CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)



ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014



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

Commission File Number 001-10924

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)



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

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

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

Securities registered pursuant to Section 12(b) of the Act:



	Title of each class		Name of each exchange on which registered
	Common Stock, $.10 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes x No

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer x		Accelerated filer o

Non-accelerated filer o		Smaller reporting company o

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter. $810,642,074.

There were 12,169,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of February 26, 2015.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement relating to the 2015 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2015, are incorporated by reference in Part III of this Form 10-K.

Table of Contents

CLAYTON WILLIAMS ENERGY, INC. TABLE OF CONTENTS

		Page
Part I
Item 1.	Business	7
	General	7
	Company Profile	7
	Desta Drilling	8
	Exploration and Development Activities	9
	Marketing Arrangements	11
	Pipelines and Other Midstream Facilities	12
	Competition and Markets	12
	Regulation	12
	Environmental and Occupational Safety and Health Matters	14
	Title to Properties	18
	Operational Hazards and Insurance	18
	Operating Segments	19
	Executive Officers	19
	Employees	19
	Website Address	19

Item 1A.	Risk Factors	20

Item 1B.	Unresolved Staff Comments	30

Item 2.	Properties	30
	Reserves	30
	Delivery Commitments	35
	Exploration and Development Activities	36
	Productive Well Summary	36
	Volumes, Prices and Production Costs	37
	Development, Exploration and Acquisition Expenditures	38
	Acreage	38
	Desta Drilling	38
	Offices	39

Item 3.	Legal Proceedings	39

Item 4.	Mine Safety Disclosures	39

Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
	Price Range of Common Stock	40
	Dividend Policy	40
	Securities Authorized for Issuance under Equity Compensation Plans	40

Item 6.	Selected Financial Data	40

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TABLE OF CONTENTS (Continued)

		Page
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
	Overview	42
	Key Factors to Consider	43
	Proved Oil and Gas Reserves	44
	Supplemental Information	45
	Operating Results	49
	Liquidity and Capital Resources	52
	Known Trends and Uncertainties	56
	Application of Critical Accounting Policies and Estimates	57
	Recent Accounting Pronouncements	61

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	61
	Oil and Gas Prices	61
	Interest Rates	62

Item 8.	Financial Statements and Supplementary Data	62

Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	62

Item 9A.	Controls and Procedures	62
	Disclosure Controls and Procedures	62
	Internal Control Over Financial Reporting	63
	Changes in Internal Control Over Financial Reporting	63
	Management’s Report on Internal Control Over Financial Reporting	63
	Report of Independent Registered Public Accounting Firm	64

Item 9B.	Other Information	65

Part III
Item 10.	Directors, Executive Officers and Corporate Governance	65
Item 11.	Executive Compensation	65
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	65
Item 13.	Certain Relationships and Related Transactions, and Director Independence	65
Item 14.	Principal Accounting Fees and Services	65

Part IV
Item 15.	Exhibits, Financial Statement Schedules	66
	Financial Statements and Schedules	66
	Exhibits	66

Glossary of Terms		70

Signatures		73

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Forward-Looking Statements

The information in this Form 10-K 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 belief, based on currently available information, as to the outcome and timing of future events. 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 this Form 10-K, (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.

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


•	estimates of our oil and gas reserves;


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


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


•	our outlook on oil and gas prices;


•	our outlook on domestic and worldwide economic conditions;


•	our access to capital and our anticipated liquidity;


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


•	the impact of political and regulatory developments;


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


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


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

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


•	the possibility of unsuccessful exploration and development drilling activities;


•	our ability to replace and sustain production;


•	commodity price volatility;


•	domestic and worldwide economic conditions;


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


•	our level of indebtedness, liquidity and compliance with debt covenants;


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

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


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


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


•	drilling and other operating risks;


•	hurricanes and other weather conditions;


•	lack of availability of goods and services;


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


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


•	the other risks described in this Form 10-K.

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 petroleum 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.

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

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

Definitions of terms commonly used in the oil and gas industry and in this Form 10-K can be found in the “Glossary of Terms.”

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PART I

Item 1 - Business

General

Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, Louisiana and New Mexico. Unless the context otherwise requires, references to the “Company,” “CWEI,” “we,” “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. On December 31, 2014, our estimated proved reserves were 75,430 MBOE, of which 56% were proved developed. Our portfolio of oil and natural gas reserves is weighted in favor of oil, with approximately 83% of our proved reserves at December 31, 2014 consisting of oil and natural gas liquids (“NGL”) and approximately 17% consisting of natural gas. During 2014, we added proved reserves of 23,336 MBOE through extensions and discoveries, had downward revisions of 10,101 MBOE and had sales of minerals-in-place of 2,057 MBOE. We also had average net production of 15.8 MBOE per day in 2014, which implies a reserve life of approximately 13.1 years. CWEI held interests in 3,190 gross (1,491.9 net) producing oil and gas wells and owned leasehold interests in approximately 680,000 gross (373,000 net) undeveloped acres at December 31, 2014.

Clayton W. Williams, Jr. (“Mr. Williams”) beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our Common Stock. In addition, The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership of which Mr. Williams’ adult children are the limited partners, owns an additional 25% of the outstanding shares of our Common Stock. Mr. Williams is also Chairman of our Board of Directors (the “Board”), President and Chief Executive Officer of the Company. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations.

Company Profile

Business Strategy

Our goal is to grow oil and gas reserves and increase shareholder value utilizing a flexible, opportunity-driven business strategy. We do not adhere to rigid guidelines for resource allocations, risk profiles, product mixes, financial measurements or other operating parameters. Instead, we try to identify exploratory and developmental projects that offer us the best possible opportunities for growth in oil and gas reserves and allocate our available resources to those projects. Our direction is heavily influenced by Mr. Williams, who has over 55 years of experience and leadership in the oil and gas industry. Strategically, we are currently focused on the development of oil reserves over gas reserves. We have significant holdings in oil-prone regions in the Permian Basin and the Giddings Area that we believe offer us attractive opportunities for growth in oil reserves, and subject to the issues discussed under “— Recent Developments,” we plan to exploit these resources once our margins between oil prices and the costs of drilling, completion and other field services return to acceptable levels. In addition to our developmental drilling, we may explore for oil and gas reserves in areas that we believe offer us exceptional opportunities for reserve growth, and we may also search for possible proved property acquisitions. From year to year, our allocation of investment capital may vary between exploratory and developmental activities depending on our analysis of all available growth opportunities, but our long-term focus on growing oil and gas reserves is consistent with our goal of value enhancement for our shareholders.

Recent Developments

The recent downturn in oil markets has caused a significant reduction in our operating margins, and the impact has been especially negative since we entered 2015 with no commodity hedges in place. Lower operating margins offer us little incentive to accelerate oil production by continuing with non-essential drilling operations. As a result, we have suspended drilling operations in both of our core resource plays until the combination of higher oil prices and lower drilling and completion costs provides us with an acceptable profit margin. Currently, we plan to reduce capital spending during fiscal 2015 to $107.4 million compared to $404.3 million in fiscal 2014. We are also taking steps to lower our operating costs and to enact meaningful cost-cutting measures to reduce our general and administrative expenses and in February 2015, we entered into commodity swaps covering 1,737 MBbls of 2015 oil production at an average price of $55.65 per barrel.

Although reducing drilling activity during an adverse economic climate is a prudent and necessary action in order to preserve liquidity and limit increases in indebtedness, that action has a negative impact on production and cash flow from operations. Based on our current plans for 2015 spending, our combined oil and gas production will decline in 2015 as compared to 2014. In addition, if product prices remain depressed during 2015, our ratio of total indebtedness to EBITDA (as defined in the credit facility) was expected to exceed the maximum ratio permitted under the credit facility. As a result, we requested and received an amendment

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to the credit facility to suspend that financial covenant through the second quarter of 2016. See the discussion under “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Revolving Credit Facility.”

We are monitoring the impact of this downturn on our business, including the extent to which lower prices could affect our financial condition and liquidity. While we believe we are taking appropriate actions to preserve our short-term liquidity, the effects of a prolonged cycle of low operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves. These factors have an adverse effect on our ability to access the capital resources we need to grow our reserve base. See the discussion under “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Alternative Capital Resources.”

Domestic Operations

We conduct all of our drilling, exploration and production activities in the United States. All of our oil and gas assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.

Development Program

Our current focus is on developmental drilling. A developmental well is a well drilled within the proved area of an oil and gas reservoir to a horizon known to be productive. We have an inventory of developmental projects available for drilling in the future, most of which are located in the oil-prone regions of the Permian Basin and the Giddings Area. In many cases, our leasehold interests in developmental projects are held by the continuous production of other wells, meaning that our rights to drill these projects are not subject to near-term expiration. This provides us with a high degree of flexibility in the timing of developing these reserves.

Exploration Program

To a lesser degree, we are also engaged in finding reserves through exploratory drilling. Our exploration program consists of generating exploratory prospects, leasing the acreage related to these prospects, drilling exploratory wells on these prospects to determine if recoverable oil and gas reserves exist, drilling developmental wells on these prospects and producing and selling any resulting oil and gas production.

Acquisition and Divestitures of Proved Properties

In addition to our exploration and development activities, we watch for opportunities to acquire proved reserves that could compliment our current operations and enhance shareholder value. However, competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it difficult for us to acquire reserves without assuming significant price and production risks. We have no definitive plans to pursue the acquisition of proved reserves in 2015.

From time to time, we sell certain of our proved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them. We consider many factors in deciding to sell properties, including the need for liquidity, the risks associated with continuing to own the properties, our expectations for future development on the properties, the fairness of the price offered and other factors related to the condition and location of the properties.

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we operate 14 drilling rigs, two of which we lease under long-term contracts. We believe that owning and operating our own rigs helps us control our cost structure while providing us flexibility to take advantage of drilling opportunities on a timely basis. The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties. Due to the downturn in oil prices discussed under “— Company Profile — Recent Developments,” all 14 rigs are currently idle.

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Exploration and Development Activities

Overview

We have been committed to drilling primarily developmental oil wells in the Permian Basin and the Giddings Area. We spent $404.3 million on exploration and development activities during 2014 and currently plan to spend approximately $107.4 million during 2015. Our actual expenditures during 2015 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Factors such as changes in operating margins, the availability of capital resources, drilling results and other factors could increase or decrease our actual expenditures during 2015.

Areas of Operations

Permian Basin

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

We spent $179 million in the Permian Basin during 2014 on drilling and completion activities and $22.2 million on leasing and seismic activities. We drilled and completed 62 gross (19.7 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during 2014. We currently plan to spend approximately $58.1 million on drilling and leasing activities in this area during 2015. Following is a discussion of our principal assets in the Permian Basin.

Delaware Basin

We currently hold approximately 71,000 net acres in the active Wolfbone resource play in the Delaware Basin, primarily in Reeves County, Texas. The Wolfbone resource play generally refers to the interval from the Bone Springs formation down through the Wolfcamp formation at depths typically found between 8,000 and 13,000 feet. A Wolfbone well generally refers to a vertical well completed in multiple intervals within these formations or a horizontal well being completed in an interval within such formations. These Permian aged formations in the Delaware Basin are composed of limestone, sandstone and shale. Geology in the Delaware Basin consists of multiple stacked pay zones with both over-pressured and normal-pressured intervals.

A significant portion of our current holdings in this area is associated with a farm-in agreement we entered into in March 2011, with Chesapeake Exploration, L.L.C. (“Chesapeake”) in southern Reeves County, Texas with a term of up to five years. Chesapeake’s position in the agreement was previously held by SWEPI, LP (“Shell”) and is currently held by COG Operating, LLC. We amended the farm-in agreement with Shell in February 2014. The amendment replaced a commitment for 20 carried wells per year (as specified within the agreement) with a commitment to drill nine additional carried wells prior to December 31, 2014, on which date the agreement terminated. We met the commitment by drilling all nine of the wells prior to December 31, 2014. To date we have earned over 22,000 net acres under the farm-in agreement and expect to earn an additional 2,400 net acres after completion and production of existing wells.

We entered the Delaware Basin as a vertical play, but with encouraging results from our horizontal drilling, we have 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 22 Wolfcamp A wells currently in production and two wells being completed. We also have three Wolfcamp C wells currently in production and one well is waiting on completion operations.

In November 2014, we entered into a farm-out and exploration agreement with Caza Oil and Gas, Inc. (“Caza”) covering a portion of our 71,000 net acre resource play in Reeves County, Texas. All of the approximate 15,000 net undeveloped acres covered by this agreement are located along the western flank of our acreage block. Caza failed to comply with the provisions of the farm-out and the agreement is no longer in force. We may continue marketing this acreage for sale or farm-out.

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We spent approximately $152.2 million on drilling and completion activities and $22 million for leasing activities in the Wolfbone play during 2014. We plan to spend approximately $46.2 million on drilling and completion activities on wells in progress at December 31, 2014, drill two continuous development wells and leasing activities in this area during 2015.

We own oil, gas and water disposal pipelines in Reeves County, Texas consisting of 104 miles of oil pipelines with a design capacity of 18,000 barrels of oil per day, 103 miles of gas pipelines with a design capacity of 25,000 Mcf of natural gas per day and 103 miles of salt water disposal pipelines with a design capacity of 20,000 barrels of produced water per day. These facilities may be expanded to accommodate new wells as we continue our development in the area.

Other Permian Basin

Approximately 33% of our 2014 oil and gas production was derived from wells in parts of the Permian Basin other than our Delaware Basin Wolfbone resource play. Many of these wells are located on the Central Basin Platform, geographically located between the Midland Basin and Delaware Basin, and produce from formations with conventional porosity such as the San Andres, Grayburg, Fusselman, Ellenburger and Yeso formations. A significant portion of our production in this area is derived from mature fields, several of which are in varying stages of secondary and/or tertiary recovery.

Giddings Area

Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas. Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale and Taylor formations. We have approximately 175,000 net acres in the Giddings Area. Following is a discussion of our principal assets in the Giddings Area.

Austin Chalk

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

Eagle Ford Shale

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 2014, we spent approximately $160.2 million on drilling and completion activities and $27.9 million for leasing activities in the Eagle Ford Shale Area, and we currently plan to spend approximately $44.4 million primarily to complete drilling and completion operations on wells in progress at December 31, 2014 and leasing activities in this area during 2015.

Other

We spent $15 million during 2014 on exploration and development activities in other regions, including South Louisiana, Oklahoma and California and we currently plan to spend $4.9 million during 2015.

Known Trends and Uncertainties

Our developmental drilling programs are very sensitive to oil prices and drilling costs. During 2014, crude oil prices remained favorable, and we were able to maintain drilling costs at acceptable levels partly by using our own drilling rigs, purchasing casing and tubing at opportune times and working with service providers to receive acceptable unit costs. However, the dramatic downturn in oil prices in recent months has reduced operating margins to unacceptable levels, forcing us to temporarily suspend drilling operations in our core development areas. We are taking steps to lower our operating costs and to enact meaningful cost-cutting measures to reduce our general and administrative expenses. While we believe we are taking appropriate actions to lessen the short-term impact of lower operating margins on our business, a prolonged downturn of this magnitude could negatively impact our long-term liquidity, financial position and results of operations. We will continue to monitor the effects of this downturn on

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our business and would expect to resume drilling operations at a time in the future when we can again realize an acceptable margin between our expected cash flows from new production and our cost to drill and complete new wells.

In addition to reducing our incentive to drill new wells, the prolonged effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves. These factors have an adverse effect on our ability to access the capital resources we need to grow our reserve base. At December 31, 2014, our leverage ratio, expressed as the ratio of total long-term debt to EBITDA, was 2.4 times based on a trailing 12-month calculation of EBITDA. In the current price environment, we expected this ratio to exceed the maximum leverage ratio of 4.0 times EBITDA in our credit facility before the end of 2015. To address this issue, we initiated discussions with lenders under the credit facility and in February 2015, received an amendment to the credit facility to suspend that covenant through the second quarter of 2016. See “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Marketing Arrangements

Oil

Most of our oil production is sold based on the New York Mercantile Exchange (“NYMEX”) futures market for West Texas Intermediate light sweet crude oil (referred to as WTI and traded in the NYMEX futures market under the symbol CL). Cushing, Oklahoma is a major trading hub for crude oil and is the price settlement point for WTI. As a result, basis differentials exist between the NYMEX price and the price we receive for our oil production depending on the proximity of our properties to the ultimate market for that production. Basis differentials are market-based and can be adversely affected by logistical factors such as pipeline constraints and inadequate storage capacities.

Approximately 66% of our oil reserves at December 31, 2014 are located in the Permian Basin. Since most Permian Basin oil production gains access to refineries through the Cushing trading hub, increased drilling and completion activities in the Permian Basin related to shale oil plays have resulted in pipeline constraints that are contributing to higher basis differentials between the Midland, Texas oil storage facility and the Cushing trading hub (referred to as the Midland-Cushing differential). Through multiple marketing arrangements, beginning in December 2012, we have effectively limited our exposure to the Midland-Cushing differential to less than $2 per barrel on a majority of our Permian Basin production. In addition, approximately 30% of our oil reserves at December 31, 2014 are located in the Giddings Area. Most of the oil production from this area gains access to Gulf Coast refineries through pipelines that bypass the Cushing trading hub.

Natural gas

Natural gas is generally sold based on the NYMEX futures market for natural gas (traded in the NYMEX futures market under the symbol NG). Since the delivery point for NYMEX traded natural gas is the distribution hub on a natural gas pipeline system in Erath, Louisiana, referred to as Henry Hub, basis differentials exist between the NYMEX price and the price we receive for our gas production depending on the proximity of our properties to the ultimate market for that production. Basis differentials are market-based and can be adversely affected by logistical factors such as pipeline constraints and inadequate storage capacities.

Most of our natural gas production is produced from our oil wells. This gas, known as casinghead gas, generally has a high Btu content. Casinghead gas may be processed downstream to extract NGL from the gas and lower the Btu content of the residue gas to a level suitable for manufacturing and residential use. Our casinghead gas is generally sold in one of three ways: (1) as processed gas where the purchaser processes the gas and pays us a percentage of the value of the NGL and a percentage of the value of the residue gas; (2) as processed gas where the purchaser accounts for the value of any extracted NGL and includes that value in the price paid to us for our gas production at the wellhead; and (3) as unprocessed gas where the purchaser pays us a price per MMBtu for our gas production at the wellhead. All of the value we receive from casinghead gas production is recorded as gas sales in our financial records, except for the value of NGL paid to us under method (1), which is reported separately as NGL sales.

Some of our natural gas production is produced from gas wells. This gas, known as dry gas, generally has a Btu content of approximately 1,000 and is not suitable for extraction of NGL. Most of our dry gas is sold under contracts where the purchaser pays us a price per MMBtu for our gas production at the wellhead.

Natural gas liquids

A portion of our casinghead gas production is processed under contracts where the purchaser pays us a percentage of the value of the NGL extracted. The price we receive for NGL is generally based on the spot liquids price for the various NGL products sold at Mont Belvieu, Texas and reported by Oil Price Information Service. We compute the price differential for NGL based on

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the NYMEX benchmark for oil, but the NGL components are subject to their own supply and demand factors, not all of which vary in correlation with changes in oil prices.

Pipelines and Other Midstream Facilities

We own an interest in and operate oil, natural gas and water service facilities in the states of Texas and Louisiana. These midstream facilities consist of interests in approximately 380 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.

Competition and Markets

Competition in all areas of our operations is intense. We experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to increase reserves in the future will depend on our success at selecting and acquiring suitable producing properties and prospects for future development and exploration activities.

The market for our oil, gas and NGL production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and NGL, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

Regulation

Generally. Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

Regulations affecting production. All of the states in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil and gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.

In the event we conduct operations on federal, state or Indian oil and gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements and on-site security regulations, and other appropriate permits issued by the Bureau of Land Management or other relevant federal or state agencies.

Regulations affecting sales. The sales prices of oil, gas and NGL are not presently regulated but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on the operations of the underlying properties.

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The Federal Energy Regulatory Commission (the “FERC”) regulates interstate gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the gas industry. We do not believe that we will be affected by any such FERC action in a manner materially different from other gas producers in our areas of operation.

