CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q

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EX-32.1 - EXHIBIT 32.1 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-093016xex321.htm
EX-31.2 - EXHIBIT 31.2 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-093016xex312.htm
EX-31.1 - EXHIBIT 31.1 - CLAYTON WILLIAMS ENERGY INC /DE	cwei-093016xex311.htm
EX-10.7 - EXHIBIT 10.7 - CLAYTON WILLIAMS ENERGY INC /DE	welborn1016ex10_7.htm
EX-10.6 - EXHIBIT 10.6 - CLAYTON WILLIAMS ENERGY INC /DE	tisdale1016ex10_6.htm
EX-10.5 - EXHIBIT 10.5 - CLAYTON WILLIAMS ENERGY INC /DE	thomas1016ex10_5.htm
EX-10.4 - EXHIBIT 10.4 - CLAYTON WILLIAMS ENERGY INC /DE	kennedy1016ex10_4.htm
EX-10.3 - EXHIBIT 10.3 - CLAYTON WILLIAMS ENERGY INC /DE	lyssy1016ex10_3.htm
EX-10.2 - EXHIBIT 10.2 - CLAYTON WILLIAMS ENERGY INC /DE	gasser1016ex10_2.htm
EX-10.1 - EXHIBIT 10.1 - CLAYTON WILLIAMS ENERGY INC /DE	riggs1016ex10_1.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 September 30, 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 17,493,486 shares of Common Stock, $.10 par value, of the registrant outstanding as of October 31, 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 September 30, 2016 and December 31, 2015	3

	Consolidated Statements of Operations and Comprehensive Loss for the three and nine months ended September 30, 2016 and 2015	5

	Consolidated Statement of Stockholders’ Equity for the nine months ended September 30, 2016	6

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015	7

	Notes to Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51

Item 4.	Controls and Procedures	53

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	54

Item 1A.	Risk Factors	54

Item 6.	Exhibits	55

	Signatures	57

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PART I. FINANCIAL INFORMATION


Item 1 -	Financial Statements

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

	September 30, 2016			December 31, 2015
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	182,993		$	7,780
Short-term investments	40,041			—
Accounts receivable:
Oil and gas sales	16,529			16,660
Joint interest and other, net of allowance for doubtful accounts of $2,694 at September 30, 2016 and $2,447 at December 31, 2015	4,764			3,661
Affiliates	187			260
Inventory	26,648			31,455
Deferred income taxes	8,778			6,526
Prepaids and other	2,031			2,463
	281,971			68,805
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,622,942			2,585,502
Pipelines and other midstream facilities	62,609			60,120
Contract drilling equipment	123,931			123,876
Other	22,268			19,371
	2,831,750			2,788,869
Less accumulated depreciation, depletion and amortization	(1,684,423		)	(1,587,585		)
Property and equipment, net	1,147,327			1,201,284

OTHER ASSETS
Investments and other	7,654			17,331
	$	1,436,952		$	1,287,420

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

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

	September 30, 2016			December 31, 2015
	(Unaudited)
CURRENT LIABILITIES
Accounts payable:
Trade	$	37,438		$	29,197
Oil and gas sales	19,750			19,490
Affiliates	1,209			383
Fair value of commodity derivatives	10,136			—
Accrued liabilities and other	24,262			16,669
	92,795			65,739
NON-CURRENT LIABILITIES
Long-term debt	846,507			742,410
Deferred income taxes	52,025			108,996
Fair value of commodity derivatives	1,490			—
Fair value of common stock warrants	171,720			—
Asset retirement obligations	62,478			48,728
Accrued compensation under non-equity award plans	22,585			16,254
Deferred revenue from volumetric production payment and other	4,572			5,695
	1,161,377			922,083
COMMITMENTS AND CONTINGENCIES (Note 15)
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; issued and outstanding — 3,500 shares at September 30, 2016 and none at December 31, 2015	—			—
Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 17,493,486 shares at September 30, 2016 and 12,169,536 at December 31, 2015	1,749			1,216
Additional paid-in capital	300,309			152,686
Retained earnings (accumulated deficit)	(119,278		)	145,696
	182,780			299,598
	$	1,436,952		$	1,287,420

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

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
REVENUES
Oil and gas sales	$	43,470		$	51,307		$	113,351		$	178,539
Midstream services	1,538			1,500			3,897			4,714
Drilling rig services	—			—			—			23
Other operating revenues	10,430			1,774			10,699			8,678
Total revenues	55,438			54,581			127,947			191,954
COSTS AND EXPENSES
Production	17,776			20,665			54,160			67,188
Exploration:
Abandonments and impairments	2,483			874			3,507			5,005
Seismic and other	(8		)	239			421			1,210
Midstream services	195			406			1,364			1,339
Drilling rig services	1,125			922			3,591			4,418
Depreciation, depletion and amortization	38,349			36,861			115,140			121,636
Impairment of property and equipment	1,091			3,089			3,438			5,620
Accretion of asset retirement obligations	1,290			1,001			3,360			2,936
General and administrative	5,571			4,631			23,027			25,102
Other operating expenses	579			5,632			3,094			8,479
Total costs and expenses	68,451			74,320			211,102			242,933
Operating loss	(13,013		)	(19,739		)	(83,155		)	(50,979		)
OTHER INCOME (EXPENSE)
Interest expense	(26,580		)	(13,565		)	(70,224		)	(40,451		)
Gain on early extinguishment of long-term debt	3,967			—			3,967			—
Loss on change in fair value of common stock warrants	(123,351		)	—			(154,956		)	—
Gain (loss) on commodity derivatives	1,330			18,099			(13,997		)	10,431
Impairment of investments and other	1,367			743			(5,832		)	2,307
Total other income (expense)	(143,267		)	5,277			(241,042		)	(27,713		)
Loss before income taxes	(156,280		)	(14,462		)	(324,197		)	(78,692		)
Income tax benefit	7,504			5,039			59,223			27,705
NET LOSS	$	(148,776	)	$	(9,423	)	$	(264,974	)	$	(50,987	)
Net loss per common share:
Basic	$	(10.62	)	$	(0.77	)	$	(20.72	)	$	(4.19	)
Diluted	$	(10.62	)	$	(0.77	)	$	(20.72	)	$	(4.19	)
Weighted average common shares outstanding:
Basic	14,013			12,170			12,789			12,170
Diluted	14,013			12,170			12,789			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)


						Retained
	Common Stock			Additional		Earnings			Total
	No. of	Par		Paid-In		(Accumulated			Stockholders’
	Shares	Value		Capital		Deficit)			Equity
BALANCE,
December 31, 2015	12,170	$	1,216	$	152,686	$	145,696		$	299,598
Net loss	—	—		—		(264,974		)	(264,974		)
Sale of common stock	5,051	506		146,840		—			147,346
Stock-based compensation plan	273	27		783		—			810
BALANCE,
September 30, 2016	17,494	$	1,749	$	300,309	$	(119,278	)	$	182,780

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

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

	Nine Months Ended
	September 30,
	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(264,974	)	$	(50,987	)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization	115,140			121,636
Impairment of property and equipment	3,438			5,620
Abandonments and impairments	3,507			5,005
Gain on sales of assets and impairment of inventory, net	(7,938		)	(835		)
Deferred income tax benefit	(59,223		)	(27,705		)
Non-cash employee compensation	7,245			4,405
(Gain) loss on commodity derivatives	13,997			(10,431		)
Cash settlements of commodity derivatives	(2,371		)	4,585
Accretion of asset retirement obligations	3,360			2,936
Amortization of debt issue costs and original issue discount	5,517			2,241
Gain on early extinguishment of long-term debt	(3,967		)	—
Loss on change in fair value of common stock warrants	154,956			—
Amortization of deferred revenue from volumetric production payment	(1,066		)	(5,181		)
Paid in-kind interest expense	27,196			—
Impairment of investment and other	8,530			669
Changes in operating working capital:
Accounts receivable	(898		)	25,307
Accounts payable	(1,702		)	(32,057		)
Other	7,219			9,788
Net cash provided by operating activities	7,966			54,996
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(62,331		)	(155,680		)
Termination of volumetric production payment	—			(13,703		)
Net purchase of short-term investments	(40,041		)	—
Proceeds from sales of assets	27,369			47,484
Decrease in equipment inventory	1,552			1,130
Proceeds from volumetric production payment and other	(689		)	1,499
Net cash used in investing activities	(74,140		)	(119,270		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	343,237			45,000
Net repayments of Senior Notes	(95,001		)	—
Repayments of long-term debt	(160,000		)	—
Payment of debt issuance costs	(10,958		)	—
Proceeds from sale of common stock	147,346			—
Proceeds from issuance of common stock warrants	16,763			—
Net cash provided by financing activities	241,387			45,000



