CWEI Clayton Williams Energy, Inc.

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PART I.  FINANCIAL INFORMATION

Item 1 -	Financial Statements

CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands)   ASSETS
	March 31, 2014				December 31, 2013
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	39,213			$	26,623
Accounts receivable:
Oil and gas sales	43,264				39,268
Joint interest and other, net of allowance for doubtful accounts of $1,184 at March 31, 2014 and December 31, 2013	17,326				17,121
Affiliates	137				264
Inventory	38,943				39,183
Deferred income taxes	6,383				7,581
Fair value of derivatives	—				2,518
Prepaids and other	4,795				5,753
	150,061				138,311
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,413,224				2,403,277
Pipelines and other midstream facilities	56,101				54,800
Contract drilling equipment	103,927				96,270
Other	20,630				20,620
	2,593,882				2,574,967
Less accumulated depreciation, depletion and amortization	(1,409,635		)		(1,375,860		)
Property and equipment, net	1,184,247				1,199,107
OTHER ASSETS
Debt issue costs, net	12,115				12,785
Investments and other	16,407				16,534
	28,522				29,319
	$	1,362,830			$	1,366,737
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
	March 31, 2014				December 31, 2013
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	75,436			$	75,872
Oil and gas sales	42,064				37,834
Affiliates	1,463				874
Fair value of derivatives	1,594				208
Accrued liabilities and other	35,814				21,607
	156,371				136,395
NON-CURRENT LIABILITIES
Long-term debt	599,653				639,638
Deferred income taxes	146,076				140,809
Asset retirement obligations	47,813				49,981
Deferred revenue from volumetric production payment	28,056				29,770
Accrued compensation under non-equity award plans	18,752				15,469
Other	934				892
	841,284				876,559
COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; none issued	—				—
Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 12,165,536 shares at March 31, 2014 and December 31, 2013	1,216				1,216
Additional paid-in capital	152,556				152,556
Retained earnings	211,403				200,011
	365,175				353,783
	$	1,362,830			$	1,366,737

 

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

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CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (Unaudited) (In thousands, except per share)
	Three Months Ended
	March 31,
	2014				2013
REVENUES
Oil and gas sales	$	110,586			$	98,364
Midstream services	1,616				896
Drilling rig services	6,879				5,317
Other operating revenues	5,524				2,290
Total revenues	124,605				106,867
COSTS AND EXPENSES
Production	26,447				31,489
Exploration:
Abandonments and impairments	3,839				810
Seismic and other	1,483				2,587
Midstream services	534				407
Drilling rig services	4,856				5,068
Depreciation, depletion and amortization	36,255				39,063
Impairment of property and equipment	3,406				69,537
Accretion of asset retirement obligations	886				1,068
General and administrative	11,818				7,588
Other operating expenses	502				133
Total costs and expenses	90,026				157,750
Operating income (loss)	34,579				(50,883		)
OTHER INCOME (EXPENSE)
Interest expense	(12,521		)		(10,571		)
Loss on derivatives	(5,041		)		(6,535		)
Other	840				1,949
Total other income (expense)	(16,722		)		(15,157		)
Income (loss) before income taxes	17,857				(66,040		)
Income tax (expense) benefit	(6,465		)		24,831
NET INCOME (LOSS)	$	11,392			$	(41,209	)
Net income (loss) per common share:
Basic	$	0.94			$	(3.39	)
Diluted	$	0.94			$	(3.39	)
Weighted average common shares outstanding:
Basic	12,166				12,165
Diluted	12,166				12,165

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

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CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited) (In thousands)
	Common Stock							Additional								Total
	No. of			Par				Paid-In				Retained				Stockholders’
	Shares			Value				Capital				Earnings				Equity
BALANCE,
December 31, 2013	12,166			$	1,216			$	152,556			$	200,011			$	353,783
Net income	—			—				—				11,392				11,392
BALANCE,
March 31, 2014	12,166			$	1,216			$	152,556			$	211,403			$	365,175

 

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

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CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (In thousands)
	Three Months Ended
	March 31,
	2014				2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	11,392			$	(41,209	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	36,255				39,063
Impairment of property and equipment	3,406				69,537
Abandonments and impairments	3,839				810
Gain on sales of assets and impairment of inventory, net	(4,640		)		(362		)
Deferred income tax expense (benefit)	6,465				(24,831		)
Non-cash employee compensation	3,424				1,471
Loss on derivatives	5,041				6,535
Cash settlements of derivatives	(1,137		)		(445		)
Accretion of asset retirement obligations	886				1,068
Amortization of debt issue costs and original issue discount	704				570
Amortization of deferred revenue from volumetric production payment	(2,010		)		(2,274		)
Changes in operating working capital:
Accounts receivable	(4,074		)		1,102
Accounts payable	5,051				(12,386		)
Other	14,701				5,645
Net cash provided by operating activities	79,303				44,294
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(99,419		)		(74,461		)
Proceeds from volumetric production payment	296				440
Proceeds from sales of assets	68,979				481
Decrease in equipment inventory	3,389				3,890
Other	42				(1,792		)
Net cash used in investing activities	(26,713		)		(71,442		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	—				35,000
Repayments of long-term debt	(40,000		)		—
Net cash provided by (used in) financing activities	(40,000		)		35,000
NET INCREASE IN CASH AND CASH EQUIVALENTS	12,590				7,852
CASH AND CASH EQUIVALENTS
Beginning of period	26,623				10,726
End of period	$	39,213			$	18,578
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	176			$	3,244
Cash paid for income taxes	$	400			$	—

 

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

March 31, 2014

(Unaudited)

 

1.	Nature of Operations

 

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

 

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

 

2.	Presentation

 

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

 

The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries.  We account for our undivided interest in oil and gas limited partnerships using the proportionate consolidation method.  Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships.  Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships.  Substantially all intercompany transactions and balances associated with the consolidated operations have been eliminated. 

 

In the opinion of management, our unaudited consolidated financial statements as of March 31, 2014 and for the three months ended March 31, 2014 and 2013 include all adjustments, which are of a normal and recurring nature, that are necessary for a fair presentation in accordance with GAAP.  These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 2014 .

 

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3.	Long-Term Debt

 

Long-term debt consists of the following:

	March 31, 2014				December 31, 2013
	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $347 at March 31, 2014 and $362 at December 31, 2013	$	599,653			$	599,638
Revolving credit facility, due April 2019 (a)	—				40,000
	$	599,653			$	639,638

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(a)	Renewed and extended in April 2014.

Senior Notes

 

In March 2011, we issued $300 million of aggregate principal amount of 7.75% Senior Notes due 2019 (the “2019 Senior Notes”).  The 2019 Senior Notes were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011.  In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million.  In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. These 2019 Senior Notes and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

 

The Indenture contains covenants that restrict our ability to:  (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business.  One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture.  These covenants are subject to a number of important exceptions and qualifications as described in the Indenture.  We were in compliance with these covenants at March 31, 2014 and December 31, 2013 .

