Clayton Williams Energy 10-K 2010
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 1
CLAYTON WILLIAMS ENERGY, INC.
(Exact name of registrant as specified in its charter)
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
There were 12,145,536 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 10, 2010.
DOCUMENTS INCORPORATED BY REFERENCE
We filed our Annual Report on Form 10-K for the year ended December 31, 2009 (“Form 10-K”) on March 12, 2010. In response to comments from the staff of the Securities and Exchange Commission, we are filing this Amendment No. 1 on Form 10-K/A (“Form 10-K/A”) to replace in its entirety Item 2 – Properties and to file or furnish certain updated exhibits.
Item 2 – Properties is being amended to:
Certain exhibits have been updated and are being filed or furnished with this Form 10-K/A to:
Except as set forth above, this Form 10-K/A does not modify, amend or update in any way any other items or disclosure in the Form 10-K. This Form 10-K/A continues to speak as of the date of the original Form 10-K and other than as specifically reflected in this Form 10-K/A does not reflect events occurring after the filing of the original Form 10-K. Accordingly, this Form 10-K/A should be read in conjunction with the Form 10-K and our other filings with the Securities and Exchange Commission subsequent to filing of the Form 10-K.
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, 2009, we had interests in 6,750 gross (941.2 net) oil and gas wells and owned leasehold interests in approximately 1.1 million gross (618,000 net) undeveloped acres.
Rule Changes Applicable to Reserve Estimates and Disclosures
In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the Financial Accounting Standards Board (“FASB”) adopted conforming changes to Accounting Standards Codification (“ASC”) Topic 932, “Extractive Industries”, to align the FASB’s reserves requirements with those of the SEC. The final rule is now in effect for companies with fiscal years ending on or after December 31, 2009. As it affects our reserve estimates and disclosures, the final rule:
See “Glossary of Terms” for current definitions of terms related to oil and gas reserves.
The following table sets forth our estimated quantities of proved reserves as of December 31, 2009, all of which are located within the United States.
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 Value”), totaled $460.4 million at December 31, 2009. The commodity prices used to estimate proved reserves and their related PV-10 Value at December 31, 2009 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 2009 through December 2009. 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 $54.81 per barrel of oil and NGL and $3.71 per Mcf of natural gas over the remaining life of our proved reserves. Operating costs were not escalated.
PV-10 Value 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, 2009, we began with the PV-10 Value of our proved reserves and deducted the present value of estimated future income taxes of $66.8 million and net abandonment costs of $29.3 million, discounted at 10%. At December 31, 2009, our standardized measure of discounted future net cash flows totaled $364.3 million. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each company, the present value 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, 2009 regarding our estimated proved reserves in each of our principal producing areas.
The following table summarizes changes in our estimated proved reserves during 2009.
Extensions and discoveries. Extensions and discoveries in 2009 added 3,655 MBOE of proved reserves, replacing 63% of our 2009 production. These additions resulted primarily from our drilling activities in the Permian Basin and the Austin Chalk (Trend) despite curtailments of capital spending during the first half of 2009 due to recessionary uncertainties. Of the total reserve additions, proved developed reserves accounted for 2,738 MBOE, while the remaining 917 MBOE were proved undeveloped reserves.
Revisions. Net downward revisions of 2,353 MBOE consisted of downward revisions of 2,420 MBOE related to performance and upward revisions of 67 MBOE related to pricing. Substantially all of the downward performance revisions resulted from the reclassification of certain Permian Basin reserves from proved undeveloped to probable (see discussion below regarding changes in proved undeveloped reserves). Net upward revisions of 67 MBOE were attributable to the effects of higher product prices on the estimated quantities of proved reserves.
Proved undeveloped reserves decreased 1,673 MBOE in 2009 from 6,724 MBOE at the beginning of the year to 5,051 MBOE at December 31, 2009 due primarily to the reclassification of 2,412 MBOE of Permian Basin reserves from proved undeveloped to probable. These reclassified reserves relate to undrilled locations we acquired in 2004 in connection with the purchase of Southwest Royalties, Inc. These undrilled locations are on leases which are held by existing production from other wells. Although we expect to develop these reserves in the future, the reserves were downgraded to probable due to a provision in the new SEC reserves rule that requires proved undeveloped reserves to be developed within five years from their date of origin. We added 917 MBOE of proved reserves from extensions and
discoveries related to nine proved undeveloped locations that we plan to drill in 2010 at an expected cost of approximately $15 million. Net downward revisions to proved undeveloped reserves of 178 MBOE resulted primarily from the loss of one drilling location due to expiration of drilling rights, offset in part by upward revisions in estimates due to price increases. We did not convert any proved undeveloped reserves at December 31, 2008 to proved developed reserves during 2009.
