CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q

Attached files

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EX-32.1 - EXHIBIT 32.1 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-33116xex321.htm
EX-31.2 - EXHIBIT 31.2 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-33116xex312.htm
EX-31.1 - EXHIBIT 31.1 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-33116xex311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended March 31, 2016



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

Commission File Number 001-10924

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)



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



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

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

Not applicable

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

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

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

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



Large accelerated filer o		Accelerated filer þ

Non-accelerated filer o		Smaller reporting company o

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

There were 12,169,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of May 6, 2016.

Table of Contents

CLAYTON WILLIAMS ENERGY, INC.

TABLE OF CONTENTS



	PART I. FINANCIAL INFORMATION

		Page

Item 1.	Financial Statements

	Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015	3

	Consolidated Statements of Operations and Comprehensive Loss for the three months ended March 31, 2016 and 2015	5

	Consolidated Statement of Stockholders’ Equity for the three months ended March 31, 2016	6

	Consolidated Statements of Cash Flows for the three months ended March 31, 2016 and 2015	7

	Notes to Consolidated Financial Statements	8

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	42

Item 4.	Controls and Procedures	43

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	45

Item 1A.	Risk Factors	46

Item 6.	Exhibits	47

	Signatures	49

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1 -	Financial Statements

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

	March 31, 2016			December 31, 2015
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	184,891		$	7,780
Accounts receivable:
Oil and gas sales	11,936			16,660
Joint interest and other, net of allowance for doubtful accounts of $2,647 at March 31, 2016 and $2,447 at December 31, 2015	3,725			3,661
Affiliates	317			260
Inventory	29,975			31,455
Deferred income taxes	6,153			6,526
Prepaids and other	1,170			2,463
	238,167			68,805
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,595,704			2,585,502
Pipelines and other midstream facilities	60,198			60,120
Contract drilling equipment	123,893			123,876
Other	19,139			19,371
	2,798,934			2,788,869
Less accumulated depreciation, depletion and amortization	(1,628,501		)	(1,587,585		)
Property and equipment, net	1,170,433			1,201,284

OTHER ASSETS
Investments and other	7,240			17,331
	$	1,415,840		$	1,287,420

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

Table of Contents

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

	March 31, 2016		December 31, 2015
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	19,107	$	29,197
Oil and gas sales	16,121		19,490
Affiliates	228		383
Fair value of commodity derivatives	2,223		—
Accrued liabilities and other	27,893		16,669
	65,572		65,739
NON-CURRENT LIABILITIES
Long-term debt	915,378		742,410
Deferred income taxes	89,580		108,996
Fair value of commodity derivatives	33		—
Fair value of common stock warrants	10,458		—
Asset retirement obligations	49,741		48,728
Accrued compensation under non-equity award plans	15,300		16,254
Deferred revenue from volumetric production payment and other	5,441		5,695
	1,085,931		922,083
COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; issued and outstanding — 3,500 shares at March 31, 2016 and none at December 31, 2015	—		—
Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 12,169,536 shares at March 31, 2016 and December 31, 2015	1,216		1,216
Additional paid-in capital	152,686		152,686
Retained earnings	110,435		145,696
	264,337		299,598
	$	1,415,840	$	1,287,420

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

Table of Contents

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


	Three Months Ended
	March 31,
	2016			2015
REVENUES
Oil and gas sales	$	28,826		$	58,570
Midstream services	1,287			1,611
Drilling rig services	—			23
Other operating revenues	201			3,938
Total revenues	30,314			64,142
COSTS AND EXPENSES
Production	17,154			23,430
Exploration:
Abandonments and impairments	990			1,623
Seismic and other	111			866
Midstream services	336			399
Drilling rig services	1,269			1,876
Depreciation, depletion and amortization	38,613			42,654
Impairment of property and equipment	2,347			2,531
Accretion of asset retirement obligations	1,029			958
General and administrative	3,891			9,143
Other operating expenses	1,151			844
Total costs and expenses	66,891			84,324
Operating loss	(36,577		)	(20,182		)
OTHER INCOME (EXPENSE)
Interest expense	(17,087		)	(13,277		)
Gain on change in fair value of common stock warrants	6,305			—
Gain on commodity derivatives	626			4,632
Impairment of investments and other	(7,571		)	693
Total other income (expense)	(17,727		)	(7,952		)
Loss before income taxes	(54,304		)	(28,134		)
Income tax benefit	19,043			9,902
NET LOSS	$	(35,261	)	$	(18,232	)
Net loss per common share:
Basic	$	(2.90	)	$	(1.50	)
Diluted	$	(2.90	)	$	(1.50	)
Weighted average common shares outstanding:
Basic	12,170			12,170
Diluted	12,170			12,170

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, 2015	12,170	$	1,216	$	152,686	$	145,696		$	299,598
Net loss	—	—		—		(35,261		)	(35,261		)
BALANCE,
March 31, 2016	12,170	$	1,216	$	152,686	$	110,435		$	264,337

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

Table of Contents

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

	Three Months Ended
	March 31,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(35,261	)	$	(18,232	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization	38,613			42,654
Impairment of property and equipment	2,347			2,531
Abandonments and impairments	990			1,623
(Gain) loss on sales of assets and impairment of inventory, net	708			(3,071		)
Deferred income tax benefit	(19,043		)	(9,902		)
Non-cash employee compensation	(1,068		)	1,314
Gain on commodity derivatives	(626		)	(4,632		)
Cash settlements of commodity derivatives	2,882			—
Accretion of asset retirement obligations	1,029			958
Amortization of debt issue costs and original issue discount	2,381			747
Gain on change in fair value of common stock warrants	(6,305		)	—
Amortization of deferred revenue from volumetric production payment	(202		)	(1,778		)
Impairment of investment in Dalea Investment Group, LLC	8,431			922
Other	(199		)	(424		)
Changes in operating working capital:
Accounts receivable	4,603			22,555
Accounts payable	(10,652		)	(26,178		)
Other	11,894			10,997
Net cash provided by operating activities	522			20,084
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(14,240		)	(89,537		)
Proceeds from sales of assets	1,380			4,995
Decrease in equipment inventory	214			1,707
Other	138			266
Net cash used in investing activities	(12,508		)	(82,569		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	343,237			42,000
Proceeds from issuance of common stock warrants	16,763			—
Repayments of long-term debt	(160,000		)	—
Payment of debt issuance costs	(10,903		)	—
Net cash provided by financing activities	189,097			42,000
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	177,111			(20,485		)
CASH AND CASH EQUIVALENTS
Beginning of period	7,780			28,016
End of period	$	184,891		$	7,531

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	3,204		$	888
Cash paid for income taxes	$	—		$	—

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2016

(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 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 25.5% of CWEI’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners, and Mel G. Riggs, our President, is the sole general partner.

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 interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of 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, 2016 and for the three months ended March 31, 2016 and 2015 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, 2016.

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, 2015.

Recent Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842).” The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted. ASU 2016-02 must be adopted using a modified retrospective transition, and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes.” This ASU requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. Adoption of the new guidance will affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements.

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

In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net debt issuance costs directly related to our senior notes and our second lien term loan to be classified as a direct deduction from the carrying amount of the related senior notes and second lien term loan. We adopted this ASU as of March 31, 2016 and reclassified $7.3 million of debt issuance costs at December 31, 2015 from a non-current asset to a direct deduction in long-term debt. The debt issuance costs related to our revolving credit facility remains classified as a non-current asset due to the revolving nature of that facility.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

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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, 2016			December 31, 2015

	(In thousands)
7.75% Senior Notes, due 2019	$	600,000		$	600,000
Original Issue Discount	(224		)	(241		)
Debt Issuance Costs	(6,834		)	(7,349		)
Net 7.75% Senior Notes, due 2019	$	592,942		$	592,410

Second Lien Term Loan, due March 2021	$	350,000		$	—
Original Issue Discount	(16,763		)	—
Debt Issuance Costs	(10,801		)	—
Net Second Lien Term Loan, due March 2021	$	322,436		$	—

Revolving credit facility, due April 2019	$	—		$	150,000
	$	915,378		$	742,410

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, which are unsecured, were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year. In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million. In October 2013, we issued an additional $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. All of the 2019 Senior Notes are treated as a single class of debt securities under the same indenture (the “Indenture”). We may redeem some or all of the 2019 Senior Notes at a redemption price (expressed as a percentage of principal amount) equal to 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 generally restricts our ability to incur indebtedness if our ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) exceeds 2.25 times. However, this restriction does not prevent us from incurring indebtedness under a credit facility (as defined in the Indenture) in an aggregate principal amount at any time outstanding not to exceed the greater of (a) $500 million and (b) 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). Our ratio of EBITDAX to consolidated interest expense at March 31, 2016 was 1.8 times consolidated EBITDAX. These covenants are subject to a number of additional important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at March 31, 2016 and December 31, 2015.

