CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q

Attached files

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EX-10.5 - EXHIBIT 10.5 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_5lyssy.htm
EX-10.2 - EXHIBIT 10.2 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_2riggs.htm
EX-10.4 - EXHIBIT 10.4 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_4gasser.htm
EX-10.7 - EXHIBIT 10.7 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_7thomas.htm
EX-10.6 - EXHIBIT 10.6 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_6kennedy.htm
EX-10.10 - EXHIBIT 10.10 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_10reesby.htm
EX-10.8 - EXHIBIT 10.8 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_8tisdale.htm
EX-10.9 - EXHIBIT 10.9 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_9welborn.htm
EX-10.1 - EXHIBIT 10.1 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_1williams.htm
EX-10.18 - EXHIBIT 10.18 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_18eaglfordii8615.htm
EX-10.17 - EXHIBIT 10.17 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_17eaglefordi8615.htm
EX-10.11 - EXHIBIT 10.11 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_11austinchalk8615.htm
EX-10.12 - EXHIBIT 10.12 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_12austinchalkii8615.htm
EX-10.15 - EXHIBIT 10.15 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_15delawarebasin8615.htm
EX-10.13 - EXHIBIT 10.13 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_13austinchalkiii8615.htm
EX-10.14 - EXHIBIT 10.14 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_14amackertippett8615.htm
EX-10.16 - EXHIBIT 10.16 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_16delawarebasinii8615.htm
EX-32.1 - EXHIBIT 32.1 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-063015xex321.htm
EX-31.2 - EXHIBIT 31.2 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-063015xex312.htm
EX-31.1 - EXHIBIT 31.1 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-063015xex311.htm
EX-10.3 - EXHIBIT 10.3 - CLAYTON WILLIAMS ENERGY INC /DE	ex10_3pollard.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2015



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.)



6 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 x		Accelerated filer o

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 12,169,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of August 3, 2015.

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, 2015 and December 31, 2014	3

	Consolidated Statements of Operations and Comprehensive Income (Loss) for the three and six months ended June 30, 2015 and 2014	5

	Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2015	6

	Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	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	44

Item 4.	Controls and Procedures	45

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	46

Item 5.	Other Information	47

Item 6.	Exhibits	49

	Signatures	51

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1 -	Financial Statements

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

	June 30, 2015			December 31, 2014
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	7,634		$	28,016
Accounts receivable:
Oil and gas sales	25,262			36,526
Joint interest and other, net of allowance for doubtful accounts of $1,329 at June 30, 2015 and $1,204 December 31, 2014	4,802			14,550
Affiliates	307			322
Inventory	40,907			42,087
Deferred income taxes	9,389			6,911
Prepaids and other	3,655			4,208
	91,956			132,620
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,733,183			2,684,913
Pipelines and other midstream facilities	59,795			59,542
Contract drilling equipment	123,415			122,751
Other	20,465			20,915
	2,936,858			2,888,121
Less accumulated depreciation, depletion and amortization	(1,626,571		)	(1,539,237		)
Property and equipment, net	1,310,287			1,348,884

OTHER ASSETS
Debt issue costs, net	11,299			12,712
Investments and other	16,274			16,669
	27,573			29,381
	$	1,429,816		$	1,510,885

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

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

	June 30, 2015		December 31, 2014
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	29,316	$	93,650
Oil and gas sales	32,233		41,328
Affiliates	159		717
Fair value of derivatives	5,901		—
Accrued liabilities and other	19,139		20,658
	86,748		156,353
NON-CURRENT LIABILITIES
Long-term debt	746,728		704,696
Deferred income taxes	144,411		164,599
Asset retirement obligations	50,326		45,697
Deferred revenue from volumetric production payment	20,135		23,129
Accrued compensation under non-equity award plans	24,761		17,866
Other	477		751
	986,838		956,738
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 — 12,169,536 shares at June 30, 2015 and December 31, 2014	1,216		1,216
Additional paid-in capital	152,686		152,686
Retained earnings	202,328		243,892
	356,230		397,794
	$	1,429,816	$	1,510,885

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,
	2015			2014			2015			2014
REVENUES
Oil and gas sales	$	68,662		$	113,303		$	127,232		$	223,889
Midstream services	1,603			1,837			3,214			3,453
Drilling rig services	—			8,493			23			15,372
Other operating revenues	2,966			6,262			6,904			11,786
Total revenues	73,231			129,895			137,373			254,500
COSTS AND EXPENSES
Production	23,093			24,632			46,523			51,079
Exploration:
Abandonments and impairments	2,508			2,887			4,131			6,726
Seismic and other	105			225			971			1,708
Midstream services	534			490			933			1,024
Drilling rig services	1,620			5,482			3,496			10,338
Depreciation, depletion and amortization	42,121			38,950			84,775			75,205
Impairment of property and equipment	—			—			2,531			3,406
Accretion of asset retirement obligations	977			901			1,935			1,787
General and administrative	11,328			21,351			20,471			33,169
Other operating expenses	2,003			238			2,847			740
Total costs and expenses	84,289			95,156			168,613			185,182
Operating income (loss)	(11,058		)	34,739			(31,240		)	69,318
OTHER INCOME (EXPENSE)
Interest expense	(13,609		)	(12,845		)	(26,886		)	(25,366		)
Loss on derivatives	(12,300		)	(8,324		)	(7,668		)	(13,365		)
Other	871			1,049			1,564			1,889
Total other income (expense)	(25,038		)	(20,120		)	(32,990		)	(36,842		)
Income (loss) before income taxes	(36,096		)	14,619			(64,230		)	32,476
Income tax (expense) benefit	12,764			(5,292		)	22,666			(11,757		)
NET INCOME (LOSS)	$	(23,332	)	$	9,327		$	(41,564	)	$	20,719
Net income (loss) per common share:
Basic	$	(1.92	)	$	0.77		$	(3.42	)	$	1.70
Diluted	$	(1.92	)	$	0.77		$	(3.42	)	$	1.70
Weighted average common shares outstanding:
Basic	12,170			12,166			12,170			12,166
Diluted	12,170			12,166			12,170			12,166

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, 2014	12,170	$	1,216	$	152,686	$	243,892		$	397,794
Net loss	—	—		—		(41,564		)	(41,564		)
BALANCE,
June 30, 2015	12,170	$	1,216	$	152,686	$	202,328		$	356,230

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,
	2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(41,564	)	$	20,719
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	84,775			75,205
Impairment of property and equipment	2,531			3,406
Abandonments and impairments	4,131			6,726
Gain on sales of assets and impairment of inventory, net	(4,249		)	(9,469		)
Deferred income tax expense (benefit)	(22,666		)	11,757
Non-cash employee compensation	7,084			16,374
Loss on derivatives	7,668			13,365
Cash settlements of derivatives	(1,767		)	(4,591		)
Accretion of asset retirement obligations	1,935			1,787
Amortization of debt issue costs and original issue discount	1,495			1,644
Amortization of deferred revenue from volumetric production payment	(3,501		)	(3,957		)
Other	404			—
Changes in operating working capital:
Accounts receivable	21,027			434
Accounts payable	(26,211		)	(5,027		)
Other	(2,472		)	(3,306		)
Net cash provided by operating activities	28,620			125,067
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(125,267		)	(184,218		)
Proceeds from volumetric production payment	507			552
Proceeds from sales of assets	32,740			73,773
Decrease in equipment inventory	1,027			11,523
Other	(9		)	(133		)
Net cash used in investing activities	(91,002		)	(98,503		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	42,000			22,522
Repayments of long-term debt	—			(40,000		)
Net cash provided by (used in) financing activities	42,000			(17,478		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(20,382		)	9,086
CASH AND CASH EQUIVALENTS
Beginning of period	28,016			26,623
End of period	$	7,634		$	35,709
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	25,463		$	23,712
Cash paid for income taxes	$	227		$	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, 2015

(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. Clayton W. Williams, Jr., our Chairman of the Board and Chief Executive Officer, beneficially owns, either individually or through his affiliates, 25.6% of the outstanding shares of our common stock. In addition, The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership of which Mr. Williams’ adult children are the limited partners, owns an additional 25% of the outstanding shares of our common stock. Mel G. Riggs, our President, is the sole general partner of WCPL and has the power to vote or direct the voting of the shares held by WCPL.

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, 2015 and for the three and six months ended June 30, 2015 and 2014 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, 2015.

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, 2014.