Alternative Pricing Cases
In addition to the estimated proved reserves disclosed above in accordance with the commodities pricing required by the new reserves rule (referred to as the “SEC Case”), the following table sets forth certain information regarding our proved reserves based on two supplementary pricing cases.
Year-end Pricing Case. The Year-end Pricing Case was provided to compare our estimated proved reserves based on the SEC Case with those estimates obtained based on previous pricing guidelines. Under the Year-end Pricing Case, we used the spot prices in effect on December 31, 2009 as our benchmark prices. 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 $70.98 per barrel of oil and NGL and $5.61 per Mcf of natural gas over the remaining life of our proved reserves. Operating costs were not escalated.
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 New York Mercantile Exchange (“NYMEX”) on December 31, 2009, as benchmark prices for 2010 through 2014, and continued to use the 2014 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 $79.99 per barrel of oil and NGL and $6.38 per Mcf of natural gas over the remaining life of the proved reserves. Operating costs were escalated at 2% per year.
Reserve Estimation Procedures
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 SEC and 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, 2009 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 53.2% and Ryder Scott evaluated 46.2% on a BOE basis.
Qualifications of Technical Manager and Consultants
Ron D. Gasser, our Engineering Manager, is the person within our organization that is primarily responsible for overseeing the preparation of the reserve estimates. Mr. Gasser joined our Company in 2002 as a Senior Engineer working on acquisitions/divestitures and special projects and was promoted to his current position as Engineering Manager in 2006. Mr. Gasser has 27 years experience as a petroleum engineer, including 24 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 their report. Mr. Savage has 28 years experience in evaluating oil and gas reserves, including 26 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 70 years. John E. Hamlin, Managing Senior Vice President of Ryder Scott, is the technical person primarily responsible for evaluating the proved reserves covered by their report. Mr. Hamlin has more than 33 years of experience in the estimation and evaluation of petroleum reserves. Mr. Hamlin holds a Bachelor of Science degree in Petroleum Engineering from the University of Texas. He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.
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 government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. 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 have been field tested and have 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.
More than 90% of our additions to proved reserves in 2009 were derived from wells drilled in the Permian Basin and the Austin Chalk (Trend). 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 2009 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 AriesTM, 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 Value. 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 “Technologies Used to Establish Proved Reserves.” Operational data includes 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 our 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 AriesTM reserves database to Ryder Scott as it relates to properties owned by Southwest Royalties, Inc., one of our wholly-owned subsidiaries, and to Williamson as it relates to properties owned by CWEI and Warrior Gas Company, another of our wholly-owned subsidiaries. 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 AriesTM reserves database which 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 AriesTM 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 Mel G. Riggs, 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 mineral-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 reserve estimates.
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 Value 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, 2009, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.
As of December 31, 2009, 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 which require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.
Exploration and Development Activities
We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.
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, 2009, of productive wells in the areas indicated.
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.
Only one field, the Giddings field in the Austin Chalk (Trend), accounted for 15% or more of our total proved reserves (on a BOE basis) as of December 31, 2009. The following table discloses our oil, gas and natural gas liquids production from the Giddings field for the periods indicated.
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.
The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2009 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.
The following table sets forth expiration dates of the leases of our gross and net undeveloped acres as of December 31, 2009.
Through a wholly-owned subsidiary, Desta Drilling, we own and operate 12 drilling rigs, consisting of five 1,000 horsepower rigs, five 1,300 horsepower rigs and two 2,000 horsepower rigs. As of March 12, 2010, we were using four of the 1,000 horsepower rigs and four of the 1,300 horsepower rigs to drill wells in our developmental drilling program. The Desta Drilling rigs are reserved for our use, and we do not have any current plans to conduct contract drilling operations for third parties. We are attempting to sell both of the 2,000 horsepower rigs and have classified those rigs as Assets Held for Sale in the accompanying consolidated financial statements.
We lease from a related partnership approximately 71,000 square feet of office space in Midland, Texas for our corporate headquarters. We also lease approximately 10,000 square feet of office space in Houston, Texas from unaffiliated third parties.
Item 15 - Exhibits and Financial Statement Schedules
Financial Statements and Schedules
The consolidated financial statements and financial statement schedules were previously filed.
The following exhibits are filed as a part of this Report, with each exhibit that consists of or includes a management contract or compensatory plan or arrangement being identified with a “†”:
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.