Revolving Credit Facility

 In April 2014, we entered into an amended and restated credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. to provide for a revolving line of credit of up to $1 billion , limited to the lesser of the borrowing base amount, as determined by the banks, and the aggregate lender commitments, as determined by us.  The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November.  We or the banks may also request an unscheduled borrowing base redetermination at other times during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under our revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency, (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest, or (4) take any combination of options (1) through (3). Increases in aggregate lender commitments require the consent of each lender.

 

The initial borrowing base and the aggregate lender commitments under the new facility remained at $415 million . The new facility, which matures in April 2019, requires an accelerated maturity of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the facility prior to October 1, 2018. Among other enhancements, the facility provides for a 25 basis point reduction in interest rates from the prior facility. At March 31, 2014, after allowing for outstanding letters of credit totaling $5.1 million , we had $409.9 million available under our revolving credit facility.

 Our revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in our revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base.  The obligations under our

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

 

At our election, annual interest rates under our new revolving credit facility are determined by reference to (1)  LIBOR plus an applicable margin between 1.50% and 2.50% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate , (B) the federal funds rate plus 0.50% , or (C)  one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.50% and 1.50% per year.  We also pay a commitment fee on the unused portion of our revolving credit facility at a rate between 0.375% and 0.50% .  The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under our revolving credit facility, excluding bank fees and amortization of debt issue costs, for the three months ended March 31, 2014 was 2.1% .

 

Our revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens.  One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1 .  Another financial covenant prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.  In connection with the issuance of the 2019 Senior Notes effective October 1, 2013, the consolidated funded indebtedness ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014, but, as of the closing of our new amended and restated credit facility, such ratio reverted to 4 to 1. The computations of consolidated current assets, current liabilities, EBITDAX and funded indebtedness are defined in our revolving credit facility.  We were in compliance with all financial and non-financial covenants at March 31, 2014 and December 31, 2013 .

4.	Sales of Assets

 

In March 2014, we closed a transaction to sell our interests in selected wells and leases in Wilson, Brazos, La Salle, Frio and Robertson Counties, Texas for $71 million , subject to customary closing adjustments, with $6.8 million being held in escrow pending resolution of certain title requirements. If the title requirements are not satisfied, waived or extended, some or all of the retained proceeds may be returned to the buyer. To the extent we are able to satisfy any of the title requirements, we may recognize additional net proceeds from the sale in future periods. Net proceeds from the sale were used to repay the outstanding balance on our revolving credit facility and to fund a portion of our planned capital expenditures for 2014.

In February 2014, our wholly owned subsidiary, Southwest Royalties, Inc. (“SWR”), sold a property in Ward County, Texas for $5.1 million , subject to customary closing adjustments.

In April 2013, we closed a transaction to monetize a substantial portion of our Andrews County Wolfberry oil and gas reserves, leasehold interests and facilities (the “Assets”). At closing, we contributed 5% of the Assets to a newly formed limited partnership in exchange for a 5% general partner interest, and a unit of GE Energy Financial Services contributed cash of $215.2 million to the limited partnership in exchange for a 95% limited partnership interest. The limited partnership then purchased 95% of the Assets from us for $215.2 million , subject to customary closing adjustments. Upon the attainment by the limited partner of predetermined rates of return, our general partner interest in the partnership may increase.

In April 2013, we sold a 75% interest in our rights to the base of the Delaware formation in approximately 12,000 net undeveloped acres in Loving County, Texas to a third party for $6.8 million . In December 2013, we sold our remaining interest in the same acreage for $34.5 million , subject to customary closing adjustments. The proceeds from these sales were used to repay a portion of our outstanding balance on our revolving credit facility.

5.	Asset Retirement Obligations

 

We record asset retirement obligations (“ARO”) associated with the retirement of our long-lived assets in the period in which they are incurred and become determinable. Under this method, we record a liability for the expected future cash outflows discounted at our credit-adjusted risk-free interest rate for the dismantlement and abandonment costs, excluding salvage values, of each oil and gas property. We also record an asset retirement cost to the oil and gas properties equal to the ARO liability. The fair value of the asset retirement cost and the ARO liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life.  The inputs are calculated based on historical data as well as current estimated costs. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects the changes in ARO during the three months ended March 31, 2014 and the year ended December 31, 2013 :

	March 31, 2014				December 31, 2013
	(In thousands)
Beginning of period	$	49,981			$	51,477
Additional ARO from new properties	242				795
Sales or abandonments of properties	(3,153		)		(5,892		)
Accretion expense	886				4,203
Revisions of previous estimates	(143		)		(602		)
End of period	$	47,813			$	49,981

6.	Deferred Revenue from Volumetric Production Payment

 

In March 2012, SWR, a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner, into SWR, with SWR continuing as the surviving entity in the mergers. To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million .  Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725,000 barrels of oil equivalents (“BOE”) of estimated future oil and gas production from certain properties derived from the mergers. The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and are to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties.  Once the scheduled volumes have been delivered to the third party, the term overriding royalty interest will terminate.  SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks related to the adequacy of the associated reserves to fully recoup the scheduled volumes and also assumed all risks associated with product prices.  As a result, the VPP has been accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes are produced. The net proceeds from the VPP are recorded as a non-current liability in the consolidated balance sheets.  Deferred revenue from the VPP is amortized over the life of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). As of March 31, 2014 , we have a remaining obligation to deliver approximately 456,000 BOE.

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

	March 31, 2014				December 31, 2013
	(In thousands)
Beginning of period	$	29,770			$	37,184
Deferred revenue from VPP	296				1,332
Amortization of deferred revenue from VPP	(2,010		)		(8,746		)
End of period	$	28,056			$	29,770

7.	Compensation Plans

 

Stock-Based Compensation

 

We presently have options outstanding under a stock option plan for independent directors covering 4,000 shares of Common Stock.  As of March 31, 2014 , the options had a weighted average exercise price of $33.03 per share (ranging from $22.90 per share to $41.74 per share), a weighted average remaining contractual term of 2.3 years, and an aggregate intrinsic value of $319,930 (based on a market price at March 31, 2014 of $113.01 per share).  No options were granted during the three months ended March 31, 2014 or 2013 .

 

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Non-Equity Award Plans

 

The Compensation Committee of the Board has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs.  The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, by the participants.  The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (the “APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas.  Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”).  At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships.  Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan.  We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements.  Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.

 

The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations.  The wells subject to the APO Reward Plan are not included in the APO Incentive Plan.  Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan.  Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area.  Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan.  As of March 31, 2014, we have granted awards under the APO Reward Plan in 12 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 May 1, 2013.  Of these 12 awards, 8 awards are fully vested, two awards will fully vest on May 1, 2015 and two will fully vest on August 1, 2015.