Revolving Credit Facility

We may borrow money under a revolving credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. On March 8, 2016, we entered into an amendment to the revolving credit facility in connection with the Refinancing (see “ — Term Loan Credit Facility”). The amendment, among other things, reduced the borrowing base and aggregate commitments of the lenders from $450 million to $100 million. The aggregate commitments may be increased to $150 million if we meet a minimum ratio of the discounted present value of our proved developed producing reserves to our debt under the revolving credit facility of 1.2 to 1.0. Increases in aggregate lender commitments require the consent of each lender.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The amendment also increased the applicable interest rates under our revolving credit facility by 0.75% at every borrowing base utilization level. At our election, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2.5% and 3.5% per year or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.5% and 2.5% per year. We are also required to pay a commitment fee on the unused portion of the commitments under the revolving credit facility of 0.5% per year. The applicable margin is determined based on the utilization of the borrowing base. Interest and fees are payable quarterly, except that interest on LIBOR-based tranches is due at maturity of each tranche but no less frequently than quarterly.

The 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 to1. The March 2016 amendment replaced a requirement that we maintain certain ratios of consolidated funded indebtedness to consolidated EBITDAX with a less restrictive ratio of debt outstanding solely under the revolving credit facility to consolidated EBITDAX of 2.0 to 1.0.

The revolving credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the revolving credit facility prior to October 1, 2018.

The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the 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).

The revolving credit facility is collateralized by a first lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the revolving credit facility) attributed to our proved oil and gas interests evaluated in determining the borrowing base. The obligations under the revolving credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries.

The failure to comply with the foregoing covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the revolving credit facility. Other events of default under the revolving credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding.

Term Loan Credit Facility

On March 8, 2016, we entered into the term loan credit facility with funds managed by Ares Management, LLC (“Ares”) providing for the lenders to make secured term loans to us in the principal amount of $350 million (the “Refinancing”). As part of the Refinancing, we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share and required certain amendments to the revolving credit facility. The term loans were issued at an original issue discount of $16.8 million, which amount equaled the cash consideration received by us for the issuance of the related warrants and shares of special voting preferred stock. Aggregate cash proceeds from the Refinancing of approximately $340 million, net of transaction costs, were used to fully repay the then-outstanding balance on the revolving credit facility of $160 million, plus accrued interest and fees, and added approximately $180 million of cash to our balance sheet to provide a dedicated source of liquidity to fund our operations and development.

The warrants expire in 2026 and contain various anti-dilution provisions. Pursuant to FASB ASC 815-40, we account for the warrants as derivative instruments and carry the warrants as a non-current liability at their fair value, with the calculated increase or decrease in fair value each quarter being recognized in the statement of operations and comprehensive loss (see Note

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

9). The warrants had a fair value of $16.8 million at the date of issuance and a fair value of $10.5 million at March 31, 2016. As a result, we recorded a gain on revaluation of the warrant liability of $6.3 million during the quarter ended March 31, 2016.

Interest on the term loans is payable quarterly in cash at 12.5% per year; however, during the period from March 15, 2016 through March 31, 2018, we may elect to pay interest for any quarter in-kind at 15% per year. We elected to pay interest for the period commencing from March 15, 2016 and ending March 31, 2016 in cash, and elected to pay interest for the quarterly period ending June 30, 2016 in-kind. Future quarterly elections to pay in-kind must be made at least 30 days prior to the beginning of each calendar quarter.

The term loan credit facility matures on March 15, 2021, but is subject to an earlier maturity on December 31, 2018, if we do not extend or refinance our existing 2019 Senior Notes on or prior to that date.

The term loan credit facility is collateralized by a second lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the term loan credit facility) attributed to our proved oil and gas interests. The obligations under the term loan credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries. Optional and mandatory prepayments made prior to September 15, 2020 are subject to make-whole or prepayment premiums.

The failure to comply with these covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the term loan credit facility. Other events of default under the term loan credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding.


4.	Sales of Assets

In February 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $0.8 million. In March 2015, we closed a transaction to assign our interests in selected wells in Martin County, Texas for $2.9 million and we sold our interests in selected wells in Yoakum County, Texas for $0.8 million, subject to customary closing adjustments. Net proceeds from each of these transactions were applied to reduce indebtedness outstanding under the revolving credit facility.


5.	Asset Retirement Obligations

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

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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, 2016 and the year ended December 31, 2015:



	March 31, 2016			December 31, 2015
	(In thousands)
Beginning of period	$	48,728		$	45,697
Additional ARO from new properties	14			469
Sales or abandonments of properties	(45		)	(4,435		)
Accretion expense	1,029			3,945
Revisions of previous estimates	15			3,052
End of period	$	49,741		$	48,728


6.	Deferred Revenue from Volumetric Production Payment

In March 2012, Southwest Royalties, Inc. (“SWR”), a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner, into SWR, with SWR continuing as the surviving entity in the mergers. To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million. Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725 MBOE of estimated future oil and gas production from certain properties derived from the mergers. The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and were 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 were delivered to the third party, the term overriding royalty interest would 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 associated with product prices. As a result, the VPP was accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes were produced. The net proceeds from the VPP were recorded as a non-current liability in the consolidated balance sheets. Deferred revenue from the VPP was amortized over the life of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive loss. In August 2015, we terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million. The termination of the VPP was accounted for as a repurchase of reserves, with the repurchase price offsetting the non-current liability and the balance of the remaining non-current liability amortized over the original term of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive loss. As of March 31, 2016, we have no further obligations under the VPP.

The following table reflects the changes in the deferred revenue during the three months ended March 31, 2016 and the year ended December 31, 2015:



	March 31, 2016			December 31, 2015

	(In thousands)
Beginning of period	$	5,470		$	23,129
Deferred revenue from VPP	—			2,866
Amortization of deferred revenue from VPP	(202		)	(6,822		)
Termination of VPP	—			(13,703		)
End of period	$	5,268		$	5,470

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


7.	Compensation Plans

Non-Equity Award Plans

The Compensation Committee of the Board has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs. The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, through the efforts of the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (“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 an APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in 15 specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to June 11, 2014. Of these 15 awards, 12 awards are fully vested and three will fully vest on June 23, 2016.

In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the APO cash flow from a 22.50% 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 the SWR Reward Plan is recognized over the applicable vesting periods, which range from two years to five years. Compensation expense related to non-equity award plans for the three months ended March 31, 2016 and 2015 were $(0.8) million and $2.1 million, respectively. Credits to expense resulted from the reversal of previously accrued compensation expense attributable to changes in estimates of future compensation expense.

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



	March 31, 2016		December 31, 2015
	(In thousands)
Current liabilities:
Accrued liabilities and other	$	1,141	$	1,251
Non-current liabilities:
Accrued compensation under non-equity award plans	15,300		16,254
Total accrued compensation under non-equity award plans	$	16,441	$	17,505

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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, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract, generally New York Mercantile Exchange (“NYMEX”) futures prices, resulting in a net amount due to or from the counterparty. In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature.

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to March 31, 2016. In addition, we granted an option on 739 MBbls of oil production from July 2016 through December 2016 at $40.25 per barrel exercisable by the counterparty on June 30, 2016. In April 2016, we entered into costless collars covering 1,128 MBbls of our oil production for the period from January 2017 through December 2017 at a weighted average floor price of $41.57 and a weighted average ceiling price of $50.81. Settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:



	Oil
	MBbls	Price
Production Period:
2nd Quarter 2016	518	$	40.47
3rd Quarter 2016	176	$	42.70
4th Quarter 2016	167	$	42.70
2017	315	$	44.30
	1,176

Swaps Subject to Optional Extension:



	Oil
	MBbls	Price
Production Period:
3rd Quarter 2016	378	$	40.25
4th Quarter 2016	361	$	40.25
	739

Crude Oil Costless Collars:



	Oil
		Weighted		Weighted
		Average		Average
	MBbls	Floor Price		Ceiling Price
Production Period:
2017	1,128	$	41.57	$	50.81
	1,128

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Accounting for Commodity Derivatives

We did not designate any of our 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, were recorded as other income (expense) in our consolidated statements of operations and comprehensive loss.

