ordinary course of business of the Company or any of its Restricted Subsidiaries but in any event not to exceed $5.0 million in the aggregate outstanding at any one time with respect to all loans or advances made since the Issue Date; provided, however, that the Company and its Subsidiaries will comply in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and

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regulations promulgated in connection therewith that would be applicable to an issuer with debt securities registered under the Securities Act relating to such loans and advances;

(4) any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries and Guarantees issued by the Company or a Restricted Subsidiary for the benefit of the Company or a Restricted Subsidiary, as the case may be, in accordance with "Certain Covenants—Limitation on Indebtedness;"

(5) the payment of reasonable and customary fees paid to, and indemnity provided on behalf of, directors of the Company or any Restricted Subsidiary;

(6) the existence of, and the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of any agreement to which the Company or any of its Restricted Subsidiaries is a party as of or on the Issue Date and identified on a schedule to the Indenture on the Issue Date, as these agreements may be amended, modified, supplemented, extended or renewed from time to time; provided, however, that any future amendment, modification, supplement, extension or renewal entered into after the Issue Date will be permitted to the extent that its terms are not more disadvantageous to the holders of the Notes than the terms of the agreements in effect on the Issue Date;

(7) transactions in the ordinary course of the business of the Company and its Restricted Subsidiaries; provided that such transactions are on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person;

(8) any issuance or sale of Capital Stock (other than Disqualified Stock) and the granting of registration and other customary rights in connection therewith; and

(9) transactions with a Person that is an Affiliate of the Company solely because the Company owns, directly or through a Restricted Subsidiary, Capital Stock of such Person.

SEC Reports

Whether or not the Company is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, the Company will make available to the Trustee and the registered holders of the Notes the business and financial information required in the annual, quarterly and current reports specified in Sections 13 and 15(d) of the Exchange Act which the Company would be required to file if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act. The Company will make such information available to the Trustee and the registered holders of the Notes no later than 60 days after the date on which the Company would have been required to file such reports with the SEC if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes to the financial statements and in Management's Discussion and Analysis of Results of Operations and Financial Condition, of the financial condition and results of operations of the Company and its Restricted Subsidiaries.

In addition, the Company and the Subsidiary Guarantors have agreed that they will make available to the holders and to prospective investors, upon the request of such holders, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act so long as the Notes are not freely transferable under the Securities Act. For purposes of this covenant, the Company and the Subsidiary Guarantors will be deemed to have furnished the reports to the Trustee and the holders of

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Notes as required by this covenant if it has filed such reports with the SEC via the EDGAR filing system and such reports are publicly available, provided, however, that the Trustee shall have no responsibility to determine if such filing has occurred.

Merger and Consolidation

The Company will not consolidate with or merge with or into, or convey, transfer or lease all or substantially all its assets to, any Person, unless:

(1) the resulting, surviving or transferee Person (the "Successor Company") will be a corporation organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and the Successor Company (if not the Company) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, in form satisfactory to the Trustee, all the obligations of the Company under the Notes and the Indenture;

(2) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the Successor Company or any Subsidiary of the Successor Company as a result of such transaction as having been Incurred by the Successor Company or such Subsidiary at the time of such transaction), no Default or Event of Default shall have occurred and be continuing;

(3) immediately after giving effect to such transaction, either (a) the Successor Company would be able to Incur at least an additional $1.00 of Indebtedness pursuant to the first paragraph of the "Limitation on Indebtedness" covenant, or (b) immediately after giving effect to such transaction on a pro forma basis and any related financing transactions as if the same had occurred at the beginning of the applicable four quarter period, the Consolidated Coverage Ratio of the Company is equal to or greater than the Consolidated Coverage Ratio of the Company immediately before such transaction;

(4) each Subsidiary Guarantor (unless it is the other party to the transactions above, in which case clause (1) shall apply) shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person's obligations in respect of the Indenture and the Notes and its obligations under the Registration Rights Agreements shall continue to be in effect; and

(5) the Company shall have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture.

For purposes of this covenant, the sale, lease, conveyance, assignment, transfer, or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of the Company, which properties and assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the properties and assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties and assets of the Company.

The predecessor Company will be released from its obligations under the Indenture and the Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture, but, in the case of a lease of all or substantially all its assets, the predecessor Company will not be released from the obligation to pay the principal of and interest on the Notes.

Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve "all or substantially all" of the property or assets of a Person.

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Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary may consolidate or merge with, merge into or transfer all or part of its properties and assets to the Company and (y) the Company may merge with an Affiliate incorporated solely for the purpose of reincorporating the Company in another jurisdiction to realize tax benefits; provided that, in the case of a Restricted Subsidiary that merges into the Company, the Company will not be required to comply with the preceding clause (5).

In addition, the Company will not permit any Subsidiary Guarantor to consolidate with or merge with or into any person (other than the Company or another Subsidiary Guarantor) and will not permit the conveyance, transfer or lease of substantially all of the assets of any Subsidiary Guarantor unless:

(1) (a) the resulting, surviving or transferee Person will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and such Person (if not such Subsidiary Guarantor) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, all the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee; (b) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the resulting, surviving or transferee Person or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Person or such Restricted Subsidiary at the time of such transaction), no Default of Event of Default shall have occurred and be continuing; and (c) the Company will have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture; or

(2) the transaction is made in compliance with the covenant described under "—Limitation on Sales of Assets and Subsidiary Stock" and this "—Merger and Consolidation" covenant.

Future Subsidiary Guarantors

The Company will cause each Restricted Subsidiary (other than an Employee Partnership or a Foreign Subsidiary) created or acquired by the Company or one or more of its Restricted Subsidiaries after the Issue Date to execute and deliver to the Trustee a Subsidiary Guarantee pursuant to which such Subsidiary Guarantor will unconditionally Guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any and interest on the Notes on a senior basis; provided, however, that Restricted Subsidiaries (other than Foreign Subsidiaries, Employee Partnerships or SWR Partnerships) that, in the aggregate, own less than five percent of the Company's Total Assets and account for less than five percent of the Company's Consolidated EBITDAX (in each case, determined on a quarterly basis) shall not be required to execute and deliver a Subsidiary Guarantee. Notwithstanding the foregoing, the Employee Partnerships and SWR Partnership shall not be required to execute and deliver a Subsidiary Guarantee.

The obligations of each Subsidiary Guarantor will be limited to the maximum amount as will, after giving effect to all other contingent and fixed liabilities of such Subsidiary Guarantor (including, without limitation, any guarantees under the Senior Secured Credit Agreement) and after giving effect to any collections from or payments made by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Subsidiary Guarantee or pursuant to its contribution obligations under the Indenture, result in the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law.

Each Subsidiary Guarantee shall be released in accordance with the provisions of the Indenture described under "—Subsidiary Guarantees."

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Limitation on Lines of Business

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

Payments for Consent

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration in the form of cash or other property to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or amendment.

Events of Default

Each of the following is an Event of Default:

(1) default in any payment of interest or additional interest (as required by the Registration Rights Agreements) on any Note when due, continued for 30 days;

(2) default in the payment of principal of or premium, if any, on any Note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration or otherwise;

(3) failure by the Company or any Subsidiary Guarantor to comply with its obligations under "Certain Covenants—Merger and Consolidation;"

(4) failure by the Company to comply for 30 days after written notice as provided below with any of its obligations under the covenants described under "Change of Control" above or under the covenants described under "Certain Covenants" above (in each case, other than a failure to purchase Notes which will constitute an Event of Default under clause (2) above and other than a failure to comply with "Certain Covenants—Merger and Consolidation" which is covered by clause (3));

(5) failure by the Company to comply for 60 days after written notice as provided below with its other agreements contained in the Indenture;

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), other than Indebtedness owed to the Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, which default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness ("payment default"); or

(b) results in the acceleration of such Indebtedness prior to its maturity (the "cross acceleration provision");

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a payment default or the maturity of which has been so accelerated, aggregates $25.0 million or more;

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(7) certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the "bankruptcy provisions");

(8) failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $25.0 million (net of any amounts that a reputable and creditworthy insurance company has acknowledged liability for in writing), which judgments are not paid, discharged or stayed for a period of 60 days (the "judgment default provision"); or

(9) any Subsidiary Guarantee of a Significant Subsidiary or group of Restricted Subsidiaries that taken together as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries would constitute a Significant Subsidiary ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that taken together as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries would constitute a Significant Subsidiary denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding Notes notify the Company of the default and the Company does not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such written notice.

If an Event of Default (other than an Event of Default described in clause (7) above) occurs and is continuing, the Trustee by written notice to the Company, or the holders of at least 25% in principal amount of the outstanding Notes by written notice to the Company and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, and accrued and unpaid interest, if any, on all the Notes to be due and payable. Upon such a declaration, such principal, premium and accrued and unpaid interest will be due and payable immediately. In the event of a declaration of acceleration of the Notes because an Event of Default described in clause (6) under "Events of Default" has occurred and is continuing, the declaration of acceleration of the Notes shall be automatically annulled if the event of default or payment default triggering such Event of Default pursuant to clause (6) shall be remedied or cured by the Company or a Restricted Subsidiary or waived by the holders of the relevant Indebtedness within 20 days after the declaration of acceleration with respect thereto and if (1) the annulment of the acceleration of the Notes would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, except nonpayment of principal, premium or interest on the Notes that became due solely because of the acceleration of the Notes, have been cured or waived. If an Event of Default described in clause (7) above occurs and is continuing, the principal of, premium, if any, and accrued and unpaid interest on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding Notes may waive all past defaults (except with respect to nonpayment of principal, premium or interest) and rescind any such acceleration with respect to the Notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by such declaration of acceleration, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the Trustee, if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights

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or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee indemnity or security satisfactory to the Trustee against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the Notes unless:

(1) such holder has previously given the Trustee written notice that an Event of Default is continuing;

(2) holders of at least 25% in principal amount of the outstanding Notes have requested the Trustee to pursue the remedy;

(3) such holders have offered the Trustee security or indemnity satisfactory to the Trustee against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) the holders of a majority in principal amount of the outstanding Notes have not given the Trustee a written direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding Notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Indenture provides that in the event an Event of Default has occurred and is continuing, the Trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use in the conduct of its own affairs. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

The Indenture provides that if a Default occurs and is continuing and is known to the Trustee, the Trustee must send to each holder notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of, premium, if any, or interest on any Note, the Trustee may withhold notice if and so long as the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Company is required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Company also is required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any events which would constitute certain Defaults, their status and what action the Company is taking or proposing to take in respect thereof.

In the case of any Event of Default occurring by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Company with the intention of avoiding payment of the premium that the Company would have had to pay if the Company then had elected to redeem the Notes pursuant to the optional redemption provisions of the Indenture or was required to repurchase the Notes, an equivalent premium shall also become and be immediately due and payable to the extent permitted by law upon the acceleration of the Notes.

Amendments and Waivers

Subject to certain exceptions, the Indenture and the Notes may be amended or supplemented with the consent of the holders of a majority in principal amount of the Notes then outstanding (including without limitation, consents obtained in connection with a purchase of, or tender offer or exchange

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offer for, Notes) and, subject to certain exceptions, any past default or compliance with any provisions may be waived with the consent of the holders of a majority in principal amount of the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes). However, without the consent of each holder of an outstanding Note affected, no amendment, supplement or waiver may, among other things:

(1) reduce the amount of Notes whose holders must consent to an amendment;

(2) reduce the stated rate of or extend the stated time for payment of interest on any Note;

(3) reduce the principal of or extend the Stated Maturity of any Note;

(4) reduce the premium payable upon the redemption of any Note or change the time at which any Note may be redeemed as described above under "Optional Redemption," except as described above under "Change of Control" or "Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock;"

(5) make any Note payable in money other than that stated in the Note;

(6) impair the right of any holder to receive payment of, premium, if any, principal of and interest on such holder's Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder's Notes;

(7) make any change in the amendment or waiver provisions which require each holder's consent; or

(8) modify the Subsidiary Guarantees in any manner adverse to the holders of the Notes.

Notwithstanding the foregoing, without the consent of any holder, the Company, the Subsidiary Guarantors and the Trustee may amend the Indenture and the Notes to:

(1) cure any ambiguity, omission, defect or inconsistency;

(2) provide for the assumption by a successor corporation of the obligations of the Company or any Subsidiary Guarantor under the Indenture;

(3) provide for uncertificated Notes in addition to or in place of certificated Notes (provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f)(2)(B) of the Code);

(4) add Guarantees with respect to the Notes or release a Subsidiary Guarantor upon its designation as an Unrestricted Subsidiary; provided, however, that the designation is in accord with the applicable provisions of the Indenture;

(5) secure the Notes;

(6) add to the covenants of the Company for the benefit of the holders or surrender any right or power conferred upon the Company;

(7) make any change that does not adversely affect the legal rights of any holder in any material respect;

(8) comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act;

(9) provide for the issuance of exchange securities which shall have terms substantially identical in all respects to the Notes (except that the transfer restrictions contained in the Notes shall be modified or eliminated as appropriate) and which shall be treated, together with any outstanding Notes, as a single class of securities;

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(10) release a Subsidiary Guarantor from its obligations under its Subsidiary Guarantee or the Indenture in accordance with the applicable provisions of the Indenture;

(11) provide for the appointment of a successor trustee; provided that the successor trustee is otherwise qualified and eligible to act as such under the terms of the Indenture; or

(12) conform any provision of the Indenture to the "Description of Notes" in the offering memorandum relating to the originally issued Notes, as provided in an officers' certificate.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment or supplement. It is sufficient if such consent approves the substance of the proposed amendment or supplement. A consent to any amendment, supplement or waiver under the Indenture by any holder of Notes given in connection with a tender of such holder's Notes will not be rendered invalid by such tender. After an amendment or supplement under the Indenture becomes effective, the Company is required to send to the holders a written notice briefly describing such amendment or supplement. However, the failure to give such notice to all the holders, or any defect in the notice will not impair or affect the validity of the amendment or supplement.

Defeasance

The Company at any time may terminate all its obligations under the Notes and the Indenture ("legal defeasance"), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the Notes, to replace mutilated, destroyed, lost or stolen Notes and to maintain a registrar and paying agent in respect of the Notes. If the Company exercises its legal defeasance option, the Subsidiary Guarantees in effect at such time will terminate.

The Company at any time may terminate its obligations described under "Change of Control" and under covenants described under "Certain Covenants" (other than "Merger and Consolidation"), the operation of the cross-default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision and the Subsidiary Guarantee provision described under "Events of Default" above and the limitations contained in clause (3) under "Certain Covenants—Merger and Consolidation" above ("covenant defeasance").

The Company may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If the Company exercises its legal defeasance option, payment of the Notes may not be accelerated because of an Event of Default with respect to the Notes. If the Company exercises its covenant defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (7) (with respect only to Significant Subsidiaries), (8) or (9) under "Events of Default" above or because of the failure of the Company to comply with clause (3) under "Certain Covenants—Merger and Consolidation" above.

In order to exercise either defeasance option, the Company must irrevocably deposit in trust (the "defeasance trust") with the Trustee money or U.S. Government Obligations sufficient (in the opinion of an independent firm of certified public accountants) for the payment of principal, premium, if any, and interest on the Notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the Notes will not recognize income, gain or loss for Federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable Federal income tax law.

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Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder, when either:

(1) all Notes that have been authenticated (except lost, stolen or destroyed Notes that have been replaced or paid and Notes for whose payment money has theretofore been deposited in trust and thereafter repaid to the Company) have been delivered to the Trustee for cancellation, or

(2) all Notes that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable within one year by reason of the giving of a notice of redemption or otherwise and the Company or any Subsidiary Guarantor has irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, U.S. Government Obligations, or a combination thereof, in such amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the Notes not delivered to the Trustee for cancellation for principal and accrued interest to the date of maturity or redemption,

and in each case certain other requirements set forth in the Indenture are satisfied.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder of the Company or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company under the Notes, the Indenture or the Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

Concerning the Trustee

Wells Fargo Bank, National Association is the Trustee under the Indenture and has been appointed by the Company as registrar and paying agent with regard to the Notes.

Governing Law

The Indenture provides that it and the Notes will be governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

"Acquired Indebtedness" means Indebtedness (i) of a Person or any of its Subsidiaries existing at the time such Person becomes a Restricted Subsidiary or (ii) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (i) of the preceding sentence, on the date such Person becomes a Restricted Subsidiary and, with respect to clause (ii) of the preceding sentence, on the date of consummation of such acquisition of assets.

"Additional Assets" means:

(1) any property, plant or equipment to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(2) capital expenditures by the Company or a Restricted Subsidiary in the Oil and Gas Business;

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(3) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary; or

(4) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided,however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

"Adjusted Consolidated Net Tangible Assets" means (without duplication), as of the date of determination, the remainder of:

(a) the sum of:

(i) discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any provincial, territorial, state, federal or foreign income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company's most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from

(A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

(B) estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves since such year end due to exploration, development or exploitation activities, in each case calculated in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

and decreased by, as of the date of determination, the estimated discounted future net revenues from

(D) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

in each case as estimated by the Company's petroleum engineers or any independent petroleum engineers engaged by the Company for that purpose;

(ii) the capitalized costs that are attributable to oil and gas properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company's books and records as of a date no earlier than the date of the Company's latest available annual or quarterly financial statements;

(iii) the Net Working Capital on a date no earlier than the date of the Company's latest annual or quarterly financial statements; and

(iv) the greater of

(A) the net book value of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company's latest annual or quarterly financial statement, and

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(B) the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company's latest audited financial statements; minus

(b) the sum of:

(i) Minority Interests;

(ii) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company's latest audited financial statements;

(iii) to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in the Company's year end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Company and its Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the successful efforts method of accounting to the full cost or a similar method, "Adjusted Consolidated Net Tangible Assets" will continue to be calculated as if the Company were still using the successful efforts method of accounting.

For purposes of calculating the amount referred to in clause (1) of the second paragraph of "—Limitation on Indebtedness," the Company will be entitled to rely on the greater of (i) Adjusted Consolidated Net Tangible Assets as calculated as of the date used for determining the borrowing base from time to time under the Company's Senior Secured Credit Agreement, or (ii) Adjusted Consolidated Net Tangible Assets as determined above as of the date of determination.

"Affiliate" of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, "control" when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms "controlling" and "controlled" have meanings correlative to the foregoing; provided that exclusively for purposes of "Certain Covenants—Limitation on Affiliate Transactions," beneficial ownership of 10% or more of the Voting Stock of a Person shall be deemed to be control.

"Asset Disposition" means any direct or indirect sale, lease (other than an operating lease entered into in the ordinary course of the Oil and Gas Business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of shares of Capital Stock of a Subsidiary (other than directors' qualifying shares), property or other assets (each referred to for the purposes of this definition as a "disposition") by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

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Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1) a disposition of assets by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Restricted Subsidiary, provided that in the case of a sale by a Restricted Subsidiary to another Restricted Subsidiary, the Company directly or indirectly owns an equal or greater percentage of the Common Stock of the transferee than of the transferor;

(2) the sale of Cash Equivalents in the ordinary course of business;

(3) dispositions of equipment, inventory, accounts receivable or other properties or assets in the ordinary course of business, including any abandonment, farm-in, farm-out, lease or sublease of any oil and gas properties or the forfeiture or other disposition of such properties pursuant to standard form operating agreements, in each case in the ordinary course of business in a manner customary in the Oil and Gas Business;

(4) a disposition of obsolete or worn out equipment or equipment that is no longer useful in the conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;

(5) transactions permitted under "Certain Covenants—Merger and Consolidation;"

(6) an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Restricted Subsidiary;

(7) for purposes of "Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock" only, the making of a Permitted Investment or a disposition subject to "Certain Covenants—Limitation on Restricted Payments;"

(8) a concurrent purchase and sale or exchange of property or assets of the Company or any Restricted Subsidiary for Additional Assets of another person having reasonably equivalent value as determined by the Company in good faith, provided that any cash received must be applied in accordance with "Limitation on Sales of Assets and Subsidiary Stock;"

(9) dispositions of assets in a single transaction or series of related transactions with an aggregate fair market value of less than $10.0 million;

(10) the creation of a Permitted Lien or dispositions in connection with Permitted Liens;

(11) dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;

(12) the licensing or sublicensing of intellectual property or other general intangibles and licenses, leases or subleases of other property;

(13) foreclosure on assets;

(14) any Production Payments and Reserve Sales; and

(15) the conveyance of assets to Employee Partnerships or the sale or grant of partnership interests in Employee Partnerships to their respective limited partners, as permitted in the definition of "Employee Partnerships."

