CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2014



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

Commission File Number 001-10924

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)



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



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

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

Not applicable

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

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

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

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



Large accelerated filer o		Accelerated filer x

Non-accelerated filer o		Smaller reporting company o

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

There were 12,165,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of July 30, 2014.

Table of Contents

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS



	PART I. FINANCIAL INFORMATION

		Page

Item 1.	Financial Statements

	Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	3

	Consolidated Statements of Operations and Comprehensive Income (Loss) for the three and six months ended June 30, 2014 and 2013	5

	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2014	6

	Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

Item 4.	Controls and Procedures	43

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44

Item 6.	Exhibits	45

	Signatures	46

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1 -	Financial Statements

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands) ASSETS

	June 30, 2014			December 31, 2013
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	35,709		$	26,623
Accounts receivable:
Oil and gas sales	40,067			39,268
Joint interest and other, net of allowance for doubtful accounts of $1,184 at June 30, 2014 and December 31, 2013	16,021			17,121
Affiliates	131			264
Inventory	31,655			39,183
Deferred income taxes	1,850			7,581
Fair value of derivatives	—			2,518
Prepaids and other	8,246			5,753
	133,679			138,311
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,501,601			2,403,277
Pipelines and other midstream facilities	56,720			54,800
Contract drilling equipment	109,046			96,270
Other	20,763			20,620
	2,688,130			2,574,967
Less accumulated depreciation, depletion and amortization	(1,449,247		)	(1,375,860		)
Property and equipment, net	1,238,883			1,199,107

OTHER ASSETS
Debt issue costs, net	13,637			12,785
Investments and other	16,696			16,534
	30,333			29,319
	$	1,402,895		$	1,366,737

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

Table of Contents

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands) LIABILITIES AND STOCKHOLDERS' EQUITY

	June 30, 2014		December 31, 2013
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	85,458	$	75,872
Oil and gas sales	38,834		37,834
Affiliates	974		874
Fair value of derivatives	6,464		208
Accrued liabilities and other	21,770		21,607
	153,500		136,395
NON-CURRENT LIABILITIES
Long-term debt	624,667		639,638
Deferred income taxes	146,835		140,809
Asset retirement obligations	45,054		49,981
Deferred revenue from volumetric production payment	26,365		29,770
Accrued compensation under non-equity award plans	31,089		15,469
Other	883		892
	874,893		876,559
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 — 12,165,536 shares at June 30, 2014 and December 31, 2013	1,216		1,216
Additional paid-in capital	152,556		152,556
Retained earnings	220,730		200,011
	374,502		353,783
	$	1,402,895	$	1,366,737

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

Table of Contents

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Unaudited) (In thousands, except per share)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
REVENUES
Oil and gas sales	$	113,303		$	93,778		$	223,889		$	192,142
Midstream services	1,837			1,331			3,453			2,227
Drilling rig services	8,493			3,535			15,372			8,852
Other operating revenues	6,262			272			11,786			2,562
Total revenues	129,895			98,916			254,500			205,783
COSTS AND EXPENSES
Production	24,632			26,114			51,079			57,603
Exploration:
Abandonments and impairments	2,887			1,561			6,726			2,371
Seismic and other	225			777			1,708			3,364
Midstream services	490			519			1,024			926
Drilling rig services	5,482			4,397			10,338			9,465
Depreciation, depletion and amortization	38,950			35,872			75,205			74,935
Impairment of property and equipment	—			19,565			3,406			89,102
Accretion of asset retirement obligations	901			1,052			1,787			2,120
General and administrative	21,351			2,783			33,169			10,371
Other operating expenses	238			1,273			740			1,406
Total costs and expenses	95,156			93,913			185,182			251,663
Operating income (loss)	34,739			5,003			69,318			(45,880		)
OTHER INCOME (EXPENSE)
Interest expense	(12,845		)	(10,273		)	(25,366		)	(20,844		)
Gain (loss) on derivatives	(8,324		)	4,894			(13,365		)	(1,641		)
Other	1,049			(416		)	1,889			1,533
Total other income (expense)	(20,120		)	(5,795		)	(36,842		)	(20,952		)
Income (loss) before income taxes	14,619			(792		)	32,476			(66,832		)
Income tax (expense) benefit	(5,292		)	(237		)	(11,757		)	24,594
NET INCOME (LOSS)	$	9,327		$	(1,029	)	$	20,719		$	(42,238	)
Net income (loss) per common share:
Basic	$	0.77		$	(0.08	)	$	1.70		$	(3.47	)
Diluted	$	0.77		$	(0.08	)	$	1.70		$	(3.47	)
Weighted average common shares outstanding:
Basic	12,166			12,165			12,166			12,165
Diluted	12,166			12,165			12,166			12,165

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

Table of Contents

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited) (In thousands)



	Common Stock			Additional				Total
	No. of	Par		Paid-In		Retained		Stockholders’
	Shares	Value		Capital		Earnings		Equity
BALANCE,
December 31, 2013	12,166	$	1,216	$	152,556	$	200,011	$	353,783
Net income	—	—		—		20,719		20,719
BALANCE,
June 30, 2014	12,166	$	1,216	$	152,556	$	220,730	$	374,502

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

Table of Contents

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands)

	Six Months Ended
	June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	20,719		$	(42,238	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	75,205			74,935
Impairment of property and equipment	3,406			89,102
Abandonments and impairments	6,726			2,371
(Gain) loss on sales of assets and impairment of inventory, net	(9,469		)	283
Deferred income tax expense (benefit)	11,757			(24,594		)
Non-cash employee compensation	16,374			(7,101		)
Loss on derivatives	13,365			1,641
Cash settlements of derivatives	(4,591		)	(909		)
Accretion of asset retirement obligations	1,787			2,120
Amortization of debt issue costs and original issue discount	1,644			1,774
Amortization of deferred revenue from volumetric production payment	(3,957		)	(4,484		)
Changes in operating working capital:
Accounts receivable	434			3,219
Accounts payable	(5,027		)	(11,523		)
Other	(3,306		)	(1,710		)
Net cash provided by operating activities	125,067			82,886
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(184,218		)	(133,106		)
Proceeds from volumetric production payment	552			737
Proceeds from sales of assets	73,773			195,277
Decrease in equipment inventory	11,523			5,588
Other	(133		)	(911		)
Net cash provided by (used in) investing activities	(98,503		)	67,585
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	22,522			35,000
Repayments of long-term debt	(40,000		)	(180,000		)
Net cash used in financing activities	(17,478		)	(145,000		)
NET INCREASE IN CASH AND CASH EQUIVALENTS	9,086			5,471
CASH AND CASH EQUIVALENTS
Beginning of period	26,623			10,726
End of period	$	35,709		$	16,197
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	23,712		$	19,169
Cash paid for income taxes	$	1,600		$	—

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

June 30, 2014

(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 June 30, 2014 and for the three and six months ended June 30, 2014 and 2013 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, 2014.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2013.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


3.	Long-Term Debt

Long-term debt consists of the following:



	June 30, 2014		December 31, 2013
	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $333 at June 30, 2014 and $362 at December 31, 2013	$	599,667	$	599,638
Revolving credit facility, due April 2019^(a)	25,000		40,000
	$	624,667	$	639,638

_______


(a)	Renewed and extended in April 2014.

Senior Notes

In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (the “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 the 2019 Senior Notes with an original issue discount of 1% or $0.5 million. In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes at 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. 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 June 30, 2014 and December 31, 2013.