Effect of Commodity Derivative Instruments on the Consolidated Balance Sheets



	Fair Value of Commodity Derivative Instruments as of March 31, 2016
	Asset Commodity Derivatives			Liability Commodity Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Commodity derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of commodity derivatives:			Fair value of commodity derivatives:
	Current	$	—	Current	$	2,223
	Non-current	—		Non-current	33
Total		$	—		$	2,256



	Fair Value of Commodity Derivative Instruments as of December 31, 2015
	Asset Commodity Derivatives			Liability Commodity Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Commodity derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of commodity derivatives:			Fair value of commodity derivatives:
	Current	$	—	Current	$	—
	Non-current	—		Non-current	—
Total		$	—		$	—

Gross to Net Presentation Reconciliation of Commodity Derivative Assets and Liabilities



	March 31, 2016
	Assets			Liabilities
	(In thousands)
Fair value of commodity derivatives — gross presentation	$	453		$	2,709
Effects of netting arrangements	(453		)	(453		)
Fair value of commodity derivatives — net presentation	$	—		$	2,256

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	December 31, 2015
	Assets		Liabilities
	(In thousands)
Fair value of commodity derivatives — gross presentation	$	—	$	—
Effects of netting arrangements	—		—
Fair value of commodity derivatives — net presentation	$	—	$	—

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

Effect of Commodity Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Loss



	Amount of Gain or (Loss) Recognized in Earnings
	Three Months Ended
	March 31,
Location of Gain or (Loss) Recognized in Earnings	2016		2015
	(In thousands)
Commodity derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain on commodity derivatives	$	626	$	4,632
Total	$	626	$	4,632


9.	Fair Value of Financial Instruments

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

Fair Value Measurements

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

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


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


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


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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The financial assets and liabilities measured on a recurring basis at March 31, 2016 and December 31, 2015 were commodity derivatives and common stock warrants.

Common stock warrant liabilities are measured at fair value on a recurring basis until the underlying common stock warrants are exercised (see Note 3). We measure the fair value of the common stock warrant liabilities using the Black-Scholes method (Level 2 inputs). Inputs used to determine fair value under this method include the Company’s stock price volatility and expected remaining life.

The fair value of all commodity derivative contracts and common stock warrants are reflected on the consolidated balance sheet as detailed in the following schedule:



	March 31, 2016		December 31, 2015

	Significant Other
	Observable Inputs
Description	(Level 2)
	(In thousands)
Assets:
Fair value of commodity derivatives	$	—	$	—
Total assets	$	—	$	—
Liabilities:
Fair value of commodity derivatives	$	2,256	$	—
Fair value of common stock warrants	10,458		—
Total liabilities	$	12,714	$	—

Fair Value of Other Financial Instruments

We estimate the fair value of the 2019 Senior Notes using quoted market prices. The carrying value of our Second Lien Term Loan as of March 31, 2016 approximates the fair value based upon the limited passage of time since being issued on March 15, 2016. Fair value is compared to the carrying value in the table below:



	Fair Value	March 31, 2016				December 31, 2015
	Hierarchy	Carrying		Estimated		Carrying		Estimated
Description	Level	Amount		Fair Value		Amount		Fair Value
		(In thousands)
7.75% Senior Notes due 2019	1	$	592,942	$	300,000	$	592,410	$	462,750
Second Lien Term Loan, due March 2021	3	$	322,436	$	322,436	$	—	$	—


10.	Income Taxes

Our effective federal and state income tax rate for the three months ended March 31, 2016 of 35.1% 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.

CWEI and its subsidiaries file federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for fiscal years after 2012 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


11.	Other Operating Revenues and Expenses

Other operating revenues and expenses for the three months ended March 31, 2016 and March 31, 2015 are as follows:



	Three Months Ended
	March 31,
	2016		2015

	(In thousands)
Other operating revenues:
Gain on sales of assets	$	201	$	3,915
Marketing revenue	—		23
Total other operating revenues	$	201	$	3,938
Other operating expenses:
Loss on sales of assets	$	492	$	61
Marketing expense	242		783
Impairment of inventory	417		—
Total other operating expenses	$	1,151	$	844

During the three months ended March 31, 2015, gain on sales of assets included the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015 (see Note 4).

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


12.	Investment in Dalea Investment Group, LLC

In June 2012, we cancelled an $11 million note receivable in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC (“Dalea”), an international oilfield services company formed in March 2012. Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea was carried at the lower of its initial cost of $11 million and its estimated fair value based on a qualitative assessment. As of March 31, 2016, we fully impaired our investment in Dalea compared to an $8.4 million investment at December 31, 2015. We categorize the measurement of fair value of this investment as a Level 3 input.


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, 2016 and December 31, 2015.



	March 31, 2016			December 31, 2015

	(In thousands)
Proved properties	$	2,549,870		$	2,539,480
Unproved properties	45,834			46,022
Total capitalized costs	2,595,704			2,585,502
Accumulated depletion	(1,497,533		)	(1,460,404		)
Net capitalized costs	$	1,098,171		$	1,125,098

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. Commitments and Contingencies

Legal Proceedings

SWR is a defendant in a suit filed in April 2011 in the Circuit Court of Union County, Arkansas where the plaintiffs initially sought in excess of $8 million for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $0.8 million, of which SWR would pay $0.7 million. To accomplish the settlement, the case was converted to a class action, and each member of the class was offered the right to either participate or opt out of the class and continue a separate action for damages. One plaintiff opted out and will be subject to all previous rulings of the court, including an order dismissing certain claims on the basis that such claims were time barred. A loss on settlement of $0.7 million was recorded for the year ended December 31, 2013 in connection with this proposed settlement. The settlement was entered by the Court on December 19, 2014, and all settlement funds were paid to plaintiffs’ counsel in January 2015. The case by the single remaining plaintiff continues.

In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under our farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”). Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. In October 2013, a judge ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million. A loss of $1.4 million was recorded for the year ended December 31, 2013 in connection with the judgment. CWEI appealed the judgment and on July 8, 2015, the El Paso Court of Appeals reversed the trial court judgment in its entirety and rendered judgment that Plaintiffs take nothing on all claims against CWEI and Chesapeake. Plaintiffs have appealed the decision of the Court of Appeals to the Texas Supreme Court.

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

In July 2013, the SELFPA case was filed in Orleans Parish and alleged that dredging and other oilfield operations of the 95 oil and gas company defendants caused degradation and destruction of the coastal marshlands which serve as a buffer protecting the coastal area of Louisiana from storms. The case was removed to Federal District Court. Legislation was enacted in Louisiana in 2014 in response to the suit which would effectively eliminate the claims, but in late 2014 the Louisiana state court judge declared the new law unconstitutional. A motion to dismiss the claims was granted in Federal District Court and the plaintiff has appealed to the United States Fifth Circuit Court of Appeals. Oral argument was heard on February 29, 2016. The Court has not yet ruled.

In November 2013, we were served with two separate suits filed by Plaquemines Parish in the 25th Judicial District Court of Plaquemines Parish, Louisiana (Designated Case Nos. 61-002 and 60-982). Multiple defendants are named in each suit, and each suit involves a different area of operation within Plaquemines Parish. Except as to the named defendants and areas of operation, the suits are identical. Plaintiff alleges that defendants’ oil and gas operations violated certain laws relating to the coastal zone management including failure to obtain permits, violation of permits, use of unlined waste pits, discharge of oil field wastes, including naturally occurring radioactive material, and that dredging operations exceeded unspecified permit limitations. Plaintiff makes no specific allegations against any individual defendant and seeks unspecified monetary damages and declaratory relief, as well as restoration, costs of remediation and attorney fees. The cases were removed to the U.S. District Court for the Eastern District of Louisiana but were remanded back to the state court in 2015. In November 2015, the Plaquemines Parish Council passed Resolution 15-389 requiring its attorneys to cease all work on the cases other than to dismiss all actions and lawsuits, but in April of 2016 the Parish voted to rescind such resolution. The State of Louisiana Department of Natural Resources, Office of Coastal Management has intervened in these cases and the Louisiana Attorney General has filed to supersede the Parish as Plaintiff.