The price we receive from the sale of oil and NGL is affected by the cost of transporting those products to market. Interstate transportation rates for oil, NGL and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil and NGL.

Market manipulation and market transparency regulations. Under the Energy Policy Act of 2005 (the “EP Act 2005”), the FERC possesses regulatory oversight over gas markets, including the purchase, sale and transportation of gas by “any entity” in order to enforce the anti-market manipulation provisions in the EP Act 2005. The Federal Trade Commission (the “FTC”) has similar regulatory oversight of oil markets in order to prevent market manipulation. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of crude oil, gas and NGL, our gathering of these energy commodities, and any related hedging transactions that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC, the FTC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

The FERC has issued certain market transparency rules for the gas industry pursuant to its EP Act 2005 authority, which may affect some or all of our operations. The FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical gas in the previous calendar year, including gas producers, gatherers, processors and marketers, to report, on May 1 of each year, beginning in 2009, aggregate volumes of gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices, as explained in Order 704. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. The FERC has issued a Notice of Inquiry in Docket No. RM13-1-000 seeking comments from the industry regarding whether it should require more detailed information from sellers of gas. It is unclear what action, if any, will result and whether our reporting burden will increase or decrease.

Gathering regulations. Section 1(b) of the Natural Gas Act (the “NGA”) exempts gas gathering facilities from the jurisdiction of the FERC under the NGA. We own certain gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC jurisdiction. The distinction between the FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, ongoing litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather gas. In addition, our gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner materially differently than other companies in our areas of operation.

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Environmental and Occupational Safety and Health Matters

Our operations pertaining to oil and gas exploration, production and related activities are subject to numerous and constantly changing federal, state and local laws governing occupational safety and health, the emission and discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits prior to commencing drilling or other regulated activities in connection with our operations; restrict or prohibit the types, quantities and concentration of substances that we can release into the environment; restrict or prohibit activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources; require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells; impose specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from our operations. Such laws and regulations may substantially increase the cost of our operations and may prevent or delay the commencement or continuation of a given project and thus generally could have an adverse effect upon our capital expenditures, earnings or competitive position. Violation of these laws and regulations could result in sanctions including administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas. We have experienced accidental spills, leaks and other discharges of contaminants at some of our properties, as have other similarly situated oil and gas companies, and some of the properties that we have acquired, operated or sold, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible. Also, some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas, that may obligate us to implement costly mitigative or precautionary measures, while some of our properties are located in areas particularly susceptible to hurricanes and other destructive storms that may damage facilities and cause the release of pollutants. Our environmental insurance coverage may not fully insure all of these risks. Although the costs of remedying such conditions may be significant, we do not believe these costs would have a material adverse impact on our financial condition and operations.

We believe that we are in substantial compliance with current applicable environmental laws and regulations, and that the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2015. We also do not believe that we will be required to incur material capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in the re-interpretation of enforcement policies could have a significant impact on our operations, as well as the oil and gas industry in general. For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements, or drilling, completion, construction or water management activities could have an adverse impact on our operations.

The following is a summary of the more significant existing environmental and worker health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous substances and wastes. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency (the “EPA”) or state agencies as non-hazardous wastes. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous wastes if such wastes have hazardous

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characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own or lease and have in the past owned or leased properties that for many years have been used for oil and natural gas exploration and production activities. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other substances and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons or other substances and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other substances and wastes was not under our control. These properties and any hydrocarbons, substances and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination.

Air emissions. The Clean Air Act and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits or utilize specific emission control technologies to limit emissions. For example, in December 2014, the EPA published proposed regulations to revise the National Ambient Air Quality Standard for ozone, recommending a standard between 65 to 70 parts per billion, or ppb, for both the 8-hour primary and secondary standards protective of public health and public welfare. The EPA requested public comments on whether the standard should be set as low as 60 ppb or whether the existing 75 ppb standard should be retained. The EPA anticipates issuing a final rule by October 1, 2015. If the EPA lowers the ozone standard, states could be required to implement new, more stringent regulations, which could apply to our exploration and production operations. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. However, we believe our operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

Water discharges and subsurface injections. The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws and regulations impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water from our operations and may be required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil, including refined petroleum products. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the United States Oil Pollution Act of 1990 (“OPA”) and similar legislation enacted in Texas, Louisiana and other coastal states impose oil spill prevention and control requirements and significantly expand liability for damages resulting from oil spills. OPA imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil spill response and removal costs and a variety of public and private damages.

Fluids associated with oil and natural gas production, consisting primarily of salt water, are disposed by injection in belowground disposal wells. These disposal wells are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. While we believe that our disposal well operations substantially comply with requirements under the UIC program, a change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that the injection of saltwater and other fluids into belowground disposal wells triggers seismic activity in certain areas, including Texas, where we operate. In response to these concerns, in October 2014, the Texas Railroad Commission (“TRC”) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal

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area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and likely to result in added costs to comply or, perhaps, may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs.

Global warming and climate change. The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for greenhouse gases from certain large stationary sources that are already potential major sources of principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that typically will be established by the states. The EPA has also adopted rules requiring the annual reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and natural gas production facilities. We believe that we are in compliance with all greenhouse gas emissions reporting requirements applicable to our operations.

While the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, in the absence of any such legislation in recent years, a number of state and regional efforts have emerged that are aimed at tracking or reducing emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, to acquire and surrender emission allowances. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse emissions would impact our business, any such future laws and regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or reduce emissions of greenhouse gases associated with our operations, and such requirements could adversely affect demand for the oil and natural gas that we produce. For example, only recently, on January 14, 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions or other similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015.

From time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states, including Texas, New Mexico and Louisiana, where we conduct operations, have adopted and other states are considering adopting legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, such as the State of New York announced in December 2014. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we

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operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. In addition, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in the first half of 2015. These ongoing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

To our knowledge, there have been no citations, suits or contamination of potable drinking water arising from our hydraulic fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Endangered species. The federal Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species or their critical habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our well drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on protected species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service (“FWS”) is required to make a determination on listing of numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. For example, in March 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas and New Mexico, where we conduct operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to us from species protection measures, time delays or limitations on the drilling program’s activities, which costs, delays or limitations may be significant.

Pipeline safety. Some of our pipelines are subject to regulation by the U.S. Department of Transportation (the “DOT”) under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and further amended by the Pipeline Safety, Regulation Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act amendments”). The DOT, through the Pipeline and Hazardous Materials Safety Administration, has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas and hazardous liquids transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas and commercially navigable waterways. Under the DOT’s regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and recordkeeping. These regulatory requirements may be expanded in the future upon completion of studies required by the 2011 Pipeline Safety Act amendments.

OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

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Claims are sometimes made or threatened against companies engaged in oil and natural gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, courts in other jurisdictions have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.

Title to Properties

As is customary in the oil and gas industry, we perform a minimal title investigation before acquiring undeveloped properties. A title opinion is obtained prior to the commencement of drilling operations on such properties. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. These title investigations and title opinions, while consistent with industry standards, may not reveal existing or potential title defects, encumbrances or adverse claims as we are subject from time to time to claims or disputes regarding title to properties. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our oil and gas properties are currently mortgaged to secure borrowings under the credit facility and may be mortgaged under any future credit facilities entered into by us.

Operational Hazards and Insurance

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.

We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

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Operating Segments

For financial information about our operating segments, see Note 17 to the accompanying consolidated financial statements.

Executive Officers

The following is a list, as of February 27, 2015 of the name, age and position with the Company of each person who is an executive officer of the Company:

CLAYTON W. WILLIAMS, JR., age 83, is Chairman of the Board, President, Chief Executive Officer and a director of the Company, having served in such capacities since September 1991. For more than the past ten years, Mr. Williams has also been the chief executive officer and a director of certain other entities that are controlled directly or indirectly by Mr. Williams. Mr. Williams beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our Common Stock.

MEL G. RIGGS, age 60, is Executive Vice President and Chief Operating Officer of the Company, having served in such capacities since January 2011. Prior to that, Mr. Riggs had served as Senior Vice President — Finance and Chief Financial Officer of the Company since 1991. Mr. Riggs has also served as a director of the Company since May 1994.

MICHAEL L. POLLARD, age 64, is Senior Vice President — Finance and Chief Financial Officer of the Company, having served in such capacity since January 2011. Prior to that, Mr. Pollard had served as Vice President — Accounting of the Company since 2003.

RONALD D. GASSER, age 56, is Vice President — Engineering of the Company, having served in such capacity since October 2012. Prior to that, Mr. Gasser had served as Engineering Manager of the Company since 2006.

JOHN F. KENNEDY, age 50, is Vice President — Drilling of the Company, having served in such capacity since October 2012. Prior to that, Mr. Kennedy had served as Drilling Manager of the Company since 1998.

ROBERT C. LYON, age 78, is Vice President — Gas Gathering and Marketing of the Company, having served in such capacity since 1993.

SAMUEL L. LYSSY, JR., age 52, is Vice President — Exploration of the Company, having served in such capacity since October 2012. Prior to that, Mr. Lyssy had served as Exploration Manager of the Company since 1995.

PATRICK C. REESBY, age 62, is Vice President — New Ventures of the Company, having served in such capacity since 1993.

ROBERT L. THOMAS, age 58, is Vice President — Accounting and Principal Accounting Officer of the Company, having served in such capacity since January 2011. Prior to that, Mr. Thomas had served as General Accounting Manager of the Company since 2003.

T. MARK TISDALE, age 58, is Vice President and General Counsel of the Company, having served in such capacity since 1993.

GREGORY S. WELBORN, age 41, is Vice President — Land of the Company, having served in such capacity since 2006. Mr. Welborn is the son-in-law of Clayton W. Williams, Jr.

Employees

At December 31, 2014, we had 451 full-time employees, of which 179 were employed by Desta Drilling. None of our employees are subject to a collective bargaining agreement. Due to the current downturn in oil prices, we have made significant reductions in our employee count since December 31, 2014 and currently have 260 full-time employees, of which 12 are employed by Desta Drilling. In our opinion, relations with employees are good.

Website Address

We maintain an Internet website at www.claytonwilliams.com. We make available, free of charge, on our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. The information contained in or incorporated in our website is not part of this report.

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Item 1A - Risk Factors

There are many factors that affect our business, some of which are beyond our control. Our business, financial condition and results of operations could be materially adversely affected by any of these risks. The nature of our business activities further subjects us to certain hazards and risks. The risks described below are a summary of some of the material risks relating to our business. Other risks are described in “Item 1 — Business” and “Item 7A — Quantitative and Qualitative Disclosures About Market Risk.” 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.

Oil and gas prices are volatile. Declines in commodity prices have adversely affected, and in the future may adversely affect, our financial condition, liquidity, results of operations, cash flows, access to the capital markets and ability to grow.

Our revenues, operating results, liquidity, cash flows, profitability and value of proved reserves depend substantially upon the market prices of oil and gas. Commodity prices affect our cash flows available for capital expenditures and our ability to access funds under the credit facility and through the capital markets. The amount available for borrowing under the credit facility is subject to a borrowing base, which is determined at least semi-annually by our lenders taking into account the estimated value of our proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in commodity prices have historically adversely affected the estimated value of our proved reserves and, in turn, the market values used by our lenders in determining our borrowing base. If commodity prices decline in the future, the decline could have adverse effects on our reserves and borrowing base.

The commodity prices we receive for our oil and gas depend upon factors beyond our control, including among others:


•	changes in the supply of and demand for oil and gas;


•	market uncertainty;


•	the level of consumer product demands;


•	pipeline constraints and sufficient capacity;


•	hurricanes and other weather conditions;


•	domestic governmental regulations and taxes;


•	the price and availability of alternative fuels;


•	political and economic conditions in oil producing countries;


•	the foreign supply of oil and gas;


•	the price of oil and gas imports; and


•	overall domestic and foreign economic conditions.

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and gas prices do not necessarily fluctuate in direct relation to each other.

We may not be able to replace production with new reserves.

In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. In past years, our oil and gas properties have had steep rates of decline and short estimated productive lives.

Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves. Also, we may not be able to make the necessary capital investments if our cash flows

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from operations decline or external sources of capital become limited or unavailable. We cannot give assurance that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

Our business is capital intensive and requires us to spend substantial amounts of capital for exploration and development activities. Low product price environments such as the current downturn in oil prices that we are currently experiencing, as well as operating difficulties and other factors, many of which are beyond our control, may cause our revenues and cash flows from operating activities to decrease and may limit our ability to internally fund our exploration and development activities. If our borrowing base under the credit facility is redetermined to a lower amount, this could adversely affect our ability to supplement cash flows from operations as a source of funding for these activities. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot give assurance that additional debt or equity financing will be available on terms acceptable to us, or that cash flows provided by operations will be sufficient to meet our capital expenditures requirements.

We have substantial indebtedness. Our leverage and the covenants in our debt agreements could negatively impact our financial condition, liquidity, results of operations and business prospects.

As of December 31, 2014, the principal amount of our outstanding consolidated debt was approximately $704.7 million, which included $105 million outstanding under the credit facility and $599.7 million in outstanding principal amount of the 2019 Senior Notes, net of unamortized discount. The credit facility and the indenture governing the 2019 Senior Notes (the “Indenture”) impose significant restrictions on our ability to take certain actions, including our ability to incur additional indebtedness, sell certain assets, merge, make investments or loans, issue redeemable or preferred stock, pay distributions or dividends, create liens, guarantee other indebtedness and enter into new lines of business.

Our level of indebtedness and the restrictive covenants in our debt agreements could have important consequences on our business and operations. Among other things, these may:


•	require us to use a significant portion of our cash flows to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;


•	adversely affect the credit ratings assigned by third-party rating agencies, which have in the past downgraded, and may in the future downgrade their ratings of our debt and other obligations due to changes in our debt level or our financial condition;


•	limit our access to the capital markets;


•	increase our borrowing costs and impact the terms, conditions and restrictions contained in our debt agreements, including the addition of more restrictive covenants;


•	limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;


•	place us at a disadvantage compared to similar companies in our industry that have less debt; and


•	make us more vulnerable to economic downturns and adverse developments in our business.

A higher level of debt will increase the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be affected by oil and gas prices, financial, business, domestic and worldwide economic conditions, governmental and environmental regulations and other factors, many of which we are unable to control. If our cash flows are not sufficient to service our debt, we may be required to refinance the debt, sell assets or sell shares of our stock on terms that we do not find attractive, if it can be done at all.

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The credit risk of financial institutions could adversely affect us.

We have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies and their affiliates. These transactions expose us to credit risk in the event of default by our counterparty, principally with respect to hedging transactions but also insurance contracts and bank lending commitments. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us.

Our hedging transactions could result in financial losses or could reduce our income and cash flow.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into and may in the future enter into hedging transactions for a significant portion of our expected oil and gas production. These transactions could result in both realized and unrealized hedging losses. Conversely, if we do not enter into hedging transactions and product prices for our oil and gas production decline significantly during any unhedged production periods, we may realize a material reduction in our operating margins. The prolonged effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves. Currently, we are not a party to any hedging transactions.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative transactions. For example, the derivative instruments we utilize are primarily based on NYMEX futures prices, which may differ significantly from the actual crude oil and gas prices we realize in our operations. Furthermore, we have adopted a policy that requires, and the credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions. If our actual future production is higher than we estimated, we will have greater commodity price exposure than we intended. If our actual future production is lower than the nominal amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flows from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

In addition, our hedging transactions are subject to the following risks:


•	we may be limited in receiving the full benefit of increases in oil and gas prices as a result of these transactions;


•	a counterparty may not perform its obligation under the applicable derivative instrument or may seek bankruptcy protection;


•	there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and


•	the steps we take to monitor our derivative instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenues, profitability and cash flows to be materially different from our estimates.

The accuracy of estimated proved reserves and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn could adversely affect our cash flows, results of operations, financial condition and the availability of capital resources. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which

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are beyond our control. Downward adjustments to our estimated proved reserves could require us to impair the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity.

The present value of proved reserves will not necessarily equal the current fair market value of our estimated oil and gas reserves. In accordance with reserve reporting requirements of the SEC, we are required to establish economic production for reserves on an average historical price. Actual future prices and costs may be materially higher or lower than those required by the SEC. The timing of both the production and expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.

The estimated proved reserve information is based upon reserve reports prepared by independent engineers. From time to time, estimates of our reserves are also made by the lenders under the credit facility in establishing the borrowing base under the credit facility and by our engineers for use in developing business plans and making various decisions. Such estimates may vary significantly from those of the independent engineers and have a material effect upon our business decisions and available capital resources.

Our producing properties are largely concentrated in two major geographic areas, the Permian Basin in West Texas and Southeastern New Mexico and the Giddings Area in East Central Texas. Concentrations of reserves in limited geographic areas may disproportionately expose us to operational, regulatory and geological risks.

Our core producing properties are geographically concentrated in the Permian Basin of West Texas and Southeastern New Mexico and the Giddings Area in East Central Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of oil, gas or NGL.

In addition, as of December 31, 2014, a significant portion of our proved reserves was derived from the Wolfcamp formation in the Delaware Basin and the Austin Chalk and Eagle Ford formations in the Giddings Area. This concentration of assets within a few producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

Our proved undeveloped locations are scheduled to be drilled over several years, subjecting us to uncertainties that could materially alter the occurrence or timing of our drilling activities.

We have assigned proved undeveloped reserves to certain of our drilling locations as an estimation of our future multi-year development activities on our existing acreage. These identified locations represent a significant part of our growth strategy. At December 31, 2014, our estimated proved undeveloped reserves were 44% of total estimated proved reserves. Our ability to drill and develop these locations depends on a number of uncertainties, including (1) our ability to timely drill wells on lands subject to complex development terms and circumstances; (2) the availability of capital, equipment, services and personnel; (3) seasonal conditions; (4) regulatory and third-party approvals; (5) oil and gas prices; and (6) drilling and recompletion costs and results. Because of these uncertainties, we may defer drilling on, or never drill, some or all of these potential locations. If we defer drilling more than five years from the date proved undeveloped reserves were first assigned to a drilling location, we may be required under SEC guidelines to downgrade the category of the applicable reserves from proved undeveloped to probable. Any reclassification of reserves from proved undeveloped to probable could reduce our ability to borrow money and could reduce the value of our debt and equity securities. In 2014, we reclassified 4,911 MBOE of reserves from proved undeveloped to probable as a result of this 5-year development rule.

Price declines may result in impairments of our asset carrying values.

Commodity prices have a significant impact on the present value of our proved reserves. Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our oil and gas properties in certain situations. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required. Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.

Our exploration activities subject us to greater risks than development activities.

Generally, our oil and gas exploration activities pose a higher economic risk to us than our development activities. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to

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increasing oil or gas production from an area that is known to be productive by drilling additional wells, working over and recompleting existing wells and other production enhancement techniques. Exploration projects are identified through subjective analysis of geological and geophysical data, including the use of 3-D seismic and other available technology. By comparison, the identification of development prospects is significantly based upon existing production surrounding or adjacent to the proposed drilling site.

To the extent we engage in exploration activities, we have a greater risk of drilling dry holes or not finding oil and gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or gas is present or can be produced economically. We cannot assure you that any of our future exploration efforts will be successful. If these activities are unsuccessful, it will have a significant adverse effect on our results of operations, cash flows and capital resources.

Drilling oil and gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

Drilling oil and gas wells, including development wells, involves numerous risks, including the risk that we may not encounter economically productive oil or gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we are often uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:


•	unexpected drilling conditions;


•	title problems;


•	pressure or irregularities in formations;


•	equipment failures or accidents;


•	adverse weather conditions;


•	compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and


•	costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment and services.

If we do not encounter reserves that can be produced economically or if our drilling operations are curtailed, delayed or cancelled, it could have a significant adverse effect on our results of operations, cash flows and financial condition.

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.

Our ongoing business strategy includes growing our reserves and drilling inventory through acquisitions. Acquired properties can be subject to significant unknown liabilities. Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed.

Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write-down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity.

Our failure to integrate acquired properties successfully into our existing business could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

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The process of integrating acquired properties into our existing business may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of our existing business.

We may not be insured against all of the operating hazards to which our business is exposed.