Revolving Credit Facility

In April 2014, we entered into an amended and restated credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. to provide for a revolving line of credit of up to $1 billion, limited to the lesser of the borrowing base amount, as determined by the banks, and the aggregate lender commitments, as determined by us. 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, (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest, or (4) take any combination of options (1) through (3). Increases in aggregate lender commitments require the consent of each lender.

The initial borrowing base and the aggregate lender commitments under the new facility remained at $415 million. The new facility, which matures in April 2019, requires an accelerated maturity of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the facility prior to October 1, 2018. At June 30, 2014, we had $25 million of borrowings outstanding on our revolving credit facility, leaving $384.9 million available under the facility after allowing for outstanding letters of credit totaling $5.1 million.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries except for CWEI Andrews Properties, GP, LLC (see Note 17).

At our election, annual interest rates under our revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.50% and 2.50% 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 0.50% and 1.50% 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 six months ended June 30, 2014 was 2.5%.

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 funded indebtedness are defined in our revolving credit facility. We were in compliance with all financial and non-financial covenants at June 30, 2014 and December 31, 2013.


4.	Sales of Assets

In March 2014, we closed a transaction to sell our interests in selected wells and leases in Wilson, Brazos, La Salle, Frio and Robertson Counties, Texas for $71 million, subject to customary closing adjustments. At closing, $6.8 million of the total proceeds was placed in escrow pending resolution of certain title requirements, $4.3 million of which was released in June 2014. If the remaining title requirements are not satisfied, waived or extended, some or all of the remaining $2.5 million of retained proceeds may be returned to the buyer. To the extent we are able to satisfy any of the remaining title requirements, we may recognize additional net proceeds from the sale in future periods. In February 2014, our wholly owned subsidiary, Southwest Royalties, Inc. (“SWR”), sold a property in Ward County, Texas for $5.1 million, subject to customary closing adjustments. Net proceeds from these sales were used to repay the outstanding balance on our revolving credit facility and to fund a portion of our planned capital expenditures for 2014.

In April 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”). 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. Upon the attainment by the limited partner of predetermined rates of return, our general partner interest in the partnership may increase.

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 December 2013, we sold our remaining interest in the same acreage for $34.5 million, subject to customary closing adjustments. The proceeds from these sales were used to repay a portion of our outstanding balance on our revolving credit facility.


5.	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 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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects the changes in ARO during the six months ended June 30, 2014 and the year ended December 31, 2013:



	June 30, 2014			December 31, 2013
	(In thousands)
Beginning of period	$	49,981		$	51,477
Additional ARO from new properties	478			795
Sales or abandonments of properties	(3,395		)	(5,892		)
Accretion expense	1,787			4,203
Revisions of previous estimates	(3,797		)	(602		)
End of period	$	45,054		$	49,981


6.	Deferred Revenue from Volumetric Production Payment

In March 2012, SWR, a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner, into SWR, with SWR continuing as the surviving entity in the mergers. 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. The net proceeds from the VPP are recorded as a non-current liability in the consolidated balance sheets. Deferred revenue from the VPP is amortized over the life of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). As of June 30, 2014, we have a remaining obligation to deliver approximately 428,000 BOE.

The following table reflects the changes in the deferred revenue during the six months ended June 30, 2014 and the year ended December 31, 2013:



	June 30, 2014			December 31, 2013
	(In thousands)
Beginning of period	$	29,770		$	37,184
Deferred revenue from VPP	552			1,332
Amortization of deferred revenue from VPP	(3,957		)	(8,746		)
End of period	$	26,365		$	29,770


7.	Compensation Plans

Stock-Based Compensation

We presently have options outstanding under a stock option plan for independent directors covering 4,000 shares of Common Stock. As of June 30, 2014, the options had a weighted average exercise price of $33.03 per share (ranging from $22.90 per share to $41.74 per share), a weighted average remaining contractual term of two years, and an aggregate intrinsic value of $417,370 (based on a market price at June 30, 2014 of $137.37 per share). No options were granted during the six months ended June 30, 2014 or 2013.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 (the “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. As of June 30, 2014, we have granted awards under the APO Reward Plan in 15 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 June 11, 2014. Of these 15 awards, eight awards are fully vested, two awards will fully vest on May 1, 2015, two will fully vest on August 1, 2015 and three will fully vest on June 23, 2016.

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 APO cash flow from a 22.5% working interest in one well. The plan is 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 related to non-equity award plans for the three months ended June 30, 2014 and 2013 and six months ended June 30, 2014 and 2013 were $13.5 million and ($4.6) million, $18.2 million and ($2.7) 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:



	June 30, 2014		December 31, 2013
	(In thousands)
Current liabilities:
Accrued liabilities and other	$	4,071	$	3,317
Non-current liabilities:
Accrued compensation under non-equity award plans	31,089		15,469
Total accrued compensation under non-equity award plans	$	35,160	$	18,786

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


8.	Derivatives

Commodity Derivatives

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

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to June 30, 2014. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:



	Oil
	Bbls	Price
Production Period:
3rd Quarter 2014	530,200	$	96.87
4th Quarter 2014	503,200	$	96.92
	1,033,400

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 June 30, 2014, a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $1 million.

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 June 30, 2014
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	—	Current	$	6,464
	Non-current	—		Non-current	—
Total		$	—		$	6,464

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Fair Value of Derivative Instruments as of December 31, 2013
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	2,518	Current	$	208
	Non-current	—		Non-current	—
Total		$	2,518		$	208

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities



	June 30, 2014
	Assets		Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	—	$	6,464
Effects of netting arrangements	—		—
Fair value of derivatives — net presentation	$	—	$	6,464



	December 31, 2013
	Assets			Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	3,909		$	1,599
Effects of netting arrangements	(1,391		)	(1,391		)
Fair value of derivatives — net presentation	$	2,518		$	208

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

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



	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended					Six Months Ended
	June 30,					June 30,
Location of Gain or (Loss) Recognized in Earnings	2014			2013		2014			2013
	(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives	$	(8,324	)	$	4,894	$	(13,365	)	$	(1,641	)
Total	$	(8,324	)	$	4,894	$	(13,365	)	$	(1,641	)

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


9.	Fair Value of Financial Instruments

Cash and cash equivalents, receivables, accounts payable and accrued liabilities are 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 is estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive.

Fair Value Measurements

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

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


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


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


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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The financial assets and liabilities measured on a recurring basis at June 30, 2014 and December 31, 2013 were commodity derivatives. The fair value of all derivative contracts is reflected on the consolidated balance sheet as detailed in the following schedule:



	June 30, 2014		December 31, 2013
	Significant Other
	Observable Inputs
Description	(Level 2)
	(In thousands)
Assets:
Fair value of commodity derivatives	$	—	$	2,518
Total assets	$	—	$	2,518
Liabilities:
Fair value of commodity derivatives	$	6,464	$	208
Total liabilities	$	6,464	$	208

Fair Value of Other Financial Instruments

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

June 30, 2014

December 31, 2013

Carrying

Estimated

Carrying

Estimated

Description

Amount

Fair Value

Amount

Fair Value

(In thousands)

7.75% Senior Notes due 2019

599,667

638,300

599,638

616,500


10.	Income Taxes

Our effective federal and state income tax rate for the six months ended June 30, 2014 of 36.2% 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 2010 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


11.	Other Operating Revenues and Expenses

Other operating revenues and expenses for the three months and six months ended June 30, 2014 and June 30, 2013 are as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013
	(In thousands)				(In thousands)
Other operating revenues:
Gain on sales of assets	$	5,067	$	272	$	10,209	$	767
Marketing revenue	1,195		—		1,577		1,795
Total other operating revenues	$	6,262	$	272	$	11,786	$	2,562
Other operating expenses:
Loss on sales of assets	$	238	$	917	$	730	$	1,044
Marketing expense	—		356		—		356
Impairment of inventory	—		—		10		6
Total other operating expenses	$	238	$	1,273	$	740	$	1,406

During the three months ended June 30, 2014, gain on sales of assets included a $4.9 million gain on sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014. Most of the gain during the three months ended June 30, 2014 related to the release of sales proceeds previously held in escrow pending resolution of title requirements. During the six months ended June 30, 2014, gain on sales of assets included the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014 and the sale of a property in Ward County, Texas in February 2014 (see Note 4).

