Attached files
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2009
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
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OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to
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Commission File Number 001-10924
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CLAYTON WILLIAMS ENERGY, INC.
(Exact name of registrant as specified in its charter)
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Delaware
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75-2396863
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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Six Desta Drive - Suite 6500
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Midland, Texas
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79705-5510
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(Address of principal executive offices)
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(Zip code)
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Registrant’s telephone number, including area code:
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(432) 682-6324
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Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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Common Stock - $.10 Par Value
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The NASDAQ Stock Market LLC
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Securities registered pursuant to Section 12(g) of the Act: None
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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act
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¨ Yes
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x No
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Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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¨ Yes
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x No
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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.
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x Yes
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¨ No
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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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).
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¨Yes
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¨ No
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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
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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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer ¨
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Accelerated filer x
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Non-accelerated filer ¨
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Smaller reporting company ¨
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
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¨ Yes
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x No
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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 common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter. $111,191,777.
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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
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Portions of the definitive proxy statement relating to the 2010 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2010, are incorporated by reference in Part III of this Form 10-K.
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CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS
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Part I
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Part II
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TABLE OF CONTENTS (Continued)
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Part III
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Part IV
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3
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. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K.
Forward-looking statements appear in a number of places and include statements with respect to, among other things:
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estimates of our oil and gas reserves;
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estimates of our future oil and gas production, including estimates of any increases or decreases in production;
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planned capital expenditures and the availability of capital resources to fund those expenditures;
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our outlook on oil and gas prices;
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our outlook on domestic and worldwide economic conditions;
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our access to capital and our anticipated liquidity;
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our future business strategy and other plans and objectives for future operations;
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the impact of political and regulatory developments;
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our assessment of counterparty risks and the ability of our counterparties to perform their future obligations;
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estimates of the impact of new accounting pronouncements on earnings in future periods; and
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our future financial condition or results of operations and our future revenues and expenses.
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We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and gas. These risks include, but are not limited to:
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the possibility of unsuccessful exploration and development drilling activities;
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our ability to replace and sustain production;
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commodity price volatility;
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domestic and worldwide economic conditions;
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the availability of capital on economic terms to fund our capital expenditures and acquisitions;
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our level of indebtedness;
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the impact of the current economic recession 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 credit facility and impairments;
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the ability of financial counterparties to perform or fulfill their obligations under existing agreements;
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the uncertainty inherent in estimating proved oil and gas reserves and in projecting future rates of production and timing of development expenditures;
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drilling and other operating risks;
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hurricanes and other weather conditions;
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lack of availability of goods and services;
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regulatory and environmental risks associated with drilling and production activities;
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the adverse effects of changes in applicable tax, environmental and other regulatory legislation; and
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the other risks described in this Form 10-K.
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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. 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 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.
PART I
Item 1 - Business
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, 2009, our estimated proved reserves were 33,637 MBOE, of which 85% were proved developed. Our portfolio of oil and natural gas reserves is weighted in favor of oil, with approximately 60% of our proved reserves at December 31, 2009 consisting of oil and natural gas liquids and approximately 40% consisting of natural gas. During 2009, we added proved reserves of 3,655 MBOE through extensions and discoveries and had downward revisions of 2,353 MBOE. We also achieved average net production of 15.8 MBOE per day in 2009, which implies a reserve life of approximately 5.8 years. CWEI held interests in 6,750 gross (941.2 net) producing oil and gas wells and owned leasehold interests in approximately 1.1 million gross (618,000 net) undeveloped acres at December 31, 2009.
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Clayton W. Williams, Jr. 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 our Chairman of the Board and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations.
Company Profile
Business Strategy
Our goal is to grow oil and gas reserves and increase shareholder value utilizing a flexible, opportunity-driven business strategy. We do not adhere to rigid guidelines for resource allocations, risk profiles, product mixes, financial measurements or other operating parameters. Instead, we try to identify exploratory and developmental projects that offer us the best possible opportunities for growth in oil and gas reserves and allocate our available resources to those projects. Our direction is heavily influenced by Mr. Williams based on over 50 years of experience and leadership in the oil and gas industry. Our business strategy consists of an aggressive exploration program, complemented by developmental drilling and 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
Our business in 2009 was adversely affected by the recession that began in 2008 and continues to impact the United States and other global economies. Reduced demand for energy caused oil and gas prices to fall sharply, resulting in a significant deterioration in our operating margins (oil and gas sales less production costs). The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our proved oil and gas reserves. These factors have an adverse effect on our ability to access the capital resources we need to grow our reserve base. Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business. As a result, we suspended our developmental drilling program in the Permian Basin and the Austin Chalk (Trend) in late 2008 and turned our business focus toward preserving short-term liquidity and conserving capital resources.
By the end of the second quarter of 2009, operating margins on oil-prone properties had begun to improve somewhat due to a combination of higher oil prices and lower costs of field services caused by decreased demand for those services. Since most of our developmental drilling locations are oil-prone, we elected to resume drilling developmental oil wells primarily in Andrews County, Texas in the Permian Basin and Burleson, Lee and Robertson Counties, Texas in the Austin Chalk (Trend). In connection with the return to drilling activities in these areas, we have taken the following actions, which we believe will enhance the development of these core areas:
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Entered into 2-year agreements with selected service providers to fix unit costs covering approximately 90% of the drilling and completion services provided by third parties;
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Improved drilling efficiencies by acquiring the noncontrolling interest in Desta Drilling, giving us full control over the management and operation of drilling services (see “Investment in Desta Drilling” below);
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Purchased casing and tubing for more than 175 wells at discounts to current market prices; and
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Entered into derivative contracts for most of our estimated proved developed oil production for 2010 and 2011 at average prices of $76.50 and $84.38 per barrel, respectively.
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We currently plan to spend approximately $274.4 million on exploration and development activities in 2010, substantially all of which is associated with our developmental drilling programs in the Permian Basin and the Austin Chalk (Trend) areas.
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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.
Exploration Program
Our exploration program consists of generating exploratory prospects, leasing the acreage related to the prospects, drilling exploratory wells on these prospects to determine if recoverable oil and gas reserves exist, drilling developmental wells on prospects, and producing and selling any resulting oil and gas production.
To generate a typical exploratory prospect, we first identify geographical areas that we believe may contain undiscovered oil and gas reserves. We then consider many other business factors related to those geographical areas, including proximity to our other areas of operations, our technical knowledge and experience in the area, the availability of acreage, and the overall potential for finding reserves. Most of our current exploration efforts are concentrated in regions that have been known to produce oil and gas. These regions include some of the larger producing regions in Texas and Louisiana.
In most cases, we then obtain and process seismic data using sophisticated geophysical technology to attempt to visualize underground structures and stratigraphic traps that may hold recoverable reserves. Although this technology increases our expectations of a successful discovery, it does not and cannot assure us of success. Many factors are involved in the interpretation of seismic data, including the field recording parameters of the data, the type of processing, the extent of attribute analyses, the availability of subsurface geological data, and the depth and complexity of the subsurface. Significant judgment is required in the evaluation of seismic data, and differences of opinion often exist between experienced professionals. These interpretations may turn out to be invalid and may result in unsuccessful drilling results.
Obtaining oil and gas reserves through exploration activities involves a higher degree of risk than through drilling developmental wells or purchasing proved reserves. We often commit significant resources to identify a prospect, lease the drilling rights and drill a test well before we know if a well will be productive. To offset this risk, our typical exploratory prospect is expected to offer a significantly higher reserve potential than a typical lower risk development prospect might offer. The reserve potential is determined by estimating the aerial extent of the structural or stratigraphic trap, the vertical thickness of the reservoir in the trap, and the recovery factor of the hydrocarbons in the trap. The recovery factor is affected by a combination of factors including (1) the reservoir drive mechanism (water drive, depletion drive or a combination of both), (2) the permeability and porosity of the reservoir, and (3) the bottom hole pressure (in the case of gas reserves).
Due to the higher risk/higher potential nature of oil and gas exploration, we expect to spend money on prospects that are ultimately nonproductive. However, over time, we believe our productive prospects will generate sufficient cash flow to provide us with an acceptable rate of return on our entire investment, both nonproductive and productive.
Many of our exploratory prospects, particularly those in our East Texas Bossier and South Louisiana areas, target gas reserves. Since we believe gas prices are likely to be less favorable than oil prices in the near term, we currently plan to spend only $9.5 million on exploration activities in 2010.
Development Program
Complementary to our higher risk/higher potential exploration program is our development program. 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 Austin Chalk (Trend). In most 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. Consistent with our business strategy, we have historically limited our spending on developmental projects in order to maximize our exploration efforts. However, since our outlook for oil prices is more favorable than gas prices, we currently plan to spend approximately $264.9 million, or 97% of our planned expenditures for 2010, on developmental projects, most of which are in oil-prone areas.
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Acquisition and Divestitures of Proved Properties
In addition to our exploration and development activities, we seek to acquire proved reserves, but 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 extremely difficult for us to acquire reserves without assuming significant price and production risks. We are actively searching for opportunities to acquire proved oil and gas properties; however, we did not acquire any proved properties in 2009, and we cannot give any assurance that we will be successful in our efforts to acquire proved properties in 2010.
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 property, the fairness of the price offered, and other factors related to the condition and location of the property.
Investment in Desta Drilling
We formed a joint venture in 2006 with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. Initially, we referred to this joint venture as Larclay JV, but in June 2009, we changed the legal name of the operating entity in the joint venture to Desta Drilling, LP (“Desta Drilling”). Desta Drilling was formed at a time when rig utilization rates in the industry were high and rates for drilling services were escalating. In order to assure the availability of drilling rigs for our exploration and development activities, we provided credit support to permit Desta Drilling to finance the construction of the 12 drilling rigs and related equipment. The credit support consisted of (1) a subordinated loan of $4.6 million to finance excess construction costs, (2) a limited guaranty to the secured lender in the original amount of $19.5 million, and (3) a drilling contract that expired in 2009 under which we were obligated to utilize the drilling rigs or pay idle rig rates. During the term of the drilling contract, we paid idle rig fees to Desta Drilling totaling $24.4 million. We and Lariat also made loans to Desta Drilling in the form of subordinated notes of $7.5 million each to provide additional financial support. Lariat was designated as the operator of the rigs and provided all management services on behalf of Desta Drilling.
Initially, we and Lariat each owned a 50% equity interest in Desta Drilling, but effective April 15, 2009, we entered into an agreement with Lariat whereby Lariat assigned to us its 50% equity interest (the “Assignment”). The Assignment from Lariat also included all of Lariat’s right, title and interest in the subordinated loans previously made by Lariat to Desta Drilling. As consideration for the Assignment, CWEI assumed all of the obligations and liabilities of Lariat relating to Desta Drilling from and after the effective date, including Lariat’s obligations as operator of Desta Drilling’s rigs. Upon consummation of the Assignment, CWEI contributed all of the subordinated loans to Desta Drilling’s capital. In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under our revolving credit facility. All of the assets of Desta Drilling were pledged as collateral under our revolving credit facility.
Of the 12 drilling rigs owned by Desta Drilling, ten are medium-sized drilling rigs (either 1,000 or 1,350 horsepower) and two are large drilling rigs (2,000 horsepower). All of the medium-sized drilling rigs are suitable for use in our developmental drilling programs, and we are currently using four of these drilling rigs in the Permian Basin and two in the Austin Chalk (Trend). We do not have immediate plans to use the large drilling rigs in our drilling programs and have designated these drilling rigs as assets held for sale.
Exploration and Development Activities
We elected to resume drilling developmental oil wells in the Permian Basin and the Austin Chalk (Trend) during the second quarter of 2009. Approximately 60% of the $138.3 million spent on exploration and development activities during 2009 was applicable to developmental prospects. We currently plan to spend approximately $274.4 million on exploration and development activities during 2010, of which approximately 97% is expected to be spent on developmental drilling. We may increase or decrease our planned activities, depending upon drilling results, operating margins, the availability of capital resources, and other factors affecting the economic viability of such activities.
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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. 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. This acquisition provided us with an inventory of potential drilling and recompletion activities.
We spent $61.7 million in the Permian Basin during fiscal 2009 on drilling and completion activities and $2 million on seismic and leasing activities. We drilled 51 gross (47.5 net) operated wells in the Permian Basin and conducted various remedial operations on other wells in 2009. We currently plan to spend approximately $210.5 million on drilling and completion activities in the Permian Basin in fiscal 2010. Our activities are expected to be concentrated in the following areas.
Andrews County - Wolfberry
We have a large acreage block in Andrews County, Texas on which we have identified more than 200 potential locations for Wolfberry wells. A Wolfberry well is a well that commingles production from the Spraberry and Wolfcamp formations. We resumed continuous drilling operations in this area in June 2009 with a single drilling rig, added a second rig in July and a third rig in October. During 2009, we drilled and completed 13 gross (11.7 net) wells in this area at an average gross cost of approximately $1.8 million. An additional 6 gross (5.2 net) wells were in progress at the end of 2009, of which 5 gross (4.3 net) have been completed to date. In 2010, we plan to use up to six of our rigs to drill and complete approximately 104 additional wells at an estimated cost of $173.9 million, net to our working interest.
Fuhrman-Mascho Field
We also resumed a drilling program in the Fuhrman-Mascho Field in Andrews County, Texas beginning in July 2009. During 2009, we drilled and completed 20 gross (18.2 net) wells in this area. An additional 4 gross (3.6 net) wells were in progress at the end of 2009, all of which have been completed to date. In 2010, we plan to drill and complete approximately 14 additional wells at an estimated cost of $4.1 million, net to our working interest.
Austin Chalk (Trend)
Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Lee, Milam and Leon Counties, Texas. 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. We believe that the existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling.