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as windstorms, lightning strikes, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids (including fluids used in hydraulic fracturing activities), fires, severe weather and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations, all of which could result in a substantial loss. We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot give assurance of the continued availability of insurance at premium levels that justify its purchase.

Our business depends on oil and gas transportation facilities, most of which are owned by others.

The marketability of our oil and gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, maintenance and repair and general economic conditions could adversely affect our ability to produce, gather and transport oil and gas.

Future shortages of available drilling rigs, equipment and personnel may delay or restrict our operations.

The oil and gas industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies and personnel. During these periods, the costs and delivery times of drilling rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or personnel may increase drilling costs or delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Market conditions or operational impediments may hinder our access to oil and gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and gas processing or transportation arrangements may hinder our access to oil and gas markets or delay our production. The availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas, the proximity of reserves to pipelines and terminal facilities, competition for such facilities and the inability of such facilities to gather, transport or process our production due to shutdowns or curtailments arising from mechanical, operational or weather-related matters, including hurricanes and other severe weather conditions. Our ability to market our production depends in substantial part on the availability and capacity of gathering and transportation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could adversely affect our business, financial condition and results of operations. We may be required to shut-in or otherwise curtail production from wells due to lack of a market or inadequacy or unavailability of oil, gas or NGL pipeline or gathering, transportation or processing capacity. If that were to occur, then we would be unable to realize revenues from those wells until suitable arrangements were made to market our production.

Because we have no current plans to pay dividends on our Common Stock, investors must look solely to stock appreciation for a return on their investment in us.

We have never paid any cash dividends on our Common Stock, and the Board does not currently anticipate paying any cash dividends to our stockholders in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of the Board and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the Board deems relevant. Covenants contained in the credit facility and the Indenture restrict the payment of dividends. Investors must rely on sales of their Common Stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our Common Stock.

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Our industry is highly competitive.

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenues. The market for our oil, gas and NGL production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and NGL, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

Our success is highly dependent on our senior management. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

We are primarily controlled by Clayton W. Williams, Jr. and his children’s limited partnership.

Clayton W. Williams, Jr., age 83, beneficially owns, either individually or through his affiliates, approximately 26% of the outstanding shares of our Common Stock. Mr. Williams is also our Chairman of the Board, President and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of the Board members, and in all other facets of our business, including both our business strategy and daily operations.

WCPL, a limited partnership in which Mr. Williams’ adult children are the limited partners, owns an additional 25% of the outstanding shares of our Common Stock. Mel G. Riggs, our Executive Vice President and Chief Operating Officer, is the sole general partner of WCPL and has the power to vote or direct the voting of the shares held by WCPL. In voting these shares, Mr. Riggs will not be acting in his capacity as an officer and director of the Company and will consider the interests of WCPL and Mr. Williams’ children. They may have interests that differ from the interests of our other shareholders.

The retirement, incapacity or death of Mr. Williams, or any change in the power to vote shares beneficially owned by Mr. Williams or held by WCPL, could result in negative market or industry perception and could have a material adverse effect on our business.

By extending credit to our customers, we are exposed to potential economic loss.

We sell our oil and gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells and enter into derivatives with various counterparties. As appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. We cannot give assurance that we will not suffer any economic loss related to credit risks in the future.

Compliance with laws and regulations governing our activities could be costly and could negatively impact production.

Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

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All of the states in which we operate generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from our properties.

The FERC regulates interstate gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

Our sales of oil and NGL are not presently regulated and are made at market prices. The price we receive from the sale of these products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil and NGL.

Under the EP Act 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our gas operations have not been regulated by the FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Our oil and gas exploration and production and related activities are subject to extensive environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.

Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the emission and discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate. Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws regardless of fault. Under a number of environmental laws, such liabilities may also be strict, joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs, as well as the issuance of administrative or judicial orders limiting operations or prohibiting certain activities. Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation. Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas. Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants. In addition, claims are sometimes made or threatened against companies engaged in oil and gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired. Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.

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Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of proposed legislation.

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively impact the value of an investment in our Common Stock.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and gas that we produce.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, including emissions of greenhouse gases from certain large stationary sources. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including certain onshore oil and gas production facilities, on an annual basis.

In addition, from time to time Congress has considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

The adoption of legislation or regulatory programs to reduce emission of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emission control systems, to acquire emission allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the U.S. District Court for the District of Columbia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definitions of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to

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be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects.

The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral that could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial condition and results of operations.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand, and chemicals under pressure into dense subsurface rock formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel, and in February 2014, issued permitting guidance for such activities. Also, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA has indicated that it expects to issue its study report in the first half of 2015. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards sometime in 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their findings, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from various sources for use in our operations. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

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A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.

A terrorist attack, anti-terrorist efforts or other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Item 1B - Unresolved Staff Comments

Not applicable.

Item 2 - Properties

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. At December 31, 2014, we had interests in 3,190 gross (1,491.9 net) oil and gas wells and owned leasehold interests in approximately 680,000 gross (373,000 net) undeveloped acres.

Reserves

The following table sets forth our estimated quantities of proved reserves as of December 31, 2014, all of which are located within the United States.



	Proved Reserves^(a)
		Natural Gas	Natural	Total Oil
	Oil	Liquids	Gas	Equivalents^(b)
Reserve Category	(MBbls)	(MBbls)	(MMcf)	(MBOE)
Developed	29,059	4,668	51,072	42,239
Undeveloped	24,808	4,299	24,503	33,191
Total Proved	53,867	8,967	75,575	75,430

_______


(a)	None of our oil and gas reserves are derived from non-traditional sources.


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

The present value of our future net cash flows from proved reserves, before deductions for estimated future income taxes and asset retirement obligations, discounted at 10% (“PV-10”), totaled $1.4 billion at December 31, 2014. The commodity prices used to estimate proved reserves and their related PV-10 at December 31, 2014 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from January 2014 through December 2014. The benchmark average prices for 2014 were $94.99 per barrel of oil and $4.35 per MMBtu of natural gas. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $90.48 per barrel of oil, $31.54 per barrel of NGL and $4.27 per Mcf of natural gas over the remaining life of our proved reserves. Operating costs were not escalated.

Adjustments to benchmark average prices, which are generally referred to as price differentials, were computed on a property-by-property basis by comparing historical first-day-of-the-month benchmark prices for oil and gas to the historical prices for oil, NGL and gas actually received by us. Historical price differentials vary by property based on each property’s production and marketing situation and include:


•	area-specific market adjustments, referred to as basis differentials, for oil, natural gas and NGL as discussed under “Item 1 — Business — Marketing Arrangements;”


•	gravity, hydrogen sulfide content and other quality characteristics of produced oil;

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•	the volume of processed NGL derived from our natural gas production, including the mix of the NGL components between ethane, propane, butane and natural gasoline;


•	the Btu content of natural gas production and the value of any imbedded NGL components that are reported as natural gas sales; and


•	the amount of transportation and marketing fees levied on oil, gas and NGL production, which vary based on factors such as the distance of a property from its delivery point, available markets and other pricing adjustments that vary from contract to contract.

Price differentials per barrel of oil and NGL and per Mcf of natural gas are subject to change and may vary materially in the future from the computed price differentials at December 31, 2014. Adverse changes in our price differentials could reduce our cash flow from operations and the PV-10 of our proved reserves.

PV-10 is not a generally accepted accounting principle (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our consolidated financial statements. To compute our standardized measure of discounted future net cash flows at December 31, 2014, we began with the PV-10 of our proved reserves and deducted the present value of estimated future income taxes of $412.6 million and net abandonment costs of $34.5 million, discounted at 10%. At December 31, 2014, our standardized measure of discounted future net cash flows totaled $932.9 million. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each company, the PV-10 of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis.

The following table summarizes certain information as of December 31, 2014 regarding our estimated proved reserves in each of our principal producing areas.



	Proved Reserves								PV-10 as a
		Natural Gas	Natural	Total Oil	Percent of		PV-10 of		Percentage of
	Oil (MBbls)	Liquids (MBbls)	Gas (MMcf)	Equivalents^(a) (MBOE)	Total Oil Equivalents		Proved Reserves		Proved Reserves
							(In thousands)
Permian Basin Area:
Delaware Basin	19,665	3,780	21,539	27,035	35.8	%	$	392,197	28.4	%
Other	14,310	3,620	32,335	23,319	30.9	%	422,376		30.6	%
Austin Chalk	5,310	506	5,600	6,749	8.9	%	201,680		14.6	%
Eagle Ford Shale	13,815	984	4,090	15,481	20.5	%	308,307		22.3	%
Other	767	77	12,011	2,846	3.9	%	55,419		4.1	%
Total	53,867	8,967	75,575	75,430	100	%	$	1,379,979	100.0	%

_______


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

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The following table summarizes changes in our estimated proved reserves during 2014.



	Proved
	Reserves
	(MBOE)
As of December 31, 2013	70,015
Extensions and discoveries	23,336
Revisions	(10,101	)
Sales of minerals-in-place	(2,057	)
Production	(5,763	)
As of December 31, 2014	75,430

Extensions and discoveries. Extensions and discoveries in 2014 added 23,336 MBOE of proved reserves, replacing 405% of our 2014 production. These additions resulted primarily from our Giddings Eagle Ford and Delaware Basin programs. Of the total reserve additions, proved developed reserves accounted for 6,998 MBOE, while the remaining 16,338 MBOE were proved undeveloped reserves.

Revisions. The 10,101 MBOE net downward revisions in proved reserves resulted from a combination of (1) reclassifications of 4,911 MBOE of proved undeveloped reserves to probable reserves due solely to the SEC 5-year development rule, (2) other net downward revisions of 4,837 MBOE related primarily to proved undeveloped reserves associated with vertical locations in Reeves County, Texas originally assigned prior to our conversion to horizontal drilling in this area, and (3) downward revisions of 353 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves.

Sales of minerals-in-place. We sold our interests in certain non-core Austin Chalk/Eagle Ford assets in March 2014 resulting in a decrease of 2,057 MBOE.

The following table summarizes changes in our estimated proved undeveloped reserves during 2014.



	Proved
	Undeveloped
	Reserves
	(MBOE)
As of December 31, 2013	31,760
Extensions and discoveries	16,338
Revisions	(12,425	)
Sales of minerals-in-place	(343	)
Reclassified to proved developed	(2,139	)
As of December 31, 2014	33,191

We added 16,338 MBOE of proved undeveloped reserves from extensions and discoveries related to Permian Basin and Eagle Ford drilling locations. Net downward revisions of 12,425 MBOE resulted primarily from the combination of 4,911 MBOE of proved undeveloped reserves to probable reserves due solely to the SEC 5-year development rule and other net downward revisions related primarily to vertical locations in Reeves County, Texas originally assigned prior to our conversion to horizontal drilling in this area. During 2014, we also converted 2,139 MBOE of proved undeveloped reserves at December 31, 2013 to proved developed reserves at a cost of approximately $46.9 million. Based on the drilling schedule set forth in our reserve reports, we would expect to develop approximately 15.1% of our proved undeveloped reserves in 2015 at a cost of approximately $103.4 million. Our actual drilling schedule may differ from the one presented in our reserve reports as we continue to monitor the effects of the current downturn in oil prices on our business.

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Alternative pricing cases

In addition to the estimated proved reserves disclosed above in accordance with the commodities pricing required by the reserves rule (the “SEC Case”), the following table compares certain information regarding our SEC proved reserves to a Futures Pricing Case.



	Proved Reserves
		Natural Gas	Natural	Total Oil
	Oil	Liquids	Gas	Equivalents^(a)
Pricing Cases	(MBbls)	(MBbls)	(MMcf)	(MBOE)	PV-10
					(In thousands)
SEC Case	53,867	8,967	75,575	75,430	$	1,379,979
Futures Pricing Case	46,650	7,456	64,277	64,819	$	778,824

_______


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

Futures Pricing Case. The Futures Pricing Case discloses our estimated proved reserves using future market-based commodities prices instead of the average historical prices used in the SEC Case. Under the Futures Pricing Case, we used futures prices, as quoted on the NYMEX on December 31, 2014, as benchmark prices for 2015 through 2019, and continued to use the 2019 futures price for all subsequent years. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $64.61 per barrel of oil, $22.58 per barrel of NGL and $3.85 per Mcf of natural gas over the remaining life of the proved reserves. Costs were adjusted to reflect expected reductions in capital costs and well operating costs consistent with the projected price environment.

Reserve estimation procedures

Overview

We have established a system of internal controls over our reserve estimation process, which we believe provides us reasonable assurance that reserve estimates have been prepared in accordance with the SEC and Financial Accounting Standards Board (the “FASB”) standards. These controls include oversight by trained technical personnel employed by us and by the use of qualified independent petroleum engineers to evaluate our proved reserves on an annual basis. Substantially all of our estimated proved reserves as of December 31, 2014 were derived from engineering evaluation reports prepared by Williamson Petroleum Consultants, Inc. (“Williamson”) and Ryder Scott Company, L.P. (“Ryder Scott”). Of our total SEC Case estimated proved reserves, Williamson evaluated 73.2% and Ryder Scott evaluated 25% on a BOE basis.

Qualifications of technical manager and consultants

Ronald D. Gasser, our Vice President — Engineering, is the person within the Company who is primarily responsible for overseeing the preparation of the reserve estimates. Mr. Gasser joined the Company in 2002 as a Senior Engineer working on acquisitions/divestitures and special projects, became Engineering Manager in 2006 and was promoted to his current position as Vice President — Engineering in October 2012. Mr. Gasser has 32 years experience as a petroleum engineer, including 29 years directly involved in the estimation and evaluation of oil and gas reserves. Mr. Gasser holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University. He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.

Williamson is an independent petroleum engineering consulting firm registered in the State of Texas, and John D. Savage, Executive Vice President — Engineering Manager of Williamson, is the technical person primarily responsible for evaluating the proved reserves covered by its report. Mr. Savage has 33 years experience in evaluating oil and gas reserves, including 31 years experience as a consulting reservoir engineer. Mr. Savage holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers and the Society of Independent Professional Earth Scientists.

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 75 years. William K. Fry, Vice President of Ryder Scott, is the technical person primarily responsible for evaluating the proved reserves covered by its report. Mr. Fry has over 30 years of experience in the estimation and evaluation

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of petroleum reserves. Mr. Fry holds a Bachelor of Science degree in Mechanical Engineering from Kansas State University. He is a Registered Professional Engineer in the State of Texas.

Technology used to establish proved reserves

Under current SEC standards, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and governmental regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. “Reliable technology” is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability. The technological data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Generally, oil and gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations. Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technological data to assess the reservoir continuity. In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities. Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data. When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of oil and gas derived through volumetric calculations.

Virtually all of our additions to proved reserves in 2014 were derived from wells drilled in the Permian Basin and the Giddings Area. A significant amount of technological data is available in these areas, which allows us to estimate with reasonable certainty the proved reserves and production decline rates attributable to most of our reserve additions through analogy to historical performance from wells in the same reservoirs. None of our additions to proved reserves for 2014 were estimated solely on volumetric calculations.

Processes and controls

Mr. Gasser and his engineering staff maintain a reserves database covering substantially all of our oil and gas properties utilizing Aries™, a widely used reserves and economics software package licensed by a unit of Halliburton Company. Some of our properties are not evaluated since they are individually and collectively insignificant to our total proved reserves and related PV-10. Our engineering staff assimilates all technological and operational data necessary to evaluate our reserves and updates the reserves database throughout the year. Technological data is described above under “—Technology used to establish proved reserves.” Operational data include ownership interests, product prices, operating expenses and future development costs.

Using the most appropriate method available, Mr. Gasser applies his professional judgment, based on his training and experience, to project a production profile for each evaluated property. Mr. Gasser consults with other engineers and geoscientists within the Company as needed to validate the accuracy and completeness of his estimates and to determine if any of the technological data upon which his estimates were based are incorrect or outdated.

The engineering staff consults with our accounting department to validate the accuracy and completeness of certain operational data maintained in the reserves database, including ownership interests, average commodity prices, price differentials and operating costs.

Although we believe that the estimates of reserves prepared by our engineering staff have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage independent petroleum engineering consultants to prepare annual evaluations of our estimated reserves. After Mr. Gasser and our engineering staff have made an internal evaluation of our estimated reserves, we provide copies of the Aries™ reserves database to Ryder Scott as it relates to properties owned by our wholly owned subsidiary, SWR and to Williamson as it relates to properties owned by CWEI and our

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wholly owned subsidiary, Warrior Gas Company. In addition, we provide to the consultants for their analysis all pertinent data needed to properly evaluate our reserves. The services provided by Williamson and Ryder Scott are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about the evaluations performed by Williamson and Ryder Scott, see copies of their respective reports filed as exhibits to this Form 10-K.

Both Williamson and Ryder Scott use the Aries™ reserves database that we provide to them as a starting point for their evaluations. This process reduces the risk of errors that can result from data input and also results in significant cost savings to us. The petroleum engineering consultants generally rely on the technical and operational data provided to them without independent verification; however, in the course of their evaluation, if any issue comes to their attention that questions the validity or sufficiency of that data, the consultants will not rely on the questionable data until they have resolved the issue to their satisfaction. The consultants analyze each production decline curve to determine if they agree with our interpretation of the underlying technical data. If they arrive at a different conclusion, the consultants revise the estimates in the database to reflect their own interpretations.

After Williamson and Ryder Scott complete their respective evaluations, they return a modified Aries™ reserves database to our engineering staff for review. Mr. Gasser identifies all material variances between our initial estimates and those of the consultants and discusses the variances with Williamson or Ryder Scott, as applicable, in order to resolve the discrepancies. If any variances relate to inaccurate or incomplete data, corrected or additional data is provided to the consultants and the related estimates are revised. When variances are caused solely by judgment differences between Mr. Gasser and the consultants, we accept the estimates of the consultants.

The final reserve estimates are then analyzed by our financial accounting group under the direction of Michael L. Pollard, our Senior Vice President and Chief Financial Officer. The group reconciles changes in reserve estimates during the year by source, consisting of changes due to extensions and discoveries, purchases/sales of minerals-in-place, revisions of previous estimates and production. Revisions of previous estimates are further analyzed by changes related to pricing and changes related to performance. All material fluctuations in reserve quantities identified through this analysis are discussed with Mr. Gasser. Although unlikely, if an error in the estimated reserves is discovered through this review process, Mr. Gasser will submit the facts related to the error to the appropriate consultant for correction prior to the public release of the estimated reserves.

Other information concerning our proved reserves

The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and PV-10 are based on various assumptions and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Since January 1, 2014, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.

Delivery Commitments

As of December 31, 2014, we had no commitments to provide fixed and determinable quantities of oil or natural gas in the near future under contracts or agreements, other than through customary marketing arrangements that require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.

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Exploration and Development Activities

We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.



	Year Ended December 31,
	2014		2013		2012
	Gross	Net	Gross	Net	Gross	Net
	(Excludes wells in progress at the end of any period)
Development Wells:
Oil	153	49.0	117	49.4	135	87.3
Gas	—	—	1	—	—	—
Dry	1	0.1	1	0.7	5	5.0
Total	154	49.1	119	50.1	140	92.3
Exploratory Wells:
Oil	3	1.7	2	0.6	5	3.8
Gas	—	—	3	0.6	—	—
Dry	7	5.0	4	2.5	1	0.5
Total	10	6.7	9	3.7	6	4.3
Total Wells:
Oil	156	50.7	119	50.0	140	91.1
Gas	—	—	4	0.6	—	—
Dry	8	5.1	5	3.2	6	5.5
Total	164	55.8	128	53.8	146	96.6

The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.

Productive Well Summary

The following table sets forth certain information regarding our ownership, as of December 31, 2014, of productive wells in the areas indicated.



	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Permian Basin Area:
Delaware Basin	112	88.9	—	—	112	88.9
Other	2,311	1,002.3	315	64.8	2,626	1,067.1
Austin Chalk	300	249.3	16	9.7	316	259.0
Eagle Ford Shale	31	31.0	1	1.0	32	32.0
Other	48	17.9	56	27.0	104	44.9
Total	2,802	1,389.4	388	102.5	3,190	1,491.9

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Volumes, Prices and Production Costs

All of our oil and gas properties are located in one geographical area, specifically the United States. The following table sets forth certain information regarding the production volumes of, average sales prices received from and average production costs associated with all of our sales of oil and gas production for the periods indicated.