(Continued)

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

	Nine Months Ended
	September 30,
	2016		2015
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	175,213		(19,274		)
CASH AND CASH EQUIVALENTS
Beginning of period	7,780		28,016
End of period	$	182,993	$	8,742

SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	29,794	$	26,993
Cash paid for income taxes	$	65	$	227

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

September 30, 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 17.8% of CWEI’s outstanding common stock, is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board of Directors (the “Board”) and Chief Executive Officer of the Company, and approximately 17.4% 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 September 30, 2016 and for the three and nine months ended September 30, 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 August 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Early adoption is permitted and is to be applied on retrospective basis. We are currently evaluating the method of adoption and impact this standard may have on our financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation.” ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Upon adoption, we expect to record a cumulative-effect adjustment to reclassify approximately $7.5 million of excess tax benefits that were not previously recognized because the related tax deduction had not reduced taxes payable. We plan to adopt ASU 2016-09 during the quarter ended March 31, 2017 to be effective as of January 1, 2017.

In February 2016, the FASB issued 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 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 August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and do not anticipate any impact on our consolidated financial statements.

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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. Early adoption is permitted for fiscal years beginning after December 15, 2016. In May 2016, the FASB issued ASU No. 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.


3.	Long-Term Debt

Long-term debt consists of the following:



	September 30, 2016			December 31, 2015

	(In thousands)
7.75% Senior Notes, due 2019	$	500,000		$	600,000
Original Issue Discount	(159		)	(241		)
Debt Issuance Costs	(4,852		)	(7,349		)
Net 7.75% Senior Notes, due 2019	$	494,989		$	592,410

Second Lien Term Loan, due March 2021	$	350,000		$	—
Paid in-kind interest	27,196			—
Original Issue Discount	(15,583		)	—
Debt Issuance Costs	(10,095		)	—
Net Second Lien Term Loan, due March 2021	$	351,518		$	—

Revolving credit facility, due April 2019	$	—		$	150,000
	$	846,507		$	742,410

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 (as defined below) (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.

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 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 to be less than 2.0 to 1.0.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The revolving credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 7.75% Senior Notes due 2019 (the “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.

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 10). The warrants had a fair value of $16.8 million at the date of issuance and a fair value of $171.7 million at September 30, 2016. As a result, for the three and nine months ended September 30, 2016, we recorded a loss on revaluation of the warrant liability of $123.4 million and $155 million, respectively.

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 paid interest for the period commencing from March 15, 2016 and ending March 31, 2016 in cash and elected to pay interest for the quarters ended June 30, 2016 and September 30, 2016 in-kind. In August 2016, we elected to pay interest for the quarterly period ending December 31, 2016 in cash. 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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

On July 22, 2016, we entered into an agreement to sell 5,051,100 shares of common stock to funds managed by Ares for cash proceeds of $150 million, or approximately $29.70 per share (the “Private Placement”) which transaction closed on August 29, 2016. In connection with the Private Placement, we entered into an amendment to the term loan facility, waiving certain restrictions to enable us to use proceeds from equity issuances and specified asset sales for debt reduction and capital expenditures.

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”). In August 2016, we redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer and for the three and nine months ended September 30, 2016 recorded a $4 million gain on early extinguishment of long-term debt, consisting of a $5 million discount and a $1 million write-off of debt issuance costs. We may redeem some or all of the remaining 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) is less than 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). 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 September 30, 2016 and December 31, 2015.


4.	Sales of Assets

In September 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $1.4 million. In July 2016, we sold our interests in certain wells in Glasscock County, Texas for approximately $19.4 million, subject to customary post-closing adjustments. In June 2016, we sold our interests in certain wells in Oklahoma for cash consideration of $1.5 million. In April 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $2 million. This acreage was sold under a one-year term assignment as long as the buyer maintains a 180-day continuous development program on the acreage. In February 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $0.8 million. Net proceeds from these transactions were used to repay the then-outstanding balance on the revolving credit facility and to fund a portion of our planned capital expenditures for 2016.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

In September 2015, we sold our interests in selected leases in South Louisiana for $11.8 million subject to customary closing adjustments. In June 2015, we sold certain acreage in Burleson County, Texas for cash consideration of $22.1 million. We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production associated with the Porter E Unit #1, our only Eagle Ford well situated on this acreage, a reversionary interest in acreage if the buyer fails to maintain a continuous development program and an overriding royalty interest in leases to the extent the net revenue interest exceeds 75%. During the first half of 2015, we sold our interests in selected leases in Oklahoma and sold our interests in certain wells in Martin and Yoakum Counties, Texas for proceeds totaling $7.3 million. Net proceeds from each of these transactions were applied to reduce indebtedness outstanding under the revolving credit facility.


5.	Asset Retirement Obligations

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

The following table reflects the changes in ARO during the nine months ended September 30, 2016 and the year ended December 31, 2015:



	September 30, 2016			December 31, 2015
	(In thousands)
Beginning of period	$	48,728		$	45,697
Additional ARO from new properties	40			469
Sales or abandonments of properties	(924		)	(4,435		)
Accretion expense	3,360			3,945
Revisions of previous estimates	11,274			3,052
End of period	$	62,478		$	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 September 30, 2016, we have no further obligations under the VPP.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table reflects the changes in the deferred revenue during the nine months ended September 30, 2016 and the year ended December 31, 2015:



	September 30, 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	(1,066		)	(6,822		)
Termination of VPP	—			(13,703		)
End of period	$	4,404		$	5,470


7.	Stockholders’ Equity and Earnings Per Share

In August 2016, we completed the sale of 5,051,100 shares of our common stock to funds managed by Ares for cash proceeds of $150 million or approximately $29.70 per share. Net proceeds from the sale, after offering expenses of $2.7 million, were used to repay indebtedness and provide additional funds for general corporate purposes.

Earnings Per Share

Basic earnings per share amounts have been computed based on the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. For the three and nine months ended September 30, 2016, there were 152,000 shares that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented.


8.	Compensation Plans

Long Term Incentive Plan

In June 2016, stockholders approved the Clayton Williams Energy, Inc. Long Term Incentive Plan (the “LTIP”), which was adopted by the Compensation Committee of the Board in April 2016. The LTIP was adopted in order to enable the Company to attract and retain highly qualified employees, directors and consultants and to provide equity-based compensation to those individuals that will align their interests with the interests of the Company’s shareholders. The LTIP provides for the granting of restricted stock awards, restricted stock units, stock options, stock appreciation rights, dividend-equivalent awards, other stock-based awards, cash awards, performance awards, and any combination of such awards. A total of 1,400,000 shares of the Company’s common stock have been reserved for issuance under the LTIP and are expected to consist of new shares of the Company. During the quarter ended September 30, 2016, initial grants of awards under the LTIP were made as disclosed in the tables below.

Stock Options

All outstanding nonqualified and incentive stock options under the LTIP expire seven years from the date of grant and vest ratably over a three-year period. The exercise price of stock options under the LTIP may not be less than the market value of the stock on the date of grant. The fair value of the stock options on the date of grant is expensed ratably over the applicable vesting period. The Company estimates the fair value of stock options granted using a Black-Scholes option valuation model, which requires the Company to make certain assumptions, as follows:

•Expected volatility of the underlying common stock is based on the Company’s historical stock volatility;


•	Expected term of options granted is based on the mid-point between the final vesting date and the expiration date since the Company does not have sufficient history to predict the expected term using historical data; and

•Risk-free interest rate is based on the U.S. Treasury yield curve for the expected term of the options at the date of grant.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following table summarizes the weighted average grant date fair values and related assumptions for grants made during the quarter ended September 30, 2016:



	September 30, 2016
Grant-date fair value	$	63.80
Expected volatility	76.3		%
Expected term (in years)	5
Risk-free rate	1.2		%

The following table sets forth certain information regarding our stock options as of September 30, 2016:



		Weighted Average			Aggregate
		Exercise		Remaining	Intrinsic
	Options	Price		Term	Value
Outstanding at January 1, 2016	—	$	—
Granted	152,000	$	63.80
Exercised	—	$	—
Outstanding at September 30, 2016	152,000	$	63.80

Vested and expected to vest at September 30, 2016	152,000	$	63.80	6.9	$	3,289,560
Exercisable at September 30, 2016	—	$	—	—	$	—

As of September 30, 2016, the unrecognized compensation cost related to granted stock options was $5.8 million. Such cost is expected to be recognized over a weighted-average period of 2.9 years.