We spent $13.8 million in the Austin Chalk (Trend) area during fiscal 2009. During 2009, we drilled and completed 3 gross (2.9 net) wells in this area. An additional 2 gross (2 net) wells were in progress at the end of 2009, both of which have been completed to date. In 2010, we plan to use two of our rigs to drill and complete approximately 20 wells at an estimated cost of $39.3 million, net to our working interest. We currently plan to spend approximately $49.8 million on drilling and completion activities in the Austin Chalk (Trend) in fiscal 2010.
Eagle Ford Shale
The Eagle Ford Shale is a formation immediately beneath the Austin Chalk (Trend) formation. We have drilled a horizontal well in Burleson County, Texas to test the Eagle Ford Shale underlying its existing Austin Chalk (Trend) acreage. The well is currently producing, and we are evaluating the data to determine if an Eagle Ford Shale drilling program is economically viable. Depending on the results of this well, we may decide to drill additional wells in the future to further evaluate our Eagle Ford Shale potential.
South Louisiana
We participated in the drilling of the State Lease 18669 #1, an exploratory well in Plaquemines Parish (West Lake Washington prospect) in 2008, and the well was placed into production in June 2009. We own a 50% non-operated working interest in this well.
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In August 2009, we terminated drilling operations on the Miami Corp. #2, an exploratory test well in the Bayou Sale field on our Liger Prospect in St. Mary Parish, Louisiana. The well targeted multiple lower Miocene sands which were encountered at depths ranging from 15,928 to 16,916 feet. Based on well logs, we determined that no commercial quantities of hydrocarbons existed in these sands and plugged and abandoned the well. The Miami Corp. #2 well was a replacement well for the Miami Corp. #1 that was abandoned in May 2009 after encountering mechanical difficulties. Since the accumulated drilling costs of both wells were capitalized pending the results of drilling activities on the Miami Corp. #2 well, we recorded a pre-tax charge of approximately $19 million related to the abandonment of these wells during 2009.
We spent $28.8 million in South Louisiana during fiscal 2009 on exploration and development activities, of which $25.8 million was spent on drilling and completion activities and $3 million was spent on seismic and leasing activities. We currently plan to spend $8.8 million for fiscal 2010, of which $8 million relates to drilling and completion activities and the remaining $800,000 relates to seismic and leasing activities.
North Louisiana
In 2005, we began a drilling program in North Louisiana targeting the Cotton Valley/Gray and Bossier formations. In this area, the Cotton Valley/Gray formations are encountered at depths ranging from 8,000 to 12,000 feet, and the Bossier formation is encountered at depths ranging from 11,000 to 15,500 feet.
To date, we have drilled 18 wells on our Terryville prospect and have completed 16 wells as producers. On our Ruston prospect, we have completed four wells as producers. We spent $5.3 million in North Louisiana during fiscal 2009 on exploration and development activities, of which $4.5 million was spent on drilling and completion activities and $800,000 was spent on seismic and leasing activities. We currently do not have any significant activities planned in this area in 2010.
East Texas Bossier
We have an extensive acreage position in East Texas targeting the prolific deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet in this area. Exploration for deep Bossier gas sands in this area is in its early stages and involves a high degree of risk. The geological structures are complex, and limited drilling activity offers minimal subsurface control. Deep Bossier wells are expensive to drill, with completed wells costing approximately $18 million each. Although seismic data is helpful in identifying possible sand accumulations, the only way to determine whether the deep Bossier sand will be commercially productive is to drill wells to the targeted structures.
We began drilling the Sunny Unit #1, a 17,300-foot exploratory well in Burleson County, Texas targeting the deep Bossier formation, in the third quarter of 2008 and completed the well in the middle Bossier sands in the second quarter of 2009. Since there is no suitable gas market in the vicinity of this well, and since the well is marginally economic to produce, we elected not to incur the costs to place the well on production. Therefore, we recorded a pre-tax charge of $17.5 million for the abandonment of this well during the fourth quarter of 2009.
We spent $17 million in the East Texas Bossier area during 2009 on exploration and development activities, of which $6 million was spent on drilling and completion activities and $11 million was spent on seismic and leasing activities. We currently plan to spend approximately $1.3 million for fiscal 2010, all of which relates to seismic and leasing activities.
Utah
In 2008, we participated in the drilling of the Ron Lamb 31A-4-1, a 12,670-foot exploratory well in which we own a 33% non-operated working interest. The well was drilled in the central Overthrust area in Sanpete County, Utah targeting the oil-prone Navajo sandstone formation. We abandoned this well in the first quarter of 2009 and recorded a pre-tax charge of approximately $1.7 million for drilling and leasehold impairments related to this well.
Marketing Arrangements
We sell substantially all of our oil production under short-term contracts based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate contracts, less agreed-upon deductions which vary by grade of crude oil. The majority of our gas production is sold under short-term contracts based on pricing formulas which are generally market responsive. From time to time, we may also sell a portion of our gas production under short-term contracts at fixed prices. We believe that the loss of any of our oil and gas purchasers would not have a material adverse effect on our results of operations due to the availability of other purchasers.
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Natural Gas Services
We own an interest in and operate natural gas service facilities in the states of Texas, Louisiana, Mississippi and New Mexico. These natural gas service facilities consist of interests in approximately 94 miles of pipeline, three treating plants, one dehydration facility, three compressor stations, and four wellhead type treating and/or compression facilities. Most of our operated gas gathering and treating activities exist to 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 also 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 revenue.
The market for our oil, gas and natural gas liquids 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 natural gas liquids, 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.
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 natural gas and requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and natural 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 natural 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 natural 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 (“BLM”) or other relevant federal or state agencies.
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Regulations affecting sales. The sales prices of oil, natural gas liquids and natural gas 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 (“FERC”) regulates interstate natural 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 natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially differently than other natural gas producers in our areas of operation.
The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. Interstate transportation rates for oil, natural gas liquids 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 natural gas liquids.
Market manipulation and market transparency regulations. Under the Energy Policy Act of 2005 (“EP Act 2005”), FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions in the EP Act 2005. The Commodity Futures Trading Commission (“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 natural gas, natural gas liquids and crude oil, our gathering of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.
FERC has issued certain market transparency rules pursuant to its EP Act 2005 authority, which may affect some or all of our operations. 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 natural gas in the previous calendar year, including natural gas producers, gatherers, processors, and marketers, to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural 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 the order. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. In addition, on November 20, 2008, FERC issued a final rule pursuant to its EP Act 2005 authority regarding daily scheduled flows and capacity posting requirements, as amended by a subsequent order on rehearing (“Order 720”). Under Order 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day. Over the previous three calendar years, we have delivered, on average, less than 50 million MMBtu of gas, and therefore we believe that we are currently exempt from Order 720.
Gathering regulations. Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own certain natural 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 FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the subject of substantial, on-going 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 the U.S. Congress.
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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 natural gas. In addition, our natural 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 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 2010. We do not believe that we will be required to incur any 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.
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. 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.
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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 (“EPA”) or state agencies as solid wastes. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. 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 Federal 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. 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. We do not believe that our operations will be materially adversely affected by any such requirements.
Water Discharges. The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws 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. 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 June 2009, the U.S. House of Representatives passed a bill—the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”)—to control and reduce the emission of “greenhouse gases” (“GHGs”), such as carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. The U.S. Senate is currently considering similar legislation that seeks to reduce emission of GHGs in the United States through the granting of emission allowances which would gradually be decreased over time. Moreover, more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of GHGs. Also, on December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has also proposed regulations that would require a reduction in emissions of GHGs from motor vehicles, and this regulatory action, if finalized, could also lead to the imposition of GHG emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. Although the vast majority of our facilities were not subject to the EPA’s GHG reporting rule adopted in September 2009, the EPA has indicated that it is evaluating whether the rule should be applied to oil and gas production activities, perhaps on a field-wide basis. While it is not possible at this time to fully predict how legislation or new regulations that may be adopted in the United States to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that we produce.
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Pipeline Safety. Some of our pipelines are subject to regulation by the U.S. Department of Transportation (“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. The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, natural gas liquids (“NGLs”), 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.
OSHA and Other Laws and Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
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, in other jurisdictions in which we operate, courts 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 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 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 16 to the accompanying consolidated financial statements.
Executive Officers
The following is a list, as of March 12, 2010 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 78, 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 entities which 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.
L. PAUL LATHAM, age 58, is Executive Vice President, Chief Operating Officer and a director of the Company, having served in such capacities since September 1991. Mr. Latham is the sole general partner of WCPL. WCPL holds approximately 25% of the outstanding shares of our common stock. As the sole general partner, Mr. Latham has the power to vote or direct the voting of the shares of our common stock held by WCPL. Mr. Latham also serves as an officer and director of certain entities which are controlled directly or indirectly by Mr. Williams.
MEL G. RIGGS, age 55, is Senior Vice President and Chief Financial Officer of the Company, having served in such capacities since September 1991. Mr. Riggs has served as a director of the Company since May 1994.
PATRICK C. REESBY, age 57, is Vice President – New Ventures of the Company, having served in such capacity since 1993.
ROBERT C. LYON, age 73, is Vice President – Gas Gathering and Marketing of the Company, having served in such capacity since 1993.
MICHAEL L. POLLARD, age 59, is Vice President – Accounting of the Company, having served in such capacity since 2003. Prior to that, Mr. Pollard had served as Controller of the Company since 1993.
T. MARK TISDALE, age 53, is Vice President and General Counsel of the Company, having served in such capacity since 1993.
GREGORY S. WELBORN, age 36, is Vice President – Land of the Company, having served in such capacity since 2006. Prior to that, Mr. Welborn was self-employed. Mr. Welborn is the son-in-law of Clayton W. Williams, Jr.
At December 31, 2009, we had 312 full-time employees, of which 111 are 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 Securities and Exchange Commission (“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 risks described below are not the only ones facing our company. Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations.
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 natural gas. Product prices affect our cash flow 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. The decline in oil and natural gas prices in 2009 has impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. If commodity prices decline in the future, the decline could have adverse effects on our reserves and borrowing base.
The prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:
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changes in the supply of and demand for oil and natural gas;
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market uncertainty;
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the level of consumer product demands;
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hurricanes and other weather conditions;
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domestic governmental regulations and taxes;
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the price and availability of alternative fuels;
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political and economic conditions in oil producing countries;
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the foreign supply of oil and natural gas;
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the price of oil and gas imports; and
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overall domestic and foreign economic conditions.
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These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural 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 natural gas prices do not necessarily fluctuate in direct relation to each other.
We may not be able to replace production with new reserves.
In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. Historically, our oil and gas properties have had steep rates of decline and short estimated productive lives. The implied life of our proved reserves at December 31, 2009 is approximately 5.8 years, based on 2009 production levels.
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Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or 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 natural 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, and if our borrowing base under the revolving facility is redetermined to a lower amount, this could adversely affect our ability to supplement cash flow 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 or cash flows provided by operations will be sufficient to meet these 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, 2009, the principal amount of our outstanding consolidated debt was approximately $395 million, which included approximately $170 million outstanding under our revolving credit facility. Our revolving credit facility and the Indenture governing our 7¾% Senior Notes due 2013 impose significant restrictions on our ability to take certain actions, including our ability to incur additional indebtedness, sell certain assets or 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:
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require us to use a significant portion of our cash flow 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;
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adversely affect the credit ratings assigned by third party rating agencies, which have in the past 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;
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limit our access to the capital markets;
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increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;
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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;
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place us at a disadvantage compared to similar companies in our industry that have less debt; and
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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 regulations and environmental regulations, and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all.
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A financial crisis may impact our business and financial condition and it may adversely impact our ability to obtain funding under our revolving credit facility or in the capital markets.
The credit crisis and related turmoil in the global financial systems have had an impact on our business and our financial condition. An economic crisis could reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas. Historically, we have used our cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a borrowing base redetermination, or (2) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, and an increased counterparty credit risk on our derivatives contracts.
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 expected or the costs of goods and services increase, our profitability would be adversely affected.
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we currently and may in the future enter into hedging transactions for a significant portion of our expected oil and gas production that 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 activities. 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 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 for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow 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:
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we may be limited in receiving the full benefit of increases in oil and gas prices as a result of these transactions;
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a counterparty may not perform its obligation under the applicable derivative instrument or seek bankruptcy protection;
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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
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the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
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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 revenue, profitability, and cash flow, to be materially different from our estimates.
The accuracy of proved reserves estimates and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn could adversely affect our cash flow, results of operations 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 the new 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 the 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 such 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.
Price declines may result in impairments of our asset carrying values.
Commodity prices have a significant impact on the present value of our proved reserves. Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our oil and gas properties in certain situations. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required. Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.
Our exploration activities subject us to greater risks than development activities.
Generally, our oil and gas exploration activities pose a higher economic risk to us than our development activities. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to increasing oil or natural 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.
For 2010, only 3% of our planned exploration and development activities relate to exploratory prospects, as compared to 40% in 2009. To the extent we engage in exploration activities, we have a greater risk of drilling dry holes or not finding oil and natural 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 natural 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 affect on our results of operations, cash flow and capital resources.
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Drilling oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.
Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil or natural 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 often are 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:
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unexpected drilling conditions;
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title problems;
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pressure or irregularities in formations;
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equipment failures or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and
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costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment and services.
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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 on-going 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 in an acquisition. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed.
Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders' equity.
Our failure to integrate acquired businesses 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 operations into our existing operations 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 existing operations.
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, 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.
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Our business depends on oil and natural gas transportation facilities, most of which are owned by others.
The marketability of our oil and natural 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 and facilities 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 natural 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 natural gas.
Future shortages of available drilling rigs, equipment and personnel may delay or restrict our operations.
The oil and natural gas industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or 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.
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 revenue.