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


12.	Investment in Dalea Investment Group, LLC

In June 2012, we cancelled an $11 million note receivable 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 June 30, 2014, we have performed a qualitative assessment and determined there has been no indication of any impairment of our investment in Dalea.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


13.	Costs of Oil and Gas Properties

The following table sets forth the net capitalized costs for oil and gas properties as of June 30, 2014 and December 31, 2013.



	June 30, 2014			December 31, 2013
	(In thousands)
Proved properties	$	2,432,557		$	2,317,053
Unproved properties	69,044			86,224
Total capitalized costs	2,501,601			2,403,277
Accumulated depletion	(1,348,563		)	(1,282,989		)
Net capitalized costs	$	1,153,038		$	1,120,288

14. Commitments and Contingencies

Legal Proceedings

SWR is a defendant in a suit filed in April 2011 in the Circuit Court of Union County, Arkansas where the plaintiffs are suing for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. The plaintiffs are seeking in excess of $8 million. In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $0.8 million, of which SWR would pay $0.7 million. 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 were to opt out of the settlement, SWR would 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 the plaintiffs’ claims on the basis that such claims were time barred. SWR believes that the judge will approve the settlement and the number of the plaintiffs opting out of the settlement, if any, will be insignificant. We recorded a loss on settlement of $0.7 million in June 2013 in connection with this proposed settlement. We are now awaiting finalization of the settlement by the court.

In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under our farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”). Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. The case was tried to the judge in October 2013 who ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million. We recorded a loss of $1.4 million in December 2013 in connection with the judgment. As a prerequisite for appeal, CWEI filed a motion with the trial court for a new trial. In March 2014, rather than ruling on the motion, the trial court ordered the parties to a mediation. In April 2014, an attempt to mediate this dispute was unsuccessful, and we have filed a Notice of Appeal. A Court of Appeals briefing is due in August 2014.

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.

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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 no provision for impairment of proved properties for the three months ended June 30, 2014, and $19.6 million for the three months ended June 30, 2013. We recorded a provision for impairment of proved properties of $3.4 million for the six months ended June 30, 2014 and $89.1 million for the six months ended June 30, 2013. The impairment for the three months ended June 30, 2013 was related to the write down of certain non-core Permian Basin properties to their estimated fair value. The impairment for the six months ended June 30, 2014 was related to the write down of certain non-operated properties located in North Dakota to their estimated fair value. The impairment for the six months ended June 30, 2013 was related to the write down of our Andrews County Wolfberry assets and certain non-core areas in the Permian Basin 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 $1.5 million for the three months ended June 30, 2014, $0.3 million for the three months ended June 30, 2013, $5 million for the six months ended June 30, 2014 and $0.4 million for the six months ended June 30, 2013, 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)


16.	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 six months ended June 30, 2014 and 2013:



For the Three Months Ended
June 30, 2014
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	121,403		$	15,242		$	(6,750	)	$	129,895
Depreciation, depletion and amortization ^(a)	36,333			3,420			(803		)	38,950
Other operating expenses ^(b)	50,603			11,014			(5,411		)	56,206
Interest expense	12,845			—			—			12,845
Other (income) expense	7,275			—			—			7,275
Income (loss) before income taxes	14,347			808			(536		)	14,619
Income tax (expense) benefit	(5,009		)	(283		)	—			(5,292		)
Net income (loss)	$	9,338		$	525		$	(536	)	$	9,327
Total assets	$	1,374,443		$	62,231		$	(33,779	)	$	1,402,895
Additions to property and equipment	$	92,587		$	5,209		$	(536	)	$	97,260



For the Six Months Ended
June 30, 2014
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	239,123		$	28,662		$	(13,285	)	$	254,500
Depreciation, depletion and amortization ^(a)	73,715			6,588			(1,692		)	78,611
Other operating expenses ^(b)	96,050			20,928			(10,407		)	106,571
Interest expense	25,366			—			—			25,366
Other (income) expense	11,476			—			—			11,476
Income (loss) before income taxes	32,516			1,146			(1,186		)	32,476
Income tax (expense) benefit	(11,356		)	(401		)	—			(11,757		)
Net income (loss)	$	21,160		$	745		$	(1,186	)	$	20,719
Total assets	$	1,374,443		$	62,231		$	(33,779	)	$	1,402,895
Additions to property and equipment	$	177,779		$	12,866		$	(1,186	)	$	189,459

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



For the Three Months Ended
June 30, 2013
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	95,381		$	6,927		$	(3,392	)	$	98,916
Depreciation, depletion and amortization ^(a)	52,332			3,640			(535		)	55,437
Other operating expenses ^(b)	34,011			7,235			(2,770		)	38,476
Interest expense	10,273			—			—			10,273
Other (income) expense	(4,478		)	—			—			(4,478		)
Income (loss) before income taxes	3,243			(3,948		)	(87		)	(792		)
Income tax (expense) benefit	(1,618		)	1,381			—			(237		)
Net income (loss)	$	1,625		$	(2,567	)	$	(87	)	$	(1,029	)
Total assets	$	1,319,901		$	56,534		$	(27,303	)	$	1,349,132
Additions to property and equipment	$	67,582		$	1,343		$	(87	)	$	68,838



For the Six Months Ended
June 30, 2013
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	196,931		$	17,639		$	(8,787	)	$	205,783
Depreciation, depletion and amortization ^(a)	157,872			7,388			(1,223		)	164,037
Other operating expenses ^(b)	78,030			17,561			(7,965		)	87,626
Interest expense	20,844			—			—			20,844
Other (income) expense	108			—			—			108
Income (loss) before income taxes	(59,923		)	(7,310		)	401			(66,832		)
Income tax (expense) benefit	22,036			2,558			—			24,594
Net income (loss)	$	(37,887	)	$	(4,752	)	$	401		$	(42,238	)
Total assets	$	1,319,901		$	56,534		$	(27,303	)	$	1,349,132
Additions to property and equipment	$	136,174		$	1,603		$	401		$	138,178

_______


(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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


17.	Guarantor Financial Information

In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes. In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes. The 2019 Senior Notes issued in October 2013 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 3). Presented below is condensed consolidated financial information of CWEI (the “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 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 17.