Restricted Stock Awards

Restricted stock awards granted under the LTIP as of September 30, 2016 vest over either a one-year or three-year period. The estimated fair value of restricted stock grants, computed based on the closing price of the Company’s common stock on the date of grant, is expensed ratably over the applicable vesting period.

The following table presents our restricted stock activity as of September 30, 2016:



		Weighted Average
	Restricted Stock	Grant-Date
	Awards	Fair Value
Unvested at January 1, 2016	—	$	—
Granted	272,850	$	63.69
Vested	—	$	—
Forfeited	—	$	—
Unvested at September 30, 2016	272,850	$	—

The aggregate fair value of restricted stock awards granted during the nine months ended September 30, 2016 was $17.4 million. As of September 30, 2016, our unrecognized compensation cost related to unvested restricted stock awards was $16.7 million. Such cost is expected to be recognized over a weighted-average period of 2.6 years.

Stock-based compensation expense related to stock options and restricted stock awards was $0.8 million for the three and nine months ended September 30, 2016 and none for the three and nine months ended September 30, 2015.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Non-Equity Award Plans

The Compensation Committee of the Board has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs. The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, 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. Through May 4, 2016, 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. As of June 23, 2016, all 15 awards were fully vested. On May 4, 2016, the Compensation Committee amended the definition of a well in each plan to end the inclusion of new wells in all plans. A well is a well drilled by the employer in the area described provided that the well has a spud date between the effective date and May 4, 2016. All other terms of the plan remain unchanged. Future payments to participants in the plan will be based on the performance of only those wells that meet the revised definition of a well. The Compensation Committee expects to utilize the LTIP in lieu of future grants under the APO Reward Plan.

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 September 30, 2016 and 2015 and the nine months ended September 30, 2016 and 2015 were $(1.1) million, $(2) million and $7.2 million, $6.6 million, respectively. Credits to expense resulted from the reversal of previously accrued compensation expense attributable to changes in estimates of future compensation expense.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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



	September 30, 2016		December 31, 2015
	(In thousands)
Current liabilities:
Accrued liabilities and other	$	1,355	$	1,251
Non-current liabilities:
Accrued compensation under non-equity award plans	22,585		16,254
Total accrued compensation under non-equity award plans	$	23,940	$	17,505


9.	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 September 30, 2016. Settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:



	Oil
	MBbls	Price
Production Period:
4th Quarter 2016	619	$	41.18
2017	407	$	45.58
	1,026

Costless Collars:



	Oil
		Weighted		Weighted
		Average		Average
	MBbls	Floor Price		Ceiling Price
Production Period:
2017	1,415	$	42.27	$	51.66
	1,415

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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Commodity Derivative Instruments on the Consolidated Balance Sheets



	Fair Value of Commodity Derivative Instruments as of September 30, 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	$	10,136
	Non-current	—		Non-current	1,490
Total		$	—		$	11,626



	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



	September 30, 2016
	Assets		Liabilities
	(In thousands)
Fair value of commodity derivatives — gross presentation	$	—	$	11,626
Effects of netting arrangements	—		—
Fair value of commodity derivatives — net presentation	$	—	$	11,626



	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., Shell Trading Risk Management LLC and Fifth Third Bank.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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				Nine Months Ended
	September 30,				September 30,
Location of Gain or (Loss) Recognized in Earnings	2016		2015		2016			2015
	(In thousands)				(In thousands)
Commodity derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain (loss) on commodity derivatives	$	1,330	$	18,099	$	(13,997	)	$	10,431
Total	$	1,330	$	18,099	$	(13,997	)	$	10,431


10.	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.

The financial assets and liabilities measured on a recurring basis at September 30, 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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:



	September 30, 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	$	11,626	$	—
Fair value of common stock warrants	171,720		—
Total liabilities	$	183,346	$	—

Fair Value of Other Financial Instruments

We estimate the fair value of the 2019 Senior Notes using quoted market prices. The fair value of our Second Lien Term Loan as of September 30, 2016 is based upon our discounted cash flow model. Fair value is compared to the carrying value in the table below:



	Fair Value	September 30, 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	$	494,989	$	481,250	$	599,759	$	462,750
Second Lien Term Loan, due March 2021	3	$	351,518	$	275,301	$	—	$	—


11.	Income Taxes

Our effective federal and state income tax rate for the nine months ended September 30, 2016 of 18.3% differed from the statutory federal rate of 35% due primarily to permanent differences related to revaluation of the warrants issued in connection with the Refinancing, 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)


12.	Other Operating Revenues and Expenses

Other operating revenues and expenses for the three and nine months ended September 30, 2016 and 2015 are as follows:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015

	(In thousands)				(In thousands)
Other operating revenues:
Gain on sales of assets	$	10,430	$	1,774	$	10,699	$	8,655
Marketing revenue	—		—		—		23
Total other operating revenues	$	10,430	$	1,774	$	10,699	$	8,678
Other operating expenses:
Loss on sales of assets	$	482	$	345	$	1,387	$	410
Marketing expense	50		445		333		660
Impairment of inventory	47		4,842		1,374		7,409
Total other operating expenses	$	579	$	5,632	$	3,094	$	8,479

During the three and nine months ended September 30, 2016, gain on sales of assets included the sale of our interests in certain wells in Glasscock County, Texas in July 2016 (see Note 4).

During the three months ended September 30, 2015, gain on sales of assets included the sale of selected leases in South Louisiana in September 2015. During the nine months ended September 30, 2015, gain on sales of assets included the sale of selected leases in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015 and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015(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.


13.	Investment in Dalea Investment Group, LLC

In June 2012, we cancelled an $11 million note receivable in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC (“Dalea”), an international oilfield services company formed in March 2012. Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea was carried at the lower of its initial cost of $11 million and its estimated fair value based on a qualitative assessment. We recorded no impairment on our investment in Dalea for the three months ended September 30, 2016, $8.4 million for the nine months ended September 30, 2016, and $0.5 million and $1.4 million for the three and nine months ended September 30, 2015, respectively. At September 30, 2016, our investment in Dalea was fully impaired compared to an estimated fair value of $8.4 million at December 31, 2015. We categorize the measurement of fair value of this investment as a Level 3 input.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


14.	Costs of Oil and Gas Properties

The following table sets forth the net capitalized costs for oil and gas properties as of September 30, 2016 and December 31, 2015:



	September 30, 2016			December 31, 2015

	(In thousands)
Proved properties	$	2,562,372		$	2,539,480
Unproved properties	60,570			46,022
Total capitalized costs	2,622,942			2,585,502
Accumulated depletion	(1,546,087		)	(1,460,404		)
Net capitalized costs	$	1,076,855		$	1,125,098


15.	Commitments and Contingencies

Legal Proceedings

In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under our farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”). Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. 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 appealed the decision of the Court of Appeals to the Texas Supreme Court, and on October 21, 2016, the Texas Supreme Court denied Plaintiffs’ Petition for Review.

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. Status conferences and potential court rulings are set for November 2016.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.