"Attributable Indebtedness" in respect of a Sale/Leaseback Transaction means, as at the time of determination, the present value (discounted at the interest rate borne by the Notes, compounded semi-annually) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such Sale/Leaseback Transaction (including any period for which such lease has been extended).

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"Average Life" means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

"Board of Directors" means, as to any Person, the board of directors of such Person or any duly authorized committee thereof.

"Business Day" means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York or a place of payment are authorized or required by law to close.

"Capital Stock" of any Person means any and all shares, interests, rights to purchase, warrants, options, participation or other equivalents of or interests in (however designated) equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into such equity.

"Capitalized Lease Obligations" means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

"Cash Equivalents" means:

(1) securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States (provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;

(2) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition (provided that the full faith and credit of the United States is pledged in support thereof) and, at the time of acquisition, having a credit rating equivalent to "A" or better from either Standard & Poor's Ratings Services or Moody's Investors Service, Inc.;

(3) certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers' acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the long-term debt of which is rated at the time of acquisition thereof at least "A" or the equivalent thereof by Standard & Poor's Ratings Services or Moody's Investors Service, Inc., and having combined capital and surplus in excess of $100 million;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;

(5) commercial paper rated at the time of acquisition thereof at least "A-2" or the equivalent thereof by Standard & Poor's Ratings Services or "P-2" or the equivalent thereof by Moody's Investors Service, Inc., or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of investments, and in any case maturing within one year after the date of acquisition thereof; and

(6) interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above.

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"Change of Control" means:

(1) (A) any "person" or "group" of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than one or more Permitted Holders, is or becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that such person or group shall be deemed to have "beneficial ownership" of all shares that any such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time), directly or indirectly, of more than a majority of the total voting power of the Voting Stock of the Company (or its successor by merger, consolidation or purchase of all or substantially all of its assets) other than as a result of any merger or consolidation in which the holders of a majority of the Voting Stock of the Company immediately prior to such transaction will, immediately after such transaction, hold or own Voting Stock of the surviving or successor entity or any parent thereof representing a majority of the voting power of the Voting Stock of such entity (for the purposes of this clause, such person or group shall be deemed to beneficially own any Voting Stock of the Company held by a parent entity, if such person or group "beneficially owns" (as defined above), directly or indirectly, more than a majority of the voting power of the Voting Stock of such parent entity); or

(2) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any "person" (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) other than a Permitted Holder; or

(3) the adoption by the stockholders of the Company of a plan or proposal for the liquidation or dissolution of the Company.

"Code" means the Internal Revenue Code of 1986, as amended.

"Commodity Agreements" means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons used, produced, processed or sold by such Person that are customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbon prices.

"Common Stock" means with respect to any Person, any and all shares, interests or other participations in, and other equivalents (however designated and whether voting or nonvoting) of such Person's common stock whether or not outstanding on the Issue Date, and includes, without limitation, all series and classes of such common stock.

"Consolidated Coverage Ratio" means as of any date of determination, with respect to any Person, the ratio of (x) the aggregate amount of Consolidated EBITDAX of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided, however, that:

(1) if the Company or any Restricted Subsidiary:

(a) has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such Indebtedness as if such Indebtedness had been Incurred on the first day of such period and the discharge of any other Indebtedness repaid, repurchased, defeased or otherwise discharged with the proceeds of such new Indebtedness as if such discharge had occurred on the first day of such period; or

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(b) has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness, including with the proceeds of such new Indebtedness, as if such discharge had occurred on the first day of such period;

provided that in making any computation under clauses (a) or (b) above with respect to the Incurrence of any Indebtedness under a revolving credit facility or any discharge of Indebtedness under a revolving credit facility (unless such Indebtedness has been permanently repaid and the related commitment terminated), the amount of Indebtedness under any revolving credit facility outstanding on the date of such calculation will be deemed to be the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding;

(2) if since the beginning of such period the Company or any Restricted Subsidiary shall have made any Asset Disposition or disposed of any company, division, operating unit, segment,

business, group of related assets or line of business or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition:

(a) the Consolidated EBITDAX for such period will be reduced by an amount equal to the Consolidated EBITDAX (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the Consolidated EBITDAX (if negative) directly attributable thereto for such period; and

(b) Consolidated Interest Expense for such period will be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3) if since the beginning of such period the Company or any Restricted Subsidiary (by merger or otherwise) shall have made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company) or an acquisition of assets, including any acquisition of assets occurring in connection with a transaction causing a calculation to be made hereunder, which constitutes all or substantially all of a company, division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition occurred on the first day of such period; and

(4) if since the beginning of such period any Person that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period shall have Incurred any Indebtedness or discharged any Indebtedness, made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets occurred on the first day of such period.

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For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company (including pro forma expense and cost reductions determined in good faith by an officer of the Company, whether or not in accordance with Regulation S-X under the Securities Act). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the rate in effect on the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness if such Interest Rate Agreement has a remaining term in excess of 12 months). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company.

"Consolidated EBITDAX" for any period means the Consolidated Net Income for such period, plus, without duplication, the following to the extent deducted in calculating such Consolidated Net Income:

(1) Consolidated Interest Expense;

(2) Consolidated Income Taxes;

(3) consolidated depletion and depreciation expense;

(4) consolidated amortization expense or impairment charges recorded in connection with the application of Financial Accounting Standard No. 142 "Goodwill and Other Intangibles" and Financial Accounting Standard No. 144 "Accounting for the Impairment or Disposal of Long Lived Assets;"

(5) other non-cash charges reducing Consolidated Net Income (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation); and

(6) consolidated exploration expenses;

less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments, and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments.

Notwithstanding the preceding sentence, clauses (2) through (6) relating to amounts of a Restricted Subsidiary that is not a Subsidiary Guarantor will be added to Consolidated Net Income to compute Consolidated EBITDAX of such Person only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person.

"Consolidated Income Taxes" means, with respect to any Person for any period, taxes imposed upon such Person or other payments required to be made by such Person by any governmental authority which taxes or other payments are calculated by reference to the income or profits of such Person or such Person and its Restricted Subsidiaries (to the extent such income or profits were included in computing Consolidated Net Income for such period), regardless of whether such taxes or payments are required to be remitted to any governmental authority.

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"Consolidated Interest Expense" means, for any period, the total consolidated interest expense of the Company and its Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense:

(1) interest expense attributable to Capitalized Lease Obligations and the interest portion of rent expense associated with Attributable Indebtedness in respect of the relevant lease giving rise thereto, determined as if such lease were a capitalized lease in accordance with GAAP and the interest component of any deferred payment obligations;

(2) amortization of debt discount and debt issuance cost (provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);

(3) non-cash interest expense;

(4) commissions, discounts and other fees and charges owed with respect to letters of credit and bankers' acceptance financing;

(5) the interest expense on Indebtedness of another Person that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries;

(6) costs associated with Interest Rate Agreements (including amortization of fees) provided, however, that if Interest Rate Agreements result in net benefits rather than costs, such benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;

(7) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;

(8) the product of (a) all dividends paid or payable, in cash, Cash Equivalents or Indebtedness or accrued during such period on any series of Disqualified Stock of such Person or on Preferred Stock of its Restricted Subsidiaries that are not Subsidiary Guarantors payable to a party other than the Company or a Wholly-Owned Subsidiary, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state, provincial and local statutory tax rate of such Person, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP; and

(9) the cash contributions to any employee stock ownership plan or similar trust to the extent such contributions are used by such plan or trust to pay interest or fees to any Person (other than the Company and its Restricted Subsidiaries) in connection with Indebtedness Incurred by such plan or trust.

For the purpose of calculating the Consolidated Coverage Ratio in connection with the Incurrence of any Indebtedness described in the final paragraph of the definition of "Indebtedness," the calculation of Consolidated Interest Expense shall include all interest expense (including any amounts described in clauses (1) through (9) above) relating to any Indebtedness of the Company or any Restricted Subsidiary described in the final paragraph of the definition of "Indebtedness."

For purposes of the foregoing, total interest expense will be determined (i) after giving effect to any net payments made or received by the Company and its Subsidiaries with respect to Interest Rate Agreements and (ii) exclusive of amounts classified as other comprehensive income in the balance sheet of the Company. Notwithstanding anything to the contrary contained herein, commissions, discounts, yield and other fees and charges Incurred in connection with any transaction pursuant to which the Company or its Restricted Subsidiaries may sell, convey or otherwise transfer or grant a

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security interest in any accounts receivable or related assets shall be included in Consolidated Interest Expense.

"Consolidated Net Income" means, for any period, the consolidated net income (loss) of the Company and its Restricted Subsidiaries determined in accordance with GAAP; provided, however, that there will not be included in such Consolidated Net Income:

(1) any net income (loss) of any Person if such Person is not a Restricted Subsidiary, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company's equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

(b) the Company's equity in a net loss of any such Person (other than an Unrestricted Subsidiary) for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary;

(2) any net income (but not loss) of any Restricted Subsidiary other than a Subsidiary Guarantor if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company's equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend (subject, in the case of a dividend to another Restricted Subsidiary, to the limitation contained in this clause); and

(b) the Company's equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Restricted Subsidiaries (including pursuant to any Sale/Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(4) any after-tax extraordinary gain or loss;

(5) the after-tax cumulative effect of a change in accounting principles;

(6) any asset impairment writedowns on oil and gas properties under GAAP or SEC guidelines;

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of FASB ASC 815);

(8) any charge or expense in connection with the early retirement of Indebtedness, including payments or any penalties or redemption premiums; and

(9) non-cash charges relating to employee stock-based compensation.

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"Credit Facility" means, with respect to the Company or any Restricted Subsidiary, one or more debt facilities (including, without limitation, the Senior Secured Credit Agreement), commercial paper facilities or indentures with banks or other institutional lenders or investors providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables), letters of credit or notes, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (and whether or not with the original administrative agent and lenders or trustee and investors or another administrative agent or agents or trustee or trustees or other lenders or investors and whether provided under the original Senior Secured Credit Agreement or any other credit or other agreement or indenture).

"Currency Agreement" means in respect of a Person any foreign exchange contract, currency swap agreement, currency futures contract, currency option contract or other similar agreement as to which such Person is a party or a beneficiary.

"Default" means any event which is, or after notice or passage of time or both would be, an Event of Default.

"Disqualified Stock" means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) or upon the happening of any event:

(1) matures or is mandatorily redeemable pursuant to a sinking fund obligation or otherwise;

(2) is convertible or exchangeable for Indebtedness or Disqualified Stock (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or

(3) is redeemable at the option of the holder of the Capital Stock in whole or in part,

in each case on or prior to the date that is 91 days after the earlier of the date (a) of the Stated Maturity of the Notes or (b) on which there are no Notes outstanding,provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock;provided, further that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or asset sale (each defined in a substantially identical manner to the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) provide that the Company may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company with the provisions of the Indenture described under the captions "Change of Control" and "Limitation on Sales of Assets and Subsidiary Stock" and such repurchase or redemption complies with "Certain Covenants—Limitation on Restricted Payments."

"Dollar-Denominated Production Payments" means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

"Employee Partnerships" means partnerships, participation agreements or trusts formed in connection with the Company's APO Incentive Plan as in effect on the Issue Date or similar partnerships or trusts with employees or consultants intended to provide compensation or incentives through the sale or grant of partnership interests representing interests in oil and gas properties or prospects of the Company and its Restricted Subsidiaries, in each case as approved by the

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Compensation Committee of the Board of Directors of the Company, provided, that, after the Issue Date, the Company and its Restricted Subsidiaries shall not sell or grant to or under any such partnership, participation agreement or trust more than 10% of their respective interests in any particular oil and gas property or prospect.

"Equity Offering" means (i) a public offering for cash by the Company of its Capital Stock (other than Disqualified Stock), other than public offerings registered on Form S-4 or S-8 or (ii) a private offering to one or more institutional investors for cash by the Company of its Capital Stock (other than Disqualified Stock).

"Exchange Act" means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

"Foreign Subsidiary" means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia.

"GAAP" means generally accepted accounting principles in the United States of America as in effect from time to time, including those set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as approved by a significant segment of the accounting profession. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP.

"Guarantee" means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

(2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part); provided, however, that the term "Guarantee" will not include endorsements for collection or deposit in the ordinary course of business. The term "Guarantee" used as a verb has a corresponding meaning.

"Guarantor Subordinated Obligation" means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinate in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

"Hedging Obligations" of any Person means the obligations of such Person pursuant to any Interest Rate Agreement, Currency Agreement or Commodity Agreement.

"Holder" means a Person in whose name a Note is registered on the registrar's books.

"Hydrocarbons" means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

"Incur" means issue, create, assume, Guarantee, incur or otherwise become liable for; provided, however, that any Indebtedness or Capital Stock of a Person existing at the time such person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms "Incurred" and "Incurrence" have meanings correlative to the foregoing.

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"Indebtedness" means, with respect to any Person on any date of determination (without duplication):

(1) the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;

(2) the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) the principal component of all obligations of such Person in respect of letters of credit, bankers' acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable and such obligation is satisfied within 30 days of Incurrence);

(4) the principal component of all obligations of such Person to pay the deferred and unpaid purchase price of property (except trade payables), which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto;

(5) Capitalized Lease Obligations and all Attributable Indebtedness of such Person;

(6) the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary that is not a Subsidiary Guarantor, any Preferred Stock (but excluding, in each case, any accrued dividends);

(7) the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the fair market value of such asset at such date of determination and (b) the amount of such Indebtedness of such other Persons;

(8) the principal component of Indebtedness of other Persons to the extent Guaranteed by such Person; and

(9) to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time).

Notwithstanding the preceding, Indebtedness shall not include Volumetric Production Payments. The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.

In addition, "Indebtedness" of any Person shall include Indebtedness described in the preceding paragraph that would not appear as a liability on the balance sheet of such Person if:

(1) such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a "Joint Venture");

(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture (a "General Partner"); and

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(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a) the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

"Interest Rate Agreement" means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

"Investment" means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan (other than advances or extensions of credit to customers in the ordinary course of business) or other extensions of credit (including by way of Guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments issued by, such Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that none of the following will be deemed to be an Investment:

(1) Hedging Obligations entered into in the ordinary course of business and in compliance with the Indenture;

(2) endorsements of negotiable instruments and documents in the ordinary course of business; and

(3) an acquisition of assets, Capital Stock or other securities by the Company or a Subsidiary for consideration to the extent such consideration consists of Capital Stock of the Company (other than Disqualified Stock).

For purposes of "Certain Covenants—Limitation on Restricted Payments,"

(1) "Investment" will include the portion (proportionate to the Company's equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the fair market value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary (as conclusively determined by the Board of Directors of the Company in good faith); provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent "Investment" in an Unrestricted Subsidiary in an amount (if positive) equal to (a) the Company's "Investment" in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company's equity interest in such Subsidiary) of the fair market value of the net assets (as conclusively determined by the Board of Directors of the Company in good faith) of such Subsidiary at the time that such Subsidiary is so re-designated a Restricted Subsidiary; and

(2) any property transferred to or from an Unrestricted Subsidiary will be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Board of Directors of the Company.

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"Investment Grade Rating" means, with respect to the Company, a corporate family rating of the Company and its consolidated subsidiaries equal to or higher than Baa3 (or the equivalent) by Moody's and BBB- (or the equivalent) by S&P.

"Issue Date" means March 16, 2011, the date on which the Notes were originally issued.

"Lien" means any mortgage, pledge, security interest, encumbrance, lien or charge of any kind (including any conditional sale or other title retention agreement or lease in the nature thereof).

"Minority Interest" means the percentage interest represented by any shares of any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

"Net Available Cash" from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and net proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring person of Indebtedness or other obligations relating to the properties or assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

(1) all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all Federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;

(2) all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

(3) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures as a result of such Asset Disposition; and

(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition.

"Net Cash Proceeds," with respect to any issuance or sale of Capital Stock, means the cash proceeds of such issuance or sale net of attorneys' fees, accountants' fees, underwriters' or placement agents' fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance or sale and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

"Net Working Capital" means (a) all current assets of the Company and its Restricted Subsidiaries except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

"Non-Recourse Debt" means Indebtedness of a Person:

(1) as to which neither the Company nor any Restricted Subsidiary (a) provides any Guarantee or credit support of any kind (including any undertaking, guarantee, indemnity,

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agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable (as a guarantor or otherwise);

(2) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon written notice, lapse of time or both) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; and

(3) the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

"Officer" means the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer, any Vice President, the Treasurer or the Secretary of the Company. Officer of any Subsidiary Guarantor has a correlative meaning.

"Officers' Certificate" means a certificate signed by two Officers or by an Officer and either an Assistant Treasurer or an Assistant Secretary of the Company.

"Oil and Gas Business" means (a) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, gas, liquid natural gas and other hydrocarbon properties, (b) the business of gathering, marketing, treating, processing, storage, refining, selling and transporting of any production from such interests or properties and products produced in association therewith or providing drilling, completion and related services and supplies and equipment, (c) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (a) and (b) of this definition.

"Opinion of Counsel" means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Company or the Trustee.

"Pari Passu Indebtedness" means Indebtedness that ranks equally in right of payment to the Notes.

"Permitted Acquisition Indebtedness" means Indebtedness (including Disqualified Stock) of the Company or any of the Restricted Subsidiaries to the extent such Indebtedness was Indebtedness:

(1) of an acquired Person prior to the date on which such Person became a Restricted Subsidiary as a result of having been acquired and not incurred in contemplation of such acquisition; or

(2) of a Person that was merged, consolidated or amalgamated with or into the Company or a Restricted Subsidiary that was not incurred in contemplation of such merger, consolidation or amalgamation,

provided that on the date such Person became a Restricted Subsidiary or the date such Person was merged, consolidated and amalgamated with or into the Company or a Restricted Subsidiary, as applicable, after giving pro forma effect thereto,

(a) the Restricted Subsidiary or the Company, as applicable, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Consolidated Coverage Ratio test described under "Certain Covenants—Limitation on Indebtedness," or

(b) the Consolidated Coverage Ratio for the Company would be greater than the Consolidated Coverage Ratio for the Company immediately prior to such transaction.

"Permitted Holders" means any of Clayton Williams, Jr., The Williams Children's Partnership, Ltd. and any Affiliate or Related Person thereof.

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"Permitted Business Investment" means any Investment made in the ordinary course of the Oil and Gas Business including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, operating, processing, gathering, refining, storing, marketing, selling or transporting oil, gas and other Hydrocarbons through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including:

(1) ownership interests in oil and gas properties, liquid natural gas facilities, processing facilities, gathering systems, pipelines or ancillary real property interests;

(2) Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements (including for limited liability companies) with third parties; and

(3) direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation and completion equipment.

"Permitted Investment" means an Investment by the Company or any Restricted Subsidiary in:

(1) the Company or a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary; provided, however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;

(2) another Person if as a result of such Investment such other Person is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary; provided, however, that such Person's primary business is the Oil and Gas Business;

(3) cash and Cash Equivalents;

(4) receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(5) payroll, travel and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

(6) loans or advances to employees made in the ordinary course of business consistent with past practices of the Company or such Restricted Subsidiary; provided, however, that the Company and its Subsidiaries will comply in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith in connection with such loans or advances as if the Company had filed a registration statement with the SEC;

(7) Capital Stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments or pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of a debtor;

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(8) Investments made as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with "Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock;"

(9) Investments in existence on the Issue Date and any amendment, renewal or replacement thereof that does not exceed the amount of the original Investment;

(10) Commodity Agreements, Currency Agreements, Interest Rate Agreements and related Hedging Obligations, which transactions or obligations are Incurred in compliance with "Certain Covenants—Limitation on Indebtedness;"

(11) Guarantees issued in accordance with "Certain Covenants—Limitation on Indebtedness;"

(12) any transaction referred to in clause (8) of the definition of "Asset Disposition;"

(13) Permitted Business Investments or Investments in Employee Partnerships;

(14) Investments held by any Person at the time such Person is acquired by or merges with or into the Company or any Restricted Subsidiary, provided that such Investments were not entered into in anticipation of such acquisition or merger, and extensions or renewals or replacements thereof that do not increase the amount of such Investment; and

(15) Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (15), in an aggregate amount at the time of such Investment not to exceed the greater of (a) 2.5% of Adjusted Consolidated Net Tangible Assets and (b) $40.0 million, in each case outstanding at any one time (with the fair market value of such Investment being measured at the time made and without giving effect to subsequent changes in value).