The market for our oil, gas and natural gas liquids 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 natural gas liquids, 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. 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 and Chief Executive Officer. As a result, Mr. Williams has significant influence over matters voted on by our shareholders, including the election of our Board members, and in all other facets of our business, including both our business strategy and daily operations.
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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. L. Paul Latham, 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. Latham 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 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. As appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. We cannot give assurance that we will not suffer any economic loss related to credit risks in the future.
Compliance with laws and regulations governing our activities could be costly and could negatively impact production.
Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.
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 natural 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 natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those 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 natural gas liquids.
Under the EP Act 2005, 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 operations have not been regulated by FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting and daily scheduled flow and capacity posting requirements, as described more fully in Item 1 above. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.
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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 discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of 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. Under a number of environmental laws, such liabilities may also be 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. 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.
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 future legislation.
The Proposed Fiscal Year 2010 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to: (1) the repeal of the percentage depletion allowance for oil and natural 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 any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.
In June 2009, the U.S. House of Representatives passed a bill—the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” (“ACESA”)—to control and reduce the emission of “greenhouse gases” (“GHGs”), such as carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes. The U.S. Senate is currently considering similar legislation that seeks to reduce emission of GHGs in the United States through the granting of emission allowances which would gradually be decreased over time. Moreover, more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of GHGs. Also, on December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has also proposed regulations that would require a reduction in emissions of GHGs from motor vehicles, and this regulatory action, if finalized, could also lead to the imposition of GHG emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22,
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2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. Although the vast majority of our facilities were not subject to the EPA’s GHG reporting rule adopted in September 2009, the EPA has indicated that it is evaluating whether the rule should be applied to oil and gas production activities, perhaps on a field-wide basis. While it is not possible at this time to fully predict how legislation or new regulations that may be adopted in the United States to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas that we produce.
The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.
The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.
Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. Separately, two committees of the House of Representatives, the Financial Services and Agriculture Committees, acted on October 15 and October 21, 2009, respectively, to adopt legislation that would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace. This legislation would subject swap dealers and major swap participants to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants, and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. A major swap participant generally would be someone other than a dealer who maintains a “substantial” position in outstanding swaps other than swaps used for commercial hedging, or whose positions create substantial exposure to its counterparties or the system. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.
Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues.
Legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells particularly in unconventional resource plays. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas and, to a lesser extent, oil production. The proposed legislation, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level. Any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of natural gas and oil, which could adversely affect our revenues and results of operations.
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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, 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:
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amends the definition of proved reserves to require the use of average commodity prices based upon the prior 12-month period rather than year-end prices;
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expands the type of technologies available to establish reserve estimates and categories;
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modifies certain definitions used in estimating proved reserves;
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permits disclosure of probable and possible reserves;
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requires disclosure of internal controls over reserve estimations and the qualifications of technical persons primarily responsible for the preparation or audit of reserve estimates;
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permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts; and
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requires disclosure of material changes in proved undeveloped reserves, including a discussion of investments and progress made to convert proved undeveloped reserves to proved developed reserves.
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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.
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Proved Reserves(a)
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Natural
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Total Oil
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Oil(b)
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Gas
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Equivalents(c)
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Reserve Category
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(MBbls)
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(MMcf)
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(MBOE)
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Developed
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16,779 | 70,840 | 28,586 | |||||||||
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Undeveloped
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4,174 | 5,263 | 5,051 | |||||||||
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Total Proved
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20,953 | 76,103 | 33,637 | |||||||||
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(a)
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None of our oil and gas reserves are derived from non-traditional sources.
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(b)
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Oil reserves include crude oil, condensate and natural gas liquids.
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(c)
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Natural gas reserves have been converted to oil equivalents at the rate of six Mcf of gas to one barrel of oil.
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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.
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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.
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Percent
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Proved Reserves
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PV-10
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of PV-10
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Natural
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Total Oil
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Percent of
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Value of
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Value of
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Oil (a)
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Gas
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Equivalents(b)
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Total Oil
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Proved
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Proved
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(MBbls)
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(MMcf)
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(MBOE)
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Equivalent
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Reserves
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Reserves
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(In thousands)
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Permian Basin
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13,325 | 39,874 | 19,971 | 59.4 | % | $ | 259,180 | 56.3 | % | |||||||||||||||
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Austin Chalk (Trend)
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6,887 | 5,131 | 7,742 | 23.0 | % | 131,408 | 28.5 | % | ||||||||||||||||
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North Louisiana
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291 | 17,205 | 3,159 | 9.4 | % | 37,140 | 8.1 | % | ||||||||||||||||
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South Louisiana
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243 | 5,968 | 1,238 | 3.7 | % | 21,801 | 4.7 | % | ||||||||||||||||
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Cotton Valley Reef Complex
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- | 5,981 | 997 | 3.0 | % | 5,444 | 1.2 | % | ||||||||||||||||
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Other
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207 | 1,944 | 530 | 1.5 | % | 5,417 | 1.2 | % | ||||||||||||||||
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Total
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20,953 | 76,103 | 33,637 | 100.0 | % | $ | 460,390 | 100.0 | % | |||||||||||||||
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(a)
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Oil reserves include crude oil, condensate and natural gas liquids.
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(b)
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Natural gas reserves have been converted to oil equivalents at the rate of six Mcf to one barrel of oil.
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The following table summarizes changes in our estimated proved reserves during 2009.
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Proved
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||||
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Reserves
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(MBOE)
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As of December 31, 2008
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38,098 | |||
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Extensions and discoveries
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3,655 | |||
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Revisions
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(2,353 | ) | ||
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Production
|
(5,763 | ) | ||
|
As of December 31, 2009
|
33,637 | |||
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
27
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.
|
Proved Reserves
|
||||||||||||||||
|
Natural
|
Total Oil
|
|||||||||||||||
|
Oil(a)
|
Gas
|
Equivalents (b)
|
||||||||||||||
|
Pricing Cases
|
(MBbls)
|
(MMcf)
|
(MBOE)
|
PV-10 Value
|
||||||||||||
|
(In thousands)
|
||||||||||||||||
|
SEC Case
|
20,953 | 76,103 | 33,637 | $ | 460,386 | |||||||||||
|
Year-end Pricing Case
|
23,117 | 84,389 | 37,182 | $ | 741,427 | |||||||||||
|
Futures Pricing Case
|
22,040 | 82,019 | 35,710 | $ | 832,292 | |||||||||||
|
(a)
|
Oil reserves include crude oil, condensate and natural gas liquids.
|
|
(b)
|
Natural gas has been converted to oil equivalents at the rate of six Mcf to one barrel of oil.
|
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
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 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.
28
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.
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 technical and operational data necessary to evaluate our reserves and updates the reserves database throughout the year. Technical data includes historical production, pressure measurement data, well logs, geological data, reservoir and fluid characteristics, reservoir size, producing mechanism, and analogous performance considerations. Operational data includes ownership interests, product prices, operating expenses and future development costs.
Generally, oil and gas reserves are estimated using, as appropriate, one of three available methods: production decline curve analysis, analogy to similar properties or volumetric calculations. Where sufficient production history is available, reserves for producing properties are determined using the production decline curve analysis method. If adequate production history is not available, as in the case of a recently-completed well or a nonproducing property, reserves are estimated by analogy to similar properties, if such data is available, or by volumetric calculations. Using the most appropriate method, 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 technical 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.
29
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.
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,
|
||||||||||||||||||||||||
|
2009
|
2008
|
2007
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
(Excludes wells in progress at the end of any period)
|
||||||||||||||||||||||||
|
Development Wells:
|
||||||||||||||||||||||||
|
Oil
|
58 | 49.5 | 70 | 51.5 | 34 | 14.9 | ||||||||||||||||||
|
Gas
|
11 | 5.4 | 41 | 14.7 | 34 | 13.2 | ||||||||||||||||||
|
Dry
|
1 | 1.0 | 1 | 1.0 | - | - | ||||||||||||||||||
|
Total
|
70 | 55.9 | 112 | 67.2 | 68 | 28.1 | ||||||||||||||||||
|
Exploratory Wells:
|
||||||||||||||||||||||||
|
Oil
|
1 | .2 | 1 | .5 | - | - | ||||||||||||||||||
|
Gas
|
1 | .1 | 3 | 1.7 | 12 | 8.0 | ||||||||||||||||||
|
Dry
|
6 | 4.4 | 4 | 3.0 | 7 | 5.8 | ||||||||||||||||||
|
Total
|
8 | 4.7 | 8 | 5.2 | 19 | 13.8 | ||||||||||||||||||
|
Total Wells:
|
||||||||||||||||||||||||
|
Oil
|
59 | 49.7 | 71 | 52.0 | 34 | 14.9 | ||||||||||||||||||
|
Gas
|
12 | 5.5 | 44 | 16.4 | 46 | 21.2 | ||||||||||||||||||
|
Dry
|
7 | 5.4 | 5 | 4.0 | 7 | 5.8 | ||||||||||||||||||
|
Total
|
78 | 60.6 | 120 | 72.4 | 87 | 41.9 | ||||||||||||||||||
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.
30
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.
|
Oil
|
Gas
|
Total
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Permian Basin
|
5,516 | 518.9 | 736 | 96.1 | 6,252 | 615.0 | ||||||||||||||||||
|
Austin Chalk (Trend)
|
313 | 243.7 | 17 | 9.3 | 330 | 253.0 | ||||||||||||||||||
|
North Louisiana
|
- | - | 51 | 16.7 | 51 | 16.7 | ||||||||||||||||||
|
South Louisiana
|
7 | 3.8 | 49 | 23.7 | 56 | 27.5 | ||||||||||||||||||
|
Cotton Valley Reef Complex
|
- | - | 14 | 11.6 | 14 | 11.6 | ||||||||||||||||||
|
Other
|
6 | 5.2 | 41 | 12.2 | 47 | 17.4 | ||||||||||||||||||
|
Total
|
5,842 | 771.6 | 908 | 169.6 | 6,750 | 941.2 | ||||||||||||||||||
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,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Oil and Gas Production Data:
|
||||||||||||
|
Oil (MBbls)
|
2,865 | 2,952 | 2,318 | |||||||||
|
Gas (MMcf)
|
15,949 | 18,553 | 20,649 | |||||||||
|
Natural gas liquids (MBbls)
|
240 | 182 | 222 | |||||||||
|
Total (MBOE)
|
5,763 | 6,226 | 5,982 | |||||||||
|
Average Realized Prices (a):
|
||||||||||||
|
Oil ($/Bbl)
|
$ | 57.37 | $ | 97.35 | $ | 70.36 | ||||||
|
Gas ($/Mcf)
|
$ | 4.35 | $ | 9.02 | $ | 7.01 | ||||||
|
Natural gas liquids ($/Bbl)
|
$ | 30.83 | $ | 54.45 | $ | 43.74 | ||||||
|
Average Production Costs:
|
||||||||||||
|
Production ($/MBOE) (b)
|
$ | 9.82 | $ | 9.83 | $ | 8.53 | ||||||
|
|
(a)
|
Excludes any realized gains or losses on settled derivatives since none were designated as cash flow hedges during the periods presented.
|
|
|
(b)
|
Excludes property taxes and severance taxes.
|
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.
|
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Giddings Field Oil and Gas Production Data:
|
||||||||||||
|
Oil (MBbls)
|
963 | 1,189 | 589 | |||||||||
|
Gas (MMcf)
|
773 | 709 | 621 | |||||||||
|
Natural gas liquids (MBbls)
|
94 | 83 | 87 | |||||||||
|
Total (MBOE)
|
1,186 | 1,390 | 780 | |||||||||
31
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,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Property Acquisitions:
|
||||||||||||
|
Proved
|
$ | - | $ | - | $ | - | ||||||
|
Unproved
|
12,558 | 36,397 | 15,746 | |||||||||
|
Developmental Costs
|
86,672 | 260,073 | 45,611 | |||||||||
|
Exploratory Costs
|
32,758 | 51,237 | 169,879 | |||||||||
|
Total
|
$ | 131,988 | $ | 347,707 | $ | 231,236 | ||||||
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.
|
Developed
|
Undeveloped
|
Total
|
||||||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||||||
|
Permian Basin
|
84,478 | 36,864 | 333,674 | 151,873 | 418,152 | 188,737 | ||||||||||||||||||
|
East Texas (a)
|
133,903 | 122,454 | 186,484 | 116,979 | 320,387 | 239,433 | ||||||||||||||||||
|
North Louisiana
|
5,405 | 4,613 | 160,326 | 149,729 | 165,731 | 154,342 | ||||||||||||||||||
|
South Louisiana
|
7,782 | 5,288 | 17,513 | 16,281 | 25,295 | 21,569 | ||||||||||||||||||
|
Other (b)
|
10,902 | 3,458 | 356,536 | 183,303 | 367,438 | 186,761 | ||||||||||||||||||
|
Total
|
242,470 | 172,677 | 1,054,533 | 618,165 | 1,297,003 | 790,842 | ||||||||||||||||||
|
|
(a)
|
Includes our acreage in the Austin Chalk (Trend), Cotton Valley Reef Complex and East Texas Bossier areas.
|
|
|
(b)
|
Net undeveloped acres are attributable to the following areas: Utah – 53,376; Mississippi – 43,187; Alabama – 38,912; Colorado – 28,798; and other – 19,030.
|
Desta Drilling
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 3 - Legal Proceedings
We are a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.