16.	Impairment of Property and Equipment

We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value. The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset. We categorize the measurement of fair value of these assets as Level 3 inputs. We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: (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 a provision for impairment of proved properties of $1.1 million for the three months ended September 30, 2016 and $3.1 million for the three months ended September 30, 2015. We recorded a provision for impairment of proved properties of $3.4 million for the nine months ended September 30, 2016 and $5.6 million for the nine months ended September 30, 2015. The provision for the three months ended September 30, 2016 was related to the write-down of certain non-core properties located in California and the Cotton Valley area of Texas to their estimated fair value and the provision for the nine months ended September 30, 2016 was related to the write-down of certain non-core properties located in California, Oklahoma and the Cotton Valley area of Texas to their estimated fair value. The provision for the three months ended September 30, 2015 was related to the write-down of certain non-core properties located in the Permian Basin and California and the provision for the nine months ended September 30, 2015 was related to the write-down of certain non-core properties located in the Permian Basin, California and 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 of $2.1 million for the three months ended September 30, 2016, $0.3 million for the three months ended September 30, 2015, $2.3 million for the nine months ended September 30, 2016 and $2.7 million for the nine months ended September 30, 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)


17.	Segment Information

We have two reportable operating segments, which are (1) oil and gas exploration and production and (2) contract drilling services. The following tables present selected financial information regarding our operating segments for the three and nine months ended September 30, 2016 and 2015:



For the Three Months Ended
September 30, 2016
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	55,372		$	66		$	—		$	55,438
Depreciation, depletion and amortization ^(a)	36,540			2,900			—			39,440
Other operating expenses ^(b)	27,886			1,125			—			29,011
Interest expense	26,580			—			—			26,580
Other (income) expense	116,687			—			—			116,687
Income (loss) before income taxes	(152,321		)	(3,959		)	—			(156,280		)
Income tax (expense) benefit	6,118			1,386			—			7,504
Net income (loss)	$	(146,203	)	$	(2,573	)	$	—		$	(148,776	)
Total assets	$	1,459,652		$	25,457		$	(48,157	)	$	1,436,952
Additions to property and equipment	$	34,627		$	3,011		$	—		$	37,638



For the Nine Months Ended
September 30, 2016
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	127,799		$	148		$	—		$	127,947
Depreciation, depletion and amortization ^(a)	109,328			9,250			—			118,578
Other operating expenses ^(b)	89,111			3,413			—			92,524
Interest expense	70,224			—			—			70,224
Other (income) expense ^(c)	162,387			8,431			—			170,818
Income (loss) before income taxes	(303,251		)	(20,946		)	—			(324,197		)
Income tax (expense) benefit	51,892			7,331			—			59,223
Net income (loss)	$	(251,359	)	$	(13,615	)	$	—		$	(264,974	)
Total assets	$	1,459,652		$	25,457		$	(48,157	)	$	1,436,952
Additions to property and equipment	$	81,292		$	3,052		$	—		$	84,344

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



For the Three Months Ended
September 30, 2015
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	54,571		$	1,606		$	(1,596	)	$	54,581
Depreciation, depletion and amortization ^(a)	37,091			3,196			(337		)	39,950
Other operating expenses ^(b)	32,441			3,126			(1,197		)	34,370
Interest expense	13,565			—			—			13,565
Other (income) expense ^(c)	(19,337		)	495			—			(18,842		)
Income (loss) before income taxes	(9,189		)	(5,211		)	(62		)	(14,462		)
Income tax (expense) benefit	3,215			1,824			—			5,039
Net income (loss)	$	(5,974	)	$	(3,387	)	$	(62	)	$	(9,423	)
Total assets	$	1,383,193		$	52,363		$	(43,730	)	$	1,391,826
Additions to property and equipment	$	28,005		$	460		$	(62	)	$	28,403



For the Nine Months Ended
September 30, 2015
(Unaudited)				Contract			Intercompany			Consolidated
(In thousands)	Oil and Gas			Drilling			Eliminations			Total
Revenues	$	191,873		$	2,328		$	(2,247	)	$	191,954
Depreciation, depletion and amortization ^(a)	118,090			9,606			(440		)	127,256
Other operating expenses ^(b)	110,118			7,610			(2,051		)	115,677
Interest expense	40,451			—			—			40,451
Other (income) expense ^(c)	(14,155		)	1,417			—			(12,738		)
Income (loss) before income taxes	(62,631		)	(16,305		)	244			(78,692		)
Income tax (expense) benefit	21,998			5,707			—			27,705
Net income (loss)	$	(40,633	)	$	(10,598	)	$	244		$	(50,987	)
Total assets	$	1,383,193		$	52,363		$	(43,730	)	$	1,391,826
Additions to property and equipment	$	105,742		$	1,202		$	244		$	107,188

_______


(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)


18.	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. In August 2016, we redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer and for the three and nine months ended September 30, 2016 recorded a $4 million gain on early extinguishment of long-term debt, consisting of a $5 million discount and a $1 million write-off of debt issuance costs (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 18.

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

Condensed Consolidating Balance Sheet September 30, 2016 (Unaudited) (Dollars in thousands)

	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Current assets	$	333,198	$	269,858	$	1,014		$	(322,099	)	$	281,971
Property and equipment, net	862,866		281,133		3,328			—			1,147,327
Investments in subsidiaries	296,918		—		—			(296,918		)	—
Other assets	5,509		2,145		—			—			7,654
Total assets	$	1,498,491	$	553,136	$	4,342		$	(619,017	)	$	1,436,952
Current liabilities	$	298,879	$	100,964	$	63		$	(307,111	)	$	92,795
Non-current liabilities:
Long-term debt	846,507		—		—			—			846,507
Fair value of commodity derivatives	11,626		—		—			(10,136		)	1,490
Fair value of common stock warrants	171,720		—		—			—			171,720
Deferred income taxes	47,758		117,051		(2,114		)	(110,670		)	52,025
Other	45,039		44,296		300			—			89,635
	1,122,650		161,347		(1,814		)	(120,806		)	1,161,377
Equity	76,962		290,825		6,093			(191,100		)	182,780
Total liabilities and equity	$	1,498,491	$	553,136	$	4,342		$	(619,017	)	$	1,436,952

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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 September 30, 2016 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Total revenue	$	41,983		$	13,219		$	236		$	—	$	55,438
Costs and expenses	48,308			19,867			276			—		68,451
Operating income (loss)	(6,325		)	(6,648		)	(40		)	—		(13,013		)
Other income (expense)	(143,695		)	236			192			—		(143,267		)
Equity in earnings of subsidiaries	(4,069		)	—			—			4,069		—
Income tax (expense) benefit	5,313			2,244			(53		)	—		7,504
Net income (loss)	$	(148,776	)	$	(4,168	)	$	99		$	4,069	$	(148,776	)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Nine Months Ended September 30, 2016 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Total revenue	$	89,819		$	37,442		$	686		$	—	$	127,947
Costs and expenses	142,557			67,619			926			—		211,102
Operating income (loss)	(52,738		)	(30,177		)	(240		)	—		(83,155		)
Other income (expense)	(233,664		)	(7,968		)	590			—		(241,042		)
Equity in earnings of subsidiaries	(24,567		)	—			—			24,567		—
Income tax (expense) benefit	45,995			13,351			(123		)	—		59,223
Net income (loss)	$	(264,974	)	$	(24,794	)	$	227		$	24,567	$	(264,974	)

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Total revenue	$	39,500		$	14,765		$	316		$	—	$	54,581
Costs and expenses	52,630			21,133			557			—		74,320
Operating income (loss)	(13,130		)	(6,368		)	(241		)	—		(19,739		)
Other income (expense)	4,912			53			312			—		5,277
Equity in earnings of subsidiaries	(4,059		)	—			—			4,059		—
Income tax (expense) benefit	2,854			2,210			(25		)	—		5,039
Net income (loss)	$	(9,423	)	$	(4,105	)	$	46		$	4,059	$	(9,423	)

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

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Total revenue	$	140,902		$	49,906		$	1,146		$	—	$	191,954
Costs and expenses	177,041			64,042			1,850			—		242,933
Operating income (loss)	(36,139		)	(14,136		)	(704		)	—		(50,979		)
Other income (expense)	(28,720		)	(488		)	1,495			—		(27,713		)
Equity in earnings of subsidiaries	(8,991		)	—			—			8,991		—
Income tax (expense) benefit	22,863			5,118			(276		)	—		27,705
Net income (loss)	$	(50,987	)	$	(9,506	)	$	515		$	8,991	$	(50,987	)

Condensed Consolidating Statement of Cash Flows Nine Months Ended September 30, 2016 (Unaudited) (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations		Consolidated
Operating activities	$	(3,780	)	$	12,090		$	(344	)	$	—	$	7,966
Investing activities	(67,166		)	(6,955		)	(19		)	—		(74,140		)
Financing activities	246,040			(4,608		)	(45		)	—		241,387
Net increase (decrease) in cash and cash equivalents	175,094			527			(408		)	—		175,213
Cash at beginning of period	4,663			1,855			1,262			—		7,780
Cash at end of period	$	179,757		$	2,382		$	854		$	—	$	182,993

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Operating activities	$	44,249		$	9,330		$	978		$	439		$	54,996
Investing activities	(101,921		)	(16,741		)	(169		)	(439		)	(119,270		)
Financing activities	41,674			3,631			(305		)	—			45,000
Net increase (decrease) in cash and cash equivalents	(15,998		)	(3,780		)	504			—			(19,274		)
Cash at beginning of period	21,217			6,693			106			—			28,016
Cash at end of period	$	5,219		$	2,913		$	610		$	—		$	8,742


19.	Subsequent Events

On October 24, 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million. The sale is subject to customary closing conditions and adjustments. We expect to close the sale in December 2016 and use the proceeds from the sale to fund development in the Delaware Basin and repay a portion of our outstanding indebtedness.