	Year Ended December 31,
	2014		2013		2012
Oil and Gas Production Data:
Oil (MBbls)	4,194		3,692		3,821
Gas (MMcf)	5,901		6,188		8,072
Natural gas liquids (MBbls)	585		532		433
Total (MBOE)^(a)	5,763		5,255		5,599
Total (BOE/d)	15,788		14,399		15,299
Average Realized Prices^{(b) (c)}:
Oil ($/Bbl)	$	86.81	$	95.05	$	90.97
Gas ($/Mcf)	$	4.35	$	3.59	$	3.59
Natural gas liquids ($/Bbl)	$	32.17	$	33.26	$	38.95
Average Production Costs:
Production ($/MBOE)^(d)	$	12.71	$	14.68	$	16.69

_______


(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 for 2014 include $7.7 million for the year ended December 31, 2014, $8.7 million for the year ended December 31, 2013 and $8.3 million for the year ended December 31, 2012 of amortized deferred revenue attributable to the volumetric production payment (the “VPP”) granted effective March 1, 2012. The calculation of average realized sales prices for 2014 excludes production of 102,011 barrels of oil and 45,392 Mcf of gas for the year ended December 31, 2014, 116,941 barrels of oil and 33,619 Mcf of gas for the year ended December 31, 2013 and 109,733 barrels of oil and 49,558 Mcf of gas for the year ended December 31, 2012 associated with the VPP.


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


(d)	Excludes property taxes and severance taxes.

Only two fields, the Giddings field and the Wolfbone Trend field in the Permian Basin, accounted for 15% or more of our total proved reserves (on a BOE basis) as of December 31, 2014. The following table discloses our oil, gas and NGL production from these fields for the periods indicated.



	Year Ended December 31,
	2014	2013	2012
Oil and Gas Production Data:
Giddings Field
Oil (MBbls)	1,639	1,203	985
Gas (MMcf)	738	683	674
Natural gas liquids (MBbls)	105	82	87
Total (MBOE) ^(a)	1,867	1,399	1,184
Wolfbone Trend Field
Oil (MBbls)	1,156	761	610
Gas (MMcf)	953	645	334
Natural gas liquids (MBbls)	158	117	63
Total (MBOE) ^(a)	1,473	986	729

_______

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

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Development, Exploration and Acquisition Expenditures

The following table sets forth certain information regarding the costs we incurred in our development, exploration and acquisition activities during the periods indicated.



	Year Ended December 31,
	2014		2013		2012
	(In thousands)
Property Acquisitions:
Proved	$	—	$	—	$	41,098
Unproved	56,327		50,104		72,235
Developmental Costs	342,716		218,341		349,972
Exploratory Costs	4,350		3,932		10,898
Total	$	403,393	$	272,377	$	474,203

Acreage

The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2014 in the areas indicated. This table excludes options to acquire leases and acreage in which our interest is limited to royalty, overriding royalty and similar interests.



	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Permian Basin	138,662	65,801	331,118	173,707	469,780	239,508
Giddings Area	145,977	133,428	67,372	49,783	213,349	183,211
Other^(a)	8,018	4,410	281,578	149,565	289,596	153,975
Total	292,657	203,639	680,068	373,055	972,725	576,694

_______


(a)	Net undeveloped acres are attributable to the following areas: Utah — 44,850; Colorado — 29,804; Alabama — 17,155; Oklahoma — 9,112; Nevada — 8,535; Louisiana — 8,282; Mississippi — 6,337; and Other — 25,490.

The following table sets forth expiration dates of the leases of our gross and net undeveloped acres as of December 31, 2014.



	Acres Expiring^(a)
	2015		2016		2017
	Gross	Net	Gross	Net	Gross	Net
Permian Basin	31,946	22,205	27,047	16,876	12,361	10,369
Giddings Area	16,162	13,226	27,816	21,854	4,399	3,289
Other	57,558	36,578	75,887	64,371	49,593	45,773
	105,666	72,009	130,750	103,101	66,353	59,431

_______


(a)	Acres expiring are based on contractual lease maturities. We may extend the leases prior to their expiration based upon planned activities or for other business activities.

Desta Drilling

Through our wholly owned subsidiary, Desta Drilling, we operate 14 drilling rigs, two of which we lease under long-term contracts. We believe that owning and operating our own rigs helps us control our cost structure while providing us flexibility to take advantage of drilling opportunities on a timely basis. The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties. Due to the downturn in oil prices discussed under “Item 1 — Business — Company Profile — Recent Developments,” all 14 rigs are currently idle.

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Offices

We lease approximately 89,000 square feet of office space in Midland, Texas from a related partnership for our corporate headquarters. We also lease approximately 7,100 square feet of office space in Houston, Texas and 1,800 square feet in College Station, Texas from unaffiliated third parties.

Item 3 - Legal Proceedings

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

In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under our farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”). Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. In October 2013, a judge ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million. A loss of $1.4 million was recorded for the year ended December 31, 2013 in connection with the judgment. CWEI is appealing the judgment. All appellate briefs have been filed with the El Paso Court of Appeals, and argument has been scheduled for June 4, 2015.

CWEI has been named a defendant in two lawsuits filed in Louisiana by Plaquemines Parish, each alleging that historical industry operations have significantly damaged coastal marsh lands.

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 area of operations, 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. On December 1, 2014, one of the two coastal cases (61-002) was remanded back to state court. Coastal case 60-982 remains in federal court, pending an order on the Plaintiff’s motion to remand.

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

Item 4 - Mine Safety Disclosures

Not applicable.

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PART II

Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Price Range of Common Stock

As of December 30, 2013, we transferred the listing of our shares of Common Stock from the NASDAQ Global Select Market (“NASDAQ”) to the New York Stock Exchange (the “NYSE”). Our Common Stock is quoted on the NYSE under the symbol “CWEI.” As of February 18, 2015, there were approximately 3,361 beneficial stockholders as reflected in security position listings. The following table sets forth, for the periods indicated, the high and low sales prices for our Common Stock, as reported on NASDAQ or the NYSE as applicable:



	High		Low
Year Ended December 31, 2014:
Fourth Quarter	$	99.16	$	49.71
Third Quarter	142.28		95.79
Second Quarter	146.93		109.10
First Quarter	114.46		65.88
Year Ended December 31, 2013:
Fourth Quarter	$	85.05	$	52.30
Third Quarter	59.10		42.47
Second Quarter	45.83		37.15
First Quarter	46.50		35.30

The closing price of our Common Stock at February 26, 2015 was $52.79 per share.

Dividend Policy

We have never paid any cash dividends on our Common Stock, and the Board does not currently anticipate paying any cash dividends to our stockholders in the foreseeable future. In addition, the terms of the credit facility and the Indenture restrict the payment of cash dividends.

Securities Authorized for Issuance under Equity Compensation Plans

For information concerning shares available for issuance under equity compensation plans, see “Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” which is to be incorporated by reference to our definitive proxy statement relating to the 2015 Annual Meeting of Stockholders.

Item 6 - Selected Financial Data

The following table sets forth selected consolidated financial data for CWEI as of the dates and for the periods indicated. The consolidated financial data for each of the years in the five-year period ended December 31, 2014 were derived from our audited consolidated financial statements. The data set forth in this table should be read in conjunction with “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the accompanying consolidated financial statements, including the notes thereto.

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	Year Ended December 31,
	2014			2013			2012			2011			2010
	(In thousands, except per share)
Statement of Operations Data:
Revenues:
Oil and gas sales	$	418,330		$	399,950		$	403,143		$	405,216		$	326,320
Midstream services	6,705			4,965			1,974			1,408			1,631
Drilling rig services	28,028			17,812			15,858			4,060			—
Other operating revenues	15,393			6,488			2,077			15,744			3,680
Total revenues	468,456			429,215			423,052			426,428			331,631
Costs and expenses:
Production	105,296			108,405			124,950			101,099			83,146
Exploration:
Abandonment and impairments	20,647			5,887			4,222			20,840			9,074
Seismic and other	2,314			3,906			11,591			5,363			6,046
Midstream services	2,212			1,816			1,228			1,039			1,209
Drilling rig services	19,232			16,290			17,423			5,064			1,198
Depreciation, depletion and amortization	154,356			150,902			142,687			104,880			101,145
Impairment of property and equipment	12,027			89,811			5,944			10,355			11,908
Accretion of asset retirement obligations	3,662			4,203			3,696			2,757			2,623
General and administrative	34,524			33,279			30,485			41,560			35,588
Other operating expenses	2,547			2,101			1,033			1,666			1,750
Total costs and expenses	356,817			416,600			343,259			294,623			253,687
Operating income	111,639			12,615			79,793			131,805			77,944
Other income (expense):
Interest expense	(50,907		)	(43,079		)	(38,664		)	(32,919		)	(24,402		)
Loss on early extinguishment of long-term debt	—			—			—			(5,501		)	—
Gain (loss) on derivatives	4,789			(8,731		)	14,448			47,027			722
Other income	3,047			1,905			1,534			5,553			3,308
Total other income (expense)	(43,071		)	(49,905		)	(22,682		)	14,160			(20,372		)
Income (loss) before income taxes	68,568			(37,290		)	57,111			145,965			57,572
Income tax (expense) benefit	(24,687		)	12,428			(22,008		)	(52,142		)	(20,634		)
NET INCOME (LOSS)	$	43,881		$	(24,862	)	$	35,103		$	93,823		$	36,938
Net income (loss) per common share:
Basic	$	3.61		$	(2.04	)	$	2.89		$	7.72		$	3.04
Diluted	$	3.61		$	(2.04	)	$	2.89		$	7.71		$	3.04
Weighted average common shares outstanding:
Basic	12,167			12,165			12,164			12,161			12,148
Diluted	12,167			12,165			12,164			12,162			12,148
Other Data:
Net cash provided by operating activities	$	258,121		$	220,576		$	189,222		$	280,047		$	208,251

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	December 31,
	2014			2013		2012		2011			2010
	(In thousands)
Balance Sheet Data:
Working capital (deficit)	$	(23,733	)	$	1,916	$	3,556	$	(13,287	)	$	(19,899	)
Total assets	1,510,885			1,366,737		1,574,584		1,226,271			890,917
Long-term debt	704,696			639,638		809,585		529,535			385,000
Stockholders’ equity	397,794			353,783		378,616		343,501			249,452

Item 7 - 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 the accompanying consolidated financial statements, including the notes thereto.

Overview

Throughout 2014, we continued our developmental drilling in two primary oil-prone regions, the Permian Basin and Giddings Area, where we have a significant inventory of developmental drilling opportunities. We spent approximately $174.2 million in the Wolfbone area in Reeves County, Texas in 2014 on drilling, completion and leasing activities and currently plan to spend approximately $46.2 million in this area in 2015.

We are continuing to exploit our extensive acreage position in the Giddings Area. Since July 2011, we have completed 41 horizontal Eagle Ford Shale wells. In 2014, we spent approximately $188.1 million on Austin Chalk/Eagle Ford Shale drilling and leasing activities and currently plan to spend approximately $44.4 million in this area in 2015.

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Key Factors to Consider

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2014.


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

•

Oil and gas sales, excluding amortized deferred revenues, increased $19.4 million, or 5%, from 2013. Production variances accounted for an increase of $50.3 million and price variances accounted for a decrease of $30.9 million. Average realized oil prices were $86.81 per barrel in 2014 versus $95.05 per barrel in 2013, average realized gas prices were $4.35 per Mcf in 2014 versus $3.59 per Mcf in 2013, and average realized NGL prices were $32.17 per barrel in 2014 versus $33.26 per barrel in 2013. Oil and gas sales in 2014 also include $7.7 million of amortized deferred revenue versus $8.7 million in 2013 attributable to the VPP granted effective March 1, 2012. Reported production and related average realized sales prices exclude volumes associated with the VPP.

•

Before giving effect to the asset sales discussed above, oil, gas and NGL production per BOE increased 10% compared to 2013, with oil production increasing 14% to 11,490 barrels per day, gas production decreasing 5% to 16,167 Mcf per day and NGL production increasing 10% to 1,603 barrels per day. Oil and NGL production accounted for approximately 83% of our total BOE production in 2014 versus 80% in 2013.


•	After giving effect to the asset sales, total production on a BOE basis increased 21% for 2014 as compared to 2013, with oil production increasing 2,457 barrels per day (27%), gas production decreasing 206 Mcf per day (1%) and NGL production increasing 260 barrels per day (19%).


•	Production costs decreased 3% from $108.4 million in 2013 to $105.3 million in 2014 due primarily to a reduction in operating costs associated with the Austin Chalk/Eagle Ford and Andrews County Wolfberry sales, offset in part by increased production taxes related to the increase in oil and gas sales.

•

We recorded a $4.8 million gain on derivatives in 2014 (including a $7.1 million gain on settled contracts). For 2013, we recorded an $8.7 million loss on derivatives (net of a $0.7 million gain on settled contracts). Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.


•	Interest expense increased to $50.9 million in 2014 from $43.1 million in 2013 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of 7.75% Senior Notes due 2019.

•

We recorded a provision for impairment of property and equipment during 2014 of $12 million related to certain non-core properties located in the Permian Basin and North Dakota to reduce the carrying value of these properties to their estimated fair values. During 2013, we recorded an impairment of property and equipment of $89.8 million related to the transaction to monetize our Andrews County Wolfberry assets and certain non-core Permian Basin properties to reduce the carrying value of those properties to their estimated fair values.


•	We recorded exploration expense related to abandonment and impairment costs during 2014 of $20.6 million compared to $5.9 million in 2013. The expense for 2014 includes a charge of $8.6 million related to unproved leasehold impairments in California and $2.4 million for the abandonment of an exploratory well in South Louisiana.


•	General and administrative (“G&A”) expenses for 2014 were $34.5 million compared to $33.3 million in 2013. Changes in compensation expense attributable to our APO reward plans accounted for a net increase of $2.5 million ($4.6 million in 2014 versus $2.1 million in 2013) offset by lower professional costs in 2014.


•	Our estimated proved oil and gas reserves at December 31, 2014 increased 8% to 75,430 MBOE from 70,015 MBOE at December 31, 2013. We replaced 405% of our oil and gas production in 2014 through extensions and discoveries of 23,336 MBOE, had net downward revisions of 10,101 MBOE and sales of minerals-in-place of 2,057 MBOE (see “Item 2 — Properties — Reserves”).

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Proved Oil and Gas Reserves

The following table summarizes changes in our estimated proved reserves during 2014.



	Proved
	Reserves
	(MBOE)
As of December 31, 2013	70,015
Extensions and discoveries	23,336
Revisions	(10,101	)
Sales of minerals-in-place	(2,057	)
Production	(5,763	)
As of December 31, 2014	75,430

Sales of minerals-in-place. We sold our interests in certain non-core Austin Chalk/Eagle Ford assets in March 2014 resulting in a decrease of 2,057 MBOE.

The following table summarizes changes in our estimated proved undeveloped reserves during 2014.



	Proved
	Undeveloped
	Reserves
	(MBOE)
As of December 31, 2013	31,760
Extensions and discoveries	16,338
Revisions	(12,425	)
Sales of minerals-in-place	(343	)
Reclassified to proved developed	(2,139	)
As of December 31, 2014	33,191

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Supplemental Information

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



	As of or for the Year Ended December 31,
	2014		2013			2012
Oil and Gas Production Data:
Oil (MBbls)	4,194		3,692			3,821
Natural Gas (MMcf)	5,901		6,188			8,072
Natural gas liquids (MBbls)	585		532			433
Total (MBOE) ^(a)	5,763		5,255			5,599
Total (BOE/d)	15,788		14,399			15,299

Average Realized Prices ^{(b) (c)}:
Oil ($/Bbl)	$	86.81	$	95.05		$	90.97
Natural Gas ($/Mcf)	$	4.35	$	3.59		$	3.59
Natural gas liquids ($/Bbl)	$	32.17	$	33.26		$	38.95

Gain (Loss) on Settled Derivative Contracts^(c):
($ in thousands, except per unit)
Oil: Cash settlements paid	$	7,099	$	1,162		$	(3,410	)
Per unit produced ($/Bbl)	$	1.69	$	0.31		$	(0.89	)
Natural Gas: Cash settlements paid	$	—	$	(472	)	$	—
Per unit produced ($/Mcf)	$	—	$	(0.08	)	$	—

Average Daily Production:
Oil (Bbls):
Permian Basin Area:
Delaware Basin	3,224		2,127			1,656
Other ^(d)	3,286		3,952			5,369
Austin Chalk ^(d)	2,033		2,581			2,728
Eagle Ford Shale ^(d)	2,529		1,136			346
Other	418		319			341
Total	11,490		10,115			10,440

Natural Gas (Mcf):
Permian Basin Area:
Delaware Basin	2,671		1,720			910
Other ^{(d) (e)}	6,932		7,963			12,560
Austin Chalk ^(d)	1,766		2,043			2,029
Eagle Ford Shale ^(d)	464		78			5
Other	4,334		5,149			6,551
Total	16,167		16,953			22,055
(Continued)

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	As of or for the Year Ended December 31,
	2014		2013		2012
Natural Gas Liquids (Bbls):
Permian Basin Area:
Delaware Basin	449		316		168
Other ^{(d) (e)}	820		880		693
Austin Chalk ^(d)	189		223		267
Eagle Ford Shale ^(d)	111		19		—
Other	34		20		55
Total	1,603		1,458		1,183

BOE:
Permian Basin Area:
Delaware Basin	4,118		2,730		1,976
Other ^{(d) (e)}	5,261		6,159		8,155
Austin Chalk ^(d)	2,517		3,145		3,333
Eagle Ford Shale ^(d)	2,717		1,168		347
Other	1,175		1,197		1,488
Total	15,788		14,399		15,299

Total Proved Reserves:
Oil (MBbls)	53,867		48,665		49,119
Natural gas liquids (MBbls)	8,967		8,487		9,182
Natural Gas (MMcf)	75,575		77,179		102,336
Total (MBOE) ^(a)	75,430		70,015		75,357
Standardized measure of discounted future net cash flows	$	932,913	$	926,923	$	939,831

Total Proved Reserves by Area:
Oil (MBbls):
Permian Basin Area:
Delaware Basin	19,665		18,675		14,618
Other	14,310		17,081		25,955
Austin Chalk	5,310		6,993		6,846
Eagle Ford Shale	13,815		5,355		1,193
Other	767		561		507
Total	53,867		48,665		49,119

Natural Gas Liquids (MBbls):
Permian Basin Area:
Delaware Basin	3,780		3,756		4,249
Other	3,620		4,078		4,345
Austin Chalk	506		580		572
Eagle Ford Shale	984		28		—
Other	77		45		16
Total	8,967		8,487		9,182
(Continued)

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	As of or for the Year Ended December 31,
	2014		2013		2012
Natural Gas (MMcf):
Permian Basin Area:
Delaware Basin	21,539		21,532		20,651
Other	32,335		36,194		64,727
Austin Chalk	5,600		6,099		5,862
Eagle Ford Shale	4,090		2,472		268
Other	12,011		10,882		10,828
Total	75,575		77,179		102,336

Total Oil Equivalents (MBOE) ^(a):
Permian Basin Area:
Delaware Basin	27,035		26,020		22,309
Other	23,319		27,190		41,087
Austin Chalk	6,749		8,590		8,395
Eagle Ford Shale	15,481		5,795		1,238
Other	2,846		2,420		2,328
Total	75,430		70,015		75,357

Exploration Costs (in thousands):
Abandonment and impairment costs:
California	$	8,559	$	—	$	—
Oklahoma	4,937		—		—
South Louisiana	2,957		1,000		1,918
Michigan	1,129		—		—
North Louisiana	994		—		—
Permian Basin	584		2,047		453
Deep Bossier	—		—		1,323
Other	1,487		2,840		528
Total	20,647		5,887		4,222
Seismic and other	2,314		3,906		11,591
Total exploration costs	$	22,961	$	9,793	$	15,813

Depreciation, Depletion and Amortization (in thousands):
Oil and gas depletion	$	142,543	$	137,295	$	133,488
Contract drilling depreciation	9,219		11,253		7,664
Other depreciation	2,594		2,354		1,535
Total depreciation, depletion and amortization	$	154,356	$	150,902	$	142,687

Oil and Gas Costs ($/BOE Produced):
Production costs	$	18.27	$	20.63	$	22.32
Production costs (excluding production taxes)	$	14.57	$	16.75	$	18.70
Oil and gas depletion	$	24.73	$	26.13	$	23.84
(Continued)

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	As of or for the Year Ended December 31,
	2014	2013	2012
Net Wells Drilled^(f):
Developmental wells	49.1	50.1	92.3
Exploratory wells	6.7	3.7	4.3

_______


(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 for 2014 include $7.7 million for the year ended December 31, 2014, $8.7 million for the year ended December 31, 2013 and $8.3 million for the year ended December 31, 2012 of amortized deferred revenue attributable to the VPP granted effective March 1, 2012. The calculation of average realized sales prices for 2014 excludes production of 102,011 barrels of oil and 45,392 Mcf of gas for the year ended December 31, 2014, 116,941 barrels of oil and 33,619 Mcf of gas for the year ended December 31, 2013 and 109,733 barrels of oil and 49,558 Mcf of gas for the year ended December 31, 2012 associated with the VPP.