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

Condensed Consolidating Balance Sheet June 30, 2014 (Unaudited) (Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Current assets	$	131,393	$	286,996	$	744	$	(285,454	)	$	133,679
Property and equipment, net	876,824		345,052		17,007		—			1,238,883
Investments in subsidiaries	358,111		—		—		(358,111		)	—
Other assets	16,898		13,435		—		—			30,333
Total assets	$	1,383,226	$	645,483	$	17,751	$	(643,565	)	$	1,402,895
Current liabilities	$	319,504	$	107,793	$	1,197	$	(274,994	)	$	153,500
Non-current liabilities:
Long-term debt	624,667		—		—		—			624,667
Deferred income taxes	120,435		139,604		3,075		(116,279		)	146,835
Other	49,937		53,290		164		—			103,391
	795,039		192,894		3,239		(116,279		)	874,893
Equity	268,683		344,796		13,315		(252,292		)	374,502
Total liabilities and equity	$	1,383,226	$	645,483	$	17,751	$	(643,565	)	$	1,402,895

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet December 31, 2013 (Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Current assets	$	140,100	$	248,314	$	538	$	(250,641	)	$	138,311
Property and equipment, net	833,980		351,171		13,956		—			1,199,107
Investments in subsidiaries	342,416		—		—		(342,416		)	—
Other assets	16,032		13,287		—		—			29,319
Total assets	$	1,332,528	$	612,772	$	14,494	$	(593,057	)	$	1,366,737
Current liabilities	$	290,327	$	93,055	$	976	$	(247,963	)	$	136,395
Non-current liabilities:
Long-term debt	639,638		—		—		—			639,638
Deferred income taxes	118,438		129,880		988		(108,497		)	140,809
Other	36,161		59,829		122		—			96,112
	794,237		189,709		1,110		(108,497		)	876,559
Equity	247,964		330,008		12,408		(236,597		)	353,783
Total liabilities and equity	$	1,332,528	$	612,772	$	14,494	$	(593,057	)	$	1,366,737

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended June 30, 2014 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Total revenue	$	92,114		$	36,801		$	980		$	—		$	129,895
Costs and expenses	70,368			24,216			572			—			95,156
Operating income (loss)	21,746			12,585			408			—			34,739
Other income (expense)	(20,719		)	244			355			—			(20,120		)
Equity in earnings of subsidiaries	8,835			—			—			(8,835		)	—
Income tax (expense) benefit	(535		)	(4,490		)	(267		)	—			(5,292		)
Net income (loss)	$	9,327		$	8,339		$	496		$	(8,835	)	$	9,327

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Six Months Ended June 30, 2014 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Total revenue	$	174,082		$	78,615		$	1,803		$	—		$	254,500
Costs and expenses	129,761			54,342			1,079			—			185,182
Operating income (loss)	44,321			24,273			724			—			69,318
Other income (expense)	(37,991		)	479			670			—			(36,842		)
Equity in earnings of subsidiaries	16,995			—			—			(16,995		)	—
Income tax (expense) benefit	(2,606		)	(8,663		)	(488		)	—			(11,757		)
Net income (loss)	$	20,719		$	16,089		$	906		$	(16,995	)	$	20,719

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended June 30, 2013 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Total revenue	$	64,086		$	34,120		$	710		$	—		$	98,916
Costs and expenses	63,974			29,581			358			—			93,913
Operating income (loss)	112			4,539			352			—			5,003
Other income (expense)	(5,362		)	(541		)	108			—			(5,795		)
Equity in earnings of subsidiaries	2,898			—			—			(2,898		)	—
Income tax (expense) benefit	1,323			(1,399		)	(161		)	—			(237		)
Net income (loss)	$	(1,029	)	$	2,599		$	299		$	(2,898	)	$	(1,029	)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Six Months Ended June 30, 2013 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Total revenue	$	137,370		$	67,703		$	710		$	—		$	205,783
Costs and expenses	191,685			59,620			358			—			251,663
Operating income (loss)	(54,315		)	8,083			352			—			(45,880		)
Other income (expense)	(20,590		)	(470		)	108			—			(20,952		)
Equity in earnings of subsidiaries	5,247			—			—			(5,247		)	—
Income tax (expense) benefit	27,420			(2,665		)	(161		)	—			24,594
Net income (loss)	$	(42,238	)	$	4,948		$	299		$	(5,247	)	$	(42,238	)

Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2014 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Operating activities	$	78,858		$	41,052		$	3,465		$	1,692		$	125,067
Investing activities	(76,913		)	(16,460		)	(3,438		)	(1,692		)	(98,503		)
Financing activities	9,985			(27,486		)	23			—			(17,478		)
Net increase (decrease) in cash and cash equivalents	11,930			(2,894		)	50			—			9,086
Cash at beginning of period	19,693			6,886			44			—			26,623
Cash at end of period	$	31,623		$	3,992		$	94		$	—		$	35,709

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2013 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Operating activities	$	38,195		$	43,274		$	201		$	1,216		$	82,886
Investing activities	83,843			(14,646		)	(396		)	(1,216		)	67,585
Financing activities	(115,481		)	(29,833		)	314			—			(145,000		)
Net increase (decrease) in cash and cash equivalents	6,557			(1,205		)	119			—			5,471
Cash at beginning of period	6,030			4,696			—			—			10,726
Cash at end of period	$	12,587		$	3,491		$	119		$	—		$	16,197


18.	Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of June 30, 2014 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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Item 2 -	Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-Q and in our Form 10-K for the year ended December 31, 2013. Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company,” “we,” “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.

Forward-Looking Statements

The information in this Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current expectations and belief, based on currently available information, as to the outcome and timing of future events and their effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All statements concerning our expectations for future operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties, many of which are beyond our control, and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in our Form 10-K for the year ended December 31, 2013 and in this Form 10-Q.

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


•	estimates of our oil and gas reserves;


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


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


•	our outlook on oil and gas prices;


•	our outlook on domestic and worldwide economic conditions;


•	our access to capital and our anticipated liquidity;


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


•	the impact of political and regulatory developments;


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


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


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

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


•	the possibility of unsuccessful exploration and development drilling activities;


•	our ability to replace and sustain production;


•	commodity price volatility;


•	domestic and worldwide economic conditions;

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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 revolving credit facility and impairments;


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


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


•	drilling and other operating risks;


•	hurricanes and other weather conditions;


•	lack of availability of goods and services;


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


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


•	the other risks described in our Form 10-K for the year ended December 31, 2013 and in this Form 10-Q.

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

As previously discussed, should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended December 31, 2013 and in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We specifically disclaim all responsibility to publicly update or revise any information contained in a forward-looking statement or any forward-looking statement in its entirety after the date made, whether as a result of new information, future events or otherwise, except as required by law.

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

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Overview

We are engaged in developmental drilling in two primary oil-prone regions, the Southern Delaware Basin and the Giddings Area in Texas, where we have a significant inventory of developmental drilling opportunities. During the six months ended June 30, 2014, we spent $176.2 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 second quarter of 2014 and the outlook for the remainder of 2014.


•	We sold all of our interests in certain non-core Austin Chalk/Eagle Ford assets in March 2014 and sold 95% of our Andrews County Wolfberry assets in April 2013. As a result, reported oil and gas production, revenues and operating costs for the quarter and six months ended June 30, 2014 are not comparable to reported amounts for the same period in 2013.

•

Our oil and gas sales, excluding amortized deferred revenues, increased $19.8 million, or 22%, from the second quarter 2013. Production variances accounted for a $16.5 million increase and price variances accounted for a $3.3 million increase. Average realized oil prices were $96.01 per barrel in the second quarter of 2014 versus $93.71 per barrel in the second quarter 2013, and average realized gas prices were $4.49 per Mcf in 2014 versus $3.89 per Mcf in 2013. In addition, oil and gas sales for the second quarter of 2014 includes $1.9 million of amortized deferred revenue attributable to the volumetric production payment (“VPP”) versus $2.2 million for the second quarter of 2013. Reported production and related average realized sales prices exclude volumes associated with the VPP.