We have evaluated events and transactions that occurred after the balance sheet date of September 30, 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 beliefs, based on currently available information, as to the outcome and timing of future events and their effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All statements concerning our expectations for future operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties, many of which are beyond our control, and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. 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”), and (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 nine months ended September 30, 2016, we spent $67.4 million on exploration and development activities. On October 24, 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing conditions and adjustments.

Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for the third quarter of 2016 and the outlook for the remainder of 2016.

•

Oil and gas sales for the third quarter of 2016, excluding amortized deferred revenues, decreased $7.5 million, or 15%, from the third quarter of 2015. Production variances accounted for a $5.7 million decrease and price variances accounted for a $1.8 million decrease. Average realized oil prices were $40.62 per barrel in the third quarter of 2016 versus $43.26 per barrel in the third quarter of 2015, average realized gas prices were $2.94 per Mcf in the third quarter of 2016 versus $2.71 per Mcf in the third quarter of 2015 and average realized natural gas liquids (“NGL”) prices were $13.14 per barrel in the third quarter of 2016 versus $11.01 per barrel in the third quarter of 2015. Amortized deferred revenue in the third quarter of 2016 totaled $0.4 million as compared to $0.8 million in the third quarter of 2015.

•

Oil, gas and NGL production per barrel of oil equivalent (“BOE”) decreased 10% in the third quarter of 2016 compared to the third quarter of 2015, with oil production decreasing 11% to 9,935 barrels per day, gas production decreasing 19% to 13,989 Mcf per day and NGL production increasing 9% to 1,685 barrels per day. Oil and NGL production accounted for approximately 83% of our total BOE production in the third quarter of 2016 compared to 82% in the third quarter of 2015. After giving effect to the sale of interests in certain wells in Glasscock County, Texas in July 2016 and the sale of selected leases and wells in South Louisiana in September 2015, oil, gas and NGL production per BOE decreased 7% in the third quarter of 2016 as compared to the third quarter of 2015.


•	Production costs decreased $2.9 million, or 14%, for the third quarter of 2016 compared to the third quarter of 2015 due to lower oilfield services costs. Production costs on a BOE basis, excluding production taxes, averaged $12.25 per BOE in the third quarter of 2016 versus $12.68 per BOE in the third quarter of 2015.

•

Interest expense for the third quarter of 2016 was $26.6 million versus $13.6 million for the third quarter of 2015. The increase was due primarily to $13.9 million of 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”). We elected to pay interest on the term loan facility in-kind and resulted in an increase in the principal amount of the term loan to $377.2 million.

•

We account for the warrants issued in connection with the Refinancing as derivative instruments and carry the warrants as a non-current liability at their fair value. We recorded a $123.4 million loss on change in fair value in the third quarter of 2016 due primarily to the impact on the valuation model of a 211% increase in the market price of our common stock from $27.46 at June 30, 2016 to $85.44 at September 30, 2016.

•

We recorded a $1.3 million gain on commodity derivatives in the third quarter of 2016 (net of a $2.4 million loss on settled contracts). For the same period in 2015, we recorded an $18.1 million gain on commodity derivatives (including a $6.4 million gain 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 an impairment of proved properties for the third quarter of 2016 of $1.1 million related primarily to non-core prospects in California and the Cotton Valley area of Texas versus $3.1 million in the third quarter of 2015 related to non-core prospects in the Permian Basin and California.

•

General and administrative (“G&A”) expenses were $5.6 million in the third quarter of 2016 compared to $4.6 million in the third quarter of 2015. Changes in compensation expense related to the Company’s APO reward plans accounted for $0.9 million of the increase ($1.1 million credit in the third quarter of 2016 versus $2 million credit in the third quarter of 2015), and additional expense related to issuances of restricted stock and stock options under our recent long-term

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incentive plan accounted for a $0.8 million increase. These increases were partially offset by reductions in salary and personnel expense.


•	In August 2016, we sold approximately 5.1 million shares of our common stock to Ares Management, LLC (“Ares”) for $150 million and used a portion of the net proceeds to redeem $100 million of 7.75% Senior Notes due 2019 (the “2019 Senior Notes”) in a tender offer in August 2016 and recorded a gain on early extinguishment of long-term debt in the third quarter of 2016 of $4 million.

Exploration and Development Activities

Overview

We spent $67.4 million during the first nine months of 2016 on exploration and development activities in the Permian Basin and the Giddings Area and currently plan to spend an additional $38.1 million during the remainder of 2016. On October 24, 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary and closing conditions and adjustments. 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 spent $38.5 million in the Permian Basin during the first nine months of 2016 on drilling and completion activities and $16.9 million on leasing and seismic activities. We drilled and completed 4 gross (4.0 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during the first nine months of 2016. We currently plan to spend an additional $33.1 million on drilling and completion activities and $4 million on leasing activities in this area during the remainder of 2016. Following is a discussion of our principal assets in the Permian Basin.

Delaware Basin

We currently hold approximately 73,000 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 11,500 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 33 Wolfcamp A wells currently on production. We also have four Wolfcamp C wells currently on production.

We spent approximately $34.7 million on drilling and completion activities and $16.8 million on leasing activities in the Wolfbone play during the first nine months of 2016. We plan to spend an additional $34 million on drilling, completion and leasing activities in this area during the remainder of 2016.

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We own oil, natural gas and water disposal pipelines in Reeves County, Texas consisting of 118 miles of oil pipelines with current capacity of 10,000 barrels of oil per day (expandable to 25,000 barrels of oil per day), 117 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 118 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).

Other Permian Basin

Approximately 33% of our 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 in East Central Texas were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations. 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 54% 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.

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 first nine months of 2016, we spent approximately $9.8 million on drilling, completion and leasing activities in the Eagle Ford Shale Area. Given the sale announced on October 24, 2016 of substantially all of our assets in the Giddings area, we expect capital spending in this area will be negligible during the remainder of 2016.

Other

We spent $2.2 million during the first nine months of 2016 on exploration and development activities in other regions, including Oklahoma and California and we currently do not plan to spend any additional capital during the remainder of 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 423 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 8 drilling rigs available for our use or for contract drilling operations. 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 have been idle since November 2015.

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Factors That Significantly Affect Our Financial Results

Revenue, cash flow from operations and future growth depend on many factors beyond our control, such as oil prices, cost of services and supplies, economic, political and regulatory developments and competition from other sources of energy. Historical oil prices have been volatile and are expected to fluctuate widely in the future. Sustained periods of low prices for oil could materially and adversely affect our financial position, our results of operations, the quantities of oil and gas that we can economically produce and our ability to obtain capital.

Like all businesses engaged in the exploration for and production of oil and gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or gas it produces. We attempt to overcome this natural decline by developing existing properties, implementing secondary and tertiary recovery techniques and by acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from existing reserves and to continue to add reserves in excess of production through exploration, development and acquisition. We will maintain our focus on costs necessary to produce our reserves as well as the costs necessary to add reserves through production enhancement, drilling and acquisitions. Our ability to make capital expenditures to increase production from existing reserves and to acquire more reserves is dependent on availability of capital resources, and can be limited by many factors, including the ability to obtain capital in a cost-effective manner and to obtain permits and regulatory approvals in a timely manner.