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


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



	Year Ended December 31,
	2014	2013	2012
Average Daily Production:

Austin Chalk/Eagle Ford:
Oil (Bbls)	93	773	373
Natural gas (Mcf)	11	121	72
NGL (Bbls)	3	25	12
Total (BOE)	98	818	397

Andrews County Wolfberry:
Oil (Bbls)	—	403	1,869
Natural gas (Mcf)	—	447	1,615
NGL (Bbls)	—	88	393
Total (BOE)	—	566	2,531

(e)

Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible. Had these incremental NGL volumes been reported separately during the year ended December 31, 2012, we estimate that our reported natural gas volumes would have decreased by 2,200 Mcf per day and that our reported NGL volumes would have increased by 600 BOE per day during 2012.


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

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Operating Results

2014 Compared to 2013

The following discussion compares our results for the year ended December 31, 2014 to the year ended December 31, 2013. Unless otherwise indicated, references to 2014 and 2013 within this section refer to the respective annual periods.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, increased $19.4 million, or 5% in 2014, from 2013. Production variances accounted for $50.3 million of the increase, and price variances accounted for a decrease of $30.9 million. Oil and gas sales in 2014 also include $7.7 million of amortized deferred revenue versus $8.7 million in 2013 attributable to the VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP. Before giving effect to the sale of our interests in certain non-core Austin Chalk/Eagle Ford assets in March 2014 and the Andrews County Wolfberry assets in April 2013, oil, gas and NGL production in 2014 (on a BOE basis) increased 10% compared to 2013. Oil production increased 14% in 2014 from 2013, NGL production increased 10% while gas production decreased 5% in 2014 from 2013. After giving effect to the asset sales discussed above, oil, gas and NGL production in 2014 (on a BOE basis) increased 21% compared to 2013. Oil production increased 27% in 2014 from 2013, NGL production increased 19% while gas production decreased 1% in 2014 from 2013. Our production mix continued to move favorably from 80% oil and NGL in 2013 to 83% in 2014. In 2014, our realized oil price declined 9% compared to 2013, and our realized gas price increased 21%. 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 3% to $105.3 million in 2014 as compared to $108.4 million in 2013, due primarily to a reduction in operating costs associated with the Austin Chalk/Eagle Ford and Andrews County Wolfberry sales, offset in part by increased production taxes related to the increase in oil and gas sales.

Oil and gas depletion expense increased $5.2 million from 2013 to 2014 due to a $13.2 million increase related to production variances and an $8 million decrease due to rate variances. On a BOE basis, depletion expense decreased 5% to $24.73 per BOE in 2014 from $26.13 per BOE in 2013. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.

We recorded a provision for impairment of property and equipment of $12 million during 2014 as compared to $89.8 million in 2013. The 2014 impairment related to certain non-core properties located in the Permian Basin and North Dakota to reduce the carrying value of these properties to their estimated fair values. The transaction to monetize our Andrews County Wolfberry assets in April 2013 triggered the assessment of a non-cash charge of $69.5 million in the first quarter of 2013 and the remainder related to write-downs during the year of certain non-core Permian Basin properties to reduce the carrying value of these properties to their estimated fair value.

Exploration costs

We follow the successful efforts method of accounting; therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs and unproved acreage impairments are expensed. In 2014, we charged to expense $23 million of exploration costs, as compared to $9.8 million in 2013. The increase was due to abandonment and impairment expense related primarily to unproved leasehold impairments in California and the abandonment of an exploratory well in South Louisiana.

Contract drilling services

We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development activities. Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss). Drilling rig services revenue related to external customers was $28 million in 2014 compared to $17.8 million in 2013. Drilling services costs related to external customers were $19.2 million in 2014 compared to $16.3 million in 2013. Contract drilling depreciation for 2014 was $9.2 million compared to $11.3 million in 2013.

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General and Administrative

G&A expenses increased $1.2 million from $33.3 million in 2013 to $34.5 million in 2014. Changes in compensation expense attributable to our APO reward plans accounted for a net increase of $2.5 million ($4.6 million in 2014 versus $2.1 million in 2013). Most of the increase in expense in 2014 was related to changes in estimated future compensation expense associated with the Eagle Ford APO reward plan offset by lower professional costs.

Interest expense

Interest expense increased 18% from $43.1 million in 2013 to $50.9 million in 2014 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of 7.75% Senior Notes due 2019.

Gain/loss on derivatives

We did not designate any derivative contracts in 2014 or 2013 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. In 2014, we reported a $4.8 million gain on derivatives (including a $7.1 million gain on settled contracts). In 2013, we reported an $8.7 million loss on derivatives (net of a $0.7 million gain on settled contracts). Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $9.1 million on sales of assets and impairment of inventory in 2014 compared to a net gain of $3 million in 2013. The 2014 gain related primarily to the sale of certain of the Austin Chalk/Eagle Ford assets sold in March 2014 and the sale of a property in Ward County, Texas in February 2014. The 2013 gain related primarily to the sale of our Andrews County, Texas properties in April 2013 and the sale of non-core properties located in Walker County, Texas in August 2013. Gain on sales of assets are included in other operating revenues and loss on sales of assets and impairment of inventory are included in other operating expenses in our consolidated statements of operations and comprehensive income (loss).

Income taxes

Our estimated federal and state effective income tax rate in 2014 of 36% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

2013 Compared to 2012

The following discussion compares our results for the year ended December 31, 2013 to the year ended December 31, 2012. Unless otherwise indicated, references to 2013 and 2012 within this section refer to the respective annual periods.

Oil and gas operating results

Oil and gas sales, excluding amortized deferred revenues, decreased $3.6 million, or 1% in 2013, from 2012. Production variances accounted for $15.6 million of the decrease, and price variances accounted for a $12 million increase. Oil and gas sales in 2013 also include $8.7 million of amortized deferred revenue versus $8.3 million in 2012 attributable to a VPP. Reported production and related average realized sales prices exclude volumes associated with the VPP. Before giving effect to the Andrews sale, oil, gas and NGL production in 2013 (on a BOE basis) decreased 6% compared to 2012. Oil production decreased 3% in 2013 from 2012, NGL production increased 23% while gas production decreased 23% in 2013 from 2012. After giving effect to the Andrews sale, oil, gas and NGL production in 2013 (on a BOE basis) increased 8% compared to 2012. Oil production increased 13% in 2013 from 2012, NGL production increased 73% while gas production decreased 19% in 2013 from 2012. Our production mix continued to move favorably from 76% oil and NGL in 2012 to 80% in 2013. Prior to 2013, certain purchasers of our casinghead gas accounted for the value of extracted NGL in the price paid for gas production at the wellhead. During the quarter ended March 31, 2013, we began reporting these products separately, when possible. Had these incremental NGL volumes been reported separately during 2012, we estimate that our natural gas volumes would have decreased by approximately 2,200 Mcf per day related to plant shrinkage and that our NGL volumes would have increased by approximately 600 BOE per day. Periods for 2012 have not been adjusted to conform to the 2013 presentation. In 2013, our realized oil price was 4% higher than 2012, and

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our realized gas price remained unchanged. 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 13% to $108.4 million in 2013 as compared to $125 million in 2012, due primarily to a reduction in costs associated with the sale of our Andrews County Wolfberry assets, lower salt water disposal costs and other cost savings resulting from infrastructure improvements in Reeves County, Texas.

Oil and gas depletion expense increased $3.8 million from 2012 to 2013 due to a $12 million increase related to rate variances and an $8.2 million decrease due to production variances. On a BOE basis, depletion expense increased 10% to $26.13 per BOE in 2013 from $23.84 per BOE in 2012. 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 $89.8 million during 2013. The transaction to monetize our Andrews County Wolfberry assets in April 2013 triggered the assessment of a non-cash charge of $69.5 million in the first quarter of 2013 and the remainder related to write-downs during the year of certain non-core Permian Basin properties to reduce the carrying value of these properties to their estimated fair value. During 2012, we recorded a $5.9 million impairment of property and equipment for certain non-core oil and gas properties in the Permian Basin and other non-core areas to reduce the carrying value of those properties to their estimated fair value.

Exploration costs

Contract drilling services

We primarily utilize drilling rigs owned by our subsidiary, Desta Drilling, to drill wells in our exploration and development activities. Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss). Drilling rig services revenue related to external customers was $17.8 million in 2013 compared to $15.9 million in 2012. Drilling services costs related to external customers were $16.3 million in 2013 compared to $17.4 million in 2012. Contract drilling depreciation for 2013 was $11.3 million compared to $7.7 million in 2012.

General and Administrative

G&A expenses increased $2.8 million from $30.5 million in 2012 to $33.3 million in 2013. Higher personnel and professional costs in 2013 accounted for an increase of approximately $4.8 million, which was partially offset by a reduction in costs related to $2 million of non-recurring donations reported in 2012.

Interest expense

Interest expense increased 11% from $38.7 million in 2012 to $43.1 million in 2013 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of the 2019 Senior Notes.

Gain/loss on derivatives

We did not designate any derivative contracts in 2013 or 2012 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. In 2013, we reported an $8.7 million loss on derivatives (net of a $0.7 million realized gain on settled contracts). In 2012, we reported a $14.4 million gain on derivatives (net of a $3.4 million realized loss on settled contracts). Because oil and gas prices are volatile, and because we do not account for our derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on derivatives can cause significant volatility in our results of operations.

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Gain/loss on sales of assets and impairment of inventory

We recorded a net gain of $3 million on sales of assets and impairment of inventory in 2013 compared to a net gain of $0.5 million in 2012. The 2013 gain related primarily to the sale of our Andrews County, Texas properties and the sale of non-core properties located in Walker County, Texas. Gain on sales of assets are included in other operating revenues and loss on sales of assets and impairment of inventory are included in other operating expenses in our consolidated statements of operations and comprehensive income (loss).

Income taxes

Our estimated federal and state effective income tax rate in 2013 of 33.3% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.

Liquidity and Capital Resources

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

At December 31, 2014, we had $105 million of borrowings outstanding under the credit facility, leaving $389.1 million available on the facility after allowing for outstanding letters of credit totaling $5.9 million as compared to $369.9 million of availability on the facility at December 31, 2013. The improvement in liquidity resulted primarily due to the sale of certain producing properties in 2014.

Outlook for 2015

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Capital expenditures

The following table summarizes, by area, our planned expenditures for exploration and development activities during 2015, as compared to our actual expenditures in 2014.



	Actual Expenditures Year Ended December 31, 2014		Planned Expenditures Year Ending December 31, 2015		2015 Percentage of Total Planned Expenditures
	(In thousands)
Drilling and Completion
Permian Basin Area:
Delaware Basin	$	152,200	$	34,200	32	%
Other	26,800		11,900		11	%
Austin Chalk/Eagle Ford Shale	160,200		26,400		25	%
Other	8,900		4,900		4	%
	348,100		77,400		72	%
Leasing and seismic	56,200		30,000		28	%
Exploration and development	$	404,300	$	107,400	100	%

Our expenditures for exploration and development activities for the year ended December 31, 2014 totaled $404.3 million. We financed these expenditures in 2014 with cash flow from operating activities, proceeds from asset sales and advances under the credit facility. Due to the downturn in oil prices, we currently plan to reduce spending on exploration and development activities in 2015 to approximately $107.4 million relating primarily to drilling activities on wells in progress at December 31, 2014 and lease renewals and extensions. Our actual expenditures during 2015 may vary significantly from these estimates since our plans for exploration and development activities change during the year. Factors, such as changes in operating margins, the availability of capital resources, drilling results and other factors, could increase or decrease our actual expenditures during 2015.

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

Cash flow provided by operating activities

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

Cash flows provided by operating activities for the year ended December 31, 2014 increased $37.5 million, or 17%, as compared to the corresponding period in 2013 due primarily to higher oil and gas production in 2014.

Senior Notes

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

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The Indenture contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDA to consolidated interest expense (as these terms are defined in the Indenture) exceeds 2.25 times. These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at December 31, 2014 and December 31, 2013.

In light of the recent downturn in oil prices and the related impact on our current plans for significant reductions in 2015 capital spending, we expect that our ratio of consolidated EBITDA to consolidated interest expense will drop below the minimum ratio in the Indenture during 2015. Under the Indenture, our ability to incur debt will be restricted at any time that we are not in compliance with the interest coverage ratio discussed in the preceding paragraph. However, noncompliance with the interest coverage ratio will not restrict our ability to borrow money under the revolving credit facility as long as the principal amount outstanding under the facility is less than the greater of $500 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture).

Revolving credit facility

We have historically relied on the credit facility for both our short-term liquidity (working capital) and a portion of our long-term financial needs. As long as we have sufficient availability under the credit facility to meet our obligations as they become due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit.

We currently borrow money under an amended and restated credit facility with a syndicate of 16 banks led by JP Morgan Chase Bank, N.A. The credit facility, which was established in April 2014 and amended in November 2014 and February 2015, provides for a revolving line of credit of up to $1 billion, limited to the lesser of the borrowing base amount, as determined by the banks, and the aggregate lender commitments, as determined by us. The credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the credit facility prior to October 1, 2018.

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

The borrowing base under the credit facility was increased in November 2014 from $415 million to $600 million and was decreased in February 2015 to $500 million. The aggregate lender commitment was increased from $415 million to $500 million in November 2014. At December 31, 2014, we had $105 million of borrowings outstanding on the credit facility, leaving $389.1 million available after allowing for outstanding letters of credit totaling $5.9 million.

The credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in the credit facility) of our oil and gas interests evaluated in determining the borrowing base. The obligations under the credit facility are guaranteed by each of CWEI’s material domestic subsidiaries except for CWEI Andrews Properties, GP, LLC (see Note 18).

At our election, annual interest rates under the credit facility are determined by reference to (1) LIBOR plus an applicable LIBOR margin or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50%, or (C) one-month LIBOR plus 1%, plus an applicable base rate margin. The LIBOR margin ranges between 1.50% and 2.50% per year (amended in February 2015 to range between 1.75% and 2.75%), and the base rate margin ranges between 0.50% and 1.50% per year (amended in February 2015 to range between 0.75% and 1.75%). We also pay a commitment fee on the unused portion of the credit facility at an applicable margin that ranges between 0.375% and 0.50% per year. Applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under the credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2014 was 2.1%.

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maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1. Another financial covenant is a leverage ratio that limits our consolidated indebtedness to consolidated EBITDA (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1. In February 2015, the credit facility was amended to temporarily redefine the leverage ratio to limit consolidated senior debt to 2.5 times consolidated EBITDA and to add a consolidated interest coverage ratio of 1.5 times consolidated EBITDA. These temporary amendments apply to each of the quarterly periods from January 1, 2015 through June 30, 2016. The computations of consolidated current assets, current liabilities, EBITDA, indebtedness and interest are defined in the credit facility.

Working capital computed for loan compliance purposes differs from our working capital computed in accordance with GAAP. Since compliance with financial covenants is a material requirement under the credit facility, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives. Our GAAP reported working capital (deficit) was $23.7 million at December 31, 2014 from working capital of $1.9 million at December 31, 2013. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $365.4 million at December 31, 2014, as compared to $369.6 million at December 31, 2013. The following table reconciles our GAAP working capital (deficit) to the working capital computed for loan compliance purposes at December 31, 2014 and December 31, 2013.



	December 31,
	2014			2013
	(In thousands)
Working capital (deficit) per GAAP	$	(23,733	)	$	1,916
Add funds available under the credit facility	389,130			369,947
Exclude fair value of derivatives classified as current assets or current liabilities	—			(2,310		)
Working capital per loan covenant	$	365,397		$	369,553

We were in compliance with all financial and non-financial covenants at December 31, 2014 and December 31, 2013. However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future, particularly after the temporary amendments to the credit facility expire with the third quarter of 2016. If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend the credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.

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

From time to time, we engage in other transactions with lenders under the credit facility. Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of February 2015, JPMorgan Chase Bank, N.A. was the counterparty to our commodity derivative agreements. Our obligations under derivative agreements with our lenders are secured by the security documents executed by the parties under the credit facility.

During 2014, we increased indebtedness outstanding under the credit facility by $65 million. At December 31, 2014, we had $105 million of borrowings outstanding on the credit facility, leaving $389.1 million available after allowing for outstanding letters of credit totaling $5.9 million.

Alternative capital resources

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

We may also use other capital resources, including (1) entering into joint venture participation agreements with other industry or financial partners in our core development areas, (2) monetizing all or a portion of our core or non-core assets and (3) issuing additional debt or equity securities in private or public offerings, in order to finance a portion of our capital spending in fiscal 2015 and subsequent periods. While we believe we would be able to obtain funds through one or more of these alternative capital resources, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.

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Contractual obligations and contingent commitments

The following table summarizes our contractual obligations as of December 31, 2014 by payment due date.



	Payments Due by Period
	Total		2015		2016 to 2017		2018 to 2019		Thereafter
	(In thousands)
Contractual obligations:
7.75% Senior Notes, due 2019, net of discount of $304^(a)	$	599,696	$	—	$	—	$	599,696	$	—
Revolving credit facility, due April 2019^(a)	105,000		—		—		105,000		—
Volumetric Production Payment Obligation	24,386		6,822		9,948		7,616		—
Lease obligations^(b)	9,829		5,050		4,779		—		—
Other	857		857		—		—		—
Total contractual obligations	$	739,768	$	12,729	$	14,727	$	712,312	$	—

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(a)	In addition to the principal payments presented, we expect to make annual interest payments of $47.1 million on the 2019 Senior Notes and approximately $2.2 million on the credit facility (based on the balances and interest rates at December 31, 2014).


(b)	Amount includes lease payments for two drilling rigs.

Off-balance sheet arrangements

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

Known Trends and Uncertainties

Operating Margins

We analyze, on a BOE produced basis, those revenues and expenses that have a significant impact on our oil and gas operating margins. Our weighted average oil and gas sales per BOE have fluctuated from $72.00 per BOE in 2012, to $76.11 per BOE in 2013 and $72.59 per BOE in 2014. Our oil and gas DD&A per BOE fluctuated from $23.84 per BOE in 2012, to $26.13 per BOE in 2013 and $24.73 per BOE in 2014. Although we replaced 405% of our production in 2014 and commodity prices were higher for a majority of 2014, our costs to find those reserves were significantly higher than our historical combined rate. Our production costs per BOE have decreased from $22.32 per BOE in 2012, to $20.63 per BOE in 2013, and $18.27 per BOE in 2014. The decrease in operating costs per BOE in 2014 from 2013 was due primarily to lower repair and maintenance costs and a reduction in production costs associated with the sale of non-core Austin Chalk/Eagle Ford assets in March 2014 and the sale of our Andrews County Wolfberry assets in April 2013.

