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, 2013
or
| 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. x
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 Act.
Large accelerated filer o | Accelerated filer x | |
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. $256,371,078.
There were 12,165,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 7, 2014.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement relating to the 2014 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2014, are incorporated by reference in Part III of this Form 10-K.
CLAYTON WILLIAMS ENERGY, INC. TABLE OF CONTENTS | ||
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| TABLE OF CONTENTS (Continued) | ||
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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) Part I, “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; |
| • | 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 our revolving credit facility and impairments; |
| • | the ability of financial counterparties to perform or fulfill their obligations under existing agreements; |
| • | the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures; |
| • | drilling and other operating risks; |
| • | hurricanes and other weather conditions; |
| • | lack of availability of goods and services; |
| • | regulatory and environmental risks associated with drilling and production activities; |
| • | the adverse effects of changes in applicable tax, environmental and other regulatory legislation; and |
| • | the other risks described in 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, 2013, our estimated proved reserves were 70,015 MBOE, of which 55% were proved developed. Our portfolio of oil and natural gas reserves is weighted in favor of oil, with approximately 82% of our proved reserves at December 31, 2013 consisting of oil and natural gas liquids (“NGL”) and approximately 18% consisting of natural gas. During 2013, we added proved reserves of 27,666 MBOE through extensions and discoveries, had downward revisions of 901 MBOE and had sales of minerals-in-place of 26,852 MBOE. We also had average net production of 14.4 MBOE per day in 2013, which implies a reserve life of approximately 13.3 years. CWEI held interests in 3,163 gross (1,542.4 net) producing oil and gas wells and owned leasehold interests in approximately 907,000 gross (479,000 net) undeveloped acres at December 31, 2013.
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 the 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 we currently plan to exploit these resources as long as our margins between oil prices and the costs of drilling, completion and other field services remain acceptable. In addition to our developmental drilling, we also remain committed to exploring for oil and gas reserves in areas that we believe offer us exceptional opportunities for reserve growth, and we continue to 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
In 2013, we successfully executed our plan to significantly improve liquidity through a combination of strategic steps to lower capital spending, sell certain producing properties and issue additional Senior Notes as defined below. We believe these actions were effective in achieving a more sustainable balance between our future capital commitments and our expected financial resources. Those actions included the following:
•Reduced capital spending by 37% from 2012 spending levels;
| • | Monetized a substantial portion of our Andrews County Wolfberry oil and gas reserves, leasehold interests and facilities for $215.2 million; |
•Sold our interest in approximately 12,000 net acres in Loving County, Texas for $41.3 million; and
•Issued an additional $250 million of our 7.75% Senior Notes due 2019 (the “2019 Senior Notes”).
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In February 2014, we entered into a purchase and sale agreement with a third party 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. The properties subject to the purchase and sale agreement, which are situated outside of our core block of Austin Chalk and Eagle Ford acreage, accounted for approximately 5% of our fourth quarter 2013 production and approximately 2% of our total proved reserves at December 31, 2013. The transaction is expected to close in March 2014. Net proceeds from the sale, if consummated, will be used to repay the outstanding balance on our revolving bank credit facility and to fund a portion of our planned capital expenditures for 2014.
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.
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”). The Assets accounted for approximately 20% of our total proved reserves at December 31, 2012. 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.
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 for $6.8 million. In December 2013, we sold our remaining interest in the same acreage for $34.5 million, subject to customary closing adjustments. The proceeds from these sales were used to repay a portion of our outstanding balance on our revolving credit facility.
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. We may sell additional non-core assets in the future and we may potentially sell a portion of our Reeves County Wolfbone assets to a joint venture partner.
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
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for our use, but are available to conduct contract drilling operations for third parties. As of February 28, 2014, we were using eight of our rigs to drill wells in our developmental drilling programs, three rigs were working for third parties and the remaining three rigs were idle.
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 $275 million during 2013 and currently plan to spend approximately $376.2 million on similar activities during 2014. Our actual expenditures during 2014 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Factors such as drilling results, changes in operating margins, the availability of capital resources and other factors could increase or decrease our actual expenditures during 2014.
Areas of Operations
Permian Basin
The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period. The Permian Basin covers an area approximately 250 miles wide and 350 miles long and contains commercial accumulations of oil and gas in multiple stratigraphic horizons at depths ranging from 1,000 feet to over 25,000 feet. The Permian Basin is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons and enhanced recovery potential. Although many fields in the Permian Basin have been heavily exploited in the past, higher product prices and improved technology (including deep horizontal drilling) continue to attract high levels of drilling and recompletion activities. We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc. (“SWR”). This acquisition provided us with an inventory of potential drilling and recompletion activities.
We spent $149.3 million in the Permian Basin during 2013 on drilling and completion activities and $12.6 million on leasing and seismic activities. We drilled and completed 50 gross (31.4 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during 2013. We currently plan to spend approximately $186.5 million on drilling and leasing activities in this area during 2014. Following is a discussion of our principal assets in the Permian Basin.
Delaware Basin
We currently hold approximately 80,000 net acres in the active Wolfbone resource play in the Delaware Basin in Reeves, Loving, Ward and Winkler Counties, Texas and may earn up to 5,000 additional net acres under an existing farm-out arrangement. The Wolfbone resource play generally refers to the interval from the Bone Springs formation down through the Wolfcamp formation at depths typically found between 8,000 and 13,000 feet. A Wolfbone well generally refers to a vertical well completed in multiple intervals within these formations or a horizontal well being completed in an interval within such formations. These Permian aged formations in the Delaware Basin are composed of limestone, sandstone and shale. Geology in the Delaware Basin consists of multiple stacked pay zones with both over-pressured and normal-pressured intervals. To date, we have focused on the over-pressured intervals, having drilled 99 wells in the area: 70 vertical wells and 29 horizontal wells targeting multiple Bone Springs/Wolfcamp intervals.
A significant portion of our current and future holdings in this area are associated with a farm-in agreement we entered into in March 2011, with Chesapeake Exploration, L.L.C. (“Chesapeake”) in southern Reeves County, Texas with a term of five years. Chesapeake’s position in the agreement is now held by SWEPI, LP (“Shell”). For each well that we drill in the farm-in area that meets certain specified requirements (each, a “carried well”), Shell, or its successors to this agreement, will retain a 25% carried interest, bearing none of the costs to drill and complete a carried well, and we will earn an undivided 75% interest in 640 net acres within the farm-in area. We amended the farm-in agreement with Shell in February 2014. The amendment replaced a commitment for 20 carried wells per year with a commitment to drill nine additional carried wells prior to December 31, 2014, on which date the agreement will terminate. Failure to drill these remaining carried wells will result in a penalty of $1 million for each undrilled well. We have since commenced the drilling of three of these wells, and anticipate that all of the commitment wells will be timely drilled. We have earned over 20,000 net acres under the farm-in. The amendment further provides for the renewal or extension of leases in the farm-in area with Shell receiving a 25% carry in the renewal costs in lieu of a drilling carry.
We are currently focused on drilling horizontal wells in the Wolfcamp A shale interval, with 14 Wolfcamp A wells currently in production and three wells being drilled. However, based on the results of our current Wolfbone C well and
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offset operators in the Wolfcamp B and C intervals, we may target the B and C zones in future wells to determine the feasibility of developmental drilling in multiple Wolfcamp shale intervals.
We spent approximately $109.6 million on drilling and completion activities and $11.5 million for leasing activities in the Wolfbone play during 2013. We plan to spend approximately $165.2 million on drilling and completion activities and $10 million on leasing activities in the Wolfbone play during 2014. We are currently utilizing three rigs in this area.
We own oil, gas and water disposal pipelines in Reeves County, consisting of 88 miles of oil pipelines with a design capacity of 18,000 barrels of oil per day, 87 miles of gas pipelines with a design capacity of 25,000 Mcf of natural gas per day and 87 miles of salt water disposal pipelines with a design capacity of 20,000 barrels of produced water per day. These facilities may be expanded to accommodate new wells as we continue our development in the area.
Other Permian Basin
Approximately 39% of our fourth quarter 2013 oil and gas production was derived from wells in parts of the Permian Basin other than our Delaware Basin Wolfbone resource play. Many of these wells are located on the Central Basin Platform, geographically located between the Midland Basin and Delaware Basin, and produce from formations with conventional porosity such as the San Andres, Grayburg, Fusselman, Ellenburger and Yeso formations. A significant portion of our production in this area is derived from mature fields, several of which are in varying stages of secondary and/or tertiary recovery.
Giddings Area
Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Giddings Area. Most of our wells in the Giddings Area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas. Hydrocarbons are also encountered in the Giddings Area from other formations, including the Cotton Valley, Deep Bossier, Eagle Ford Shale and Taylor formations. We have approximately 186,000 net acres in the Giddings Area. Following is a discussion of our principal assets in the Giddings Area.
Austin Chalk
Most of our existing production in the Giddings Area is derived from the Austin Chalk formation, an upper Cretaceous geologic formation in the Gulf Coast region of the United States that stretches across numerous fields in Texas and Louisiana. The Austin Chalk formation is generally encountered at depths of 5,500 to 7,000 feet. Horizontal drilling is the primary technique used in the Austin Chalk formation to enhance productivity by intersecting multiple zones. Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations in East Central Texas.
Eagle Ford Shale
Since July 2011, we have drilled and completed 16 horizontal Eagle Ford Shale wells. Each of these wells has been or will be completed by multi-stage hydraulic fracturing processes using about five million pounds of proppant and 100,000 barrels of water. We are currently using two of our drilling rigs in this area. During 2013, we spent approximately $64.2 million on drilling and completion activities and $31.2 million for leasing activities in the Eagle Ford Shale Area, and we currently plan to spend approximately $185.5 million on similar drilling and leasing activities in this area during 2014.
Other
We spent $18.9 million during 2013 on exploration and development activities in other regions, including South Louisiana, Oklahoma and California and we currently plan to spend $4.3 million during 2014.
South Louisiana
During the first quarter of 2013, we completed the Christian #1, an exploratory well in Jefferson Parish. During the second quarter we drilled the Macon Stringer Heirs #1, an exploratory well in Terrebone Parish, resulting in a dry hole. During 2013, we spent $6.6 million on drilling and leasing activities in South Louisiana.
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Oklahoma
We began drilling operations in 2013 on certain exploratory prospects in Oklahoma. These prospects were generated over the past two years using data obtained through proprietary 3-D seismic shoots and target multiple conventional oil-prone formations encountered above a vertical depth of 6,000 feet. To date, we have drilled four exploratory wells, resulting in three dry holes and one productive well, and have completed five development wells as productive wells. Two wells are currently being completed. During 2013, we spent $3.4 million on seismic, leasing and drilling activities in this area and we currently plan to spend approximately $2.3 million on similar drilling and leasing activities during 2014.
California
We own a 70% working interest in approximately 1,600 acres in two contiguous leases near the city of Whittier, California. Based on production history from more than 400 wells in the area, we are targeting multiple oil-bearing Miocene sands first encountered at depths above 1,500 feet, which we plan to directionally drill in order to maximize exposure to each target sand. We do not currently plan to drill on this acreage during 2014.
Known Trends and Uncertainties
We began 2013 with limited availability under our revolving credit facility and our leverage ratios were increasing. In 2013, we successfully executed our plan to significantly improve liquidity through a combination of strategic steps to lower capital spending, sell certain producing properties and issue additional 2019 Senior Notes. At December 31, 2013, we had $40 million of borrowings outstanding under our revolving credit facility, leaving $369.9 million available on the facility after allowing for outstanding letters of credit totaling $5.1 million as compared to $121 million of availability on the facility at December 31, 2012. Our leverage ratio, expressed as the ratio of total long-term debt to EBITDAX, improved from 3.4 times to 2.5 times. We believe these actions were effective in achieving a more sustainable balance between our future capital commitments and our expected financial resources.
Our developmental drilling programs are very sensitive to oil prices and drilling costs. We attempt to control costs through drilling efficiencies by the use of our own rigs, purchasing casing and tubing at periods when we believe prices are suitable and working with service providers to receive acceptable unit costs. We plan to continue these programs as long as oil prices remain favorable. In order to continue drilling in these areas, we must be able to realize an acceptable margin between our expected cash flows from new production and our cost to drill and complete new wells. If any combination of falling oil prices and rising costs of drilling, completion and other field services occurs in future periods, we may discontinue a program until margins return to acceptable levels.
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 74% of our oil reserves at December 31, 2013 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 more than a majority of our Permian Basin production.
Approximately 25% of our oil reserves at December 31, 2013 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. As a result, we receive a price that competes more directly with imported oil and therefore receive a premium to WTI, which premium averaged $2.20 per barrel in 2013.
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Although existing marketing arrangements in the Permian Basin mitigate, to a large extent, our exposure to material adverse changes in the Midland-Cushing differential, we remain exposed to that differential for a portion of our Permian Basin oil production and are exposed to material changes in the premium we currently receive for our Giddings Area production.
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.
Approximately 95% of our gas reserves at December 31, 2013 are attributable to a combination of dry gas and residue gas from processed casinghead production. This portion of our gas production is generally sold at values that correlate to the NYMEX natural gas market. The remaining 5% of our gas reserves at December 31, 2013 are attributable to a combination of unprocessed casinghead gas and processed casinghead gas for which the value of extracted NGL is included with the value of residue gas in determining the sales value of our wellhead production.
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 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 351 miles of pipeline, two treating plants, one dehydration facility and multiple wellhead type treating and/or compression stations. Most of our operated gas gathering and treating activities facilitate the transportation and marketing of our operated oil and gas production.
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.
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.
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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.
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
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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 in some instances 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.
Environmental 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 the emission and discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits prior to commencing certain activities or 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; 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 significant fines or penalties. 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. Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas. Some of our properties are located in areas particularly susceptible to hurricanes and other destructive storms, which 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 the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2014. We 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 interpretations thereof 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 could have an adverse impact on our operations.
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Hazardous substances. 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.
Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid 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 solid 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 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.
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 August 2012, the EPA adopted new rules that impose additional air emission control standards on well completion activities and certain production equipment, such as glycol dehydrators and storage vessels. Some of these new rules, such as a requirement for flaring of gas not sent to a gathering line, became effective in October 2012, but the most significant new rule, requiring the use of “green completions” emission control technology to reduce air emissions during well completions, does not become effective until January 1, 2015. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and potentially criminal enforcement actions. Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by us. 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. 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. 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. 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.
Global warming and climate change. 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,
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the EPA adopted rules regulating greenhouse gas emissions under the Clean Air Act, including emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. 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 natural gas production facilities, on an annual basis. We believe that we are in compliance with all greenhouse gas emissions reporting requirements applicable to our operations.
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 emissions 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 natural 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.
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, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. 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 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 either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisitions, chemical mixing, well injection, flowback and produced water, and wastewater treatment and waste disposal. The EPA has indicated that it expects to issue its study report in late 2014. 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 by late 2014. 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 degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act 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 Endangered Species Act and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. 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,
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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.
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, NGL, oil and condensate 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 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.
Claims are sometimes made or threatened against companies engaged in oil and 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 our revolving 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 18 to the accompanying consolidated financial statements.