Recent Accounting Pronouncements

In July 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2015-11, “Simplifying the Measurement of Inventory.” This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively, with early adoption permitted. The adoption of this standard will not have a material impact on our consolidated financial statements.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” that requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this Update. An entity is required to apply ASU 2015-03 for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption permitted. An entity should apply ASU 2015-03 on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. These disclosures include the nature of and reason for the change in accounting principle, the transition method, a description of the prior-period information that has been retrospectively adjusted, and the effect of the change on the financial statement line items (that is, debt issuance cost asset and the debt liability). We currently present debt issuance costs on the balance sheet as an asset. As of June 30, 2015, we had $11.3 million of debt issuance costs, which under this standard would be reclassified from an asset to a direct deduction to the related debt liability.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. An entity is required to apply ASU 2014-09 for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.


3.	Long-Term Debt

Long-term debt consists of the following:



	June 30, 2015		December 31, 2014

	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $272 at June 30, 2015 and $304 at December 31, 2014	$	599,728	$	599,696
Revolving credit facility, due April 2019^(a)	147,000		105,000
	$	746,728	$	704,696

_______


(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. 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 an additional $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. All of the 2019 Senior Notes 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 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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

defined in the Indenture) exceeds 2.25 times. 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, 2015 and December 31, 2014.

Revolving Credit Facility

We borrow money under an amended and restated credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. The credit facility provides 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 credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the credit facility prior to October 1, 2018.

The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the 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 borrowing base under the credit facility was $600 million at December 31, 2014 and was decreased in February 2015 to $500 million. The aggregate lender commitment remained at $500 million. At June 30, 2015, we had $147 million of borrowings outstanding on the credit facility, leaving $351.1 million available after allowing for outstanding letters of credit totaling $1.9 million.

The credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in the credit facility) of our oil and gas interests evaluated in determining the borrowing base. The obligations under the 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 the credit facility are determined by reference to (1) LIBOR plus an applicable LIBOR margin 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 an applicable base rate margin. The LIBOR margin ranges between 1.75% and 2.75% per year (as amended in February 2015), and the base rate margin ranges between 0.75% and 1.75% per year (as amended in February 2015). We also pay a commitment fee on the unused portion of the credit facility at an applicable margin that ranges between 0.375% and 0.50% per year. Applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under the credit facility, excluding bank fees and amortization of debt issue costs, for the six months ended June 30, 2015 was 2.1%.

The 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 is a consolidated leverage ratio that limits our consolidated indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1. In February 2015, the credit facility was amended to temporarily replace the consolidated leverage ratio covenant with a consolidated senior debt leverage ratio covenant, which may be no greater than 2.5 times consolidated EBITDAX and to add a consolidated interest coverage ratio covenant of 1.5 times consolidated EBITDAX. These temporary amendments apply to each of the quarterly periods from January 1, 2015 through June 30, 2016. The computations of consolidated current assets, current liabilities, EBITDAX, indebtedness and interest are defined in the credit facility. We were in compliance with all financial and non-financial covenants at June 30, 2015 and December 31, 2014.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Sales of Assets

In June 2015, we sold approximately 3,700 net acres in Burleson County, Texas (the “Acreage”) for cash consideration of $22.1 million. The Acreage, located east of our contiguous acreage block, was sold under a term assignment that terminates on October 27, 2015 unless the buyer commences a 90-day continuous development program on the Acreage. We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production associated with the Porter E Unit #1, our only Eagle Ford well situated on the Acreage.

During the first half of 2015, we sold our interests in selected leases in Oklahoma and sold our interests in certain wells in Martin and Yoakum Counties, Texas for proceeds totaling $7.3 million.

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. As of May 2015, the title requirements have been satisfied and the remaining proceeds have been released. In February 2014, we sold a property in Ward County, Texas for $5.1 million, subject to customary closing adjustments.

Net proceeds from each of these transactions were applied to reduce indebtedness outstanding under the 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.

The following table reflects the changes in ARO during the six months ended June 30, 2015 and the year ended December 31, 2014:



	June 30, 2015			December 31, 2014

	(In thousands)
Beginning of period	$	45,697		$	49,981
Additional ARO from new properties	293			1,209
Sales or abandonments of properties	(670		)	(5,246		)
Accretion expense	1,935			3,662
Revisions of previous estimates	3,071			(3,909		)
End of period	$	50,326		$	45,697


6.	Deferred Revenue from Volumetric Production Payment

In March 2012, Southwest Royalties, Inc. (“SWR”), a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner, 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 MBOE 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

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to prudently operate and produce the properties during the term of the VPP, and the third party 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 will be amortized over the life of the VPP and will be recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). As of June 30, 2015, we have a remaining obligation to deliver approximately 324 MBOE.

The following table reflects the changes in the deferred revenue during the six months ended June 30, 2015 and the year ended December 31, 2014:



	June 30, 2015			December 31, 2014

	(In thousands)
Beginning of period	$	23,129		$	29,770
Deferred revenue from VPP	507			1,067
Amortization of deferred revenue from VPP	(3,501		)	(7,708		)
End of period	$	20,135		$	23,129


7.	Compensation Plans

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

The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to the APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in 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, 10 awards are fully vested, two awards fully vested on August 1, 2015 and three awards 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.

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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 applicable 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, 2015 and 2014 and six months ended June 30, 2015 and 2014 were $6.5 million and $13.5 million, $8.6 million and $18.2 million, respectively.

Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule:



	June 30, 2015		December 31, 2014

	(In thousands)
Current liabilities:
Accrued liabilities and other	$	2,503	$	2,317
Non-current liabilities:
Accrued compensation under non-equity award plans	24,761		17,866
Total accrued compensation under non-equity award plans	$	27,264	$	20,183


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, 2015. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps



	Oil
	MBbls	Price
Production Period:
3rd Quarter 2015	697	$	55.65
4th Quarter 2015	592	$	55.65
	1,289

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, 2015, a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $1.3 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).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on the Consolidated Balance Sheets



	Fair Value of Derivative Instruments as of June 30, 2015
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	—	Current	$	5,901
	Non-current	—		Non-current	—
Total		$	—		$	5,901



	Fair Value of Derivative Instruments as of December 31, 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	$	—
	Non-current	—		Non-current	—
Total		$	—		$	—

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities



	June 30, 2015
	Assets		Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	—	$	5,901
Effects of netting arrangements	—		—
Fair value of derivatives — net presentation	$	—	$	5,901



	December 31, 2014
	Assets		Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	—	$	—
Effects of netting arrangements	—		—
Fair value of derivatives — net presentation	$	—	$	—

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

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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	2015			2014			2015			2014
	(In thousands)						(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Loss on derivatives	$	(12,300	)	$	(8,324	)	$	(7,668	)	$	(13,365	)
Total	$	(12,300	)	$	(8,324	)	$	(7,668	)	$	(13,365	)


9.	Fair Value of Financial Instruments

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

Fair Value Measurements

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

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


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


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


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

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The financial assets and liabilities measured on a recurring basis at June 30, 2015 and December 31, 2014 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, 2015		December 31, 2014

	Significant Other
	Observable Inputs
Description	(Level 2)
	(In thousands)
Assets:
Fair value of commodity derivatives	$	—	$	—
Total assets	$	—	$	—
Liabilities:
Fair value of commodity derivatives	$	5,901	$	—
Total liabilities	$	5,901	$	—

Fair Value of Other Financial Instruments

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

June 30, 2015

December 31, 2014

Carrying

Estimated

Carrying

Estimated

Description

Amount

Fair Value

Amount

Fair Value

(In thousands)

7.75% Senior Notes due 2019

599,728

572,300

599,696

510,000


10.	Income Taxes

Our effective federal and state income tax rate for the six months ended June 30, 2015 of 35.3% 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 2011 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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11.	Other Operating Revenues and Expenses

Other operating revenues and expenses for the three and six months ended June 30, 2015 and June 30, 2014 are as follows:



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014

	(In thousands)				(In thousands)
Other operating revenues:
Gain on sales of assets	$	2,966	$	5,067	$	6,881	$	10,209
Marketing revenue	—		1,195		23		1,577
Total other operating revenues	$	2,966	$	6,262	$	6,904	$	11,786
Other operating expenses:
Loss on sales of assets	$	4	$	238	$	65	$	730
Marketing expense	215		—		215		—
Impairment of inventory	1,784		—		2,567		10
Total other operating expenses	$	2,003	$	238	$	2,847	$	740

During the three months ended June 30, 2015, gain on sales of assets included 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 and the sale of leases in Oklahoma in May and June 2015. During the six months ended June 30, 2015, gain on sales of assets included the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015, 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 and the sale of leases in Oklahoma in May and June 2015 (see Note 4).

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, 2015, we have performed a qualitative assessment based on the difference between the carrying value and the estimated fair value of our investment. We estimated the fair value of our investment by comparing our interest of the equity in Dalea to our carrying value at June 30, 2015 and December 31, 2014. In comparing the estimated fair value to our carrying value at June 30, 2015, we recorded no impairment on our investment in Dalea for the three months ended June 30, 2015, none for the three months ended June 30, 2014, $0.9 million for the six months ended June 30, 2015 and none for the six months ended June 30, 2014. We categorize the measurement of fair value of this investment as a Level 3 input.