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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 September 30,
	2016			2015
Oil and Gas Production Data:
Oil (MBbls)	914			1,026
Gas (MMcf)	1,287			1,590
Natural gas liquids (MBbls)	155			142
Total (MBOE)^(a)	1,284			1,433
Total (BOE/d)	13,952			15,576

Average Realized Prices ^{(b) (c)}:
Oil ($/Bbl)	$	40.62		$	43.26
Gas ($/Mcf)	$	2.94		$	2.71
Natural gas liquids ($/Bbl)	$	13.14		$	11.01

Gain (Loss) on Settled Commodity Derivative Contracts ^(c):
($ in thousands, except per unit)
Oil: Cash settlements received (paid)	$	(2,347	)	$	6,352
Per unit produced ($/Bbl)	$	(2.57	)	$	6.19

Average Daily Production ^(d):
Oil (Bbls):
Permian Basin Area:
Delaware Basin	3,749			3,175
Other ^(e)	2,789			3,040
Austin Chalk	1,635			1,806
Eagle Ford Shale	1,518			2,634
Other ^(f)	244			497
Total	9,935			11,152
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	2,833			2,766
Other ^(e)	5,821			6,170
Austin Chalk	1,706			1,708
Eagle Ford Shale	299			451
Other ^(f)	3,330			6,188
Total	13,989			17,283
(Continued)

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	Three Months Ended September 30,
	2016			2015
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	543			408
Other ^(e)	823			795
Austin Chalk	196			179
Eagle Ford Shale	82			121
Other ^(f)	41			40
Total	1,685			1,543

BOE/d:
Permian Basin Area:
Delaware Basin	4,764			4,044
Other ^(e)	4,583			4,864
Austin Chalk	2,115			2,270
Eagle Ford Shale	1,650			2,830
Other ^(f)	840			1,568
Total	13,952			15,576

Exploration Costs (in thousands):
Abandonment and impairment costs:
California	$	52		$	254
Oklahoma	37			228
South Louisiana	—			336
Other	2,394			56
Total	2,483			874
Seismic and other	(8		)	239
Total exploration costs	$	2,475		$	1,113

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	34,779		$	33,338
Contract drilling depreciation	2,900			2,859
Other depreciation	670			664
Total depreciation, depletion and amortization	$	38,349		$	36,861

Oil and Gas Costs ($/BOE Produced):
Production costs	$	13.84		$	14.42
Production costs (excluding production taxes)	$	12.25		$	12.68
Oil and gas depletion	$	27.09		$	23.26

Net Wells Drilled ^(g):
Exploratory Wells	1.0			3.1
Developmental Wells	2.7			2.6
(Continued)

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	Nine Months Ended September 30,
	2016			2015
Oil and Gas Production Data:
Oil (MBbls)	2,707			3,330
Gas (MMcf)	3,756			4,458
Natural gas liquids (MBbls)	427			418
Total (MBOE)^(a)	3,760			4,491
Total (BOE/d)	13,723			16,451

Average Realized Prices ^{(b) (c)}:
Oil ($/Bbl)	$	36.44		$	46.93
Gas ($/Mcf)	$	2.19		$	2.65
Natural gas liquids ($/Bbl)	$	12.21		$	13.09

Gain (Loss) on Settled Derivative Contracts ^(c):
($ in thousands, except per unit)
Oil: Cash settlement received (paid)	$	(2,371	)	$	4,585
Per unit produced ($/Bbl)	$	(0.88	)	$	1.38

Average Daily Production ^(d):
Oil (Bbls):
Permian Basin Area:
Delaware Basin	3,161			3,561
Other ^(e)	2,856			2,917
Austin Chalk	1,705			1,884
Eagle Ford Shale	1,721			3,269
Other ^(f)	437			567
Total	9,880			12,198
Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	2,678			3,036
Other ^(e)	5,732			5,944
Austin Chalk	1,702			1,737
Eagle Ford Shale	339			540
Other ^(f)	3,257			5,073
Total	13,708			16,330
(Continued)

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	Nine Months Ended September 30,
	2016		2015
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	458		417
Other ^(e)	764		779
Austin Chalk	184		169
Eagle Ford Shale	84		126
Other ^(f)	68		40
Total	1,558		1,531

BOE/d:
Permian Basin Area:
Delaware Basin	4,065		4,484
Other ^(e)	4,575		4,687
Austin Chalk	2,173		2,343
Eagle Ford Shale	1,862		3,485
Other ^(f)	1,048		1,452
Total	13,723		16,451

Exploration Costs (in thousands):
Abandonment and impairment costs:
Oklahoma	$	867	$	318
California	240		414
South Louisiana	5		2,483
Other	2,395		1,790
Total	3,507		5,005
Seismic and other	421		1,210
Total exploration costs	$	3,928	$	6,215

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	103,910	$	110,478
Contract drilling depreciation	9,250		9,166
Other depreciation	1,980		1,992
Total depreciation, depletion and amortization	$	115,140	$	121,636

Oil and Gas Costs ($/BOE Produced):
Production costs	$	14.40	$	14.96
Production costs (excluding production taxes)	$	13.00	$	12.99
Oil and gas depletion	$	27.64	$	24.60
(Continued)

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	Nine Months Ended September 30,
	2016	2015
Net Wells Drilled ^(g):
Exploratory Wells	4.7	4.7
Developmental Wells	2.9	15.0

_______


(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 $0.4 million for three months ended September 30, 2016, $0.8 million for the three months ended September 30, 2015, $1.1 million for the nine months ended September 30, 2016 and $4.3 million for the nine months ended September 30, 2015 of amortized deferred revenue attributable to a volumetric production payment (“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 7,371 barrels of oil and 4,898 Mcf of gas for the three months ended September 30, 2015 and 53,026 barrels of oil and 35,735 Mcf of gas for the nine months ended September 30, 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)	Historical average daily production volumes have been reclassified to conform with current period presentation.


(e)	The average daily production related to interests in certain wells in Glasscock County, Texas sold in July 2016 was 90 total BOE for the three months ended September 30, 2016, 90 total BOE for the three months ended September 30, 2015, 66 total BOE for the nine months ended September 30, 2016 and 119 total BOE for the nine months ended September 30, 2015.


(f)	The average daily production related to selected leases and wells in South Louisiana sold in September 2015 was 584 total BOE for the three months ended September 30, 2015 and 521 total BOE for the nine months ended September 30, 2015.


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

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Operating Results — Three-Month Periods

The following discussion compares our results for the three months ended September 30, 2016 to the comparative period in 2015. Unless otherwise indicated, references to 2016 and 2015 within this section refer to the three months ended September 30, 2016 and 2015, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $7.5 million, or 15%, in 2016 from 2015. Production variances accounted for a $5.7 million decrease and price variances accounted for a $1.8 million decrease. Amortized deferred revenue in 2016 totaled $0.4 million as compared to $0.8 million in 2015. Oil, gas and NGL production in 2016 (on a BOE basis) decreased 10% compared to 2015. Oil production decreased 11%, gas production decreased 19% and NGL production increased 9% in 2016 from 2015. After giving effect to the sale of interests in certain wells in Glasscock County, Texas in July 2016 and the sale of selected leases and wells in South Louisiana in September 2015, oil, gas and NGL production per BOE decreased 7% in 2016 as compared to 2015. Oil and NGL production accounted for approximately 83% of our total BOE production in 2016 compared to 82% in 2015. In 2016, our realized oil price decreased 6% compared to 2015, and our realized gas price increased 9%. 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 14% to $17.8 million in 2016 as compared to $20.7 million in 2015 due to lower oilfield service costs. After giving effect to a 10% decrease in total production, production costs on a BOE basis, excluding production taxes, averaged $12.25 per BOE in 2016 compared to $12.68 per BOE in 2015.

Oil and gas depletion expense increased $1.4 million from 2015 to 2016 due to a $4.9 million increase related to rate variances and a $3.5 million decrease due to production variances. On a BOE basis, depletion expense increased 16% to $27.09 per BOE in 2016 from $23.26 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 $1.1 million during 2016 as compared to $3.1 million in 2015. The 2016 impairment related to non-core prospects in California and the Cotton Valley area of Texas to reduce the carrying value of these properties to their estimated fair value. The 2015 impairment related to non-core prospects in the Permian Basin and California. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value. If prices decline from current levels, we may incur future impairments. 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 $2.5 million of exploration costs, as compared to $1.1 million in 2015. The expense for 2016 includes a charge of $1.8 million related to unproved acreage impairments in Smith County, Texas. Exploration costs in 2015 were due primarily to dry hole costs and unproved acreage impairments in California, Oklahoma and South Louisiana.