Executive Officers
The following is a list, as of March 10, 2014 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 82, 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 five 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 59, 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 63, 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 55, 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 49, 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 77, is Vice President — Gas Gathering and Marketing of the Company, having served in such capacity since 1993.
SAMUEL L. LYSSY, JR., age 51, 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 61, is Vice President — New Ventures of the Company, having served in such capacity since 1993.
ROBERT L. THOMAS, age 57, 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 57, is Vice President and General Counsel of the Company, having served in such capacity since 1993.
GREGORY S. WELBORN, age 40, 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, 2013, we had 466 full-time employees, of which 216 were employed by Desta Drilling. None of our employees are subject to a collective bargaining agreement. 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 our revolving credit facility and through the capital markets. The amount available for borrowing under our revolving 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.
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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 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. If low oil and gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to internally fund our exploration and development activities. If our borrowing base under our revolving 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, 2013, the principal amount of our outstanding consolidated debt was approximately $639.6 million, which included $40 million outstanding under our revolving credit facility and $599.6 million in outstanding principal amount of the 2019 Senior Notes, net of unamortized discount. Our revolving 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. |
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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.
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. To the extent we have hedged a significant portion of our expected production and actual production is lower than we expected or the costs of goods and services increase, our profitability would be adversely affected.
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.
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 our revolving 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
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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 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 our revolving credit facility in establishing the borrowing base under the revolving 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, 2013, a significant portion of our proved reserves was derived from the Wolfberry play in Andrews County, Texas, the Wolfbone play in the Delaware Basin and the Austin Chalk formation 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, 2013, our estimated proved undeveloped reserves were 45% 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.
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.
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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 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.
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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.
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 our revolving
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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.
Our industry is highly competitive.
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.
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 82, 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
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and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.
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 Colombia 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 is an important and common practice that is used to stimulate production of 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 gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. 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.
On August 16, 2012, the EPA adopted final regulations under the Clean Air Act that, among other things, require additional emission controls for gas and NGL production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require the reduction of VOC emissions from gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. Compliance with these requirements could increase our costs of development and production.
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on water resources. The EPA’s study includes 18 separate research projects addressing topics such as water acquisition, chemical mixing, well injection, flowback and produced water, and wastewater treatment and disposal. The EPA has indicated that it expects to issue its study report in late 2014. 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 by late 2014. 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 efforts could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms, ultimately make it more difficult or costly for us to perform hydraulic fracturing and increase our costs of compliance and doing business.
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. During the past several years, West Texas and Southeastern New Mexico have experienced the lowest inflows of water in recent history, and these drought conditions expanded into the southern plains states in 2012. As a result of this severe drought, some local water districts may begin restricting the use of water subject
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to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. 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.
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, 2013, we had interests in 3,163 gross (1,542.4 net) oil and gas wells and owned leasehold interests in approximately 907,000 gross (479,000 net) undeveloped acres.
Reserves
The following table sets forth our estimated quantities of proved reserves as of December 31, 2013, 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 | 25,989 | 4,293 | 47,839 | 38,255 | ||||||||
| Undeveloped | 22,676 | 4,194 | 29,340 | 31,760 | ||||||||
| Total Proved | 48,665 | 8,487 | 77,179 | 70,015 | ||||||||
_______
| (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 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, 2013. The commodity prices used to estimate proved reserves and their related PV-10 at December 31, 2013 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from January 2013 through December 2013. The benchmark average prices for 2013 were $96.78 per barrel of oil and $3.67 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 $94.88 per barrel of oil, $31.63 per barrel of NGL and $3.59 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:
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| • | area-specific market adjustments, referred to as basis differentials, for oil, natural gas and NGL as discussed under “Marketing Arrangements;” |
| • | gravity, hydrogen sulfide content and other quality characteristics of produced oil; |
| • | 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, 2013. 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, 2013, we began with the PV-10 of our proved reserves and deducted the present value of estimated future income taxes of $415.5 million and net abandonment costs of $38.5 million, discounted at 10%. At December 31, 2013, our standardized measure of discounted future net cash flows totaled $926.9 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, 2013 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 | 18,675 | 3,756 | 21,532 | 26,020 | 37.2 | % | $ | 350,823 | 25.4 | % | |||||||||||
| Other | 17,081 | 4,078 | 36,194 | 27,190 | 38.8 | % | 489,554 | 35.4 | % | ||||||||||||
| Austin Chalk/Eagle Ford Shale | 12,348 | 608 | 8,571 | 14,385 | 20.5 | % | 495,551 | 35.9 | % | ||||||||||||
| Other | 561 | 45 | 10,882 | 2,420 | 3.5 | % | 45,020 | 3.3 | % | ||||||||||||
| Total | 48,665 | 8,487 | 77,179 | 70,015 | 100.0 | % | $ | 1,380,948 | 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 2013.
| Proved | ||
| Reserves | ||
| (MBOE) | ||
| As of December 31, 2012 | 75,357 | |
| Extensions and discoveries | 27,666 | |
| Revisions | (901 | ) |
| Sales of minerals-in-place | (26,852 | ) |
| Production | (5,255 | ) |
| As of December 31, 2013 | 70,015 | |
Extensions and discoveries. Extensions and discoveries in 2013 added 27,666 MBOE of proved reserves, replacing 526% of our 2013 production. These additions resulted primarily from our Andrews County Wolfberry, Delaware Basin and Giddings Eagle Ford programs. Of the total reserve additions, proved developed reserves accounted for 6,967 MBOE, while the remaining 20,699 MBOE were proved undeveloped reserves.
Revisions. Net downward revisions of 901 MBOE consisted of downward revisions of 1,504 MBOE related primarily to well performance, offset in part by upward revisions of 603 MBOE related to higher commodity prices on the estimated quantities of proved reserves.
Sales of minerals-in-place. The sale of our Andrews County Wolfberry assets in April 2013 accounted for approximately 20% of our total proved reserves at December 31, 2012. The sale included 26,852 MBOE of estimated future oil and gas production.
The following table summarizes changes in our estimated proved undeveloped reserves during 2013.
| Proved | ||
| Undeveloped | ||
| Reserves | ||
| (MBOE) | ||
| As of December 31, 2012 | 32,004 | |
| Extensions and discoveries | 20,699 | |
| Revisions | (2,231 | ) |
| Sales of minerals-in-place | (17,105 | ) |
| Reclassified to proved developed | (1,607 | ) |
| As of December 31, 2013 | 31,760 | |
We added 20,699 MBOE of proved undeveloped reserves from extensions and discoveries related to Permian Basin and Giddings Area drilling locations. Net downward revisions of 2,231 MBOE resulted primarily from downward performance revisions of 6,713 MBOE, offset in part by upward pricing revisions of 4,482 MBOE. The sale of our Andrews County Wolfberry assets in April 2013 included 17,105 MBOE of proved undeveloped reserves. We also converted 1,607 MBOE of proved undeveloped reserves at December 31, 2012 to proved developed reserves during 2013 at a cost of approximately $25.4 million. We expect to develop approximately 37.5% of our proved undeveloped reserves in 2014 at a cost of approximately $221.2 million.
As of December 31, 2013 approximately 0.9 MMBOE of our proved undeveloped reserves, or approximately 1% of our total proved reserves, have remained undeveloped for more than five years after disclosure as proved undeveloped reserves. Development of these reserves, which are attributable to our properties in the Empire East Field, Eddy County, New Mexico, have been delayed by a title dispute that was resolved in 2013. We expect to apply for the necessary state and federal drilling permits in 2014 and complete development in 2015.
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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 | 48,665 | 8,487 | 77,179 | 70,015 | $ | 1,380,948 | ||||||||||
| Futures Pricing Case | 40,094 | 6,674 | 64,761 | 57,562 | $ | 1,013,448 | ||||||||||
_______
| (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, 2013, as benchmark prices for 2014 through 2018, and continued to use the 2018 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 $80.96 per barrel of oil, $26.84 per barrel of NGL and $4.08 per Mcf of natural gas over the remaining life of the proved reserves.
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, 2013 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 66.4% and Ryder Scott evaluated 31.1% 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 31 years experience as a petroleum engineer, including 28 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 32 years experience in evaluating oil and gas reserves, including 30 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 2013 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 2013 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
33
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, 2013, 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, 2013, 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, | |||||||||||||||||
| 2013 | 2012 | 2011 | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| (Excludes wells in progress at the end of any period) | |||||||||||||||||
| Development Wells: | |||||||||||||||||
| Oil | 117 | 49.4 | 135 | 87.3 | 156 | 111.6 | |||||||||||
| Gas | 1 | — | — | — | 3 | 0.2 | |||||||||||
| Dry | 1 | 0.7 | 5 | 5.0 | — | — | |||||||||||
| Total | 119 | 50.1 | 140 | 92.3 | 159 | 111.8 | |||||||||||
| Exploratory Wells: | |||||||||||||||||
| Oil | 2 | 0.6 | 5 | 3.8 | 5 | 1.4 | |||||||||||
| Gas | 3 | 0.6 | — | — | 2 | 0.7 | |||||||||||
| Dry | 4 | 2.5 | 1 | 0.5 | 3 | 1.5 | |||||||||||
| Total | 9 | 3.7 | 6 | 4.3 | 10 | 3.6 | |||||||||||
| Total Wells: | |||||||||||||||||
| Oil | 119 | 50.0 | 140 | 91.1 | 161 | 113.0 | |||||||||||
| Gas | 4 | 0.6 | — | — | 5 | 0.9 | |||||||||||
| Dry | 5 | 3.2 | 6 | 5.5 | 3 | 1.5 | |||||||||||
| Total | 128 | 53.8 | 146 | 96.6 | 169 | 115.4 | |||||||||||
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, 2013, of productive wells in the areas indicated.
| Oil | Gas | Total | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Permian Basin Area: | |||||||||||||||||
| Delaware Basin | 97 | 78.7 | — | — | 97 | 78.7 | |||||||||||
| Other | 2,281 | 1,052.0 | 320 | 68.4 | 2,601 | 1,120.4 | |||||||||||
| Austin Chalk/Eagle Ford Shale | 351 | 287.6 | 19 | 11.2 | 370 | 298.8 | |||||||||||
| Other | 36 | 14.5 | 59 | 30.0 | 95 | 44.5 | |||||||||||
| Total | 2,765 | 1,432.8 | 398 | 109.6 | 3,163 | 1,542.4 | |||||||||||
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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, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Oil and Gas Production Data: | |||||||||||
| Oil (MBbls) | 3,692 | 3,821 | 3,727 | ||||||||
| Gas (MMcf) | 6,188 | 8,072 | 8,594 | ||||||||
| Natural gas liquids (MBbls) | 532 | 433 | 275 | ||||||||
Total (MBOE)(a) | 5,255 | 5,599 | 5,434 | ||||||||
Average Realized Prices(b) (c): | |||||||||||
| Oil ($/Bbl) | $ | 95.05 | $ | 90.97 | $ | 92.43 | |||||
| Gas ($/Mcf) | $ | 3.59 | $ | 3.59 | $ | 5.30 | |||||
| Natural gas liquids ($/Bbl) | $ | 33.26 | $ | 38.95 | $ | 53.37 | |||||
| Average Production Costs: | |||||||||||
Production ($/MBOE)(d) | $ | 14.68 | $ | 16.69 | $ | 13.07 | |||||
_______
| (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 2013 includes $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 2013 excludes production of 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, 2013. The following table discloses our oil, gas and NGL production from these fields for the periods indicated.
| Year Ended December 31, | ||||||||
| 2013 | 2012 | 2011 | ||||||
| Oil and Gas Production Data: | ||||||||
| Giddings Field | ||||||||
| Oil (MBbls) | 1,203 | 985 | 1,191 | |||||
| Gas (MMcf) | 683 | 674 | 679 | |||||
| Natural gas liquids (MBbls) | 82 | 87 | 73 | |||||
Total (MBOE) (a) | 1,399 | 1,184 | 1,377 | |||||
| Wolfbone Trend Field | ||||||||
| Oil (MBbls) | 761 | 610 | 83 | |||||
| Gas (MMcf) | 645 | 334 | 16 | |||||
| Natural gas liquids (MBbls) | 117 | 63 | — | |||||
Total (MBOE) (a) | 986 | 729 | 86 | |||||
_______
(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, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| (In thousands) | |||||||||||
| Property Acquisitions: | |||||||||||
| Proved | $ | — | $ | 41,098 | $ | — | |||||
| Unproved | 50,104 | 72,235 | 61,236 | ||||||||
| Developmental Costs | 218,341 | 349,972 | 328,418 | ||||||||
| Exploratory Costs | 3,932 | 10,898 | 27,425 | ||||||||
| Total | $ | 272,377 | $ | 474,203 | $ | 417,079 | |||||
Acreage
The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2013 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 | 183,896 | 62,371 | 476,804 | 217,536 | 660,700 | 279,907 | |||||||||||
| Giddings Area | 152,287 | 137,035 | 134,959 | 111,749 | 287,246 | 248,784 | |||||||||||
Other(a) | 16,065 | 7,710 | 294,754 | 149,506 | 310,819 | 157,216 | |||||||||||
| Total | 352,248 | 207,116 | 906,517 | 478,791 | 1,258,765 | 685,907 | |||||||||||
_______
| (a) | Net undeveloped acres are attributable to the following areas: Utah — 44,850; Colorado — 29,804; Alabama — 17,155; Louisiana — 9,513; Nevada — 8,535; Oklahoma — 7,631; Mississippi — 6,337; and Other — 25,681. |
The following table sets forth expiration dates of the leases of our gross and net undeveloped acres as of December 31, 2013.
Acres Expiring(a) | |||||||||||||||||
| 2014 | 2015 | 2016 | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Permian Basin | 55,544 | 30,181 | 38,825 | 22,629 | 12,390 | 6,749 | |||||||||||
| Giddings Area | 24,883 | 22,266 | 26,812 | 22,777 | 40,294 | 39,258 | |||||||||||
| Other | 22,884 | 10,765 | 42,084 | 22,054 | 41,603 | 37,268 | |||||||||||
| 103,311 | 63,212 | 107,721 | 67,460 | 94,287 | 83,275 | ||||||||||||
_______
| (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 Desta Drilling, we currently operate 14 drilling rigs, two of which we lease under long-term contracts. The Desta Drilling rigs are primarily reserved for our use but are available to conduct contract drilling operations for third parties. As of February 28, 2014, we were using eight of our rigs to drill wells in our developmental drilling programs, three rigs were working for third parties and the remaining three rigs were idle.
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Offices
We lease from a related partnership approximately 89,000 square feet of office space in Midland, Texas 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
In a case pending since 2001, SWR is a defendant in a suit filed in April 2011 in the Circuit Court of Union County, Arkansas where the plaintiffs are suing for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. The plaintiffs are seeking in excess of $8 million. In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $0.8 million, of which SWR would pay $0.7 million. To accomplish the settlement, the case would be converted to a class action, and each member of the class would be offered the right to either participate or opt out of the class and continue a separate action for damages. If more than 25% of the plaintiffs were to opt out of the settlement, SWR would have the right to terminate the settlement. Any plaintiffs opting out would be subject to all previous rulings of the court, including an order dismissing a significant number of the plaintiffs’ claims on the basis that such claims were time barred. SWR believes that the judge will approve the settlement and the number of the plaintiffs opting out of the settlement, if any, will be insignificant. We recorded a loss on settlement of $0.7 million for the year ended December 31, 2013 in connection with this proposed settlement. We are now awaiting finalization of the settlement by the court.