 

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

 

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

 

We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the vesting periods, which range from two years to five years . Compensation expense related to non-equity award plans for the three months ended March 31, 2014 and 2013 were $4.7 million and $1.9 million , respectively. Aggregate compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule:

 

	March 31, 2014				December 31, 2013
	(In thousands)
Current liabilities:
Accrued liabilities and other	$	3,458			$	3,317
Non-current liabilities:
Accrued compensation under non-equity award plans	18,752				15,469
Total accrued compensation under non-equity award plans	$	22,210			$	18,786

 

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8.	Derivatives

 

Commodity Derivatives

 

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

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to March 31, 2014 .  The settlement prices of commodity derivatives are based on NYMEX futures prices.

 

Swaps:

	Oil
	Bbls			Price
Production Period:
2nd Quarter 2014	560,600			$	96.81
3rd Quarter 2014	530,200			$	96.87
4th Quarter 2014	503,200			$	96.92
	1,594,000

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives.  As of March 31, 2014 , a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $1.6 million .

Accounting For Derivatives

 

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

Effect of Derivative Instruments on the Consolidated Balance Sheets

	Fair Value of Derivative Instruments as of March 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		$	1,594
	Non-current		—				Non-current		—
Total			$	—					$	1,594

 

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	March 31, 2014
	Assets				Liabilities
	(In thousands)
Fair value of derivatives — gross presentation	$	1,151			$	2,745
Effects of netting arrangements	(1,151		)		(1,151		)
Fair value of derivatives — net presentation	$	—			$	1,594

 

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

 

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

 

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

		Amount of Gain or (Loss) Recognized in Earnings
		Three Months Ended												Three Months Ended
Location of Gain or (Loss)		March 31, 2014												March 31, 2013
Recognized in Earnings		Realized				Unrealized				Total				Realized				Unrealized				Total
						(In thousands)												(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives		$	(1,137	)		$	(3,904	)		$	(5,041	)		$	(445	)		$	(6,090	)		$	(6,535	)
Total		$	(1,137	)		$	(3,904	)		$	(5,041	)		$	(445	)		$	(6,090	)		$	(6,535	)

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9.	Fair Value of Financial Instruments

 

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

 

Fair Value Measurements

 

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

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

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

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

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

 

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

 

		March 31, 2014				December 31, 2013
		Significant Other
		Observable Inputs
Description		(Level 2)
		(In thousands)
Assets:
Fair value of commodity derivatives		$	—			$	2,518
Total assets		$	—			$	2,518
Liabilities:
Fair value of commodity derivatives		$	1,594			$	208
Total liabilities		$	1,594			$	208

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Value of Other Financial Instruments

 

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

 

March 31, 2014

December 31, 2013

Carrying

Estimated

Carrying

Estimated

Description

Amount

Fair Value

Amount

Fair Value

(In thousands)

7.75% Senior Notes due 2019

$

599,653

$

639,000

$

599,638

$

616,500

 

10.	Income Taxes

 

Our effective federal and state income tax rate for the three months ended March 31, 2014 of 36.2% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

 

We file federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions.  Our tax returns for fiscal years after 2010 currently remain subject to examination by appropriate taxing authorities.  None of our income tax returns are under examination at this time.

11.	Other Operating Revenues and Expenses

 

Other operating revenues and expenses for the three months ended March 31, 2014 and March 31, 2013 are as follows:

 

		Three Months Ended March 31,
		2014				2013
		(In thousands)
Other operating revenues:
Gain on sales of assets		$	5,142			$	495
Marketing revenue		382				1,795
Total other operating revenues		$	5,524			$	2,290
Other operating expenses:
Loss on sales of assets		$	(492	)		$	(127	)
Impairment of inventory		(10		)		(6		)
Total other operating expenses		$	(502	)		$	(133	)

 

During the three months ended March 31, 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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 March 31, 2014 , we have performed a qualitative assessment and determined there has been no indication of any impairment of our investment in Dalea.

13.	Costs of Oil and Gas Properties

 

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

 

	March 31, 2014				December 31, 2013
	(In thousands)
Proved properties	$	2,338,303			$	2,317,053
Unproved properties	74,921				86,224
Total capitalized costs	2,413,224				2,403,277
Accumulated depletion	(1,312,963		)		(1,282,989		)
Net capitalized costs	$	1,100,261			$	1,120,288

 

14.                    Commitments and Contingencies

Legal Proceedings

 

SWR is a defendant in a suit filed in April 2011 in the Circuit Court of Union County, Arkansas where the plaintiffs are suing for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. The plaintiffs are seeking in excess of $8 million . In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $0.8 million , of which SWR would pay $0.7 million . To accomplish the settlement, the case would be converted to a class action, and each member of the class would be offered the right to either participate or opt out of the class and continue a separate action for damages. If more than 25% of the plaintiffs were to opt out of the settlement, SWR would have the right to terminate the settlement. Any plaintiffs opting out would be subject to all previous rulings of the court, including an order dismissing a significant number of the plaintiffs’ claims on the basis that such claims were time barred. SWR believes that the judge will approve the settlement and the number of the plaintiffs opting out of the settlement, if any, will be insignificant. We recorded a loss on settlement of $0.7 million in June 2013 in connection with this proposed settlement. We are now awaiting finalization of the settlement by the court.

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

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

15.	Impairment of Property and Equipment

 

We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value.  The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset.  We categorize the measurement of fair value of these assets as Level 3 inputs.  We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: discounted cash flow method, flowing daily production method and proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances.  We recorded a provision for impairment of proved properties of $3.4 million for the three months ended March 31, 2014 , and a $69.5 million provision for impairment of proved properties for the three months ended March 31, 2013 .  The impairment for the three months ended March 31, 2014 was related to the write down of certain non-operated properties located in North Dakota to their estimated fair value. The impairments for the three months ended March 31, 2013 were related to the write down of our Andrews County Wolfberry assets 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 $3.5 million for the three months ended March 31, 2014 and $61,000 for the three months ended March 31, 2013 , and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16.	Segment Information

 

We have two reportable operating segments, which are (1) oil and gas exploration and production and (2) contract drilling services.