Contract Drilling Services

Drilling services revenues received by our subsidiary, 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 $1.1 million in 2016 compared to $0.9 million in 2015. Contract drilling depreciation for 2016 and 2015 was $2.9 million. Due to the downturn in oil prices, all our rigs have been idle since November 2015.

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General and Administrative

G&A expenses increased $1 million from $4.6 million in 2015 to $5.6 million in 2016. Changes in compensation expense related to our APO reward plans accounted for $0.9 million of the increase ($1.1 million credit in 2016 versus $2 million credit in 2015), and additional expense related to issuances of restricted stock and stock options under our recent long-term incentive plan accounted for a $0.8 million increase. These increases were partially offset by reductions in salary and personnel expense.

Interest expense

Interest expense increased from $13.6 million in 2015 to $26.6 million in 2016 due primarily to $13.9 million of incremental interest expense on funded indebtedness incurred under a second lien term loan credit facility issued in connection with the Refinancing. We elected to pay interest on the term loan facility in-kind and resulted in an increase in the principal amount of the term loan to $377.2 million.

Gain on early extinguishment of long-term debt

We redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer in August 2016 and recorded a $4 million gain on early extinguishment of long-term debt consisting of a $5 million discount and a $1 million write-off of debt issuance costs.

Loss on change in fair value of common stock warrants

We account for the warrants issued in connection with the Refinancing as derivative instruments and carry the warrants as a non-current liability at their fair value. We recorded a $123.4 million loss on change in fair value in 2016 due primarily to the impact on the valuation model of a 211% increase in the market price of our common stock from $27.46 at June 30, 2016 to $85.44 at September 30, 2016.

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 $1.3 million gain on commodity derivatives (net of a $2.4 million loss on settled contracts) compared to an $18.1 million gain on commodity derivatives (including a $6.4 million gain 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 a $0.5 million charge to partially impair the carrying value of our investment in Dalea Investment Group, LLC (“Dalea”) in 2015.

Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $9.9 million on sales of assets and impairment of inventory in 2016 compared to a net loss of $3.4 million in 2015. The 2016 gain related primarily to the sale of our interests in certain wells in Glasscock County, Texas in July 2016. The 2015 loss related primarily to a $4.8 million write-down of inventory to reduce the carrying value to the estimated fair value partially offset by a gain of $1.8 million related primarily to the sale of selected leases in South Louisiana in September 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 4.8% was less than the statutory federal rate of 35% due primarily to permanent differences related to revaluation of the warrants issued in connection with the Refinancing, increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

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Operating Results — Nine-Month Periods

The following discussion compares our results for the nine months ended September 30, 2016 to the comparative period in 2015. Unless otherwise indicated, references to 2016 and 2015 within this section refer to the nine months ended September 30, 2016 and 2015, respectively.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $62 million, or 36%, in 2016 from 2015. Production variances accounted for a $31.5 million decrease and price variances accounted for a $30.5 million decrease. Oil and gas sales in 2016 also includes $1.1 million of amortized deferred revenue compared to $4.3 million in 2015 attributable to the VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP. Oil, gas and NGL production in 2016 (on a BOE basis) decreased 16% compared to 2015. Oil production decreased 19%, gas production decreased 16%, and NGL production increased 2% in 2016 from 2015. After giving effect to the sale of interests in certain wells in Glasscock County, Texas in July 2016 and the sale of selected leases and wells in South Louisiana in September 2015, oil, gas and NGL production in 2016 (on a BOE basis) decreased 13% compared to 2015. Oil and NGL production accounted for approximately 83% of our total BOE production in 2016 compared to 84% in 2015. In 2016, our realized oil price decreased 22% compared to 2015, and our realized gas price decreased 17%. 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 19% to $54.2 million in 2016 as compared to $67.2 million in 2015, due primarily to lower oilfield service costs and reductions in production taxes associated with a decrease in oil and gas sales. After giving effect to a 16% decrease in total production, production costs, excluding production taxes, averaged $13.00 per BOE in 2016 compared to $12.99 per BOE in 2015.

Oil and gas depletion expense decreased $6.6 million from 2015 to 2016 due to an $18 million decrease related to production variances and an $11.4 million increase due to rate variances. On a BOE basis, depletion expense increased 12% to $27.64 per BOE in 2016 from $24.60 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 $3.4 million during 2016 as compared to $5.6 million in 2015. The 2016 impairment related to non-core prospects in California, Oklahoma and the Cotton Valley area of Texas to reduce the carrying value of these properties to their estimated fair value. The 2015 impairment related to non-core prospects in the Permian Basin, California and Louisiana. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value. If prices decline from current levels, we may incur future impairments. 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 $3.9 million of exploration costs, as compared to $6.2 million in 2015. The 2016 expense includes a charge of $1.8 million related to unproved acreage impairments in Smith County, Texas. Exploration costs in 2015 were due primarily to dry hole costs and unproved acreage impairments in California, Oklahoma and South Louisiana.

Contract Drilling Services

Drilling services revenues received by our subsidiary, 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 $3.6 million in 2016 compared to $4.4 million in 2015. Contract drilling depreciation for 2016 was $9.3 million compared to $9.2 million in 2015. Due to the downturn in oil prices, all our rigs have been idle since November 2015.

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General and Administrative

G&A expenses decreased $2.1 million from $25.1 million in 2015 to $23 million in 2016 due primarily to reductions in salary and personnel expense. Changes in compensation expense related to our APO reward plans accounted for an increase of $0.6 million ($7.2 million in 2016 versus $6.6 million in 2015), and additional expense related to issuances of restricted stock and stock options under our recent long-term incentive plan accounted for a $0.8 million increase.

Interest expense

Interest expense increased from $40.5 million in 2015 to $70.2 million in 2016 due primarily to $27.2 million of incremental interest expense on funded indebtedness incurred under a second lien term loan credit facility issued in connection with the Refinancing. We elected to pay interest on the term loan facility in-kind and resulted in an increase in the principal amount of the term loan to $377.2 million.

Gain on early extinguishment of long-term debt

Loss on change in fair value of common stock warrants

We account for the warrants issued in connection with the Refinancing as derivative instruments and carry the warrants as a non-current liability at their fair value. We recorded a $155 million loss on change in fair value in 2016 due primarily to the impact on the valuation model of a 495% increase in the market price of our common stock from $14.37 at March 15, 2016 to $85.44 at September 30, 2016.

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 $14 million loss on commodity derivatives (including a $2.4 million loss on settled contacts) compared to a $10.4 million gain on commodity derivatives (including a $4.6 million gain 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 $1.4 million in 2015.

Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $7.9 million on sales of assets and impairment of inventory in 2016 compared to a net gain of $0.8 million in 2015. The 2016 gain related primarily to the sale of our interests in certain wells in Glasscock County, Texas in July 2016. The 2015 gain related primarily to the sale of selected leases in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015, and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015. The 2015 gain was partially offset by a $7.4 million write-down of inventory to reduce the carrying value to the estimated fair value. 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 18.3% was less than the statutory federal rate of 35% due primarily to permanent differences related to revaluation of the warrants issued in connection with the Refinancing, increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

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Liquidity and Capital Resources

Overview

Our primary financial resource is our base of oil and gas reserves. We pledge 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 “ — Revolving credit facility” 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.

At September 30, 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 $348.1 million of availability on the facility at September 30, 2015. Our indebtedness at September 30, 2016 was $846.5 million, consisting of $351.5 million including paid in-kind interest, net of original issue discount and debt issuance costs, under the second lien term loan credit facility and $495 million in outstanding principal amount of the 2019 Senior Notes, net of original issue discount and debt issuance costs.

Recent Events and Outlook for 2016

On October 24, 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing conditions and adjustments. We expect to close the sale in December 2016 and use the proceeds from the sale to fund development in the Delaware Basin and repay a portion of our outstanding indebtedness. We do not expect the sale of the Giddings assets to have a significant reduction in funds available under the revolving credit facility.