In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under the Chesapeake farm-in agreement. Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. The case was tried to the judge in October 2013 who ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million. As a result, CWEI recorded a loss of $1.4 million for the year ended December 31, 2013 in connection with the judgment. As a prerequisite for appeal, CWEI filed a motion with the trial court for new trial. In March 2014, rather than ruling on the motion, the trial court ordered the parties to a mediation.
CWEI has been named a defendant in three lawsuits filed in Louisiana by two parishes and a regional Levee Authority in coastal Louisiana, each alleging that historical industry operations have significantly damaged coastal marsh lands.
In July 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority-East filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against us, and approximately 100 other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations over the past 100 years have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. Plaintiff asserts claims for negligence, strict liability, public nuisance, private nuisance and breach of contract without making specific allegations against any individual defendant. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana.
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.
Our overall exposure to these three suits is not currently determinable. 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.
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Item 4 - Mine Safety Disclosures
Not applicable.
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 25, 2014, there were approximately 3,377 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, 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 | |||||
| Year Ended December 31, 2012: | |||||||
| Fourth Quarter | $ | 53.02 | $ | 35.32 | |||
| Third Quarter | 61.09 | 39.09 | |||||
| Second Quarter | 81.98 | 41.05 | |||||
| First Quarter | 98.17 | 73.04 | |||||
The closing price of our Common Stock at March 7, 2014 was $99.97 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 our revolving 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 Part III, “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 2014 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, 2013 were derived from our audited consolidated financial statements. The data set forth in this table should be read in conjunction with Part II, “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, | |||||||||||||||||||
| 2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
| (In thousands, except per share) | |||||||||||||||||||
| Statement of Operations Data: | |||||||||||||||||||
| Revenues: | |||||||||||||||||||
| Oil and gas sales | $ | 399,950 | $ | 403,143 | $ | 405,216 | $ | 326,320 | $ | 242,338 | |||||||||
| Midstream services | 4,965 | 1,974 | 1,408 | 1,631 | 6,146 | ||||||||||||||
| Drilling rig services | 17,812 | 15,858 | 4,060 | — | 6,681 | ||||||||||||||
| Other operating revenues | 6,488 | 2,077 | 15,744 | 3,680 | 796 | ||||||||||||||
| Total revenues | 429,215 | 423,052 | 426,428 | 331,631 | 255,961 | ||||||||||||||
| Costs and expenses: | |||||||||||||||||||
| Production | 108,405 | 124,950 | 101,099 | 83,146 | 76,288 | ||||||||||||||
| Exploration: | |||||||||||||||||||
| Abandonment and impairments | 5,887 | 4,222 | 20,840 | 9,074 | 78,798 | ||||||||||||||
| Seismic and other | 3,906 | 11,591 | 5,363 | 6,046 | 8,189 | ||||||||||||||
| Midstream services | 1,816 | 1,228 | 1,039 | 1,209 | 5,348 | ||||||||||||||
| Drilling rig services | 16,290 | 17,423 | 5,064 | 1,198 | 10,848 | ||||||||||||||
| Depreciation, depletion and amortization | 150,902 | 142,687 | 104,880 | 101,145 | 129,658 | ||||||||||||||
| Impairment of property and equipment | 89,811 | 5,944 | 10,355 | 11,908 | 59,140 | ||||||||||||||
| Accretion of asset retirement obligations | 4,203 | 3,696 | 2,757 | 2,623 | 3,120 | ||||||||||||||
| General and administrative | 33,279 | 30,485 | 41,560 | 35,588 | 20,715 | ||||||||||||||
| Other operating expenses | 2,101 | 1,033 | 1,666 | 1,750 | 5,282 | ||||||||||||||
| Total costs and expenses | 416,600 | 343,259 | 294,623 | 253,687 | 397,386 | ||||||||||||||
| Operating income (loss) | 12,615 | 79,793 | 131,805 | 77,944 | (141,425 | ) | |||||||||||||
| Other income (expense): | |||||||||||||||||||
| Interest expense | (43,079 | ) | (38,664 | ) | (32,919 | ) | (24,402 | ) | (23,758 | ) | |||||||||
| Loss on early extinguishment of long-term debt | — | — | (5,501 | ) | — | — | |||||||||||||
| Gain (loss) on derivatives | (8,731 | ) | 14,448 | 47,027 | 722 | (17,416 | ) | ||||||||||||
| Other income | 1,905 | 1,534 | 5,553 | 3,308 | 2,543 | ||||||||||||||
| Total other income (expense) | (49,905 | ) | (22,682 | ) | 14,160 | (20,372 | ) | (38,631 | ) | ||||||||||
| Income (loss) before income taxes | (37,290 | ) | 57,111 | 145,965 | 57,572 | (180,056 | ) | ||||||||||||
| Income tax (expense) benefit | 12,428 | (22,008 | ) | (52,142 | ) | (20,634 | ) | 64,096 | |||||||||||
| NET INCOME (LOSS) | (24,862 | ) | 35,103 | 93,823 | 36,938 | (115,960 | ) | ||||||||||||
| Less income attributable to noncontrolling interest, net of tax | — | — | — | — | (1,455 | ) | |||||||||||||
| NET INCOME (LOSS) attributable to Clayton Williams Energy, Inc. | $ | (24,862 | ) | $ | 35,103 | $ | 93,823 | $ | 36,938 | $ | (117,415 | ) | |||||||
| Net income (loss) per common share attributable to Clayton Williams Energy, Inc. stockholders: | |||||||||||||||||||
| Basic | $ | (2.04 | ) | $ | 2.89 | $ | 7.72 | $ | 3.04 | $ | (9.67 | ) | |||||||
| Diluted | $ | (2.04 | ) | $ | 2.89 | $ | 7.71 | $ | 3.04 | $ | (9.67 | ) | |||||||
| Weighted average common shares outstanding: | |||||||||||||||||||
| Basic | 12,165 | 12,164 | 12,161 | 12,148 | 12,138 | ||||||||||||||
| Diluted | 12,165 | 12,164 | 12,162 | 12,148 | 12,138 | ||||||||||||||
| Other Data: | |||||||||||||||||||
| Net cash provided by operating activities | $ | 220,576 | $ | 189,222 | $ | 280,047 | $ | 208,251 | $ | 104,711 | |||||||||
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| December 31, | |||||||||||||||||||
| 2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
| (In thousands) | |||||||||||||||||||
| Balance Sheet Data: | |||||||||||||||||||
| Working capital (deficit) | $ | 1,916 | $ | 3,556 | $ | (13,287 | ) | $ | (19,899 | ) | $ | 19,324 | |||||||
| Total assets | 1,366,737 | 1,574,584 | 1,226,271 | 890,917 | 784,604 | ||||||||||||||
| Long-term debt | 639,638 | 809,585 | 529,535 | 385,000 | 395,000 | ||||||||||||||
| Stockholders’ equity | 353,783 | 378,616 | 343,501 | 249,452 | 212,275 | ||||||||||||||
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 2013, 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 currently have three of our drilling rigs working in Reeves County, Texas drilling Wolfbone wells. We spent approximately $121.1 million in the Wolfbone area in Reeves County in 2013 on drilling, completion and leasing activities and currently plan to spend approximately $175.2 million in this area in 2014.
We are continuing to exploit our extensive acreage position in the Giddings Area. We currently have two of our rigs drilling Eagle Ford Shale wells. Since July 2011, we have completed 16 horizontal Eagle Ford Shale wells. In 2013, we spent approximately $95.4 million on Austin Chalk/Eagle Ford Shale drilling and leasing activities and currently plan to spend approximately $185.5 million in this area in 2014.
We currently have three of our drilling rigs working in Andrews County, Texas drilling Wolfberry wells. We spent approximately $13.8 million related primarily to drilling and completing Wolfberry wells in Andrews County in 2013 and currently plan to spend approximately $2.9 million in this area in 2014.
In 2013, we successfully executed our plan to significantly improve liquidity through a combination of strategic steps to lower capital spending, sell certain producing properties and issue additional 2019 Senior Notes. We believe these actions were effective in achieving a more sustainable balance between our future capital commitments and our expected financial resources.
Key Factors to Consider
The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2013 and the outlook for 2014.
| • | In April 2013, we sold 95% of our Wolfberry oil and gas reserves, leasehold interests and facilities located in Andrews County, Texas for $215.2 million, subject to customary closing adjustments. As a result, reported oil and gas production, revenues and operating costs for the quarter and year ended December 31, 2013 are not comparable to reported amounts for periods in 2012. |
| • | Oil and gas sales, excluding amortized deferred revenues, decreased $3.6 million, or 1%, from 2012. Production variances accounted for a decrease of $15.6 million, and price variances accounted for a $12 million increase. Oil and gas sales in 2013 also includes $8.7 million of amortized deferred revenue versus $8.3 million in 2012 attributable to the volumetric production payment (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 sale of our Andrews County Wolfberry assets discussed above, oil, gas and NGL production per BOE declined 6% compared to 2012, with oil production decreasing 3% to 10,115 barrels per day, gas production decreasing 23% to 16,953 Mcf per day and NGL production increasing 23% to 1,458 barrels per day. Oil and NGL production accounted for approximately 80% of our total BOE production in 2013 versus 76% in 2012. 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 |
41
quarter ended March 31, 2013, we began reporting these products separately, when possible, resulting in a reduction in natural gas volumes and an increase in extracted NGL volumes. Periods for 2012 have not been adjusted to conform to the 2013 presentation.
| • | After giving effect to the sale of our Andrews County Wolfberry assets discussed above, oil, gas and NGL production on a BOE basis increased 8% for 2013 as compared to 2012, with oil production increasing 1,141 barrels per day, gas production decreasing 3,933 Mcf per day and NGL production increasing 580 barrels per day. |
| • | Production costs decreased 13% from $125 million in 2012 to $108.4 million in 2013 due primarily to a reduction in costs associated with the sale of our Andrews County Wolfberry assets discussed above, lower salt water disposal costs and other cost savings resulting from infrastructure improvements in Reeves County. |
| • | We recorded an $8.7 million loss on derivatives in 2013 (net of a $0.7 million gain on settled contracts). For 2012, we recorded a $14.4 million gain on derivatives (net of a $3.4 million loss on settled contracts). Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations. |
| • | Interest expense increased to $43.1 million in 2013 from $38.7 million in 2012 due primarily to the issuance in October 2013 of $250 million aggregate principal amount of the 2019 Senior Notes. |
| • | General and administrative (“G&A”) expenses for 2013 were $33.3 million compared to $30.5 million in 2012. 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. |
| • | Our estimated proved oil and gas reserves at December 31, 2013 decreased 7% to 70,015 MBOE from 75,357 MBOE at December 31, 2012. We replaced 526% of our oil and gas production in 2013 through extensions and discoveries of 27,666 MBOE, had net downward revisions of 901 MBOE and sales of minerals-in-place of 26,852 MBOE (see Part I, “Item 2 — Properties — Reserves”). |
Proved Oil and Gas Reserves
The following table summarizes changes in our estimated proved reserves during 2013.
| Proved | ||
| Reserves | ||
| (MBOE) | ||
| As of December 31, 2012 | 75,357 | |
| Extensions and discoveries | 27,666 | |
| Revisions | (901 | ) |
| Sales of minerals-in-place | (26,852 | ) |
| Production | (5,255 | ) |
| As of December 31, 2013 | 70,015 | |
Extensions and discoveries. Extensions and discoveries in 2013 added 27,666 MBOE of proved reserves, replacing 526% of our 2013 production. These additions resulted primarily from our Andrews County Wolfberry, Delaware Basin and Giddings Eagle Ford programs. Of the total reserve additions, proved developed reserves accounted for 6,967 MBOE, while the remaining 20,699 MBOE were proved undeveloped reserves.
Revisions. Net downward revisions of 901 MBOE consisted of downward revisions of 1,504 MBOE related primarily to well performance, offset in part by upward revisions of 603 MBOE related to higher commodity prices on the estimated quantities of proved reserves.
Sales of minerals-in-place. The sale of our Andrews County Wolfberry assets in April 2013 accounted for approximately 20% of our total proved reserves at December 31, 2012. The sale included 26,852 MBOE of estimated future oil and gas production.
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The following table summarizes changes in our estimated proved undeveloped reserves during 2013.
| Proved | ||
| Undeveloped | ||
| Reserves | ||
| (MBOE) | ||
| As of December 31, 2012 | 32,004 | |
| Extensions and discoveries | 20,699 | |
| Revisions | (2,231 | ) |
| Sales of minerals-in-place | (17,105 | ) |
| Reclassified to proved developed | (1,607 | ) |
| As of December 31, 2013 | 31,760 | |
We added 20,699 MBOE of proved undeveloped reserves from extensions and discoveries related to Permian Basin and Giddings Area drilling locations. Net downward revisions of 2,231 MBOE resulted primarily from downward performance revisions of 6,713 MBOE, offset in part by upward pricing revisions of 4,482 MBOE. The sale of our Andrews County Wolfberry assets in April 2013 included 17,105 MBOE of proved undeveloped reserves. We also converted 1,607 MBOE of proved undeveloped reserves at December 31, 2012 to proved developed reserves during 2013 at a cost of approximately $25.4 million. We expect to develop approximately 37.5% of our proved undeveloped reserves in 2014 at a cost of approximately $221.2 million.