 

The following tables present selected financial information regarding our operating segments for the three months ended March 31, 2014 and 2013 :

For the Three Months Ended
March 31, 2014
(Unaudited)						Contract				Intercompany				Consolidated
(In thousands)		Oil and Gas				Drilling				Eliminations				Total
Revenues		$	117,720			$	13,420			$	(6,535	)		$	124,605
Depreciation, depletion and amortization (a)		37,382				3,168				(889		)		39,661
Other operating expenses (b)		45,447				9,914				(4,996		)		50,365
Interest expense		12,521				—				—				12,521
Other (income) expense		4,201				—				—				4,201
Income (loss) before income taxes		18,169				338				(650		)		17,857
Income tax (expense) benefit		(6,347		)		(118		)		—				(6,465		)
Net income (loss)		$	11,822			$	220			$	(650	)		$	11,392
Total assets		$	1,332,223			$	58,245			$	(27,638	)		$	1,362,830
Additions to property and equipment		$	85,193			$	7,657			$	(651	)		$	92,199

For the Three Months Ended
March 31, 2013
(Unaudited)						Contract				Intercompany				Consolidated
(In thousands)		Oil and Gas				Drilling				Eliminations				Total
Revenues		$	101,550			$	10,712			$	(5,395	)		$	106,867
Depreciation, depletion and amortization (a)		105,540				3,748				(688		)		108,600
Other operating expenses (b)		44,019				10,326				(5,195		)		49,150
Interest expense		10,571				—				—				10,571
Other (income) expense		4,586				—				—				4,586
Income (loss) before income taxes		(63,166		)		(3,362		)		488				(66,040		)
Income tax (expense) benefit		23,654				1,177				—				24,831
Net income (loss)		$	(39,512	)		$	(2,185	)		$	488			$	(41,209	)
Total assets		$	1,499,796			$	58,548			$	(25,479	)		$	1,532,865
Additions to property and equipment		$	68,592			$	260			$	488			$	69,340

_______

(a)	Includes impairment of property and equipment.

(b)	Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of asset retirement obligations, general and administrative and other operating expenses.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17.	Guarantor Financial Information

In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes.  In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes. The 2019 Senior Notes issued in October 2013 and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture (see Note 3). Presented below is condensed consolidated financial information of CWEI (the “Issuer”) and the Issuer’s material wholly owned subsidiaries. Other than CWEI Andrews Properties, GP, LLC, the general partner of CWEI Andrews Properties, L.P., an affiliated limited partnership formed in April 2013, all of the Issuer’s wholly owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the Indenture. CWEI Andrews Properties, GP, LLC, is not a guarantor of the 2019 Senior Notes and its accounts are reflected in the “Non-Guarantor Subsidiary” column in this Note 17.

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

 

Condensed Consolidating Balance Sheet March 31, 2014 (Unaudited) (Dollars in thousands)
	Issuer				Guarantor Subsidiaries				Non-Guarantor Subsidiary				Adjustments/ Eliminations				Consolidated
Current assets	$	143,000			$	266,324			$	605			$	(259,868	)		$	150,061
Property and equipment, net	821,503				347,368				15,376				—				1,184,247
Investments in subsidiaries	350,576				—				—				(350,576		)		—
Other assets	15,197				13,325				—				—				28,522
Total assets	$	1,330,276			$	627,017			$	15,981			$	(610,444	)		$	1,362,830
Current liabilities	$	311,081			$	98,052			$	1,221			$	(253,983	)		$	156,371
Non-current liabilities:
Long-term debt	599,653				—				—				—				599,653
Deferred income taxes	121,918				134,054				1,808				(111,704		)		146,076
Other	38,268				57,154				133				—				95,555
	759,839				191,208				1,941				(111,704		)		841,284
Equity	259,356				337,757				12,819				(244,757		)		365,175
Total liabilities and equity	$	1,330,276			$	627,017			$	15,981			$	(610,444	)		$	1,362,830

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet December 31, 2013 (Dollars in thousands)
	Issuer				Guarantor Subsidiaries				Non-Guarantor Subsidiary				Adjustments/ Eliminations				Consolidated
Current assets	$	140,100			$	248,314			$	538			$	(250,641	)		$	138,311
Property and equipment, net	833,980				351,171				13,956				—				1,199,107
Investments in subsidiaries	342,416				—				—				(342,416		)		—
Other assets	16,032				13,287				—				—				29,319
Total assets	$	1,332,528			$	612,772			$	14,494			$	(593,057	)		$	1,366,737
Current liabilities	$	290,327			$	93,055			$	976			$	(247,963	)		$	136,395
Non-current liabilities:
Long-term debt	639,638				—				—				—				639,638
Deferred income taxes	118,438				129,880				988				(108,497		)		140,809
Other	36,161				59,829				122				—				96,112
	794,237				189,709				1,110				(108,497		)		876,559
Equity	247,964				330,008				12,408				(236,597		)		353,783
Total liabilities and equity	$	1,332,528			$	612,772			$	14,494			$	(593,057	)		$	1,366,737

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended March 31, 2014 (Unaudited) (Dollars in thousands)
	Issuer				Guarantor Subsidiaries				Non-Guarantor Subsidiary				Adjustments/ Eliminations				Consolidated
Total revenue	$	81,968			$	41,814			$	823			$	—			$	124,605
Costs and expenses	59,393				30,126				507				—				90,026
Operating income (loss)	22,575				11,688				316				—				34,579
Other income (expense)	(17,272		)		235				315				—				(16,722		)
Equity in earnings of subsidiaries	8,160				—				—				(8,160		)		—
Income tax (expense) benefit	(2,071		)		(4,173		)		(221		)		—				(6,465		)
Net income (loss)	$	11,392			$	7,750			$	410			$	(8,160	)		$	11,392

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended March 31, 2013 (Unaudited) (Dollars in thousands)
	Issuer				Guarantor Subsidiaries				Non-Guarantor Subsidiary				Adjustments/ Eliminations				Consolidated
Total revenue	$	73,284			$	33,583			$	—			$	—			$	106,867
Costs and expenses	127,711				30,039				—				—				157,750
Operating income (loss)	(54,427		)		3,544				—				—				(50,883		)
Other income (expense)	(15,228		)		71				—				—				(15,157		)
Equity in earnings of subsidiaries	2,350				—				—				(2,350		)		—
Income tax (expense) benefit	26,096				(1,265		)		—				—				24,831
Net income (loss)	$	(41,209	)		$	2,350			$	—			$	(2,350	)		$	(41,209	)

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2014 (Unaudited) (Dollars in thousands)
	Issuer				Guarantor Subsidiaries				Non-Guarantor Subsidiary				Adjustments/ Eliminations				Consolidated
Operating activities	$	53,573			$	23,309			$	1,532			$	889			$	79,303
Investing activities	(18,322		)		(5,910		)		(1,592		)		(889		)		(26,713		)
Financing activities	(20,844		)		(19,232		)		76				—				(40,000		)
Net increase (decrease) in cash and cash equivalents	14,407				(1,833		)		16				—				12,590
Cash at beginning of period	19,693				6,886				44				—				26,623
Cash at end of period	$	34,100			$	5,053			$	60			$	—			$	39,213

Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2013 (Unaudited) (Dollars in thousands)
	Issuer				Guarantor Subsidiaries				Non-Guarantor Subsidiary				Adjustments/ Eliminations				Consolidated
Operating activities	$	29,404			$	14,202			$	—			$	688			$	44,294
Investing activities	(64,103		)		(6,651		)		—				(688		)		(71,442		)
Financing activities	43,102				(8,102		)		—				—				35,000
Net increase (decrease) in cash and cash equivalents	8,403				(551		)		—				—				7,852
Cash at beginning of period	6,030				4,696				—				—				10,726
Cash at end of period	$	14,433			$	4,145			$	—			$	—			$	18,578

 

18.	Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of March 31, 2014 and have determined that no other events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.