Our overall exposure to these suits is not currently determinable and we intend to vigorously defend these cases. We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these lawsuits 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: (1) discounted cash flow method; (2) flowing daily production method; and (3) proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances. We utilize all three methods when that information is available, or if not will utilize the discounted cash flow method. We recorded provisions for impairment of proved properties of $2.3 million for the three months ended March 31, 2016 and $2.5 million for the three months ended March 31, 2015. The provision for the three months ended March 31, 2016 of $2.3 million related primarily to the write-down of certain non-core properties located in Oklahoma and the Permian Basin to their estimated fair value. The provision for the three months ended March 31, 2015 of $2.5 million related to the write-down of certain non-core properties located in Louisiana 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 $0.2 million for the three months ended March 31, 2016 and $0.2 million for the three months ended March 31, 2015, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive 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, 2016 and 2015:



For the Three Months Ended
March 31, 2016
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	30,250		$	64		$	—		$	30,314
Depreciation, depletion and amortization ^(a)	37,780			3,180			—			40,960
Other operating expenses ^(b)	24,600			1,331			—			25,931
Interest expense	17,087			—			—			17,087
Other (income) expense ^(c)	(7,791		)	8,431			—			640
Income (loss) before income taxes	(41,426		)	(12,878		)	—			(54,304		)
Income tax (expense) benefit	14,536			4,507			—			19,043
Net income (loss)	$	(26,890	)	$	(8,371	)	$	—		$	(35,261	)
Total assets	$	1,422,199		$	40,038		$	(46,397	)	$	1,415,840
Additions to property and equipment	$	11,906		$	17		$	—		$	11,923



For the Three Months Ended
March 31, 2015
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	64,080		$	680		$	(618	)	$	64,142
Depreciation, depletion and amortization ^(a)	42,076			3,204			(95		)	45,185
Other operating expenses ^(b)	37,201			2,788			(850		)	39,139
Interest expense	13,277			—			—			13,277
Other (income) expense ^(c)	(6,247		)	922			—			(5,325		)
Income (loss) before income taxes	(22,227		)	(6,234		)	327			(28,134		)
Income tax (expense) benefit	7,720			2,182			—			9,902
Net income (loss)	$	(14,507	)	$	(4,052	)	$	327		$	(18,232	)
Total assets	$	1,449,345		$	61,272		$	(42,459	)	$	1,468,158
Additions to property and equipment	$	54,511		$	636		$	327		$	55,474

_______


(a)	Includes impairment of property and equipment.


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


(c)	Includes impairment of our investment in Dalea.

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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 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, 2016 (Unaudited) (Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Current assets	$	285,284	$	265,797	$	649		$	(313,563	)	$	238,167
Property and equipment, net	875,616		291,315		3,502			—			1,170,433
Investments in subsidiaries	308,446		—		—			(308,446		)	—
Other assets	5,102		2,138		—			—			7,240
Total assets	$	1,474,448	$	559,250	$	4,151		$	(622,009	)	$	1,415,840
Current liabilities	$	276,501	$	96,669	$	144		$	(307,742	)	$	65,572
Non-current liabilities:
Long-term debt	915,378		—		—			—			915,378
Fair value of commodity derivatives	2,256		—		—			(2,223		)	33
Fair value of common stock warrants	10,458		—		—			—			10,458
Deferred income taxes	78,070		123,118		(2,192		)	(109,416		)	89,580
Other	33,266		36,964		252			—			70,482
	1,039,428		160,082		(1,940		)	(111,639		)	1,085,931
Equity	158,519		302,499		5,947			(202,628		)	264,337
Total liabilities and equity	$	1,474,448	$	559,250	$	4,151		$	(622,009	)	$	1,415,840

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet December 31, 2015 (Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Current assets	$	112,861	$	272,310	$	1,441		$	(317,807	)	$	68,805
Property and equipment, net	892,791		304,936		3,557			—			1,201,284
Investments in subsidiaries	324,484		—		—			(324,484		)	—
Other assets	6,681		10,650		—			—			17,331
Total assets	$	1,336,817	$	587,896	$	4,998		$	(642,291	)	$	1,287,420
Current liabilities	$	276,354	$	102,267	$	117		$	(312,999	)	$	65,739
Non-current liabilities:
Long-term debt	742,410		—		—			—			742,410
Deferred income taxes	90,387		130,471		(1,236		)	(110,626		)	108,996
Other	33,886		36,539		252			—			70,677
	866,683		167,010		(984		)	(110,626		)	922,083
Equity	193,780		318,619		5,865			(218,666		)	299,598
Total liabilities and equity	$	1,336,817	$	587,896	$	4,998		$	(642,291	)	$	1,287,420

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended March 31, 2016 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Total revenue	$	20,237		$	9,873		$	204		$	—	$	30,314
Costs and expenses	41,700			24,886			305			—		66,891
Operating income (loss)	(21,463		)	(15,013		)	(101		)	—		(36,577		)
Other income (expense)	(9,705		)	(8,249		)	227			—		(17,727		)
Equity in earnings of subsidiaries	(15,038		)	—			—			15,038		—
Income tax (expense) benefit	10,945			8,142			(44		)	—		19,043
Net income (loss)	$	(35,261	)	$	(15,120	)	$	82		$	15,038	$	(35,261	)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Three Months Ended March 31, 2015 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Total revenue	$	45,688		$	18,042		$	412		$	—	$	64,142
Costs and expenses	61,021			22,675			628			—		84,324
Operating income (loss)	(15,333		)	(4,633		)	(216		)	—		(20,182		)
Other income (expense)	(8,105		)	(743		)	896			—		(7,952		)
Equity in earnings of subsidiaries	(3,052		)	—			—			3,052		—
Income tax (expense) benefit	8,258			1,882			(238		)	—		9,902
Net income (loss)	$	(18,232	)	$	(3,494	)	$	442		$	3,052	$	(18,232	)

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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, 2016 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Operating activities	$	10,344		$	(9,074	)	$	(748	)	$	—	$	522
Investing activities	(13,579		)	1,118			(47		)	—		(12,508		)
Financing activities	180,067			8,990			40			—		189,097
Net increase (decrease) in cash and cash equivalents	176,832			1,034			(755		)	—		177,111
Cash at beginning of period	4,663			1,855			1,262			—		7,780
Cash at end of period	$	181,495		$	2,889		$	507		$	—	$	184,891

Condensed Consolidating Statement of Cash Flows Three Months Ended March 31, 2015 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Operating activities	$	23,173		$	(4,260	)	$	1,076		$	95		$	20,084
Investing activities	(82,419		)	116			(171		)	(95		)	(82,569		)
Financing activities	40,338			1,915			(253		)	—			42,000
Net increase (decrease) in cash and cash equivalents	(18,908		)	(2,229		)	652			—			(20,485		)
Cash at beginning of period	21,217			6,693			106			—			28,016
Cash at end of period	$	2,309		$	4,464		$	758		$	—		$	7,531


18.	Subsequent Events

We have evaluated events and transactions that occurred after the balance sheet date of March 31, 2016 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, 2015. 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. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those described in (1)“Item 1A - Risk Factors” and other cautionary statements in our Form 10-K for the year ended December 31, 2015, (2) our reports and registration statements filed from time to time with the Securities and Exchange Commission (the “SEC”), (3) other announcements we make from time to time 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, including any strategic alternatives to enhance shareholder value;


•	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, including continued low or furthering declining prices for oil and gas;

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•	the potential need to sell assets or otherwise raise additional capital;


•	the need to take impairments due to lower commodity prices;


•	domestic and worldwide economic conditions;


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


•	our level of indebtedness (including the ability to service such indebtedness), liquidity and compliance with debt covenants;


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


•	declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under the 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, 2015 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, 2015 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 forward-looking statements or 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 have been committed to drilling primarily developmental oil wells in two primary oil-prone regions, the Permian Basin and the Giddings Area, where we have a significant inventory of developmental drilling opportunities. During the three months ended March 31, 2016, we spent $11.9 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 2016 and the outlook for the remainder of 2016.

•

Oil and gas sales for the first quarter of 2016, excluding amortized deferred revenues, decreased $28.2 million, or 50%, from the first quarter of 2015. Price variances accounted for a $15.9 million decrease and production variances accounted for a $12.3 million decrease. Average realized oil prices were $28.10 per barrel in the first quarter of 2016 versus $43.90 per barrel in the first quarter of 2015, average realized gas prices were $1.74 per Mcf in the first quarter of 2016 versus $2.65 per Mcf in the first quarter of 2015 and average realized natural gas liquids (“NGL”) prices were $8.91 per barrel in the first quarter of 2016 versus $13.01 per barrel in the first quarter of 2015. Amortized deferred revenue in the first quarter of 2016 totaled $0.2 million as compared to $1.8 million in the first quarter of 2015.