•

Before giving effect to the asset sales discussed above, oil, gas and natural gas liquids (“NGL”) production per barrel of oil equivalent (“BOE”) increased 12% in the second quarter of 2014 compared to the second quarter of 2013, with oil production increasing 20% to 11,451 barrels per day, gas production decreasing 14% to 15,154 Mcf per day and NGL production increasing 12% to 1,582 barrels per day. Oil and NGL production accounted for approximately 84% of our total BOE production in the second quarter of 2014 versus 79% in the second quarter of 2013.


•	After giving effect to the asset sales, total production on a BOE basis increased 20% in the second quarter of 2014 as compared to the second quarter of 2013, with oil production increasing 2,803 barrels per day (32%), gas production decreasing 2,308 Mcf per day (13%) and NGL production increasing 186 barrels per day (13%).


•	Production costs decreased 6%, or $1.5 million, in the second quarter of 2014 compared to the second quarter of 2013 due primarily to cost reductions associated with the sale of non-core Austin Chalk/Eagle Ford assets in March 2014 and lower repairs and maintenance costs. These reductions were offset in part by an increase in production taxes associated with higher oil and gas sales.

•

We recorded an $8.3 million loss on derivatives in the second quarter of 2014 (including a $3.5 million loss on settled contracts). For the same period in 2013, we recorded a $4.9 million gain on derivatives (net of a $0.5 million 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 $21.4 million in the second quarter of 2014 compared to $2.8 million in the second quarter of 2013. Changes in compensation expense attributable to our APO reward plans accounted for a net increase of $18.1 million ($13.5 million expense in the second quarter of 2014 versus a $4.6 million credit in the second quarter of 2013). Most of the expense in the second quarter of 2014 related to increases in estimated future compensation expense associated with Delaware Basin and Eagle Ford APO reward plans, while the credit in the second quarter of 2013 related primarily to reductions in previously accrued compensation associated with APO reward plans affected by the Andrews sale.


•	Other operating revenues in the second quarter of 2014 include a $4.9 million gain on sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014. Most of the gain in the second quarter of 2014 related to the release of sales proceeds previously held in escrow pending resolution of certain title requirements.

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Recent Exploration and Development Activities

Overview

We have been committed to drilling primarily developmental oil wells in the Permian Basin and the Giddings Area. We spent $176.2 million during the first six months of 2014 on exploration and development activities and currently plan to spend approximately $440 million on similar activities during 2014. Our actual expenditures during 2014 may vary significantly from these estimates since our plans for exploration and development activities may change during 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 2014.

Areas of Operations

Permian Basin

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

We spent $86 million in the Permian Basin during the first six months of 2014 on drilling and completion activities and $11 million on leasing and seismic activities. We drilled and completed 36 gross (11 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during the first six months of 2014. We currently plan to spend approximately $213.2 million on drilling and leasing activities in this area during 2014. Following is a discussion of our principal assets in the Permian Basin.

Delaware Basin

We currently hold approximately 80,000 net acres in the active Wolfbone resource play in the Delaware Basin in Reeves, Ward and Winkler Counties, Texas and may earn up to 5,000 additional net acres under an existing farm-in arrangement. The Wolfbone resource play generally refers to the interval from the Bone Springs formation down through the Wolfcamp formation at depths typically found between 8,000 and 13,000 feet. A Wolfbone well generally refers to a vertical well completed in multiple intervals within these formations or a horizontal well being completed in an interval within such formations. These Permian aged formations in the Delaware Basin are composed of limestone, sandstone and shale. Geology in the Delaware Basin consists of multiple stacked pay zones with both over-pressured and normal-pressured intervals.

A significant portion of our current holdings in this area is associated with a farm-in agreement we entered into in March 2011, with Chesapeake Exploration, L.L.C. (“Chesapeake”) in southern Reeves County, Texas with a term of five years. Chesapeake’s position in the agreement is now held by SWEPI, LP (“Shell”). For the first well that we drill in a section within the farm-in area that meets certain specified requirements (each, a “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. We amended the farm-in agreement with Shell in February 2014. The amendment replaced a commitment for 20 carried wells per year with a commitment to drill nine additional carried wells prior to December 31, 2014, on which date the agreement will terminate. Failure to drill these remaining carried wells will result in a penalty of $1 million for each undrilled well. We have since commenced the drilling of seven of these wells, and anticipate that all of the commitment wells will be timely drilled. We have earned over 21,000 net acres under the farm-in. The amendment further provides for the renewal or extension of leases in the farm-in area with Shell receiving a 25% carry in the renewal costs in lieu of a drilling carry.

Most of our horizontal drilling to date has targeted the Wolfcamp A shale interval in Reeves County, with 17 Wolfcamp A wells currently in production, one well being completed and two wells being drilled. We also have one Wolfcamp C well currently in production, two wells being completed and one well being drilled.

We spent approximately $74.6 million on drilling and completion activities and $10.6 million for leasing activities in the Wolfbone play during the first six months of 2014. We plan to spend approximately $175.9 million on drilling and

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completion activities and $15.6 million on leasing activities in the Wolfbone play during 2014. In May 2014, we added a third drilling rig to our Wolfbone play and plan to add one additional rig in September 2014.

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.

Other Permian Basin

During the first six months of 2014, approximately 34% of our oil and gas production was derived from wells in parts of the Permian Basin other than our Delaware Basin Wolfbone resource play. Many of these wells are located on the Central Basin Platform, geographically located between the Midland Basin and Delaware Basin, and produce from formations with conventional porosity such as the San Andres, Grayburg, Fusselman, Ellenburger and Yeso formations. A significant portion of our production in this area is derived from mature fields, several of which are in varying stages of secondary and/or tertiary recovery.

Giddings Area

Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area. Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas. Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale and Taylor formations. We have approximately 185,000 net acres in the Giddings Area. 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

In June 2014, we added a third drilling rig to our Eagle Ford Shale play, which is concentrated in the northern portion of our legacy Austin Chalk acreage block in Robertson, Burleson and Lee Counties, Texas. We currently have 16 horizontal Eagle Ford Shale wells in this area in production, three wells being completed and three wells being drilled. During the first six months of 2014, we spent approximately $59.6 million on drilling and completion activities and $13.7 million on leasing activities in the Eagle Ford Shale Area, and we currently plan to spend approximately $213.7 million on similar drilling and leasing activities in this area during 2014.

Other

We spent $5.9 million during the first six months of 2014 on exploration and development activities in other regions, including South Louisiana, Oklahoma and California, and we currently plan to spend approximately $13.1 million for 2014.

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 351 miles of pipeline, two treating plants, one dehydration facility and multiple 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.

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Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we operate 14 drilling rigs, 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 July 24, 2014, we were using six of our rigs to drill wells in our core development areas, three rigs were working for an affiliated partnership, three rigs were working for third parties and the remaining two rigs were idle.

Known Trends and Uncertainties

We began 2013 with limited availability under our revolving credit facility and our leverage ratios were increasing. In 2013, we successfully executed our plan to significantly improve liquidity through a combination of strategic steps to lower capital spending, sell certain producing properties and issue additional 2019 Senior Notes. At June 30, 2014, we had $25 million outstanding under our revolving credit facility, leaving $384.9 million available on the facility after allowing for outstanding letters of credit totaling $5.1 million as compared to $315 million on our revolving credit facility at June 30, 2013. Our leverage ratio, expressed as the ratio of total long-term debt to EBITDAX, was 2.0 times based on annualized EBITDAX for the first six months of 2014. We believe these actions were effective in achieving a more sustainable balance between our future capital commitments and our expected financial resources.