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

 

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

 

Forward-Looking Statements

 

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

 

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

•	estimates of our oil and gas reserves;

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

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

•	our outlook on oil and gas prices;

•	our outlook on domestic and worldwide economic conditions;

•	our access to capital and our anticipated liquidity;

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

•	the impact of political and regulatory developments;

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

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

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

 

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

•	the possibility of unsuccessful exploration and development drilling activities;

•	our ability to replace and sustain production;

•	commodity price volatility;

•	domestic and worldwide economic conditions;

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

•	our level of indebtedness;

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

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

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

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

•	drilling and other operating risks;

•	hurricanes and other weather conditions;

•	lack of availability of goods and services;

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

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

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

 

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

 

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

 

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

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Overview

We are engaged in developmental drilling in two primary oil-prone regions, the Southern Delaware Basin and the Giddings Area in Texas, where we have a significant inventory of developmental drilling opportunities.  During the three months ended March 31, 2014 , we spent $84.4 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 first quarter of 2014 and the outlook for the remainder of 2014 .

 

•	We sold all of our interests in certain non-core Austin Chalk/Eagle Ford assets in March 2014 and sold 95% of our Andrews County Wolfberry assets in April 2013. As a result, reported oil and gas production, revenues and operating costs for the three months ended March 31, 2014 are not comparable to reported amounts for the same period in 2013.

•

Our oil and gas sales, excluding amortized deferred revenues, increased $12.5 million, or 13%, from the first quarter 2013 .  Production variances accounted for a $6.7 million increase and price variances accounted for a $5.8 million increase. Average realized oil prices were $93.60 per barrel in the first quarter of 2014 versus $91.26 per barrel in the first quarter 2013, and average realized gas prices were $4.97 per Mcf in 2014 versus $3.31 per Mcf in 2013. In addition, oil and gas sales for the first quarter of 2014 includes $2 million of amortized deferred revenue attributable to the volumetric production payment (“VPP”) versus $2.3 million for the first quarter of 2013. Reported production and related average realized sales prices exclude volumes associated with the VPP.

•

Before giving effect to the asset sales discussed above, oil, gas and natural gas liquids (“NGL”) production per barrel of oil equivalent (“BOE”) increased 3% in the first quarter of 2014 compared to the first quarter of 2013 , with oil production increasing 8% to 11,233 barrels per day, gas production decreasing 13% to 15,711 Mcf per day and NGL production increasing 1% to 1,622 barrels per day. Oil and NGL production accounted for approximately 83% of our total BOE production in the first quarter of 2014 versus 80% in the first quarter of 2013.

•	After giving effect to the asset sales, total production on a BOE basis increased 25% for the first quarter of 2014 as compared to the first quarter of 2013, with oil production increasing 2,756 barrels per day, gas production decreasing 455 Mcf per day and NGL production increasing 378 barrels per day.

•	Production costs decreased 16% or $5 million for the first quarter of 2014 compared to the first quarter of 2013 due primarily to a reduction in costs associated with the Andrews County sale in April 2013.

•

We recorded a $5 million loss on derivatives in the first quarter of 2014 (net of a $1.1 million loss on settled contracts).  For the same period in 2013 , we recorded a $6.5 million loss on derivatives (net of a $0.4 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 $11.8 million in the first quarter of 2014 compared to $7.6 million in the first quarter of 2013 .  Compensation expense attributable to our APO Reward Plans accounted for $2.8 million of the increase in personnel costs. The remaining increase was due primarily to higher personnel and professional costs in the first quarter of 2014.

•	Other operating revenues in the first quarter of 2014 include a $2.9 million gain on sale of certain of the Austin Chalk assets sold in March 2014. The gain excludes $6.8 million of sales proceeds held in escrow pending resolution of certain title requirements.

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Recent Exploration and Development Activities

 

Overview

 

We have been committed to drilling primarily developmental oil wells in the Permian Basin and the Giddings Area.  We spent $84.4 million during the first three months of 2014 on exploration and development activities and currently plan to spend approximately $418.7 million on similar activities during 2014 .  Our actual expenditures during 2014 may vary significantly from these estimates since our plans for exploration and development activities may change during the year.  Factors such as drilling results, changes in operating margins, and the availability of capital resources and other factors, could increase or decrease our actual expenditures during 2014 .

 

Areas of Operations

 

Permian Basin

 

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

 

We spent $47.6 million in the Permian Basin during the first three months of 2014 on drilling and completion activities and $6.6 million on leasing and seismic activities.  We drilled and completed 15 gross (5.5 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during the first three months of 2014 .  We currently plan to spend approximately $193.5 million on drilling and leasing activities in this area during 2014 .  Following is a discussion of our principal assets in the Permian Basin.

 

Delaware Basin

 

We currently hold approximately 80,000 net acres in the active Wolfbone resource play in the Delaware Basin in Reeves, Ward and Winkler Counties, Texas and may earn up to 5,000 additional net acres under an existing farm-in arrangement. The Wolfbone resource play generally refers to the interval from the Bone Springs formation down through the Wolfcamp formation at depths typically found between 8,000 and 13,000 feet. A Wolfbone well generally refers to a vertical well completed in multiple intervals within these formations or a horizontal well being completed in an interval within such formations.  These Permian aged formations in the Delaware Basin are composed of limestone, sandstone and shale. Geology in the Delaware Basin consists of multiple stacked pay zones with both over-pressured and normal-pressured intervals. To date, we have focused on the over-pressured intervals, having drilled 102 wells in the area: 70 vertical wells and 32 horizontal wells targeting multiple Bone Springs/Wolfcamp intervals.

A significant portion of our current and future holdings in this area are associated with a farm-in agreement we entered into in March 2011, with Chesapeake Exploration, L.L.C. (“Chesapeake”) in southern Reeves County, Texas with a term of five years.  Chesapeake’s position in the agreement is now held by SWEPI, LP (“Shell”). For the first well that we drill in a section within the farm-in area that meets certain specified requirements (each, a “carried well”), Shell, or its successors to this agreement, will retain a 25% carried interest, bearing none of the costs to drill and complete a carried well, and we will earn an undivided 75% interest in 640 net acres within the farm-in area. We amended the farm-in agreement with Shell in February 2014. The amendment replaced a commitment for 20 carried wells per year with a commitment to drill nine additional carried wells prior to December 31, 2014, on which date the agreement will terminate. Failure to drill these remaining carried wells will result in a penalty of $1 million for each undrilled well. We have since commenced the drilling of five of these wells, and anticipate that all of the commitment wells will be timely drilled. We have earned over 21,000 net acres under the farm-in. The amendment further provides for the renewal or extension of leases in the farm-in area with Shell receiving a 25% carry in the renewal costs in lieu of a drilling carry.