Supplemental Information
The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-K with data that is not readily available from those statements.
| As of or for the Year Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Oil and Gas Production Data: | |||||||||||
| Oil (MBbls) | 3,692 | 3,821 | 3,727 | ||||||||
| Natural Gas (MMcf) | 6,188 | 8,072 | 8,594 | ||||||||
| Natural gas liquids (MBbls) | 532 | 433 | 275 | ||||||||
Total (MBOE) (a) | 5,255 | 5,599 | 5,434 | ||||||||
Average Realized Prices (b) (c): | |||||||||||
| Oil ($/Bbl) | $ | 95.05 | $ | 90.97 | $ | 92.43 | |||||
| Natural Gas ($/Mcf) | $ | 3.59 | $ | 3.59 | $ | 5.30 | |||||
| Natural gas liquids ($/Bbl) | $ | 33.26 | $ | 38.95 | $ | 53.37 | |||||
Gain (Loss) on Settled Derivative Contracts(c): | |||||||||||
| ($ in thousands, except per unit) | |||||||||||
| Oil: Net realized gain (loss) | $ | 1,162 | $ | (3,410 | ) | $ | 23,354 | ||||
| Per unit produced ($/Bbl) | $ | 0.31 | $ | (0.89 | ) | $ | 6.27 | ||||
| Natural Gas: Net realized gain (loss) | $ | (472 | ) | $ | — | $ | 19,167 | ||||
| Per unit produced ($/Mcf) | $ | (0.08 | ) | $ | — | $ | 2.23 | ||||
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| As of or for the Year Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Average Daily Production: | |||||||||||
| Oil (Bbls): | |||||||||||
| Permian Basin Area: | |||||||||||
| Delaware Basin | 2,127 | 1,656 | 202 | ||||||||
Other (d) | 3,952 | 5,369 | 6,060 | ||||||||
| Austin Chalk | 2,581 | 2,728 | 3,397 | ||||||||
| Eagle Ford Shale | 1,136 | 346 | 80 | ||||||||
| Other | 319 | 341 | 472 | ||||||||
| Total | 10,115 | 10,440 | 10,211 | ||||||||
| Natural Gas (Mcf): | |||||||||||
| Permian Basin Area: | |||||||||||
| Delaware Basin | 1,720 | 910 | — | ||||||||
Other (d) (e) | 7,963 | 12,560 | 12,304 | ||||||||
| Austin Chalk | 2,043 | 2,029 | 2,140 | ||||||||
| Eagle Ford Shale | 78 | 5 | 2 | ||||||||
| Other | 5,149 | 6,551 | 9,099 | ||||||||
| Total | 16,953 | 22,055 | 23,545 | ||||||||
| Natural Gas Liquids (Bbls): | |||||||||||
| Permian Basin Area: | |||||||||||
| Delaware Basin | 316 | 168 | — | ||||||||
Other (d) (e) | 880 | 693 | 461 | ||||||||
| Austin Chalk | 223 | 267 | 212 | ||||||||
| Eagle Ford Shale | 19 | — | — | ||||||||
| Other | 20 | 55 | 80 | ||||||||
| Total | 1,458 | 1,183 | 753 | ||||||||
| Total Proved Reserves: | |||||||||||
| Oil (MBbls) | 48,665 | 49,119 | 44,919 | ||||||||
| Natural gas liquids (MBbls) | 8,487 | 9,182 | 4,617 | ||||||||
| Natural Gas (MMcf) | 77,179 | 102,336 | 88,876 | ||||||||
Total (MBOE) (a) | 70,015 | 75,357 | 64,349 | ||||||||
| Standardized measure of discounted future net cash flows | $ | 926,923 | $ | 939,831 | $ | 938,513 | |||||
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| As of or for the Year Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Total Proved Reserves by Area: | |||||||||||
| Oil (MBbls): | |||||||||||
| Permian Basin Area: | |||||||||||
| Delaware Basin | 18,675 | 14,618 | 7,519 | ||||||||
| Other | 17,081 | 25,955 | 28,226 | ||||||||
| Austin Chalk/Eagle Ford Shale | 12,348 | 8,039 | 8,669 | ||||||||
| Other | 561 | 507 | 505 | ||||||||
| Total | 48,665 | 49,119 | 44,919 | ||||||||
| Natural Gas Liquids (MBbls): | |||||||||||
| Permian Basin Area: | |||||||||||
| Delaware Basin | 3,756 | 4,249 | — | ||||||||
| Other | 4,078 | 4,345 | 4,016 | ||||||||
| Austin Chalk/Eagle Ford Shale | 608 | 572 | 545 | ||||||||
| Other | 45 | 16 | 56 | ||||||||
| Total | 8,487 | 9,182 | 4,617 | ||||||||
| Natural Gas (MMcf): | |||||||||||
| Permian Basin Area: | |||||||||||
| Delaware Basin | 21,532 | 20,651 | 6,887 | ||||||||
| Other | 36,194 | 64,727 | 62,549 | ||||||||
| Austin Chalk/Eagle Ford Shale | 8,571 | 6,130 | 6,271 | ||||||||
| Other | 10,882 | 10,828 | 13,169 | ||||||||
| Total | 77,179 | 102,336 | 88,876 | ||||||||
Total Oil Equivalents (MBOE) (a): | |||||||||||
| Permian Basin Area: | |||||||||||
| Delaware Basin | 26,020 | 22,309 | 8,667 | ||||||||
| Other | 27,190 | 41,087 | 42,667 | ||||||||
| Austin Chalk/Eagle Ford Shale | 14,385 | 9,633 | 10,259 | ||||||||
| Other | 2,420 | 2,328 | 2,756 | ||||||||
| Total | 70,015 | 75,357 | 64,349 | ||||||||
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| As of or for the Year Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Exploration Costs (in thousands): | |||||||||||
| Abandonment and impairment costs: | |||||||||||
| South Louisiana | $ | 1,000 | $ | 1,918 | $ | 2,105 | |||||
| Permian Basin | 2,047 | 453 | 673 | ||||||||
| Deep Bossier | — | 1,323 | 16,771 | ||||||||
| Other | 2,840 | 528 | 1,291 | ||||||||
| Total | 5,887 | 4,222 | 20,840 | ||||||||
| Seismic and other | 3,906 | 11,591 | 5,363 | ||||||||
| Total exploration costs | $ | 9,793 | $ | 15,813 | $ | 26,203 | |||||
| Oil and Gas Costs ($/BOE Produced): | |||||||||||
| Production costs | $ | 20.63 | $ | 22.32 | $ | 18.60 | |||||
| Production costs (excluding production taxes) | $ | 16.75 | $ | 18.70 | $ | 14.79 | |||||
| Oil and gas depletion | $ | 26.13 | $ | 23.84 | $ | 18.72 | |||||
Net Wells Drilled(f): | |||||||||||
| Developmental wells | 50.1 | 92.3 | 111.8 | ||||||||
| Exploratory wells | 3.7 | 4.3 | 3.6 | ||||||||
_______
| (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 2013 includes $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 2013 excludes production of 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) | In April 2013, we sold 95% of our interest in certain properties in Andrews County, Texas. The following is a recap of the average daily production related to the sold interest for periods prior to April 1, 2013. |
| Year Ended December 31, | |||||
| 2013 | 2012 | ||||
| Average Daily Production: | |||||
| 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
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 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.
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
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 2013, we charged to expense $9.8 million of exploration costs, as compared to $15.8 million in 2012.
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 and idle rig charges 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.
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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.
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.
2012 Compared to 2011
The following discussion compares our results for the year ended December 31, 2012 to the year ended December 31, 2011. Unless otherwise indicated, references to 2012 and 2011 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales, excluding amortized deferred revenues, decreased $10.4 million, or 3% in 2012, from 2011. Price variances accounted for $25.6 million of the decrease and production variances accounted for a $15.2 million increase. Oil and gas sales in 2012 also includes $8.3 million of amortized deferred revenue attributable to the VPP granted effective March 1, 2012. Combined oil and gas production in 2012 (on a BOE basis) increased 3% compared to 2011. Our production mix continued to move favorably from 74% oil and NGL in 2011 to 76% in 2012. Oil production increased 3% in 2012 from 2011 while gas production decreased 6% in 2012 from 2011. Most of the decrease in gas production from 2011 levels was attributed to normal production declines from existing wells. In 2012, our realized oil price was 2% lower than 2011, and our realized gas price was 32% lower. 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, increased 24% to $125 million in 2012 as compared to $101.1 million in 2011. The increase in production costs was due to a combination of an increase in the number of producing wells, higher costs of field services, including salt water disposal costs, and higher property taxes on Texas properties resulting from rising appraisal values.
Oil and gas depletion expense increased $31.8 million from 2011 to 2012 due to a $28.7 million increase related to rate variances and a $3.1 million increase due to production variances. Most of the increase in the depletion rate related to downward revisions in proved reserves in our Andrews County Wolfberry play. On a BOE basis, depletion expense increased 27% to $23.84
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per BOE in 2012 from $18.72 per BOE in 2011. 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 $5.9 million during 2012 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. During 2011, we recorded a $10.4 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
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 2012, we charged to expense $15.8 million of exploration costs, as compared to $26.2 million in 2011.
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 services costs related to external customers were $17.4 million in 2012 compared to $5.1 million in 2011.
General and Administrative
G&A expenses decreased $11.1 million from $41.6 million in 2011 to $30.5 million in 2012. Compensation expense related to non-equity award plans decreased $12.3 million from 2011 to 2012 due to a decrease in estimated future compensation expense from these plans resulting primarily from lower commodity prices. This decrease was offset in part by $2 million of non-recurring donations to charitable and 527 organizations in 2012.
Interest expense
Interest expense increased 17% from $32.9 million in 2011 to $38.7 million in 2012. Interest expense associated with our revolving credit facility increased by $6.3 million due primarily to an increase in borrowings, which increased from an average daily principal balance of $113.4 million in 2011 compared to $349.1 million in 2012.
Loss on early extinguishment of long-term debt
In 2011, we redeemed $225 million in aggregate principal amount of 7¾% Senior Notes due 2013 in a tender offer and recorded a $5.5 million loss on early extinguishment of long-term debt consisting of a $2.8 million premium and a $2.7 million write-off of debt issuance costs.
Gain/loss on derivatives
We did not designate any derivative contracts in 2012 or 2011 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 2012, we reported a $14.4 million gain on derivatives (net of a $3.4 million loss on settled contracts). In 2011, we reported a $47 million gain on derivatives (net of a $42.5 million gain on settled contracts). Cash settlements in 2011 included $50 million from the early termination of contracts covering oil production for 2012 and 2013. 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 $0.5 million on sales of assets and impairment of inventory in 2012 compared to a net gain of $14.1 million in 2011. The 2011 gain related primarily to the sale of our two 2,000 horsepower drilling rigs and related equipment for a $13.2 million gain.
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Income tax expense
Our estimated effective income tax rate in 2012 of 38.5% 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 led by JPMorgan Chase Bank, N.A. to secure our revolving credit facility. The banks establish a borrowing base, in part, by making an estimate of the collateral value of our oil and gas properties. We borrow funds on our revolving credit facility as needed to supplement our operating cash flow as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our exploration program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. However, we may mitigate the effects of product prices on cash flow through the use of commodity derivatives.
At December 31, 2013, we had $40 million of borrowings outstanding under our revolving credit facility, leaving $369.9 million available on the facility after allowing for outstanding letters of credit totaling $5.1 million as compared to $121 million of availability on the facility at December 31, 2012. The significant improvement in liquidity resulted from a combination of strategic steps we took during 2013 to lower capital spending, sell certain producing properties and issue additional 2019 Senior Notes. We believe these actions were effective in achieving a more sustainable balance between our future capital commitments and our expected financial resources.
Capital expenditures
The following table summarizes, by area, our planned expenditures for exploration and development activities during 2014, as compared to our actual expenditures in 2013.
Actual Expenditures Year Ended December 31, 2013 | Planned Expenditures Year Ending December 31, 2014 | 2014 Percentage of Total | ||||||||
| (In thousands) | ||||||||||
| Drilling and Completion | ||||||||||
| Permian Basin Area: | ||||||||||
| Delaware Basin | $ | 109,600 | $ | 165,200 | 44 | % | ||||
| Other | 39,800 | 11,300 | 3 | % | ||||||
| Austin Chalk/Eagle Ford Shale | 64,200 | 155,500 | 41 | % | ||||||
| Other | 9,300 | 3,800 | 1 | % | ||||||
| 222,900 | 335,800 | 89 | % | |||||||
| Leasing and seismic | 52,100 | 40,400 | 11 | % | ||||||
| Exploration and development | $ | 275,000 | $ | 376,200 | 100 | % | ||||
Our expenditures for exploration and development activities for the year ended December 31, 2013 totaled $275 million. We financed these expenditures in 2013 with cash flows from operating activities and $54 million of advances under our revolving credit facility. We currently plan to spend approximately $376.2 million on exploration and development activities during 2014. Our actual expenditures during 2014 may vary significantly from these estimates since our plans for exploration and development activities change during the year. Factors, such as drilling results, changes in operating margins and the availability of capital resources and other factors, could increase or decrease our actual expenditures during 2014.
Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flows, combined with funds available to us on our revolving credit facility, will be sufficient to finance our planned exploration and development activities through 2014. Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and the borrowing base under our revolving credit facility may be less than expected, cash flows may be
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less than expected, or capital expenditures may be more than expected. In the event we lack adequate liquidity to finance our expenditures through 2014, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets.
Cash flow provided by operating activities
Substantially all of our cash 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, 2013 increased $31.4 million, or 16.6%, as compared to the corresponding period in 2012 due primarily to higher commodity prices and a 13% reduction in production 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.
Senior Notes
In March 2011, we issued $300 million of aggregate principal amount of the 2019 Senior Notes. The 2019 Senior Notes were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year, beginning October 1, 2011. In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million. In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes. The notes were sold at par to yield 7.75% to maturity. These 2019 Senior Notes and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.
The Indenture contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture. These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at December 31, 2013 and December 31, 2012.
Revolving credit facility
We have a revolving credit facility with a syndicate of banks that provides for a revolving line of credit of up to $415 million, limited to the amount of a borrowing base as determined by the banks. We have historically relied on our revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs. As long as we have sufficient availability under our revolving credit facility to meet our obligations as they become due, we believe that we will have sufficient liquidity and will be able to fund any short-term working capital deficit.
The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under our revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment to eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest. In connection with the sale of our Andrews County Wolfberry assets in April 2013 as discussed in Note 5 in the accompanying consolidated financial statements, we entered into an amendment to our revolving credit facility, pursuant to which the banks decreased the aggregate commitment and borrowing base under our revolving credit facility from $585 million to $470 million. On October 1, 2013, we used the net proceeds from our issuance of $250 million aggregate principal amount of the 2019 Senior Notes to repay outstanding indebtedness under our revolving credit facility. In connection with the issuance of the additional 2019 Senior Notes, the borrowing base was reduced to $407.5 million. In November 2013, the banks increased the aggregate commitment and borrowing base from $407.5 million to $415 million.
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Our revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in our revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base. The obligations under our revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries except for CWEI Andrews Properties, GP, LLC.
At our election, annual interest rates under our revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.75% and 2.75% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.75% and 1.75% per year. We also pay a commitment fee on the unused portion of our revolving credit facility at a rate between 0.375% and 0.50%. The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under our revolving credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2013 was 2.6%.
Our revolving credit facility contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities (the “Consolidated Current Ratio”) of at least 1 to 1. In computing the Consolidated Current Ratio at any balance sheet date, we must (1) include the amount of funds available under this facility as a current asset, (2) exclude current assets and liabilities related to the fair value of derivatives (non-cash assets or liabilities), and (3) exclude current assets and liabilities attributable to vendor financing transactions, if any.
Working capital computed for loan compliance purposes differs from our working capital computed in accordance with GAAP. Since compliance with financial covenants is a material requirement under the revolving credit facility, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under our revolving 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 decreased to $1.9 million at December 31, 2013 from working capital of $3.6 million at December 31, 2012. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $369.6 million at December 31, 2013, as compared to $117 million at December 31, 2012. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2013 and December 31, 2012.
| December 31, | |||||||
| 2013 | 2012 | ||||||
| (In thousands) | |||||||
| Working capital per GAAP | $ | 1,916 | $ | 3,556 | |||
| Add funds available under our revolving credit facility | 369,947 | 120,950 | |||||
| Exclude fair value of derivatives classified as current assets or current liabilities | (2,310 | ) | (7,495 | ) | |||
| Working capital per loan covenant | $ | 369,553 | $ | 117,011 | |||
Our revolving credit facility provides that the ratio of our consolidated funded indebtedness to consolidated EBITDAX (the “Leverage Ratio”) (determined as of the last day of each fiscal quarter for the then most-recently ended four fiscal quarters) not be greater than 4 to 1. In connection with the issuance of the additional 2019 Senior Notes effective October 1, 2013, the Leverage Ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014.