•

Oil, gas and NGL production per barrel of oil equivalent (“BOE”) decreased 21% in the first quarter of 2016 compared to the first quarter of 2015, with oil production decreasing 25% to 9,868 barrels per day, gas production decreasing 9% to 14,242 Mcf per day and NGL production decreasing 6% to 1,396 barrels per day. Oil and NGL production accounted for approximately 83% of our total BOE production in the first quarter of 2016 versus 85% in the first quarter of 2015.

After giving effect to the sale of selected leases and wells in South Louisiana in September 2015, oil, gas and NGL production per BOE decreased 19% in the first quarter of 2016 as compared to the first quarter of 2015.


•	Production costs decreased $6.3 million, or 27%, for the first quarter of 2016 compared to the first quarter of 2015 due to lower oilfield service costs and reductions in production taxes associated with lower oil and gas sales. Production costs on a BOE basis, excluding production taxes, averaged $12.97 per BOE in the first quarter of 2016 versus $13.26 per BOE in the first quarter of 2015.

•

Interest expense for the first quarter of 2016 was $17.1 million versus $13.3 million for the first quarter of 2015. The increase was due primarily to incremental interest expense on funded indebtedness under our second lien term loan credit facility issued in connection with our March 2016 refinancing transaction (the “Refinancing”) and to the write-off of debt issuance costs associated with a reduction in aggregate lender commitments under our revolving credit facility.

•

In connection with the Refinancing, we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share for cash consideration of $16.8 million. The warrants expire in 2026 and contain various anti-dilution provisions. We account for the warrants as derivative instruments and carry the warrants as a non-current liability at their fair value. We recorded a $6.3 million gain on change in fair value in the first quarter of 2016.

•

We recorded a $0.6 million gain on commodity derivatives in the first quarter of 2016 (including a $2.9 million gain on settled contracts). For the same period in 2015, we recorded a $4.6 million gain on commodity derivatives (no gain or loss on settled contracts). Since we do not presently designate our commodity 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.

•

Lower commodity prices negatively impacted our results of operations due to asset impairments. We recorded a provision for impairment of property and equipment of $2.3 million related to the write-down of certain non-core properties located primarily in Oklahoma and the Permian Basin to their estimated fair value versus $2.5 million in the first quarter of 2015 related to the write-down of certain non-core properties located in Louisiana to their estimated fair value.


•	We recorded an $8.4 million charge to fully impair the carrying value of our investment in Dalea Investment Group, LLC (“Dalea”) in the first quarter of 2016, as compared to a partial impairment of this investment of $0.9 million for the same period in 2015.


•	General and administrative (“G&A”) expenses were $3.9 million in the first quarter of 2016 compared to $9.1 million in the first quarter of 2015. Changes in compensation expense attributable to our APO Reward Plans accounted for a net

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decrease of $2.9 million ($0.8 million credit in the first quarter of 2016 versus a $2.1 million expense in the first quarter of 2015). The remaining decrease was largely attributable to salary and personnel reductions.

Exploration and Development Activities

Overview

We spent $11.9 million during the first quarter of 2016 on exploration and development activities in the Permian Basin and the Giddings Area and currently plan to spend approximately $69.5 million during 2016. Our actual expenditures during 2016 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Factors such as changes in commodity prices, operating margins, the availability of capital resources, drilling results and other factors could increase or decrease our actual expenditures during 2016.

Areas of Operations

Permian Basin

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

We spent $2 million in the Permian Basin during the three months ended March 31, 2016 on drilling and completion activities and $4.4 million on leasing and seismic activities. We currently plan to spend approximately $42.9 million on drilling and completion activities and $11.9 million on leasing activities in this area during 2016. Following is a discussion of our principal assets in the Permian Basin.

Delaware Basin

We currently hold approximately 66,000 net acres in the active Wolfbone resource play in the Delaware Basin, primarily in Reeves County, Texas. The Wolfbone resource play generally refers to the interval from the Bone Springs formation down through the Wolfcamp formation at depths typically found between 8,000 and 13,000 feet. A Wolfbone well generally refers to a vertical well completed in multiple intervals within these formations or a horizontal well being completed in an interval within such formations. These Permian aged formations in the Delaware Basin are composed of limestone, sandstone and shale. Geology in the Delaware Basin consists of multiple stacked pay zones with both over-pressured and normal-pressured intervals.

We entered the Delaware Basin as a vertical play, but with encouraging results from our horizontal drilling, we shifted our emphasis to a horizontal program. Most of our horizontal drilling to date has targeted the Wolfcamp A shale interval in Reeves County, Texas with 25 Wolfcamp A wells currently on production. We also have four Wolfcamp C wells currently on production.

We spent approximately $2 million on drilling and completion activities and $4.4 million for leasing activities in the Wolfbone play during the three months ended March 31, 2016. We plan to spend approximately $54.8 million on drilling, completion and leasing activities in this area during 2016.

We own oil, natural gas and water disposal pipelines in Reeves County, Texas consisting of 105 miles of oil pipelines with current capacity of 10,000 barrels of oil per day (expandable to 25,000 barrels of oil per day), 109 miles of natural gas pipelines with a current capacity of 10,000 Mcf of natural gas per day (expandable to 25,000 Mcf of natural gas per day) and 109 miles of salt water disposal pipelines with a current capacity of 15,000 barrels of produced water per day (expandable to 36,000 barrels of produced water per day).

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Other Permian Basin

Approximately 36% of our first quarter 2016 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

Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas. Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale and Taylor formations. We have approximately 170,000 net acres in the Giddings Area. Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

Approximately 51% of our existing production in the Giddings Area is derived from the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana. The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet. Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity. Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas.

Eagle Ford Shale

Our horizontal Eagle Ford Shale play is concentrated in the northern portion of our legacy Austin Chalk acreage block in Robertson, Burleson and Lee Counties, Texas. In this area, we currently have 41 horizontal Eagle Ford Shale wells on production. During the three months ended March 31, 2016, we spent approximately $4.2 million on drilling, completion and leasing activities in the Eagle Ford Shale Area, and we currently plan to spend approximately $12.1 million on drilling, completion and leasing activities in this area during 2016.

Other

We spent $1.3 million during the three months ended March 31, 2016 on exploration and development activities in other regions, including Oklahoma and California and we currently plan to spend $2.6 million during 2016.

Pipelines and Other Midstream Facilities

We own interests in and operate oil, natural gas and water service facilities in the state of Texas. These midstream facilities consist of interests in approximately 393 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 and third party producers.

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we currently have 10 drilling rigs available for our use or for contract drilling operations, of which eight are owned and two are under lease until October 2016. Owning and operating our own rigs helps control our cost structure while providing 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. Due to the downturn in oil prices, all our rigs are currently idle.

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Known Trends and Uncertainties

Our business is subject to various trends and uncertainties, the most significant of which are related to commodity prices. The severe downturn in oil prices that began late in 2014 significantly reduced our cash flow from operations, causing us to suspend drilling operations in both of our core resource plays early in 2015 in order to preserve liquidity. Management quickly took decisive steps to reduce costs in an attempt to improve margins, but the combination of declining production attributable to suspended drilling activities and the impact of substantially lower oil and natural gas prices on cash flow will continue to have an adverse effect on our business if the downturn is prolonged.

Further significant and prolonged declines in prices could impact our ability to service our debt obligations and will further constrain our ability to use cash flows to drill, replace or increase our production and reserves.

To mitigate the impact of further deterioration in prices, we entered into swaps covering 1,597 MBbls of our oil production for the period from January 2016 through June 2017 at prices ranging from $40.25 to $44.30 per barrel. In addition, we granted an option on an additional 739 MBbls of oil production from July 2016 through December 2016 at $40.25 per barrel exercisable by the counterparty on June 30, 2016. In April 2016, we entered into crude oil costless collars covering 1,128 MBbls of our oil production for the period from January 2017 through December 2017 at a weighted average floor price of $41.57 and a weighted average ceiling price of $50.81.

The prolonged effects of lower oil prices, declining production and lower proved reserves may have an adverse effect on our ability to access the capital resources we need to grow our reserve base. See “ — Liquidity and Capital Resources” for a discussion of our current liquidity status and availability of capital, including the impact of the Refinancing. If we continue limited drilling activities for a significant period of time, or if our future access to capital resources is limited, we will likely further delay our development of our proved undeveloped reserves or ultimately suspend such development, which could result in further reductions in undeveloped reserves.