We are currently focused on drilling horizontal wells in the Wolfcamp A shale interval, with 14 Wolfcamp A wells currently in production, two wells being drilled and three wells are being completed. However, based on early results of our first Wolfbone C well and results by offset operators in the Wolfcamp B and C intervals, we may target the B and C zones in future wells to determine the feasibility of developmental drilling in multiple Wolfcamp shale intervals.

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We spent approximately $40.8 million on drilling and completion activities and $6.6 million for leasing activities in the Wolfbone play during the first quarter of 2014.  We plan to spend approximately $161.3 million on drilling and completion activities and $14.1 million on leasing activities in the Wolfbone play during 2014.  We currently plan to utilize three rigs in this area in 2014.

We own oil, gas and water disposal pipelines in Reeves County, consisting of 88 miles of oil pipelines with a design capacity of 18,000 barrels of oil per day, 87 miles of gas pipelines with a design capacity of 25,000 Mcf of natural gas per day and 87 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 36% of our first quarter 2014 oil and gas production was derived from wells in parts of the Permian Basin other than our Delaware Basin Wolfbone resource play. Many of these wells are located on the Central Basin Platform, geographically located between the Midland Basin and Delaware Basin, and produce from formations with conventional porosity such as the San Andres, Grayburg, Fusselman, Ellenburger and Yeso formations. A significant portion of our production in this area is derived from mature fields, several of which are in varying stages of secondary and/or tertiary recovery.

 

Giddings Area

 

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

 

Austin Chalk

 

Most of our existing production in the Giddings Area is derived from the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana.  The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet.  Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity by intersecting multiple zones.  Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas.

 

Eagle Ford Shale

 

Since July 2011, we have drilled and completed 18 horizontal Eagle Ford Shale wells.  Each of these wells has been or will be completed by multi-stage hydraulic fracturing processes using about five million pounds of proppant and 100,000 barrels of water.  We currently plan to utilize three drilling rigs in this area in 2014. During the first three months of 2014, we spent approximately $20.7 million on drilling and completion activities and $6.5 million for leasing activities in the Eagle Ford Shale Area, and we currently plan to spend approximately $215.8 million on similar drilling and leasing activities in this area during 2014 .

Other

 

We spent $3 million during the first three months of 2014 on exploration and development activities in other regions, including South Louisiana, Oklahoma and California, and we currently plan to spend approximately $9.4 million for 2014. 

Pipelines and Other Midstream Facilities

 

We own an interest in and operate oil, natural gas and water service facilities in the states of Texas and Louisiana. These midstream facilities consist of interests in approximately 351 miles of pipeline, two treating plants, one dehydration facility and multiple wellhead type treating and/or compression stations.  Most of our operated gas gathering and treating activities facilitate the transportation and marketing of our operated oil and gas production.

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Desta Drilling

 

 Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we operate 14 drilling rigs, two of which we lease under long-term contracts.  We believe that owning and operating our own rigs helps us control our cost structure while providing us flexibility to take advantage of drilling opportunities on a timely basis.  The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties.  As of April 30, 2014, we were using seven of our rigs to drill wells in our developmental drilling programs, four rigs were working for third parties and the remaining three rigs were idle.

Known Trends and Uncertainties

 

We began 2013 with limited availability under our revolving credit facility and our leverage ratios were increasing. In 2013, we successfully executed our plan to significantly improve liquidity through a combination of strategic steps to lower capital spending, sell certain producing properties and issue additional 2019 Senior Notes. At March 31, 2014, we had no borrowings outstanding under our revolving credit facility, leaving $409.9 million available on the facility after allowing for outstanding letters of credit totaling $5.1 million as compared to $86 million on our revolving credit facility at March 31, 2013. Our leverage ratio, expressed as the ratio of total long-term debt to EBITDAX, was 1.9 times based on annualized EBITDAX for the first three months of 2014. We believe these actions were effective in achieving a more sustainable balance between our future capital commitments and our expected financial resources.

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

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Supplemental Information

 

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

 

	Three Months Ended March 31,
	2014				2013
Oil and Gas Production Data:
Oil (MBbls)	1,011				938
Gas (MMcf)	1,414				1,626
Natural gas liquids (MBbls)	146				145
Total (MBOE)	1,393				1,354
Total (BOE/d)	15,474				15,044
Average Realized Prices (a) (b) :
Oil ($/Bbl)	$	93.60			$	91.26
Gas ($/Mcf)	$	4.97			$	3.31
Natural gas liquids ($/Bbl)	$	39.70			$	32.77
Loss on Settled Derivative Contracts (b) :
($ in thousands, except per unit)
Oil: Net realized loss	$	(1,137	)		$	(445	)
Per unit produced ($/Bbl)	$	(1.12	)		$	(0.47	)
Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	3,573				1,734
Other (c)	3,464				5,084
Austin Chalk (c)	2,168				2,760
Eagle Ford Shale (c)	1,651				604
Other	377				240
Total	11,233				10,422
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	2,806				1,124
Other (c)	7,142				9,668
Austin Chalk (c)	2,008				2,026
Eagle Ford Shale (c)	265				72
Other	3,490				5,177
Total	15,711				18,067
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	443				265
Other (c)	902				1,121
Austin Chalk (c)	221				206
Eagle Ford Shale (c)	37				12
Other	19				7
Total	1,622				1,611
(Continued)

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	Three Months Ended March 31,
	2014				2013
Exploration Costs (in thousands):
Abandonment and impairment costs:
North Louisiana	$	994			$	—
Michigan	933				—
Oklahoma	696				—
South Louisiana	602				215
Permian Basin	566				4
Other	48				591
Total	3,839				810
Seismic and other	1,483				2,587
Total exploration costs	$	5,322			$	3,397
Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	33,341			$	35,436
Contract drilling depreciation	2,280				3,060
Other depreciation	634				567
Total depreciation, depletion, and amortization	$	36,255			$	39,063
Oil and Gas Costs ($/BOE Produced):
Production costs	$	18.99			$	23.26
Production costs (excluding production taxes)	$	14.89			$	19.68
Oil and gas depletion	$	23.93			$	26.17
Net Wells Drilled (d) :
Exploratory Wells	1.3				—
Developmental Wells	10.3				12.5

 

_______

(a)

Oil and gas sales includes $2 million for the three months ended March 31, 2014 and $2.3 million for the three months ended March 31, 2013 of amortized deferred revenue attributable to the VPP transaction effective March 1, 2012. The calculation of average realized sales prices excludes production of 26,595 barrels of oil and 11,933 Mcf of gas for the three months ended March 31, 2014 and 30,488 barrels of oil and 7,533 Mcf of gas for the three months ended March 31, 2013 associated with the VPP.