"Permitted Liens" means, with respect to any Person:

(1) Liens securing Indebtedness and other obligations under any Credit Facility permitted to be Incurred under the Indenture;

(2) pledges or deposits by such Person under workmen's compensation laws, unemployment insurance laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure public or statutory obligations of such Person or deposits of cash or United States government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;

(3) Liens imposed by law, including carriers', warehousemen's, mechanics' materialmen's and repairmen's Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if a reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made in respect thereof;

(4) Liens for taxes, assessments or other governmental charges not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings; provided that appropriate reserves required pursuant to GAAP have been made in respect thereof;

(5) Liens in favor of issuers of surety or performance bonds or letters of credit or bankers' acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business; provided, however, that such letters of credit do not constitute Indebtedness;

(6) encumbrances, ground leases, easements or reservations of, or rights of others for, licenses, rights of way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning, building codes or other restrictions (including, without limitation, minor

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defects or irregularities in title and similar encumbrances) as to the use of real properties or liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(7) Liens securing Hedging Obligations;

(8) leases, licenses, subleases and sublicenses of assets (including, without limitation, real property and intellectual property rights) which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;

(9) judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10) Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capitalized Lease Obligations, purchase money obligations or other payments Incurred to finance the acquisition, lease, improvement or construction of, assets or property acquired or constructed in the ordinary course of business; provided that:

(a) the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture and does not exceed the cost of the assets or property so acquired or constructed; and

(b) such Liens are created within 180 days of construction or acquisition of such assets or property and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11) Liens arising solely by virtue of any statutory or common law provisions relating to banker's Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b) such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(13) Liens existing on the Issue Date;

(14) Liens on property or shares of stock of a Person at the time such Person becomes a Restricted Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such other Person becoming a Restricted Subsidiary; provided further, however, that any such Lien may not extend to any other property owned by the Company or any Restricted Subsidiary;

(15) Liens on property at the time the Company or a Restricted Subsidiary acquired the property, including any acquisition by means of a merger or consolidation with or into the Company or any Restricted Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such acquisition; provided,

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further, however, that such Liens may not extend to any other property owned by the Company or any Restricted Subsidiary;

(16) Liens securing Indebtedness or other obligations of a Restricted Subsidiary owing to the Company or a Wholly-Owned Subsidiary;

(17) Liens securing the Notes, Subsidiary Guarantees and other obligations under the Indenture;

(18) Liens securing obligations under Refinancing Indebtedness Incurred to refinance, refund, replace, amend, extend or modify Indebtedness that was previously so secured (other than Liens permitted pursuant to clause (1) above), provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property that is the security for a Permitted Lien hereunder;

(19) any interest or title of a lessor under any Capitalized Lease Obligation or operating lease;

(20) Liens in respect of Production Payments and Reserve Sales, which Liens shall be limited to the property that is the subject of such Production Payments and Reserve Sales;

(21) Liens arising under farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, operating agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;

(22) Liens on pipelines or pipeline facilities that arise by operation of law; and

(23) Liens securing obligations under Indebtedness (other than Subordinated Obligations and Guarantor Subordinated Obligations) in an aggregate principal amount outstanding at any one time not to exceed $20.0 million.

"Person" means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision hereof or any other entity.

"Preferred Stock," as applied to the Capital Stock of any corporation, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such corporation, over shares of Capital Stock of any other class of such corporation.

"Production Payments and Reserve Sales" means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in oil and gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including

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any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or a Restricted Subsidiary.

"Rating Agencies" means Moody's and S&P or if Moody's or S&P or both shall not make a rating on the Notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by the Company which shall be substituted for Moody's or S&P or both, as the case may be.

"Refinancing Indebtedness" means Indebtedness that is Incurred to refund, refinance, replace, exchange, renew, repay or extend (including pursuant to any defeasance or discharge mechanism) (collectively, "refinance," "refinances," and "refinanced" shall have a correlative meaning) any Indebtedness existing on the date of the Indenture or Incurred in compliance with the Indenture (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary) including Indebtedness that refinances Refinancing Indebtedness, provided, however, that:

(1) (a) if the Stated Maturity of the Indebtedness being refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;

(2) the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;

(3) such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest or premiums required by the instruments governing such existing Indebtedness and fees and expenses Incurred in connection therewith); and

(4) if the Indebtedness being refinanced is subordinated in right of payment to the Notes or a Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantee on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

"Registration Rights Agreements" means that certain registration rights agreement dated as of October 1, 2013 by and among the Company, the Subsidiary Guarantors and the initial purchaser set forth therein and, with respect to any Additional Notes, one or more substantially similar registration rights agreements among the Company and the other parties thereto, as such agreements may be amended from time to time.

"Related Person" with respect to any Permitted Holder means:

(1) any controlling stockholder or a majority (or more) owned Subsidiary of such Permitted Holder or, in the case of an individual, any spouse, family member, (including adopted children), heir or descendant of such Permitted Holder, any trust created for the benefit of such individual or such individual's estate, executor, administrator, committee or beneficiaries; or

(2) any trust, corporation, partnership or other entity, the beneficiaries, stockholders, partners, owners or Persons beneficially holding a majority (or more) controlling interest of which

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consist of such Permitted Holder and/or such other Persons referred to in the immediately preceding clause (1).

"Restricted Investment" means any Investment other than a Permitted Investment.

"Restricted Subsidiary" means any Subsidiary of the Company other than an Unrestricted Subsidiary.

"Sale/Leaseback Transaction" means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

"SEC" means the United States Securities and Exchange Commission.

"Senior Secured Credit Agreement" means the Second Amended and Restated Credit Agreement, dated November 29, 2010, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto from time to time, as the same may be amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (including increasing the amount loaned thereunder; provided that such additional Indebtedness is Incurred in accordance with the covenant described under "—Limitation on Indebtedness").

"Significant Subsidiary" means any Restricted Subsidiary that would be a "Significant Subsidiary" of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC.

"Stated Maturity" means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

"Subordinated Obligation" means any Indebtedness of the Company (whether outstanding on the Issue Date or thereafter Incurred) which is subordinate or junior in right of payment to the Notes pursuant to a written agreement.

"Subsidiary" of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total ordinary voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof (or persons performing similar functions) or (b) any partnership, joint venture, limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary will refer to a Subsidiary of the Company.

"Subsidiary Guarantee" means, individually, any Guarantee of payment of the Notes and exchange notes issued in a registered exchange offer pursuant to the Registration Rights Agreements by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such Guarantees. Each such Subsidiary Guarantee will be in the form prescribed by the Indenture.

"Subsidiary Guarantor" means the Restricted Subsidiaries of the Company who are party to the Indenture on the Issue Date and any other Restricted Subsidiary of the Company that later becomes a Subsidiary Guarantor in accordance with the Indenture.

"SWR Partnerships" means the oil and gas limited partnerships of which Southwest Royalties, Inc. (a wholly-owned subsidiary of the Company) is general partner, as of the Issue Date, and any successor to any such partnerships.

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"Total Assets" means, with respect to any Person, the total consolidated assets of such Person and its Restricted Subsidiaries, as shown on the most recent balance sheet of such Person.

"Unrestricted Subsidiary" means:

(1) any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and

(2) any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1) such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;

(2) all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;

(3) on the date of such designation, such designation and the Investment of the Company in such Subsidiary complies with "Certain Covenants—Limitation on Restricted Payments;"

(4) such Subsidiary, either alone or in the aggregate with all other Unrestricted Subsidiaries, does not operate, directly or indirectly, all or substantially all of the business of the Company and its Subsidiaries;

(5) such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation:

(a) to subscribe for additional Capital Stock of such Person; or

(b) to maintain or preserve such Person's financial condition or to cause such Person to achieve any specified levels of operating results; and

(6) on the date such Subsidiary is designated an Unrestricted Subsidiary, such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms substantially less favorable to the Company than those that might have been obtained from Persons who are not Affiliates of the Company.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers' Certificate certifying that such designation complies with the foregoing conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could Incur at least $1.00 of additional Indebtedness under the first paragraph of the "Limitation on Indebtedness" covenant on a pro forma basis taking into account such designation.

"U.S. Government Obligations" means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations

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of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

"Volumetric Production Payments" means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

"Voting Stock" of a corporation means all classes of Capital Stock of such corporation then outstanding and normally entitled to vote in the election of directors.

"Wholly-Owned Subsidiary" means a Restricted Subsidiary, all of the Capital Stock of which (other than directors' qualifying shares) is owned by the Company or another Wholly-Owned Subsidiary.

Book-Entry, Delivery and Form

The Notes will be represented by one or more notes in registered, global form without interest coupons (collectively, the "Global Notes"). The Global Notes will be deposited with the Trustee as custodian for The Depository Trust Company ("DTC"), in New York, New York, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below.

Except as set forth below, the Global Notes may be transferred, in whole but not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for definitive new Notes in registered certificated form ("Certificated Notes") new Notes except in the limited circumstances described below. See "—Exchange of Global Notes for Certificated Notes." Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of Certificated Notes.

Depositary Procedures

The following description of the operations and procedures of DTC is provided solely as a matter of convenience. These operations and procedures are solely within the control of DTC's settlement system and are subject to changes by DTC. We take no responsibility for these operations and procedures and urge investors to contact DTC or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the "Participants") and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the banks), banks, trust companies, clearing corporations and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the "Indirect Participants"). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants.

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The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised us that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the initial purchaser with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Notes).

Investors in the Global Notes who are Participants in DTC's system may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations which are Participants in such system.

The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of an interest in the Global Notes will not have Notes registered in their names, will not receive physical delivery of certificated Notes and will not be considered the registered owners or "Holders" thereof under the Indenture for any purpose.

Payments in respect of the principal of, and interest, premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered Holder under the Indenture. Under the terms of the Indenture, the Company and the Trustee will treat the Persons in whose names the new Notes, including the Global Notes, are registered as the owners of the new Notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Company, the Trustee nor any agent of the Company or the Trustee has or will have any responsibility or liability for:

(1) any aspect of DTC's records or any Participant's or Indirect Participant's records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC's records or any Participant's or Indirect Participant's records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, at the due date of any payment in respect of securities such as the new Notes, is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of new Notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee or the Company. Neither the Company nor the Trustee will be liable for any delay by DTC or any of its Participants or Indirect Participants in identifying the beneficial owners of the new Notes, and the Company and the Trustee

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may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between Participants will be effected in accordance with DTC's procedures, and will be settled in same-day funds.

DTC has advised us that it will take any action permitted to be taken by a Holder of Notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the Notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the Notes, DTC reserves the right to exchange the Global Notes for legended new Notes in registered certificated form, and to distribute such new Notes to its Participants.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes, if:

(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and in either event the Company fails to appoint a successor depositary within 90 days; or

(2) there has occurred and is continuing an Event of Default and DTC notifies the Trustee of its decision to exchange the Global Note for Certificated Notes.

Beneficial interests in a Global Note also may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in the limited other circumstances permitted by the Indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear a restrictive legend, unless that legend is not required by applicable law.

Exchange of Certificated Notes for Global Notes

Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the Trustee a written certificate (in the form provided in the Indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such new Notes.

Same Day Settlement and Payment

The Company will make payments in respect of the new Notes represented by the Global Notes (including principal, interest and premium, if any) by wire transfer of immediately available funds to the accounts specified by the Global Note Holder. The Company will make all payments of principal, interest and premium, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the Holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such Holder's registered address. The new Notes represented by the Global Notes are expected to be eligible to trade in DTC's Same-Day Funds Settlement System, and any permitted secondary market trading activity in such new Notes will, therefore, be required by DTC to be settled in immediately available funds. The Company expects that secondary trading in any Certificated Notes will also be settled in immediately available funds.

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PLAN OF DISTRIBUTION

You may transfer new notes issued under the exchange offer in exchange for the old notes if:

•: you acquire the new notes in the ordinary course of your business;
•: you have no arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of such new notes in violation of the provisions of the Securities Act; and
•: you are not our "affiliate" (within the meaning of Rule 405 under the Securities Act).

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We and the subsidiary guarantors have agreed that, starting on the expiration date of the exchange offer and ending on the close of business 180 days after the date of such expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale.

If you wish to exchange new notes for your old notes in the exchange offer, you will be required to make representations to us as described in "Exchange Offer—Purpose and Effect of the Exchange Offer" and "—Procedures for Tendering—Your Representations to Us" in this prospectus and in the letter of transmittal. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale by you of such new notes.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time on one or more transactions in any of the following ways:

•: in the over-the-counter market;
•: in negotiated transactions;
•: through the writing of options on the new notes or a combination of such methods of resale;
•: at market prices prevailing at the time of resale;
•: at prices related to such prevailing market prices; or
•: at negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes.

Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities may be deemed to be an "underwriter" within the meaning of the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. We agreed to permit the use of this prospectus for a period of up to 180 days after the completion of the exchange offer by such broker-dealers to satisfy this prospectus

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delivery requirement. Furthermore, we agree to amend or supplement this prospectus during such period if so requested in order to expedite or facilitate the disposition of any new notes by broker-dealers.

We have agreed to pay all expenses incident to the exchange offer other than fees and expenses of counsel to the holders and brokerage commissions and transfer taxes, if any, and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

The following discussion is a summary of material federal income tax considerations relevant to the exchange of old notes for new notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended (the "Code"), Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. We cannot assure you that the Internal Revenue Service will not challenge one or more of the tax considerations described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the IRS or an opinion of counsel with respect to the U.S. federal income tax consequences described herein. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, persons whose functional currency is not the U.S. dollar, or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below. We recommend that each holder consult his own tax advisor as to the holder's particular tax consequences of exchanging such holder's old notes for new notes, including the applicability and effect of any foreign, state, local or other tax laws or estate or gift tax considerations.

We believe that the exchange of old notes for new notes will not be an exchange or otherwise a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange, and the holder's tax basis and holding period in the new note will be the same as its tax basis and holding period in the corresponding old note immediately before the exchange.

LEGAL MATTERS

The validity of the new notes offered in this exchange offer will be passed upon for us by Vinson & Elkins L.L.P.

EXPERTS

The consolidated financial statements of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and for each of the years in the three-year period ended December 31, 2012, and management's assessment of the effectiveness of internal control over financial reporting as of December 31, 2012 have been included herein in reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

Certain information included in this prospectus regarding estimated quantities of oil and natural gas reserves owned by us, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from reports of Williamson Petroleum Consultants, Inc., independent oil and gas consultants, and Ryder Scott Company, L.P., independent engineering consultants, and has been included in this prospectus in reliance on the authority of said firms as experts in giving such reports and regarding the matters contained in their reports.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements, and other information with the Securities and Exchange Commission. You may read and copy any materials that we have filed with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding us. The SEC's website address iswww.sec.gov. You may also inspect our SEC reports and other information at the New York Stock Exchange, 20 Broad Street, New York, New York 10005, or at our website athttp://www.claytonwilliams.com. We do not intend for information contained in our website to be part of this prospectus.

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INDEX TO FINANCIAL STATEMENTS


Unaudited Consolidated Financial Statements
Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012			F-2
Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three Months Ended September 30, 2013 and 2012 and for the Nine Months Ended September 30, 2013 and 2012			F-4
Consolidated Statement of Stockholders' Equity			F-5
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012			F-6
Notes to Consolidated Financial Statements			F-7
Audited Financial Statements
Report of Independent Registered Public Accounting Firm			F-29
Consolidated Balance Sheets as of December 31, 2012 and 2011			F-30
Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2012, 2011 and 2010			F-32
Consolidated Statements of Stockholders' Equity			F-33
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010			F-34
Notes to Consolidated Financial Statements			F-35
Report of Independent Registered Public Accounting Firm			F-61
Supplemental Information
Supplemental Quarterly Financial Data			S-1
Supplemental Oil and Gas Reserve Information			S-2

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	September 30, 2013			December 31, 2012

	(unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	23,209		$	10,726
Accounts receivable:
Oil and gas sales		37,828			32,371
Joint interest and other, net of allowance for doubtful accounts of $1,181 at September 30, 2013 and $1,193 at December 31, 2012		10,173			16,767
Affiliates		27,544			353
Inventory		36,986			41,703
Deferred income taxes		10,623			8,560
Fair value of derivatives		2,139			7,495
Prepaids and other		8,219			6,495


		156,721			124,470


PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		2,364,117			2,570,803
Pipelines and other midstream facilities		52,693			49,839
Contract drilling equipment		94,260			91,163
Other		20,574			20,245


		2,531,644			2,732,050
Less accumulated depreciation, depletion and amortization		(1,334,165	)		(1,311,692	)


Property and equipment, net		1,197,479			1,420,358


OTHER ASSETS
Debt issue costs, net		8,074			10,259
Fair value of derivatives		1,038			4,236
Investments and other		16,398			15,261


		25,510			29,756


	$	1,379,710		$	1,574,584

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS' EQUITY

	September 30, 2013		December 31, 2012

	(unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	67,232	$	73,026
Oil and gas sales		35,458		32,146
Affiliates		647		164
Accrued liabilities and other		21,961		15,578


		125,298		120,914


NON-CURRENT LIABILITIES
Long-term debt		672,625		809,585
Deferred income taxes		139,202		155,830
Asset retirement obligations		49,647		51,477
Deferred revenue from volumetric production payment		31,579		37,184
Accrued compensation under non-equity award plans		13,121		20,058
Other		909		920


		907,083		1,075,054


COMMITMENTS AND CONTINGENCIES (Note 15)
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—12,164,536 shares at September 30, 2013 and December 31, 2012		1,216		1,216
Additional paid-in capital		152,527		152,527
Retained earnings		193,586		224,873


		347,329		378,616


	$	1,379,710	$	1,574,584

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(In thousands, except per share)

	Three Months Ended September 30,						Nine Months Ended September 30,

	2013			2012			2013			2012
REVENUES
Oil and gas sales	$	104,004		$	101,638		$	296,146		$	308,116
Midstream services		1,146			671			3,373			1,305
Drilling rig services		4,044			5,348			12,896			11,478
Other operating revenues		1,971			106			4,533			543


Total revenues		111,165			107,763			316,948			321,442


COSTS AND EXPENSES
Production		25,651			32,564			83,254			93,937
Exploration:
Abandonments and impairments		609			306			2,980			2,292
Seismic and other		177			2,710			3,541			5,445
Midstream services		392			508			1,318			956
Drilling rig services		3,239			5,335			12,704			12,164
Depreciation, depletion and amortization		34,928			37,661			109,863			103,486
Impairment of property and equipment		709			—			89,811			5,711
Accretion of asset retirement obligations		1,049			1,069			3,169			2,628
General and administrative		10,030			5,830			20,401			25,133
Other operating expenses		463			207			1,869			485


Total costs and expenses		77,247			86,190			328,910			252,237
												��

Operating income (loss)		33,918			21,573			(11,962	)		69,205


OTHER INCOME (EXPENSE)
Interest expense		(9,262	)		(9,786	)		(30,106	)		(27,817	)
Gain (loss) on derivatives		(8,278	)		(21,901	)		(9,919	)		9,856
Other		474			(559	)		2,007			739


Total other income (expense)		(17,066	)		(32,246	)		(38,018	)		(17,222	)


Income (loss) before income taxes		16,852			(10,673	)		(49,980	)		51,983
Income tax (expense) benefit		(5,901	)		3,497			18,693			(18,558	)


NET INCOME (LOSS)	$	10,951		$	(7,176	)	$	(31,287	)	$	33,425




Net income (loss) per common share:
Basic	$	0.90		$	(0.59	)	$	(2.57	)	$	2.75




Diluted	$	0.90		$	(0.59	)	$	(2.57	)	$	2.75




Weighted average common shares outstanding:
Basic		12,165			12,164			12,165			12,164




Diluted		12,165			12,164			12,165			12,164

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(Unaudited)

(In thousands)

	Common Stock

	No. of Shares		Par Value		Additional Paid-In Capital		Retained Earnings			Total Stockholders' Equity
BALANCE,
December 31, 2012		12,165	$	1,216	$	152,527	$	224,873		$	378,616
Net loss		—		—		—		(31,287	)		(31,287	)


BALANCE,
September 30, 2013		12,165	$	1,216	$	152,527	$	193,586		$	347,329

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months Ended September 30,

	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(31,287	)	$	33,425
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		109,863			103,486
Impairment of property and equipment		89,811			5,711
Abandonments and impairments		2,980			2,292
Gain on sales of assets and impairment of inventory, net		(1,527	)		(58	)
Deferred income tax expense (benefit)		(18,693	)		18,558
Non-cash employee compensation		(5,897	)		2,200
(Gain) loss on derivatives		9,919			(9,856	)
Cash settlements of derivatives		(1,364	)		(4,961	)
Accretion of asset retirement obligations		3,169			2,628
Amortization of debt issue costs and original issue discount		2,281			1,587
Amortization of deferred revenue from volumetric production payment		(6,639	)		(5,862	)
Changes in operating working capital:
Accounts receivable		(188	)		7,150
Accounts payable		(4,060	)		(5,772	)
Other		5,513			7,355


Net cash provided by operating activities		153,881			157,883


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(208,022	)		(438,482	)
Proceeds from volumetric production payment		1,034			45,032
Proceeds from sales of assets		197,941			867
Decrease in equipment inventory		5,818			64
Other		(1,169	)		(195	)


Net cash used in investing activities		(4,398	)		(392,714	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		43,000			240,000
Repayments of long-term debt		(180,000	)		—


Net cash provided by (used in) financing activities		(137,000	)		240,000


NET INCREASE IN CASH AND CASH EQUIVALENTS		12,483			5,169
CASH AND CASH EQUIVALENTS
Beginning of period		10,726			17,575


End of period	$	23,209		$	22,694




SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	20,968		$	19,295

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2013

(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 CWEI's outstanding Common Stock is beneficially owned by Clayton W. Williams, Jr. ("Mr. Williams"), Chairman of the Board, President and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams' adult children are limited partners.