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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,
	2016		2015
Oil and Gas Production Data:
Oil (MBbls)	898		1,179
Gas (MMcf)	1,296		1,406
Natural gas liquids (MBbls)	127		134
Total (MBOE)^(a)	1,241		1,547
Total (BOE/d)	13,638		17,193

Average Realized Prices ^{(b) (c)}:
Oil ($/Bbl)	$	28.10	$	43.90
Gas ($/Mcf)	$	1.74	$	2.65
Natural gas liquids ($/Bbl)	$	8.91	$	13.01

Gain on Settled Commodity Derivative Contracts ^(c):
($ in thousands, except per unit)
Oil: Cash settlements received (paid)	$	2,882	$	—
Per unit produced ($/Bbl)	$	3.21	$	—

Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	2,938		3,780
Other	3,071		3,117
Austin Chalk	1,773		1,918
Eagle Ford Shale	1,987		3,949
Other ^(d)	99		336
Total	9,868		13,100
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	2,571		3,039
Other	6,663		6,803
Austin Chalk	1,686		1,716
Eagle Ford Shale	411		604
Other ^(d)	2,911		3,460
Total	14,242		15,622
(Continued)

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	Three Months Ended March 31,
	2016		2015
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	381		393
Other	744		765
Austin Chalk	170		167
Eagle Ford Shale	85		139
Other ^(d)	16		25
Total	1,396		1,489

BOE:
Permian Basin Area:
Delaware Basin	3,748		4,679
Other	4,925		5,016
Austin Chalk	2,224		2,371
Eagle Ford Shale	2,141		4,189
Other ^(d)	600		938
Total	13,638		17,193

Exploration Costs (in thousands):
Abandonment and impairment costs:
Oklahoma	$	801	$	90
California	188		110
South Louisiana	—		1,423
Other	1		—
Total	990		1,623
Seismic and other	111		866
Total exploration costs	$	1,101	$	2,489

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	34,784	$	38,883
Contract drilling depreciation	3,180		3,109
Other depreciation	649		662
Total depreciation, depletion and amortization	$	38,613	$	42,654

Oil and Gas Costs ($/BOE Produced):
Production costs	$	13.82	$	15.15
Production costs (excluding production taxes)	$	12.97	$	13.26
Oil and gas depletion	$	28.03	$	25.13
(Continued)

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	Three Months Ended March 31,
	2016	2015
Net Wells Drilled ^(e):
Exploratory Wells	1.7	0.6
Developmental Wells	0.1	10.5

_______


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

(b)

Oil and gas sales includes $0.2 million for three months ended March 31, 2016 and $1.8 million for the three months ended March 31, 2015 of amortized deferred revenue attributable to a VPP transaction effective March 1, 2012. In August 2015, we terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million. The calculation of average realized sales prices excludes production of 23,151 barrels of oil and 16,087 Mcf of gas for the three months ended March 31, 2015 associated with the VPP.


(c)	No commodity derivatives were designated as cash flow hedges in the table above. All gains or losses on settled commodity derivatives were included in other income (expense) - gain (loss) on commodity derivatives.


(d)	Following is a summary of the average daily production related to interests in producing properties we sold effective September 2015 (selected leases and wells in South Louisiana).



	Three Months Ended March 31,
	2016	2015
Average Daily Production:

South Louisiana:
Oil (Bbls)	—	178
Natural gas (Mcf)	—	1,633
NGL (Bbls)	—	—
Total (BOE)	—	450


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

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Operating Results — Three-Month Periods

The following discussion compares our results for the three months ended March 31, 2016 to the comparative period in 2015. Unless otherwise indicated, references to 2016 and 2015 within this section refer to the three months ended March 31, 2016 and 2015, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $28.2 million, or 50%, in 2016 from 2015. Price variances accounted for a $15.9 million decrease and production variances accounted for a $12.3 million decrease. Amortized deferred revenue in 2016 totaled $0.2 million as compared to $1.8 million in 2015. Oil, gas and NGL production in 2016 (on a BOE basis) decreased 21% compared to 2015. Oil production decreased 25% in 2016 from 2015, NGL production decreased 6% and gas production decreased 9% in 2016 from 2015. After giving effect to the sale of selected leases and wells in South Louisiana in September 2015, oil, gas and NGL production per BOE decreased 19% in 2016 as compared to 2015. The liquids component of our production mix accounted for approximately 83% oil and NGL in 2016 versus 85% in 2015. In 2016, our realized oil price decreased 36% compared to 2015, and our realized gas price decreased 34%. 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 27% to $17.2 million in 2016 as compared to $23.4 million in 2015, due primarily to lower oilfield service costs and reductions in production taxes associated with a decrease in oil and gas sales. Production costs on a BOE basis, excluding production taxes, averaged $12.97 per BOE in 2016 compared to $13.26 per BOE in 2015.

Oil and gas depletion expense decreased $4.1 million from 2015 to 2016 due to a $7.7 million decrease related to production variances and a $3.6 million increase due to rate variances. On a BOE basis, depletion expense increased 12% to $28.03 per BOE in 2016 from $25.13 per BOE in 2015. 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 $2.3 million during 2016 as compared to $2.5 million in 2015. The 2016 impairment related primarily to proved non-core properties located in Oklahoma and the Permian Basin to reduce the carrying value to their estimated fair value. The 2015 impairment related to proved non-core properties located in Louisiana to reduce the carrying value to their estimated fair value. Assuming that commodity prices continue to decline, we may incur further asset impairments in 2016. Although it is difficult to provide an estimate because of the numerous variables and management input decisions required to evaluate the amount of any asset impairments, they could be significant.

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 2016, we charged to expense $1.1 million of exploration costs, as compared to $2.5 million in 2015. The expense for 2016 includes a charge of $0.8 million related to the abandonment of exploratory wells in Oklahoma. The expense for 2015 includes a charge of $1.4 million related to the abandonment of an exploratory well in South Louisiana.

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 loss. Drilling rig services revenue related to external customers was negligible in 2016 and 2015 due to decreased demand for contract drilling services. Drilling services costs, net of eliminations, were $1.3 million in 2016 compared to $1.9 million in 2015. Contract drilling depreciation for 2016 was $3.2 million compared to $3.1 million in 2015.

General and Administrative

G&A expenses decreased $5.2 million from $9.1 million in 2015 to $3.9 million in 2016. Changes in compensation expense attributable to the Company’s APO reward plans accounted for a net decrease of $2.9 million ($0.8 million credit in 2016 versus a $2.1 million expense in 2015). The remaining decrease was largely attributable to salary and personnel reductions.

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Interest expense

Interest expense increased 29% from $13.3 million in 2015 to $17.1 million in 2016 due primarily to incremental interest expense on funded indebtedness incurred under a second lien term loan credit facility issued in connection with the Refinancing and to the write-off of debt issuance costs associated with a reduction in aggregate lender commitments under our revolving credit facility.

Gain/loss on change in fair value of common stock warrants

Gain/loss on commodity derivatives

We did not designate any commodity derivative contracts in 2016 or 2015 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on commodity derivatives. In 2016, we reported a $0.6 million gain on commodity derivatives (including a $2.9 million gain on settled contracts) compared to a $4.6 million gain on commodity derivatives (no gain or loss on settled contracts) in 2015. Because oil and gas prices are volatile, and because we do not account for our commodity derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on commodity derivatives can cause significant volatility in our results of operations.

Impairment of investments and other

We recorded an $8.4 million charge to fully impair the carrying value of our investment in Dalea in 2016, as compared to a partial impairment of $0.9 million in 2015.

Gain/loss on sales of assets and impairment of inventory

We recorded a net loss of $0.7 million on sales of assets and impairment of inventory in 2016 compared to a net gain of $3.1 million in 2015. The 2016 loss related primarily to a $0.4 million write-down of inventory to reduce the carrying value to the estimated fair value. The 2015 gain related primarily to the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015. 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 loss.

Income taxes

Our estimated federal and state effective income tax rate in 2016 of 35.1% was more 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 substantially all of our producing oil and gas properties to secure our obligations under the revolving credit facility and the term loan credit facility (see “ — Outlook for 2016” and “ — Term loan credit facility”). The banks under the revolving credit facility establish a borrowing base, in part, by making an estimate of the collateral value of our oil and gas properties. We believe the term loans have provided us with a source of dedicated liquidity; however, we intend to borrow funds under the revolving credit facility as needed in the future 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 under the revolving credit facility may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. However, we may mitigate the effects of product prices on our cash flow and borrowing base through the use of commodity derivatives.