Item 4 - (Removed and Reserved)
32
PART II
Item 5 - Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities
Price Range of Common Stock
Our Common Stock is quoted on the Nasdaq Stock Market’s Global Market under the symbol “CWEI”. As of March 10, 2010, there were approximately 2,713 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 the Nasdaq Global Market:
|
High
|
Low
|
|||||||
|
Year Ended December 31, 2009:
|
||||||||
|
Fourth Quarter
|
$ | 37.51 | $ | 24.67 | ||||
|
Third Quarter
|
31.84 | 15.66 | ||||||
|
Second Quarter
|
35.27 | 17.80 | ||||||
|
First Quarter
|
52.69 | 19.37 | ||||||
|
Year Ended December 31, 2008:
|
||||||||
|
Fourth Quarter
|
$ | 68.89 | $ | 29.70 | ||||
|
Third Quarter
|
120.00 | 61.89 | ||||||
|
Second Quarter
|
121.50 | 48.86 | ||||||
|
First Quarter
|
53.50 | 30.84 | ||||||
The closing price of our common stock at March 10, 2010 was $39.17 per share.
Dividend Policy
We have never paid any cash dividends on our Common Stock, and our Board of Directors does not currently anticipate paying any cash dividends to our stockholders in the foreseeable future. In addition, the terms of our secured bank credit facilities and the indenture governing our senior notes restrict the payment of cash dividends.
Securities Authorized for Issuance under Equity Compensation Plans
For information concerning shares available for issuance under equity compensation plans, see Item 12, which is to be incorporated by reference to our proxy statement.
33
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, 2009 was derived from our audited financial statements. The data set forth in this table should be read in conjunction with “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the accompanying consolidated financial statements, including the notes thereto.
|
Year Ended December 31,
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
(In thousands, except per share)
|
||||||||||||||||||||
|
Statement of Operations Data:
|
||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Oil and gas sales
|
$ | 242,338 | $ | 463,964 | $ | 316,992 | $ | 245,967 | $ | 252,599 | ||||||||||
|
Natural gas services
|
6,146 | 10,926 | 10,230 | 11,327 | 12,080 | |||||||||||||||
|
Drilling rig services
|
6,681 | 46,124 | 52,649 | 6,937 | - | |||||||||||||||
|
Gain on sales of assets
|
796 | 44,503 | 14,024 | 1,767 | 18,920 | |||||||||||||||
|
Total revenues
|
255,961 | 565,517 | 393,895 | 265,998 | 283,599 | |||||||||||||||
|
Costs and expenses:
|
||||||||||||||||||||
|
Production
|
76,288 | 89,054 | 75,319 | 63,298 | 57,404 | |||||||||||||||
|
Exploration:
|
||||||||||||||||||||
|
Abandonment and impairments
|
78,798 | 80,112 | 68,870 | 65,173 | 39,957 | |||||||||||||||
|
Seismic and other
|
8,189 | 22,685 | 4,765 | 11,299 | 10,780 | |||||||||||||||
|
Natural gas services
|
5,348 | 10,060 | 9,745 | 10,005 | 11,212 | |||||||||||||||
|
Drilling rig services
|
10,848 | 37,789 | 32,964 | 4,538 | - | |||||||||||||||
|
Depreciation, depletion and amortization
|
129,658 | 120,542 | 84,476 | 66,163 | 47,509 | |||||||||||||||
|
Impairment of property and equipment
|
59,140 | 12,882 | 12,137 | 21,848 | 18,266 | |||||||||||||||
|
Accretion of abandonment obligations
|
3,120 | 2,355 | 2,508 | 1,653 | 1,158 | |||||||||||||||
|
General and administrative
|
20,715 | 25,635 | 19,266 | 16,676 | 15,410 | |||||||||||||||
|
Loss on sales of assets and impairment of inventory
|
5,282 | 2,122 | 9,815 | 99 | 209 | |||||||||||||||
|
Other
|
- | - | - | - | 1,353 | |||||||||||||||
|
Total costs and expenses
|
397,386 | 403,236 | 319,865 | 260,752 | 203,258 | |||||||||||||||
|
Operating income (loss)
|
(141,425 | ) | 162,281 | 74,030 | 5,246 | 80,341 | ||||||||||||||
|
Other income (expense):
|
||||||||||||||||||||
|
Interest expense
|
(23,758 | ) | (24,994 | ) | (32,118 | ) | (20,895 | ) | (14,498 | ) | ||||||||||
|
Gain (loss) on derivatives
|
(17,416 | ) | 74,743 | (31,968 | ) | 37,340 | (70,059 | ) | ||||||||||||
|
Other income (expense)
|
2,543 | 6,539 | 5,355 | (1,339 | ) | 4,022 | ||||||||||||||
|
Total other income (expense)
|
(38,631 | ) | 56,288 | (58,731 | ) | 15,106 | (80,535 | ) | ||||||||||||
|
Income (loss) before income taxes
|
(180,056 | ) | 218,569 | 15,299 | 20,352 | (194 | ) | |||||||||||||
|
Income tax (expense) benefit
|
64,096 | (77,327 | ) | (5,497 | ) | (1,979 | ) | 451 | ||||||||||||
|
NET INCOME (LOSS)
|
(115,960 | ) | 141,242 | 9,802 | 18,373 | 257 | ||||||||||||||
|
Less income attributable to noncontrolling
|
||||||||||||||||||||
|
interest, net of tax
|
(1,455 | ) | (708 | ) | (3,812 | ) | (574 | ) | - | |||||||||||
|
NET INCOME (LOSS) attributable to
|
||||||||||||||||||||
|
Clayton Williams Energy, Inc.
|
$ | (117,415 | ) | $ | 140,534 | $ | 5,990 | $ | 17,799 | $ | 257 | |||||||||
|
Net income (loss) per common share attributable
|
||||||||||||||||||||
|
to Clayton Williams Energy, Inc. stockholders:
|
||||||||||||||||||||
|
Basic
|
$ | (9.67 | ) | $ | 11.78 | $ | .53 | $ | 1.64 | $ | .02 | |||||||||
|
Diluted
|
$ | (9.67 | ) | $ | 11.67 | $ | .52 | $ | 1.58 | $ | .02 | |||||||||
|
Weighted average common shares outstanding:
|
||||||||||||||||||||
|
Basic
|
12,138 | 11,932 | 11,337 | 10,885 | 10,804 | |||||||||||||||
|
Diluted
|
12,138 | 12,039 | 11,494 | 11,244 | 11,241 | |||||||||||||||
|
Other Data:
|
||||||||||||||||||||
|
Net cash provided by operating activities
|
$ | 104,711 | $ | 381,980 | $ | 234,866 | $ | 145,990 | $ | 163,475 | ||||||||||
|
December 31,
|
||||||||||||||||||||
| 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||
|
Balance Sheet Data:
|
||||||||||||||||||||
|
Working capital (deficit)
|
$ | 19,324 | $ | 2,607 | $ | (76,388 | ) | $ | (23,068 | ) | $ | (35,812 | ) | |||||||
|
Total assets
|
784,604 | 943,409 | 861,096 | 795,433 | 587,335 | |||||||||||||||
|
Long-term debt
|
395,000 | 347,225 | 430,175 | 413,876 | 235,700 | |||||||||||||||
|
Total equity
|
212,275 | 320,276 | 160,806 | 144,980 | 120,291 | |||||||||||||||
34
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 our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.
We are an independent oil and natural gas exploration, development, acquisition, and production company. Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities, and selling the production from those reserves at a profit. To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment. From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.
Our business in 2009 was adversely affected by the recession that began in 2008 and continues to impact the United States and other global economies. Reduced demand for energy caused oil and gas prices to fall sharply, resulting in a significant deterioration in our operating margins (oil and gas sales less production costs). The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our proved oil and gas reserves. These factors have an adverse effect on our ability to access the capital resources we need to grow our reserve base. Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business. As a result, we suspended our developmental drilling program in the Permian Basin and the Austin Chalk (Trend) in late 2008 and turned our business focus toward preserving short-term liquidity and conserving capital resources.
By the end of the second quarter of 2009, operating margins on oil-prone properties had begun to improve somewhat due to a combination of higher oil prices and lower costs of field services caused by decreased demand for those services. Since most of our developmental drilling locations are oil-prone, we elected to resume drilling developmental oil wells primarily in Andrews County, Texas in the Permian Basin and Burleson and Robertson Counties, Texas in the Austin Chalk (Trend). In connection with the return to drilling activities in these areas, we have taken the following actions which we believe will enhance the development of these core areas:
|
·
|
Entered into 2-year agreements with selected service providers to fix unit costs covering approximately 90% of the drilling and completion services provided by third parties;
|
|
·
|
Improved drilling efficiencies by acquiring the noncontrolling interest in Desta Drilling, giving us full control over the management and operation of drilling services;
|
|
·
|
Purchased casing and tubing for more than 175 wells at discounts to current market prices; and
|
|
·
|
Entered into derivative contracts for most of our estimated proved developed oil production for 2010 and 2011 at average prices of $76.50 and $84.38 per barrel, respectively.
|
Key Factors to Consider
The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2009 and the outlook for 2010.
|
·
|
Our oil and gas sales decreased $221.6 million, or 48%, from 2008, comprised of $195.4 million in price variances and $26.2 million in volume variances.
|
|
·
|
During 2009, we increased borrowings under our revolving credit facility by $75.9 million from $94.1 million at December 31, 2008 to $170 million at December 31, 2009. In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under the revolving credit facility (see Liquidity and Capital Resources).
|
35
|
·
|
We spent $138.3 million on exploration and development activities during fiscal 2009, of which approximately 40% was on exploratory prospects. We currently plan to spend approximately $274.4 million on exploration and development for fiscal 2010, with approximately 97% applied to developmental activities.
|
|
·
|
Exploration costs were $87 million for 2009, of which approximately $42.7 million related to unsuccessful exploratory well costs, $36.1 million related to impairment of unproved acreage and the remaining $8.2 million was spent on seismic related activities. Most of the abandonment and impairment costs in 2009 related to prospects in East Texas Bossier area, South Louisiana and Utah.
|
|
·
|
We recorded a non-cash charge during 2009 of $59.1 million for impairments of property and equipment which included $32.1 million for impairments of certain drilling rigs held for sale and $27 million for impairments of proved oil and gas properties to reduce the carrying values to their estimated fair value based on applicable accounting standards.
|
|
·
|
At December 31, 2009, our capitalized unproved oil and gas properties totaled $47.2 million, of which approximately $19.7 million was attributable to unproved acreage. Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value. Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.
|
|
·
|
We recorded a $17.4 million net loss on derivatives in fiscal 2009, consisting of a $15.9 million realized loss on settled contracts and a $1.5 million loss for changes in mark-to-market valuations. 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.
|
|
·
|
Our estimated proved oil and gas reserves at December 31, 2009 were 33,637 MBOE compared to 38,098 MBOE at December 31, 2008. In 2009, we added 3,655 MBOE through extensions and discoveries, had downward net revisions of 2,353 MBOE (see Item 2 – Properties – Reserves).
|
Proved Oil and Gas Reserves
In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the FASB adopted conforming changes to 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:
|
·
|
amends the definition of proved reserves to require the use of average commodity prices based upon the prior 12-month period rather than year-end prices;
|
|
·
|
expands the type of technologies available to establish reserve estimates and categories;
|
|
·
|
modifies certain definitions used in estimating proved reserves;
|
|
·
|
permits disclosure of probable and possible reserves;
|
|
·
|
requires disclosure of internal controls over reserve estimations and the qualifications of technical persons primarily responsible for the preparation or audit of reserve estimates;
|
|
·
|
permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts; and
|
|
·
|
requires disclosure of material changes in proved undeveloped reserves, including a discussion of investments and progress made to convert proved undeveloped reserves to proved developed reserves.
|
36
The following table summarizes changes in our estimated proved reserves during 2009.
|
Proved
|
||||
|
Reserves
|
||||
|
(MBOE)
|
||||
|
As of December 31, 2008
|
38,098 | |||
|
Extensions and discoveries
|
3,655 | |||
|
Revisions
|
(2,353 | ) | ||
|
Production
|
(5,763 | ) | ||
|
As of December 31, 2009
|
33,637 | |||
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 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 $15 million. Net downward revisions to proved undeveloped reserves of 178 MBOE resulted primarily from the loss of one drilling location due to expiration of drilling rights, offset in part by upward revisions in estimates due to price increases. We did not convert any proved undeveloped reserves at December 31, 2008 to proved developed reserves during 2009.