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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, 2015 and December 31, 2014.



	June 30, 2015			December 31, 2014

	(In thousands)
Proved properties	$	2,684,265		$	2,585,279
Unproved properties	48,918			99,634
Total capitalized costs	2,733,183			2,684,913
Accumulated depletion	(1,510,368		)	(1,430,699		)
Net capitalized costs	$	1,222,815		$	1,254,214

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 initially sought in excess of $8 million for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. 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 was converted to a class action, and each member of the class was offered the right to either participate or opt out of the class and continue a separate action for damages. One plaintiff opted out and will be subject to all previous rulings of the court, including an order dismissing certain claims on the basis that such claims were time barred. A loss on settlement of $0.7 million was recorded for the year ended December 31, 2013 in connection with this proposed settlement. The settlement was entered by the Court on December 19, 2014, and all settlement funds were paid to plaintiffs’ counsel in January 2015. The case against the single plaintiff will continue in 2015.

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. In October 2013, a judge 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. A loss of $1.4 million was recorded for the year ended December 31, 2013 in connection with the judgment. CWEI appealed the judgment and on July 8, 2015, the El Paso Court of Appeals reversed the trial court judgment in its entirety and rendered judgment that Plaintiffs take nothing on all claims against CWEI and Chesapeake. CWEI expects Plaintiffs to appeal the Court of Appeals’ decision to the Texas Supreme Court.

CWEI has been named a defendant in three lawsuits filed in Louisiana, one by Southeast Louisiana Flood Protection Authority-East (“SELFPA”) and two by Plaquemines Parish, each alleging that historical industry operations have significantly damaged coastal marshlands.

in 2014 in response to the suit which would effectively eliminate the claims, but in late 2014 the Louisiana state court judge declared the new law unconstitutional. A motion to dismiss the claims was granted in Federal District Court and the plaintiff has appealed to the United States Fifth Circuit Court of Appeals. All parties have filed their initial briefs with the Fifth Circuit. The Court has not yet scheduled oral argument.

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including naturally occurring radioactive material, and that dredging operations exceeded unspecified permit limitations. Plaintiff makes no specific allegations against any individual defendant and seeks unspecified monetary damages and declaratory relief, as well as restoration, costs of remediation and attorney fees. The cases were removed to the U.S. District Court for the Eastern District of Louisiana and have since been remanded in 2015 back to the state court.

Our overall exposure to these three suits is not currently determinable and we intend to vigorously defend these cases. We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.


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: (1) discounted cash flow method; (2) flowing daily production method; and (3) proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances. We utilize all three methods when that information is available, or if not will utilize the discounted cash flow method. We recorded no provision for impairment of proved properties for the three months ended June 30, 2015 and none for the three months ended June 30, 2014. We recorded a provision for impairment of proved properties of $2.5 million for the six months ended June 30, 2015 and $3.4 million for the six months ended June 30, 2014. The provision for the six months ended June 30, 2015 was related to the write-down of certain non-core properties located in Louisiana to their estimated fair value. The provision 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.

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 $2.3 million for the three months ended June 30, 2015, $1.5 million for the three months ended June 30, 2014, $2.5 million for the six months ended June 30, 2015 and $5 million for the six months ended June 30, 2014, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

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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 and six months ended June 30, 2015 and 2014:



For the Three Months Ended
June 30, 2015
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	73,222		$	42		$	(33	)	$	73,231
Depreciation, depletion and amortization ^(a)	38,923			3,206			(8		)	42,121
Other operating expenses ^(b)	40,476			1,696			(4		)	42,168
Interest expense	13,609			—			—			13,609
Other (income) expense	11,429			—			—			11,429
Income (loss) before income taxes	(31,215		)	(4,860		)	(21		)	(36,096		)
Income tax (expense) benefit	11,063			1,701			—			12,764
Net income (loss)	$	(20,152	)	$	(3,159	)	$	(21	)	$	(23,332	)
Total assets	$	1,416,665		$	56,476		$	(43,325	)	$	1,429,816
Additions to property and equipment	$	23,226		$	106		$	(21	)	$	23,311



For the Six Months Ended
June 30, 2015
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	137,302		$	722		$	(651	)	$	137,373
Depreciation, depletion and amortization ^(a)	80,999			6,410			(103		)	87,306
Other operating expenses ^(b)	77,677			4,484			(854		)	81,307
Interest expense	26,886			—			—			26,886
Other (income) expense	5,182			922			—			6,104
Income (loss) before income taxes	(53,442		)	(11,094		)	306			(64,230		)
Income tax (expense) benefit	18,783			3,883			—			22,666
Net income (loss)	$	(34,659	)	$	(7,211	)	$	306		$	(41,564	)
Total assets	$	1,416,665		$	56,476		$	(43,325	)	$	1,429,816
Additions to property and equipment	$	77,737		$	742		$	306		$	78,785

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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

_______


(a)	Includes impairment of property and equipment.


(b)	Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, G&A 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 an additional $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, 2015 (Unaudited) (Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Current assets	$	125,831	$	294,425	$	1,415	$	(329,715	)	$	91,956
Property and equipment, net	961,590		330,584		18,113		—			1,310,287
Investments in subsidiaries	352,344		—		—		(352,344		)	—
Other assets	15,172		12,401		—		—			27,573
Total assets	$	1,454,937	$	637,410	$	19,528	$	(682,059	)	$	1,429,816
Current liabilities	$	296,739	$	108,948	$	185	$	(319,124	)	$	86,748
Non-current liabilities:
Long-term debt	746,728		—		—		—			746,728
Deferred income taxes	116,647		139,694		4,479		(116,409		)	144,411
Other	44,411		51,044		244		—			95,699
	907,786		190,738		4,723		(116,409		)	986,838
Equity	250,412		337,724		14,620		(246,526		)	356,230
Total liabilities and equity	$	1,454,937	$	637,410	$	19,528	$	(682,059	)	$	1,429,816

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet December 31, 2014 (Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Current assets	$	153,373	$	293,613	$	546	$	(314,912	)	$	132,620
Property and equipment, net	986,110		344,174		18,600		—			1,348,884
Investments in subsidiaries	359,777		—		—		(359,777		)	—
Other assets	16,077		13,304		—		—			29,381
Total assets	$	1,515,337	$	651,091	$	19,146	$	(674,689	)	$	1,510,885
Current liabilities	$	352,889	$	113,746	$	586	$	(310,868	)	$	156,353
Non-current liabilities:
Long-term debt	704,696		—		—		—			704,696
Deferred income taxes	129,105		141,130		4,227		(109,863		)	164,599
Other	36,671		50,591		181		—			87,443
	870,472		191,721		4,408		(109,863		)	956,738
Equity	291,976		345,624		14,152		(253,958		)	397,794
Total liabilities and equity	$	1,515,337	$	651,091	$	19,146	$	(674,689	)	$	1,510,885

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended June 30, 2015 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Total revenue	$	55,714		$	17,099		$	418		$	—	$	73,231
Costs and expenses	63,390			20,234			665			—		84,289
Operating income (loss)	(7,676		)	(3,135		)	(247		)	—		(11,058		)
Other income (expense)	(24,605		)	(720		)	287			—		(25,038		)
Equity in earnings of subsidiaries	(2,480		)	—			—			2,480		—
Income tax (expense) benefit	11,429			1,349			(14		)	—		12,764
Net income (loss)	$	(23,332	)	$	(2,506	)	$	26		$	2,480	$	(23,332	)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Six Months Ended June 30, 2015 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Total revenue	$	101,402		$	35,141		$	830		$	—	$	137,373
Costs and expenses	124,411			42,909			1,293			—		168,613
Operating income (loss)	(23,009		)	(7,768		)	(463		)	—		(31,240		)
Other income (expense)	(33,632		)	(541		)	1,183			—		(32,990		)
Equity in earnings of subsidiaries	(4,933		)	—			—			4,933		—
Income tax (expense) benefit	20,010			2,908			(252		)	—		22,666
Net income (loss)	$	(41,564	)	$	(5,401	)	$	468		$	4,933	$	(41,564	)

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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, 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

Condensed Consolidating Statement of Cash Flows Six Months Ended June 30, 2015 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Operating activities	$	19,608		$	7,395		$	1,514		$	103		$	28,620
Investing activities	(88,774		)	(1,955		)	(170		)	(103		)	(91,002		)
Financing activities	50,952			(8,632		)	(320		)	—			42,000
Net increase (decrease) in cash and cash equivalents	(18,214		)	(3,192		)	1,024			—			(20,382		)
Cash at beginning of period	21,217			6,693			106			—			28,016
Cash at end of period	$	3,003		$	3,501		$	1,130		$	—		$	7,634

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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, 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


18.	Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of June 30, 2015 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, 2014. 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 beliefs, 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, 2014 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, liquidity and compliance with debt covenants;


•	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 the 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, 2014 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, 2014 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 Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities. During the six months ended June 30, 2015, we spent $77.6 million on exploration and development activities.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the second quarter of 2015 and the outlook for the remainder of 2015.