(b)

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

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

		Three Months Ended March 31,
		2014			2013
Average Daily Production:
Andrews County Wolfberry:
Oil (Bbls)		—			1,633
Natural gas (Mcf)		—			1,811
NGL (Bbls)		—			356
Total (BOE)		—			2,291
Austin Chalk/Eagle Ford:
Oil (Bbls)		367			678
Natural gas (Mcf)		44			133
NGL (Bbls)		11			22
Total (BOE)		385			722

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

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Operating Results — Three-Month Periods

 

The following discussion compares our results for the three months ended March 31, 2014 to the comparative period in 2013 .  Unless otherwise indicated, references to 2014 and 2013 within this section refer to the three months ended March 31, 2014 and 2013, respectively.

 

Oil and gas operating results

 

Oil and gas sales, excluding amortized deferred revenues, increased $12.5 million, or 13%, in 2014 from 2013 .  Production variances accounted for a $6.7 million increase, and price variances accounted for a $5.8 million increase.  Oil and gas sales in 2014 also include $2 million of amortized deferred revenue versus $2.3 million in 2013 attributable to a VPP.  Combined oil, gas and NGL production in 2014 (on a BOE basis) increased 3% compared to 2013 .  Our production mix increased from 80% oil and NGL in 2013 to approximately 83% in 2014 . Oil production increased 8% in 2014 from 2013 . NGL production increased 1% while gas production decreased 13% in 2014 from 2013 .  In 2014 , our realized oil price was 3% higher than 2013 , and our realized gas price was 50% higher.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

 

Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, decreased 16% to $26.4 million in 2014 as compared to $31.5 million in 2013 due primarily to a reduction in costs associated with the Andrews County sale in April 2013.

 

Oil and gas depletion expense decreased $2.1 million from 2013 to 2014 due to a $3.1 million decrease related to rate variances and a $1 million increase due to production variances.  On a BOE basis, depletion expense decreased 9% to $23.93 per BOE in 2014 from $26.17 per BOE in 2013 .  Most of the decrease in depletion expense related to the sale of our Andrews County assets. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production.  We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

We recorded a provision for impairment of property and equipment of $3.4 million in 2014 and $69.5 million in 2013. The 2014 impairment related to the write down of the carrying value of certain non-operated properties in North Dakota to their estimated fair value. The transaction to monetize our Andrews County Wolfberry assets in April 2013 triggered the assessment of a non-cash charge in 2013. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value.

 

Exploration costs

 

We follow the successful efforts method of accounting, therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed.  In 2014 , we charged to expense $5.3 million of exploration costs, as compared to $3.4 million in 2013.

 

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 $6.9 million in 2014 compared to $5.3 million in 2013. Drilling service costs related to external customers and idle rig charges were $4.9 million in 2014 and $5.1 million in 2013 . Contract drilling depreciation for 2014 was $2.3 million compared to $3.1 million in 2013.

 

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General and Administrative

 

G&A expenses increased $4.2 million from $7.6 million in 2013 to $11.8 million in 2014 .  Compensation expense attributable to our APO Reward Plans accounted for $2.8 million of the increase in personnel costs. The remaining increase was due primarily to higher personnel and professional costs in 2014.

Gain/loss on derivatives

 

We did not designate any derivative contracts in 2014 or 2013 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives.  For the three months ended March 31, 2014 , we reported a $5 million loss on derivatives, (net of a $1.1 million loss on settled contracts).  For the three months ended March 31, 2013 , we reported a $6.5 million loss on derivatives, (net of a $0.4 million loss on settled contracts).  Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

 

Gain/loss on sales of assets and impairment of inventory

 

We recorded a net gain of $4.6 million on sales of assets and impairment of inventory in 2014 compared to a net gain of $0.4 million in 2013 .  The 2014 gain related primarily to the sale of certain of the Austin Chalk/Eagle Ford assets sold in March 2014 and the sale of a property in Ward County, Texas in February 2014. The 2013 gain related primarily to the sale of a certain non-core area in the Permian Basin. Gain on sales of assets are included in other operating revenues and loss on sales of assets and impairment of inventory are included in other operating expenses in our consolidated statements of operations and comprehensive income (loss). 

Income taxes

 

Our estimated federal and state effective income tax rate in 2014 of 36.2% was greater than the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

Liquidity and Capital Resources

 

Overview

 

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

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Capital expenditures

 

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

	Actual Expenditures Three Months Ended March 31, 2014				Planned Expenditures Year Ending December 31, 2014				2014 Percentage of Total
	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	40,800			$	161,300			38	%
Other	6,800				18,200				4	%
Austin Chalk/Eagle Ford Shale	20,700				182,300				44	%
Other	2,500				6,900				2	%
	70,800				368,700				88	%
Leasing and seismic	13,600				50,000				12	%
Exploration and development	$	84,400			$	418,700			100	%

 

Our expenditures for exploration and development activities for the three months ended March 31, 2014 totaled $84.4 million .  We financed these expenditures for the three months of 2014 with cash flow from operating activities and proceeds from asset sales.  We currently plan to spend approximately $ 418.7 million on exploration and development activities during fiscal 2014 .  Our actual expenditures during 2014 may vary significantly from these estimates since our plans for exploration and development activities may change during the year.  Factors, such as drilling results, changes in operating margins, and the availability of capital resources and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2014 .

 

Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow, combined with funds available to us on our revolving credit facility, will be sufficient to finance our planned exploration and development activities through 2014 .  Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base may under our credit facility be less than expected, cash flow may be less than expected, or capital expenditures may be more than expected.  In the event we lack adequate liquidity to finance our expenditures through 2014 , we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.

Cash flow provided by operating activities

 

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

 

Cash flow provided by operating activities for the three months ended March 31, 2014 increased $35 million , or 79% , as compared to the corresponding period in 2013 due primarily to increased production and higher commodity prices and a reduction in production costs associated with the sale of our Andrews County Wolfberry assets.

Senior Notes

 

In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes.  The 2019 Senior Notes were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011.  In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million.  In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes. The notes were sold at par to yield 7.75% to maturity. These 2019 Senior Notes and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.

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The Indenture contains covenants that restrict our ability to:  (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business.  One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture.  These covenants are subject to a number of important exceptions and qualifications as described in the Indenture.  We were in compliance with these covenants at March 31, 2014 and December 31, 2013.

Revolving credit facility

 

We have historically relied on a revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs.  As long as we have sufficient availability under our revolving credit facility to meet our obligations as they become due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit. In April 2014, we entered into an amended and restated credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. to provide for a revolving line of credit of up to $1 billion, limited to the lesser of the borrowing base amount, as determined by the banks, and the aggregate lender commitments, as determined by us. 

 

The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November.  We or the banks may also request an unscheduled borrowing base redetermination at other times during the year.  If, at any time, the borrowing base is less than the amount of outstanding credit exposure under our revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency, (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest, or (4) take any combination of items (1) through (3). Increases in aggregate lender commitments require the consent of each lender.