Oil and Gas Production

As with all companies engaged in oil and gas exploration and production, we face the challenge of natural production decline because oil and gas reserves are a depletable resource. With each unit of oil and gas we produce, we are depleting our proved reserve base, so we must be able to conduct successful exploration and development activities or acquire properties with proved reserves in order to grow our reserve base. Our production in 2014 increased 10% to 5.8 MMBOE compared to 5.3 MMBOE in 2013, and we replaced 405% of our 2014 oil and gas production through extensions and discoveries. While these 2014 reserve additions will contribute favorably to our production in 2015, we do not expect this production to be sufficient to fully offset the natural production declines from our existing base of oil and gas reserves.

We currently plan to decrease capital spending during 2015 to $107.4 million on exploration and development activities compared to $404.3 million in 2014. Failure to maintain or grow our oil and gas reserves may result in lower production and may adversely affect our financial condition, results of operations and cash flows.

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Impact of Downturn in Oil Prices

Application of Critical Accounting Policies and Estimates

Summary

In this section, we will identify the critical accounting policies we follow in preparing our consolidated financial statements and disclosures. Many of these policies require us to make difficult, subjective and complex judgments in the course of making estimates of matters that are inherently imprecise. We explain the nature of these estimates, assumptions and judgments, and the likelihood that materially different amounts would be reported in our consolidated financial statements under different conditions or using different assumptions.

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The following table lists our critical accounting policies, the estimates and assumptions that can have a significant impact on the application of these accounting policies and the financial statement accounts affected by these estimates and assumptions.



Accounting Policies	Estimates or Assumptions	Accounts Affected

Successful efforts accounting for oil and gas properties	· Reserve estimates · Valuation of unproved properties · Judgment regarding status of in progress exploratory wells	· Oil and gas properties · Accumulated DD&A · Provision for DD&A · Impairment of unproved properties · Abandonment costs (dry hole costs)

Impairment of proved properties and long-lived assets	· Reserve estimates and related present value of future net revenues (proved properties) · Estimates of future undiscounted cash flows (long-lived assets)	· Oil and gas properties · Contract drilling equipment · Accumulated DD&A · Impairment of proved properties and long-lived assets

Asset retirement obligations	· Estimates of the present value of future abandonment costs	· Asset retirement obligations (non-current liability) · Oil and gas properties · Accretion of discount expense

Inventory stated at the lower of average cost or estimated market value	· Estimates of market value of tubular goods and other well equipment	· Impairment of inventory

Derivatives mark-to-market	· Estimates of the fair value of derivatives	· Fair value of derivatives · Other income (expense): Gain (loss) on derivatives

Significant Estimates and Assumptions

Oil and gas reserves

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of a reserve estimate depends on the quality of available geological and engineering data, the precision of and the interpretation of that data and judgment based on experience and training. Annually, we engage independent petroleum engineering firms to evaluate our oil and gas reserves. As a part of this process, our internal reservoir engineer and the independent petroleum engineers exchange information and attempt to reconcile any material differences in estimates and assumptions.

The techniques used in estimating reserves usually depend on the nature and extent of available data, and the accuracy of the estimates may vary accordingly. As a general rule, the degree of accuracy of reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table.



Type of Reserves	Nature of Available Data	Degree of Precision
Proved undeveloped	Data from offsetting wells, seismic data	Least precise
Proved developed non-producing	Logs, core samples, well tests, pressure data	More precise
Proved developed producing	Production history, pressure data over time	Most precise

Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable reserves exceed the projected revenues from the reserves). But more significantly, the standardized measure of discounted future net cash flows is extremely sensitive to prices and costs, and may vary materially based on different assumptions. Current SEC financial accounting and reporting standards require that

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pricing parameters be the arithmetic average of the first-day-of-the-month price for the 12-month period preceding the effective date of the reserve report. Varying pricing can result in significant changes in reserves and standardized measure of discounted future net cash flows from period to period, as illustrated in the following table.



	Proved Reserves			Average Price						Standardized Measure of Discounted Future
	Oil	Natural Gas Liquids	Gas	Oil		Natural Gas Liquids		Gas		Standardized Measure of Discounted Future
	(MMBbls)	(MMBbls)	(Bcf)	($/Bbl)		($/Bbl)		($/Mcf)		Net Cash Flows
										(In millions)
As of December 31:
2014	53.9	8.9	75.6	$	90.48	$	31.54	$	4.27	$	932.9
2013	48.7	8.5	77.2	$	94.88	$	31.63	$	3.59	$	926.9
2012	49.1	9.2	102.3	$	90.45	$	43.74	$	3.70	$	939.8

Valuation of unproved properties

Estimating fair market value of unproved properties (also known as prospects) is very subjective since there is no quoted market for undeveloped exploratory prospects. The negotiated price of any prospect between a willing seller and willing buyer depends on the specific facts regarding the prospect, including:


•	the location of the prospect in relation to known fields and reservoirs, available markets and transportation systems for oil and gas production in the vicinity and other critical services;


•	the nature and extent of geological and geophysical data on the prospect;


•	the terms of the leases holding the acreage in the prospect, such as ownership interests, expiration terms, delay rental obligations, depth limitations, drilling and marketing restrictions and similar terms;


•	the prospect’s risk-adjusted potential for return on investment, giving effect to such factors as potential reserves to be discovered, drilling and completion costs, prevailing commodity prices and other economic factors; and


•	the results of drilling activity in close proximity to the prospect that could either enhance or condemn the prospect’s chances of success.

Asset Retirement Obligations

We estimate the present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We compute our liability for asset retirement obligations by calculating the present value of estimated future cash flows related to each property. This requires us to use significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations.

Effects of Estimates and Assumptions on Financial Statements

GAAP does not require, or even permit, the restatement of previously issued financial statements due to changes in estimates unless such estimates were unreasonable or did not comply with applicable SEC accounting rules. We are required to use our best judgment in making estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate. At each accounting period, we make a new estimate using new data, and continue the cycle. You should be aware that estimates prepared at various times may be substantially different due to new or additional data. While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available data or assumptions. In this section, we will discuss the effects of different estimates on our consolidated financial statements.

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Provision for DD&A

We compute our provision for DD&A on a unit-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for each of our producing properties (or appropriate groups of properties based on geographical and geological similarities):


•	DD&A Rate = Unamortized Cost / Beginning of Period Reserves


•	Provision for DD&A = DD&A Rate x Current Period Production

Reserve estimates have a significant impact on the DD&A rate. If reserve estimates for a property or group of properties are revised downward in future periods, the DD&A rate for that property or group of properties will increase as a result of the revision. Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease.

Impairment of Unproved Properties

Each quarter, we review our unproved oil and gas properties to determine if there has been, in our judgment, an impairment in value of each prospect that we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimated value, we make a provision for impairment of unproved properties and record the provision as abandonments and impairments within exploration costs on our consolidated statements of operations and comprehensive income (loss). If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the prospect at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period.

Impairment of Proved Properties and Long-Lived Assets

Each quarter, we assess our producing properties for impairment. If we determine there has been an impairment in any of our producing properties (or appropriate groups of properties based on geographical and geological similarities), we will estimate the value of each affected property. In accordance with GAAP, the value for this purpose is a fair value using Level 3 inputs instead of a standardized reserve value as prescribed by the SEC. We attempt to value each property using reserve classifications and pricing parameters similar to what a willing seller and willing buyer might use. These parameters may include escalations of prices instead of constant pricing, and they may also include the risk-adjusted value of reserves. To the extent that the carrying cost for the affected property exceeds its estimated fair value, we make a provision for impairment of proved properties. If the fair value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the property at a net cost that is lower than its estimated fair value. If the fair value is revised downward in a future period, an additional provision for impairment is made in that period. Accordingly, the carrying costs of producing properties on our balance sheet will vary from (and often will be less than) the present value of proved reserves for these properties.

Judgment Regarding Status of In-Progress Wells

On a quarterly basis, we review the status of each in-progress well to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress wells remain capitalized until their productive status becomes known. If an in-progress exploratory well is found to be unsuccessful (often referred to as a dry hole) prior to the issuance of our consolidated financial statements, we write-off all costs incurred through the balance sheet date to abandonments and impairments expense, a component of exploration costs. Costs incurred on that dry hole after the balance sheet date are charged to exploration costs in the period incurred.

Occasionally, we are unable to make a final determination about the productive status of a well prior to issuance of our consolidated financial statements. In these cases, we leave the well classified as in-progress until we have had sufficient time to conduct additional completion or testing operations and to evaluate the pertinent geological and geophysical and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the in-progress status and the proper accounting treatment is recorded.

Asset Retirement Obligations

Our asset retirement obligations are recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to oil and gas properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the consolidated statements of operations and comprehensive income (loss). During 2014, we had a downward revision of our estimated asset retirement obligations of $3.9 million based on a review of current plugging and abandonment costs. Revisions

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to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to DD&A expense and accretion expense. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. An entity is required to apply ASU 2014-09 for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods. An entity can apply ASU 2014-09 using either a full retrospective method, meaning the standard is applied to all of the periods presented, or a modified retrospective method, meaning the cumulative effect of initially applying the standard is recognized in the most current period presented in the financial statements. We are evaluating the impact that this new guidance will have on our consolidated financial statements.

Item 7A - 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 risk and quantify the potential effect of market volatility on our financial condition and results of operations.

Oil and Gas Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market commodity prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, many of which are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas commodity prices with any degree of certainty. Sustained weakness in oil and gas commodity prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to commodity price fluctuations, can reduce the borrowing base under the credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas commodity prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2014 reserve estimates, we project that a $1 decline in the price per barrel of oil and a $0.50 decline in the price per Mcf of gas from year end 2014 would reduce our gross revenues for the year ending December 31, 2015 by $6.1 million.

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

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

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The following summarizes information concerning our net positions in open commodity derivatives, all of which were entered into in February 2015, applicable to periods subsequent to December 31, 2014. The settlement prices of commodity derivatives are based on NYMEX futures prices.

Swaps



	Oil
	MBbls	Price
Production Period:
2nd Quarter 2015	448	$	55.65
3rd Quarter 2015	697	$	55.65
4th Quarter 2015	592	$	55.65
	1,737

Interest Rates

We are exposed to interest rate risk on our long-term debt with a variable interest rate. At December 31, 2014, our fixed rate debt had a carrying value of $599.7 million and an approximate fair value of $510 million, based on current market quotes. We estimate that the hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $17.5 million. Based on our outstanding variable rate indebtedness at December 31, 2014 of $105 million, a change in interest rates of 100-basis points would affect annual interest payments by $1.1 million.

Item 8 - Financial Statements and Supplementary Data

For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements on page F-1.

Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A - 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 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.

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Internal Control Over Financial Reporting

Management designed our internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:


•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;


•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with GAAP and that our receipts and expenditures are being made only in accordance with authorizations of management and the Board; and


•	provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control Over Financial Reporting

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

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework (2013). Based on this assessment, management has concluded that, as of December 31, 2014, our internal control over financial reporting is effective based on those criteria.

KPMG LLP has issued an audit report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, the contents of which are shown below.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Clayton Williams Energy, Inc.:

We have audited Clayton Williams Energy, Inc.’s (the Company) internal control over financial reporting as of December 31, 2014, based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, Clayton Williams Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2014 and 2013, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2014, and our report dated February 27, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Dallas, Texas

February 27, 2015

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Item 9B - Other Information

None.

PART III

Item 10 - Directors, Executive Officers and Corporate Governance

Information required by this Item 10 is incorporated by reference to our definitive proxy statement relating to the 2015 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2015.

Item 11 - Executive Compensation

Information required by this Item 11 is incorporated by reference to our definitive proxy statement relating to the 2015 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2015.

Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this Item 12 is incorporated by reference to our definitive proxy statement relating to the 2015 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2015.

Item 13 - Certain Relationships and Related Transactions, and Director Independence

Information required by this Item 13 is incorporated by reference to our definitive proxy statement relating to the 2015 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2015.

Item 14 - Principal Accounting Fees and Services

Information required by this Item 14 is incorporated by reference to our definitive proxy statement relating to the 2015 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2015.

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PART IV

Item 15 - Exhibits, Financial Statement Schedules

Financial Statements and Schedules

For a list of the consolidated financial statements and financial statement schedules filed as part of this Form 10-K, see the Index to Consolidated Financial Statements on page F-1.

Exhibits

The following exhibits are filed as a part of this Form 10-K, with each exhibit that consists of or includes a management contract or compensatory plan or arrangement being identified with a “†”:



Exhibit Number		Description of Exhibit
**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 the Company’s Form S-2 Registration Statement, Commission File No. 333-13441

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

**3.3		Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 13, 2008††

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

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

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

**10.2		Amendment No. 1 to Third Amended and Restated Credit Agreement dated April 23, 2014, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on November 14, 2014††

**10.3		Amendment No. 2 to Third Amended and Restated Credit Agreement dated April 23, 2014, filed as Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on February 25, 2015††

**10.4†		Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316

**10.5†		First Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 1995††

**10.6†		Second Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 2005††

**10.7†		Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316

**10.8†		Form of stock option agreement for Outside Directors Stock Option Plan, filed as Exhibit 10.38 to the Company’s Form 10-K for the period ended December 31, 2004††

**10.9†		Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68320

**10.10†		First Amendment to Bonus Incentive Plan, filed as Exhibit 10.9 to the Company’s Form 10-K for the period ended December 31, 1997††

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Exhibit Number		Description of Exhibit
**10.11†		Scudder Trust Company Prototype Defined Contribution Plan adopted by Clayton Williams Energy, Inc. effective as of August 1, 2004, filed as Exhibit 10.12 to the Company’s Form 10-K for the period ended December 31, 2004††

**10.12†		Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-92834

**10.13†		First Amendment to Executive Incentive Stock Compensation Plan, filed as Exhibit 10.16 to the Company’s Form 10-K for the period ended December 31, 1996††

**10.14		Consolidation Agreement dated May 13, 1993 among Clayton Williams Energy, Inc., Warrior Gas Co. and the Williams Entities, filed as Exhibit 10.1 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350

**10.15		Amendment to Consolidation Agreement dated August 7, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams Companies, filed as Exhibit 10.1 to the Company’s Form 10-Q for the period ended September 30, 2000††

**10.16		Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.42 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350

**10.17		Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.35 to the Company’s Form 10-K for the period ended December 31, 2004††

**10.18		Second Amendment to Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.36 to the Company’s Form 10-K for the period ended December 31, 2004††

**10.19		Second Amended and Restated Service Agreement effective March 1, 2005 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., Clayton Williams Partnership, Ltd. and CWPLCO, Inc., filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 3, 2005††

**10.20		Amendment to Second Amended and Restated Service Agreement effective January 1, 2008 among Clayton Williams Energy, Inc. and its subsidiaries, Clayton Williams, Jr., Clayton Williams Ranch Holdings, Inc., ClayDesta L.P., The Williams Children’s Partnership, Ltd. and CWPLCO, Inc. filed as Exhibit 10.26 to the Company's Form 10-K for the period ended December 31, 2008††

**10.21†		Form of Director Indemnification Agreement, filed as Exhibit 10.71 to the Company’s Form 10-K for the period ended December 31, 2008††

**10.22†		Employment Agreement by and between Clayton Williams Energy, Inc. and Clayton W. Williams, Jr., effective as of March 1, 2010, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.23†		Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Mel G. Riggs, effective as of June 1, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.24†		Employment Agreement by and between Clayton Williams Energy, Inc. and Patrick C. Reesby, effective as of March 1, 2010, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.25†		Amended and Restated Employment Agreement between Clayton Williams Energy, Inc. and Michael L. Pollard, effective as of June 1, 2011, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

**10.26†		Employment Agreement by and between Clayton Williams Energy, Inc. and Greg S. Welborn, effective as of March 1, 2010, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.27†		Employment Agreement by and between Clayton Williams Energy, Inc. and T. Mark Tisdale, effective as of March 1, 2010, filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K filed with the Commission on March 18, 2010††

**10.28†		Employment Agreement between Clayton Williams Energy, Inc. and Robert L. Thomas, effective as of June 1, 2011, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 7, 2011††

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Exhibit Number		Description of Exhibit
*10.29†		Employment Agreement between Clayton Williams Energy, Inc. and Ron D. Gasser dated February 21, 2013 filed as Exhibit 10.33 to the Company's Form 10-K for the period ended December 31, 2012††

*10.30†		Employment Agreement between Clayton Williams Energy, Inc. and Sam Lyssy dated February 21, 2013 filed as Exhibit 10.34 to the Company's Form 10-K for the period ended December 31, 2012††

*10.31†		Employment Agreement between Clayton Williams Energy, Inc. and John F. Kennedy dated February 21, 2013 filed as Exhibit 10.35 to the Company's Form 10-K for the period ended December 31, 2012††

**10.32†		Southwest Royalties, Inc. Reward Plan dated January 15, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with Commission on January 18, 2007††

**10.33†		Form of Notice of Bonus Award Under the Southwest Royalties, Inc. Reward Plan, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on January 18, 2007††

**10.34†		Amacker Tippett Reward Plan dated June 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.35†		Austin Chalk Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.36†		Barstow Area Reward Plan dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.37†		Fuhrman-Mascho Reward Plan dated December 1, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 2, 2009††

**10.38†		CWEI Andrews Fee Reward Plan dated October 19, 2010, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 22, 2010††

**10.39†		CWEI Andrews Samson Reward Plan dated October 19, 2010, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on October 22, 2010††

**10.40†		CWEI Austin Chalk Reward Plan II dated October 19, 2010, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on October 22, 2010††

**10.41†		CWEI Andrews Fee Reward Plan II dated June 28, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.42†		CWEI Andrews University Reward Plan dated June 28, 2011, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.43†		CWEI Austin Chalk Reward Plan III dated June 28, 2011, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.44†		CWEI Delaware Basin Reward Plan dated June 28, 2011, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.45†		CWEI Andrews Samson Reward Plan II dated June 28, 2011, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.46†		CWEI South Louisiana Reward Plan dated June 28, 2011, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on June 30, 2011††

**10.47†		CWEI Oklahoma 3D Phase 1 Reward Plan dated May 1, 2013, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 28, 2013††

**10.48†		CWEI Oklahoma 3D Phase 2 Reward Plan dated May 1, 2013, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on May 28, 2013††

**10.49†		CWEI Eagle Ford I Reward Plan dated August 20, 2013, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on August 22, 2013††

**10.50†		CWEI East Permian Reward Plan dated August 20, 2013, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on August 22, 2013††

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

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Exhibit Number		Description of Exhibit

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

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

**10.54†		Participation Agreement relating to West Coast Energy Properties, L.P. dated December 11, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 14, 2006††

**10.55†		Participation Agreement relating to RMS/Warwink dated April 10, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 13, 2007††

**10.56†		Participation Agreement relating to CWEI Andrews Area dated June 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.57†		Participation Agreement relating to CWEI Crockett County Area dated June 19, 2008, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.58†		Participation Agreement relating to CWEI South Louisiana VI dated June 19, 2008, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.59†		Participation Agreement relating to CWEI Utah dated June 19, 2008, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††

**10.60†		Participation Agreement relating to CWEI Sacramento Basin I dated August 12, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on August 14, 2008††

*21.1		Subsidiaries of the Registrant

*23.1		Consent of KPMG LLP

*23.2		Consent of Williamson Petroleum Consultants, Inc.

*23.3		Consent of Ryder Scott Company, L.P.

*24.1		Power of Attorney

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

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

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

*99.1		Summary Report of Williamson Petroleum Consultants, Inc. independent consulting engineers

*99.2		Summary Report of Ryder Scott Company, L.P. independent consulting engineers

*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 the Company’s Commission File No. 001-10924.

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GLOSSARY OF TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this Form 10-K.

3-D seismic. An advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

BOE. One barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

Bbl. One barrel, or 42 U.S. gallons of liquid volume.

Bcf. One billion cubic feet.

Btu. One British thermal unit. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or gas.

Credit facility. A line of credit provided by a group of banks, secured by oil and gas properties.

DD&A. Depreciation, depletion and amortization of the Company’s property and equipment.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the cost of the operation.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Gross acres or wells. The total acres or wells in which the Company has a working interest.

Horizontal drilling. A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.

MBbls. One thousand barrels.

MBOE. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet.

MMbtu. One million British thermal units.

MMBbls. One million barrels.

MMBOE. One million barrels of oil equivalent.