•

The downturn in commodity prices continues to have a significant impact on our business and results of operations. We suspended drilling operations in our core resource plays early in 2015 to preserve our liquidity and to allow time for well costs to adjust to a lower commodity price environment. In July 2015, we resumed drilling activities in our core areas with one rig in the Delaware Basin and one rig in the Eagle Ford Shale.

•

Oil and gas sales for the second quarter of 2015, excluding amortized deferred revenues, decreased $44.4 million, or 40%, from the second quarter of 2014. Price variances accounted for a $53.9 million decrease and production variances accounted for a $9.5 million increase. Average realized oil prices were $53.32 per barrel in the second quarter of 2015 versus $96.01 per barrel in the second quarter of 2014, average realized gas prices were $2.58 per Mcf in the second quarter of 2015 versus $4.49 per Mcf in the second quarter of 2014 and average realized natural gas liquids (“NGL”) prices were $15.30 per barrel in the second quarter of 2015 versus $31.55 per barrel in the second quarter of 2014. Oil and gas sales for the second quarter of 2015 also includes $1.7 million of amortized deferred revenue attributable to the volumetric production payment (“VPP”) compared to $1.9 million for the second quarter of 2014. Reported production and related average realized sales prices exclude volumes associated with the VPP.

•

Oil, gas and NGL production per barrel of oil equivalent (“BOE”) increased 7% in the second quarter of 2015 compared to the second quarter of 2014, with oil production increasing 8% to 12,363 barrels per day, gas production increasing 6% to 16,066 Mcf per day and NGL production decreasing 1% to 1,560 barrels per day. Oil and NGL production accounted for approximately 84% of our total BOE production in the second quarter of 2015 and 2014.

•

Production costs decreased $1.5 million for the second quarter of 2015 compared to the second quarter of 2014 due primarily to reductions in production taxes associated with a decrease in oil and gas sales. After giving effect to a 7% increase in total production, production costs, excluding production taxes, averaged $13.02 per BOE in the second quarter of 2015 versus $13.41 per BOE in the second quarter of 2014.

•

We recorded a $12.3 million loss on derivatives in the second quarter of 2015 (including a $1.8 million loss on settled contracts). For the same period in 2014, we recorded an $8.3 million loss on derivatives (including a $3.5 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 $11.3 million in the second quarter of 2015 compared to $21.4 million in the second quarter of 2014. Of the $10.1 million reduction, changes in compensation expense attributable to our APO Reward Plans accounted for a net decrease of $7 million ($6.5 million in the second quarter of 2015 versus $13.5 million in the second quarter of 2014). The remainder was largely attributable to salary and personnel reductions implemented in the first quarter of 2015.

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 $77.6 million during the first six months of 2015 on exploration and development activities and currently plan to spend an additional $56.9 million during the last half of 2015. Our actual expenditures during 2015 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Factors such as changes in operating margins, the availability of capital resources, drilling results and other factors could increase or decrease our actual expenditures during 2015.

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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, favorable product prices over the past several years, coupled with improved technology (including deep horizontal drilling) continued to attract high levels of drilling and recompletion activities. We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc. This acquisition provided us with an inventory of potential drilling and recompletion activities.

We spent $34.7 million in the Permian Basin during the first six months of 2015 on drilling and completion activities and $6 million on leasing and seismic activities. We drilled and completed 5 gross (2.9 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during the first six months of 2015. We currently plan to spend an additional $27.8 million on drilling and leasing activities in this area during the last half of 2015. Following is a discussion of our principal assets in the Permian Basin.

Delaware Basin

We currently hold approximately 66,000 net acres in the active Wolfbone resource play in the Delaware Basin, primarily in Reeves County, Texas. 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.

We entered the Delaware Basin as a vertical play, but with encouraging results from our horizontal drilling, we shifted our emphasis to a horizontal program. Most of our horizontal drilling to date has targeted the Wolfcamp A shale interval in Reeves County, Texas with 24 Wolfcamp A wells currently on production. We also have four Wolfcamp C wells currently on production.

We spent approximately $26.1 million on drilling and completion activities and $6 million for leasing activities in the Wolfbone play during the first six months of 2015. We plan to spend an additional $22 million on drilling, completion and leasing activities in this area during the last half of 2015.

We own oil, gas and water disposal pipelines in Reeves County, Texas consisting of 105 miles of oil pipelines with a design capacity of 18,000 barrels of oil per day, 104 miles of gas pipelines with a design capacity of 25,000 Mcf of natural gas per day and 104 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

Approximately 30% of our second quarter 2015 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.

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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 170,000 net acres in the Giddings Area. Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

Approximately 40% 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. 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

Our horizontal Eagle Ford Shale play is concentrated in the northern portion of our legacy Austin Chalk acreage block in Robertson, Burleson and Lee Counties, Texas. In this area, we currently have 42 horizontal Eagle Ford Shale wells on production. During the first six months of 2015, we spent approximately $22.9 million on drilling and completion activities and $7.5 million for leasing activities in the Eagle Ford Shale Area, and we currently plan to spend an additional $27.4 million on drilling and completion activities and leasing in this area during the last half of 2015.

Other

We spent $6.5 million during the first six months of 2015 on drilling and completion operations and leasing activities in other regions, including South Louisiana, Oklahoma and California and we currently plan to spend an additional $1.7 million during the last half of 2015.

Pipelines and Other Midstream Facilities

We own interests 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 383 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.

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we own and 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 22, 2015, we were using two of our rigs to drill wells in our core development areas and the remaining 12 rigs were idle.

Known Trends and Uncertainties

Developmental drilling programs are very sensitive to oil prices and drilling costs. The dramatic downturn in oil prices that began late in 2014 reduced operating margins to unacceptable levels, forcing us to temporarily suspend drilling operations in both of our core resource plays early in 2015. We have taken steps to significantly reduce our drilling and completion costs, lower our operating costs and reduce our general and administrative expenses. Oil prices briefly improved in the second quarter of 2015 to more than $60 per barrel, and we resumed drilling activities in our core areas with one rig in the Delaware Basin and one rig in the Eagle Ford Shale. Oil prices have since dropped below $50 per barrel. For the near term, we plan to continue drilling at a two-rig pace; however, we plan to closely monitor this low commodity price environment to measure the impact of a prolonged downturn on our long-term liquidity, financial position and results of operations. In February 2015, we entered into a commodity swap covering 1,289 MBbls of oil production from July 2015 through December 2015 at a price of $55.65 per barrel.

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In addition to reducing our incentive to drill new wells, the prolonged effects of lower oil prices and operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves. These factors have an adverse effect on our ability to access the capital resources we need to grow our reserve base. To address the likelihood that our consolidated leverage ratio, a financial covenant expressed as the ratio of total long-term debt to EBITDAX, would exceed the then-stated maximum leverage ratio of 4.0 times EBITDAX in our credit facility, we received an amendment to the credit facility in February 2015 to suspend that covenant through the second quarter of 2016. Specifically, the credit facility was amended to temporarily replace the consolidated leverage ratio covenant with a consolidated senior debt leverage ratio covenant, which may be no greater than 2.5 times consolidated EBITDAX and to add a consolidated interest coverage ratio covenant of 1.5 times consolidated EBITDAX. These temporary amendments apply to each of the quarterly periods from January 1, 2015 through June 30, 2016. The computations of consolidated current assets, current liabilities, EBITDAX, indebtedness and interest are defined in the credit facility.