37
Supplemental Information
The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-K with data that is not readily available from those statements.
|
As of or for the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Oil and Gas Production Data:
|
||||||||||||
|
Oil (MBbls)
|
2,865 | 2,952 | 2,318 | |||||||||
|
Gas (MMcf)
|
15,949 | 18,553 | 20,649 | |||||||||
|
Natural gas liquids (MBbls)
|
240 | 182 | 222 | |||||||||
|
Total (MBOE)
|
5,763 | 6,226 | 5,982 | |||||||||
|
Average Realized Prices(a):
|
||||||||||||
|
Oil ($/Bbl)
|
$ | 57.37 | $ | 97.35 | $ | 70.36 | ||||||
|
Gas ($/Mcf)
|
$ | 4.35 | $ | 9.02 | $ | 7.01 | ||||||
|
Natural gas liquids ($/Bbl)
|
$ | 30.83 | $ | 54.45 | $ | 43.74 | ||||||
|
Gain (Loss) on Settled Derivative
|
||||||||||||
|
Contracts(a):
|
||||||||||||
|
Oil: Net realized gain (loss)
|
$ | (25,713 | ) | $ | 15,560 | $ | (20,086 | ) | ||||
|
Per unit produced ($/Bbl)
|
$ | (8.97 | ) | $ | 5.27 | $ | (8.67 | ) | ||||
|
Gas: Net realized gain
|
$ | 9,777 | $ | 11,764 | $ | 12,229 | ||||||
|
Per unit produced ($/Mcf)
|
$ | .61 | $ | .63 | $ | .59 | ||||||
|
Average Daily Production:
|
||||||||||||
|
Oil (Bbls):
|
||||||||||||
|
Permian Basin
|
4,142 | 3,821 | 3,212 | |||||||||
|
Austin Chalk (Trend)
|
2,734 | 3,384 | 1,737 | |||||||||
|
North Louisiana
|
238 | 415 | 182 | |||||||||
|
South Louisiana
|
649 | 378 | 1,139 | |||||||||
|
Other
|
86 | 90 | 81 | |||||||||
|
Total
|
7,849 | 8,088 | 6,351 | |||||||||
|
Gas (Mcf):
|
||||||||||||
|
Permian Basin
|
14,739 | 14,326 | 14,649 | |||||||||
|
Austin Chalk (Trend)
|
2,485 | 2,367 | 2,220 | |||||||||
|
North Louisiana
|
11,325 | 17,500 | 8,096 | |||||||||
|
South Louisiana
|
9,851 | 10,402 | 24,025 | |||||||||
|
Cotton Valley Reef Complex
|
3,960 | 5,745 | 7,133 | |||||||||
|
Other
|
1,336 | 490 | 450 | |||||||||
|
Total
|
43,696 | 50,830 | 56,573 | |||||||||
|
Natural Gas Liquids (Bbls):
|
||||||||||||
|
Permian Basin
|
241 | 183 | 198 | |||||||||
|
Austin Chalk (Trend)
|
288 | 250 | 259 | |||||||||
|
North Louisiana
|
22 | 7 | 1 | |||||||||
|
South Louisiana
|
98 | 49 | 141 | |||||||||
|
Other
|
9 | 10 | 9 | |||||||||
|
Total
|
658 | 499 | 608 | |||||||||
|
Total Proved Reserves:
|
||||||||||||
|
Oil and natural gas liquids (MBbls)
|
20,953 | 20,776 | 27,946 | |||||||||
|
Gas (MMcf)
|
76,103 | 103,929 | 123,156 | |||||||||
|
Total (MBOE)
|
33,637 | 38,098 | 48,472 | |||||||||
|
Standardized measure of discounted
|
||||||||||||
|
future net cash flows
|
$ | 364,273 | $ | 405,166 | $ | 925,969 | ||||||
(Continued)
38
|
As of or for the Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Total Proved Reserves by Area:
|
||||||||||||
|
Oil and Natural Gas Liquids (MBbls):
|
||||||||||||
|
Permian Basin
|
13,325 | 13,491 | 17,318 | |||||||||
|
Austin Chalk (Trend)
|
6,887 | 6,280 | 7,530 | |||||||||
|
North Louisiana
|
291 | 285 | 319 | |||||||||
|
South Louisiana
|
243 | 524 | 1,117 | |||||||||
|
Other
|
207 | 196 | 1,662 | |||||||||
|
Total
|
20,953 | 20,776 | 27,946 | |||||||||
|
Gas (MMcf):
|
||||||||||||
|
Permian Basin
|
39,874 | 54,914 | 65,248 | |||||||||
|
Austin Chalk (Trend)
|
5,131 | 4,471 | 5,387 | |||||||||
|
North Louisiana
|
17,205 | 19,750 | 14,046 | |||||||||
|
South Louisiana
|
5,968 | 13,966 | 27,196 | |||||||||
|
Cotton Valley Reef Complex
|
5,981 | 9,281 | 9,157 | |||||||||
|
East Texas Bossier
|
98 | 519 | - | |||||||||
|
Other
|
1,846 | 1,028 | 2,122 | |||||||||
|
Total
|
76,103 | 103,929 | 123,156 | |||||||||
|
Total Oil Equivalent (MBOE):
|
||||||||||||
|
Permian Basin
|
19,971 | 22,643 | 28,193 | |||||||||
|
Austin Chalk (Trend)
|
7,742 | 7,025 | 8,428 | |||||||||
|
North Louisiana
|
3,159 | 3,577 | 2,660 | |||||||||
|
South Louisiana
|
1,238 | 2,852 | 5,650 | |||||||||
|
Cotton Valley Reef Complex
|
997 | 1,547 | 1,526 | |||||||||
|
East Texas Bossier
|
16 | 87 | - | |||||||||
|
Other
|
514 | 367 | 2,015 | |||||||||
|
Total
|
33,637 | 38,098 | 48,472 | |||||||||
|
Exploration Costs (in thousands):
|
||||||||||||
|
Abandonment and impairment costs:
|
||||||||||||
|
North Louisiana
|
$ | 9,716 | $ | 25,414 | $ | 30,356 | ||||||
|
South Louisiana
|
22,502 | 3,187 | 28,805 | |||||||||
|
Permian Basin
|
3,484 | 717 | 1,322 | |||||||||
|
East Texas Bossier
|
30,200 | 40,544 | 2,640 | |||||||||
|
Utah
|
11,111 | 6,331 | 4,062 | |||||||||
|
Mississippi
|
515 | 1,270 | 1,148 | |||||||||
|
Other
|
1,270 | 2,649 | 537 | |||||||||
|
Total
|
78,798 | 80,112 | 68,870 | |||||||||
|
Seismic and other
|
8,189 | 22,685 | 4,765 | |||||||||
|
Total exploration costs
|
$ | 86,987 | $ | 102,797 | $ | 73,635 | ||||||
|
Oil and Gas Costs ($/BOE Produced):
|
||||||||||||
|
Production(c)
|
$ | 13.24 | $ | 14.30 | $ | 12.59 | ||||||
|
DD&A
|
$ | 21.94 | $ | 17.83 | $ | 12.70 | ||||||
|
Net Wells Drilled(b):
|
||||||||||||
|
Exploratory wells
|
4.7 | 5.2 | 13.8 | |||||||||
|
Developmental wells
|
55.9 | 67.2 | 28.1 | |||||||||
|
(a) No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in gain (loss) on derivatives.
|
||||||||||||
|
(b) Excludes wells being drilled or completed at the end of each period.
|
||||||||||||
|
(c) Includes property and severance taxes.
|
||||||||||||
39
Operating Results
2009 Compared to 2008
The following discussion compares our results for the year ended December 31, 2009 to the year ended December 31, 2008. Unless otherwise indicated, references to 2009 and 2008 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales in 2009 decreased $221.6 million, or 48%, from 2008. Price variances accounted for a $195.4 million decrease, and production variances accounted for a $26.2 million decrease. In 2009, our realized oil price was 41% lower than 2008 while our realized gas price was 52% lower than 2008. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Production in 2009 (on a BOE basis) was 7% lower than 2008. Oil production decreased 3% and gas production decreased 14% in 2009 from 2008.
Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, decreased 14% in 2009 as compared to 2008. Some of the key components for the reduction in costs include lower production taxes caused by decreases in commodity prices, lower oilfield service costs and decreases in our overall activity level. After giving effect to a 7% decrease in oil and gas production on a BOE basis, production costs per BOE decreased 7% from $14.30 per BOE in 2008 to $13.24 per BOE in 2009.
Oil and gas depletion expense increased $15.5 million from 2008 to 2009, of which rate variances accounted for a $23.7 million increase and production variances accounted for an $8.2 million decrease. On a BOE basis, depletion expense increased 23% from $17.83 per BOE in 2008 to $21.94 per BOE in 2009 due to a combination of higher depletable cost basis and higher depletion rates caused by lower estimated reserves. 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 $59.1 million during 2009, of which $32.1 million related to impairment of certain drilling rigs and related equipment of Desta Drilling to reduce the carrying value of the equipment to its estimated fair value, and the remaining $27 million related to a provision for impairment of proved properties relating primarily to South Louisiana.
Exploration costs
Since we follow the successful efforts method of accounting, 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 2009, we charged to expense $87 million of exploration costs, as compared to $102.8 million in 2008.
At December 31, 2009, our capitalized unproved oil and gas properties totaled $47.2 million, of which approximately $19.7 million was attributable to unproved acreage. Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value. Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.
We plan to spend approximately $274.4 million on exploration and development activities in 2010, of which approximately 97% is expected to be allocated to exploration activities, most of which are in oil-prone areas.
Contract Drilling Services
In 2006, CWEI formed a joint venture with Lariat Services, Inc. (“Lariat”) to construct, own, and operate 12 new drilling rigs. Until April 15, 2009, CWEI owned a 50% equity interest in this joint venture that we have historically referred to as Larclay JV and which we now refer to as Desta Drilling. Effective April 15, 2009, CWEI acquired the remaining 50% equity interest in Desta Drilling. As primary beneficiary of Desta Drilling’s expected cash flows, prior to April 15, 2009, we fully consolidated the accounts of Desta Drilling in our financial statements and accounted for the equity interest owned by Lariat as a noncontrolling interest.
40
We utilize drilling rigs owned by Desta Drilling to drill wells in our exploration and development activities. All intercompany transactions are eliminated in consolidation to the extent of our equity ownership in Desta Drilling. Accordingly, consolidated drilling services revenues and drilling services costs may vary significantly based on our equity ownership and the percentage of revenues derived from CWEI. Since April 2009, Desta Drilling has worked exclusively for CWEI. As a result, all drilling services revenues received by Desta Drilling subsequent to April 2009, along with the related drilling services costs, have been eliminated in our consolidated statements of operations.
In April 2009, we adopted a plan of disposition to sell eight of the 12 drilling rigs owned by Desta Drilling. As a result, we recorded a $32.1 million impairment of property and equipment during the second quarter of 2009 to write-down the rigs to their estimated fair value of $18.8 million. In December 2009, we modified the plan of disposition to move six of the previous eight rigs back into operations. The decision to keep these six drilling rigs was based on an increased requirement for drilling rigs in our developmental drilling program. As a result, we have recorded $7.4 million for the remaining two designated rigs as “Assets Held for Sale” in the accompanying consolidated balance sheet.
General and Administrative
General and administrative (“G&A”) expenses decreased 19% from $25.6 million in 2008 to $20.7 million in 2009. Excluding employee compensation related to non-equity incentive plans, G&A expenses decreased from $19.8 million in 2008 to $17.9 million in 2009 due primarily to a one-time charge in 2008 for cash bonuses paid to employees relating to the sale of certain properties in South Louisiana. Employee compensation expense related to non-equity incentive plans was $2.8 million in 2009 compared to $5.8 million in 2008.
Interest expense
Interest expense decreased 5% from $25 million in 2008 to $23.8 million in 2009 due to a combination of reduced consolidated debt levels and lower interest rates. Lower interest rates during 2009 were a major component of the decrease in interest expense from 2008. The average interest rate for 2009 was 2.6% compared to 4.5% in 2008. The average daily principal balance outstanding under our revolving credit facility for 2009 was $135.2 million compared to $128.5 million for 2008. In addition, capitalized interest for 2009 was $698,000 compared to $3.8 million in 2008, and interest expense associated with Desta Drilling’s term loan during 2009 was $1.5 million compared to $3.4 million in 2008.
Gain/loss on derivatives
We did not designate any derivative contracts in 2009 or 2008 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the year ended December 31, 2009, we reported a $17.4 million net loss on derivatives, consisting of a $15.9 million realized loss on settled contracts and a $1.5 million non-cash loss to mark our derivative positions to their fair value at December 31, 2009. For the year ended December 31, 2008, we reported a $74.7 million net gain on derivatives, consisting of a $25 million realized gain on settled contracts and a $49.7 million non-cash gain to mark our derivative positions to their fair value at December 31, 2008. 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 loss of $4.5 million on sales of assets and impairment of inventory for 2009 related primarily to the impairment of inventory to its estimated market value at December 31, 2009. In 2008, we recorded a net gain on sales of assets and impairment of inventory of $42.4 million, which included a $33.1 million gain on sales of properties in South Louisiana, a $3 million gain on the sale of a North Louisiana prospect, and a $5.7 million gain on the sales of two drilling rigs and a surplus well servicing unit.
Income tax expense (benefit)
Our effective income tax rate in 2009 of 35.6% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and tax benefits derived from statutory depletion deductions, offset by the effects of certain non-deductible expenses.
41
2008 Compared to 2007
The following discussion compares our results for the year ended December 31, 2008 to the year ended December 31, 2007. Unless otherwise indicated, references to 2008 and 2007 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales in 2008 increased $147 million, or 46%, from 2007. Price variances accounted for $118.7 million of this increase and production volume variances accounted for the remaining $28.3 million of incremental sales. Production in 2008 (on a BOE basis) was 4% higher than 2007. Oil production increased 27% and gas production decreased 10% in 2008 from 2007. The comparability of production between 2007 and 2008 was affected by two primary factors. Certain South Louisiana properties were sold during the second quarter of 2008 and South Louisiana production in 2008 was curtailed due to Hurricanes Gustav and Ike. In 2008, our realized oil price was 38% higher than 2007, while our realized gas price was 29% higher.
Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 18% in 2008 as compared to 2007. Some of the key components giving rise to the higher costs included increases in oilfield service costs, higher repair and maintenance costs and increased production tax costs related to higher product prices. After giving effect to a 4% increase in oil and gas production on a BOE basis, production costs per BOE increased 13% from $12.59 per BOE in 2007 to $14.30 per BOE in 2008.
Oil and gas depletion expense increased $35 million from 2007 to 2008, of which rate variances accounted for a $31.9 million increase and production variances accounted for a $3.1 million increase. On a BOE basis, depletion expense increased 40% from $12.70 per BOE in 2007 to $17.83 per BOE in 2008 due to a combination of higher depletable costs and lower estimated reserve quantities in 2008 compared to the 2007 period. 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 recorded a provision for impairment of property and equipment of $12.9 million during 2008, including $11.3 million related to the Margarita #1 well in our East Texas Bossier area. We recorded a provision for impairment of property and equipment of $12.1 million during 2007, of which $7.1 million related to write-downs of two 2,000 horsepower drilling rigs and related components, $1.1 million related to well service equipment, and $3.9 million related to producing properties in the Permian Basin.