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At March 31, 2016, we had $98.1 million available on the revolving credit facility after allowing for outstanding letters of credit totaling $1.9 million, as compared to $347.1 million of availability on the facility at March 31, 2015. Following the Refinancing, our indebtedness at March 31, 2016 was $915.4 million, consisting of $322.5 million, net of original issue discount and debt issuance costs, under the second lien term loan credit facility and $592.9 million in outstanding principal amount of the 7.75% Senior Notes due 2019 (the “2019 Senior Notes”), net of original issue discount and debt issuance costs. The Refinancing also added approximately $180 million of cash to the balance sheet.

Outlook for 2016

The severe downturn in oil prices that began in 2014 significantly reduced our cash flow from operations, causing us to suspend drilling operations in both of our core resource plays early in 2015 in order to preserve liquidity. Management quickly took decisive steps to reduce costs in an attempt to improve margins, but the combination of declining production attributable to suspended drilling activities and the impact of substantially lower oil and natural gas prices on cash flow led our senior management and the Board of Directors (“the Board”), beginning in early July 2015, to consider a variety of strategic and financial alternatives for the Company.

In August 2015, the Board formed a special committee comprising all four of our independent and disinterested directors to develop, explore and evaluate strategic alternatives for the Company, including potential transactions involving a business combination, a recapitalization, a sale of assets or securities of the Company, or another extraordinary transaction. Goldman Sachs & Co. (“Goldman”) was engaged to serve as the Company’s exclusive financial advisor in this process. The special committee also engaged independent legal counsel.

With the assistance of senior management, Goldman identified and contacted potential counterparties on a confidential basis to determine their interest in one or more of the strategic alternatives under consideration by the Company. The Company received indications of interest across all of these alternatives. Throughout the review process, the special committee reviewed indications of interest and other information with Goldman, senior management, legal counsel for the Company, and legal counsel for the special committee.

In mid-January 2016, final bids were submitted for various potential transactions, including proposals for secured debt financing. The special committee concluded that a secured debt alternative was favorable to the Company and its stockholders. In reaching this conclusion, the special committee considered, among other factors, that the secured debt alternative (1) avoided a sale of our core assets during a time of declining commodity prices, (2) provided a dedicated source of liquidity to fund our operations and development activities over the next two to three years, (3) limited immediate dilution to existing stockholders and (4) retained the opportunity to ultimately enhance shareholder value if the commodity environment improves. The special committee instructed Goldman to negotiate final proposals with these bidders, and following negotiations, the special committee and the Board unanimously selected the proposal submitted by Ares Management, LLC (“Ares”). On March 8, 2016, we entered into (1) a credit agreement with Ares providing for the issuance of second lien term loans and common stock warrants and (2) an amendment to the revolving credit facility with our banks (see “ — Revolving credit facility” and “ — Term loan credit facility”).

Throughout our review process, oil prices fell dramatically, causing uncertainty and significant volatility in the debt and equity markets. We are continuing to closely monitor the impact of the downturn in commodity prices on our business, including the extent to which lower prices could affect our financial condition and liquidity. While we believe we are taking appropriate actions to preserve our short-term liquidity, the effects of a prolonged cycle of low operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves. These factors have an adverse effect on our ability to access the capital resources we need to grow our reserve base.

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Capital expenditures

The following table summarizes, by area, our actual expenditures for exploration and development activities for the three months ended March 31, 2016 and our planned expenditures for the year ending December 31, 2016.



	Actual Expenditures Three Months Ended March 31, 2016		Planned Expenditures Year Ending December 31, 2016		2016 Percentage of Total Planned Expenditures
	(In thousands)
Drilling and completion
Permian Basin Area:
Delaware Basin	$	2,000	$	42,900	62	%
Austin Chalk/Eagle Ford Shale	1,000		1,700		2	%
Other	800		2,000		3	%
	3,800		46,600		67	%
Leasing and seismic	8,100		22,900		33	%
Exploration and development	$	11,900	$	69,500	100	%

Our expenditures for exploration and development activities for the three months ended March 31, 2016 totaled $11.9 million. We financed these expenditures for the three months ended March 31, 2016 with cash flow from operating activities, proceeds from asset sales, and borrowings under our credit facilities. We currently plan to spend approximately $69.5 million on exploration and development activities during fiscal 2016. Our actual expenditures during 2016 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Factors, such as changes in commodity prices, operating margins, the availability of capital resources, drilling results and other factors, could increase or decrease our actual expenditures during the remainder of fiscal 2016.

Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flows, combined with cash on hand made available by the Refinancing and funds available to us under the revolving credit facility, will be sufficient to finance our planned exploration and development activities at these reduced levels through 2016. Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base under the revolving credit facility may be less than expected, cash flows may be less than expected, or capital expenditures may be more than expected. We will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets if necessary when we deem appropriate. Further significant and prolonged declines in prices could impact our ability to service our debt obligations and will further constrain our ability to use cash flows to drill to replace or increase our production and reserves.

Cash flow provided by operating activities

Substantially all of our cash flow from operating activities is derived from the production of our oil and gas reserves. We use this cash flow to fund our on-going exploration and development activities in search of new oil and gas reserves. Variations in cash flows 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, 2016 decreased $19.6 million, or 97%, as compared to the corresponding period in 2015 due primarily to lower commodity prices and decreased production.

Revolving credit facility

We may borrow money under a revolving credit facility with a syndicate of 16 banks led by JPMorgan Chase Bank, N.A. On March 8, 2016, we entered into an amendment to the revolving credit facility in connection with the Refinancing (see “ —Term loan credit facility”). The amendment, among other things, reduced the borrowing base and the aggregate commitments of the lenders from $450 million to $100 million. The aggregate commitments may be increased to $150 million if we meet a minimum ratio of the discounted present value of our proved developed producing reserves to our debt under the revolving credit facility of 1.2 to 1.0. Increases in aggregate lender commitments require the consent of each lender.

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applicable margin between 2.5% and 3.5% per year or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.5% and 2.5% per year. We are also required to pay a commitment fee on the unused portion of the commitments under the revolving credit facility of 0.5% per year. The applicable margin is determined based on the utilization of the borrowing base. Interest and fees are payable quarterly, except that interest on LIBOR-based tranches is due at maturity of each tranche but no less frequently than quarterly.

The 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. The March 2016 amendment replaced a requirement that we maintain certain ratios of consolidated funded indebtedness to consolidated EBITDAX with a less restrictive ratio of debt outstanding solely under the revolving credit facility to consolidated EBITDAX of 2.0 to 1.0.

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 semiannually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency, (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).

At March 31, 2016, we had $98.1 million available under the revolving credit facility after allowing for outstanding letters of credit totaling $1.9 million. The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the three months ended March 31, 2016 was 2.5%. We were in compliance with all financial and non-financial covenants at March 31, 2016 and December 31, 2015. Under current commodities pricing, we expect that we will be in compliance with all financial covenants through 2016. Further deterioration in commodities pricing, however, could result in non-compliance and cause us to seek to negotiate revisions to our loan covenants, which relief may not be obtainable from our bank lenders.

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 revolving credit facility, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of commodity derivatives. Our GAAP reported working capital increased to $172.6 million at March 31, 2016 from working capital of $3.1 million at December 31, 2015. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $272.9 million at March 31, 2016, as compared to $301.2 million at December 31, 2015.

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The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at March 31, 2016 and December 31, 2015.



	March 31, 2016		December 31, 2015

	(In thousands)
Working capital per GAAP	$	172,595	$	3,066
Add funds available under our revolving credit facility	98,130		298,130
Exclude fair value of commodity derivatives classified as current assets or current liabilities	2,223		—
Working capital per loan covenant	$	272,948	$	301,196

As a condition to borrowing funds or issuing letters of credit under our revolving credit facility, we must remain in compliance with the financial and non-financial covenants, including financial ratios, in our revolving credit facility, as amended to date. We also must make certain representations and warranties to our bank lenders at the time of each borrowing. We were in compliance with all financial and non-financial covenants at March 31, 2016 and December 31, 2015. However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend the revolving credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means. Although we believe our bank lenders are well secured under the terms of our revolving credit facility, there is no assurance that the bank lenders will waive or amend our covenants or other conditions to further lending. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

The lending group under the credit facility includes the following institutions: JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., MUFG Union Bank, N.A., Compass Bank, Frost Bank, Toronto Dominion (Texas) LLC, KeyBank National Association, Natixis, New York Branch, UBS AG, Stamford Branch, Fifth Third Bank, U.S. Bank National Association, Whitney Bank, Bank of America, N.A., Branch Banking and Trust Company, Capital One, National Association and PNC Bank, National Association.