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

2. Presentation

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

The consolidated financial statements include the accounts of CWEI and its wholly-owned subsidiaries. We account for our undivided interest in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships. Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships. Substantially all intercompany transactions and balances associated with the consolidated operations have been eliminated.

In the opinion of management, our unaudited consolidated financial statements as of September 30, 2013 and for the three and nine month periods ended September 30, 2013 and 2012 include all adjustments, which are of a normal and recurring nature, 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, 2013.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with GAAP have been condensed or omitted in this prospectus pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). These

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

2. Presentation (Continued)

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, 2012.

3. Long-Term Debt

Long-term debt consists of the following:

	September 30, 2013		December 31, 2012

	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $375 at September 30, 2013 and $415 at December 31, 2012	$	349,625	$	349,585
Revolving credit facility, due November 2015		323,000		460,000


	$	672,625	$	809,585

Senior Notes

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

Effective October 1, 2013, we issued an additional $250 million aggregate principal amount of 2019 Senior Notes at par. The notes were sold at 100% of par to yield 7.75% to maturity. These 2019 Senior Notes and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture (see Note 19).

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

3. Long-Term Debt (Continued)

Revolving Credit Facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $470 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 our revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.

In connection with the sale of our Andrews County assets discussed in Note 5, we entered into an amendment to our revolving credit facility, pursuant to which the banks decreased the aggregate commitment and borrowing base under our revolving credit facility from $585 million to $470 million in April 2013. At September 30, 2013, we had $323 million of borrowings outstanding under our revolving credit facility, leaving $141.9 million available under the facility after allowing for outstanding letters of credit totaling $5.1 million. On October 1, 2013, we used the net proceeds from our issuance of an additional $250 million aggregate principal amount of 2019 Senior Notes to repay outstanding indebtedness under our revolving credit facility. In connection with the issuance of the additional 2019 Senior Notes the borrowing base was reduced to $407.5 million. After giving pro forma effect to the application of net proceeds and the reduction in borrowing base, we had $323.4 million available as of September 30, 2013.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

3. Long-Term Debt (Continued)

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. In connection with the issuance of additional Senior Notes due 2019 effective October 1, 2013, the consolidated funded indebtedness ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014. The computations of consolidated current assets, current liabilities, EBITDAX and funded indebtedness are defined in our revolving credit facility. We were in compliance with all financial and non-financial covenants at September 30, 2013 and December 31, 2012.

4. Acquisition of Southwest Royalties, Inc. Limited Partnerships

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

To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment ("VPP") with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million. Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725,000 barrels of oil equivalents ("BOE") of estimated future oil and gas production from certain properties derived from the mergers. The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and are to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties. Once the scheduled volumes have been delivered to the third party, the term overriding royalty interest will terminate. SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks related to the adequacy of the associated reserves to fully recoup the scheduled volumes and also assumed all risks associated with product prices. As a result, the VPP has been accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes are produced (see Note 7).

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

4. Acquisition of Southwest Royalties, Inc. Limited Partnerships (Continued)

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


Cash and cash equivalents	$	4,118
Oil and gas properties		41,098
Other non-current assets		210


Total assets acquired		45,426
Asset retirement obligations		(6,864	)


Total liabilities assumed		(6,864	)


Net assets acquired	$	38,562

5. Sales of Assets

On April 24, 2013, we closed a transaction to monetize a substantial portion of our Andrews County Wolfberry oil and gas reserves, leasehold interests and facilities (the "Assets"). The Assets accounted for approximately 20% of our total proved reserves at December 31, 2012. At closing, we contributed 5% of the Assets to a newly formed limited partnership in exchange for a 5% general partner interest, and a unit of GE Energy Financial Services contributed cash of $215.2 million to the limited partnership in exchange for a 95% limited partnership interest. The limited partnership then purchased 95% of the Assets from us for $215.2 million, subject to customary closing adjustments, with $26.5 million being placed in escrow pending resolution of certain title requirements. If the title requirements are not satisfied, waived or extended within 180 days, the affected properties will be conveyed back to us and the escrowed funds will be returned to the limited partner. As of October 15, 2013, the buyer has exercised its right to extend the post-closing cure deadline an additional 180 days. We believe that the defects will be cured timely and have a remaining $25.9 million escrow balance as an account receivable from affiliate in the accompanying consolidated balance sheet at September 30, 2013. Upon the attainment by the limited partner of predetermined rates of return, our general partner interest in the partnership may increase.

6. Asset Retirement Obligations

We record asset retirement obligations ("ARO") associated with the retirement of our long-lived assets in the period in which they are incurred and become determinable. Under this method, we record a liability for the expected future cash outflows discounted at our credit-adjusted risk-free interest rate for the dismantlement and abandonment costs, excluding salvage values, of each oil and gas property. We also record an asset retirement cost to the oil and gas properties equal to the ARO

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

6. Asset Retirement Obligations (Continued)

liability. The fair value of the asset retirement cost and the ARO liability 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. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.

The following table reflects the changes in the ARO during the nine months ended September 30, 2013 and the year ended December 31, 2012:

	September 30, 2013			December 31, 2012

	(In thousands)
Beginning of period	$	51,477		$	40,794
Additional ARO from new properties		453			7,868
Sales or abandonments of properties		(4,863	)		(2,184	)
Accretion expense		3,169			3,696
Revisions of previous estimates		(589	)		1,303


End of period	$	49,647		$	51,477

7. Deferred Revenue from Volumetric Production Payment

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

The following table reflects the changes in the deferred revenue during the nine months ended September 30, 2013 and the year ended December 31, 2012:

	September 30, 2013			December 31, 2012

	(In thousands)
Beginning of period	$	37,184		$	—
Deferred revenue from VPP		1,034			45,479
Amortization of deferred revenue from VPP		(6,639	)		(8,295	)


End of period	$	31,579		$	37,184

Under the terms of the VPP, SWR conveyed to a third party a term overriding royalty interest covering approximately 725,000 BOE of estimated future oil and gas production. As of September 30, 2013, we have a remaining obligation to deliver approximately 514,000 BOE.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

8. Compensation Plans

Stock-Based Compensation

We presently have options outstanding under a stock option plan for independent directors covering 5,000 shares of Common Stock. As of September 30, 2013, the options had a weighted average exercise price of $32.21 per share (ranging from $22.90 per share to $41.74 per share), a weighted average remaining contractual term of 2.3 years, and an aggregate intrinsic value of $101,310 (based on a market price at September 30, 2013 of $52.47 per share). No options were granted during the nine months ended September 30, 2013 or 2012.

Non-Equity Award Plans

The Compensation Committee of the Board has adopted an after-payout ("APO") incentive plan (the "APO Incentive Plan") for officers, key employees and consultants who promote our drilling and acquisition programs. The Compensation Committee's objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, by the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes ("APO Partnerships"), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas. Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest ("payout"). At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships. Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan. We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements. Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.

The Compensation Committee has also adopted an APO reward plan (the "APO Reward Plan") which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to the 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 17 specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each award, which dates range from January 1, 2007 to May 1, 2013. Of these 17 awards, one award fully vested on November 4, 2011, three awards fully vested on August 9, 2012, three awards fully vested on May 5, 2013, six awards fully vested on June 1, 2013, two will fully vest on May 1, 2015 and two will fully vest on August 1, 2015.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

8. Compensation Plans (Continued)

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

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

We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the vesting periods, which range from two years to five years. Compensation expense (credit) related to non-equity award plans for the three months ended September 30, 2013 and 2012 and for the nine months ended September 30, 2013 and 2012 were $1.2 million, ($2.2) million, ($5.9) million and $2.2 million, respectively. Credits to expense resulted from the reversal of previously accrued compensation expense attributable to a combination of actual payments of accrued compensation and changes in estimates of future compensation expense.

Aggregate compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule:

	September 30, 2013		December 31, 2012

	(In thousands)
Current liabilities:
Accrued liabilities and other	$	3,262	$	2,220
Non-current liabilities:
Accrued compensation under non-equity award plans		13,121		20,058


Total accrued compensation under non-equity award plans	$	16,383	$	22,278

9. 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.

In October 2013, we entered into swap agreements with a counterparty covering 1 million barrels of our 2014 oil production at a price of $96.10 per barrel.

In December 2013, we entered into swap agreements with a counterparty covering 600,000 barrels of our 2014 oil production at a price of $95.58 per barrel.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

9. Derivatives (Continued)

Swaps:

	Oil				Gas

	Bbls		Price		MMBtu(a)		Price
Production Period:
4th Quarter 2013		300,000	$	104.60		330,000	$	3.34
2014		2,200,000	$	96.83		—	$	—


		2,500,000				330,000

(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 consolidated statements of operations and comprehensive income (loss).

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of September 30, 2013

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	2,139	Current	$	—
	Non-current		1,038	Non-current		—


Total		$	3,177		$	—

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

9. Derivatives (Continued)

	Fair Value of Derivative Instruments as of December 31, 2012

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	7,495	Current	$	—
	Non-current		4,236	Non-current		—


Total		$	11,731		$	—

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	September 30, 2013

	Assets			Liabilities
	(In thousands)
Fair value of derivatives—gross presentation	$	3,286		$	109
Effects of netting arrangements		(109	)		(109	)


Fair value of derivatives—net presentation	$	3,177		$	—

	December 31, 2012

	Assets			Liabilities
	(In thousands)
Fair value of derivatives—gross presentation	$	17,851		$	6,120
Effects of netting arrangements		(6,120	)		(6,120	)


Fair value of derivatives—net presentation	$	11,731		$	—

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

9. Derivatives (Continued)

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

	Amount of Gain or (Loss) Recognized in Earnings

	Three Months Ended September 30, 2013									Nine Months Ended September 30, 2013
Location of Gain or (Loss) Recognized in Earnings	Realized			Unrealized			Total			Realized			Unrealized			Total
	(In thousands)									(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense)—Gain (loss) on derivatives	$	(455	)	$	(7,823	)	$	(8,278	)	$	(1,364	)	$	(8,555	)	$	(9,919	)


Total	$	(455	)	$	(7,823	)	$	(8,278	)	$	(1,364	)	$	(8,555	)	$	(9,919	)

	Amount of Gain or (Loss) Recognized in Earnings

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


Total	$	(1,390	)	$	(20,511	)	$	(21,901	)	$	(4,961	)	$	14,817	$	9,856

10. Financial Instruments

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

Fair Value Measurements

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

10. Financial Instruments (Continued)

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.

The financial assets and liabilities measured on a recurring basis at September 30, 2013 and December 31, 2012 were commodity derivatives. The fair value of all derivative contracts is reflected on the consolidated balance sheet as detailed in the following schedule:

	Significant Other Observable Inputs (Level 2)

Description	September 30, 2013		December 31, 2012
	(In thousands)
Assets:
Fair value of commodity derivatives	$	3,177	$	11,731


Total assets	$	3,177	$	11,731




Liabilities:
Fair value of commodity derivatives	$	—	$	—


Total liabilities	$	—	$	—

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

10. Financial Instruments (Continued)

Fair Value of Other Financial Instruments

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

	September 30, 2013				December 31, 2012

Description	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
7.75% Senior Notes due 2019	$	349,625	$	348,250	$	349,585	$	348,700

11. Income Taxes

Our effective federal and state income tax rate for the nine months ended September 30, 2013 of 37.4% 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 and state income tax returns in various state tax jurisdictions. Our tax returns for fiscal years after 2009 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time.

12. Other Operating Revenues and Expenses

Net other operating revenues and expenses for the three months and nine months ended September 30, 2013 and September 30, 2012 are as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,

	2013		2012		2013		2012
	(In thousands)				(In thousands)
Other operating revenues:
Gain on sales of assets	$	1,971	$	106	$	2,738	$	543
Net marketing revenue		—		—		1,795		—


Total other operating revenues	$	1,971	$	106	$	4,533	$	543




Other operating expenses:
Loss on sales of assets	$	39	$	38	$	1,084	$	38
Net marketing expense		302		—		658		—
Impairment of inventory		122		169		127		447


Total other operating expenses	$	463	$	207	$	1,869	$	485

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

12. Other Operating Revenues and Expenses (Continued)

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.

13. Investment in Dalea Investment Group, LLC

In June 2012, we cancelled an $11 million note receivable in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC ("Dalea"), an international oilfield services company formed in March 2012. Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea is carried at cost of $11 million. As of September 30, 2013, we have performed a qualitative assessment and determined there has been no indication of any impairment of our investment in Dalea.

14. Costs of Oil and Gas Properties

The following sets forth the net capitalized costs for oil and gas properties as of September 30, 2013 and December 31, 2012.

	September 30, 2013			December 31, 2012

	(In thousands)
Proved properties	$	2,267,590		$	2,482,185
Unproved properties		96,527			88,618


Total capitalized costs		2,364,117			2,570,803
Accumulated depletion		(1,244,965	)		(1,234,626	)


Net capitalized costs	$	1,119,152		$	1,336,177

15. Commitments and Contingencies

Legal Proceedings

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

15. Commitments and Contingencies (Continued)

16. 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 recorded a provision for impairment of proved properties of $709,000 for the three months ended September 30, 2013, and there were no provisions for impairment of proved properties for the three months ended September 30, 2012. We recorded a provision for impairment of proved properties of $89.8 million for the nine months ended September 30, 2013 and $5.7 million for the nine months ended September 30, 2012. The impairment for the three months ended September 30, 2013 was related to the write down of certain non-core Permian Basin properties to their estimated fair value. The impairment for the nine months ended September 30, 2013 was related to the write down of our Andrews County Wolfberry assets and certain non-core Permian Basin properties to their estimated fair value. The impairments for the nine months ended September 30, 2012 related to non-core areas in the Permian Basin to reduce the carrying values of those properties to their estimated fair value.

Unproved properties are nonproducing and do not have estimable cash flow streams. Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to the proximity of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors. Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects. Based on the assessments previously discussed, we will impair our unproved oil and gas properties when we determine that a prospect's carrying value exceeds its estimated fair value. We categorize the measurement of fair value of unproved properties as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $568,000 for the three months ended September 30, 2013 and $187,000 for the three months ended September 30, 2012, and $944,000 for the nine months ended September 30, 2013 and $711,000 for the nine months ended September 30, 2012, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

17. Segment Information

We have two reportable operating segments, which are (1) oil and gas exploration and production and (2) contract drilling services.

The following tables present selected financial information regarding our operating segments for the three months and nine months ended September 30, 2013 and 2012:

For the Three Months Ended September 30, 2013 (Unaudited) (In thousands)	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total

Revenues	$	107,121		$	9,021		$	(4,977	)	$	111,165
Depreciation, depletion and amortization(a)		32,941			3,340			(644	)		35,637
Other operating expenses(b)		38,289			7,144			(3,823	)		41,610
Interest expense		9,262			—			—			9,262
Other (income) expense		7,804			—			—			7,804


Income (loss) before income taxes		18,825			(1,463	)		(510	)		16,852
Income tax (expense) benefit		(6,414	)		513			—			(5,901	)


Net income (loss)	$	12,411		$	(950	)	$	(510	)	$	10,951




Total assets	$	1,352,645		$	54,524		$	(27,459	)	$	1,379,710




Additions to property and equipment	$	64,775		$	1,494		$	(510	)	$	65,759

For the Nine Months Ended September 30, 2013 (Unaudited) (In thousands)	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total

Revenues	$	304,052		$	26,660		$	(13,764	)	$	316,948
Depreciation, depletion and amortization(a)		190,813			10,728			(1,867	)		199,674
Other operating expenses(b)		116,319			24,705			(11,788	)		129,236
Interest expense		30,106			—			—			30,106
Other (income) expense		7,912			—			—			7,912


Income (loss) before income taxes		(41,098	)		(8,773	)		(109	)		(49,980	)
Income tax (expense) benefit		15,622			3,071			—			18,693


Net income (loss)	$	(25,476	)	$	(5,702	)	$	(109	)	$	(31,287	)




Total assets	$	1,352,645		$	54,524		$	(27,459	)	$	1,379,710




Additions to property and equipment	$	200,949		$	3,097		$	(109	)	$	203,937

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

17. Segment Information (Continued)

For the Three Months Ended September 30, 2012 (Unaudited) (In thousands)	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total

Revenues	$	102,415		$	14,869		$	(9,521	)	$	107,763
Depreciation, depletion and amortization(a)		35,580			3,666			(1,585	)		37,661
Other operating expenses(b)		43,117			13,169			(7,757	)		48,529
Interest expense		9,786			—			—			9,786
Other (income) expense		22,463			(3	)		—			22,460


Income (loss) before income taxes		(8,531	)		(1,963	)		(179	)		(10,673	)
Income tax (expense) benefit		2,810			687			—			3,497


Net income (loss)	$	(5,721	)	$	(1,276	)	$	(179	)	$	(7,176	)




Total assets	$	1,504,338		$	63,731		$	(21,530	)	$	1,546,539




Additions to property and equipment	$	107,178		$	3,023		$	(179	)	$	110,022

For the Nine Months Ended September 30, 2012 (Unaudited) (In thousands)	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total

Revenues	$	309,964		$	46,134		$	(34,656	)	$	321,442
Depreciation, depletion and amortization(a)		104,416			10,703			(5,922	)		109,197
Other operating expenses(b)		130,668			40,963			(28,591	)		143,040
Interest expense		27,817			—			—			27,817
Other (income) expense		(10,592	)		(3	)		—			(10,595	)


Income (loss) before income taxes		57,655			(5,529	)		(143	)		51,983
Income tax (expense) benefit		(20,493	)		1,935			—			(18,558	)


Net income (loss)	$	37,162		$	(3,594	)	$	(143	)	$	33,425




Total assets	$	1,504,338		$	63,731		$	(21,530	)	$	1,546,539




Additions to property and equipment	$	419,094		$	12,614		$	(143	)	$	431,565

(a): Includes impairment of property and equipment.
(b): Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of asset retirement obligations, general and administrative and other operating expenses.

18. Guarantor Financial Information

In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes (see Note 3). Presented below is condensed consolidated financial information of CWEI ("Issuer") and the Issuer's material wholly owned subsidiaries. Other than CWEI Andrews Properties, GP, LLC, the general partner of CWEI Andrews Properties, L.P., an affiliated limited

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

18. Guarantor Financial Information (Continued)

partnership formed in April 2013, all of the Issuer's wholly-owned and active subsidiaries ("Guarantor Subsidiaries") have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the Indenture. CWEI Andrews Properties, GP, LLC, is not a guarantor of the 2019 Senior Notes and its accounts are reflected in the "Non-Guarantor Subsidiary" column in this Note 18.