We were in compliance with all financial and non-financial covenants at December 31, 2013 and December 31, 2012. However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend our revolving credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.
The lending group under our revolving credit facility includes the following institutions: JPMorgan Chase Bank, N.A., Union Bank, N.A., Wells Fargo Bank, N.A., The Royal Bank of Scotland plc, Compass Bank, Frost Bank, Natixis, KeyBank, N.A., UBS Loan Finance, LLC, Fifth Third Bank, US Bank, N.A. and Whitney Bank.
From time to time, we engage in other transactions with lenders under our revolving credit facility. Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of December 31, 2013, JPMorgan Chase Bank, N.A. and Union Bank, N.A. were the counterparties to our commodity derivative agreements. Our
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obligations under existing derivative agreements with our lenders are secured by the security documents executed by the parties under our revolving credit facility.
During 2013, we decreased indebtedness outstanding under our revolving credit facility by $420 million. At December 31, 2013, we had $40 million of borrowings outstanding under our revolving credit facility, leaving $369.9 million available on the facility after allowing for outstanding letters of credit totaling $5.1 million. Our revolving credit facility matures in November 2015.
Alternative capital resources
We believe we currently have adequate liquidity to enable us to fund our expected capital expenditures for 2014 through a combination of cash flow from operations, borrowings on our revolving credit facility and proceeds from the pending sale of certain assets in our Giddings area as discussed in “Item 1 - Business - Company Profile - Recent Developments.”
We may also use other capital resources, including (1) entering into joint venture participation agreements with other industry or financial partners in our core development areas, (2) monetizing other non-core assets and (3) issuing additional debt or equity securities in private or public offerings, in order to finance a portion of our capital spending in fiscal 2014 and subsequent periods. While we believe we would be able to obtain funds through one or more of these alternative capital resources, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.
Contractual obligations and contingent commitments
The following table summarizes our contractual obligations as of December 31, 2013 by payment due date.
| Payments Due by Period | |||||||||||||||||||
| Total | 2014 | 2015 to 2016 | 2017 to 2018 | Thereafter | |||||||||||||||
| (In thousands) | |||||||||||||||||||
| Contractual obligations: | |||||||||||||||||||
7.75% Senior Notes, due 2019, net of discount of $362(a) | $ | 599,638 | $ | — | $ | — | $ | — | $ | 599,638 | |||||||||
Revolving credit facility, due November 2015(a) | 40,000 | — | 40,000 | — | — | ||||||||||||||
| Volumetric Production Payment Obligation | 32,094 | 7,708 | 12,130 | 8,684 | 3,572 | ||||||||||||||
Lease obligations(b) | 13,672 | 4,819 | 8,515 | 338 | — | ||||||||||||||
| Total contractual obligations | $ | 685,404 | $ | 12,527 | $ | 60,645 | $ | 9,022 | $ | 603,210 | |||||||||
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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 $1.1 million on our revolving credit facility (based on the balances and interest rates at December 31, 2013). |
| (b) | Amount includes lease payments for two drilling rigs. |
Off-balance sheet arrangements
Currently, we do not have any material off-balance sheet arrangements.
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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 $74.57 per BOE in 2011, to $72.00 per BOE in 2012 and $76.11 per BOE in 2013. Our oil and gas DD&A per BOE was $18.72 per BOE in 2011, $23.84 per BOE in 2012 and $26.13 per BOE in 2013. An upward trend in DD&A per BOE indicates that our cost to find and/or acquire reserves is increasing at a faster rate than we are adding reserves. Although we replaced 526% of our production in 2013 and commodity prices were higher, our costs to find those reserves were significantly higher than our historical combined rate. Our production costs per BOE have fluctuated from $18.60 per BOE in 2011, to $22.32 per BOE in 2012, to $20.63 per BOE in 2013. The decrease in operating costs per BOE in 2013 from 2012 was 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.
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 2013 decreased 6% to 5.3 MMBOE compared to 5.6 MMBOE in 2012, and we replaced 526% of our 2013 oil and gas production through extensions and discoveries. While these 2013 reserve additions will contribute favorably to our production in 2014, 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 increase capital spending during 2014 to $376.2 million on exploration and development activities compared to $275 million in 2013. An increase in spending levels will allow us to grow our production and reserves. 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.
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).
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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 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 | |||||||||||||||||||
| (MMBbls) | (MMBbls) | (Bcf) | ($/Bbl) | ($/Bbl) | ($/Mcf) | Net Cash Flows | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| As of December 31: | ||||||||||||||||||||||||
| 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 | |||||||||||||
| 2011 | 44.9 | 4.6 | 88.9 | $ | 91.35 | $ | 51.19 | $ | 5.31 | $ | 938.5 | |||||||||||||
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 2013, we had a downward revision of our
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estimated asset retirement obligations of $0.6 million based on a review of current plugging and abandonment costs. Revisions 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 December 2011, the FASB issued ASU No. 2011-11, “Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”). The amendments in ASU 2013-01 clarify that the disclosure requirements of ASU 2011-11 are limited to derivatives, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and lending transactions that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement. ASU 2013-01 is effective retrospectively for annual periods beginning on or after January 1, 2013. The adoption of these new accounting rules did not have a material effect on our financial condition, results of operations or cash flows.
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 our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas commodity prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2013 reserve estimates, we project that a $1 decline in the price per Bbl of oil and a $0.50 decline in the price per Mcf of gas from year end 2013 would reduce our gross revenues for the year ending December 31, 2014 by $7.1 million.
From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production. We do not enter into commodity derivatives for trading purposes. When using swaps to hedge our oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. When purchasing floors, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.
The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements. We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge. If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received. If we
58
terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.
The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2013. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Swaps:
| Oil | |||||||
| Bbls | Price | ||||||
| Production Period: | |||||||
1st Quarter 2014 | 606,000 | $ | 96.74 | ||||
2nd Quarter 2014 | 560,600 | $ | 96.81 | ||||
3rd Quarter 2014 | 530,200 | $ | 96.87 | ||||
4th Quarter 2014 | 503,200 | $ | 96.92 | ||||
| 2,200,000 | |||||||
We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $0.50 per MMBtu change in the price of gas would change the fair value of our outstanding commodity derivatives at December 31, 2013 by approximately $2.2 million.
Interest Rates
We are exposed to interest rate risk on our long-term debt with a variable interest rate. At December 31, 2013, our fixed rate debt had a carrying value of $599.6 million and an approximate fair value of $616.5 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 $26.3 million. Based on our outstanding variable rate indebtedness at December 31, 2013 of $40 million, a change in interest rates of 100-basis points would affect annual interest payments by $0.4 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 |
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| • | 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. |
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, 2013 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, 2013. 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 (1992). Based on this assessment, management has concluded that, as of December 31, 2013, 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, 2013, 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, 2013, based on criteria established in the Internal Control - Integrated Framework (1992) 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.
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.
In our opinion, Clayton Williams Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the Internal Control - Integrated Framework (1992) 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, 2013 and 2012, 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, 2013, and our report dated March 10, 2014 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
March 10, 2014
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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 2014 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2014.
Item 11 - Executive Compensation
Information required by this Item 11 is incorporated by reference to our definitive proxy statement relating to the 2014 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2014.
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 2014 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2014.
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 2014 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2014.
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 2014 Annual Meeting of Stockholders, which will be filed with the SEC no later than April 30, 2014.
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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†† | |
| **4.3 | Registration Rights Agreement dated as of October 1, 2013, by and among Clayton Williams Energy, Inc., the Guarantors named therein and the Initial Purchasers named therein, filed as Exhibit 4.2 to the Company's Current Report on Form 8-K filed with the Commission on October 2, 2013†† | |
| **10.1 | Second Amended and Restated Credit Agreement dated as of November 29, 2010, among Clayton Williams Energy, Inc., as Borrower, certain Subsidiaries of Clayton Williams Energy, Inc., as Guarantors, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 2, 2010†† | |
| **10.2 | First Amendment to Second Amended and Restated Credit Agreement dated March 3, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 7, 2011†† | |
| **10.3 | Second Amendment to Second Amended and Restated Credit Agreement dated May 17, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 10-Q filed with the Commission on August 5, 2011†† | |
| **10.4 | Third Amendment to Second Amended and Restated Credit Agreement dated as of November 17, 2011, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on November 21, 2011†† | |
| **10.5 | Fourth Amendment to Second Amended and Restated Credit Agreement dated April 23, 2012, filed as Exhibit 10.1 to the Company’s Current Report on Form 10-Q filed with the Commission on August 7, 2012†† | |
| **10.6 | Fifth Amendment to Second Amended and Restated Credit Agreement dated August 30, 2012, filed as Exhibit 10.1 to the Company’s Current Report on Form 10-Q filed with the Commission on November 6, 2012†† | |
| **10.7 | Sixth Amendment to Second Amended and Restated Credit Agreement dated November 16, 2012, filed as Exhibit 10.7 to the Company's Form 10-K for the period ended December 31, 2012†† | |
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Exhibit Number | Description of Exhibit | |
| **10.8 | Seventh Amendment to Second Amended and Restated Credit Agreement and Limited Consent dated April 5, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on April 30, 2013†† | |
| **10.9 | Eighth Amendment to Second Amended and Restated Credit Agreement Limited Consent dated September 17, 2013, filed as Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Commission on September 23, 2013†† | |
| **10.10† | Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316 | |
| **10.11† | 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†† | |
| **10.12† | 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†† | |
| **10.13† | 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 | |
| **10.14† | 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†† | |
| **10.15† | Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68320 | |
| **10.16† | 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†† | |
| **10.17† | 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†† | |
| **10.18† | Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-92834 | |
| **10.19† | 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†† | |
| **10.20 | 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 | |
| **10.21 | 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†† | |
| **10.22 | 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 | |
| **10.23 | 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†† | |
| **10.24 | 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†† | |
| **10.25 | 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†† | |
| **10.26 | 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†† | |
| **10.27† | Form of Director Indemnification Agreement, filed as Exhibit 10.71 to the Company’s Form 10-K for the period ended December 31, 2008†† | |
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Exhibit Number | Description of Exhibit | |
| **10.28† | 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†† | |
| **10.29† | 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†† | |
| **10.30† | 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†† | |
| **10.31† | 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†† | |
| **10.32† | 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†† | |
| **10.33† | 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†† | |
| **10.34† | 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†† | |
| *10.35† | 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†† | |
| *10.36† | 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†† | |
| *10.37† | 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†† | |
| **10.38† | 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†† | |
| **10.39† | 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†† | |
| **10.40† | 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†† | |
| **10.41† | 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†† | |
| **10.42† | 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†† | |
| **10.43† | 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†† | |
| **10.44† | 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†† | |
| **10.45† | 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†† | |
| **10.46† | 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†† | |
| **10.47† | 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†† | |
| **10.48† | 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†† | |
65
Exhibit Number | Description of Exhibit | |
| **10.49† | 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†† | |
| **10.50† | 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†† | |
| **10.51† | 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†† | |
| **10.52† | 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†† | |
| **10.53† | 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†† | |
| **10.54† | 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†† | |
| **10.55† | 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†† | |
| **10.56† | 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†† | |
| **10.57† | 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†† | |
| **10.58† | 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†† | |
| **10.59† | 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†† | |
| **10.60† | 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†† | |
| **10.61† | 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†† | |
| **10.62† | 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†† | |
| **10.63† | 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 | |
66
Exhibit Number | Description of Exhibit | |
| *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. | |
67
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.
68
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
69
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.