MMcf. One million cubic feet.

Natural gas liquids. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

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Net acres or wells. The sum of fractional ownership working interests in gross acres or wells.

Net production. Oil and gas production that is owned by the Company, less royalties and production due others.

NYMEX. New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded.

Oil. Crude oil or condensate.

Operator. The individual or company responsible for the exploration, development and production of an oil or gas well or lease.

Present value of proved reserves (“PV-10”). The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) nonproperty related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

Productive wells. Producing wells and wells mechanically capable of production.

Proved Developed Reserves. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves (PUD). Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual

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projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure of discounted future net cash flows. Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) estimated future income taxes.

Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

Workover. Operations on a producing well to restore or increase production.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	CLAYTON WILLIAMS ENERGY, INC.
	(Registrant)

	By:	/s/ CLAYTON W. WILLIAMS, JR.
		Clayton W. Williams, Jr.
		Chairman of the Board, President
		and Chief Executive Officer

	Date:	February 27, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date

/s/ CLAYTON W. WILLIAMS, JR.	Chairman of the Board,	February 27, 2015
Clayton W. Williams, Jr.	President, Chief Executive Officer and Director

/s/ MEL G. RIGGS	Executive Vice President,	February 27, 2015
Mel G. Riggs	Chief Operating Officer and Director

/s/ MICHAEL L. POLLARD	Senior Vice President —	February 27, 2015
Michael L. Pollard	Finance, Chief Financial Officer and Treasurer

/s/ ROBERT L. THOMAS	Vice President — Accounting and Principal Accounting Officer	February 27, 2015
Robert L. Thomas

*	Director	February 27, 2015
Ted Gray, Jr.

*	Director	February 27, 2015
Davis L. Ford

*	Director	February 27, 2015
Robert L. Parker

*	Director	February 27, 2015
Jordan R. Smith

* By: /s/ MEL G. RIGGS
* Mel G. Riggs
Attorney-in-Fact

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CLAYTON WILLIAMS ENERGY, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND SUPPLEMENTAL INFORMATION



	Page

Report of Independent Registered Public Accounting Firm	F-2

Consolidated Balance Sheets	F-3

Consolidated Statements of Operations and Comprehensive Income (Loss)	F-5

Consolidated Statements of Stockholders’ Equity	F-6

Consolidated Statements of Cash Flows	F-7

Notes to Consolidated Financial Statements	F-8

Supplemental Information
Supplemental Quarterly Financial Data	S-1

Supplemental Oil and Gas Reserve Information	S-2

F-1

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REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Clayton Williams Energy, Inc.:

We have audited the accompanying consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of operations and comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Clayton Williams Energy, Inc.’s internal control over financial reporting as of December 31, 2014, based on criteria established in the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2015, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Dallas, Texas

February 27, 2015

F-2

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

	December 31,
	2014			2013
CURRENT ASSETS
Cash and cash equivalents	$	28,016		$	26,623
Accounts receivable:
Oil and gas sales	36,526			39,268
Joint interest and other, net of allowance for doubtful accounts of $1,204 at December 31, 2014 and $1,184 at December 31, 2013	14,550			17,121
Affiliates	322			264
Inventory	42,087			39,183
Deferred income taxes	6,911			7,581
Fair value of derivatives	—			2,518
Prepaids and other	4,208			5,753
	132,620			138,311
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method	2,684,913			2,403,277
Pipelines and other midstream facilities	59,542			54,800
Contract drilling equipment	122,751			96,270
Other	20,915			20,620
	2,888,121			2,574,967
Less accumulated depreciation, depletion and amortization	(1,539,237		)	(1,375,860		)
Property and equipment, net	1,348,884			1,199,107
OTHER ASSETS
Debt issue costs, net	12,712			12,785
Investments and other	16,669			16,534
	29,381			29,319
	$	1,510,885		$	1,366,737

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

F-3

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

	December 31,
	2014		2013
CURRENT LIABILITIES
Accounts payable:
Trade	$	93,650	$	75,872
Oil and gas sales	41,328		37,834
Affiliates	717		874
Fair value of derivatives	—		208
Accrued liabilities and other	20,658		21,607
	156,353		136,395
NON-CURRENT LIABILITIES
Long-term debt	704,696		639,638
Deferred income taxes	164,599		140,809
Asset retirement obligations	45,697		49,981
Deferred revenue from volumetric production payment	23,129		29,770
Accrued compensation under non-equity award plans	17,866		15,469
Other	751		892
	956,738		876,559
COMMITMENTS AND CONTINGENCIES (see Note 14)
STOCKHOLDERS’ EQUITY
Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; none issued	—		—
Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 12,169,536 shares at December 31, 2014 and 12,165,536 shares at December 31, 2013	1,216		1,216
Additional paid-in capital	152,686		152,556
Retained earnings	243,892		200,011
	397,794		353,783
	$	1,510,885	$	1,366,737

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

F-4

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

	Year Ended December 31,
	2014			2013			2012
REVENUES
Oil and gas sales	$	418,330		$	399,950		$	403,143
Midstream services	6,705			4,965			1,974
Drilling rig services	28,028			17,812			15,858
Other operating revenues	15,393			6,488			2,077
Total revenues	468,456			429,215			423,052
COSTS AND EXPENSES
Production	105,296			108,405			124,950
Exploration:
Abandonments and impairments	20,647			5,887			4,222
Seismic and other	2,314			3,906			11,591
Midstream services	2,212			1,816			1,228
Drilling rig services	19,232			16,290			17,423
Depreciation, depletion and amortization	154,356			150,902			142,687
Impairment of property and equipment	12,027			89,811			5,944
Accretion of asset retirement obligations	3,662			4,203			3,696
General and administrative	34,524			33,279			30,485
Other operating expenses	2,547			2,101			1,033
Total costs and expenses	356,817			416,600			343,259
Operating income	111,639			12,615			79,793
OTHER INCOME (EXPENSE)
Interest expense	(50,907		)	(43,079		)	(38,664		)
Gain (loss) on derivatives	4,789			(8,731		)	14,448
Other	3,047			1,905			1,534
Total other income (expense)	(43,071		)	(49,905		)	(22,682		)
Income (loss) before income taxes	68,568			(37,290		)	57,111
Income tax (expense) benefit	(24,687		)	12,428			(22,008		)
NET INCOME (LOSS)	$	43,881		$	(24,862	)	$	35,103
Net income (loss) per common share:
Basic	$	3.61		$	(2.04	)	$	2.89
Diluted	$	3.61		$	(2.04	)	$	2.89
Weighted average common shares outstanding:
Basic	12,167			12,165			12,164
Diluted	12,167			12,165			12,164

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

F-5

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


	Common Stock			Additional					Total
	No. of	Par		Paid-In		Retained			Stockholders’
	Shares	Value		Capital		Earnings			Equity
BALANCE,
December 31, 2011	12,164	$	1,216	$	152,515	$	189,770		$	343,501
Net income	—	—		—		35,103			35,103
Issuance of stock through compensation plans, including income tax benefits	1	—		12		—			12
BALANCE,
December 31, 2012	12,165	1,216		152,527		224,873			378,616
Net loss	—	—		—		(24,862		)	(24,862		)
Issuance of stock through compensation plans, including income tax benefits	1	—		29		—			29
BALANCE,
December 31, 2013	12,166	1,216		152,556		200,011			353,783
Net income	—	—		—		43,881			43,881
Issuance of stock through compensation plans, including income tax benefits	4	—		130		—			130
BALANCE,
December 31, 2014	12,170	$	1,216	$	152,686	$	243,892		$	397,794

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

F-6

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

	Year Ended December 31,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	43,881		$	(24,862	)	$	35,103
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	154,356			150,902			142,687
Impairment of property and equipment	12,027			89,811			5,944
Abandonments and impairments	20,647			5,887			4,222
Gain on sales of assets and impairment of inventory, net	(9,138		)	(3,024		)	(463		)
Deferred income tax expense (benefit)	24,460			(14,042		)	22,008
Non-cash employee compensation	1,397			(3,493		)	(404		)
(Gain) loss on derivatives	(4,789		)	8,731			(14,448		)
Cash settlements of derivatives	7,099			690			(3,410		)
Accretion of asset retirement obligations	3,662			4,203			3,696
Amortization of debt issue costs and original issue discount	3,030			3,266			2,554
Amortization of deferred revenue from volumetric production payment	(7,708		)	(8,746		)	(8,295		)
Changes in operating working capital:
Accounts receivable	5,255			(7,163		)	7,299
Accounts payable	4,561			12,740			(9,386		)
Other	(619		)	5,676			2,115
Net cash provided by operating activities	258,121			220,576			189,222
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment	(422,473		)	(288,133		)	(526,521		)
Proceeds from volumetric production payment	1,067			1,332			45,479
Proceeds from sales of assets	104,529			259,799			3,778
(Increase) decrease in equipment inventory	(1,886		)	(726		)	1,313
Other	(234		)	(1,315		)	(82		)
Net cash used in investing activities	(318,997		)	(29,043		)	(476,033		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt	102,139			268,335			280,000
Repayments of long-term debt	(40,000		)	(444,000		)	—
Proceeds from exercise of stock options	130			29			12
Net cash provided by (used in) financing activities	62,269			(175,636		)	280,012
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,393			15,897			(6,799		)
CASH AND CASH EQUIVALENTS
Beginning of period	26,623			10,726			17,525
End of period	$	28,016		$	26,623		$	10,726
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized	$	47,817		$	35,219		$	35,932
Cash paid for income taxes	$	1,600		$	—		$	—

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

F-7

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

2. Summary of Significant Accounting Policies

Estimates and Assumptions

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:


•	Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves;


•	Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets;


•	Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases;


•	Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements;


•	Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory; and


•	Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells.

Principles of Consolidation

The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries. We also 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 these limited partnerships. Less than 5% of the Company’s consolidated total assets and total revenues are derived from oil and gas limited partnerships. All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.

F-8

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Oil and Gas Properties

We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.

Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.

Pipelines and Other Midstream Facilities and Other Property and Equipment

Pipelines and other midstream facilities consist of pipelines to transport oil, gas and water, gas processing facilities and compressors. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income in the accompanying consolidated statements of operations and comprehensive income (loss).

Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years.

Contract Drilling

We conduct contract drilling operations through Desta Drilling, a wholly owned subsidiary of CWEI. Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable.

Property and equipment, including buildings, major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.

Valuation of Property and Equipment

Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred. An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset.

Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs. The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.

Asset Retirement Obligations

We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Income Taxes

We utilize the asset and liability method to account for income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date. We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense.

Hedging Transactions

From time to time, we utilize derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. All of our derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative. Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur. If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period. Actual gains or losses from derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on derivatives.

Inventory

Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value.

Capitalization of Interest

Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress. During the years ended December 31, 2014, 2013 and 2012, we capitalized interest totaling approximately $1 million, $1.4 million and $1 million, respectively.

Cash and Cash Equivalents

We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.

Net Income (Loss) Per Common Share

Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of Common Shares outstanding for the period. Diluted net income per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted net income per share calculations for 2014, 2013 and 2012 include changes in potential shares attributable to dilutive stock options.

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

Revenue Recognition and Gas Balancing

We utilize the sales method of accounting for oil, natural gas and natural gas liquids (“NGL”) revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers. The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties. We did not have any significant gas imbalance positions at December 31, 2014, 2013 or 2012. Revenues from midstream services and drilling rig services are recognized as services are provided.

Comprehensive Income (Loss)

There were no differences between net income (loss) and comprehensive income (loss) in 2014, 2013 and 2012.

Concentration Risks

We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2014 and 2013 relate to amounts due from joint interest owners.

Recent Accounting Pronouncements

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Long-Term Debt

Long-term debt consists of the following:



	December 31, 2014		December 31, 2013
	(In thousands)
7.75% Senior Notes due 2019, net of unamortized original issue discount of $304 at December 31, 2014 and $362 at December 31, 2013	$	599,696	$	599,638
Revolving credit facility, due April 2019^(a)	105,000		40,000
	$	704,696	$	639,638
_______

(a) Renewed and extended in April 2014.

Aggregate maturities of long-term debt at December 31, 2014 are as follows: 2019 - $704.7 million, net of unamortized original issue discount of $304,000.

Senior Notes

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

Revolving Credit Facility

We borrow money under an amended and restated credit facility with a syndicate of 16 banks led by JP Morgan Chase Bank, N.A. The credit facility, which was established in April 2014 and amended in November 2014 and February 2015, provides for a revolving line of credit of up to $1 billion, limited to the lesser of the borrowing base amount, as determined by the banks, and the aggregate lender commitments, as determined by us. The credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the credit facility prior to October 1, 2018.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

in November 2014. At December 31, 2014, we had $105 million of borrowings outstanding on the credit facility, leaving $389.1 million available after allowing for outstanding letters of credit totaling $5.9 million.

The credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1. Another financial covenant is a leverage ratio that limits our consolidated indebtedness to consolidated EBITDA (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1. In February 2015, the credit facility was amended to temporarily redefine the leverage ratio to limit consolidated senior debt to 2.5 times consolidated EBITDA and to add a consolidated interest coverage ratio of 1.5 times consolidated EBITDA. These temporary amendments apply to each of the quarterly periods from January 1, 2015 through June 30, 2016. The computations of consolidated current assets, current liabilities, EBITDA, indebtedness and interest are defined in the credit facility. We were in compliance with all financial and non-financial covenants at December 31, 2014 and December 31, 2013.

4. Sales of Assets

In September 2014, we sold our interests in approximately 7,500 net acres in the Delaware Basin in Ward and Winkler Counties, Texas to an unaffiliated third party for $29.3 million. In March 2014, we closed a transaction to sell our interests in selected wells and leases in Wilson, Brazos, La Salle, Frio and Robertson Counties, Texas for $71 million, subject to customary closing adjustments. At closing, $6.8 million of the total proceeds was placed in escrow pending resolution of certain title requirements, $4.3 million of which was released in June 2014. If the remaining title requirements are not satisfied, waived or extended, some or all of the remaining $2.5 million of retained proceeds may be returned to the buyer. To the extent we are able to satisfy any of the remaining title requirements, we may recognize additional net proceeds from the sale in future periods. In February 2014, we sold a property in Ward County, Texas for $5.1 million, subject to customary closing adjustments.

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

In April 2013, we sold a 75% interest in our rights to the base of the Delaware formation in approximately 12,000 net undeveloped acres in Loving County, Texas to an unaffiliated third party for $6.8 million. In December 2013, we sold our remaining interest in the same acreage for $34.5 million, subject to customary closing adjustments.

Net proceeds from each of these transactions were applied to repay a portion of the outstanding balance on the credit facility at the time of receipt.

5. Asset Retirement Obligations

We record the 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.

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 for the years ended December 31, 2014 and December 31, 2013:



	2014			2013
	(In thousands)
Beginning of year	$	49,981		$	51,477
Additional ARO from new properties	1,209			795
Sales or abandonments of properties	(5,246		)	(5,892		)
Accretion expense	3,662			4,203
Revisions of previous estimates	(3,909		)	(602		)
End of year	$	45,697		$	49,981

6. Deferred Revenue from Volumetric Production Payment

In March 2012, Southwest Royalties, Inc. (“SWR”), a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner, into SWR, with SWR continuing as the surviving entity in the mergers. To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million. Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725 MBOE of estimated future oil and gas production from certain properties derived from the mergers. The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and are to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties. Once the scheduled volumes have been delivered to the third party, the term overriding royalty interest will terminate. SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks associated with product prices. As a result, the VPP has been accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes are produced. The net proceeds from the VPP are recorded as a non-current liability in the consolidated balance sheets. Deferred revenue from the VPP will be amortized over the life of the VPP and will be recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). As of December 31, 2014, we have a remaining obligation to deliver approximately 375 MBOE.

The following table reflects the changes in deferred revenue during the years ended December 31, 2014 and December 31, 2013:



	2014			2013
	(In thousands)
Beginning of period	$	29,770		$	37,184
Deferred revenue from VPP	1,067			1,332
Amortization of deferred revenue from VPP	(7,708		)	(8,746		)
End of period	$	23,129		$	29,770

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Income Taxes

Deferred tax assets and liabilities are the result of temporary differences between the consolidated financial statement carrying values and the tax basis of assets and liabilities. Significant components of net deferred tax assets (liabilities) at December 31, 2014 and 2013 are as follows:



	2014			2013
	(In thousands)
Deferred tax assets:
Net operating loss carryforwards	$	84,587		$	65,814
Statutory depletion carryforwards	9,581			8,658
Asset retirement obligations and other	19,061			22,470
	113,229			96,942
Deferred tax liabilities:
Fair value of derivatives	—			(598		)
Property and equipment	(270,917		)	(229,572		)
	(270,917		)	(230,170		)
Net deferred tax liabilities	$	(157,688	)	$	(133,228	)

Components of net deferred tax liabilities:
Current assets	$	6,911		$	7,581
Non-current liabilities	(164,599		)	(140,809		)
Net deferred tax liabilities	$	(157,688	)	$	(133,228	)

For the years ended December 31, 2014, 2013 and 2012, effective income tax rates were different than the statutory federal income tax rates for the following reasons:



	2014			2013			2012
	(In thousands)
Income tax expense (benefit) at statutory rate of 35%	$	23,999		$	(13,052	)	$	19,989
Tax depletion in excess of basis	(729		)	(518		)	(581		)
Revision of previous tax estimates	(155		)	373			700
State income taxes, net of federal tax effect	1,008			76			1,513
Other	564			693			387
Income tax expense (benefit)	$	24,687		$	(12,428	)	$	22,008

Current	$	227		$	1,614		$	—
Deferred	24,460			(14,042		)	22,008
Income tax expense (benefit)	$	24,687		$	(12,428	)	$	22,008

We derive a tax deduction when options are exercised under our stock option plans. To the extent these tax deductions are used to reduce currently payable taxes in any period, we record a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements. At December 31, 2014, our cumulative tax loss carryforwards were approximately $263.2 million, of which $22 million relates to excess tax benefits from exercise of stock options. The cumulative tax loss carryforwards are scheduled to expire if not utilized between 2025 and 2029.

In assessing the ability to realize deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

generation of future taxable income during the periods in which those temporary differences become deductible. If it is more likely than not that some portion or all of the assets will not be realized, the assets are reduced by a valuation allowance. Based on our analysis of future taxable income, no valuation allowance is required.

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 2010 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time. We do not have any uncertain tax positions as of December 31, 2014 and 2013.

8. Derivatives

Commodity Derivatives

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

Swaps



	Oil
	MBbls	Price
Production Period:
2nd Quarter 2015	448	$	55.65
3rd Quarter 2015	697	$	55.65
4th Quarter 2015	592	$	55.65
	1,737

Accounting for 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 income (loss).

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Effect of Derivative Instruments on the Consolidated Balance Sheets



	Fair Value of Derivative Instruments as of December 31, 2014
	Asset Derivatives			Liability Derivatives
	Balance Sheet			Balance Sheet
	Location	Fair Value		Location	Fair Value
		(In thousands)			(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives	Fair value of derivatives:			Fair value of derivatives:
	Current	$	—	Current	$	—
	Non-current	—		Non-current	—
Total		$	—		$	—



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

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities



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



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

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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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



	Amount of Gain or (Loss) Recognized in Earnings
	Year Ended December 31,
Location of Gain or (Loss) Recognized in Earnings	2014		2013			2012
	(In thousands)
Derivatives not designated as hedging instruments:
Commodity derivatives:
Other income (expense) -
Gain (loss) on derivatives	$	4,789	$	(8,731	)	$	14,448
Total	$	4,789	$	(8,731	)	$	14,448

9. Fair Value of Financial Instruments

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

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



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

Fair Value of Other Financial Instruments

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

December 31, 2014

December 31, 2013

Carrying

Estimated

Carrying

Estimated

Description

Amount

Fair Value

Amount

Fair Value

(In thousands)

7.75% Senior Notes due 2019

599,696

510,000

599,638

616,500

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

10. Compensation Plans

Stock-Based Compensation

Initially, we reserved 86,300 shares of Common Stock for issuance under the Outside Directors Stock Option Plan (the “Directors Plan”). Since the inception of the Directors Plan, CWEI has issued options covering 52,000 shares of Common Stock at option prices ranging from $3.25 to $41.74 per share. All options expired ten years from the grant date and were fully exercisable upon issuance. No options were granted under the Directors Plan in 2014 or 2013, and options to purchase 4,000 shares of Common Stock (with an intrinsic value of $262,890) were exercised during the year ended December 31, 2014. In December 2009, the Board reduced the number of shares available for issuance under the Directors Plan to a level sufficient to cover only the remaining outstanding shares.