In November 2013, the banks increased the aggregate commitment and borrowing base from $407.5 million to $415 million. During the three month period ended March 31, 2014, we decreased indebtedness outstanding under our revolving cred it facility by $40 million , effective with the closing of the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014. The initial borrowing base and the aggregate lender commitments under the new facility remained at $415 million . The new facility, which matures in April 2019, will require an accelerated maturity of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the new facility prior to October 1, 2018. Among other enhancements, the new facility provides for a 25 basis point reduction in interest rates.

 

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

 

At our election, annual interest rates under our revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.50% and 2.50% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50% , or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.50% and 1.50% per year.  We also pay a commitment fee on the unused portion of our revolving credit facility at a rate between 0.375% and 0.50% .  The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base.  Interest and fees are payable no less often than quarterly.  The effective annual interest rate on borrowings under our revolving credit facility, excluding bank fees and amortization of debt issue costs, for the three months ended March 31, 2014 was 2.1% .

 

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

Working capital computed for loan compliance purposes differs from our working capital computed in accordance with accounting principles generally accepted in the United States (“GAAP”).  Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under our revolving credit facility and is not affected by the volatility in working

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capital caused by changes in fair value of derivatives.  Our GAAP reported working capital deficit was $6.3 million at March 31, 2014 compared to working capital of $1.9 million at December 31, 2013 .  After giving effect to the adjustments, our working capital computed for loan compliance purposes was $405.2 million at March 31, 2014 , as compared to $369.6 million at December 31, 2013 . 

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

 

	March 31, 2014				December 31, 2013
	(In thousands)
Working capital (deficit) per GAAP	$	(6,310	)		$	1,916
Add funds available under our revolving credit facility	409,947				369,947
Exclude fair value of derivatives classified as current assets or current liabilities	1,594				(2,310		)
Working capital per loan covenant	$	405,231			$	369,553

 

Our revolving credit facility also prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the last end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1.  In connection with the issuance of the 2019 Senior Notes effective October 1, 2013, the consolidated funded indebtedness ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014, but, as of the closing of our new amended and restated credit facility, such ratio reverted back to 4 to 1.

 

We were in compliance with all financial and non-financial covenants at March 31, 2014 and December 31, 2013.  However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future.  If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend our revolving credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means.  If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

 

The lending group under our revolving credit facility includes the following institutions:  JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Union Bank, N.A., Compass Bank, Frost Bank, The Royal Bank of Scotland plc, KeyBank National Association, Natixis, New York Branch, UBS AG, Stamford Branch, Fifth Third Bank, U.S. Bank National Association, Whitney Bank, Bank of America, N.A., Branch Banking and Trust Company, Capital One, National Association and PNC Bank, National Association.

 From time to time, we engage in other transactions with lenders under our revolving credit facility.  Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements.  As of March 31, 2014 , JPMorgan Chase Bank, N.A. and Union Bank, N.A. were the counterparties to our commodity derivative agreements.  Our obligations under existing derivative agreements with our lenders are secured by the security documents executed by the parties under our revolving credit facility.

 

At March 31, 2014 , we had no outstanding advances under the bank credit facility, resulting in availability under the credit facility of $409.9 million, net of outstanding letters of credit of $5.1 million . With cash on hand of $39.2 million, total liquidity at March 31, 2014 was $449.1 million.

Alternative capital resources

 

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

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

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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, 2013.

 

Oil and Gas Prices

 

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market commodity prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, many of which are beyond our control.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.  We cannot predict future oil and gas commodity prices with any degree of certainty.  Sustained weakness in oil and gas commodity prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically.  Any reduction in reserves, including reductions due to commodity price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities.  Similarly, any improvements in oil and gas commodity prices can have a favorable impact on our financial condition, results of operations and capital resources.  Based on December 31, 2013 reserve estimates, we project that a $1 decline in the price per Bbl of oil and a $.50 decline in the price per Mcf of gas from year end 2013 would reduce our gross revenues for the year ending December 31, 2014 by $7.1 million.

 

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

 

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

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The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to March 31, 2014 . The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:

 

	Oil
	Bbls			Price
Production Period:
2nd Quarter 2014	560,600			$	96.81
3rd Quarter 2014	530,200			$	96.87
4th Quarter 2014	503,200			$	96.92
	1,594,000

 

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives.  As of March 31, 2014, a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $1.6 million.

 

Interest Rates

 

We are exposed to interest rate risk on our long-term debt with a variable interest rate.  At March 31, 2014 , our fixed rate debt maturing 2019 had a carrying value of $599.7 million and an approximate fair value of $639 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 $26.4 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 March 31, 2014 these disclosure controls and procedures are effective at the reasonable assurance level in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

Changes in Internal Control Over Financial Reporting

 

No changes in internal control over financial reporting were made during the three months ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1 -	Legal Proceedings

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

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.

Item 1A -	Risk Factors

 

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

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

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Item 6 -	Exhibits

Exhibits
**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441
**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††
**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††
**4.1		Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††
**4.2		Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††
**4.3		Registration Rights Agreement, dated as of September 26, 2013, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on October 2, 2013††
**10.1		Third Amended and Restated Credit Agreement dated April 23, 2014, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on April 25, 2014††
*31.1		Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
*31.2		Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
***32.1		Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*101.INS		XBRL Instance Document
*101.SCH		XBRL Schema Document
*101.CAL		XBRL Calculation Linkbase Document
*101.DEF		XBRL Definition Linkbase Document
*101.LAB		XBRL Labels Linkbase Document
*101.PRE		XBRL Presentation Linkbase Document

*                        Filed herewith.

**                 Incorporated by reference to the filing indicated.

***          Furnished herewith.

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

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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:	May 2, 2014	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			Executive Vice President and Chief Operating Officer
Date:	May 2, 2014	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibits
**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement, Commission File No. 333-13441
**3.2		Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to our Form 10-Q for the period ended September 30, 2000††
**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 14, 2008††
**4.1		Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004††
**4.2		Indenture, dated March 16, 2011, among Clayton Williams Energy, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as Trustee, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 17, 2011††
**4.3		Registration Rights Agreement, dated as of September 26, 2013, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to our Current Report on Form 8-K filed with the Commission on October 2, 2013††
**10.1		Third Amended and Restated Credit Agreement dated April 23, 2014, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on April 25, 2014††
*31.1		Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
*31.2		Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
***32.1		Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*101.INS		XBRL Instance Document
*101.SCH		XBRL Schema Document
*101.CAL		XBRL Calculation Linkbase Document
*101.DEF		XBRL Definition Linkbase Document
*101.LAB		XBRL Labels Linkbase Document
*101.PRE		XBRL Presentation Linkbase Document

*                        Filed herewith.

**                 Incorporated by reference to the filing indicated.

***          Furnished herewith.

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

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