70
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: | March 10, 2014 | |
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, | March 10, 2014 | ||
| Clayton W. Williams, Jr. | President, Chief Executive Officer and Director | |||
| /s/ MEL G. RIGGS | Executive Vice President, | March 10, 2014 | ||
| Mel G. Riggs | Chief Operating Officer and Director | |||
| /s/ MICHAEL L. POLLARD | Senior Vice President — | March 10, 2014 | ||
| Michael L. Pollard | Finance, Chief Financial Officer and Treasurer | |||
| /s/ ROBERT L. THOMAS | Vice President — Accounting and Principal Accounting Officer | March 10, 2014 | ||
| Robert L. Thomas | ||||
| * | Director | March 10, 2014 | ||
| Ted Gray, Jr. | ||||
| * | Director | March 10, 2014 | ||
| Davis L. Ford | ||||
| * | Director | March 10, 2014 | ||
| Robert L. Parker | ||||
| * | Director | March 10, 2014 | ||
| Jordan R. Smith | ||||
| * By: /s/ MEL G. RIGGS | ||||
| * Mel G. Riggs | ||||
| Attorney-in-Fact | ||||
71
CLAYTON WILLIAMS ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTAL INFORMATION
| Page | |
| Supplemental Information | |
F-1
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, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, 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, 2013, based on criteria established in the Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2014, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Dallas, Texas
March 10, 2014
F-2
CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands) ASSETS | |||||||
| December 31, | |||||||
| 2013 | 2012 | ||||||
| CURRENT ASSETS | |||||||
| Cash and cash equivalents | $ | 26,623 | $ | 10,726 | |||
| Accounts receivable: | |||||||
| Oil and gas sales | 39,268 | 32,371 | |||||
| Joint interest and other, net of allowance for doubtful accounts of $1,184 at December 31, 2013 and $1,193 at December 31, 2012 | 17,121 | 16,767 | |||||
| Affiliates | 264 | 353 | |||||
| Inventory | 39,183 | 41,703 | |||||
| Deferred income taxes | 7,581 | 8,560 | |||||
| Fair value of derivatives | 2,518 | 7,495 | |||||
| Prepaids and other | 5,753 | 6,495 | |||||
| 138,311 | 124,470 | ||||||
| PROPERTY AND EQUIPMENT | |||||||
| Oil and gas properties, successful efforts method | 2,403,277 | 2,570,803 | |||||
| Pipelines and other midstream facilities | 54,800 | 49,839 | |||||
| Contract drilling equipment | 96,270 | 91,163 | |||||
| Other | 20,620 | 20,245 | |||||
| 2,574,967 | 2,732,050 | ||||||
| Less accumulated depreciation, depletion and amortization | (1,375,860 | ) | (1,311,692 | ) | |||
| Property and equipment, net | 1,199,107 | 1,420,358 | |||||
| OTHER ASSETS | |||||||
| Debt issue costs, net | 12,785 | 10,259 | |||||
| Fair value of derivatives | — | 4,236 | |||||
| Investments and other | 16,534 | 15,261 | |||||
| 29,319 | 29,756 | ||||||
| $ | 1,366,737 | $ | 1,574,584 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-3
CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (Dollars in thousands) LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
| December 31, | |||||||
| 2013 | 2012 | ||||||
| CURRENT LIABILITIES | |||||||
| Accounts payable: | |||||||
| Trade | $ | 75,872 | $ | 73,026 | |||
| Oil and gas sales | 37,834 | 32,146 | |||||
| Affiliates | 874 | 164 | |||||
| Fair value of derivatives | 208 | — | |||||
| Accrued liabilities and other | 21,607 | 15,578 | |||||
| 136,395 | 120,914 | ||||||
| NON-CURRENT LIABILITIES | |||||||
| Long-term debt | 639,638 | 809,585 | |||||
| Deferred income taxes | 140,809 | 155,830 | |||||
| Asset retirement obligations | 49,981 | 51,477 | |||||
| Deferred revenue from volumetric production payment | 29,770 | 37,184 | |||||
| Accrued compensation under non-equity award plans | 15,469 | 20,058 | |||||
| Other | 892 | 920 | |||||
| 876,559 | 1,075,054 | ||||||
| COMMITMENTS AND CONTINGENCIES (see Note 15) | |||||||
| STOCKHOLDERS’ EQUITY | |||||||
| Preferred stock, par value $.10 per share, authorized — 3,000,000 shares; none issued | — | — | |||||
| Common stock, par value $.10 per share, authorized — 30,000,000 shares; issued and outstanding — 12,165,536 shares at December 31, 2013 and 12,164,536 shares at December 31, 2012 | 1,216 | 1,216 | |||||
| Additional paid-in capital | 152,556 | 152,527 | |||||
| Retained earnings | 200,011 | 224,873 | |||||
| 353,783 | 378,616 | ||||||
| $ | 1,366,737 | $ | 1,574,584 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (In thousands, except per share) | |||||||||||
| Year Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| REVENUES | |||||||||||
| Oil and gas sales | $ | 399,950 | $ | 403,143 | $ | 405,216 | |||||
| Midstream services | 4,965 | 1,974 | 1,408 | ||||||||
| Drilling rig services | 17,812 | 15,858 | 4,060 | ||||||||
| Other operating revenues | 6,488 | 2,077 | 15,744 | ||||||||
| Total revenues | 429,215 | 423,052 | 426,428 | ||||||||
| COSTS AND EXPENSES | |||||||||||
| Production | 108,405 | 124,950 | 101,099 | ||||||||
| Exploration: | |||||||||||
| Abandonments and impairments | 5,887 | 4,222 | 20,840 | ||||||||
| Seismic and other | 3,906 | 11,591 | 5,363 | ||||||||
| Midstream services | 1,816 | 1,228 | 1,039 | ||||||||
| Drilling rig services | 16,290 | 17,423 | 5,064 | ||||||||
| Depreciation, depletion and amortization | 150,902 | 142,687 | 104,880 | ||||||||
| Impairment of property and equipment | 89,811 | 5,944 | 10,355 | ||||||||
| Accretion of asset retirement obligations | 4,203 | 3,696 | 2,757 | ||||||||
| General and administrative | 33,279 | 30,485 | 41,560 | ||||||||
| Other operating expenses | 2,101 | 1,033 | 1,666 | ||||||||
| Total costs and expenses | 416,600 | 343,259 | 294,623 | ||||||||
| Operating income | 12,615 | 79,793 | 131,805 | ||||||||
| OTHER INCOME (EXPENSE) | |||||||||||
| Interest expense | (43,079 | ) | (38,664 | ) | (32,919 | ) | |||||
| Loss on early extinguishment of long-term debt | — | — | (5,501 | ) | |||||||
| Gain (loss) on derivatives | (8,731 | ) | 14,448 | 47,027 | |||||||
| Other | 1,905 | 1,534 | 5,553 | ||||||||
| Total other income (expense) | (49,905 | ) | (22,682 | ) | 14,160 | ||||||
| Income (loss) before income taxes | (37,290 | ) | 57,111 | 145,965 | |||||||
| Income tax (expense) benefit | 12,428 | (22,008 | ) | (52,142 | ) | ||||||
| NET INCOME (LOSS) | $ | (24,862 | ) | $ | 35,103 | $ | 93,823 | ||||
| Net income (loss) per common share: | |||||||||||
| Basic | $ | (2.04 | ) | $ | 2.89 | $ | 7.72 | ||||
| Diluted | $ | (2.04 | ) | $ | 2.89 | $ | 7.71 | ||||
| Weighted average common shares outstanding: | |||||||||||
| Basic | 12,165 | 12,164 | 12,161 | ||||||||
| Diluted | 12,165 | 12,164 | 12,162 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
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, 2010 | 12,155 | $ | 1,215 | $ | 152,290 | $ | 95,947 | $ | 249,452 | |||||||||
| Net income | — | — | — | 93,823 | 93,823 | |||||||||||||
| Issuance of stock through compensation plans, including income tax benefits | 9 | 1 | 225 | — | 226 | |||||||||||||
| 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 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) | |||||||||||
| Year Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||
| Net income (loss) | $ | (24,862 | ) | $ | 35,103 | $ | 93,823 | ||||
| Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||||||||||
| Depreciation, depletion and amortization | 150,902 | 142,687 | 104,880 | ||||||||
| Impairment of property and equipment | 89,811 | 5,944 | 10,355 | ||||||||
| Abandonments and impairments | 5,887 | 4,222 | 20,840 | ||||||||
| Gain on sales of assets and impairment of inventory, net | (3,024 | ) | (463 | ) | (14,078 | ) | |||||
| Deferred income tax expense (benefit) | (14,042 | ) | 22,008 | 52,550 | |||||||
| Non-cash employee compensation | (3,493 | ) | (404 | ) | 12,866 | ||||||
| (Gain) loss on derivatives | 8,731 | (14,448 | ) | (47,027 | ) | ||||||
| Cash settlements of derivatives | 690 | (3,410 | ) | 42,521 | |||||||
| Accretion of asset retirement obligations | 4,203 | 3,696 | 2,757 | ||||||||
| Amortization of debt issue costs and original issue discount | 3,266 | 2,554 | 2,342 | ||||||||
| Loss on early extinguishment of long-term debt | — | — | 5,501 | ||||||||
| Amortization of deferred revenue from volumetric production payment | (8,746 | ) | (8,295 | ) | — | ||||||
| Changes in operating working capital: | |||||||||||
| Accounts receivable | (7,163 | ) | 7,299 | (10,739 | ) | ||||||
| Accounts payable | 12,740 | (9,386 | ) | 7,551 | |||||||
| Other | 5,676 | 2,115 | (4,095 | ) | |||||||
| Net cash provided by operating activities | 220,576 | 189,222 | 280,047 | ||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||
| Additions to property and equipment | (288,133 | ) | (526,521 | ) | (413,013 | ) | |||||
| Proceeds from volumetric production payment | 1,332 | 45,479 | — | ||||||||
| Proceeds from sales of assets | 259,799 | 3,778 | 13,902 | ||||||||
| (Increase) decrease in equipment inventory | (726 | ) | 1,313 | (5,305 | ) | ||||||
| Other | (1,315 | ) | (82 | ) | (497 | ) | |||||
| Net cash used in investing activities | (29,043 | ) | (476,033 | ) | (404,913 | ) | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||
| Proceeds from long-term debt | 268,335 | 280,000 | 547,710 | ||||||||
| Repayments of long-term debt | (444,000 | ) | — | (411,500 | ) | ||||||
| Premium on early extinguishment of long-term debt | — | — | (2,765 | ) | |||||||
| Proceeds from exercise of stock options | 29 | 12 | 226 | ||||||||
| Net cash provided by (used in) financing activities | (175,636 | ) | 280,012 | 133,671 | |||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 15,897 | (6,799 | ) | 8,805 | |||||||
| CASH AND CASH EQUIVALENTS | |||||||||||
| Beginning of period | 10,726 | 17,525 | 8,720 | ||||||||
| End of period | $ | 26,623 | $ | 10,726 | $ | 17,525 | |||||
| SUPPLEMENTAL DISCLOSURES | |||||||||||
| Cash paid for interest, net of amounts capitalized | $ | 35,219 | $ | 35,932 | $ | 23,923 | |||||
| Cash paid for income taxes | $ | — | $ | — | $ | — | |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-7
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 its core areas in Texas, Louisiana and New Mexico. Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to the “Company,” “we,” “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. Approximately 26% of CWEI’s outstanding Common Stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board, President and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.
Substantially all of our oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels and overall domestic and foreign economic conditions.
2. 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; |
| • | Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory; |
| • | Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells; and |
| • | Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements. |
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.
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
F-8
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
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
F-9
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2013, 2012 and 2011, we capitalized interest totaling approximately $1.4 million, $1 million and $0.7 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 2012 and 2011 include changes in potential shares attributable to dilutive stock options.
Stock-Based Compensation
We measure and recognize compensation expense for all share-based payment awards, including employee stock options, based on estimated fair values. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods, if any.
We estimate the fair value of stock option awards on the date of grant using an option-pricing model. We use the Black-Scholes option-pricing model as our method of valuation for share-based awards granted on or after January 1, 2006. Our determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by our stock price, as well as assumptions regarding a number of subjective variables. These variables include, but are not limited to, our expected stock price volatility over the term of the awards, as well as actual and projected exercise and forfeiture activity.
F-10
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Fair Value Measurements
We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:
| Level 1 - | Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. |
| Level 2 - | Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. |
| Level 3 - | Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. |
Revenue Recognition and Gas Balancing
We utilize the sales method of accounting for oil, natural gas and 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, 2013, 2012 or 2011. 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 2013, 2012 and 2011.
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, 2013 and 2012 relate to amounts due from joint interest owners.
Recent Accounting Pronouncements
In December 2011, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2011-11, “Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“ASU 2013-01”). The amendments in ASU 2013-01 clarify that the disclosure requirements of ASU 2011-11 are limited to derivatives, including bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and lending transactions that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement. ASU 2013-01 is effective retrospectively for annual periods beginning on or after January 1, 2013. The adoption of these new accounting rules did not have a material effect on our financial condition, results of operations or cash flows.
F-11
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Long-Term Debt
Long-term debt consists of the following:
| December 31, 2013 | December 31, 2012 | ||||||
| (In thousands) | |||||||
| 7.75% Senior Notes due 2019, net of unamortized original issue discount of $362 at December 31, 2013 and $415 at December 31, 2012 | $ | 599,638 | $ | 349,585 | |||
| Revolving credit facility, due November 2015 | 40,000 | 460,000 | |||||
| $ | 639,638 | $ | 809,585 | ||||
Aggregate maturities of long-term debt at December 31, 2013 are as follows: 2015- $40 million; 2019 - $599.6 million, net of unamortized original issue discount of $362,000.
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, beginning October 1, 2011. In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million. In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. These 2019 Senior Notes and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the same indenture. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% beginning on April 1, 2015, 101.938% beginning on April 1, 2016, and 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.
The Indenture contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant provides that we may only incur indebtedness if the ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) does not exceed certain ratios specified in the Indenture. These covenants are subject to a number of important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at December 31, 2013.
Revolving Credit Facility
We have a revolving credit facility with a syndicate of banks that provides for a revolving line of credit of up to $415 million, limited to the amount of a borrowing base as determined by the banks. The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under our revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency (or by a combination of such additional security and such prepayment eliminate such deficiency), or (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest.
In April 2013, the borrowing base was reduced from $585 million to $470 million due to the sale of a substantial portion of our Andrews County assets discussed in Note 5 and was further reduced to $407.5 million in October 2013 in connection with the issuance of $250 million of the 2019 Senior Notes. In November 2013, the borrowing base was increased to its current level of $415 million. At December 31, 2013, after allowing for outstanding letters of credit totaling $5.1 million, we had $369.9 million available under our revolving credit facility.
Our revolving credit facility is collateralized primarily by 80% or more of the adjusted engineered value (as defined in our revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base. The obligations under our revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries except for CWEI Andrews Properties, GP, LLC (see Note 19).
F-12
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
At our election, annual interest rates under our revolving credit facility are determined by reference to (1) LIBOR plus an applicable margin between 1.75% and 2.75% per year or (2) if an alternate base rate loan, the greatest of (A) the prime rate, (B) the federal funds rate plus 0.50%, or (C) one-month LIBOR plus 1% plus, if any of (A), (B) or (C), an applicable margin between 0.75% and 1.75% per year. We also pay a commitment fee on the unused portion of our revolving credit facility at a rate between 0.375% and 0.50%. The applicable margins are based on actual borrowings outstanding as a percentage of the borrowing base. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under our revolving credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2013 was 2.6%.
Our revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1. Another financial covenant prohibits the ratio of our consolidated funded indebtedness to consolidated EBITDAX (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) from being greater than 4 to 1. In connection with the issuance of the 2019 Senior Notes effective October 1, 2013, the consolidated funded indebtedness ratio was temporarily increased to 4.5 to 1 through the fourth quarter of 2014. The computations of consolidated current assets, current liabilities, EBITDAX and funded indebtedness are defined in our revolving credit facility. We were in compliance with all financial and non-financial covenants at December 31, 2013 and December 31, 2012.
| 4. | Acquisition of Southwest Royalties, Inc. Limited Partnerships |
On March 14, 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 (the “SWR Partnerships”) into SWR, with SWR continuing as the surviving entity in the mergers. At the effective time of the mergers, all of the units representing limited partnership interests in the SWR Partnerships, other than those held by SWR, were converted into the right to receive cash. SWR did not receive any cash payment for its partnership interests in the SWR Partnerships. However, as a result of the mergers, SWR acquired 100% of the assets and liabilities of the SWR Partnerships. SWR paid aggregate merger consideration of $38.6 million in the mergers. Pro forma financial information is not presented as it would not be materially different from the information presented in the consolidated statements of operations and comprehensive income (loss) of the Company.
To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million. Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725,000 BOE of estimated future oil and gas production from certain properties derived from the mergers. The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and are to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties. Once the scheduled volumes have been delivered to the third party, the term overriding royalty interest will terminate. SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks related to the adequacy of the associated reserves to fully recoup the scheduled volumes and also assumed all risks associated with product prices. As a result, the VPP has been accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes are produced (see Note 7).
The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the date of acquisition (in thousands):
| Cash and cash equivalents | $ | 4,118 | |
| Oil and gas properties | 41,098 | ||
| Other non-current assets | 210 | ||
| Total assets acquired | 45,426 | ||
| Asset retirement obligations | (6,864 | ) | |
| Total liabilities assumed | (6,864 | ) | |
| Net assets acquired | $ | 38,562 | |
F-13
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
5. | Sales of Assets |
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”). The Assets accounted for approximately 20% of our total proved reserves at December 31, 2012. 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. As of December 30, 2013, all title requirements were satisfied and we received the remaining escrow balance of $25.9 million. 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 for $6.8 million. In December 2013, we sold our remaining interest in the same acreage for $34.5 million, subject to customary closing adjustments. The proceeds from these sales were used to repay a portion of our outstanding balance on our revolving credit facility.
6. 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. 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, 2013 and December 31, 2012:
| 2013 | 2012 | ||||||
| (In thousands) | |||||||
| Beginning of year | $ | 51,477 | $ | 40,794 | |||
| Additional ARO from new properties | 795 | 7,868 | |||||
| Sales or abandonments of properties | (5,892 | ) | (2,184 | ) | |||
| Accretion expense | 4,203 | 3,696 | |||||
| Revisions of previous estimates | (602 | ) | 1,303 | ||||
| End of year | $ | 49,981 | $ | 51,477 | |||
7. Deferred Revenue from Volumetric Production Payment
The net proceeds from the VPP discussed in Note 4 are recorded as a non-current liability in the consolidated balance sheets. Deferred revenue from 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).