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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,
	2015			2014
Oil and Gas Production Data:
Oil (MBbls)	1,125			1,042
Gas (MMcf)	1,462			1,379
Natural gas liquids (MBbls)	142			144
Total (MBOE)^(a)	1,511			1,416
Total (BOE/d)	16,601			15,559

Average Realized Prices ^{(b) (c)}:
Oil ($/Bbl)	$	53.32		$	96.01
Gas ($/Mcf)	$	2.58		$	4.49
Natural gas liquids ($/Bbl)	$	15.30		$	31.55

Loss on Settled Derivative Contracts ^(c):
($ in thousands, except per unit)
Oil: Cash settlement paid	$	(1,767	)	$	(3,454	)
Per unit produced ($/Bbl)	$	(1.57	)	$	(3.31	)

Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	3,735			3,613
Other	3,080			3,306
Austin Chalk	1,929			2,122
Eagle Ford Shale	3,238			1,953
Other	381			457
Total	12,363			11,451
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	3,305			2,932
Other	6,391			6,588
Austin Chalk	1,783			1,593
Eagle Ford Shale	566			344
Other	4,021			3,697
Total	16,066			15,154
(Continued)

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	Three Months Ended June 30,
	2015		2014
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	451		537
Other	802		732
Austin Chalk	164		152
Eagle Ford Shale	119		141
Other	24		20
Total	1,560		1,582

BOE:
Permian Basin Area:
Delaware Basin	4,738		4,639
Other	4,947		5,136
Austin Chalk	2,390		2,540
Eagle Ford Shale	3,451		2,151
Other	1,075		1,093
Total	16,601		15,559

Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	724	$	—
California	50		—
Oklahoma	—		2,390
Permian Basin	—		18
Michigan	—		3
Other	1,734		476
Total	2,508		2,887
Seismic and other	105		225
Total exploration costs	$	2,613	$	3,112

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	38,257	$	35,687
Contract drilling depreciation	3,198		2,616
Other depreciation	666		647
Total depreciation, depletion and amortization	$	42,121	$	38,950

Oil and Gas Costs ($/BOE Produced):
Production costs	$	15.28	$	17.40
Production costs (excluding production taxes)	$	13.02	$	13.41
Oil and gas depletion	$	25.32	$	25.20

Net Wells Drilled ^(e):
Exploratory Wells	1.0		6.9
Developmental Wells	1.9		7.6
(Continued)

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	Six Months Ended June 30,
	2015			2014
Oil and Gas Production Data:
Oil (MBbls)	2,304			2,053
Gas (MMcf)	2,868			2,793
Natural gas liquids (MBbls)	276			290
Total (MBOE)^(a)	3,058			2,809
Total (BOE/d)	16,895			15,517

Average Realized Prices ^{(b) (c)}:
Oil ($/Bbl)	$	48.56		$	94.82
Gas ($/Mcf)	$	2.61		$	4.73
Natural gas liquids ($/Bbl)	$	14.20		$	35.65

Loss on Settled Derivative Contracts ^(c):
($ in thousands, except per unit)
Oil: Cash settlement paid	$	(1,767	)	$	(4,591	)
Per unit produced ($/Bbl)	$	(0.77	)	$	(2.24	)

Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	3,757			3,593
Other	3,100			3,385
Austin Chalk^(d)	1,924			2,146
Eagle Ford Shale^(d)	3,592			1,802
Other	356			417
Total	12,729			11,343
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	3,172			2,870
Other	6,596			6,861
Austin Chalk^(d)	1,750			1,800
Eagle Ford Shale^(d)	585			304
Other	3,742			3,596
Total	15,845			15,431
(Continued)

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	Six Months Ended June 30,
	2015		2014
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	422		490
Other	782		816
Austin Chalk^(d)	167		187
Eagle Ford Shale^(d)	129		89
Other	25		20
Total	1,525		1,602

BOE:
Permian Basin Area:
Delaware Basin	4,707		4,561
Other	4,981		5,345
Austin Chalk ^(d)	2,383		2,633
Eagle Ford Shale ^(d)	3,819		1,942
Other	1,005		1,036
Total	16,895		15,517

Exploration Costs (in thousands):
Abandonment and impairment costs:
South Louisiana	$	2,147	$	602
California	160		—
Oklahoma	90		3,086
North Louisiana	—		994
Michigan	—		936
Permian Basin	—		584
Other	1,734		524
Total	4,131		6,726
Seismic and other	971		1,708
Total exploration costs	$	5,102	$	8,434

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	77,140	$	69,028
Contract drilling depreciation	6,307		4,896
Other depreciation	1,328		1,281
Total depreciation, depletion and amortization	$	84,775	$	75,205

Oil and Gas Costs ($/BOE Produced):
Production costs	$	15.21	$	18.18
Production costs (excluding production taxes)	$	13.14	$	14.14
Oil and gas depletion	$	25.23	$	24.57
(Continued)

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	Six Months Ended June 30,
	2015	2014
Net Wells Drilled ^(e):
Exploratory Wells	1.6	8.2
Developmental Wells	12.4	17.9

_______


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

(b)

Oil and gas sales includes $1.7 million for the three months ended June 30, 2015, $1.9 million for the three months ended June 30, 2014, $3.5 million for the six months ended June 30, 2015 and $4 million for the six months ended June 30, 2014 of amortized deferred revenue attributable to the VPP granted effective March 1, 2012. The calculation of average realized sales prices excludes production of 22,503 barrels of oil and 14,750 Mcf of gas for the three months ended June 30, 2015, 25,826 barrels of oil and 10,689 Mcf of gas for the three months ended June 30, 2014, 45,654 barrels of oil and 30,837 Mcf of gas for the six months ended June 30, 2015 and 52,421 barrels of oil and 22,622 Mcf of gas for the six months ended June 30, 2014 associated with the VPP.

(c)

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 2015 or 2014 derivative contracts as cash flow hedges. This means that our derivatives for 2015 and 2014 have been marked-to-market through our statements 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.


(d)	Following is a summary of the average daily production related to interests in producing properties we sold effective March 2014.



	Six Months Ended June 30,
	2015	2014
Average Daily Production:

Austin Chalk/Eagle Ford:
Oil (Bbls)	—	188
Natural gas (Mcf)	—	22
NGL (Bbls)	—	6
Total (BOE)	—	198


(e)	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, 2015 to the comparative period in 2014. Unless otherwise indicated, references to 2015 and 2014 within this section refer to the three months ended June 30, 2015 and 2014, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $44.4 million, or 40%, in 2015 from 2014. Price variances accounted for a $53.9 million decrease and production variances accounted for a $9.5 million increase. Oil and gas sales in 2015 also includes $1.7 million of amortized deferred revenue compared to $1.9 million in 2014 attributable to the VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP. Oil, gas and NGL production in 2015 (on a BOE basis) increased 7% compared to 2014. Oil production increased 8% in 2015 from 2014, NGL production decreased 1% while gas production increased 6% in 2015 from 2014. The liquids component of our production mix accounted for approximately 84% oil and NGL in 2014 and in 2015. In 2015, our realized oil price decreased 44% compared to 2014, and our realized gas price decreased 43%. 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 $23.1 million in 2015 as compared to $24.6 million in 2014, due primarily to reductions in production taxes associated with a decrease in oil and gas sales. After giving effect to a 7% increase in total production, production costs, excluding production taxes, averaged $13.02 per BOE in 2015 compared to $13.41 per BOE in 2014.

Oil and gas depletion expense increased $2.6 million from 2014 to 2015 due to a $2.4 million increase related to production variances and a $0.2 million increase due to rate variances. On a BOE basis, depletion expense increased less than 1% to $25.32 per BOE in 2015 from $25.20 per BOE in 2014. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

Exploration costs

We follow the successful efforts method of accounting; therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs and unproved acreage impairments are expensed. In 2015, we charged to expense $2.6 million of exploration costs, as compared to $3.1 million in 2014.

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 negligible in 2015 compared to $8.5 million in 2014 due to decreased demand for contract drilling services. Drilling services costs, net of eliminations, were $1.6 million in 2015 compared to $5.5 million in 2014. Contract drilling depreciation for 2015 was $3.2 million compared to $2.6 million in 2014.

General and Administrative

G&A expenses decreased $10.1 million from $21.4 million in 2014 to $11.3 million in 2015. Of the $10.1 million reduction, changes in compensation expense attributable to our APO reward plans accounted for a net decrease of $7 million ($6.5 million in 2015 versus $13.5 million in 2014). The remainder was largely attributable to salary and personnel reductions implemented in the first quarter of 2015.

Interest expense

Interest expense increased 6% from $12.8 million in 2014 to $13.6 million in 2015 due primarily to an increase in borrowings, which increased from an average daily principal balance of $16 million in 2014 compared to $172.5 million in 2015.