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

Condensed Consolidating Balance Sheet
September 30, 2013
(Unaudited)
(In thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated

Current assets	$	148,083	$	226,845	$	2,099	$	(220,306	)	$	156,721
Property and equipment, net		828,932		355,721		12,826		—			1,197,479
Investments in subsidiaries		333,243		—		—		(333,243	)		—
Fair value of derivatives		1,038		—		—		—			1,038
Other assets		11,073		13,399		—		—			24,472


Total assets	$	1,322,369	$	595,965	$	14,925	$	(553,549	)	$	1,379,710




Current liabilities	$	252,565	$	88,084	$	2,177	$	(217,528	)	$	125,298
Non-current liabilities:
Long-term debt		672,625		—		—		—			672,625
Deferred income taxes		122,141		125,114		544		(108,597	)		139,202
Other		33,528		61,611		117		—			95,256


		828,294		186,725		661		(108,597	)		907,083
Equity		241,510		321,156		12,087		(227,424	)		347,329


Total liabilities and equity	$	1,322,369	$	595,965	$	14,925	$	(553,549	)	$	1,379,710

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

18. Guarantor Financial Information (Continued)

Condensed Consolidating Balance Sheet
December 31, 2012
(In thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated

Current assets	$	133,080	$	224,210	$	—	$	(232,820	)	$	124,470
Property and equipment, net		1,053,453		366,905		—		—			1,420,358
Investments in subsidiaries		305,899		—		—		(305,899	)		—
Fair value of derivatives		4,236		—		—		—			4,236
Other assets		12,112		13,408		—		—			25,520


Total assets	$	1,508,780	$	604,523	$	—	$	(538,719	)	$	1,574,584




Current liabilities	$	241,200	$	112,534	$	—	$	(232,820	)	$	120,914
Non-current liabilities:
Long-term debt		809,585		—		—		—			809,585
Deferred income taxes		143,699		117,950		—		(105,819	)		155,830
Other		41,499		68,140		—		—			109,639


		994,783		186,090		—		(105,819	)		1,075,054
Equity		272,797		305,899		—		(200,080	)		378,616


Total liabilities and equity	$	1,508,780	$	604,523	$	—	$	(538,719	)	$	1,574,584

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Three Months Ended September 30, 2013
(Unaudited)
(In thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated

Total revenue	$	71,943		$	38,470		$	752		$	—		$	111,165
Costs and expenses		51,320			25,598			329			—			77,247


Operating income (loss)		20,623			12,872			423			—			33,918
Other income (expense)		(17,372	)		(13	)		319			—			(17,066	)
Equity in earnings of subsidiaries		8,841			—			—			(8,841	)		—
Income tax (expense) benefit		(1,141	)		(4,500	)		(260	)		—			(5,901	)


Net income (loss)	$	10,951		$	8,359		$	482		$	(8,841	)	$	10,951

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

18. Guarantor Financial Information (Continued)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Nine Months Ended September 30, 2013
(Unaudited)
(In thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated

Total revenue	$	209,313		$	106,173		$	1,462		$	—		$	316,948
Costs and expenses		243,005			85,218			687			—			328,910


Operating income (loss)		(33,692	)		20,955			775			—			(11,962	)
Other income (expense)		(37,962	)		(483	)		427			—			(38,018	)
Equity in earnings of subsidiaries		14,088			—			—			(14,088	)		—
Income tax (expense) benefit		26,279			(7,165	)		(421	)		—			18,693


Net income (loss)	$	(31,287	)	$	13,307		$	781		$	(14,088	)	$	(31,287	)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Three Months Ended September 30, 2012
(Unaudited)
(In thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated

Total revenue	$	74,129		$	34,065		$	—	$	(431	)	$	107,763
Costs and expenses		57,952			28,669			—		(431	)		86,190


Operating income (loss)		16,177			5,396			—		—			21,573
Other income (expense)		(32,431	)		185			—		—			(32,246	)
Equity in earnings of subsidiaries		3,628			—			—		(3,628	)		—
Income tax (expense) benefit		5,450			(1,953	)		—		—			3,497


Net income (loss)	$	(7,176	)	$	3,628		$	—	$	(3,628	)	$	(7,176	)

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

18. Guarantor Financial Information (Continued)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Nine Months Ended September 30, 2012
(Unaudited)
(In thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated

Total revenue	$	222,570		$	99,896		$	—	$	(1,024	)	$	321,442
Costs and expenses		166,584			86,677			—		(1,024	)		252,237


Operating income (loss)		55,986			13,219			—		—			69,205
Other income (expense)		(19,672	)		2,450			—		—			(17,222	)
Equity in earnings of subsidiaries		10,185			—			—		(10,185	)		—
Income tax (expense) benefit		(13,074	)		(5,484	)		—		—			(18,558	)


Net income (loss)	$	33,425		$	10,185		$	—	$	(10,185	)	$	33,425

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2013
(Unaudited)
(In thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated

Operating activities	$	85,851		$	64,905		$	1,258		$	1,867		$	153,881
Investing activities		24,790			(25,837	)		(1,484	)		(1,867	)		(4,398	)
Financing activities		(100,050	)		(37,406	)		456			—			(137,000	)


Net increase (decrease) in cash and cash equivalents		10,591			1,662			230			—			12,483
Cash at beginning of period		6,030			4,696			—			—			10,726


Cash at end of period	$	16,621		$	6,358		$	230		$	—		$	23,209

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

September 30, 2013

(Unaudited)

18. Guarantor Financial Information (Continued)

Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2012
(Unaudited)
(In thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated

Operating activities	$	78,864		$	73,097		$	—	$	5,922		$	157,883
Investing activities		(359,332	)		(27,460	)		—		(5,922	)		(392,714	)
Financing activities		286,360			(46,360	)		—		—			240,000


Net increase (decrease) in cash and cash equivalents		5,892			(723	)		—		—			5,169
Cash at beginning of period		12,853			4,672			—		—			17,525


Cash at end of period	$	18,745		$	3,949		$	—	$	—		$	22,694

19. Subsequent Events

Effective October 1, 2013, we issued an additional $250 million of aggregate principal amount of our 2019 Senior Notes. These notes and the 2019 Senior Notes issued in March and April 2011 are treated as a single class of debt securities under the same indenture. The net proceeds from the offering were used to repay borrowings under our revolving credit facility (see Note 3).

As of October 15, 2013, the buyer of our Andrews County Wolfberry Assets, has exercised its right to extend the post-closing cure deadline an additional 180 days related to the remaining escrow balance of $25.9 million pending resolution of certain title requirements (see Note 5).

In October 2013, we entered into swap agreements with a counterparty covering 1 million barrels of our 2014 oil production at a price of $96.10 per barrel (see Note 9).

In December 2013, we entered into swap agreements with a counterparty covering 600,000 barrels of our 2014 oil production at a price of $95.58 per barrel.

We have evaluated events and transactions that occurred after the balance sheet date of September 30, 2013 and have determined that no other events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

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REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Clayton Williams Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries (the Company) as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Clayton Williams Energy, Inc.'s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 5, 2013, expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas
March 5, 2013

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

ASSETS

	December 31,

	2012			2011
CURRENT ASSETS
Cash and cash equivalents	$	10,726		$	17,525
Accounts receivable:
Oil and gas sales		32,371			41,282
Joint interest and other, net of allowance for doubtful accounts of $1,193 at December 31, 2012 and $1,215 at December 31, 2011		16,767			14,517
Affiliates		353			990
Inventory		41,703			44,868
Deferred income taxes		8,560			8,948
Fair value of derivatives		7,495			—
Prepaids and other		6,495			14,813


		124,470			142,943


PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method		2,570,803			2,103,085
Pipelines and other midstream facilities		49,839			26,040
Contract drilling equipment		91,163			75,956
Other		20,245			19,134


		2,732,050			2,224,215
Less accumulated depreciation, depletion and amortization		(1,311,692	)		(1,156,664	)


Property and equipment, net		1,420,358			1,067,551


OTHER ASSETS
Debt issue costs, net		10,259			11,644
Fair value of derivatives		4,236			—
Investments and other		15,261			4,133


		29,756			15,777


	$	1,574,584		$	1,226,271

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

(Dollars in thousands)

LIABILITIES AND STOCKHOLDERS' EQUITY

	December 31,

��	2012		2011
CURRENT LIABILITIES
Accounts payable:
Trade	$	73,026	$	98,645
Oil and gas sales		32,146		37,409
Affiliates		164		1,501
Fair value of derivatives		—		5,633
Accrued liabilities and other		15,578		13,042


		120,914		156,230


NON-CURRENT LIABILITIES
Long-term debt		809,585		529,535
Deferred income taxes		155,830		134,209
Fair value of derivatives		—		494
Asset retirement obligations		51,477		40,794
Deferred revenue from volumetric production payment		37,184		—
Accrued compensation under non-equity award plans		20,058		20,757
Other		920		751


		1,075,054		726,540


COMMITMENTS AND CONTINGENCIES (Note 14)
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—12,164,536 shares at December 31, 2012 and 12,163,536 shares at December 31, 2011		1,216		1,216
Additional paid-in capital		152,527		152,515
Retained earnings		224,873		189,770


		378,616		343,501


	$	1,574,584	$	1,226,271

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(In thousands, except per share)

	Year Ended December 31,

	2012			2011			2010
REVENUES
Oil and gas sales	$	403,143		$	405,216		$	326,320
Midstream services		1,974			1,408			1,631
Drilling rig services		15,858			4,060			—
Other operating revenues		2,077			15,744			3,680


Total revenues		423,052			426,428			331,631


COSTS AND EXPENSES
Production		124,950			101,099			83,146
Exploration:
Abandonments and impairments		4,222			20,840			9,074
Seismic and other		11,591			5,363			6,046
Midstream services		1,228			1,039			1,209
Drilling rig services		17,423			5,064			1,198
Depreciation, depletion and amortization		142,687			104,880			101,145
Impairment of property and equipment		5,944			10,355			11,908
Accretion of asset retirement obligations		3,696			2,757			2,623
General and administrative		30,485			41,560			35,588
Other operating expenses		1,033			1,666			1,750


Total costs and expenses		343,259			294,623			253,687


Operating income		79,793			131,805			77,944


OTHER INCOME (EXPENSE)
Interest expense		(38,664	)		(32,919	)		(24,402	)
Loss on early extinguishment of long-term debt		—			(5,501	)		—
Gain on derivatives		14,448			47,027			722
Other		1,534			5,553			3,308


Total other income (expense)		(22,682	)		14,160			(20,372	)


Income before income taxes		57,111			145,965			57,572
Income tax expense		(22,008	)		(52,142	)		(20,634	)


NET INCOME	$	35,103		$	93,823		$	36,938




Net income per common share:
Basic	$	2.89		$	7.72		$	3.04




Diluted	$	2.89		$	7.71		$	3.04




Weighted average common shares outstanding:
Basic		12,164			12,161			12,148




Diluted		12,164			12,162			12,148

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands)

	Common Stock

	No. of Shares		Par Value		Additional Paid-In Capital		Retained Earnings		Total Stockholders' Equity
BALANCE,
December 31, 2009		12,146	$	1,215	$	152,051	$	59,009	$	212,275
Net income		—		—		—		36,938		36,938
Issuance of stock through compensation plans, including income tax benefits		9		—		239		—		239


BALANCE,
December 31, 2010		12,155		1,215		152,290		95,947		249,452
Net income		—		—		—		93,823		93,823
Issuance of stock through compensation plans, including income tax benefits		9		1		225		—		226


BALANCE,
December 31, 2011		12,164		1,216		152,515		189,770		343,501
Net income		—		—		—		35,103		35,103
Issuance of stock through compensation plans, including income tax benefits		1		—		12		—		12


BALANCE,
December 31, 2012		12,165	$	1,216	$	152,527	$	224,873	$	378,616

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

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CLAYTON WILLIAMS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,

	2012			2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	35,103		$	93,823		$	36,938
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization		142,687			104,880			101,145
Impairment of property and equipment		5,944			10,355			11,908
Exploration costs		4,222			20,840			9,074
Gain on sales of assets and impairment of inventory, net		(463	)		(14,078	)		(1,930	)
Deferred income tax expense		22,008			52,550			20,259
Non-cash employee compensation		(404	)		12,866			13,898
Unrealized (gain) loss on derivatives		(17,858	)		(4,506	)		9,153
Amortization of debt issue costs and original issue discount		2,554			2,342			1,648
Accretion of asset retirement obligations		3,696			2,757			2,623
Loss on early extinguishment of long-term debt		—			5,501			—
Amortization of deferred revenue from volumetric production payment		(8,295	)		—			—
Changes in operating working capital:
Accounts receivable		7,299			(10,739	)		(10,036	)
Accounts payable		(9,386	)		7,551			19,144
Other		2,115			(4,095	)		(5,573	)


Net cash provided by operating activities		189,222			280,047			208,251


CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(526,521	)		(413,013	)		(285,655	)
Proceeds from volumetric production payment		45,479			—			—
Proceeds from sales of assets		3,778			13,902			77,216
(Increase) decrease in equipment inventory		1,313			(5,305	)		4,638
Other		(82	)		(497	)		18


Net cash used in investing activities		(476,033	)		(404,913	)		(203,783	)


CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		280,000			547,710			—
Repayments of long-term debt		—			(411,500	)		(10,000	)
Premium on early extinguishment of long-term debt		—			(2,765	)		—
Proceeds from exercise of stock options		12			226			239


Net cash provided by (used in) financing activities		280,012			133,671			(9,761	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(6,799	)		8,805			(5,293	)
CASH AND CASH EQUIVALENTS
Beginning of period		17,525			8,720			14,013


End of period	$	10,726		$	17,525		$	8,720




SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	35,932		$	23,923		$	22,457




Cash paid for income taxes	$	—		$	—		$	—

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations

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

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

2. Summary of Significant Accounting Policies

Estimates and Assumptions

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management's estimates and assumptions are as follows:

•: Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves;
•: Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets;
•: Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases;
•: Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory;
•: Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells; and
•: Asset retirement obligations are based on estimates regarding the timing and cost of future asset retirements.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Principles of Consolidation

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 the Company's 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.

Oil and Gas Properties

We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.

Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well's ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.

Pipelines and Other Midstream Facilities and Other Property and Equipment

Pipelines and other midstream facilities consist of pipelines to transport oil, gas, and water, gas processing facilities and compressors. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income in the accompanying consolidated statements of operations and comprehensive income (loss).

Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years.

Contract Drilling

We conduct contract drilling operations through Desta Drilling, a wholly owned subsidiary of CWEI. Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Property and equipment, including buildings, major replacements, improvements, and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.

Valuation of Property and Equipment

Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred. An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset.

Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs. The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

Asset Retirement Obligations

We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

Income Taxes

We utilize the asset and liability method to account for income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date. We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense.

Hedging Activities

From time to time, we utilize derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. All of our derivative instruments

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

are recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative. Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur. If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period. Actual gains or losses from derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on derivatives.

Inventory

Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value.

Capitalization of Interest

Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress. During the years ended December 31, 2012, 2011 and 2010, we capitalized interest totaling approximately $1 million, $729,000 and $493,000, respectively.

Cash and Cash Equivalents

We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.

Net Income Per Common Share

Basic net income per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted net income per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted net income per share calculations for 2012, 2011 and 2010 include changes in potential shares attributable to dilutive stock options.

Stock-Based Compensation

We measure and recognize compensation expense for all share-based payment awards, including employee stock options, based on estimated fair values. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

We estimate the fair value of stock option awards on the date of grant using an option-pricing model. We use the Black-Scholes option-pricing model ("Black-Scholes Model") as our method of valuation for share-based awards granted on or after January 1, 2006. Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price, as well as assumptions regarding a number of subjective variables. These variables include, but are not limited to, our expected stock price volatility over the term of the awards, as well as actual and projected exercise and forfeiture activity.

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.

Revenue Recognition and Gas Balancing

We utilize the sales method of accounting for oil, natural gas and natural gas liquids revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers. The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties. We did not have any significant gas imbalance positions at December 31, 2012, 2011 or 2010. Revenues from midstream services and drilling rig services are recognized as services are provided.

Comprehensive Income (Loss)

There were no differences between net income (loss) and comprehensive income (loss) in 2012, 2011 and 2010.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Concentration Risks

We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2012 and 2011 relate to amounts due from joint interest owners.

Recent Accounting Pronouncements

In December 2011 the FASB issued ASU No.2011-11, "Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities" ("ASU 2011-11"). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of the ASU is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. At that time we will make the necessary disclosures. The adoption of ASU 2011-11 will not impact the Company's future financial position, results of operation or liquidity.

3. Long-Term Debt

Long-term debt consists of the following:

	December 31, 2012		December 31, 2011

	(In thousands)
Revolving credit facility, due November 2015	$	460,000	$	180,000
7.75% Senior Notes due 2019, net of unamortized original issue discount of $415 at December 31, 2012 and $465 at December 31, 2011		349,585		349,535


	$	809,585	$	529,535

Aggregate maturities of long-term debt at December 31, 2012 are as follows: 2015—$460 million; 2019—$349.6 million net of unamortized original issue discount of $415,000.

Revolving Credit Facility

We have a credit facility with a syndicate of banks that provides for a revolving line of credit of up to $585 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 our 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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Long-Term Debt (Continued)

security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.

In May 2012, the banks increased the borrowing base from $475 million to $565 million and then to $585 million in November 2012 and increased the maximum credit facility from $500 million to $565 million in May 2012 and then to $585 million in November 2012. The banks also increased the aggregate commitment from $350 million to $475 million in April 2012, to $555 million in August 2012 and then to $585 million in November 2012. At December 31, 2012, after allowing for outstanding letters of credit totaling $4.1 million, we had $121 million available under our revolving credit facility based on then-existing commitments. During 2012, we increased indebtedness outstanding under our revolving credit facility by $280 million.

Our revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1. Another financial covenant prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1. The computations of consolidated current assets, current liabilities, EBITDAX and indebtedness are defined in our revolving credit facility. We were in compliance with all financial and non-financial covenants at December 31, 2012.

Senior Notes

In July 2005, we issued $225 million of aggregate principal amount of 7³/4% Senior Notes due 2013 ("2013 Senior Notes"). The 2013 Senior Notes were issued at face value and bore interest at 7³/4% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006. In March 2011, we redeemed $143.2 million in aggregate principal amount of 2013 Senior Notes in a tender offer and recorded a $4.6 million loss on early extinguishment of long-term debt, consisting of a $2.8 million premium and a $1.8 million write-off of debt issuance costs. On August 1, 2011, we called at par and redeemed in full the remaining $81.8 million of 2013 Senior Notes and recorded an additional $907,000 loss on early extinguishment of long-term debt related to the write-off of debt issuance costs.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Long-Term Debt (Continued)

4. Acquisition of Southwest Royalties, Inc. Limited Partnerships

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Acquisition of Southwest Royalties, Inc. Limited Partnerships (Continued)

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


Cash and cash equivalents	$	4,118
Oil and gas properties		41,098
Other non-current assets		210


Total assets acquired		45,426
Asset retirement obligations		(6,864	)


Total liabilities assumed		(6,864	)


Net assets acquired	$	38,562

5. Asset Retirement Obligations

Changes in asset retirement obligations ("ARO") for 2012 and 2011 are as follows:

	2012			2011

	(In thousands)
Beginning of year	$	40,794		$	40,444
Additional ARO from new properties		7,868			1,526
Sales or abandonments of properties		(2,184	)		(4,425	)
Accretion expense		3,696			2,757
Revisions of previous estimates		1,303			492


End of year	$	51,477		$	40,794

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

6. Deferred Revenue from Volumetric Production Payment

Changes in deferred revenue from the VPP are as follows:

	December 31, 2012			December 31, 2011

	(In thousands)
Beginning of period	$	—		$	—
Deferred revenue from VPP		45,479			—
Amortization of deferred revenue from VPP		(8,295	)		—


End of period	$	37,184		$	—

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Deferred Revenue from Volumetric Production Payment (Continued)

Under the terms of the VPP, SWR conveyed to a third party a term overriding royalty interest covering approximately 725,000 BOE of estimated future oil and gas production. As of December 31, 2012, we have a remaining obligation to deliver approximately 607,000 BOE.