F-14
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table reflects the changes in deferred revenue during the years ended December 31, 2013 and December 31, 2012:
| 2013 | 2012 | ||||||
| (In thousands) | |||||||
| Beginning of period | $ | 37,184 | $ | — | |||
| Deferred revenue from VPP | 1,332 | 45,479 | |||||
| Amortization of deferred revenue from VPP | (8,746 | ) | (8,295 | ) | |||
| End of period | $ | 29,770 | $ | 37,184 | |||
Under the terms of the VPP, SWR conveyed to a third party a term overriding royalty interest covering approximately 725,000 BOE of estimated future oil and gas production. As of December 31, 2013, we have a remaining obligation to deliver approximately 485,000 BOE.
8. 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, 2013 and 2012 are as follows:
| 2013 | 2012 | ||||||
| (In thousands) | |||||||
| Deferred tax assets: | |||||||
| Net operating loss carryforwards | $ | 65,814 | $ | 122,393 | |||
| Statutory depletion carryforwards | 8,658 | 8,159 | |||||
| Asset retirement obligations and other | 22,470 | 21,814 | |||||
| 96,942 | 152,366 | ||||||
| Deferred tax liabilities: | |||||||
| Fair value of derivatives | (598 | ) | (4,208 | ) | |||
| Property and equipment | (229,572 | ) | (295,428 | ) | |||
| (230,170 | ) | (299,636 | ) | ||||
| Net deferred tax liabilities | $ | (133,228 | ) | $ | (147,270 | ) | |
| Components of net deferred tax liabilities: | |||||||
| Current assets | $ | 7,581 | $ | 8,560 | |||
| Non-current liabilities | (140,809 | ) | (155,830 | ) | |||
| Net deferred tax liabilities | $ | (133,228 | ) | $ | (147,270 | ) | |
F-15
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2013, 2012 and 2011, effective income tax rates were different than the statutory federal income tax rates for the following reasons:
| 2013 | 2012 | 2011 | |||||||||
| (In thousands) | |||||||||||
| Income tax expense at statutory rate of 35% | $ | (13,052 | ) | $ | 19,989 | $ | 50,921 | ||||
| Tax depletion in excess of basis | (518 | ) | (581 | ) | (425 | ) | |||||
| Revision of previous tax estimates | 373 | 700 | 217 | ||||||||
| State income taxes, net of federal tax effect | 76 | 1,513 | 1,310 | ||||||||
| Other | 693 | 387 | 119 | ||||||||
| Income tax expense (benefit) | $ | (12,428 | ) | $ | 22,008 | $ | 52,142 | ||||
| Current | $ | 1,614 | $ | — | $ | (408 | ) | ||||
| Deferred | (14,042 | ) | 22,008 | 52,550 | |||||||
| Income tax expense (benefit) | $ | (12,428 | ) | $ | 22,008 | $ | 52,142 | ||||
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, 2013, our cumulative tax loss carryforwards were approximately $209.5 million, of which $21.8 million relates to excess tax benefits from exercise of stock options. The cumulative tax loss carryforwards are scheduled to expire if not utilized between 2024 and 2028.
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 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 2009 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, 2013 and 2012.
9. Derivatives
Commodity Derivatives
From time to time, we utilize commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract, generally New York Mercantile Exchange (“NYMEX”) futures prices, resulting in a net amount due to or from the counterparty. In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature.
F-16
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2013. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Swaps
| Oil | ||||||
| Bbls | Price | |||||
| Production Period: | ||||||
| 1st Quarter 2014 | 606,000 | $ | 96.74 | |||
| 2nd Quarter 2014 | 560,600 | $ | 96.81 | |||
| 3rd Quarter 2014 | 530,200 | $ | 96.87 | |||
| 4th Quarter 2014 | 503,200 | $ | 96.92 | |||
| 2,200,000 | ||||||
We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $0.50 per MMBtu change in the price of gas would change the fair value of our outstanding commodity derivatives at December 31, 2013 by approximately $2.2 million.
Accounting for Derivatives
We did not designate any of our currently open commodity derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in our consolidated statements of operations and comprehensive income (loss).
Effect of Derivative Instruments on the Consolidated Balance Sheets
| Fair Value of Derivative Instruments as of 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 | |||||||
| Fair Value of Derivative Instruments as of December 31, 2012 | |||||||||||
| 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 | $ | 7,495 | Current | $ | — | ||||||
| Non-current | 4,236 | Non-current | — | ||||||||
| Total | $ | 11,731 | $ | — | |||||||
F-17
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities
| 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 | |||
| December 31, 2012 | |||||||
| Assets | Liabilities | ||||||
| (In thousands) | |||||||
| Fair value of derivatives — gross presentation | $ | 17,851 | $ | 6,120 | |||
| Effects of netting arrangements | (6,120 | ) | (6,120 | ) | |||
| Fair value of derivatives — net presentation | $ | 11,731 | $ | — | |||
Our derivative contracts are with JPMorgan Chase Bank, N.A. and Union Bank, N.A. We have elected to net the outstanding positions with these counterparties between current and noncurrent assets or liabilities since we have the right to settle these positions on a net basis.
Effect of Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss)
| Amount of Gain or (Loss) Recognized in Earnings | ||||||||||||
| Year Ended December 31, 2013 | ||||||||||||
| Location of Gain or (Loss) Recognized in Earnings | Realized | Unrealized | Total | |||||||||
| (In thousands) | ||||||||||||
| Derivatives not designated as hedging instruments: | ||||||||||||
| Commodity derivatives: | ||||||||||||
| Other income (expense) - Gain (loss) on derivatives | $ | 690 | $ | (9,421 | ) | $ | (8,731 | ) | ||||
| Total | $ | 690 | $ | (9,421 | ) | $ | (8,731 | ) | ||||
| Amount of Gain or (Loss) Recognized in Earnings | ||||||||||||
| Year Ended December 31, 2012 | ||||||||||||
| Location of Gain or (Loss) Recognized in Earnings | Realized | Unrealized | Total | |||||||||
| (In thousands) | ||||||||||||
| Derivatives not designated as hedging instruments: | ||||||||||||
| Commodity derivatives: | ||||||||||||
| Other income (expense) - Gain (loss) on derivatives | $ | (3,410 | ) | $ | 17,858 | $ | 14,448 | |||||
| Total | $ | (3,410 | ) | $ | 17,858 | $ | 14,448 | |||||
F-18
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| Amount of Gain or (Loss) Recognized in Earnings | ||||||||||||
| Year Ended December 31, 2011 | ||||||||||||
| Location of Gain or (Loss) Recognized in Earnings | Realized | Unrealized | Total | |||||||||
| (In thousands) | ||||||||||||
| Derivatives not designated as hedging instruments: | ||||||||||||
| Commodity derivatives: | ||||||||||||
| Other income (expense) - Gain (loss) on derivatives | $ | 42,521 | $ | 4,506 | $ | 47,027 | ||||||
| Total | $ | 42,521 | $ | 4,506 | $ | 47,027 | ||||||
10. Fair Value of Financial Instruments
Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under our revolving 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, 2013 and 2012 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, | ||||||||
| 2013 | 2012 | |||||||
Significant Other Observable Inputs | ||||||||
| Description | (Level 2) | |||||||
| (In thousands) | ||||||||
| Assets: | ||||||||
| Fair value of commodity derivatives | $ | 2,518 | $ | 11,731 | ||||
| Total assets | $ | 2,518 | $ | 11,731 | ||||
| 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, 2013 | December 31, 2012 | |||||||||||||||
| Carrying | Estimated | Carrying | Estimated | |||||||||||||
| Description | Amount | Fair Value | Amount | Fair Value | ||||||||||||
| (In thousands) | ||||||||||||||||
| 7.75% Senior Notes due 2019 | $ | 599,638 | $ | 616,500 | $ | 349,585 | $ | 348,700 | ||||||||
11. 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 outstanding options expire ten years from the grant date and are fully exercisable upon issuance. No options were granted under the Directors Plan in 2013 or 2012. At December 31, 2013, 4,000 options were outstanding under this plan. 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.
F-19
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth certain information regarding our stock option plans as of and for the year ended December 31, 2013:
| Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term | Aggregate Intrinsic Value(a) | |||||||||
| Outstanding at January 1, 2013 | 5,000 | $ | 32.21 | |||||||||
Exercised (b) | (1,000 | ) | $ | 28.93 | ||||||||
| Outstanding at December 31, 2013 | 4,000 | $ | 33.03 | 2.5 | $ | 195,690 | ||||||
| Vested at December 31, 2013 | 4,000 | $ | 33.03 | 2.5 | $ | 195,690 | ||||||
| Exercisable at December 31, 2013 | 4,000 | $ | 33.03 | 2.5 | $ | 195,690 | ||||||
_______
| (a) | Based on closing price at December 31, 2013 of $81.95 per share. |
| (b) | Cash received for options exercised totaled $28,930. |
The following table summarizes information with respect to options outstanding at December 31, 2013, all of which were granted under the Directors Plan and are currently exercisable.
| Outstanding and Exercisable Options | ||||||||
| Weighted | ||||||||
| Shares | Weighted Average Exercise Price | Average Remaining Life in Years | ||||||
| Range of exercise prices: | ||||||||
| $22.90 - $41.74 | 4,000 | $ | 33.03 | 2.5 | ||||
The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2013, 2012 and 2011.
| 2013 | 2012 | 2011 | |||||||||
| (In thousands, except per share) | |||||||||||
| Weighted average grant date fair value of options granted per share | $ | — | $ | — | $ | — | |||||
| Intrinsic value of options exercised | $ | 53 | $ | 28 | $ | 594 | |||||
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.
F-20
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”), which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to an APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in 17 specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to May 1, 2013. Of these 17 awards, 13 awards are fully vested, two awards will fully vest on May 1, 2015 and two awards will fully vest on August 1, 2015.
In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the APO cash flow from a 22.5% working interest in one well. The plan is fully vested and 100% of subsequent quarterly bonus amounts are payable to participants.
To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each award. The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.
We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and 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 $2.1 million in 2013, $2.1 million in 2012 and $14.4 million in 2011.
Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule:
| December 31, 2013 | December 31, 2012 | ||||||
| (In thousands) | |||||||
| Current liabilities: | |||||||
| Accrued liabilities and other | $ | 3,317 | $ | 2,220 | |||
| Non-current liabilities: | |||||||
| Accrued compensation under non-equity award plans | 15,469 | 20,058 | |||||
| Total accrued compensation under non-equity award plans | $ | 18,786 | $ | 22,278 | |||
F-21
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. 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, 2013, 2012 and 2011.
| 2013 | 2012 | 2011 | |||||||||
| (In thousands) | |||||||||||
| Amounts received from the Williams Entities: | |||||||||||
| Service Agreement: | |||||||||||
| Services | $ | 715 | $ | 671 | $ | 566 | |||||
| Insurance premiums and benefits | 837 | 920 | 821 | ||||||||
| Reimbursed expenses | 427 | 566 | 371 | ||||||||
| $ | 1,979 | $ | 2,157 | $ | 1,758 | ||||||
| Amounts paid to the Williams Entities: | |||||||||||
Rent(a) | $ | 1,560 | $ | 1,478 | $ | 843 | |||||
| Service Agreement: | |||||||||||
Business entertainment(b) | 344 | 116 | 116 | ||||||||
| Reimbursed expenses | 216 | 267 | 289 | ||||||||
| $ | 2,120 | $ | 1,861 | $ | 1,248 | ||||||
_______
| (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.
13. Other Operating Revenues and Expenses
Other operating revenues and expenses for the years ended December 31, 2013, 2012 and 2011 are as follows:
| 2013 | 2012 | 2011 | |||||||||
| (In thousands) | |||||||||||
| Other operating revenues: | |||||||||||
| Gain on sales of assets | $ | 4,467 | $ | 1,496 | $ | 15,744 | |||||
| Marketing revenue | 2,021 | 581 | — | ||||||||
| Total other operating revenues | $ | 6,488 | $ | 2,077 | $ | 15,744 | |||||
| Other operating expenses: | |||||||||||
| Loss on sales of assets | $ | (1,233 | ) | $ | (523 | ) | $ | (945 | ) | ||
| Marketing expense | (658 | ) | — | — | |||||||
| Impairment of inventory | (210 | ) | (510 | ) | (721 | ) | |||||
| Total other operating expenses | $ | (2,101 | ) | $ | (1,033 | ) | $ | (1,666 | ) | ||
F-22
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
During 2013, gain or loss on sales of assets included the sale of a portion of our Andrews County Wolfberry assets (see Note 5) and certain other non-core properties in Walker County, Texas.
In February 2011, we sold two 2,000 horsepower drilling rigs and related equipment for $22 million of total consideration. In connection with the sale, we recorded a gain of $13.2 million during the first quarter of 2011. Proceeds from the sale consisted of $11 million cash and an $11 million promissory note that was subsequently exchanged for a membership interest in Dalea Investment Group, LLC (“Dalea”) in June 2012 (see Note 14).
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.
14. Investment in Dalea Investment Group, LLC
In June 2012, we cancelled an $11 million note receivable (see Note 13) in exchange for a 7.66% non-controlling membership interest in 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, 2013, we have performed a qualitative assessment and determined there has been no indication of any impairment of our investment in Dalea.
15. 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, $1.6 million and $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Future minimum payments under noncancelable leases at December 31, 2013, are as follows:
| Leases | |||||||||||
Capital(a) | Operating(b) | Total | |||||||||
| (In thousands) | |||||||||||
| 2014 | $ | 1,001 | $ | 3,818 | $ | 4,819 | |||||
| 2015 | 620 | 3,998 | 4,618 | ||||||||
| 2016 | 213 | 3,684 | 3,897 | ||||||||
| Thereafter | — | 338 | 338 | ||||||||
| Total minimum lease payments | $ | 1,834 | $ | 11,838 | $ | 13,672 | |||||
_______
(a) Relates to vehicle leases.
(b) Includes leases for two drilling rigs.
Legal Proceedings
In a case pending since 2001, SWR is a defendant in a suit filed in April 2011 in the Circuit Court of Union County, Arkansas where the plaintiffs are suing for the costs of environmental remediation to a lease on which operations were commenced in the 1930s. The plaintiffs are seeking in excess of $8 million. In June 2013, the plaintiffs, SWR and the remaining defendants agreed to a settlement of $0.8 million, of which SWR would pay $0.7 million. To accomplish the settlement, the case would be converted to a class action, and each member of the class would be offered the right to either participate or opt out of the class and continue a separate action for damages. If more than 25% of the plaintiffs were to opt out of the settlement, SWR would have the right to terminate the settlement. Any plaintiffs opting out would be subject to all previous rulings of the court, including an order dismissing a significant number of the plaintiffs’ claims on the basis that such claims were time barred. SWR believes that the judge will
F-23
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
approve the settlement and the number of the plaintiffs opting out of the settlement, if any, will be insignificant. We recorded a loss on settlement of $0.7 million for the year ended December 31, 2013 in connection with this proposed settlement. We are now awaiting finalization of the settlement by the court.