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Gain/loss on derivatives

We did not designate any derivative contracts in 2015 or 2014 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. In 2015, we reported a $12.3 million loss on derivatives (including a $1.8 million loss on settled contracts) compared to an $8.3 million loss on derivatives (including a $3.5 million loss on settled contracts) in 2014. Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $1.2 million on sales of assets and impairment of inventory in 2015 compared to a net gain of $4.8 million in 2014. The 2015 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 and the sale of leases in Oklahoma in May and June 2015. The 2015 gain was partially offset by a $1.8 million write-down of inventory to reduce the carrying value to the estimated fair value. 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. 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 2015 of 35.4% 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, 2015 to the comparative period in 2014. Unless otherwise indicated, references to 2015 and 2014 within this section refer to the six months ended June 30, 2015 and 2014, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $96.2 million, or 44%, in 2015 from 2014. Price variances accounted for a $119 million decrease and production variances accounted for a $22.8 million increase. Oil and gas sales in 2015 also includes $3.5 million of amortized deferred revenue compared to $4 million in 2014 attributable to the VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP. Oil, gas and NGL production in 2015 (on a BOE basis) increased 9% compared to 2014. Oil production increased 12% in 2015 from 2014, NGL production decreased 5% while gas production increased 3% in 2015 from 2014. After giving effect to the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014, oil, gas and NGL production in 2015 (on a BOE basis) increased 10% compared to 2014. Oil production increased 14% in 2015 from 2014, NGL production decreased 4% while gas production increased 3% in 2015 from 2014. The liquids component of our production mix accounted for approximately 83% oil and NGL in 2014 compared to 84% in 2015. In 2015, our realized oil price decreased 49% compared to 2014, and our realized gas price decreased 45%. 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 9% to $46.5 million in 2015 as compared to $51.1 million in 2014, due primarily to reductions in production taxes associated with a decrease in oil and gas sales. After giving effect to a 9% increase in total production, production costs, excluding production taxes, averaged $13.14 per BOE in 2015 compared to $14.14 per BOE in 2014.

Oil and gas depletion expense increased $8.1 million from 2014 to 2015 due to a $6.1 million increase related to production variances and a $2 million increase due to rate variances. On a BOE basis, depletion expense increased 3% to $25.23 per BOE in 2015 from $24.57 per BOE in 2014. 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.

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We recorded a provision for impairment of property and equipment of $2.5 million during 2015 as compared to $3.4 million in 2014. The 2015 impairment related to certain non-core properties located in Louisiana to reduce the carrying value of these properties to their estimated fair values. 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. 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 2015, we charged to expense $5.1 million of exploration costs, as compared to $8.4 million in 2014.

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 negligible in 2015 compared to$15.4 million in 2014 due to decreased demand for contract drilling services. Drilling services costs, net of eliminations, were $3.5 million in 2015 compared to $10.3 million in 2014. Contract drilling depreciation for 2015 was $6.3 million compared to $4.9 million in 2014.

General and Administrative

G&A expenses decreased $12.7 million from $33.2 million in 2014 to $20.5 million in 2015. Of the $12.7 million reduction, changes in compensation expense attributable to our APO reward plans accounted for a net decrease of $9.6 million ($8.6 million in 2015 versus $18.2 million in 2014). The remainder was largely attributable to salary and personnel reductions implemented in the first quarter of 2015.

Interest expense

Interest expense increased 6% from $25.4 million in 2014 to $26.9 million in 2015 due primarily to an increase in borrowings, which increased from an average daily principal balance of $25.5 million in 2014 compared to $153.3 million in 2015.

Gain/loss on derivatives

We did not designate any derivative contracts in 2015 or 2014 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. In 2015, we reported a $7.7 million loss on derivatives (including a $1.8 million loss on settled contacts) compared to a $13.4 million loss on derivatives (including a $4.6 million loss on settled contracts) in 2014. 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 $4.2 million on sales of assets and impairment of inventory in 2015 compared to a net gain of $9.5 million in 2014. The 2015 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 sale of leases in Oklahoma in May and June 2015, and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015. The 2015 gain was partially offset by a $2.6 million write-down of inventory to reduce the carrying value to the estimated fair value. 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. 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 2015 of 35.3% 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.

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Liquidity and Capital Resources

Overview

Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to a syndicate of banks to secure the 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 under the credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. However, we may mitigate the effects of product prices on our cash flow and borrowing base through the use of commodity derivatives.

At June 30, 2015, we had $147 million of borrowings outstanding under the credit facility, leaving $351.1 million available on the facility after allowing for outstanding letters of credit totaling $1.9 million as compared to $384.9 million of availability on the facility at June 30, 2014.

Outlook for 2015

The downturn in oil prices that began late in 2014 has caused a significant reduction in our operating margins, and the impact has been especially negative since we entered 2015 with no commodity hedges in place. The reduction in operating margins caused us to suspend drilling operations in both of our core resource plays early in 2015. We have taken steps to significantly reduce our drilling and completion costs, lower our operating costs and reduce our general and administrative expenses. Oil prices briefly improved in the second quarter of 2015 to more than $60 per barrel, and we resumed drilling activities in our core areas with one rig in the Delaware Basin and one rig in the Eagle Ford Shale. Oil prices have since dropped below $50 per barrel. For the near term, we plan to continue drilling at a two-rig pace; however, we plan to closely monitor this low commodity price environment to measure the impact of a prolonged downturn on our long-term liquidity, financial position and results of operations. Assuming continuation of a two-rig drilling program for the remainder of 2015, we expect to spend $134.5 million on exploration and development activities during fiscal 2015 as compared to $404.3 million in fiscal 2014. In February 2015, we entered into a commodity swap covering 1,289 MBbls of our oil production from July 2015 through December 2015 at a price of $55.65 per barrel.

While we believe that reducing drilling activity during an adverse economic climate is a prudent and necessary action in order to preserve liquidity and limit increases in indebtedness, this will continue to have a negative impact on production and cash flow from operations. Based on our current plans for 2015 spending, we expect our combined oil and gas production to remain relatively constant in 2015 as compared to 2014, and then decline as we move into 2016. In addition, if product prices remain depressed during 2015, our ratio of total indebtedness to EBITDAX (as defined in the credit facility) was expected to exceed the maximum ratio permitted under the credit facility. As a result, we requested and received an amendment to the credit facility to suspend that financial covenant through the second quarter of 2016. In February 2015, the credit facility was amended to temporarily replace the consolidated leverage ratio covenant with a consolidated senior debt leverage ratio covenant, which may be no greater than 2.5 times consolidated EBITDAX and to add a consolidated interest coverage ratio covenant of 1.5 times consolidated EBITDAX. These temporary amendments apply to each of the quarterly periods from January 1, 2015 through June 30, 2016. The computations of consolidated current assets, current liabilities, EBITDAX, indebtedness and interest are defined in the credit facility.

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Capital expenditures

The following table summarizes, by area, our actual expenditures for exploration and development activities for the first six months of 2015 and our planned expenditures for the year ending December 31, 2015.



	Actual Expenditures Six Months Ended June 30, 2015		Planned Expenditures Year Ending December 31, 2015		2015 Percentage of Total Planned Expenditures
	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	26,100	$	42,100	31	%
Other	8,600		14,400		11	%
Austin Chalk/Eagle Ford Shale	22,900		46,300		34	%
Other	5,300		6,900		5	%
	62,900		109,700		81	%
Leasing and seismic	14,700		24,800		19	%
Exploration and development	$	77,600	$	134,500	100	%

Our expenditures for exploration and development activities for the six months ended June 30, 2015 totaled $77.6 million. We financed these expenditures for the first six months of 2015 with cash flow from operating activities, proceeds from asset sales and advances under the credit facility. We currently plan to spend approximately $134.5 million on exploration and development activities in 2015. Our actual expenditures during 2015 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Factors, such as changes in operating margins, the availability of capital resources, drilling results and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2015.

Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flows, combined with funds available to us under the credit facility, will be sufficient to finance our planned exploration and development activities at these reduced levels through 2015. Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base under the credit facility may be less than expected, cash flows may be less than expected, or capital expenditures may be more than expected. We will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets if necessary when we deem appropriate.

Cash flow provided by operating activities

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

Cash flow provided by operating activities for the six months ended June 30, 2015 decreased $96.4 million, or 77.1%, as compared to the corresponding period in 2014 due primarily to lower commodity prices.

Senior Notes

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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) exceeds 2.25 times. 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, 2015 and December 31, 2014.

Revolving credit facility

We have historically relied on the credit facility for both our short-term liquidity (working capital) and a portion of our long-term financial needs. As long as we have sufficient availability under the 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.

We currently borrow money under an amended and restated credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. The credit facility provides 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 credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the credit facility prior to October 1, 2018.

The borrowing base under the credit facility was $600 million at December 31, 2014 and was decreased in February 2015 to $500 million. The aggregate lender commitment remained at $500 million. During the six months ended June 30, 2015, we increased indebtedness outstanding under the credit facility by $42 million. At June 30, 2015, we had $147 million of borrowings outstanding on the credit facility, leaving $351.1 million available after allowing for outstanding letters of credit totaling $1.9 million. We and our banks have agreed to conduct the next scheduled borrowing base redetermination in September instead of November 2015. Due primarily to lower commodity prices, we anticipate a reduction in the borrowing base from its current level. We will not know the revised borrowing base amount until the banks have made that determination; however, we do not expect the reduction, if any, to have a material adverse effect on our liquidity position.