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 flows 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 occurs in future periods, we may discontinue a program until margins return to acceptable levels.

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Supplemental Information

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



	Three Months Ended June 30,
	2014			2013
Oil and Gas Production Data:
Oil (MBbls)	1,042			867
Gas (MMcf)	1,379			1,600
Natural gas liquids (MBbls)	144			129
Total (MBOE)	1,416			1,263
Total (BOE/d)	15,559			13,875
Average Realized Prices ^{(a) (b)}:
Oil ($/Bbl)	$	96.01		$	93.71
Gas ($/Mcf)	$	4.49		$	3.89
Natural gas liquids ($/Bbl)	$	31.55		$	31.07
Loss on Settled Derivative Contracts ^(b):
($ in thousands, except per unit)
Oil: Net realized loss	$	(3,454	)	$	(169	)
Per unit produced ($/Bbl)	$	(3.31	)	$	(0.19	)
Gas: Net realized loss	$	—		$	(295	)
Per unit produced ($/Mcf)	$	—		$	(0.18	)
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	3,613			1,989
Other ^(c)	3,306			3,406
Austin Chalk ^(c)	2,122			2,737
Eagle Ford Shale ^(c)	1,953			1,128
Other	457			267
Total	11,451			9,527
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	2,932			1,921
Other ^(c)	6,588			7,474
Austin Chalk ^(c)	1,593			2,146
Eagle Ford Shale ^(c)	344			50
Other	3,697			5,991
Total	15,154			17,582
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	537			283
Other ^(c)	732			882
Austin Chalk ^(c)	152			212
Eagle Ford Shale ^(c)	141			14
Other	20			27
Total	1,582			1,418
(Continued)

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	Three Months Ended June 30,
	2014		2013
Exploration Costs (in thousands):
Abandonment and impairment costs:
Oklahoma	$	2,390	$	—
Permian Basin	18		—
Michigan	3		—
South Louisiana	—		785
Other	476		776
Total	2,887		1,561
Seismic and other	225		777
Total exploration costs	$	3,112	$	2,338
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	35,687	$	32,194
Contract drilling depreciation	2,616		3,105
Other depreciation	647		573
Total depreciation, depletion, and amortization	$	38,950	$	35,872
Oil and Gas Costs ($/BOE Produced):
Production costs	$	17.40	$	20.68
Production costs (excluding production taxes)	$	13.41	$	16.90
Oil and gas depletion	$	25.20	$	25.49
Net Wells Drilled ^(d):
Exploratory Wells	6.9		1.5
Developmental Wells	7.6		12.2



	Six Months Ended June 30,
	2014			2013
Oil and Gas Production Data:
Oil (MBbls)	2,053			1,805
Gas (MMcf)	2,793			3,226
Natural gas liquids (MBbls)	290			274
Total (MBOE)	2,809			2,617
Total (BOE/d)	15,517			14,457
Average Realized Prices ^{(a) (b)}:
Oil ($/Bbl)	$	94.82		$	92.43
Gas ($/Mcf)	$	4.73		$	3.59
Natural gas liquids ($/Bbl)	$	35.65		$	31.97
Loss on Settled Derivative Contracts ^(b):
($ in thousands, except per unit)
Oil: Net realized loss	$	(4,591	)	$	(613	)
Per unit produced ($/Bbl)	$	(2.24	)	$	(0.34	)
Gas: Net realized loss	$	—		$	(296	)
Per unit produced ($/Mcf)	$	—		$	(0.09	)
(Continued)

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	Six Months Ended June 30,
	2014		2013
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	3,593		1,862
Other ^(c)	3,385		4,240
Austin Chalk ^(c)	2,146		2,748
Eagle Ford Shale ^(c)	1,802		868
Other	417		254
Total	11,343		9,972
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	2,870		1,524
Other ^(c)	6,861		8,565
Austin Chalk ^(c)	1,800		2,086
Eagle Ford Shale ^(c)	304		61
Other	3,596		5,587
Total	15,431		17,823
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	490		274
Other ^(c)	816		999
Austin Chalk ^(c)	187		210
Eagle Ford Shale ^(c)	89		13
Other	20		18
Total	1,602		1,514
Exploration Costs (in thousands):
Abandonment and impairment costs:
Oklahoma	$	3,086	$	—
North Louisiana	994		—
Michigan	936		—
South Louisiana	602		1,000
Permian Basin	584		4
Other	524		1,367
Total	6,726		2,371
Seismic and other	1,708		3,364
Total exploration costs	$	8,434	$	5,735
(Continued)

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	Six Months Ended June 30,
	2014		2013
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	69,028	$	67,629
Contract drilling depreciation	4,896		6,165
Other depreciation	1,281		1,141
Total depreciation, depletion, and amortization	$	75,205	$	74,935
Oil and Gas Costs ($/BOE Produced):
Production costs	$	18.18	$	22.01
Production costs (excluding production taxes)	$	14.14	$	18.34
Oil and gas depletion	$	24.57	$	25.84
Net Wells Drilled ^(d):
Exploratory Wells	8.2		1.5
Developmental Wells	17.9		24.7

_______

(a)

Oil and gas sales includes $1.9 million for the three months ended June 30, 2014, $2.2 million for the three months ended June 30, 2013, $4 million for the six months ended June 30, 2014 and $4.5 million for the six months ended June 30, 2013 of amortized deferred revenue attributable to the VPP transaction effective March 1, 2012. The calculation of average realized sales prices excludes production of 25,826 barrels of oil and 10,689 Mcf of gas for the three months ended June 30, 2014 and 29,616 barrels of oil and 7,506 Mcf of gas for the three months ended June 30, 2013, 52,421 barrels of oil and 22,622 Mcf of gas for the six months ended June 30, 2014 and 60,104 barrels of oil and 15,039 Mcf of gas for the six months ended June 30, 2013 associated with the VPP.

(b)

Hedging gains/losses are only included in the determination of our average realized prices if the underlying derivative contracts are designated as cash flow hedges under applicable accounting standards. We did not designate any of our 2014 or 2013 derivative contracts as cash flow hedges. This means that our derivatives for 2014 and 2013 have been marked-to-market through our statement of operations as other income/expense instead of through accumulated other comprehensive income on our balance sheet. This also means that all realized gains/losses on these derivatives are reported in other income/expense instead of as a component of oil and gas sales.


(c)	Following is a recap of the average daily production related to interests in producing properties we sold effective April 2013 (Andrews County Wolfberry) and March 2014 (non-core Austin Chalk/Eagle Ford).