Exploration costs
Since we follow the successful efforts method of accounting, 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 2008, we charged to expense $102.8 million of exploration costs, as compared to $73.6 million in 2007.
At December 31, 2008, our capitalized unproved oil and gas properties totaled $90.8 million, of which approximately $52.5 million was attributable to unproved acreage. Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value. Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.
42
Contract Drilling Services
During 2008, we included contract drilling revenues of $50.8 million, other operating expenses of $37.8 million, depreciation expense of $8.6 million and interest expense of $3.9 million in our statement of operations (see Note 10 to the consolidated financial statements). Since the Desta drilling rigs were partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.
General and Administrative
G&A expenses increased 33% from $19.3 million in 2007 to $25.6 million in 2008. Excluding non-cash employee compensation, G&A expenses increased from $17.4 million in 2007 to $19.8 million in 2008 due in part to cash bonuses paid to employees in connection with our sale of properties in South Louisiana and higher personnel costs. In 2008, we recorded a $5.7 million non-cash compensation charge related to our after payout incentive plan and $92,000 for stock-based compensation to directors. In 2007, we recorded a $1.8 million non-cash compensation charge related to our after payout incentive plan and $110,000 for stock-based compensation to directors.
Interest expense
Interest expense decreased 22% from $32.1 million in 2007 to $25 million in 2008 due to a combination of reduced debt levels and lower interest rates. The average daily principal balance outstanding under our revolving credit facility for 2008 was $128.5 million compared to $176.5 million for 2007. Debt reductions on our revolving credit facility accounted for $3.5 million of the decrease in interest expense, while lower interest rates resulted in a decrease of approximately $3.3 million. In addition, capitalized interest for 2008 was $3.8 million compared to $4.2 million in 2007, and interest expense associated with Desta Drilling during 2008 was $3.4 million compared to $4.3 million in 2007.
Gain/loss on derivatives
We did not designate any derivative contracts in 2008 or 2007 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For 2008, we reported a $74.7 million net gain on derivatives, consisting of a $49.7 million non-cash gain to mark our derivative positions to their fair value and a $25 million realized gain on settled contracts. For 2007, we reported a $32 million net loss on derivatives, consisting of an $24.3 million non-cash loss to mark our derivative positions to their fair value at December 31, 2007 and a $7.7 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 on sales of assets and impairment of inventory of $42.4 million for 2008, which included a $33.1 million gain on sales of properties in South Louisiana, a $3 million gain on the sale of a North Louisiana prospect, and a $5.7 million gain on the sales of two drilling rigs and a surplus well servicing unit. In 2007, we recorded a net gain of $4.2 million, which included the sale of all of our producing and non-producing acreage in Pecos County, Texas for $21 million, net of closing costs, and recorded a gain of approximately $12.5 million in connection with this sale, offset by a $9.8 million loss due primarily to the write-down of inventory to its market value.
Income tax expense
Our effective income tax rate in 2008 of 35.4% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from statutory depletion deductions.
43
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 group of banks to secure our revolving credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We borrow funds on the 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 and development programs 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, the effects of product prices on cash flow can be mitigated through the use of commodity derivatives.
Our business in 2009 was adversely affected by the recession that began in 2008 and continues to impact the United States and other global economies. Reduced demand for energy caused oil and gas prices to fall sharply, resulting in a significant deterioration in our operating margins (oil and gas sales less production costs). The effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the PV-10 Value of our proved oil and gas reserves. These factors have an adverse affect on our ability to access the capital resources we need to grow our reserve base. Lower cash flow from operations can limit our ability to incur indebtedness under the Indenture discussed below, and downward revisions in the PV-10 Value of our estimated proved reserves can adversely affect the amount of funds we can borrow on the credit facility. Lower operating margins also offer us less incentive to assume the drilling risks that are inherent in our business.
The Indenture governing the issuance of our 7¾% Senior Notes due 2013 contains covenants that restrict our ability to incur indebtedness. One covenant establishes a minimum ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture). If we are restricted from incurring indebtedness under this covenant, we may still borrow funds under the revolving credit facility provided that our outstanding balance on the facility does not exceed the greater of $150 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). Based on our PV-10 Value at December 31, 2009, this alternative to the EBITDAX coverage test would not be available since our outstanding borrowings under the revolving credit facility currently exceed the maximum permitted. We currently have, and expect to have in 2010, sufficient EBITDAX coverage under the Indenture to permit us to borrow funds as needed in 2010 to fund our exploration and development activities.
Capital expenditures
The following table summarizes, by area, our planned expenditures for exploration and development activities during 2010, as compared to our actual expenditures in 2009.
|
Actual
|
Planned
|
|||||||||||
|
Expenditures
|
Expenditures
|
2010
|
||||||||||
|
Year Ended
|
Year Ended
|
Percentage
|
||||||||||
|
December 31, 2009
|
December 31, 2010
|
of Total
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Permian Basin
|
$ | 63,700 | $ | 210,500 | 77 | % | ||||||
|
Austin Chalk (Trend)
|
13,800 | 49,800 | 18 | % | ||||||||
|
South Louisiana
|
28,800 | 8,800 | 3 | % | ||||||||
|
California
|
3,900 | 2,500 | 1 | % | ||||||||
|
Other(a)
|
28,100 | 2,800 | 1 | % | ||||||||
| $ | 138,300 | $ | 274,400 | 100 | % | |||||||
|
(a) Includes expenditures in 2009 in the following areas (In thousands): East Texas Bossier - $17,000; North Louisiana – $5,300; Utah – $2,400; and Other - $3,400.
|
||||||||||||
Our planned exploration and development activities for 2010 are significantly higher than fiscal 2009 actual expenditures due to additional planned developmental drilling in the Permian Basin and the Austin Chalk (Trend) based on improved operating margins. However, our actual expenditures during fiscal 2010 may vary significantly from these estimates if our plans for exploration and development activities change during the year. Factors, such as changes in operating margins and the availability of capital resources could increase or decrease our ultimate level of expenditures during fiscal 2010.
44
We spent $138.3 million on exploration and development activities during 2009, of which approximately 60% was on developmental drilling. We currently plan to spend approximately $274.4 million for fiscal 2010, of which approximately 97% is estimated to be spent on developmental drilling. We financed these expenditures in 2009 with cash flow from operating activities and advances under the revolving credit facility. Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flow will be sufficient to finance our exploration and development activities through 2010. Although we believe the assumptions and estimates made in our forecasts are reasonable, we are unable to predict the extent and duration of lower operating margins resulting from the current economic depression. Accordingly, cash flow may be less than expected, the availability of funds under the credit facility may be less than expected, or capital expenditures may be more than expected. In the event we lack adequate liquidity to finance our expenditures through fiscal 2010, we will consider options for obtaining alternative capital resources, including selling assets or accessing capital markets. Because of significant uncertainties regarding the current economic environment, we can give no assurance that these alternative capital resources can be obtained on terms acceptable to us.
Cash flow provided by operating activities
Substantially all of our cash flow from operating activities is derived from the production of our oil and gas reserves. We use this cash flow to fund our on-going exploration and development activities in search of new oil and gas reserves. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.
Cash flow provided by operating activities for the year ended December 31, 2009 decreased $277.3 million, or 73%, as compared to the corresponding period in 2008 due primarily to a 48% drop in oil and gas sales caused by lower commodity prices.
Credit facility
We have a revolving credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A. We have historically relied on the revolving credit facility for both our short-term liquidity (working capital) and our long-term financial needs. The funds available to us at any time under the revolving credit facility are limited to the amount of the borrowing base determined by the banks. As long as we have sufficient availability under the 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 banks redetermine the borrowing base under the revolving credit facility on a semi-annual basis, in May and November. In addition, we or the banks may request an unscheduled borrowing base redetermination at other times during the year. If at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) pledge additional collateral, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the excess or (3) prepay the excess in six equal monthly installments. In October 2009, the borrowing was affirmed by the banks at $250 million.
The revolving credit facility is collateralized by substantially all of our assets, including at least 80% of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base for the revolving credit facility. The obligations under the revolving credit facility are guaranteed by each of our domestic subsidiaries, excluding WCEP, LLC.
At our election, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2% and 3% per annum or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus .5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.125% and 2.125% per annum. We also pay a commitment fee on the unused portion of the revolving credit facility equal to .5%. Interest and fees are payable quarterly, except that interest on LIBOR-based traunches are due at maturity of each traunche but no less frequently than quarterly. The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2009 was 2.7%.
The revolving credit facility contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain 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, (3) exclude current maturities of loans under the revolving credit
45
facility, if any, and (4) exclude current assets and liabilities attributable to vendor financing transactions, if any.
Working capital computed for loan compliance purposes differs from our working capital in accordance with GAAP. Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives. Our GAAP reported working capital increased from $2.6 million at December 31, 2008 to $19.3 million at December 31, 2009. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $104.4 million at December 31, 2009, as compared to $170.9 million at December 31, 2008. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2009 and December 31, 2008.
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In thousands)
|
||||||||
|
Working capital per GAAP
|
$ | 19,324 | $ | 2,607 | ||||
|
Add funds available under the revolving credit facility
|
79,196 | 155,096 | ||||||
|
Exclude fair value of derivatives classified as current assets or current liabilities
|
5,907 | - | ||||||
|
Exclude current assets and current liabilities of Desta Drilling (a)
|
- | 13,205 | ||||||
|
Working capital per loan covenant
|
$ | 104,427 | $ | 170,908 | ||||
|
(a) In August 2009, we repaid all of the secured term loan of Desta Drilling with borrowings under our secured bank credit facility due May 2012.
|
||||||||
The revolving credit facility provides that the ratio of our consolidated funded indebtedness to consolidated EBITDAX (the “Leverage Ratio”) (determined as of the end of each fiscal quarter for the then most-recently ended four fiscal quarters) may not be greater than (1) 3.5 to 1 for any fiscal quarter ending on or prior to December 31, 2010, (2) 3.25 to 1 for any fiscal quarter ending on or after March 31, 2011 through December 31, 2011 and (3) 3 to 1 for any fiscal quarter thereafter.
We were in compliance with all financial and non-financial covenants at December 31, 2009. However, our increased leverage and reduced liquidity may result in our failing to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend the loan agreement to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.
The lending group under the revolving credit facility includes the following institutions: JPMorgan Chase Bank, N.A., Union Bank of California, N.A., Bank of Scotland, BNP Paribas, Fortis Capital Corp., Compass Bank, Natixis, Bank of Texas, N.A., and Frost Bank.
From time to time, we engage in other transactions with lenders under the revolving credit facility. Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of December 31, 2009, JPMorgan Chase Bank, N.A. was the only counterparty to our commodity derivative agreements. Our obligations under existing derivative agreements with our lenders are secured by the security documents executed by the parties under the revolving credit facility.
During 2009, we increased indebtedness outstanding under the revolving credit facility by $75.9 million. At December 31, 2009, we had $170 million of borrowings outstanding under the revolving credit facility, leaving $79.2 million available on the facility after allowing for outstanding letters of credit totaling $804,000. The revolving credit facility matures in May 2012.
46
7¾% Senior Notes due 2013
In July 2005, we issued, in a private placement, $225 million of aggregate principal amount of Senior Notes. The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.
We may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on August 1, 2009, 101.938% for the twelve-month period beginning on August 1, 2010, and 100% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.
The Indenture governing the Senior Notes contains covenants that restrict the ability of us and our subsidiaries to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 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) exceeds 2.5 to 1 for the four most recently completed fiscal quarters. However, this restriction does not prevent us from borrowing funds under the revolving credit facility provided that our outstanding balance on the facility does not exceed the greater of $150 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined 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, 2009.
Desta Drilling Term Loan
In 2006, Desta Drilling (formerly Larclay JV) obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs. In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under our revolving credit facility. All of the assets of Desta Drilling were pledged as collateral under our revolving credit facility.
Alternative capital resources
Although our base of oil and gas reserves, as collateral for our revolving credit facility, has historically been our primary capital resource, we have in the past, and we believe we could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or public or private issuances of common stock. We could also issue senior or subordinated debt or preferred stock in a public or a private placement if we choose to raise capital through either of these markets. While we believe we would be able to obtain funds through one or more of these alternatives, 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, 2009 by payment due date.
|
Payments Due by Period
|
||||||||||||||||
|
Total
|
2010
|
2011
to
2012
|
2013
to
2014
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Contractual obligations:
|
||||||||||||||||
|
7¾% Senior Notes (a)
|
$ | 225,000 | $ | - | $ | - | $ | 225,000 | ||||||||
|
Secured bank credit facility(a)
|
170,000 | - | 170,000 | - | ||||||||||||
|
Lease obligations
|
3,530 | 1,771 | 1,735 | 24 | ||||||||||||
|
Other
|
170 | 85 | 85 | - | ||||||||||||
|
Total contractual obligations
|
$ | 398,700 | $ | 1,856 | $ | 171,820 | $ | 225,024 | ||||||||
|
|
(a)
|
In addition to the principal payments presented, we expect to make annual interest payments of $17.4 million on the Senior Notes and approximately $4.7 million on the secured bank credit facility (based on the balances and interest rates at December 31, 2009).
|
47
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 $52.99 per BOE in 2007, to $74.52 per BOE in 2008 and to $42.05 per BOE in 2009. However, our expenses per BOE have been on an upward trend and are resulting in narrowing operating margins. Our oil and gas DD&A per BOE has increased from $12.70 per BOE in 2007, to $17.83 per BOE in 2008 and to $21.94 per BOE in 2009. 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 the reserves we are adding. Although we replaced 63% of our production in 2009, our cost to find those reserves was significantly higher than our historical combined rate. Also affecting our operating margins is the cost of producing our reserves. Our production costs per BOE have fluctuated from $12.59 per BOE in 2007, to $14.30 per BOE in 2008, to $13.24 per BOE in 2009. The decrease in operating costs per BOE in 2009 was due primarily to lower costs of field services and decreased production taxes resulting from lower commodity prices.