The following table sets forth certain information regarding our stock option plans as of and for the year ended December 31, 2014:



	Shares		Weighted Average Exercise Price		Aggregate Intrinsic Value^(a)
Outstanding at January 1, 2014	4,000		$	33.03
Exercised ^(b)	(4,000	)	$	33.03	$	262,890
Outstanding at December 31, 2014	—

_______


(a)	Based on exercise date closing price at September 25, 2014 of $98.75 per share.


(b)	Cash received for options exercised totaled approximately $130,000.

The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2014, 2013 and 2012.



	2014		2013		2012
	(In thousands, except per share)
Weighted average grant date fair value of options granted per share	$	—	$	—	$	—
Intrinsic value of options exercised	$	263	$	53	$	28

Non-Equity Award Plans

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

The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to 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

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CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in 15 specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to June 11, 2014. Of these 15 awards, eight awards are fully vested, two awards will fully vest on May 1, 2015, two awards will fully vest on August 1, 2015 and three will fully vest on June 23, 2016.

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

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

We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and 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 was $4.6 million in 2014, $2.1 million in 2013 and $2.1 million in 2012.

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



	December 31, 2014		December 31, 2013
	(In thousands)
Current liabilities:
Accrued liabilities and other	$	2,317	$	3,317
Non-current liabilities:
Accrued compensation under non-equity award plans	17,866		15,469
Total accrued compensation under non-equity award plans	$	20,183	$	18,786

F-20

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Transactions with Affiliates

The Company and other entities (the “Williams Entities”) controlled by Mr. Williams are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, as amended from time to time, CWEI provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services, and financial and accounting services to the Williams Entities, as well as technical services with respect to certain oil and gas properties owned by the Williams Entities. The Williams Entities provide business entertainment to or for the benefit of CWEI. The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2014, 2013 and 2012.



	2014		2013		2012
	(In thousands)
Amounts received from the Williams Entities:
Service Agreement:
Services	$	663	$	715	$	671
Insurance premiums and benefits	960		837		920
Reimbursed expenses	296		427		566
	$	1,919	$	1,979	$	2,157
Amounts paid to the Williams Entities:
Rent^(a)	$	1,614	$	1,560	$	1,478
Service Agreement:
Business entertainment^(b)	205		344		116
Reimbursed expenses	204		216		267
	$	2,023	$	2,120	$	1,861

_______


(a)	Rent amounts were paid to a partnership within the Williams Entities. The Company owns 31.9% of the partnership and affiliates of the Company own 25.8%.


(b)	Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams.

Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for customary charges by the Company as operator of certain wells in which affiliates own an interest.

12. Other Operating Revenues and Expenses

Other operating revenues and expenses for the years ended December 31, 2014, 2013 and 2012 are as follows:



	2014			2013			2012
	(In thousands)
Other operating revenues:
Gain on sales of assets	$	11,685		$	4,467		$	1,496
Marketing revenue	3,708			2,021			581
Total other operating revenues	$	15,393		$	6,488		$	2,077
Other operating expenses:
Loss on sales of assets	$	(2,511	)	$	(1,233	)	$	(523	)
Marketing expense	—			(658		)	—
Impairment of inventory	(36		)	(210		)	(510		)
Total other operating expenses	$	(2,547	)	$	(2,101	)	$	(1,033	)

F-21

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Gain on sales of assets included the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014, the sale of a property in Ward County, Texas in February 2014, and the sale of a portion of our Andrews County Wolfberry assets in April 2013 (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 is carried at cost of $11 million. As of December 31, 2014, we have performed a qualitative assessment and determined there has been no indication of any impairment of our investment in Dalea.

14. Commitments and Contingencies

Leases

We lease office space from affiliates and nonaffiliates under noncancelable operating leases. Rental expense pursuant to the office leases amounted to $1.8 million, $1.8 million and $1.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Future minimum payments under noncancelable leases at December 31, 2014 are as follows:



	Leases
	Capital^(a)		Operating^(b)		Total
	(In thousands)
2015	$	995	$	4,055	$	5,050
2016	575		3,719		4,294
2017	131		354		485
Thereafter	—		—		—
Total minimum lease payments	$	1,701	$	8,128	$	9,829

_______

(a) Relates to vehicle leases.

(b) Includes leases for two drilling rigs.

Legal Proceedings

F-22

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 is appealing the judgment. All appellate briefs have been filed with the El Paso Court of Appeals, and argument has been scheduled for June 4, 2015.

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

15. Impairment of Property and Equipment

We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value. The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset. We categorize the measurement of fair value of these assets as Level 3 inputs. We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: (1) discounted cash flow method; (2) flowing daily production method; and (3) proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances. We utilize all three methods when that information is available, or if not will utilize the discounted cash flow method. We recorded provisions for impairment of proved properties aggregating $12 million in 2014, $89.8 million in 2013 and $5.9 million in 2012 to reduce the carrying value of those properties to their estimated fair values. The 2014 provision of $12 million related to the write-down of certain non-core properties in the Permian Basin and North Dakota. The 2013 provision of $89.8 million related to the write down of our Andrews County Wolfberry assets and certain non-core properties in the Permian Basin. The 2012 provision of $5.9 million related primarily to certain non-core properties in the Permian Basin.

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 these assets as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $15.4 million, $3.4 million and $1.4 million in 2014, 2013 and 2012, respectively, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).

F-23

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Costs of Oil and Gas Properties

The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2014, 2013 and 2012.



	2014		2013		2012
	(In thousands)
Property acquisitions:
Proved	$	—	$	—	$	41,098
Unproved	56,327		50,104		72,235
Developmental costs	342,716		218,341		349,972
Exploratory costs	4,350		3,932		10,898
Total	$	403,393	$	272,377	$	474,203

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



	2014			2013
	(In thousands)
Proved properties	$	2,585,279		$	2,317,053
Unproved properties	99,634			86,224
Total capitalized costs	2,684,913			2,403,277
Accumulated depletion	(1,430,699		)	(1,282,989		)
Net capitalized costs	$	1,254,214		$	1,120,288

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 years ended December 31, 2014, 2013 and 2012.



				Contract			Intercompany			Consolidated
For the Year Ended December 31, 2014	Oil and Gas			Drilling			Eliminations			Total
	(In thousands)
Revenues	$	440,428		$	59,107		$	(31,079	)	$	468,456
Depreciation, depletion and amortization^(a)	157,164			13,307			(4,088		)	166,383
Other operating expenses^(b)	170,878			41,912			(22,356		)	190,434
Interest expense	50,907			—			—			50,907
Other (income) expense	(8,001		)	165			—			(7,836		)
Income (loss) before income taxes	69,480			3,723			(4,635		)	68,568
Income tax (expense) benefit	(23,384		)	(1,303		)	—			(24,687		)
Net income (loss)	$	46,096		$	2,420		$	(4,635	)	$	43,881
Total assets	$	1,482,863		$	70,051		$	(42,029	)	$	1,510,885
Additions to property and equipment	$	412,951		$	27,128		$	(4,635	)	$	435,444

F-24

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



				Contract			Intercompany			Consolidated
For the Year Ended December 31, 2013	Oil and Gas			Drilling			Eliminations			Total
	(In thousands)
Revenues	$	411,403		$	37,255		$	(19,443	)	$	429,215
Depreciation, depletion and amortization^(a)	229,460			13,844			(2,591		)	240,713
Other operating expenses^(b)	159,294			32,817			(16,224		)	175,887
Interest expense	43,079			—			—			43,079
Other (income) expense	6,826			—			—			6,826
Income (loss) before income taxes	(27,256		)	(9,406		)	(628		)	(37,290		)
Income tax (expense) benefit	9,136			3,292			—			12,428
Net income (loss)	$	(18,120	)	$	(6,114	)	$	(628	)	$	(24,862	)
Total assets	$	1,339,920		$	54,697		$	(27,880	)	$	1,366,737
Additions to property and equipment	$	280,173		$	5,107		$	(628	)	$	284,652



				Contract			Intercompany			Consolidated
For the Year Ended December 31, 2012	Oil and Gas			Drilling			Eliminations			Total
	(In thousands)
Revenues	$	407,194		$	57,218		$	(41,360	)	$	423,052
Depreciation, depletion and amortization^(a)	140,967			14,442			(6,778		)	148,631
Other operating expenses^(b)	176,922			52,678			(34,972		)	194,628
Interest expense	38,664			—			—			38,664
Other (income) expense	(15,979		)	(3		)	—			(15,982		)
Income (loss) before income taxes	66,620			(9,899		)	390			57,111
Income tax (expense) benefit	(25,473		)	3,465			—			(22,008		)
Net income (loss)	$	41,147		$	(6,434	)	$	390		$	35,103
Total assets	$	1,535,544		$	64,045		$	(25,005	)	$	1,574,584
Additions to property and equipment	$	500,161		$	15,207		$	390		$	515,758

_______


(a)	Includes impairment of property and equipment.


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

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 same indenture (see Note 3). Presented below is condensed consolidated financial information of CWEI (the “Issuer”) and the Issuer’s material wholly owned subsidiaries. Other than CWEI Andrews Properties, GP, LLC, the general partner of CWEI Andrews Properties, L.P., an affiliated limited partnership formed in April 2013, all of the Issuer’s wholly owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the Indenture. CWEI Andrews Properties, GP, LLC, is not a guarantor of the 2019 Senior Notes and its accounts are reflected in the “Non-Guarantor Subsidiary” column in this Note 18.

F-25

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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


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

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

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

F-26

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2014 (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Total revenue	$	324,055		$	140,857		$	3,544		$	—		$	468,456
Costs and expenses	242,658			111,750			2,409			—			356,817
Operating income (loss)	81,397			29,107			1,135			—			111,639
Other income (expense)	(45,538		)	919			1,548			—			(43,071		)
Equity in earnings of subsidiaries	21,261			—			—			(21,261		)	—
Income tax (expense) benefit	(13,239		)	(10,509		)	(939		)	—			(24,687		)
Net income (loss)	$	43,881		$	19,517		$	1,744		$	(21,261	)	$	43,881

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2013 (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Total revenue	$	280,423		$	146,556		$	2,236		$	—		$	429,215
Costs and expenses	302,898			112,441			1,261			—			416,600
Operating income (loss)	(22,475		)	34,115			975			—			12,615
Other income (expense)	(50,601		)	(25		)	721			—			(49,905		)
Equity in earnings of subsidiaries	23,261			—			—			(23,261		)	—
Income tax (expense) benefit	24,953			(11,931		)	(594		)	—			12,428
Net income (loss)	$	(24,862	)	$	22,159		$	1,102		$	(23,261	)	$	(24,862	)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2012 (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Total revenue	$	291,782		$	132,690		$	—	$	(1,420	)	$	423,052
Costs and expenses	230,033			114,646			—		(1,420		)	343,259
Operating income (loss)	61,749			18,044			—		—			79,793
Other income (expense)	(25,495		)	2,813			—		—			(22,682		)
Equity in earnings of subsidiaries	13,557			—			—		(13,557		)	—
Income tax (expense) benefit	(14,708		)	(7,300		)	—		—			(22,008		)
Net income (loss)	$	35,103		$	13,557		$	—	$	(13,557	)	$	35,103

F-27

CLAYTON WILLIAMS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Operating activities	$	178,769		$	69,543		$	5,842		$	3,967		$	258,121
Investing activities	(274,629		)	(34,749		)	(5,652		)	(3,967		)	(318,997		)
Financing activities	97,384			(34,987		)	(128		)	—			62,269
Net increase (decrease) in cash and cash equivalents	1,524			(193		)	62			—			1,393
Cash at the beginning of the period	19,693			6,886			44			—			26,623
Cash at end of the period	$	21,217		$	6,693		$	106		$	—		$	28,016

Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2013 (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary			Adjustments/ Eliminations			Consolidated
Operating activities	$	128,146		$	87,433		$	2,406		$	2,591		$	220,576
Investing activities	10,544			(34,121		)	(2,875		)	(2,591		)	(29,043		)
Financing activities	(125,027		)	(51,122		)	513			—			(175,636		)
Net increase (decrease) in cash and cash equivalents	13,663			2,190			44			—			15,897
Cash at the beginning of the period	6,030			4,696			—			—			10,726
Cash at end of the period	$	19,693		$	6,886		$	44		$	—		$	26,623

Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2012 (Dollars in thousands)

	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiary		Adjustments/ Eliminations			Consolidated
Operating activities	$	92,521		$	89,923		$	—	$	6,778		$	189,222
Investing activities	(432,433		)	(36,822		)	—		(6,778		)	(476,033		)
Financing activities	333,703			(53,691		)	—		—			280,012
Net increase (decrease) in cash and cash equivalents	(6,209		)	(590		)	—		—			(6,799		)
Cash at the beginning of the period	12,239			5,286			—		—			17,525
Cash at end of the period	$	6,030		$	4,696		$	—	$	—		$	10,726

19. Subsequent Events

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

F-28

Table of Contents



CLAYTON WILLIAMS ENERGY, INC.
SUPPLEMENTAL INFORMATION
(UNAUDITED)

Supplemental Quarterly Financial Data

The following table summarizes results for each of the four quarters in the years ended December 31, 2014 and 2013.



	First Quarter			Second Quarter			Third Quarter		Fourth Quarter			Year
	(In thousands, except per share)
Year ended December 31, 2014:
Total revenues	$	124,605		$	129,895		$	119,283	$	94,673		$	468,456
Operating income (loss)	$	34,579		$	34,739		$	45,565	$	(3,244	)	$	111,639
Net income (loss)	$	11,392		$	9,327		$	27,429	$	(4,267	)	$	43,881
Net income (loss) per common share^(a):
Basic	$	0.94		$	0.77		$	2.25	$	(0.35	)	$	3.61
Diluted	$	0.94		$	0.77		$	2.25	$	(0.35	)	$	3.61
Weighted average common shares outstanding:
Basic	12,166			12,166			12,166		12,170			12,167
Diluted	12,166			12,166			12,166		12,170			12,167
Year ended December 31, 2013:
Total revenues	$	106,867		$	98,916		$	111,165	$	112,267		$	429,215
Operating income (loss)	$	(50,883	)	$	5,003		$	33,918	$	24,577		$	12,615
Net income (loss)	$	(41,209	)	$	(1,029	)	$	10,951	$	6,425		$	(24,862	)
Net income (loss) per common share^(a):
Basic	$	(3.39	)	$	(0.08	)	$	0.90	$	0.53		$	(2.04	)
Diluted	$	(3.39	)	$	(0.08	)	$	0.90	$	0.53		$	(2.04	)
Weighted average common shares outstanding:
Basic	12,165			12,165			12,165		12,165			12,165
Diluted	12,165			12,165			12,165		12,165			12,165

_______


(a)	The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.

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CLAYTON WILLIAMS ENERGY, INC.
SUPPLEMENTAL INFORMATION (Continued)
(UNAUDITED)

Supplemental Oil and Gas Reserve Information

The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the Securities and Exchange Commission and the FASB. All of our reserves are located in the United States. For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations and comprehensive income (loss).

We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.

We did not have any capital costs relating to exploratory wells pending the determination of proved reserves for the years ended December 31, 2014, 2013 and 2012.

The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended December 31, 2014, 2013 and 2012.



	Oil		Natural Gas Liquids		Natural Gas		MBOE
Proved reserves:
December 31, 2011	44,919		4,617		88,876		64,349
Extensions and discoveries	13,501		3,175		22,604		20,443
Revisions	(7,303	)	1,805		(6,699	)	(6,615	)
Purchases of minerals-in-place	2,456		18		6,182		3,504
Sales of minerals-in-place	(633	)	—		(555	)	(725	)
Production	(3,821	)	(433	)	(8,072	)	(5,599	)
December 31, 2012	49,119		9,182		102,336		75,357
Extensions and discoveries	20,540		3,562		21,389		27,666
Revisions	85		1,806		(16,753	)	(901	)
Sales of minerals-in-place	(17,387	)	(5,531	)	(23,605	)	(26,852	)
Production	(3,692	)	(532	)	(6,188	)	(5,255	)
December 31, 2013	48,665		8,487		77,179		70,015
Extensions and discoveries	19,032		2,298		12,034		23,336
Revisions	(7,786	)	(1,160	)	(6,934	)	(10,101	)
Sales of minerals-in-place	(1,850	)	(73	)	(803	)	(2,057	)
Production	(4,194	)	(585	)	(5,901	)	(5,763	)
December 31, 2014	53,867		8,967		75,575		75,430
Proved developed reserves:
December 31, 2012	27,641		5,044		64,013		43,354
December 31, 2013	25,989		4,293		47,839		38,255
December 31, 2014	29,059		4,668		51,072		42,239

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CLAYTON WILLIAMS ENERGY, INC.
SUPPLEMENTAL INFORMATION (Continued)
(UNAUDITED)

The 10,101 MBOE of net downward revisions in proved reserves for 2014 resulted from a combination of (1) reclassifications of 4,911 MBOE of proved undeveloped reserves to probable reserves due solely to the SEC 5-year development rule, (2) other net downward revisions of 4,837 MBOE related primarily to proved undeveloped reserves associated with vertical locations in Reeves County, Texas originally assigned prior to our conversion to horizontal drilling in this area, and (3) downward revisions of 353 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves.

The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2014, 2013 and 2012 was as follows:



	2014			2013			2012
	(In thousands)
Future cash inflows	$	5,479,211		$	5,162,702		$	5,222,621
Future costs:
Production	(1,719,989		)	(1,724,560		)	(1,819,356		)
Abandonment	(149,112		)	(131,747		)	(137,499		)
Development	(695,180		)	(592,695		)	(651,292		)
Income taxes	(833,601		)	(786,196		)	(673,686		)
Future net cash flows	2,081,329			1,927,504			1,940,788
10% discount factor	(1,148,416		)	(1,000,581		)	(1,000,957		)
Standardized measure of discounted net cash flows	$	932,913		$	926,923		$	939,831

Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2014, 2013 and 2012 were as follows:



	2014			2013			2012
	(In thousands)
Standardized measure, beginning of period	$	926,923		$	939,831		$	938,513
Net changes in sales prices, net of production costs	(94,104		)	13,292			(196,930		)
Revisions of quantity estimates	(234,612		)	(10,680		)	(144,899		)
Accretion of discount	138,095			130,736			137,369
Changes in future development costs, including development costs incurred that reduced future development costs	146,392			46,068			148,733
Changes in timing and other	(70,774		)	(10,249		)	(58,323		)
Net change in income taxes	2,893			(84,673		)	76,593
Future abandonment cost, net of salvage	4,066			232			(9,230		)
Extensions and discoveries	431,895			502,619			289,999
Sales, net of production costs	(309,758		)	(289,035		)	(277,248		)
Purchases of minerals-in-place	—			—			80,744
Sales of minerals-in-place	(8,103		)	(311,218		)	(45,490		)
Standardized measure, end of period	$	932,913		$	926,923		$	939,831

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CLAYTON WILLIAMS ENERGY, INC.
SUPPLEMENTAL INFORMATION (Continued)
(UNAUDITED)

The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period. Average prices for December 31, 2014, 2013 and 2012 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from January through December during each respective calendar year. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties. The average prices used for each commodity for the years ended December 31, 2014, 2013 and 2012 were as follows:



	Average Price
	Oil		Natural Gas Liquids		Natural Gas
	($/Bbl)		($/Bbl)		($/Mcf)
As of December 31:
2014	$	90.48	$	31.54	$	4.27
2013	$	94.88	$	31.63	$	3.59
2012	$	90.45	$	43.74	$	3.70

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CLAYTON WILLIAMS ENERGY INC /DE - FORM 10-K - February 27, 2015

Attached files

CLAYTON WILLIAMS ENERGY INC /DE Reports