From time to time, we engage in other transactions with lenders under the revolving credit facility. Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of March 2016, JPMorgan Chase Bank, N.A. was the counterparty to our commodity derivative agreements. Our obligations under commodity derivative agreements with our lenders are secured by the security documents executed by the parties under the revolving credit facility.

Term loan credit facility

On March 8, 2016, we entered into (1) a credit agreement with Ares providing for the issuance of second lien term loans and common stock warrants and (2) an amendment to the revolving credit facility with our banks. Upon closing of the Refinancing on March 15, 2016, we issued term loans to Ares in the principal amount of $350 million, net of original issue discount of $16.8 million, for cash proceeds of $333.2 million. Concurrently, we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share to Ares for cash proceeds equal to the original issue discount from the issuance on the term loans. The warrants represent the right to acquire approximately 18.5% of our currently outstanding shares of common stock, or approximately 15.6% of our common shares on a fully exercised basis. In connection with the issuance of the warrants, we designated and issued to the initial warrant holders 3,500 shares of special voting preferred stock, $0.10 par value per share, granting them certain rights to elect two members of our Board. Aggregate cash proceeds from the transaction of approximately $340 million, net of transaction costs, were used to fully repay the outstanding indebtedness under the revolving credit facility of $160 million, plus accrued interest and fees, and added approximately $180 million of cash to our balance sheet to provide additional liquidity to fund our operations and future development.

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The term loan credit facility also contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain an asset-to-secured debt coverage ratio as of each December 31 and June 30 of each year, beginning with December 31, 2018, of at least 1.2 to 1.0. We were in compliance with these covenants at March 31, 2016. Under current commodities pricing, we expect that we will be in compliance with all financial covenants through 2016. Further deterioration in commodities pricing, however, could result in non-compliance and cause us to seek to negotiate revisions to our loan covenants, which relief may not be obtainable from our bank lenders.

Senior Notes

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

Asset Sales

From time to time, we sell certain of our proved and unproved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them. During the first three months of 2016, we received cash proceeds aggregating $1.4 million from various sales of assets. We are actively considering other selected sales as a source of additional funds to supplement cash flow from operations and borrowings under the credit facility to meet our capital needs.

Alternative capital resources

We believe we currently have adequate liquidity to enable us to fund our expected capital expenditures for 2016 through a combination of (1) cash on hand made available by the Refinancing, (2) cash flow from operations, and (3) borrowings under the revolving credit facility.

Subject to any restrictions in the revolving credit facility and the term loan credit facility, we may also use other capital resources, including (1) entering into joint venture participation agreements with other industry or financial partners in our core

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development areas, (2) monetizing all or a portion of our core or non-core assets and (3) issuing additional debt or equity securities in private or public offerings, in order to finance a portion of our capital spending in fiscal 2016 and subsequent periods. While we believe we would be able to obtain funds through one or more of these alternative capital resources, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

Off-balance sheet arrangements

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


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 Part II, “Item 7A, Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2015.

Oil and Gas Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market commodity prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, many of which are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas commodity prices with any degree of certainty. Sustained weakness in oil and gas commodity prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to commodity price fluctuations, can reduce the borrowing base under the 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, 2015 reserve estimates, we project that a $1 decline in the price per barrel of oil and a $0.50 decline in the price per Mcf of gas from year end 2015 would reduce our gross revenues for the year ending December 31, 2016 by $6.6 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, 2016. In April 2016, we entered into crude oil costless collars covering 1,128 MBbls of our oil production for the period from January 2017 through December 2017 at a weighted average floor price of $41.57 and a weighted average ceiling price of $50.81. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:



	Oil
	MBbls	Price
Production Period:
2nd Quarter 2016	518	$	40.47
3rd Quarter 2016	176	$	42.70
4th Quarter 2016	167	$	42.70
2017	315	$	44.30
	1,176

Swaps Subject to Optional Extension:



	Oil
	MBbls	Price
Production Period:
3rd Quarter 2016	378	$	40.25
4th Quarter 2016	361	$	40.25
	739

Crude Oil Costless Collars:



	Oil
		Weighted		Weighted
		Average		Average
	MBbls	Floor Price		Ceiling Price
Production Period:
2017	1,128	$	41.57	$	50.81
	1,128

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil may have on the fair value of our commodity derivatives. As of March 31, 2016, a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $1.7 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At March 31, 2016, our 2019 Senior Notes had a fixed rate of 7.75%, a carrying value of $592.9 million and an approximate fair value of $300 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 $6.6 million. At March 31, 2016, our Second Lien Term Loan had a fixed rate of 12.5%, if paid in cash, and a fixed rate of 15%, if paid in-kind, a carrying value of $322.5 million and a fair value that approximates the carrying value based upon the limited passage of time since being issued on March 15, 2016.


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

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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, 2016 these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the three months ended March 31, 2016 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

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Item 1A -	Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015, which could materially affect our business, financial condition or results of operations. Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations. If any of these risks actually occur, it could materially harm our business, financial condition or results of operations and impair our ability to implement business plans or complete development projects as scheduled. In that case, the market price of our common stock could decline.

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Item 6 -	Exhibits



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

**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement filed with the Commission on October 4, 1996, Commission File No. 333-13441

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

**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended through March 24, 2016, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 30, 2016††

**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		Certificate of Designation of the Special Voting Preferred Stock of Clayton Williams Energy, Inc., dated as of March 15, 2016, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.1		Credit Agreement by and among the Company, as Borrower, certain subsidiaries of the Company, as Guarantors, the Lenders party thereto and Wilmington Trust, National Association, as Administrative Agent, dated as of March 8, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 9, 2016††

**10.2		Warrant and Preferred Stock Purchase Agreement by and between the Company and AF IV Energy LLC, dated as of March 8, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on March 9, 2016††

**10.3		Amendment No. 4 to Third Amended and Restated Credit Agreement by and among the Company, as Borrower, certain of the Company’s subsidiaries, as Guarantors, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, dated as of March 8, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.4		Amendment No. 1 to Credit Agreement by and among the Company, as Borrower, certain subsidiaries of the Company, as Guarantors, the Lenders party thereto and Wilmington Trust, National Association, as Administrative Agent, dated as of March 15, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.5		Form of Warrant to Purchase Common Stock dated as of March 15, 2016, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.6		Form of Standstill Agreement dated as of March 15, 2016, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.7		Registration Rights Agreement by and between the Company and the Sellers listed on Schedule I thereto, dated as of March 15, 2016, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on March 15, 2016††

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

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

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

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.DEF		XBRL Definition Linkbase Document

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*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 9, 2016	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			President

Date:	May 9, 2016	By:	/s/ Michael L. Pollard
			Michael L. Pollard
			Senior Vice President - Finance and Chief Financial Officer

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INDEX TO EXHIBITS



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

**3.1		Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to our Form S-2 Registration Statement filed with the Commission on October 4, 1996, Commission File No. 333-13441

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

**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended through March 24, 2016, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on March 30, 2016††

**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		Certificate of Designation of the Special Voting Preferred Stock of Clayton Williams Energy, Inc., dated as of March 15, 2016, filed as Exhibit 4.1 to our Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.1		Credit Agreement by and among the Company, as Borrower, certain subsidiaries of the Company, as Guarantors, the Lenders party thereto and Wilmington Trust, National Association, as Administrative Agent, dated as of March 8, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 9, 2016††

**10.2		Warrant and Preferred Stock Purchase Agreement by and between the Company and AF IV Energy LLC, dated as of March 8, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on March 9, 2016††

**10.3		Amendment No. 4 to Third Amended and Restated Credit Agreement by and among the Company, as Borrower, certain of the Company’s subsidiaries, as Guarantors, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, dated as of March 8, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.4		Amendment No. 1 to Credit Agreement by and among the Company, as Borrower, certain subsidiaries of the Company, as Guarantors, the Lenders party thereto and Wilmington Trust, National Association, as Administrative Agent, dated as of March 15, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.5		Form of Warrant to Purchase Common Stock dated as of March 15, 2016, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.6		Form of Standstill Agreement dated as of March 15, 2016, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on March 15, 2016††

**10.7		Registration Rights Agreement by and between the Company and the Sellers listed on Schedule I thereto, dated as of March 15, 2016, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on March 15, 2016††

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

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

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

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

Table of Contents



*101.DEF		XBRL Definition Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

* Filed herewith.

** Incorporated by reference to the filing indicated.

*** Furnished herewith.

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

CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q - May 9, 2016

Attached files

CLAYTON WILLIAMS ENERGY INC /DE Reports