7. Income Taxes

Deferred tax assets and liabilities are the result of temporary differences between the consolidated financial statement carrying values and the tax basis of assets and liabilities. Significant components of net deferred tax assets (liabilities) at December 31, 2012 and 2011 are as follows:

	2012			2011

	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	122,393		$	54,124
Fair value of derivatives		—			1,958
Statutory depletion carryforwards		8,159			7,359
Asset retirement obligations and other		21,814			21,165


		152,366			84,606


Deferred tax liabilities:
Fair value of derivatives		(4,208	)		—
Property and equipment		(295,428	)		(209,867	)


		(299,636	)		(209,867	)


Net deferred tax liabilities	$	(147,270	)	$	(125,261	)




Components of net deferred tax liabilities:
Current assets	$	8,560		$	8,948
Non-current liabilities		(155,830	)		(134,209	)


Net deferred tax liabilities	$	(147,270	)	$	(125,261	)

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Income Taxes (Continued)

For the years ended December 31, 2012, 2011 and 2010, effective income tax rates were different than the statutory federal income tax rates for the following reasons:

	2012			2011			2010

	(In thousands)
Income tax expense at statutory rate of 35%	$	19,989		$	50,921		$	20,150
Tax depletion in excess of basis		(581	)		(425	)		(490	)
Revision of previous tax estimates		700			217			8
State income taxes, net of federal tax effect		1,513			1,310			884
Other		387			119			82


Income tax expense	$	22,008		$	52,142		$	20,634




Current	$	—		$	(408	)	$	375
Deferred		22,008			52,550			20,259


Income tax expense	$	22,008		$	52,142		$	20,634

We derive a tax deduction when employees and directors exercise options granted under our stock option plans. To the extent these tax deductions are used to reduce currently payable taxes in any period, we record a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements. At December 31, 2012, our cumulative tax loss carryforwards were approximately $371.1 million, of which $21.8 million relates to excess tax benefits from exercise of stock options. The cumulative tax loss carryforwards are scheduled to expire if not utilized between 2023 and 2027.

In assessing the ability to realize deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. If it is more likely than not that some portion or all of the assets will not be realized, the assets are reduced by a valuation allowance. Based on our analysis of future taxable income, no valuation allowance is required.

The Company and its subsidiaries file federal income tax returns with the United States Internal Revenue Service ("IRS") and state income tax returns in various state tax jurisdictions. As a general rule, the Company's tax returns for fiscal years after 2008 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time. We do not have any uncertain tax positions as of December 31, 2012 and 2011.

8. Derivatives

Commodity Derivatives

From time to time, we utilize commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. When using swaps to hedge 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. In floor transactions, 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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Derivatives (Continued)

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. 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 December 31, 2012. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps

	Oil				Gas

	Bbls		Price		MMBtu(a)		Price
Production Period:
1st Quarter 2013		665,000	$	93.70		400,000	$	3.34
2nd Quarter 2013		648,000	$	93.94		390,000	$	3.34
3rd Quarter 2013		300,000	$	104.60		360,000	$	3.34
4th Quarter 2013		300,000	$	104.60		330,000	$	3.34
2014		600,000	$	99.30		—	$	—


		2,513,000				1,480,000

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

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $0.50 per MMBtu change in the price of gas would change the fair value of our outstanding commodity derivatives at December 31, 2012 by approximately $3.2 million.

Accounting for Derivatives

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Derivatives (Continued)

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of December 31, 2012

	Asset Derivatives			Liability Derivatives
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
		(In thousands)
					(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	7,495	Current	$	—
	Non-current		4,236	Non-current		—


Total		$	11,731		$	—

	Fair Value of Derivative Instruments as of December 31, 2011

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


Total		$	—		$	6,127

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	December 31, 2012

	Assets			Liabilities
	(In thousands)
Fair value of derivatives—gross presentation	$	17,851		$	6,120
Effects of netting arrangements		(6,120	)		(6,120	)


Fair value of derivatives—net presentation	$	11,731		$	—

	December 31, 2011

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


Fair value of derivatives—net presentation	$	—		$	6,127

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Derivatives (Continued)

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

	Amount of Gain or (Loss) Recognized in Earnings

	Year Ended December 31, 2012
Location of Gain or (Loss) Recognized in Earnings	Realized			Unrealized		Total
	(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense)—Gain (loss) on derivatives	$	(3,410	)	$	17,858	$	14,448


Total	$	(3,410	)	$	17,858	$	14,448

	Amount of Gain or (Loss) Recognized in Earnings

	Year Ended December 31, 2011
Location of Gain or (Loss) Recognized in Earnings	Realized		Unrealized		Total
	(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense)—Gain (loss) on derivatives	$	42,521	$	4,506	$	47,027


Total	$	42,521	$	4,506	$	47,027

	Amount of Gain or (Loss) Recognized in Earnings

	Year Ended December 31, 2010
Location of Gain or (Loss) Recognized in Earnings	Realized		Unrealized			Total
	(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense)—Gain (loss) on derivatives	$	9,875	$	(9,153	)	$	722


Total	$	9,875	$	(9,153	)	$	722

9. Fair Value of 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 secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9. Fair Value of Financial Instruments (Continued)

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

	Significant Other Observable Inputs (Level 2)

	December 31,
Description	2012		2011
	(In thousands)
Assets:
Fair value of commodity derivatives	$	11,731	$	—


Total assets	$	11,731	$	—




Liabilities:
Fair value of commodity derivatives	$	—	$	6,127


Total liabilities	$	—	$	6,127

Fair Value of Other Financial Instruments

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

	December 31, 2012				December 31, 2011

Description	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(In thousands)
7.75% Senior Notes due 2019	$	349,585	$	348,700	$	349,535	$	334,300

10. Compensation Plans

Stock-Based Compensation

Initially, we reserved 86,300 shares of Common Stock for issuance under the Outside Directors Stock Option Plan ("Directors Plan"). Since the inception of the Directors Plan, CWEI has issued options covering 52,000 shares of Common Stock at option prices ranging from $3.25 to $41.74 per share. All outstanding options expire ten years from the grant date and are fully exercisable upon issuance. No options were granted under the Directors Plan in 2012 or 2011. At December 31, 2012, 5,000 options were outstanding under this plan. In December 2009, the Board reduced the number of shares available for issuance under the Directors Plan to a level sufficient to cover only the remaining outstanding shares.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Compensation Plans (Continued)

The following table sets forth certain information regarding our stock option plans as of and for the year ended December 31, 2012:

			Weighted Average Exercise Price			Aggregate Intrinsic Value(a)

Outstanding at January 1, 2012	6,000		$	28.86
Exercised(b)	(1,000	)	$	12.14


Outstanding at December 31, 2012	5,000		$	32.21	3.0	$	40,700




Vested at December 31, 2012	5,000		$	32.21	3.0	$	40,700
Exercisable at December 31, 2012	5,000		$	32.21	3.0	$	40,700

(a): Based on closing price at December 31, 2012 of $40.00 per share.
(b): Cash received for options exercised totaled $12,140.

The following table summarizes information with respect to options outstanding at December 31, 2012, all of which were granted under the Directors Plan and are currently exercisable.

	Outstanding and Exercisable Options

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Life in Years
Range of exercise prices:
$22.90 - $41.74		5,000	$	32.21		3.0

The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2012, 2011 and 2010.

	2012		2011		2010

	(In thousands, except per share))
Weighted average grant date fair value of options granted per share	$	—	$	—	$	—
Intrinsic value of options exercised	$	28	$	594	$	261

Non-Equity Award Plans

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Compensation Plans (Continued)

acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest ("payout"). At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships. Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan. We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements. Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Compensation Plans (Continued)

award plans. Aggregate compensation under non-equity award plans is reflected on the balance sheet as detailed in the following schedule:

	December 31, 2012		December 31, 2011

	(In thousands)
Current liabilities:
Accrued liabilities and other	$	2,220	$	1,994
Non-current liabilities:
Accrued compensation under non-equity award plans		20,058		20,757


Total accrued compensation under non-equity award plans	$	22,278	$	22,751

11. Transactions with Affiliates

The Company and other entities (the "Williams Entities") controlled by Mr. Williams are parties to an agreement (the "Service Agreement") pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, as amended from time to time, CWEI provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services, and financial and accounting services to the Williams Entities, as well as technical services with respect to certain oil and gas properties owned by the Williams Entities. The Williams Entities provide business entertainment to or for the benefit of CWEI. The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2012, 2011 and 2010.

	2012		2011		2010

	(In thousands)
Amounts received from the Williams Entities:
Service Agreement:
Services	$	671	$	566	$	513
Insurance premiums and benefits		920		821		859
Reimbursed expenses		566		371		319


	$	2,157	$	1,758	$	1,691




Amounts paid to the Williams Entities:
Rent(a)	$	1,478	$	843	$	811
Service Agreement:
Business entertainment(b)		116		116		116
Reimbursed expenses		267		289		146


	$	1,861	$	1,248	$	1,073

(a): Rent amounts were paid to a Partnership within the Williams Entities. The Company owns 31.9% of the Partnership and affiliates of the Company own 23.3%.
(b): Consists of hunting and fishing rights pertaining to land owned by affiliates of Mr. Williams.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Transactions with Affiliates (Continued)

Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for customary charges by the Company as operator of certain wells in which affiliates own an interest.

12. Other Operating Revenues and Expenses

Net other operating revenues and expenses for the years ended December 31, 2012, 2011 and 2010 are as follows:

	2012			2011			2010

	(In thousands)
Other operating revenues:
Gain on sales of assets	$	1,496		$	15,744		$	3,680
Net marketing revenue		581			—			—


Total other operating revenues	$	2,077		$	15,744		$	3,680




Other operating expenses:
Loss on sales of assets	$	(523	)	$	(945	)	$	(1,655	)
Impairment of inventory		(510	)		(721	)		(95	)


Total other operating expenses	$	(1,033	)	$	(1,666	)	$	(1,750	)

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 that was subsequently exchanged for a membership interest in Dalea Investment Group, LLC in June 2012 (See Note 13). In 2011, we also sold certain interests in two prospects in South Louisiana and recorded a gain of $852,000.

In June 2010, we sold our interests in 22 operated and 76 non-operated producing wells in North Louisiana for net proceeds of $73.1 million, after giving effect to customary closing adjustments and the allocation of approximately $2 million of proceeds to applicable APO Partnerships (see Note 10), resulting in a loss on the sale of approximately $1.4 million. Proceeds from the sale were used to repay indebtedness under our revolving credit facility. The assets that were sold in this transaction represented substantially all of our proved oil and gas properties in North Louisiana but did not meet the criteria for treatment as discontinued operations under applicable accounting standards. Additionally in August 2010, we sold our interest in a non-operated well and related leasehold interests in North Louisiana for net proceeds of $2.9 million, all of which was recorded as a gain on sale of assets.

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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

13. Investment in Dalea Investment Group, LLC

In June 2012, we cancelled an $11 million note receivable (see Note 12) in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC ("Dalea"), an international oilfield services company formed in March 2012. Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea is carried at cost of $11 million. As of December 31, 2012, we have performed a qualitative assessment and determined there has been no indication of any impairment of our investment in Dalea.

14. Commitments and Contingencies

Leases

We lease office space from affiliates and nonaffiliates under noncancelable operating leases. Rental expense pursuant to the office leases amounted to $1.6 million, $1 million and $1 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Future minimum payments under noncancelable leases at December 31, 2012, are as follows:

	Leases

	Capital(a)		Operating(b)		Total
	(In thousands)
2013	$	1,083	$	3,960	$	5,043
2014		609		3,819		4,428
2015		209		3,843		4,052
Thereafter		—		3,865		3,865


Total minimum lease payments	$	1,901	$	15,487	$	17,388

(a): Relates to vehicle leases.
(b): Includes leases for two drilling rigs.

Legal Proceedings

We are currently the defendant in a lawsuit where the plaintiffs are suing for the cost of remediating a lease on which operations were commenced in the 1930s. We were brought into the suit as the successor through a series of mergers to an earlier lessee, and never owned or operated the lease. The portion of the lease in our chain of title is 40 acres, and the lands subject to plaintiffs' claims are less than 3 acres. The plaintiffs contend that the cost to remediate the surface could be as much as $8 million. We have undertaken certain remediation operations which we believe will substantially reduce any potential exposure. We strongly deny liability and will vigorously defend the suit. We believe that it is reasonably possible that these claims will ultimately be held to be time barred. This case is scheduled for trial in June 2013.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15. 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 recorded provisions for impairment of proved properties triggered by a combination of well performance and lower reserve estimates due to performance and changes in oil and gas prices aggregating $5.9 million in 2012, $10.4 million in 2011, and $11.9 million in 2010 to reduce the carrying value of those properties to their estimated fair values. The 2012 provision related to $5.4 million for certain non-core properties in the Permian Basin. The 2011 provision related to $10.4 million for certain non-core properties in the Permian Basin and other non-core areas. The 2010 provision related primarily to $11.1 million for certain non-core properties in the Permian Basin.

Unproved properties are nonproducing and do not have estimable cash flow streams. Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to the proximity of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors. Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects. Based on the assessments previously discussed, we will impair our unproved oil and gas properties when we determine that a prospect's carrying value exceed its estimated fair value. We categorize the measurement of fair value of these assets as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $1.4 million, $6.2 million and $7.8 million in 2012, 2011 and 2010, respectively, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

16. Costs of Oil and Gas Properties

The following table sets forth certain information with respect to costs incurred in connection with the Company's oil and gas producing activities during the years ended December 31, 2012, 2011 and 2010.

	2012		2011		2010

	(In thousands)
Property acquisitions:
Proved	$	41,098	$	—	$	9,556
Unproved		72,235		61,236		29,680
Developmental costs		349,972		328,418		238,197
Exploratory costs		10,898		27,425		7,528


Total	$	474,203	$	417,079	$	284,961

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Costs of Oil and Gas Properties (Continued)

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

	2012			2011

	(In thousands)
Proved properties	$	2,482,185		$	2,021,181
Unproved properties		88,618			81,904


Total capitalized costs		2,570,803			2,103,085
Accumulated depletion		(1,234,626	)		(1,095,197	)


Net capitalized costs	$	1,336,177		$	1,007,888

17. 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 2012, 2011 and 2010.

For the Year Ended December 31, 2012	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total

	(In thousands)
Revenues	$	407,194		$	57,218		$	(41,360	)	$	423,052
Depreciation, depletion and amortization(a)		140,967			14,442			(6,778	)		148,631
Other operating expenses(b)		176,922			52,678			(34,972	)		194,628
Interest expense		38,664			—			—			38,664
Other (income) expense		(15,979	)		(3	)		—			(15,982	)


Income (loss) before income taxes		66,620			(9,899	)		390			57,111
Income tax (expense) benefit		(25,473	)		3,465			—			(22,008	)


Net income (loss)	$	41,147		$	(6,434	)	$	390		$	35,103




Total assets	$	1,535,544		$	64,045		$	(25,005	)	$	1,574,584
Additions to property and equipment	$	510,924		$	15,207		$	390		$	526,521

For the Year Ended December 31, 2011	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total

	(In thousands)
Revenues	$	422,368		$	52,716		$	(48,656	)	$	426,428
Depreciation, depletion and amortization(a)		112,863			12,214			(9,842	)		115,235
Other operating expenses(b)		174,027			44,318			(38,957	)		179,388
Interest expense		32,919			—			—			32,919
Other (income) expense		(33,280	)		(13,799	)		—			(47,079	)


Income (loss) before income taxes		135,839			9,983			143			145,965
Income tax (expense) benefit		(48,648	)		(3,494	)		—			(52,142	)


Net income (loss)	$	87,191		$	6,489		$	143		$	93,823




Total assets	$	1,178,725		$	62,846		$	(15,300	)	$	1,226,271
Additions to property and equipment	$	395,292		$	17,578		$	143		$	413,013

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. Segment Information (Continued)

For the Year Ended December 31, 2010	Oil and Gas			Contract Drilling			Intercompany Eliminations			Consolidated Total

	(In thousands)
Revenues	$	331,631		$	35,269		$	(35,269	)	$	331,631
Depreciation, depletion and amortization(a)		111,353			10,044			(8,344	)		113,053
Other operating expenses(b)		139,212			26,916			(25,494	)		140,634
Interest expense		24,397			5			—			24,402
Other (income) expense		(4,030	)		—			—			(4,030	)


Income (loss) before income taxes		60,699			(1,696	)		(1,431	)		57,572
Income tax (expense) benefit		(21,228	)		594			—			(20,634	)


Net income (loss)	$	39,471		$	(1,102	)	$	(1,431	)	$	36,938




Total assets	$	854,621		$	48,414		$	(12,118	)	$	890,917
Additions to property and equipment	$	270,108		$	16,978		$	(1,431	)	$	285,655

(a): Includes impairment of property and equipment.
(b): Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of asset retirement obligations, general and administrative, and other operating expenses.

18. Guarantor Financial Information

In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes (see Note 3). Presented below is condensed consolidated financial information of CWEI ("Issuer") and the Issuer's material wholly owned subsidiaries, all of which have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes and are referred to as "Guarantor Subsidiaries" in the following condensed consolidating financial statements. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the indenture.

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. Guarantor Financial Information (Continued)

Condensed Consolidating Balance Sheet
December 31, 2012
(Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Adjustments/ Eliminations			Consolidated

Current assets	$	133,080	$	224,210	$	(232,820	)	$	124,470
Property and equipment, net		1,053,453		366,905		—			1,420,358
Investments in subsidiaries		305,899		—		(305,899	)		—
Fair value of derivatives		4,236		—		—			4,236
Other assets		12,112		13,408		—			25,520


Total assets	$	1,508,780	$	604,523	$	(538,719	)	$	1,574,584




Current liabilities	$	241,200	$	112,534	$	(232,820	)	$	120,914
Non-current liabilities:
Long-term debt		809,585		—		—			809,585
Deferred income taxes		143,699		117,950		(105,819	)		155,830
Other		41,499		68,140	��	—			109,639


		994,783		186,090		(105,819	)		1,075,054
Equity		272,797		305,899		(200,080	)		378,616


Total liabilities and equity	$	1,508,780	$	604,523	$	(538,719	)	$	1,574,584

Condensed Consolidating Balance Sheet
December 31, 2011
(Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Adjustments/ Eliminations			Consolidated

Current assets	$	142,102	$	164,515	$	(163,674	)	$	142,943
Property and equipment, net		737,562		329,989		—			1,067,551
Investments in subsidiaries		271,342		—		(271,342	)		—
Other assets		13,538		2,239		—			15,777


Total assets	$	1,164,544	$	496,743	$	(435,016	)	$	1,226,271




Current liabilities	$	233,729	$	86,175	$	(163,674	)	$	156,230
Non-current liabilities:
Long-term debt		529,535		—		—			529,535
Fair value of derivatives		494		—		—			494
Deferred income taxes		141,923		111,662		(119,376	)		134,209
Other		34,738		27,564		—			62,302


		706,690		139,226		(119,376	)		726,540
Equity		224,125		271,342		(151,966	)		343,501


Total liabilities and equity	$	1,164,544	$	496,743	$	(435,016	)	$	1,226,271

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. Guarantor Financial Information (Continued)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Year Ended December 31, 2012
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated

Total revenue	$	291,782		$	132,690		$	(1,420	)	$	423,052
Costs and expenses		230,033			114,646			(1,420	)		343,259


Operating income (loss)		61,749			18,044			—			79,793
Other income (expense)		(25,495	)		2,813			—			(22,682	)
Equity in earnings of subsidiaries		13,557			—			(13,557	)		—
Income tax (expense) benefit		(14,708	)		(7,300	)		—			(22,008	)


Net income (loss)	$	35,103		$	13,557		$	(13,557	)	$	35,103

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Year Ended December 31, 2011
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated

Total revenue	$	280,359		$	147,015		$	(946	)	$	426,428
Costs and expenses		191,012			104,557			(946	)		294,623


Operating income (loss)		89,347			42,458			—			131,805
Other income (expense)		6,816			7,344			—			14,160
Equity in earnings of subsidiaries		32,371			—			(32,371	)		—
Income tax (expense) benefit		(34,711	)		(17,431	)		—			(52,142	)


Net income (loss)	$	93,823		$	32,371		$	(32,371	)	$	93,823

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Year Ended December 31, 2010
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated

Total revenue	$	209,046		$	123,396		$	(811	)	$	331,631
Costs and expenses		166,846			87,652			(811	)		253,687


Operating income (loss)		42,200			35,744			—			77,944
Other income (expense)		(26,801	)		6,429			—			(20,372	)
Equity in earnings of subsidiaries		27,412			—			(27,412	)		—
Income tax (expense) benefit		(5,873	)		(14,761	)		—			(20,634	)


Net income (loss)	$	36,938		$	27,412		$	(27,412	)	$	36,938

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

18. Guarantor Financial Information (Continued)

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated

Operating activities	$	92,521		$	89,923		$	6,778		$	189,222
Investing activities		(432,433	)		(36,822	)		(6,778	)		(476,033	)
Financing activities		333,703			(53,691	)		—			280,012


Net increase (decrease) in cash and cash equivalents		(6,209	)		(590	)		—			(6,799	)
Cash at the beginning of the period		12,239			5,286			—			17,525


Cash at end of the period	$	6,030		$	4,696		$	—		$	10,726

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated

Operating activities	$	209,886		$	60,319		$	9,842		$	280,047
Investing activities		(389,681	)		(5,390	)		(9,842	)		(404,913	)
Financing activities		186,994			(53,323	)		—			133,671


Net increase (decrease) in cash and cash equivalents		7,199			1,606			—			8,805
Cash at the beginning of the period		5,040			3,680			—			8,720


Cash at end of the period	$	12,239		$	5,286		$	—		$	17,525

Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2010
(Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Adjustments/ Eliminations			Consolidated

Operating activities	$	114,960		$	84,947		$	8,344		$	208,251
Investing activities		(161,742	)		(33,697	)		(8,344	)		(203,783	)
Financing activities		39,983			(49,744	)		—			(9,761	)


Net increase (decrease) in cash and cash equivalents		(6,799	)		1,506			—			(5,293	)
Cash at the beginning of the period		11,839			2,174			—			14,013


Cash at end of the period	$	5,040		$	3,680		$	—		$	8,720

19. Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2012 and have determined that no events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Clayton Williams Energy, Inc.:

We have audited Clayton Williams Energy, Inc.'s (the Company) internal control over financial reporting as of December 31, 2012, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanyingManagement's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Clayton Williams Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated March 5, 2013 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas
March 5, 2013

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CLAYTON WILLIAMS ENERGY, INC.