	Three Months Ended June 30,	Six Months Ended June 30,
	2013	2014	2013
Average Daily Production:

Andrews County Wolfberry:
Oil (Bbls)	—	—	814
Natural gas (Mcf)	—	—	902
NGL (Bbls)	—	—	179
Total (BOE)	—	—	1,143

Austin Chalk/Eagle Ford:
Oil (Bbls)	879	188	776
Natural gas (Mcf)	121	22	125
NGL (Bbls)	22	6	22
Total (BOE)	921	198	819


(d)	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 June 30, 2014 to the comparative period in 2013. Unless otherwise indicated, references to 2014 and 2013 within this section refer to the three months ended June 30, 2014 and 2013, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, increased $19.8 million, or 22%, in 2014 from 2013. Production variances accounted for a $16.5 million increase, and price variances accounted for a $3.3 million increase. Oil and gas sales in 2014 also includes $1.9 million of amortized deferred revenue versus $2.2 million in 2013 attributable to a VPP. Combined oil, gas and NGL production in 2014 (on a BOE basis) increased 12% compared to 2013. Our production mix increased from 79% oil and NGL in 2013 to approximately 84% in 2014. Oil production increased 20% in 2014 from 2013. NGL production increased 12% while gas production decreased 14% in 2014 from 2013. In 2014, our realized oil price was 2% higher than 2013, and our realized gas price was 15% 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 6% to $24.6 million in 2014 as compared to $26.1 million in 2013 due primarily to cost reductions associated with the sale of non-core Austin Chalk/Eagle Ford assets in March 2014 and lower repair and maintenance costs. These reductions were offset in part by an increase in production taxes associated with higher oil and gas sales.

Oil and gas depletion expense increased $3.5 million from 2013 to 2014 due to a $3.8 million increase related to production variances and a $0.3 million decrease due to rate variances. On a BOE basis, depletion expense decreased 1% to $25.20 per BOE in 2014 from $25.49 per BOE in 2013. Most of the increase in depletion expense related to increases in cost and production in the Wolfbone and Giddings areas. 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 no provision for impairment of property and equipment in 2014 compared to $19.6 million in 2013 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 2014, we charged to expense $3.1 million of exploration costs, as compared to $2.3 million in 2013. Exploration costs in 2014 were primarily due to dry hole costs and unproved acreage impairments in Oklahoma.

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 $8.5 million in 2014 compared to $3.5 million in 2013. Drilling service costs related to external customers and idle rig charges were $5.5 million in 2014 compared to $4.4 million in 2013. Contract drilling depreciation for 2014 was $2.6 million compared to $3.1 million in 2013.

General and Administrative

G&A expenses increased $18.6 million from $2.8 million in 2013 to $21.4 million in 2014. Changes in compensation expense attributable to our APO reward plans accounted for a net increase of $18.1 million ($13.5 million expense in 2014 versus a $4.6 million credit in 2013). Most of the expense in 2014 related to increases in estimated future compensation expense associated with Delaware Basin and Eagle Ford APO reward plans, while the credit in 2013 related primarily to reductions in previously accrued compensation associated with APO reward plans affected by the Andrews sale.

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Gain/loss on derivatives

We did not designate any derivative contracts in 2014 or 2013 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 June 30, 2014, we reported an $8.3 million loss on derivatives, (including a $3.5 million loss on settled contracts). For the three months ended June 30, 2013, we reported a $4.9 million gain on derivatives, (net of a $0.5 million 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 $4.8 million on sales of assets and impairment of inventory in 2014 compared to a net loss of $0.6 million in 2013. The 2014 gain related primarily to the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014. The 2013 loss related primarily to the sale of our Andrews County Wolfberry assets in April 2013. 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 2014 of 36.2% was greater than the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

Operating Results — Six-Month Periods

The following discussion compares our results for the six months ended June 30, 2014 to the comparative period in 2013. Unless otherwise indicated, references to 2014 and 2013 within this section refer to the six months ended June 30, 2014 and 2013, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, increased $32.3 million, or 17%, in 2014 from 2013. Production variances accounted for a $23.1 million increase, and price variances accounted for a $9.2 million increase. Oil and gas sales in 2014 also includes $4 million of amortized deferred revenue versus $4.5 million in 2013 attributable to a VPP. Combined oil, gas and NGL production in 2014 (on a BOE basis) increased 7% compared to 2013. Our production mix increased from 79% oil and NGL in 2013 to approximately 83% in 2014. Oil production increased 14% in 2014 from 2013. NGL production increased 6% while gas production decreased 13% in 2014 from 2013. In 2014, our realized oil price was 3% higher than 2013, and our realized gas price was 32% 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 $51.1 million in 2014 as compared to $57.6 million in 2013 due primarily to cost reductions associated with the sale of non-core Austin Chalk/Eagle Ford assets in March 2014, the sale of our Andrews County Wolfberry assets in April 2013 and lower repair and maintenance costs.

Oil and gas depletion expense increased $1.4 million from 2013 to 2014 due to a $4.9 million increase related to production variances and a $3.5 million decrease due to rate variances. On a BOE basis, depletion expense decreased 5% to $24.57 per BOE in 2014 from $25.84 per BOE in 2013. Most of the increase in depletion expense related to increases in cost and production in the Wolfbone and Giddings areas offset by a decrease in depletion expense due to the sale of non-core Austin Chalk/Eagle Ford assets in March 2014 and the sale of our Andrews County Wolfberry assets in April 2013. 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 $3.4 million in 2014 and $89.1 million in 2013. The 2014 impairment related to the write down of the carrying value of certain non-operated properties in North Dakota to their estimated fair value. The transaction to monetize our Andrews County Wolfberry assets in April 2013 triggered the assessment

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of a non-cash charge in 2013. 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 2014, we charged to expense $8.4 million of exploration costs, as compared to $5.7 million in 2013. Exploration costs in 2014 were primarily due to dry hole costs and unproved acreage impairments in Oklahoma.

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 $15.4 million in 2014 compared to $8.9 million in 2013. Drilling service costs related to external customers and idle rig charges were $10.3 million in 2014 compared to $9.5 million in 2013. Contract drilling depreciation for 2014 was $4.9 million compared to $6.2 million in 2013.

General and Administrative

G&A expenses increased $22.8 million from $10.4 million in 2013 to $33.2 million in 2014. Compensation expense attributable to our APO reward plans accounted for $20.9 million of the increase ($18.2 million expense in 2014 versus a $2.7 million credit in 2013). Most of the increase in expense in 2014 was related to changes in estimated future compensation expense associated with Delaware Basin and Eagle Ford APO reward plans, while the credit in 2013 related primarily to reductions in previously accrued compensation associated with APO reward plans affected by the Andrews sale.

Gain/loss on derivatives

We did not designate any derivative contracts in 2014 or 2013 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 six months ended June 30, 2014, we reported a $13.4 million loss on derivatives, (including a $4.6 million loss on settled contracts). For the six months ended June 30, 2013, we reported a $1.6 million loss on derivatives, (including a $0.9 million 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 $9.5 million on sales of assets and impairment of inventory in 2014 compared to a net loss of $0.3 million in 2013. The 2014 gain related primarily to the sale of certain of the Austin Chalk/Eagle Ford assets sold in March 2014 and the sale of a property in Ward County, Texas in February 2014. The 2013 loss related primarily to the sale of our Andrews County Wolfberry assets in April 2013. 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

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 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

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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.

Capital expenditures

The following table summarizes, by area, our actual expenditures for exploration and development activities for the first six months of 2014 and our planned expenditures for the year ending December 31, 2014.



	Actual Expenditures Six Months Ended June 30, 2014		Planned Expenditures Year Ending December 31, 2014		2014 Percentage of Total
	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	74,600	$	175,900	40	%
Other	11,400		21,300		5	%
Austin Chalk/Eagle Ford Shale	59,600		182,000		41	%
Other	4,900		9,500		2	%
	150,500		388,700		88	%
Leasing and seismic	25,700		51,300		12	%
Exploration and development	$	176,200	$	440,000	100	%

Our expenditures for exploration and development activities for the six months ended June 30, 2014 totaled $176.2 million. We financed these expenditures for the first six months of 2014 with cash flow from operating activities and proceeds from asset sales. We currently plan to spend approximately $440 million on exploration and development activities during fiscal 2014. Our actual expenditures during 2014 may vary significantly from these estimates since our plans for exploration and development activities may change during 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 2014.

Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow, combined with funds available to us on our revolving credit facility, will be sufficient to finance our planned exploration and development activities through 2014. 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 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 2014, 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 these cash flows to fund our ongoing 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 six months ended June 30, 2014 increased $42.2 million, or 51%, as compared to the corresponding period in 2013 due primarily to increased production, higher commodity prices, and a reduction in production costs associated with the sale of non-core Austin Chalk/Eagle Ford assets in March 2014, the sale of our Andrews County Wolfberry assets in April 2013 and lower repair and maintenance costs.

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 the 2019 Senior Notes with an original issue discount of 1% or $0.5 million. In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior

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Notes. The notes were sold at 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. 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.

Revolving credit facility

We have historically relied on a 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. In April 2014, we entered into an amended and restated credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. to provide for a revolving line of credit of up to $1 billion, limited to the lesser of the borrowing base amount, as determined by the banks, and the aggregate lender commitments, as determined by us.

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, (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest, or (4) take any combination of items (1) through (3). Increases in aggregate lender commitments require the consent of each lender.

In November 2013, the banks increased the aggregate commitment and borrowing base from $407.5 million to $415 million. During the six-month period ended June 30, 2014, we decreased indebtedness outstanding under our revolving credit facility by $15 million. The initial borrowing base and the aggregate lender commitments under the new facility remained at $415 million. The new facility, which matures in April 2019, will require an accelerated maturity of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the facility prior to October 1, 2018.

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.

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.

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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 deficit was $19.8 million at June 30, 2014 compared to working capital of $1.9 million at December 31, 2013. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $371.6 million at June 30, 2014, as compared to $369.6 million at December 31, 2013.

The following table reconciles our GAAP working capital (deficit) to the working capital computed for loan compliance purposes at June 30, 2014 and December 31, 2013.



	June 30, 2014			December 31, 2013
	(In thousands)
Working capital (deficit) per GAAP	$	(19,821	)	$	1,916
Add funds available under our revolving credit facility	384,947			369,947
Exclude fair value of derivatives classified as current assets or current liabilities	6,464			(2,310		)
Working capital per loan covenant	$	371,590		$	369,553

Our revolving credit facility also 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.

We were in compliance with all financial and non-financial covenants at June 30, 2014 and December 31, 2013. 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., Wells Fargo Bank, N.A., Union Bank, N.A., Compass Bank, Frost Bank, The Royal Bank of Scotland plc, KeyBank National Association, Natixis, New York Branch, UBS AG, Stamford Branch, Fifth Third Bank, U.S. Bank National Association, Whitney Bank, Bank of America, N.A., Branch Banking and Trust Company, Capital One, National Association and PNC Bank, National Association.

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 June 30, 2014, JPMorgan Chase Bank, N.A. and Union Bank, N.A. were the counterparties 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 June 30, 2014, we had $25 million of borrowings outstanding under the bank credit facility, resulting in availability under the credit facility of $384.9 million, net of outstanding letters of credit of $5.1 million. With cash on hand of $35.7 million, total liquidity at June 30, 2014 was $420.6 million.

Alternative capital resources

We believe we currently have adequate liquidity to enable us to fund our expected capital expenditures for 2014 through a combination of cash flow from operations, borrowings on our revolving credit facility and proceeds from the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014.

We may also use other capital resources, including (1) entering into joint venture participation agreements with other industry or financial partners in our core development areas, (2) monetizing other non-core assets and (3) issuing additional debt or equity securities in private or public offerings, in order to finance a portion of our capital spending in fiscal 2014 and subsequent periods.

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While we believe we would be able to obtain funds through one or more of these alternative capital resources, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.


Item 3 -	Quantitative and Qualitative Disclosures About Market Risk

Our business is impacted by fluctuations in commodity prices and interest rates. The following discussion is intended to identify the nature of these market risks, describe our strategy for managing such risks, and to quantify the potential effect of market volatility on our financial condition and results of operations and should be read in conjunction with “Quantitative and Qualitative Disclosures About Market Risk” included under Part II - Item 7A of our Form 10-K for the year ended December 31, 2013.

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, 2013 reserve estimates, we project that a $1 decline in the price per barrel of oil and a $.50 decline in the price per Mcf of gas from year end 2013 would reduce our gross revenues for the year ending December 31, 2014 by $7.1 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 New York Mercantile Exchange (“NYMEX”) futures prices, resulting in a net amount due to or from the counterparty. When purchasing floors, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.

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

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Swaps:



	Oil
	Bbls	Price
Production Period:
3rd Quarter 2014	530,200	$	96.87
4th Quarter 2014	503,200	$	96.92
	1,033,400

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At June 30, 2014, our fixed rate debt maturing 2019 had a carrying value of $599.7 million and an approximate fair value of $638.3 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 $25.4 million. Based on our outstanding variable rate indebtedness at June 30, 2014 of $25 million, a change in interest rates of 100-basis points would affect interest payments by $0.3 million.


Item 4 -	Controls and Procedures

Disclosure Controls and Procedures

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

With respect to our disclosure controls and procedures:


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


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

•

it is the conclusion of our chief executive and chief financial officers that as of June 30, 2014 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 six months ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION


Item 1 -	Legal Proceedings


Item 1A -	Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements. Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on March 10, 2014, and available at www.sec.gov.

There have been no material changes to these risk factors. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or future results.

Table of Contents


Item 6 -	Exhibits



Exhibits
**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441

**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††

**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††

**4.1		Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††

**4.2		Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††

**10.1		Third Amended and Restated Credit Agreement dated April 23, 2014, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on April 25, 2014††

**10.2		CWEI Andrews Properties I Reward Plan effective April 18, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2014††

**10.3		CWEI Eagle Ford II Reward Plan effective June 11, 2014, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2014††

**10.4		CWEI Delaware Basin II Reward Plan effective June 11, 2014, filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2014††

*31.1		Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934

*31.2		Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934

***32.1		Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

* Filed herewith.

** Incorporated by reference to the filing indicated.

*** Furnished herewith.

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

Table of Contents

CLAYTON WILLIAMS ENERGY, INC.

SIGNATURES

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



		CLAYTON WILLIAMS ENERGY, INC.

Date:	August 1, 2014	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief Operating Officer

Date:	August 1, 2014	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President and Chief Financial Officer

Table of Contents

INDEX TO EXHIBITS



Exhibits
**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441

**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††

**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††

**4.1		Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††

**4.2		Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††

**10.1		Third Amended and Restated Credit Agreement dated April 23, 2014, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on April 25, 2014††

**10.2		CWEI Andrews Properties I Reward Plan effective April 18, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2014††

**10.3		CWEI Eagle Ford II Reward Plan effective June 11, 2014, filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2014††

**10.4		CWEI Delaware Basin II Reward Plan effective June 11, 2014, filed as Exhibit 10.3 to the Company's Current Report on Form 8-K filed with the Commission on June 25, 2014††

*31.1		Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934

*31.2		Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934

***32.1		Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

* Filed herewith.

** Incorporated by reference to the filing indicated.

*** Furnished herewith.

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

CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q - August 1, 2014

Attached files

CLAYTON WILLIAMS ENERGY INC /DE Reports