During the last half of 2009, operating margins, particularly on oil-prone properties, began to improve due to higher oil prices and lower costs of field services. In recent months, our costs to drill and equip wells in the Permian Basin and Austin Chalk (Trend) areas have been significantly lower than the costs we incurred to drill similar wells in 2008 as a result of lower service and equipment costs and improved drilling efficiencies obtained through Desta Drilling. Lower drilling and completion costs should improve our operating margins for 2010 as compared to 2009. However, any ultimate improvement in our operating margins will be dependent on the quantities of proved reserves and production added through our 2010 drilling program.
Oil and Gas Production
As with all companies engaged in oil and gas exploration and production, we face the challenge of natural production decline since 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. Prior to 2008 our production had been on a gradual decline since 2003 due to the effects of natural production decline, offset in part by reserve additions through exploration and development and acquisitions. Although we increased our production by 4% in 2008 over 2007 levels, our production in 2009 decreased 7% to 5.8 MMBOE from 6.2 MMBOE in 2008, and we replaced only 63% of our 2009 oil and gas production through extensions and discoveries. While these 2009 reserve additions will contribute favorably to our production in 2010, 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. To grow our production in 2010, we will need to add production from wells drilled in 2010 through our developmental drilling program.
As discussed above, operating margins began to improve during the last half of 2009. As a result, we currently plan to increase capital spending during fiscal 2010 to $274.4 million compared to $138.3 million in fiscal 2009. Higher spending levels, if successful, should positively impact our ability to replace 2010 production with new 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 flow.
Application of Critical Accounting Policies and Estimates
Summary
In this section, we will identify the critical accounting policies we follow in preparing our 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 financial statements under different conditions or using different assumptions.
48
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
|
· Reserve estimates
|
· Oil and gas properties
|
||
|
for oil and gas properties
|
· Valuation of unproved
|
· Accumulated DD&A
|
||
|
properties
|
· Provision for DD&A
|
|||
|
· Judgment regarding status of
in progress exploratory wells
|
· Impairment of unproved
properties
|
|||
|
· Abandonment costs
|
||||
|
(dry hole costs)
|
||||
|
Impairment of proved
|
· Reserve estimates and related
|
· Oil and gas properties
|
||
|
properties and long-
|
present value of future net
|
· Contract drilling equipment
|
||
|
lived assets
|
revenues (proved properties)
|
· Accumulated DD&A
|
||
|
· Estimates of future undiscounted
|
· Impairment of proved properties
|
|||
|
cash flows (long-lived assets)
|
and long-lived assets
|
|||
|
Asset retirement obligations
|
· Estimates of the present value
|
· Abandonment obligations
|
||
|
of future abandonment costs
|
(non-current liability)
|
|||
|
· Oil and gas properties
|
||||
|
· Accretion of discount
|
||||
|
expense
|
||||
|
Inventory stated at average cost
|
· Estimates of market value of
|
· Impairment of inventory
|
||
|
or estimated market value
|
tubular goods and other well
|
|||
|
equipment
|
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 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 Accuracy
|
||
|
Proved undeveloped
|
Data from offsetting wells, seismic data
|
Least accurate
|
||
|
Proved developed non-producing
|
Logs, core samples, well tests, pressure data
|
More accurate
|
||
|
Proved developed producing
|
Production history, pressure data over time
|
Most accurate
|
Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable reserves exceed the projected revenues from the reserves). But more significantly, the standardized measure of discounted future net cash flows is extremely sensitive to prices and costs, and may vary materially based on different assumptions. Current SEC financial accounting and reporting standards require that 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.
49
|
Standardized
|
||||||||||||||||||||
|
Measure
|
||||||||||||||||||||
|
Proved Reserves
|
Average Price
|
of Discounted
|
||||||||||||||||||
|
Oil(a)
|
Gas
|
Oil (a)
|
Gas
|
Future
|
||||||||||||||||
|
(MMBbls)
|
(Bcf)
|
($/Bbl)
|
($/Mcf)
|
Net Cash Flows
|
||||||||||||||||
|
(In millions)
|
||||||||||||||||||||
|
As of December 31:
|
||||||||||||||||||||
|
2009
|
21.0 | 76.1 | $ | 54.81 | $ | 3.71 | $ | 364.3 | ||||||||||||
|
2008
|
20.8 | 103.9 | $ | 42.03 | $ | 5.90 | $ | 405.2 | ||||||||||||
|
2007
|
27.9 | 123.2 | $ | 91.30 | $ | 7.37 | $ | 926.0 | ||||||||||||
(a) Includes crude oil, condensate and natural gas liquids.
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;
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|
·
|
The nature and extent of geological and geophysical data on the prospect;
|
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·
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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;
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·
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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
|
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·
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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
Generally accepted accounting principles do 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 information. 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 information or assumptions. In this section, we will discuss the effects of different estimates on our financial statements.
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):
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·
|
DD&A Rate = Unamortized Cost ¸ Beginning of Period Reserves
|
|
·
|
Provision for DD&A = DD&A Rate ´ Current Period Production
|
50
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 statement of operations. 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 applicable accounting standards, 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 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 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 obligation is 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 statement of operations. During 2009, we had an upward revision of our estimated asset retirement obligations by $2.2 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 depreciation, depletion and amortization 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.
Adopted Accounting Pronouncements
Effective July 1, 2009, we adopted SFAS No. 168, “The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS 168”) superseded by topic 105-10-5 of the FASB Accounting Standards Codification (“ASC”). SFAS 168 establishes the ASC as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with GAAP. Other than the manner in which new accounting guidance is referenced, the adoption did not have a material impact on our financial statements.
51
Effective January 1, 2009, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (“SFAS 160”) (superseded by ASC topic 810-10-65). Noncontrolling interests (previously referred to as minority interests) are ownership interests in a consolidated subsidiary held by parties other than the parent. SFAS 160 requires that noncontrolling interests be clearly identified and reported as a component of equity in the parent’s balance sheet. SFAS 160 also requires that the amount of net income or loss attributable to the parent and the noncontrolling interest be presented separately on the face of the consolidated statement of operations. The presentations of noncontrolling interest in our consolidated financial statements, as required by SFAS 160, have been applied retrospectively to prior periods.
Effective January 1, 2009, we adopted SFAS Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”) (superseded by ASC topic 815-10-65). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (“SFAS 133”) (superseded by ASC topic 815-10) as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. The adoption of SFAS 161 did not have a material effect on our financial statements, other than disclosures.
Effective January 1, 2009, we adopted SFAS No. 141R, “Business Combinations” (“SFAS 141R”) (superseded by ASC topic 805-10). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. The adoption of SFAS 141R did not have a material impact on our financial statements.
Effective January 1, 2009, we adopted SFAS No. 157, “Fair Value Measurements (as amended)” (“SFAS 157”) (superseded by ASC topic 820-10), for nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis (see Note 8). SFAS 157 defines fair value, establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measures. We had previously adopted SFAS 157 for financial assets and liabilities that are measured at fair value and for nonfinancial assets and liabilities that are measured at fair value on a recurring basis.
Effective April 1, 2009, we adopted SFAS No. 165, “Subsequent Events” (“SFAS 165”) (superseded by ASC topic 855-10-5), which establishes principles and requirements for disclosure of subsequent events. It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential disclosure. It also establishes the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date. The adoption of SFAS 165 did not have a material impact on our disclosure of subsequent events.
In December 2008, the SEC released Final Rule, “Modernization of Oil and Gas Reporting”. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor, (2) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (3) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. In January 2010, the FASB issued new accounting guidance to align the reserve estimation and disclosure requirements within generally accepted accounting principles with the Final Rule. All of these rule changes became effective December 31, 2009. We have adopted these changes and conformed our reserve estimation and disclosure practices in accordance with the guidance contained in the releases.
Recent Accounting Pronouncements
In June 2009, the FASB issued accounting guidance on the consolidation of variable interest entities (“VIEs”). This new guidance revises previous guidance by replacing the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a VIE with a qualitative approach focused on identifying which enterprise has both the power to direct the activities of the VIE that most significantly impacts the entity’s economic performance and has the obligation to absorb losses or the right to
52
receive benefits that could be significant to the entity. In addition, this guidance requires reconsideration of whether an entity is a VIE when any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impact the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and additional disclosures about an enterprise’s involvement in variable interest entities. This guidance is effective for fiscal years beginning after November 15, 2009. Accordingly, we will adopt the provisions of the new guidance in the first quarter of 2010. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
Item 7A - Quantitative and Qualitative Disclosure About Market Risks
Our business is impacted by fluctuations in commodity prices and interest rates. The following discussion is intended to identify the nature of these market risks, describe our strategy for managing such risks, and to quantify the potential affect 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 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 prices with any degree of certainty. Sustained weakness in oil and gas 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 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 prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2009 reserve estimates, we project that a $1 decline in the price per Bbl of oil and a $.50 decline in the price per Mcf of gas from year end 2009 would reduce our gross revenues for the year ending December 31, 2010 by $8.6 million.
From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production. 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. We do not enter into commodity derivatives for trading purposes. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.
The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements. We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge. If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received. If we terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.
53
The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2009. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Swaps:
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Oil
|
Gas
|
|||||||||||||||
|
Bbls
|
Price
|
MMBtu (a)
|
Price
|
|||||||||||||
|
Production Period:
|
||||||||||||||||
|
1st Quarter 2010
|
628,000 | $ | 76.70 | 2,280,000 | $ | 6.80 | ||||||||||
|
2nd Quarter 2010
|
574,000 | $ | 76.60 | 1,830,000 | $ | 6.80 | ||||||||||
|
3rd Quarter 2010
|
522,000 | $ | 76.40 | 1,750,000 | $ | 6.80 | ||||||||||
|
4th Quarter 2010
|
480,000 | $ | 76.24 | 1,680,000 | $ | 6.80 | ||||||||||
|
2011
|
1,656,000 | $ | 84.38 | 6,420,000 | $ | 7.07 | ||||||||||
| 3,860,000 | 13,960,000 | |||||||||||||||
|
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.
|
||||||||||||||||
In March 2009, we terminated certain fixed-priced oil swaps covering 332,000 barrels at a price of $57.35 from January 2010 through December 2010, resulting in an aggregate loss of approximately $1.3 million, which will be paid to the counterparty monthly as the applicable contracts are settled.
Interest Rates
We are exposed to interest rate risk on our long-term debt with a variable interest rate. At December 31, 2009, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $198 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 $6 million. Based on our outstanding variable rate indebtedness at December 31, 2009 of $170 million, a change in interest rates of 100 basis points would affect annual interest payments by $1.7 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 included elsewhere in this Form 10-K.
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, our Board of Directors 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. 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:
|
·
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management has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;
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·
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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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·
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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.
|
54
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 financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:
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·
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pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
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·
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provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Board of Directors; and
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·
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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 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.
Changes in Internal Control Over Financial Reporting
No changes in internal control over financial reporting were made during the quarter ended December 31, 2009 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, 2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management has concluded that, as of December 31, 2009, 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, 2009, the contents of which are shown below.
55
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 (Company) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework 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, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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, 2009 and 2008, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2009, and our report dated March 12, 2010 expressed an unqualified opinion on those consolidated financial statements.
Dallas, Texas
March 12, 2010
56
Item 9B- Other Information
None.
PART III
Item 10 - Directors, Executive Officers and Corporate Governance
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2010.
Item 11 - Executive Compensation
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2010.
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2010.
Item 13 - Certain Relationships and Related Transactions, and Director Independence
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2010.
Item 14 - Principal Accounting Fees and Services
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2010.
57
PART IV
Item 15 - Exhibits and 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.