At our election, annual interest rates under the credit facility are determined by reference to (1) LIBOR plus an applicable LIBOR margin 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 an applicable base rate margin. The LIBOR margin ranges between 1.75% and 2.75% per year (as amended in February 2015) and the base rate margin ranges between 0.75% and 1.75% per year (as amended in February 2015). We also pay a commitment fee on the unused portion of the credit facility at an applicable margin that ranges between 0.375% and 0.50% per year. Applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under the credit facility, excluding bank fees and amortization of debt issue costs, for the six months ended June 30, 2015 was 2.1%.

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Working capital computed for loan compliance purposes differs from our working capital computed in accordance with GAAP. Since compliance with financial covenants is a material requirement under the credit facility, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the 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 increased to $5.2 million at June 30, 2015 from a working capital deficit of $23.7 million at December 31, 2014. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $362.2 million at June 30, 2015, as compared to $365.4 million at December 31, 2014. The following table reconciles our GAAP working capital (deficit) to the working capital computed for loan compliance purposes at June 30, 2015 and December 31, 2014.



	June 30, 2015		December 31, 2014

	(In thousands)
Working capital (deficit) per GAAP	$	5,208	$	(23,733	)
Add funds available under our revolving credit facility	351,130		389,130
Exclude fair value of derivatives classified as current assets or current liabilities	5,901		—
Working capital per loan covenant	$	362,239	$	365,397

We were in compliance with all financial and non-financial covenants at June 30, 2015 and December 31, 2014. 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, particularly after the temporary amendments to the credit facility expire with the third quarter of 2016. If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend the credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The lending group under the credit facility includes the following institutions: JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., MUFG 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 the credit facility. Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of February 2015, JPMorgan Chase Bank, N.A. was the counterparty to our commodity derivative agreements. Our obligations under existing derivative agreements with our lenders are secured by the security documents executed by the parties under the credit facility.

Asset Sales

From time to time, we sell certain of our proved and unproved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them. During the first half of 2015, we received cash proceeds aggregating $32.7 million from various sales of assets, the most significant of which was the sale in June 2015 of approximately 3,700 net acres in Burleson County, Texas for $22.1 million. We are actively considering other selected sales as a source of additional funds to supplement cash flow from operations and borrowings under the credit facility to meet our capital needs.

Alternative capital resources

We believe we currently have adequate liquidity to enable us to fund our expected capital expenditures for 2015 through a combination of cash flow from operations and borrowings under the credit facility.

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 all or a portion of our core or 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 2015 and subsequent periods. 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.

Off-balance sheet arrangements

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

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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, 2014.

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 the 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, 2014 reserve estimates, we project that a $1 decline in the price per barrel of oil and a $0.50 decline in the price per Mcf of gas from year end 2014 would reduce our gross revenues for the year ending December 31, 2015 by $6.1 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 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.

Swaps



	Oil
	MBbls	Price
Production Period:
3rd Quarter 2015	697	$	55.65
4th Quarter 2015	592	$	55.65
	1,289

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We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil may have on the fair value of our commodity derivatives. As of June 30, 2015, a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $1.3 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At June 30, 2015, our fixed rate debt had a carrying value of $599.7 million and an approximate fair value of $572.3 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 $18.2 million. Based on our outstanding variable rate indebtedness at June 30, 2015 of $147 million, a change in interest rates of 100-basis points would affect annual interest payments by $1.5 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, 2015 these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the six months ended June 30, 2015 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

In July 2013, the SELFPA case was filed in Orleans Parish and alleged that dredging and other oil field operations of the 95 oil and gas company defendants caused degradation and destruction of the coastal marshlands which serve as a buffer protecting the coastal area of Louisiana from storms. The case was removed to Federal District Court. Legislation was enacted in Louisiana in 2014 in response to the suit which would effectively eliminate the claims, but in late 2014 the Louisiana state court judge declared the new law unconstitutional. A motion to dismiss the claims was granted in Federal District Court and the plaintiff has appealed to the United States Fifth Circuit Court of Appeals. All parties have filed their initial briefs with the Fifth Circuit. The Court has not yet scheduled oral argument.

In November 2013, we were served with two separate suits filed by Plaquemines Parish in the 25th Judicial District Court of Plaquemines Parish, Louisiana (Designated Case Nos. 61-002 and 60-982). Multiple defendants are named in each suit, and each suit involves a different area of operation within Plaquemines Parish. Except as to the named defendants and areas of operation, the suits are identical. Plaintiff alleges that defendants’ oil and gas operations violated certain laws relating to the coastal zone management including failure to obtain permits, violation of permits, use of unlined waste pits, discharge of oilfield wastes, including naturally occurring radioactive material, and that dredging operations exceeded unspecified permit limitations. Plaintiff makes no specific allegations against any individual defendant and seeks unspecified monetary damages and declaratory relief, as well as restoration, costs of remediation and attorney fees. The cases were removed to the U.S. District Court for the Eastern District of Louisiana and have since been remanded in 2015 back to the state court.


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, 2014, as filed with the SEC on February 27, 2015, 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.

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Item 5 -	Other Information

In August 2015, we entered into new employment agreements (the “Employment Agreements”) with each of Clayton W. Williams, Jr., Chairman of the Board and Chief Executive Officer, Mel G. Riggs, President, Michael L. Pollard, Senior Vice President - Finance and Chief Financial Officer, Ronald D. Gasser, Vice President - Engineering, and Samuel L. Lyssy, Jr., Vice President - Exploration (the “Named Executive Officers”). The Employment Agreements are substantially similar to the prior employment agreements between the Company and each of the Named Executive Officers, which prior agreements were scheduled to expire by their terms on March 1, 2016. The Employment Agreements terminate and replace in their entirety the prior employment agreements and are effective as of June 1, 2015 (the “Effective Date”).

The Employment Agreements are effective for an initial term of three years, and will be automatically extended for an additional one year period on the third anniversary date of the Effective Date (and on the fourth and fifth anniversary dates of the Effective Date), unless, at least 90 days prior to any such anniversary date, either party gives notice of non-renewal. The Employment Agreements provide for minimum base salaries as follows: Mr. Williams - $891,000; Mr. Riggs - $584,600; Mr. Pollard - $466,400; Mr. Gasser - $475,200; and Mr. Lyssy - $534,600. Notwithstanding the above, the Employment Agreements recognize that the Named Executive Officers have agreed to a 20% reduction in base salary, effective February 16, 2015, which reduction is currently effective and not in violation of the Employment Agreements. The Employment Agreements also provide the Named Executive Officers with certain other specified compensation and employee benefits.

Pursuant to the Employment Agreements, the Company is required to provide compensation to a Named Executive Officer in the event the Named Executive Officer’s employment is terminated under certain circumstances. If a Named Executive Officer becomes disabled or dies, the agreements provide for a lump sum payment of 18 months of base salary, payable within 90 days of termination or by March 15 of the year following termination, if earlier, and 12 months of continued health benefits (or, if the continued benefits cannot be offered through the Company’s group health plans, reimbursement for 12 months of similar health benefits). If a Named Executive Officer’s employment is terminated by the Company without cause or by the executive for good reason, or if the Company gives a notice of non-renewal to the executive, the executive will receive a lump sum payment equal to either 200% (for Messrs. Williams, Riggs and Pollard) or 150% (for Messrs. Gasser and Lyssy) of his annualized compensation, consisting of base salary, average bonus paid for the most recent three years, automobile allowance, and 401(k) matching contributions, payable within 90 days of termination or by March 15 of the year following termination, if earlier, plus 18 months of continued health benefits (or, if the continued benefits cannot be offered through the Company’s group health plans, reimbursement for 18 months of similar health benefits). If a Named Executive Officer’s employment is terminated by the Company without cause or by the executive for good reason, or if the Company gives notice of non-renewal to the Named Executive Officer, in each case, within 24 months following a change in control of the Company, the executive will receive a lump sum payment equal to either 300% (for Messrs. Williams, Riggs and Pollard) or 200% (for Messrs. Gasser and Lyssy) of his annualized compensation, consisting of base salary, average bonus paid for the most recent three years, automobile allowance, and 401(k) matching contributions, payable within 90 days of termination or by March 15 of the year following termination, if earlier, plus 18 months of continued health benefits (or, if the continued benefits cannot be offered through the Company’s group health plans, reimbursement for 18 months of similar health benefits). The Named Executive Officers are also entitled to accelerated vesting of equity and non-equity incentive awards (except that certain forfeiture conditions may continue to apply) if their employment is terminated due to death or disability, or by the Company without cause, by the executive for good reason, or pursuant to a non-renewal notice given by the Company (including such a termination occurring within 24 months following a change in control of the Company).