SUPPLEMENTAL INFORMATION

(UNAUDITED)

Supplemental Quarterly Financial Data

The following table summarizes results for each of the four quarters in the years ended December 31, 2012 and 2011.

	First Quarter			Second Quarter		Third Quarter			Fourth Quarter			Year

	(In thousands, except per share)
Year ended December 31, 2012:
Total revenues	$	109,069		$	104,610	$	107,763		$	101,610		$	423,052
Operating income	$	26,795		$	20,837	$	21,573		$	10,588		$	79,793
Net income (loss)	$	7,779		$	32,822	$	(7,176	)	$	1,678		$	35,103
Net income (loss) per common share(a):
Basic	$	0.64		$	2.70	$	(0.59	)	$	0.14		$	2.89
Diluted	$	0.64		$	2.70	$	(0.59	)	$	0.14		$	2.89
Weighted average common shares outstanding:
Basic		12,164			12,164		12,164			12,164			12,164
Diluted		12,164			12,164		12,164			12,164			12,164
Year ended December 31, 2011:
Total revenues	$	109,173		$	109,543	$	101,064		$	106,648		$	426,428
Operating income	$	44,036		$	45,258	$	32,878		$	9,633		$	131,805
Net income (loss)	$	(7,875	)	$	42,668	$	74,523		$	(15,493	)	$	93,823
Net income (loss) per common share(a):
Basic	$	(0.65	)	$	3.51	$	6.13		$	(1.27	)	$	7.72
Diluted	$	(0.65	)	$	3.51	$	6.13		$	(1.27	)	$	7.71
Weighted average common shares outstanding:
Basic		12,156			12,162		12,163			12,163			12,161
Diluted		12,156			12,163		12,163			12,163			12,162

(a): The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period's computation is based on the weighted average number of common shares outstanding during each period.

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CLAYTON WILLIAMS ENERGY, INC.

SUPPLEMENTAL INFORMATION (Continued)

(UNAUDITED)

Supplemental Oil and Gas Reserve Information

The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the SEC and the FASB. All of our reserves are located in the United States. For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations and comprehensive income (loss).

We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

We did not have any capital costs relating to exploratory wells pending the determination of proved reserves for the years ended December 31, 2012, 2011 and 2010.

The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended December 31, 2012, 2011 and 2010.



Proved reserves:
December 31, 2009	20,953		76,103		33,637
Revisions	1,511		4,628		2,282
Extensions and discoveries	18,969		25,343		23,193
Purchases of minerals-in-place	317		190		349
Sales of minerals-in-place	(268	)	(16,017	)	(2,937	)
Production	(3,667	)	(10,750	)	(5,459	)


December 31, 2010	37,815		79,497		51,065
Revisions	(1,802	)	(1,227	)	(2,007	)
Extensions and discoveries	17,570		19,864		20,881
Sales of minerals-in-place	(45	)	(664	)	(156	)
Production	(4,002	)	(8,594	)	(5,434	)


December 31, 2011	49,536		88,876		64,349
Revisions	(5,498	)	(6,699	)	(6,615	)
Extensions and discoveries	16,676		22,604		20,443
Purchases of minerals-in-place	2,474		6,182		3,504
Sales of minerals-in-place	(633	)	(555	)	(725	)
Production	(4,254	)	(8,072	)	(5,599	)


December 31, 2012	58,301		102,336		75,357




Proved developed reserves:
December 31, 2010	24,570		59,409		34,472




December 31, 2011	28,962		61,811		39,264




December 31, 2012	32,685		64,013		43,354

(a): Includes natural gas liquids.

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CLAYTON WILLIAMS ENERGY, INC.

SUPPLEMENTAL INFORMATION (Continued)

(UNAUDITED)

Net downward revisions of 6,615 MBOE consisted of downward revisions of 4,339 MBOE related to performance and downward revisions of 2,276 MBOE related to pricing. Downward price revisions of 2,276 MBOE were attributable to the effects of lower product prices on the estimated quantities of proved reserves. Substantially all of the downward performance revisions were attributable to our Andrews County Wolfberry program.

The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2012, 2011 and 2010 was as follows:

	2012			2011			2010

	(In thousands)
Future cash inflows	$	5,085,122		$	4,701,004		$	3,058,637
Future costs:
Production		(1,819,356	)		(1,558,067	)		(1,127,744	)
Development		(651,292	)		(510,709	)		(308,420	)
Income taxes		(673,686	)		(757,253	)		(455,980	)


Future net cash flows		1,940,788			1,874,975			1,166,493
10% discount factor		(1,000,957	)		(936,462	)		(482,055	)


Standardized measure of discounted net cash flows	$	939,831		$	938,513		$	684,438

Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2012, 2011 and 2010 were as follows:

	2012			2011			2010

	(In thousands)
Standardized measure, beginning of period	$	938,512		$	684,438		$	364,273
Net changes in sales prices, net of production costs		(196,930	)		206,357			192,193
Revisions of quantity estimates		(144,899	)		(53,089	)		56,190
Accretion of discount		137,369			99,028			45,963
Changes in future development costs, including development costs incurred that reduced future development costs		148,733			84,638			39,689
Changes in timing and other		(58,322	)		(45,055	)		20,839
Net change in income taxes		76,593			(130,562	)		(210,090	)
Future abandonment cost, net of salvage		(9,230	)		925			(1,107	)
Extensions and discoveries		289,999			399,068			441,719
Sales, net of production costs		(277,248	)		(305,769	)		(244,792	)
Purchases of minerals-in-place		80,744			—			9,290
Sales of minerals-in-place		(45,490	)		(1,466	)		(29,729	)


Standardized measure, end of period	$	939,831		$	938,512		$	684,438

The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period. The average prices used for each commodity for the years ended December 31, 2012, 2011 and 2010 were as follows:

	Average Price

	Oil(a)		Gas
As of December 31:
2012(b)	$	83.09	$	3.70
2011(b)	$	87.61	$	5.31
2010(b)	$	72.36	$	5.44

(a): Includes natural gas liquids.
(b): Average prices for December 31, 2012, 2011 and 2010 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January through December during each respective calendar year.

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ANNEX A:

LETTER OF TRANSMITTAL

TO TENDER
OLD 7.75% SENIOR NOTES DUE 2019
OF
CLAYTON WILLIAMS ENERGY, INC.
PURSUANT TO THE EXCHANGE OFFER AND PROSPECTUS
DATED , 2014

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON , 2014 (THE "EXPIRATION DATE"), UNLESS THE EXCHANGE OFFER IS EXTENDED BY THE ISSUER.

The Exchange Agent for the Exchange Offer is:
WELLS FARGO BANK, NATIONAL ASSOCIATION


By Registered or Certified Mail: Wells Fargo Bank, N.A. MAC-N9303-121 Corporate Trust Operations P.O. Box 1517 Minneapolis, MN 55480-1517 Attn: Reorg		By Overnight Delivery or Regular Mail: Wells Fargo Bank, N.A MAC-N9303-121 Corporate Trust Operations Sixth Street & Marquette Avenue Minneapolis, MN 55479 Attn: Reorg

By Facsimile:
(612) 667-6282
Attn: Bondholder Communications

Confirm by Email:
bondholdercommunications@wellsfargo.com

Confirm by Telephone:
(800) 344-5128
Attn: Bondholder Communications

If you wish to exchange old 7.75% Senior Notes due 2019 for an equal aggregate principal amount at maturity of new 7.75% Senior Notes due 2019 pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the exchange agent prior to the expiration date.

The undersigned hereby acknowledges receipt and review of the Prospectus, dated , 2014 (the "Prospectus"), of Clayton Williams Energy, Inc. (the "Issuer"), and this Letter of Transmittal (the "Letter of Transmittal"), which together describe the Issuer's offer (the "Exchange Offer") to exchange its 7.75% Senior Notes due 2019 (the "new notes") that have been registered under the Securities Act, as amended (the "Securities Act"), for a like principal amount of its issued and outstanding 7.75% Senior Notes due 2019 (the "old notes"). Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

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The Issuer reserves the right, at any time or from time to time, to extend the Exchange Offer at its discretion, in which event the term "Expiration Date" shall mean the latest date to which the Exchange Offer is extended. The Issuer shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

This Letter of Transmittal is to be used by holders of the old notes. Tender of old notes is to be made according to the Automated Tender Offer Program ("ATOP") of the Depository Trust Company ("DTC") pursuant to the procedures set forth in the prospectus under the caption "Exchange Offer—Procedures for Tendering." DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent's DTC account. DTC will then send a computer generated message known as an "agent's message" to the exchange agent for its acceptance. For you to validly tender your old notes in the Exchange Offer the Exchange Agent must receive prior to the Expiration Date, an agent's message under the ATOP procedures that confirms that:

•: DTC has received your instructions to tender your old notes; and
•: you agree to be bound by the terms of this Letter of Transmittal.

BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT

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ANNEX B: GLOSSARY OF NATURAL GAS AND OIL TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:

3-D seismic. An advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

BOE. One barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

Bbl. One barrel, or 42 U.S. gallons of liquid volume.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet of natural gas equivalents.

Btu. One British thermal unit. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or gas.

Credit facility. A line of credit provided by a group of banks, secured by oil and gas properties.

DD&A. Depreciation, depletion and amortization of the Company's property and equipment.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the cost of the operation.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Gross acres or wells. The total acres or wells in which the Company has a working interest.

Horizontal drilling. A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

MBbls. One thousand barrels.

MBOE. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content.

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MMbtu. One million British thermal units.

MMBbls. One million barrels.

MMBOE. One million barrels of oil equivalent.

MMcf. One million cubic feet.

MMcfe. One million cubic feet of natural gas equivalents.

Natural gas liquids. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

Net acres or wells. The sum of fractional ownership working interest in gross acres or wells.

Net production. Oil and gas production that is owned by the Company, less royalties and production due others.

NGL. Natural gas liquids.

NYMEX. New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded.

Oil. Crude oil or condensate.

Operator. The individual or company responsible for the exploration, development and production of an oil or gas well or lease.

Present value of proved reserves ("PV-10"). The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) nonproperty related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

Productive wells. Producing wells and wells mechanically capable of production.

Proved Developed Reserves. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as

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seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities.

Proved undeveloped reserves (PUD). Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

SEC. The United States Securities and Exchange Commission.

Standardized measure of discounted future net cash flows. Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) estimated future income taxes.

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Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.

VPP. Volumetric production payment.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

Workover. Operations on a producing well to restore or increase production.

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 20. Indemnification of Directors and Officers.

Subsection (a) of Section 145 of the Delaware General Corporation Law, or DGCL, empowers a corporation to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by the person in connection with such action, suit or proceeding if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe the person's conduct was unlawful.

Subsection (b) of Section 145 empowers a corporation to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that such person acted in any of the capacities set forth above, against expenses (including attorneys' fees) actually and reasonably incurred by the person in connection with the defense or settlement of such action or suit if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation, except that no indemnification shall be made in respect to any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper.

Section 145 further provides that to the extent a director or officer of a corporation has been successful on the merits or otherwise in the defense of any such action, suit or proceeding referred to in subsections (a) and (b) of Section 145 or in the defense of any claim, issue or matter therein, he shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred by him in connection therewith; that the indemnification provided for by Section 145 shall not be deemed exclusive of any other rights which the indemnified party may be entitled; that indemnification provided by Section 145 shall, unless otherwise provided when authorized or ratified, continue as to a person who has ceased to be a director, officer, employee or agent and shall inure to the benefit of such person's heirs, executors and administrators; and empowers the corporation to purchase and maintain insurance on behalf of a director or officer of the corporation against any liability asserted against him and incurred by him in any such capacity, or arising out of his status as such, whether or not the corporation would have the power to indemnify him against such liabilities under Section 145.

Section 102(b)(7) of the DGCL provides that a certificate of incorporation may contain a provision eliminating or limiting the personal liability of a director to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, provided that such provision shall not eliminate or limit the liability of the director:

•: For any breach of the director's duty of loyalty to the corporation or its stockholders;
•: For acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;
•: Under Section 174 of the DGCL; or

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•: For any transaction from which the director derived an improper personal benefit.

In accordance with Section 102(b)(7), Article VI of our Second Restated Certificate of Incorporation, as amended, provides that, in general, no director of the registrant shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director's duty of loyalty to the Company or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the General Corporation Law of the State of Delaware, or (iv) for any transaction from which the director derived an improper personal benefit.

In addition, Article IX of our Second Restated Certificate of Incorporation, as amended, and Article VI of our Bylaws provide, in general, that we shall indemnify each of our directors and officers against expenses, judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with any third party proceeding if such person acted in good faith and in a manner such person reasonably believed to be in, or not opposed to, our best interests and, with respect to any criminal third party proceeding, had no reasonable cause to believe such conduct was unlawful.

Item 21. Exhibits and Financial Statement Schedules.

(a) The following documents are filed as exhibits to this Registration Statement:

Exhibit Number			Description

	**2.1		Agreement and Plan of Merger among Clayton Williams Energy, Inc. and Southwest Royalties, Inc. dated May 3, 2004, filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the Commission on June 3, 2004††

	**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to the Company's Form S-2 Registration Statement, Commission File No. 333-13441 (incorporated by reference to the filing indicated)

	**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to the Company's Form 10-Q for the period ended September 30, 2000 (incorporated by reference to the filing indicated)

	**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the Commission on March 12, 2008 (incorporated by reference to the filing indicated)

	**4.1		Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company's Current Report on Form 8-K filed with the Commission on June 2, 2004 (incorporated by reference to the filing indicated)

	**4.2		Indenture, dated March 16, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee, filed as Exhibit 4.1 to the Company's Current Report on Form 8-K (File No. 1-10924) filed with the SEC on March 17, 2011 (incorporated by reference to the filing indicated)

	**4.3		Registration Rights Agreement dated as of October 1, 2013, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to the Company's Current Report on Form 8-K filed with the SEC on October 2, 2013 (incorporated by reference to the filing indicated)

	*5.1		Opinion of Vinson & Elkins L.L.P.

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		Description

**10.1		Second Amended and Restated Credit Agreement dated as of November 29, 2010, among Clayton Williams Energy, Inc., as Borrower, certain Subsidiaries of Clayton Williams Energy, Inc., as Guarantors, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on December 2, 2010††

**10.2		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††

**10.3		Second Amendment to Second Amended and Restated Credit Agreement dated May 17, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 10-Q filed with the Commission on August 5, 2011††

**10.4		Third Amendment to Second Amended and Restated Credit Agreement dated as of November 17, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on November 21, 2011††

**10.5		Fourth Amendment to Second Amended and Restated Credit Agreement dated April 23, 2012, filed as Exhibit 10.1 to the Company's Current Report on Form 10-Q filed with the Commission on August 7, 2012††

**10.6		Fifth Amendment to Second Amended and Restated Credit Agreement dated August 30, 2012, filed as Exhibit 10.1 to the Company's Current Report on Form 10-Q filed with the Commission on November 6, 2012††

**10.7		Sixth Amendment to Second Amended and Restated Credit Agreement dated November 16, 2012, filed as Exhibit 10.7 to the Company's Form 10-K for the period ended December 31, 2012††

**10.8		Seventh Amendment to Second Amended and Restated Credit Agreement dated April 5, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on April 30, 2013††

**10.9		Eighth Amendment to Second Amended and Restated Credit Agreement dated September 17, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on September 23, 2013††

**10.10	†	Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company's Form S-8 Registration Statement, Commission File No. 33-68316

**10.11	†	First Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company's Form 10-K for the period ended December 31, 1995††

**10.12	†	Second Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company's Form 10-K for the period ended December 31, 2005††

**10.13	†	Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company's Form S-8 Registration Statement, Commission File No. 33-68316

**10.14	†	Form of stock option agreement for Outside Directors Stock Option Plan, filed as Exhibit 10.38 to the Company's Form 10-K for the period ended December 31, 2004††

**10.15	†	Bonus Incentive Plan, filed as Exhibit 10.1 to the Company's Form S-8 Registration Statement, Commission File No. 33-68320

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		Description

**10.16	†	First Amendment to Bonus Incentive Plan, filed as Exhibit 10.9 to the Company's Form 10-K for the period ended December 31, 1997††

**10.17	†	Scudder Trust Company Prototype Defined Contribution Plan adopted by Clayton Williams Energy, Inc. effective as of August 1, 2004, filed as Exhibit 10.12 to the Company's Form 10-K for the period ended December 31, 2004††

**10.18	†	Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company's Form S-8 Registration Statement, Commission File No. 33-92834

**10.19	†	First Amendment to Executive Incentive Stock Compensation Plan, filed as Exhibit 10.16 to the Company's Form 10-K for the period ended December 31, 1996††

**10.20		Consolidation Agreement dated May 13, 1993 among Clayton Williams Energy, Inc., Warrior Gas Co. and the Williams Entities, filed as Exhibit 10.1 to the Company's Form S-1 Registration Statement, Commission File No. 033-43350

**10.21		Amendment to Consolidation Agreement dated August 7, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams Companies, filed as Exhibit 10.1 to the Company's Form 10-Q for the period ended September 30, 2000††

**10.22		Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.42 to the Company's Form S-1 Registration Statement, Commission File No. 033-43350

**10.23		Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.35 to the Company's Form 10-K for the period ended December 31, 2004††

**10.24		Second Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.36 to the Company's Form 10-K for the period ended December 31, 2004††

**10.25		Second Amended and Restated Service Agreement effective March 1, 2005 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., Clayton Williams Partnership, Ltd. and CWPLCO, Inc., filed as Exhibit 99.1 to the Company's Current Report on Form 8-K filed with the Commission on March 3, 2005††

**10.26		Amendment to Second Amended and Restated Service Agreement effective January 1, 2008 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams, Jr., Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., The Williams Children's Partnership, Ltd. and CWPLCO, Inc. filed as Exhibit 10.26 to the Company's Form 10-K for the period ended December 31, 2008††

**10.27	†	Form of Director Indemnification Agreement, filed as Exhibit 10.71 to the Company's Form 10-K for the period ended December 31, 2008††

**10.28	†	Employment Agreement by and between Clayton Williams Energy, Inc. and Clayton W. Williams, Jr., effective as of March 1, 2010, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.29	†	Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of June 1, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 7, 2011††

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		Description

**10.30	†	Employment Agreement by and between Clayton Williams Energy, Inc. and Patrick C. Reesby, effective as of March 1, 2010, filed as Exhibit 10.4 to the Company's Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.31	†	Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Michael L. Pollard, effective as of June 1, 2011, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.32	†	Employment Agreement by and between Clayton Williams Energy, Inc. and Greg S. Welborn, effective as of March 1, 2010, filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.33	†	Employment Agreement by and between Clayton Williams Energy, Inc. and T. Mark Tisdale, effective as of March 1, 2010, filed as Exhibit 10.7 to the Company's Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.34	†	Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of June 1, 2011, filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.35	†	Employment Agreement between Clayton Williams Energy, Inc. and Ron D. Gasser dated February 21, 2013 filed as Exhibit 10.33 to the Company's Form 10-K for the period ended December 31, 2012††