In July 2016, we entered into an agreement to sell 5,051,100 shares of common stock to funds managed by Ares for cash proceeds of $150 million or approximately $29.70 per share (the “Private Placement”), which transaction closed on August 29, 2016. In connection with the Private Placement, we entered into an amendment to the term loan facility, waiving certain restrictions to enable us to use proceeds from equity issuances and specified asset sales for debt reduction and capital expenditures.

In July 2016, we commenced a cash tender offer to purchase up to $100 million aggregate principal amount of the 2019 Senior Notes with a bid range from $880 to $950 per each $1,000 aggregate principal amount of the 2019 Senior Notes. The tender offer expired on August 29, 2016 and we accepted for purchase $100 million in aggregate principal amount of 2019 Senior Notes at a purchase price of $947.50 per $1,000 principal amount, which included an early tender premium of $30.00 for each $1,000 principal amount of 2019 Senior Notes so purchased.

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Capital expenditures

The following table summarizes, by area, our actual expenditures for exploration and development activities for the nine months ended September 30, 2016 and our planned expenditures for the year ending December 31, 2016.



	Actual Expenditures Nine Months Ended September 30, 2016		Planned Expenditures Year Ending December 31, 2016		2016 Percentage of Total Planned Expenditures
	(In thousands)
Drilling and completion
Permian Basin Area:
Delaware Basin	$	34,700	$	64,700	61	%
Austin Chalk/Eagle Ford Shale	2,100		2,100		2	%
Other	5,000		8,100		8	%
	41,800		74,900		71	%
Leasing and seismic	25,600		30,600		29	%
Exploration and development	$	67,400	$	105,500	100	%

Our expenditures for exploration and development activities for the nine months ended September 30, 2016 totaled $67.4 million. We financed these expenditures for the nine months ended September 30, 2016 with cash flow from operating activities, a combination of proceeds from the Refinancing and the Private Placement, proceeds from asset sales, and borrowings under our credit facilities. We currently plan to spend approximately $105.5 million on exploration and development activities during fiscal 2016. We plan to continue utilizing one rig in Reeves County, Texas for the remainder of 2016. With recent improvements in drill times we now expect to have drilled eight wells by the end of the year, with five wells on production and three wells in various stages of completion. 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 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 nine months ended September 30, 2016 decreased $47 million, or 86%, 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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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 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 September 30, 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 nine months ended September 30, 2016 was 2.5%. We were in compliance with all financial and non-financial covenants at September 30, 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 $189.2 million at September 30, 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 $297.4 million at September 30, 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 September 30, 2016 and December 31, 2015.



	September 30, 2016		December 31, 2015

	(In thousands)
Working capital per GAAP	$	189,176	$	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	10,136		—
Working capital per loan covenant	$	297,442	$	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 September 30, 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 September 30, 2016, JPMorgan Chase Bank, N.A., Shell Trading Risk Management LLC and Fifth Third Bank were the counterparties 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 the Board. Aggregate cash proceeds from the transaction of approximately $340 million, net of transaction costs, were used to fully repay the then-outstanding indebtedness under the revolving credit facility of $160 million, plus accrued interest and fees.

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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 September 30, 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. In connection with the Private Placement, we entered into an amendment to the term loan facility, waiving certain restrictions to enable us to use proceeds from equity issuances and specified asset sales for debt reduction and capital expenditures. The amendment is effective upon closing of the Private Placement.

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”). In August 2016, we redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer and for the three and nine months ended September 30, 2016 recorded a $4 million gain on early extinguishment of long-term debt, consisting of a $5 million premium and a $1 million write-off of debt issuance costs. We may redeem some or all of the remaining 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 nine months of 2016, we received cash proceeds aggregating $27.4 million from various sales of assets. On October 24, 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing conditions and adjustments. We expect to close the sale in December 2016. We are 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.

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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 cash on hand and cash flow from operations.

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 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

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terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.

The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to September 30, 2016. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps:



	Oil
	MBbls	Price
Production Period:
4th Quarter 2016	619	$	41.18
2017	407	$	45.58
	1,026

Costless Collars:



	Oil
		Weighted		Weighted
		Average		Average
	MBbls	Floor Price		Ceiling Price
Production Period:
2017	1,415	$	42.27	$	51.66
	1,415

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 September 30, 2016, a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $2.1 million.

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At September 30, 2016, the 2019 Senior Notes had a fixed rate of 7.75%, a carrying value of $495 million and an approximate fair value of $481.3 million, based on current market quotes. We estimate that a hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $10.6 million. At September 30, 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 $351.5 million and an approximate fair value of $275.3 million.

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Item 4 -	Controls and Procedures

Disclosure Controls and Procedures

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

With respect to our disclosure controls and procedures:


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


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

•

it is the conclusion of our chief executive and chief financial officers that as of September 30, 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, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

Changes in Internal Control Over Financial Reporting

No changes in internal control over financial reporting were made during the nine months ended September 30, 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


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††

**3.4		Corporate Bylaws of Clayton Williams Energy, Inc., as amended through July 22, 2016, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on July 25, 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		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of October 1, 2016

*10.2		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Ron D. Gasser, effective as of October 1, 2016

*10.3		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Sam Lyssy, effective as of October 1, 2016

*10.4		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and John F. Kennedy, effective as of October 1, 2016

*10.5		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of October 1, 2016

*10.6		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and T. Mark Tisdale, effective as of October 1, 2016

*10.7		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Greg S. Welborn, effective as of October 1, 2016

**10.8		Common Stock Purchase Agreement by and between the Company and the Purchasers named on Schedule A thereto, dated as of July 22, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on July 25, 2016††

**10.9		Amendment No. 2 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 July 22, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on July 25, 2016††

**10.10		Stockholder Agreement by and between the Company and Ares Management LLC, dated as of August 29, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on August 29, 2016††

**10.11		Amendment No. 5 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 August 26, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on August 29, 2016††

**†10.12		Employment Agreement by and between the Company and Jaime R. Casas, dated as of October 1, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 5, 2016††

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**†10.13		Separation Agreement by and between the Company and Michael L. Pollard, dated as of October 1, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on October 5, 2016††

**†10.14		Employment Agreement by and between the Company and Patrick G. Cooke, dated as of October 31, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 25, 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

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

* Filed herewith.

** Incorporated by reference to the filing indicated.

*** Furnished herewith.

† Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.

†† 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:	November 7, 2016	By:	/s/ Mel G. Riggs
			Mel G. Riggs
			President

Date:	November 7, 2016	By:	/s/ Jaime R. Casas
			Jaime R. Casas
			Senior Vice President and Chief Financial Officer

Table of Contents

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††

**3.4		Corporate Bylaws of Clayton Williams Energy, Inc., as amended through July 22, 2016, filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the Commission on July 25, 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		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of October 1, 2016

*10.2		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Ron D. Gasser, effective as of October 1, 2016

*10.3		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Sam Lyssy, effective as of October 1, 2016

*10.4		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and John F. Kennedy, effective as of October 1, 2016

*10.5		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of October 1, 2016

*10.6		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and T. Mark Tisdale, effective as of October 1, 2016

*10.7		Amended And Restated Employment Agreement between Clayton Williams Energy, Inc. and Greg S. Welborn, effective as of October 1, 2016

**10.8		Common Stock Purchase Agreement by and between the Company and the Purchasers named on Schedule A thereto, dated as of July 22, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on July 25, 2016††

**10.9		Amendment No. 2 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 July 22, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on July 25, 2016††

**10.10		Stockholder Agreement by and between the Company and Ares Management LLC, dated as of August 29, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on August 29, 2016††

**10.11		Amendment No. 5 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 August 26, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on August 29, 2016††

**†10.12		Employment Agreement by and between the Company and Jaime R. Casas, dated as of October 1, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 5, 2016††

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**†10.13		Separation Agreement by and between the Company and Michael L. Pollard, dated as of October 1, 2016, filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the Commission on October 5, 2016††

**†10.14		Employment Agreement by and between the Company and Patrick G. Cooke, dated as of October 31, 2016, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on October 25, 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

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

* Filed herewith.

** Incorporated by reference to the filing indicated.

*** Furnished herewith.

† Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.

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

CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-Q - November 7, 2016

Attached files

CLAYTON WILLIAMS ENERGY INC /DE Reports