In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under the Chesapeake farm-in agreement. Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. The case was tried to the judge in October 2013 who ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million. As a result, CWEI recorded a loss of $1.4 million for the year ended December 31, 2013 in connection with the judgment. As a prerequisite for appeal, CWEI filed a motion with the trial court for new trial. In March 2014, rather than ruling on the motion, the trial court ordered the parties to a mediation.
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.
16. Impairment of Property and Equipment
We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value. The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset. We categorize the measurement of fair value of these assets as Level 3 inputs. We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: (1) discounted cash flow method; (2) flowing daily production method; and (3) proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances. We recorded provisions for impairment of proved properties triggered by a combination of well performance and lower reserve estimates due to performance and changes in oil and gas prices aggregating $89.8 million in 2013, $5.9 million in 2012 and $10.4 million in 2011 to reduce the carrying value of those properties to their estimated fair values. 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 related to $5.4 million for certain non-core properties in the Permian Basin. The 2011 provision of $10.4 million related primarily to certain non-core properties in the Permian Basin and other non-core areas.
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 $3.4 million, $1.4 million and $6.2 million in 2013, 2012 and 2011, respectively, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).
F-24
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. 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, 2013, 2012 and 2011.
| 2013 | 2012 | 2011 | |||||||||
| (In thousands) | |||||||||||
| Property acquisitions: | |||||||||||
| Proved | $ | — | $ | 41,098 | $ | — | |||||
| Unproved | 50,104 | 72,235 | 61,236 | ||||||||
| Developmental costs | 218,341 | 349,972 | 328,418 | ||||||||
| Exploratory costs | 3,932 | 10,898 | 27,425 | ||||||||
| Total | $ | 272,377 | $ | 474,203 | $ | 417,079 | |||||
The following table sets forth the net capitalized costs for oil and gas properties as of December 31, 2013 and 2012.
| 2013 | 2012 | ||||||
| (In thousands) | |||||||
| Proved properties | $ | 2,317,053 | $ | 2,482,185 | |||
| Unproved properties | 86,224 | 88,618 | |||||
| Total capitalized costs | 2,403,277 | 2,570,803 | |||||
| Accumulated depletion | (1,282,989 | ) | (1,234,626 | ) | |||
| Net capitalized costs | $ | 1,120,288 | $ | 1,336,177 | |||
18. 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, 2013, 2012 and 2011.
| 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 | |||||||
F-25
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| 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 | ||||||||
| Contract | Intercompany | Consolidated | ||||||||||||||
| For the Year Ended December 31, 2011 | Oil and Gas | Drilling | Eliminations | Total | ||||||||||||
| (In thousands) | ||||||||||||||||
| Revenues | $ | 422,368 | $ | 52,716 | $ | (48,656 | ) | $ | 426,428 | |||||||
Depreciation, depletion and amortization(a) | 112,863 | 12,214 | (9,842 | ) | 115,235 | |||||||||||
Other operating expenses(b) | 174,027 | 44,318 | (38,957 | ) | 179,388 | |||||||||||
| Interest expense | 32,919 | — | — | 32,919 | ||||||||||||
| Other (income) expense | (33,280 | ) | (13,799 | ) | — | (47,079 | ) | |||||||||
| Income (loss) before income taxes | 135,839 | 9,983 | 143 | 145,965 | ||||||||||||
| Income tax (expense) benefit | (48,648 | ) | (3,494 | ) | — | (52,142 | ) | |||||||||
| Net income (loss) | $ | 87,191 | $ | 6,489 | $ | 143 | $ | 93,823 | ||||||||
| Total assets | $ | 1,178,725 | $ | 62,846 | $ | (15,300 | ) | $ | 1,226,271 | |||||||
| Additions to property and equipment | $ | 429,142 | $ | 17,578 | $ | 143 | $ | 446,863 | ||||||||
_______
| (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. |
19. 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 (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 19.
F-26
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, 2013 (Dollars in thousands) | |||||||||||||||||||
| Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiary | Adjustments/ Eliminations | Consolidated | |||||||||||||||
| Current assets | $ | 140,100 | $ | 248,314 | $ | 538 | $ | (250,641 | ) | $ | 138,311 | ||||||||
| Property and equipment, net | 833,980 | 351,171 | 13,956 | — | 1,199,107 | ||||||||||||||
| Investments in subsidiaries | 342,416 | — | — | (342,416 | ) | — | |||||||||||||
| Other assets | 16,032 | 13,287 | — | — | 29,319 | ||||||||||||||
| Total assets | $ | 1,332,528 | $ | 612,772 | $ | 14,494 | $ | (593,057 | ) | $ | 1,366,737 | ||||||||
| Current liabilities | $ | 290,327 | $ | 93,055 | $ | 976 | $ | (247,963 | ) | $ | 136,395 | ||||||||
| Non-current liabilities: | |||||||||||||||||||
| Long-term debt | 639,638 | — | — | — | 639,638 | ||||||||||||||
| Deferred income taxes | 118,438 | 129,880 | 988 | (108,497 | ) | 140,809 | |||||||||||||
| Other | 36,161 | 59,829 | 122 | — | 96,112 | ||||||||||||||
| 794,237 | 189,709 | 1,110 | (108,497 | ) | 876,559 | ||||||||||||||
| Equity | 247,964 | 330,008 | 12,408 | (236,597 | ) | 353,783 | |||||||||||||
| Total liabilities and equity | $ | 1,332,528 | $ | 612,772 | $ | 14,494 | $ | (593,057 | ) | $ | 1,366,737 | ||||||||
Condensed Consolidating Balance Sheet December 31, 2012 (Dollars in thousands) | |||||||||||||||||||
| Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiary | Adjustments/ Eliminations | Consolidated | |||||||||||||||
| Current assets | $ | 133,080 | $ | 224,210 | $ | — | $ | (232,820 | ) | $ | 124,470 | ||||||||
| Property and equipment, net | 1,053,453 | 366,905 | — | — | 1,420,358 | ||||||||||||||
| Investments in subsidiaries | 305,899 | — | — | (305,899 | ) | — | |||||||||||||
| Fair value of derivatives | 4,236 | — | — | — | 4,236 | ||||||||||||||
| Other assets | 12,112 | 13,408 | — | — | 25,520 | ||||||||||||||
| Total assets | $ | 1,508,780 | $ | 604,523 | $ | — | $ | (538,719 | ) | $ | 1,574,584 | ||||||||
| Current liabilities | $ | 241,200 | $ | 112,534 | $ | — | $ | (232,820 | ) | $ | 120,914 | ||||||||
| Non-current liabilities: | |||||||||||||||||||
| Long-term debt | 809,585 | — | — | — | 809,585 | ||||||||||||||
| Deferred income taxes | 143,699 | 117,950 | — | (105,819 | ) | 155,830 | |||||||||||||
| Other | 41,499 | 68,140 | — | — | 109,639 | ||||||||||||||
| 994,783 | 186,090 | — | (105,819 | ) | 1,075,054 | ||||||||||||||
| Equity | 272,797 | 305,899 | — | (200,080 | ) | 378,616 | |||||||||||||
| Total liabilities and equity | $ | 1,508,780 | $ | 604,523 | $ | — | $ | (538,719 | ) | $ | 1,574,584 | ||||||||
F-27
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 | ||||||||
Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2011 (Dollars in thousands) | |||||||||||||||||||
| Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiary | Adjustments/ Eliminations | Consolidated | |||||||||||||||
| Total revenue | $ | 280,359 | $ | 147,015 | $ | — | $ | (946 | ) | $ | 426,428 | ||||||||
| Costs and expenses | 191,012 | 104,557 | — | (946 | ) | 294,623 | |||||||||||||
| Operating income (loss) | 89,347 | 42,458 | — | — | 131,805 | ||||||||||||||
| Other income (expense) | 6,816 | 7,344 | — | — | 14,160 | ||||||||||||||
| Equity in earnings of subsidiaries | 32,371 | — | — | (32,371 | ) | — | |||||||||||||
| Income tax (expense) benefit | (34,711 | ) | (17,431 | ) | — | — | (52,142 | ) | |||||||||||
| Net income (loss) | $ | 93,823 | $ | 32,371 | $ | — | $ | (32,371 | ) | $ | 93,823 | ||||||||
F-28
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 | |||||||||
Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2011 (Dollars in thousands) | |||||||||||||||||||
| Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiary | Adjustments/ Eliminations | Consolidated | |||||||||||||||
| Operating activities | $ | 209,886 | $ | 60,319 | $ | — | $ | 9,842 | $ | 280,047 | |||||||||
| Investing activities | (389,681 | ) | (5,390 | ) | — | (9,842 | ) | (404,913 | ) | ||||||||||
| Financing activities | 186,994 | (53,323 | ) | — | — | 133,671 | |||||||||||||
| Net increase (decrease) in cash and cash equivalents | 7,199 | 1,606 | — | — | 8,805 | ||||||||||||||
| Cash at the beginning of the period | 5,040 | 3,680 | — | — | 8,720 | ||||||||||||||
| Cash at end of the period | $ | 12,239 | $ | 5,286 | $ | — | $ | — | $ | 17,525 | |||||||||
F-29
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20. Subsequent Events
On February 10, 2014, our wholly owned subsidiary, SWR, sold property in Ward County, Texas for $5.1 million, subject to customary closing adjustments.
In February 2014, we entered into a purchase and sale agreement with a third party 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. The transaction is expected to close in March 2014. Net proceeds from the sale, if consummated, will be used to repay the outstanding balance on our revolving bank credit facility and to fund a portion of our planned capital expenditures for 2014.
We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2013 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-30
| 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, 2013 and 2012.
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Year | |||||||||||
| (In thousands, except per share) | |||||||||||||||
| 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 | ||||||||||
| Year ended December 31, 2012: | |||||||||||||||
| Total revenues | $ | 109,069 | $ | 104,610 | $ | 107,763 | $ | 101,610 | $ | 423,052 | |||||
| Operating income | $ | 26,795 | $ | 20,837 | $ | 21,573 | $ | 10,588 | $ | 79,793 | |||||
| Net income (loss) | $ | 7,779 | $ | 32,822 | $ | (7,176 | ) | $ | 1,678 | $ | 35,103 | ||||
Net income (loss) per common share(a): | |||||||||||||||
| Basic | $ | 0.64 | $ | 2.70 | $ | (0.59 | ) | $ | 0.14 | $ | 2.89 | ||||
| Diluted | $ | 0.64 | $ | 2.70 | $ | (0.59 | ) | $ | 0.14 | $ | 2.89 | ||||
| Weighted average common shares outstanding: | |||||||||||||||
| Basic | 12,164 | 12,164 | 12,164 | 12,164 | 12,164 | ||||||||||
| Diluted | 12,164 | 12,164 | 12,164 | 12,164 | 12,164 | ||||||||||
_______
| (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. |
S-1
| 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, 2013, 2012 and 2011.
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, 2013, 2012 and 2011.
| Oil | Natural Gas Liquids | Natural Gas | MBOE | ||||||||
| Proved reserves: | |||||||||||
| December 31, 2010 | 34,379 | 3,436 | 79,497 | 51,065 | |||||||
| Extensions and discoveries | 16,121 | 1,449 | 19,864 | 20,881 | |||||||
| Revisions | (1,809 | ) | 7 | (1,227 | ) | (2,007 | ) | ||||
| Sales of minerals-in-place | (45 | ) | — | (664 | ) | (156 | ) | ||||
| Production | (3,727 | ) | (275 | ) | (8,594 | ) | (5,434 | ) | |||
| 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 | |||||||
| Proved developed reserves: | |||||||||||
| December 31, 2011 | 26,198 | 2,764 | 61,811 | 39,264 | |||||||
| December 31, 2012 | 27,641 | 5,044 | 64,013 | 43,354 | |||||||
| December 31, 2013 | 25,989 | 4,293 | 47,839 | 38,255 | |||||||
S-2
| CLAYTON WILLIAMS ENERGY, INC. | ||||
| SUPPLEMENTAL INFORMATION (Continued) | ||||
| (UNAUDITED) | ||||
Net downward revisions of 901 MBOE consisted of downward revisions of 1,504 MBOE primarily related to well performance offset in part by upward revisions of 603 MBOE, which were attributable to the effects of higher commodity prices on estimated quantities of proved reserves.
The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2013, 2012 and 2011 was as follows:
| 2013 | 2012 | 2011 | |||||||||
| (In thousands) | |||||||||||
| Future cash inflows | $ | 5,162,702 | $ | 5,222,621 | $ | 4,811,837 | |||||
| Future costs: | |||||||||||
| Production | (1,724,560 | ) | (1,819,356 | ) | (1,558,067 | ) | |||||
| Abandonment | (131,747 | ) | (137,499 | ) | (110,833 | ) | |||||
| Development | (592,695 | ) | (651,292 | ) | (510,709 | ) | |||||
| Income taxes | (786,196 | ) | (673,686 | ) | (757,253 | ) | |||||
| Future net cash flows | 1,927,504 | 1,940,788 | 1,874,975 | ||||||||
| 10% discount factor | (1,000,581 | ) | (1,000,957 | ) | (936,462 | ) | |||||
| Standardized measure of discounted net cash flows | $ | 926,923 | $ | 939,831 | $ | 938,513 | |||||
Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2013, 2012 and 2011 were as follows:
| 2013 | 2012 | 2011 | |||||||||
| (In thousands) | |||||||||||
| Standardized measure, beginning of period | $ | 939,831 | $ | 938,513 | $ | 684,438 | |||||
| Net changes in sales prices, net of production costs | 13,292 | (196,930 | ) | 206,357 | |||||||
| Revisions of quantity estimates | (10,680 | ) | (144,899 | ) | (53,089 | ) | |||||
| Accretion of discount | 130,736 | 137,369 | 99,028 | ||||||||
| Changes in future development costs, including development costs incurred that reduced future development costs | 46,068 | 148,733 | 84,638 | ||||||||
| Changes in timing and other | (10,249 | ) | (58,323 | ) | (45,055 | ) | |||||
| Net change in income taxes | (84,673 | ) | 76,593 | (130,562 | ) | ||||||
| Future abandonment cost, net of salvage | 232 | (9,230 | ) | 925 | |||||||
| Extensions and discoveries | 502,619 | 289,999 | 399,068 | ||||||||
| Sales, net of production costs | (289,035 | ) | (277,248 | ) | (305,769 | ) | |||||
| Purchases of minerals-in-place | — | 80,744 | — | ||||||||
| Sales of minerals-in-place | (311,218 | ) | (45,490 | ) | (1,466 | ) | |||||
| Standardized measure, end of period | $ | 926,923 | $ | 939,831 | $ | 938,513 | |||||
S-3
| 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, 2013, 2012 and 2011 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. The average prices used for each commodity for the years ended December 31, 2013, 2012 and 2011 were as follows:
| Average Price | |||||||||||
| Oil | Natural Gas Liquids | Natural Gas | |||||||||
| As of December 31: | |||||||||||
| 2013 | $ | 94.88 | $ | 31.63 | $ | 3.59 | |||||
| 2012 | $ | 90.45 | $ | 43.74 | $ | 3.70 | |||||
| 2011 | $ | 91.35 | $ | 51.19 | $ | 5.31 | |||||
S-4