**10.36	†	Employment Agreement between Clayton Williams Energy, Inc. and Sam Lyssy dated February 21, 2013 filed as Exhibit 10.34 to the Company's Form 10-K for the period ended December 31, 2012††

**10.37	†	Employment Agreement between Clayton Williams Energy, Inc. and John F. Kennedy dated February 21, 2013 filed as Exhibit 10.35 to the Company's Form 10-K for the period ended December 31, 2012††

**10.38	†	Southwest Royalties, Inc. Reward Plan dated January 15, 2007, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with Commission on January 18, 2007††

**10.39	†	Form of Notice of Bonus Award Under the Southwest Royalties, Inc. Reward Plan, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on January 18, 2007††

**10.40	†	Amacker Tippett Reward Plan dated June 19, 2008, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.41	†	Austin Chalk Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.42	†	Barstow Area Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.43	†	Fuhrman-Mascho Reward Plan dated December 1, 2009, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on December 2, 2009††

**10.44	†	CWEI Andrews Fee Reward Plan dated October 19, 2010, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on October 22, 2010††

**10.45	†	CWEI Andrews Samson Reward Plan dated October 19, 2010, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on October 22, 2010††

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		Description

**10.46	†	CWEI Austin Chalk Reward Plan II dated October 19, 2010, filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the Commission on October 22, 2010††

**10.47	†	CWEI Andrews Fee Reward Plan II dated June 28, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.48	†	CWEI Andrews University Reward Plan dated June 28, 2011, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.49	†	CWEI Austin Chalk Reward Plan III dated June 28, 2011, filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.50	†	CWEI Delaware Basin Reward Plan dated June 28, 2011, filed as Exhibit 10.4 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.51	†	CWEI Andrews Samson Reward Plan II dated June 28, 2011, filed as Exhibit 10.5 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.52	†	CWEI South Louisiana Reward Plan dated June 28, 2011, filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.53	†	CWEI Oklahoma 3D Phase 1 Reward Plan dated May 1, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on May 28, 2013††

**10.54	†	CWEI Oklahoma 3D Phase 2 Reward Plan dated May 1, 2013, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on May 28, 2013††

**10.55	†	CWEI Eagle Ford I Reward Plan dated August 20, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on August 22, 2013††

**10.56	†	CWEI East Permian Reward Plan dated August 20, 2013, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on August 22, 2013††

**10.57	†	Participation Agreement relating to West Coast Energy Properties, L.P. dated December 11, 2006, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on December 14, 2006††

**10.58	†	Participation Agreement relating to RMS/Warwink dated April 10, 2007, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on April 13, 2007††

**10.59	†	Participation Agreement relating to CWEI Andrews Area dated June 19, 2008, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.60	†	Participation Agreement relating to CWEI Crockett County Area dated June 19, 2008, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.61	†	Participation Agreement relating to CWEI South Louisiana VI dated June 19, 2008, filed as Exhibit 10.5 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.62	†	Participation Agreement relating to CWEI Utah dated June 19, 2008, filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

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		Description

**10.63	†	Participation Agreement relating to CWEI Sacramento Basin I dated August 12, 2008, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on August 14, 2008††

*12.1		Computation of Ratio of Earnings to Fixed Charges

*21.1		Subsidiaries of the Registrant

*23.1		Consent of KPMG LLP

*23.2		Consent of Williamson Petroleum Consultants, Inc.

*23.3		Consent of Ryder Scott Company, L.P.

*23.4		Consent of Vinson & Elkins L.L.P. (included in Exhibit 5.1)

*24.1		Power of Attorney

*25.1		Statement of Eligibility on Form T-1 of Wells Fargo Bank, National Association

**99.1		Summary Report of Williamson Petroleum Consultants, Inc. relating to Warrior Gas Company properties (incorporated by reference to Exhibit 99.1 to the Annual Report on Form 10-K (Commission File No. 001-10924) filed on March 5, 2013)

**99.2		Summary Report of Ryder Scott Company, L.P. relating to Southwest Royalties, Inc. properties (incorporated by reference to Exhibit 99.2 to the Annual Report on Form 10-K (Commission File No. 001-10924) filed on March 5, 2013)

*: Filed herewith.
**: Incorporated by reference to the filing indicated
†: Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.
††: Filed under the Company's Commission File No. 001-10924.

(b) Financial Data Schedule.

Schedules are omitted because they either are not required or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.

Item 22. Undertakings.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrants, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of a registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, such registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

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Each registrant hereby undertakes:

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(a) to include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(b) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement; and

(c) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if such registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

That, for the purpose of determining liability of such registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, in a primary offering of securities of such registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(a) any preliminary prospectus or prospectus of the undersigned registrants relating to the offering required to be filed pursuant to Rule 424;

(b) any free writing prospectus relating to the offering prepared by or on behalf of such registrant or used or referred to by the undersigned registrants;

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(c) the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrants or their securities provided by or on behalf of such registrant; and

(d) any other communication that is an offer in the offering made by such registrant to the purchaser.

That, for purposes of determining any liability under the Securities Act of 1933, each filing of a registrant annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan's annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

To deliver or cause to be delivered with the prospectus, to each person to whom the prospectus is sent or given, the latest annual report to security holders that is incorporated by reference in the prospectus and furnished pursuant to and meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act of 1934; and, where interim financial information required to be presented by Article 3 of Regulation S-X are not set forth in the prospectus, to deliver, or cause to be delivered to each person to whom the prospectus is sent or given, the latest quarterly report that is specifically incorporated by reference in the prospectus to provide such interim financial information.

To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, State of Texas, on January 24, 2014.


CLAYTON WILLIAMS ENERGY, INC.
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President and Chief Financial Officer
SOUTHWEST ROYALTIES, INC.
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
WARRIOR GAS CO.
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
CWEI ACQUISITIONS, INC.
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
ROMERE PASS ACQUISITION L.L.C.
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
CWEI ROMERE PASS ACQUISITION CORP.
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President

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BLUE HEEL COMPANY
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
TEX-HAL PARTNERS, INC.
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
DESTA DRILLING GP, LLC
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
DESTA DRILLING, L.P.
By:	Desta Drilling GP, LLC, its general partner
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
WEST COAST ENERGY PROPERTIES GP, LLC
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
CLAJON INDUSTRIAL GAS, INC.
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President

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CLAYTON WILLIAMS PIPELINE CORPORATION
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President
SWR VPP LLC
By:	/s/ MICHAEL L. POLLARD
	Name:	Michael L. Pollard
	Title:	Senior Vice President

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Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities indicated.

CLAYTON WILLIAMS ENERGY, INC.

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer)	January 24, 2014
* Mel G. Riggs		Executive Vice President, Chief Operating Officer and Director	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President—Finance and Chief Financial Officer (Principal Financial Officer)	January 24, 2014
* Robert L. Thomas		Vice President—Accounting and Principal Accounting Officer	January 24, 2014
* Robert L. Parker		Director	January 24, 2014
* Jordan R. Smith		Director	January 24, 2014
* Ted Gray, Jr.		Director	January 24, 2014
* Davis L. Ford, Ph.D.		Director	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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SOUTHWEST ROYALTIES, INC.

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board and Director	January 24, 2014
* Mel G. Riggs		President and Director (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
* Ted Gray, Jr.		Director	January 24, 2014
* Davis L. Ford, Ph.D.		Director	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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WARRIOR GAS CO.

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board and Director	January 24, 2014
* Mel G. Riggs		President and Director (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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CWEI ACQUISITIONS, INC.

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board and Director	January 24, 2014
* Mel G. Riggs		President and Director (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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ROMERE PASS ACQUISITION L.L.C.

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board and Manager	January 24, 2014
* Mel G. Riggs		President and Manager (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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CWEI ROMERE PASS ACQUISITION CORP.

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board and Director	January 24, 2014
* Mel G. Riggs		President and Director (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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BLUE HEEL COMPANY

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board and Director	January 24, 2014
* Mel G. Riggs		President and Director (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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TEX-HAL PARTNERS, INC.

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board and Director	January 24, 2014
* Mel G. Riggs		President and Director (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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DESTA DRILLING GP, LLC, on behalf of itself and as general partner of DESTA DRILLING, L.P.

Signatures		Title	Date


* Clayton W. Williams, Jr.		President and Manager	January 24, 2014
* Mel G. Riggs		Executive Vice President and Manager (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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WEST COAST ENERGY PROPERTIES GP, LLC

Signatures		Title	Date


* Clayton W. Williams, Jr.		President	January 24, 2014
* Mel G. Riggs		Executive Vice President and Manager (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
* T. Mark Tisdale		Vice President and Manager	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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CLAJON INDUSTRIAL GAS, INC.

Signatures		Title	Date


* Clayton W. Williams, Jr.		Chairman of the Board, President and Director	January 24, 2014
* Mel G. Riggs		Vice Chairman of the Board, Executive Vice President and Director (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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CLAYTON WILLIAMS PIPELINE CORPORATION

Signatures		Title	Date


* Clayton W. Williams, Jr.		Director	January 24, 2014
* Mel G. Riggs		President and Director (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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SWR VPP, LLC

Signatures		Title	Date


* Clayton W. Williams, Jr.		President	January 24, 2014
* Mel G. Riggs		Executive Vice President (Principal Executive Officer)	January 24, 2014
/s/ MICHAEL L. POLLARD Michael L. Pollard		Senior Vice President and Treasurer (Principal Financial Officer) (Principal Accounting Officer)	January 24, 2014
*By:	/s/ MICHAEL L. POLLARD Michael L. Pollard Attorney-in-fact

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INDEX TO EXHIBITS

Exhibit Number			Description

	**2.1		Agreement and Plan of Merger among Clayton Williams Energy, Inc. and Southwest Royalties, Inc. dated May 3, 2004, filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the Commission on June 3, 2004††
	**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to the Company's Form S-2 Registration Statement, Commission File No. 333-13441 (incorporated by reference to the filing indicated)

	**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to the Company's Form 10-Q for the period ended September 30, 2000 (incorporated by reference to the filing indicated)

	**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the Commission on March 12, 2008 (incorporated by reference to the filing indicated)

	**4.1		Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company's Current Report on Form 8-K filed with the Commission on June 2, 2004 (incorporated by reference to the filing indicated)

	**4.2		Indenture, dated March 16, 2011, by and among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee, filed as Exhibit 4.1 to the Company's Current Report on Form 8-K (File No. 1-10924) filed with the SEC on March 17, 2011 (incorporated by reference to the filing indicated)

	**4.3		Registration Rights Agreement dated as of October 1, 2013, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to the Company's Current Report on Form 8-K filed with the SEC on October 2, 2013 (incorporated by reference to the filing indicated)

	*5.1		Opinion of Vinson & Elkins L.L.P.

	**10.1		Second Amended and Restated Credit Agreement dated as of November 29, 2010, among Clayton Williams Energy, Inc., as Borrower, certain Subsidiaries of Clayton Williams Energy, Inc., as Guarantors, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on December 2, 2010††

	**10.2		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††

	**10.3		Second Amendment to Second Amended and Restated Credit Agreement dated May 17, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 10-Q filed with the Commission on August 5, 2011††

	**10.4		Third Amendment to Second Amended and Restated Credit Agreement dated as of November 17, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on November 21, 2011††

	**10.5		Fourth Amendment to Second Amended and Restated Credit Agreement dated April 23, 2012, filed as Exhibit 10.1 to the Company's Current Report on Form 10-Q filed with the Commission on August 7, 2012††

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		Description


**10.6		Fifth Amendment to Second Amended and Restated Credit Agreement dated August 30, 2012, filed as Exhibit 10.1 to the Company's Current Report on Form 10-Q filed with the Commission on November 6, 2012††

**10.7		Sixth Amendment to Second Amended and Restated Credit Agreement dated November 16, 2012, filed as Exhibit 10.7 to the Company's Form 10-K for the period ended December 31, 2012††

**10.8		Seventh Amendment to Second Amended and Restated Credit Agreement dated April 5, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on April 30, 2013††

**10.9		Eighth Amendment to Second Amended and Restated Credit Agreement dated September 17, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on September 23, 2013††

**10.10	†	Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company's Form S-8 Registration Statement, Commission File No. 33-68316

**10.11	†	First Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company's Form 10-K for the period ended December 31, 1995††

**10.12	†	Second Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company's Form 10-K for the period ended December 31, 2005††

**10.13	†	Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company's Form S-8 Registration Statement, Commission File No. 33-68316

**10.14	†	Form of stock option agreement for Outside Directors Stock Option Plan, filed as Exhibit 10.38 to the Company's Form 10-K for the period ended December 31, 2004††

**10.15	†	Bonus Incentive Plan, filed as Exhibit 10.1 to the Company's Form S-8 Registration Statement, Commission File No. 33-68320

**10.16	†	First Amendment to Bonus Incentive Plan, filed as Exhibit 10.9 to the Company's Form 10-K for the period ended December 31, 1997††

**10.17	†	Scudder Trust Company Prototype Defined Contribution Plan adopted by Clayton Williams Energy, Inc. effective as of August 1, 2004, filed as Exhibit 10.12 to the Company's Form 10-K for the period ended December 31, 2004††

**10.18	†	Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company's Form S-8 Registration Statement, Commission File No. 33-92834

**10.19	†	First Amendment to Executive Incentive Stock Compensation Plan, filed as Exhibit 10.16 to the Company's Form 10-K for the period ended December 31, 1996††

**10.20		Consolidation Agreement dated May 13, 1993 among Clayton Williams Energy, Inc., Warrior Gas Co. and the Williams Entities, filed as Exhibit 10.1 to the Company's Form S-1 Registration Statement, Commission File No. 033-43350

**10.21		Amendment to Consolidation Agreement dated August 7, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams Companies, filed as Exhibit 10.1 to the Company's Form 10-Q for the period ended September 30, 2000††

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		Description

**10.22		Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.42 to the Company's Form S-1 Registration Statement, Commission File No. 033-43350

**10.23		Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.35 to the Company's Form 10-K for the period ended December 31, 2004††

**10.24		Second Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.36 to the Company's Form 10-K for the period ended December 31, 2004††

**10.25		Second Amended and Restated Service Agreement effective March 1, 2005 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., Clayton Williams Partnership, Ltd. and CWPLCO, Inc., filed as Exhibit 99.1 to the Company's Current Report on Form 8-K filed with the Commission on March 3, 2005††

**10.26		Amendment to Second Amended and Restated Service Agreement effective January 1, 2008 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams, Jr., Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., The Williams Children's Partnership, Ltd. and CWPLCO, Inc. filed as Exhibit 10.26 to the Company's Form 10-K for the period ended December 31, 2008††

**10.27	†	Form of Director Indemnification Agreement, filed as Exhibit 10.71 to the Company's Form 10-K for the period ended December 31, 2008††

**10.28	†	Employment Agreement by and between Clayton Williams Energy, Inc. and Clayton W. Williams, Jr., effective as of March 1, 2010, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.29	†	Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of June 1, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.30	†	Employment Agreement by and between Clayton Williams Energy, Inc. and Patrick C. Reesby, effective as of March 1, 2010, filed as Exhibit 10.4 to the Company's Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.31	†	Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Michael L. Pollard, effective as of June 1, 2011, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.32	†	Employment Agreement by and between Clayton Williams Energy, Inc. and Greg S. Welborn, effective as of March 1, 2010, filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.33	†	Employment Agreement by and between Clayton Williams Energy, Inc. and T. Mark Tisdale, effective as of March 1, 2010, filed as Exhibit 10.7 to the Company's Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.34	†	Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of June 1, 2011, filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the Commission on June 7, 2011††

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		Description

**10.35	†	Employment Agreement between Clayton Williams Energy, Inc. and Ron D. Gasser dated February 21, 2013 filed as Exhibit 10.33 to the Company's Form 10-K for the period ended December 31, 2012††

**10.36	†	Employment Agreement between Clayton Williams Energy, Inc. and Sam Lyssy dated February 21, 2013 filed as Exhibit 10.34 to the Company's Form 10-K for the period ended December 31, 2012††

**10.37	†	Employment Agreement between Clayton Williams Energy, Inc. and John F. Kennedy dated February 21, 2013 filed as Exhibit 10.35 to the Company's Form 10-K for the period ended December 31, 2012††

**10.38	†	Southwest Royalties, Inc. Reward Plan dated January 15, 2007, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with Commission on January 18, 2007††

**10.39	†	Form of Notice of Bonus Award Under the Southwest Royalties, Inc. Reward Plan, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on January 18, 2007††

**10.40	†	Amacker Tippett Reward Plan dated June 19, 2008, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.41	†	Austin Chalk Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.42	†	Barstow Area Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.43	†	Fuhrman-Mascho Reward Plan dated December 1, 2009, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on December 2, 2009††

**10.44	†	CWEI Andrews Fee Reward Plan dated October 19, 2010, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on October 22, 2010††

**10.45	†	CWEI Andrews Samson Reward Plan dated October 19, 2010, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on October 22, 2010††

**10.46	†	CWEI Austin Chalk Reward Plan II dated October 19, 2010, filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the Commission on October 22, 2010††

**10.47	†	CWEI Andrews Fee Reward Plan II dated June 28, 2011, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.48	†	CWEI Andrews University Reward Plan dated June 28, 2011, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.49	†	CWEI Austin Chalk Reward Plan III dated June 28, 2011, filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.50	†	CWEI Delaware Basin Reward Plan dated June 28, 2011, filed as Exhibit 10.4 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.51	†	CWEI Andrews Samson Reward Plan II dated June 28, 2011, filed as Exhibit 10.5 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.52	†	CWEI South Louisiana Reward Plan dated June 28, 2011, filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed with the Commission on June 30, 2011††

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		Description

**10.53	†	CWEI Oklahoma 3D Phase 1 Reward Plan dated May 1, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on May 28, 2013††

**10.54	†	CWEI Oklahoma 3D Phase 2 Reward Plan dated May 1, 2013, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on May 28, 2013††

**10.55	†	CWEI Eagle Ford I Reward Plan dated August 20, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on August 22, 2013††

**10.56	†	CWEI East Permian Reward Plan dated August 20, 2013, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on August 22, 2013††

**10.57	†	Participation Agreement relating to West Coast Energy Properties, L.P. dated December 11, 2006, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on December 14, 2006††

**10.58	†	Participation Agreement relating to RMS/Warwink dated April 10, 2007, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on April 13, 2007††

**10.59	†	Participation Agreement relating to CWEI Andrews Area dated June 19, 2008, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.60	†	Participation Agreement relating to CWEI Crockett County Area dated June 19, 2008, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††
**10.61	†	Participation Agreement relating to CWEI South Louisiana VI dated June 19, 2008, filed as Exhibit 10.5 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.62	†	Participation Agreement relating to CWEI Utah dated June 19, 2008, filed as Exhibit 10.6 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.63	†	Participation Agreement relating to CWEI Sacramento Basin I dated August 12, 2008, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on August 14, 2008††

*12.1		Computation of Ratio of Earnings to Fixed Charges

*21.1		Subsidiaries of the Registrant

*23.1		Consent of KPMG LLP

*23.2		Consent of Williamson Petroleum Consultants, Inc.

*23.3		Consent of Ryder Scott Company, L.P.

*23.4		Consent of Vinson & Elkins L.L.P. (included in Exhibit 5.1)

*24.1		Power of Attorney

*25.1		Statement of Eligibility on Form T-1 of Wells Fargo Bank, National Association

**99.1		Summary Report of Williamson Petroleum Consultants, Inc. relating to Warrior Gas Company properties (incorporated by reference to Exhibit 99.1 to the Annual Report on Form 10-K (Commission File No. 001-10924) filed on March 5, 2013)

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Exhibit Number			Description

	**99.2		Summary Report of Ryder Scott Company, L.P. relating to Southwest Royalties, Inc. properties (incorporated by reference to Exhibit 99.2 to the Annual Report on Form 10-K (Commission File No. 001-10924) filed on March 5, 2013)

*: Filed herewith.
**: Incorporated by reference to the filing indicated
†: Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.
††: Filed under the Company's Commission File No. 001-10924.

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Southwest Royalties Inactive S-4Registration of securities issued in business combination transactions