For purposes of the Employment Agreements, the terms listed below have been given the following meanings:

(a) “cause” means the executive (1) has been convicted of a misdemeanor involving intentionally dishonest behavior or that the Company determines will have a material adverse effect on the Company’s reputation or any felony, (2) has engaged in conduct that is materially injurious to the Company or its affiliates, (3) has engaged in gross negligence or willful misconduct in performing his duties, (4) has willfully refused without proper legal reason to perform his duties, (5) has breached a material provision of the Employment Agreement or another agreement with the Company, or (6) has breached a material corporate policy of the Company. If any act described in clause (4), (5) or (6) could be cured, the Company will give the executive written notice of such act within 30 days of the occurrence and will give the executive 30 days to cure.

(b) “change in control” means (1) a change in the majority of the board of directors serving on the board as of the Effective Date unless such change was authorized by a majority of the directors in place on that date (or approved by the majority of the directors in place on that date); (2) a third party, including a group of third parties acting together, acquires more than 35%, and Mr. Williams, his affiliates and certain other related persons own less than 25%, of the total voting power of Company’s voting stock; (3) the sale of all or substantially all of the Company’s assets; and (4) the adoption of a plan or a proposal for the liquidation or dissolution of the Company. Except in the case of Mr. Williams’ employment agreement, “change in control” also includes the

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resignation or removal for any reason of Mr. Williams as the Company’s Chairman of the Board and Chief Executive Officer, including by reason of the death or disability of Mr. Williams.

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

(d) “good reason” means, without the express written consent of the executive, (1) a material breach by the Company of the Employment Agreement, (2) a material reduction in the executive’s base salary, (3) a material diminution in the executive’s authority, duties or responsibilities or the assignment of duties to the executive that are not materially commensurate with the executive’s position, or (4) a material change in the geographic location at which the executive must normally perform services. The executive must give the Company notice of any alleged good reason event within 60 days, and the Company shall have 30 days to remedy such event. The Named Executive Officers have agreed that the February 16, 2015 base salary reductions do not constitute good reason for purposes of the Employment Agreements and the prior agreements.

The Employment Agreements include a modified cutback provision which states that, if amounts payable in connection with a change in control under the Employment Agreements or otherwise by the Company exceed the amount allowed under section 280G of the Internal Revenue Code, thereby subjecting the executive officer to an excise tax under section 4999 of the Internal Revenue Code, then the parachute payments shall either be: (a) reduced to the level at which no excise tax applies, such that the full amount of the payments would be equal to $1 less than three times the executive’s “base amount,” which is the average W-2 earnings for the five preceding calendar years, or (b) paid in full, which would subject the executive to the excise tax. The Company will determine, in good faith, which route produces the best net after tax position for the executive officer, but the Company will not provide any gross-up payments for such excise taxes. The Employment Agreements also contain “clawback” provisions that enable the Company to recoup any compensation that is deemed incentive compensation if required by any Company policy adopted to comply with any law, government regulation, or stock exchange listing requirement.

The Employment Agreements contain confidentiality provisions, as well as covenants not to compete, during the employment term and continuing until the first anniversary of the date of termination, and not to solicit the employment of other employees of the Company, during the employment term and continuing until the second anniversary of the date of termination, subject to some limited exceptions. The noncompete covenant does not apply if a Named Executive Officer is terminated for cause by the Company or voluntarily without good reason by the executive, unless the Company continues to pay the executive his base salary for a period of 12 months. Mr. Williams’ noncompete and nonsolicitation obligations are governed by the Consolidation Agreement entered into with Mr. Williams and certain Williams Entities in May 1993. Termination of employment of any of the Named Executive Officers due to a breach of one of these provisions would constitute a termination for cause. In addition, the Employment Agreements also condition payment of severance payments and health care continuation coverage upon the Named Executive Officer’s execution of a release within 45 days of termination of employment (and nonrevocation thereafter).

This description of the Employment Agreements is only a summary of, and is qualified in its entirety by reference to, the Employment Agreements, copies of which are filed as Exhibits 10.1 through 10.5 to this Quarterly Report on Form 10-Q and are incorporated herein by reference.

We also entered into employment agreements with Patrick C. Reesby, Vice President - Acquisitions/New Ventures, T. Mark Tisdale, Vice President and General Counsel, Gregory S. Welborn, Vice President - Land, Robert L. Thomas, Vice President - Accounting and Principal Accounting Officer, and John F. Kennedy, Vice President - Drilling in August 2015. Copies of the employment agreements for Messrs. Reesby, Tisdale, Welborn, Thomas and Kennedy are filed as Exhibits 10.6 through 10.10 to this Quarterly Report on Form 10-Q.

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Item 6 -	Exhibits



Exhibits
**2.1		Agreement and Plan of Merger among Clayton Williams Energy, Inc. and Southwest Royalties, Inc. dated May 3, 2004, filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the Commission on June 3, 2004

**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement filed with the Commission on October 4, 1996, 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		Employment Agreement between Clayton Williams Energy, Inc. and Clayton W. Williams, Jr., effective as of June 1, 2015

*10.2		Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of June 1, 2015

*10.3		Employment Agreement between Clayton Williams Energy, Inc. and Michael L. Pollard, effective as of June 1, 2015

*10.4		Employment Agreement between Clayton Williams Energy, Inc. and Ron D. Gasser, effective as of June 1, 2015

*10.5		Employment Agreement between Clayton Williams Energy, Inc. and Sam Lyssy, effective as of June 1, 2015

*10.6		Employment Agreement between Clayton Williams Energy, Inc. and John F. Kennedy, effective as of June 1, 2015

*10.7		Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of June 1, 2015

*10.8		Employment Agreement between Clayton Williams Energy, Inc. and T. Mark Tisdale, effective as of June 1, 2015

*10.9		Employment Agreement between Clayton Williams Energy, Inc. and Greg S. Welborn, effective as of June 1, 2015

*10.10		Employment Agreement between Clayton Williams Energy, Inc. and Patrick C. Reesby, effective as of June 1, 2015

*10.11		CWEI Austin Chalk Reward Plan dated June 19, 2008, as amended

*10.12		CWEI Austin Chalk Reward Plan II dated October 19, 2010, as amended

*10.13		CWEI Austin Chalk Reward Plan III dated June 28, 2011, as amended

*10.14		CWEI Amacker Tippett Reward Plan dated June 19, 2008, as amended

*10.15		CWEI Delaware Basin Reward Plan dated June 28, 2011, as amended

*10.16		CWEI Delaware Basin II Reward Plan dated June 11, 2014, as amended

*10.17		CWEI Eagle Ford I Reward Plan dated August 20, 2013, as amended

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*10.18		CWEI Eagle Ford II Reward Plan dated June 11, 2014, as amended

*31.1		Certification by the 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.

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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 7, 2015	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			President

Date:	August 7, 2015	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President - Finance and Chief Financial Officer

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INDEX TO EXHIBITS



Exhibits
**2.1		Agreement and Plan of Merger among Clayton Williams Energy, Inc. and Southwest Royalties, Inc. dated May 3, 2004, filed as Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the Commission on June 3, 2004

**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement filed with the Commission on October 4, 1996, 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		Employment Agreement between Clayton Williams Energy, Inc. and Clayton W. Williams, Jr., effective as of June 1, 2015

*10.2		Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of June 1, 2015

*10.3		Employment Agreement between Clayton Williams Energy, Inc. and Michael L. Pollard, effective as of June 1, 2015

*10.4		Employment Agreement between Clayton Williams Energy, Inc. and Ron D. Gasser, effective as of June 1, 2015

*10.5		Employment Agreement between Clayton Williams Energy, Inc. and Sam Lyssy, effective as of June 1, 2015

*10.6		Employment Agreement between Clayton Williams Energy, Inc. and John F. Kennedy, effective as of June 1, 2015

*10.7		Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of June 1, 2015

*10.8		Employment Agreement between Clayton Williams Energy, Inc. and T. Mark Tisdale, effective as of June 1, 2015

*10.9		Employment Agreement between Clayton Williams Energy, Inc. and Greg S. Welborn, effective as of June 1, 2015

*10.10		Employment Agreement between Clayton Williams Energy, Inc. and Patrick C. Reesby, effective as of June 1, 2015

*10.11		CWEI Austin Chalk Reward Plan dated June 19, 2008, as amended

*10.12		CWEI Austin Chalk Reward Plan II dated October 19, 2010, as amended

*10.13		CWEI Austin Chalk Reward Plan III dated June 28, 2011, as amended

*10.14		CWEI Amacker Tippett Reward Plan dated June 19, 2008, as amended

*10.15		CWEI Delaware Basin Reward Plan dated June 28, 2011, as amended

*10.16		CWEI Delaware Basin II Reward Plan dated June 11, 2014, as amended

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*10.17		CWEI Eagle Ford I Reward Plan dated August 20, 2013, as amended

*10.18		CWEI Eagle Ford II Reward Plan dated June 11, 2014, as amended

*31.1		Certification by the 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 7, 2015

Attached files

CLAYTON WILLIAMS ENERGY INC /DE Reports