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 “†”:
|
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 July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 22, 2005††
|
||
|
**10.1
|
Amended and Restated Credit Agreement dated as of May 21, 2004 among Clayton Williams Energy, Inc., et al, and Bank One, NA, et al, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed with the Commission on June 23, 2004††
|
||
|
**10.2
|
First Amendment to Amended and Restated Credit Agreement dated July 18, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 20, 2005††
|
||
|
**10.3
|
Second Amendment to Amended and Restated Credit Agreement dated December 30, 2005, filed as Exhibit 10.3 to the Company’s Form 10-K for the period ended December 31, 2005††
|
||
|
**10.4
|
Third Amendment to Amended and Restated Credit Agreement dated June 30, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 14, 2006††
|
||
|
**10.5
|
Fourth Amendment to Amended and Restated Credit Agreement dated July 28, 2006
|
||
58
|
**10.6
|
Fifth Amendment to Amended and Restated Credit Agreement dated June 13, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 18, 2008††
|
||
|
**10.7
|
Sixth Amendment to Amended and Restated Credit Agreement dated April 14, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 17, 2009††
|
||
|
**10.8
|
Seventh Amendment to Amended and Restated Credit Agreement dated May 26, 2009, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 26, 2009††
|
||
|
**10.9†
|
Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316
|
||
|
**10.10†
|
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††
|
||
|
**10.11†
|
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††
|
||
|
**10.12†
|
Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68320
|
||
|
**10.13†
|
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††
|
||
|
**10.14†
|
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††
|
||
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**10.15†
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Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-92834
|
||
|
**10.16†
|
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††
|
||
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**10.17
|
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
|
||
|
**10.18
|
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††
|
||
|
**10.19
|
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
|
||
|
**10.20
|
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††
|
||
|
**10.21
|
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.††
|
59
|
**10.22†
|
Agreement of Limited Partnership of CWEI Longfellow Ranch I, L.P. dated April 1, 2003, filed as Exhibit 10.32 to the Company’s Form 10-K for the period ended December 31, 2003††
|
||
|
**10.23†
|
Agreement of Limited Partnership of CWEI South Louisiana II, L.P. effective as of January 1, 2004, filed as Exhibit 10.29 to the Company’s Form 10-K for the period ended December 31, 2004††
|
||
|
**10.24†
|
Agreement of Limited Partnership of Rocky Arroyo, L.P. effective as of January 2, 2005, filed as Exhibit 10.31 to the Company’s Form 10-K for the period ended December 31, 2004††
|
||
|
**10.25†
|
Agreement of Limited Partnership of CWEI West Pyle/McGonagill, L.P. effective as of January 2, 2005, filed as Exhibit 10.33 to the Company’s Form 10-K for the period ended December 31, 2004††
|
||
|
**10.26†
|
Agreement of Limited Partnership of CWEI South Louisiana III, L.P. effective as of March 1, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 14, 2005††
|
||
|
**10.27†
|
Agreement of Limited Partnership of CWEI North Louisiana, L.P. effective as of March 1, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 14, 2005††
|
||
|
**10.28†
|
Agreement of Limited Partnership of Floyd Prospect, L.P. effective as of March 1, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 3, 2005††
|
||
|
**10.29†
|
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††
|
||
|
**10.30†
|
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††
|
||
|
**10.31†
|
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††
|
||
|
**10.32†
|
Agreement of Limited Partnership of Floyd Prospect II, L.P. dated May 15, 2006., filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 17, 2006††
|
||
|
**10.33†
|
Participation Agreement relating to South Louisiana IV dated August 2, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006††
|
||
|
**10.34†
|
Participation Agreement relating to North Louisiana — Hosston/Cotton Valley dated August 2, 2006, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006††
|
||
|
**10.35†
|
Participation Agreement relating to North Louisiana — Bossier dated August 2, 2006, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006††
|
||
|
**10.36†
|
Participation Agreement relating to Floyd Prospect III dated November 15, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006††
|
||
60
|
**10.37†
|
Participation Agreement relating to North Louisiana - Bossier II dated November 15, 2006, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006††
|
||
|
**10.38†
|
Participation Agreement relating to North Louisiana - Hosston/Cotton Valley II dated November 15, 2006, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006††
|
||
|
**10.39†
|
Participation Agreement relating to South Louisiana V dated November 15, 2006, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006††
|
||
|
**10.40†
|
Southwest Royalties 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††
|
||
|
**10.41†
|
Form of Notice of Bonus Award Under the Southwest Royalties 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††
|
||
|
**10.42†
|
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††
|
||
|
**10.43†
|
Participation Agreement relating to RMS/Warnick 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††
|
||
|
**10.44†
|
Participation Agreement relating to East Texas Bossier – Big Bill Simpson dated December 17, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2007††
|
||
|
**10.45†
|
Participation Agreement relating to East Texas Bossier – Margarita dated December 17, 2007, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2007††
|
||
|
**10.46†
|
Amaker 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††
|
||
|
**10.47†
|
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††
|
||
|
**10.48†
|
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††
|
||
|
**10.49†
|
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††
|
||
|
**10.50†
|
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††
|
||
|
**10.51†
|
Participation Agreement relating to CWEI North Louisiana Bossier III dated June 19, 2008, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
|
||
|
**10.52†
|
Participation Agreement relating to CWEI North Louisiana Hosston/Cotton Valley III dated June 19, 2008, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on June 25, 2008††
|
61
|
**10.53†
|
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††
|
||
|
**10.54†
|
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††
|
||
|
**10.55†
|
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††
|
||
|
**10.56†
|
Form of Director Indemnification Agreement
|
||
|
**10.57†
|
Participation Agreement relating to CWEI East Texas Bossier - Sunny dated November 19, 2008, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on November 20, 2008††
|
||
|
**10.58†
|
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††
|
||
|
*21
|
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
|
Report of Williamson Petroleum Consultants, Inc. independent consulting engineers
|
||
|
*99.2
|
Report of Ryder Scott Company, L.P. independent consulting engineers
|
||
|
* 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.
|
|||
62
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. Means a 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.
Bcfe. One billion cubic feet of natural gas equivalents.
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. Refers to depreciation, depletion and amortization of the Company’s property and equipment.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
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. Refers to 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 BOEs.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content.
MMbtu. One million British thermal units. 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.
MMBOE. One million BOEs.
MMcf. One million cubic feet.
63
MMcfe. One million cubic feet of natural gas equivalents.
Natural gas liquids. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.
Net acres or wells. Refers to gross the sum of fractional ownership working interest 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 Securities and Exchange Commission 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. Proved oil and gas reserves are 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 (LKH) 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 (HKO) 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.
64
Proved undeveloped reserves (PUD). Undeveloped oil and gas reserves are 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 projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Probable reserves. Probable reserves are 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 proves 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.
SEC. The United States Securities and Exchange Commission.
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.
65
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 *
|
|
Clayton W. Williams
|
|
|
Chairman of the Board, President
|
|
|
and Chief Executive Officer
|
|
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 *
|
Chairman of the Board,
|
March 12, 2010
|
||
|
Clayton W. Williams
|
President and Chief Executive
|
|||
|
Officer and Director
|
||||
|
/s/ L. PAUL LATHAM
|
Executive Vice President,
|
March 12, 2010
|
||
|
L. Paul Latham
|
Chief Operating Officer and
|
|||
|
Director
|
||||
|
/s/ MEL G. RIGGS
|
Senior Vice President -
|
March 12, 2010
|
||
|
Mel G. Riggs
|
Finance, Secretary, Treasurer,
|
|||
|
Chief Financial Officer and Director
|
||||
|
/s/ MICHAEL L. POLLARD
|
Vice President – Accounting and
|
March 12, 2010
|
||
|
Michael L. Pollard
|
Principal Accounting Officer
|
|||
|
/s/ TED GRAY, JR.*
|
Director
|
March 12, 2010
|
||
|
Ted Gray, Jr.
|
||||
|
/s/ DAVIS L. FORD *
|
Director
|
March 12, 2010
|
||
|
Davis L. Ford
|
||||
|
/s/ ROBERT L. PARKER *
|
Director
|
March 12, 2010
|
||
|
Robert L. Parker
|
||||
|
/s/ JORDAN R. SMITH *
|
Director
|
March 12, 2010
|
||
|
Jordan R. Smith
|
||||
|
* By: /s/ L. PAUL LATHAM
|
||||
|
L. Paul Latham
|
||||
|
Attorney-in-Fact
|
66
CLAYTON WILLIAMS ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULE
|
Page
|
||
|
F-2
|
||
|
F-3
|
||
|
F-5
|
||
|
F-6
|
||
|
F-7
|
||
|
F-8
|
||
|
F-9
|
||
|
S-1
|
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 as of December 31, 2009 and 2008, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2009. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and the financial statement schedule 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, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 2 of the consolidated financial statements, effective January 1, 2008, the Company adopted the authoritative guidance for fair value measurements as it relates to financial instruments.
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, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 12, 2010, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 12, 2010
F-2
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
|
ASSETS
|
||||||||
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
CURRENT ASSETS
|
||||||||
|
Cash and cash equivalents
|
$ | 14,013 | $ | 41,199 | ||||
|
Accounts receivable:
|
||||||||
|
Oil and gas sales
|
28,721 | 26,009 | ||||||
|
Joint interest and other, net
|
6,669 | 14,349 | ||||||
|
Affiliates
|
624 | 227 | ||||||
|
Inventory
|
43,068 | 20,052 | ||||||
|
Deferred income taxes
|
1,362 | 3,637 | ||||||
|
Assets held for sale
|
7,411 | - | ||||||
|
Prepaids and other
|
1,729 | 20,011 | ||||||
| 103,597 | 125,484 | |||||||
|
PROPERTY AND EQUIPMENT
|
||||||||
|
Oil and gas properties, successful efforts method
|
1,579,664 | 1,526,473 | ||||||
|
Natural gas gathering and processing systems
|
17,816 | 17,816 | ||||||
|
Contract drilling equipment
|
41,533 | 91,151 | ||||||
|
Other
|
16,550 | 14,954 | ||||||
| 1,655,563 | 1,650,394 | |||||||
|
Less accumulated depreciation, depletion and amortization
|
(985,517 | ) | (840,366 | ) | ||||
|
Property and equipment, net
|
670,046 | 810,028 | ||||||
|
OTHER ASSETS
|
||||||||
|
Debt issue costs, net
|
4,874 | 6,225 | ||||||
|
Fair value of derivatives
|
4,427 | - | ||||||
|
Other
|
1,660 | 1,672 | ||||||
| 10,961 | 7,897 | |||||||
| $ | 784,604 | $ | 943,409 | |||||
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 EQUITY
|
||||||||
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
CURRENT LIABILITIES
|
||||||||
|
Accounts payable:
|
||||||||
|
Trade
|
$ | 47,211 | $ | 67,189 | ||||
|
Oil and gas sales
|
18,063 | 24,702 | ||||||
|
Affiliates
|
1,097 | 1,627 | ||||||
|
Current maturities of long-term debt
|
- | 18,750 | ||||||
|
Fair value of derivatives
|
5,907 | - | ||||||
|
Accrued liabilities and other
|
11,995 | 10,609 | ||||||
| 84,273 | 122,877 | |||||||
|
NON-CURRENT LIABILITIES
|
||||||||
|
Long-term debt
|
395,000 | 347,225 | ||||||
|
Deferred income taxes
|
54,065 | 120,414 | ||||||
|
Other
|
38,991 | 32,617 | ||||||
| 488,056 | 500,256 | |||||||
|
COMMITMENTS AND CONTINGENCIES
|
||||||||
|
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 – 12,145,536 shares in 2009
|
||||||||
|
and 12,115,898 shares in 2008
|
1,215 | 1,212 | ||||||
|
Additional paid-in capital
|
152,051 | 137,046 | ||||||
|
Retained earnings
|
59,009 | 176,424 | ||||||
|
Total Clayton Williams Energy, Inc. stockholders’ equity
|
212,275 | 314,682 | ||||||
|
Noncontrolling interest, net of tax
|
- | 5,594 | ||||||
|
Total equity
|
212,275 | 320,276 | ||||||
| $ | 784,604 | $ | 943,409 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share)
|
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
REVENUES
|
||||||||||||
|
Oil and gas sales
|
$ | 242,338 | $ | 463,964 | $ | 316,992 | ||||||
|
Natural gas services
|
6,146 | 10,926 | 10,230 | |||||||||
|
Drilling rig services
|
6,681 | 46,124 | 52,649 | |||||||||
|
Gain on sales of assets
|
796 | 44,503 | 14,024 | |||||||||
|
Total revenues
|
255,961 | 565,517 | 393,895 | |||||||||
|
COSTS AND EXPENSES
|
||||||||||||
|
Production
|
76,288 | 89,054 | 75,319 | |||||||||
|
Exploration:
|
||||||||||||
|
Abandonments and impairments
|
78,798 | 80,112 | 68,870 | |||||||||
|
Seismic and other
|
8,189 | 22,685 | 4,765 | |||||||||
|
Natural gas services
|
5,348 | 10,060 | 9,745 | |||||||||
|
Drilling rig services
|
10,848 | 37,789 | 32,964 | |||||||||
|
Depreciation, depletion and amortization
|
129,658 | 120,542 | 84,476 | |||||||||
|
Impairment of property and equipment
|
59,140 | 12,882 | 12,137 | |||||||||
|
Accretion of abandonment obligations
|
3,120 | 2,355 | 2,508 | |||||||||
|
General and administrative
|
20,715 | 25,635 | 19,266 | |||||||||
|
Loss on sales of assets and impairment of inventory
|
5,282 | 2,122 | 9,815 | |||||||||
|
Total costs and expenses
|
397,386 | 403,236 | 319,865 | |||||||||
|
Operating income (loss)
|
(141,425 | ) | 162,281 | 74,030 | ||||||||
|
OTHER INCOME (EXPENSE)
|
||||||||||||
|
Interest expense
|
(23,758 | ) | (24,994 | ) | (32,118 | ) | ||||||
|
Gain (loss) on derivatives
|
(17,416 | ) | 74,743 | (31,968 | ) | |||||||
|
Other
|
2,543 | 6,539 | 5,355 | |||||||||
|
Total other income (expense)
|
(38,631 | ) | 56,288 | (58,731 | ) | |||||||
|
Income (loss) before income taxes
|
(180,056 | ) | 218,569 | 15,299 | ||||||||
|
Income tax (expense) benefit
|
64,096 | (77,327 | ) | (5,497 | ) | |||||||
|
NET INCOME (LOSS)
|
(115,960 | ) | 141,242 | 9,802 | ||||||||
|
Less income attributable to
|
||||||||||||
|
noncontrolling interest, net of tax
|
(1,455 | ) | (708 | ) | (3,812 | ) | ||||||
|
NET INCOME (LOSS) attributable to Clayton
|
||||||||||||
|
Williams Energy, Inc.
|
$ | (117,415 | ) | $ | 140,534 | $ | 5,990 | |||||
|
Net income (loss) per common share attributable to
|
||||||||||||
|
Clayton Williams Energy, Inc. stockholders:
|
||||||||||||
|
Basic
|
$ | (9.67 | ) | $ | 11.78 | $ | .53 | |||||
|
Diluted
|
$ | (9.67 | ) | $ | 11.67 | $ | .52 | |||||
|
Weighted average common shares outstanding:
|
||||||||||||
|
Basic
|
12,138 | 11,932 | 11,337 | |||||||||
|
Diluted
|
12,138 | 12,039 | 11,494 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
|
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net income (loss)
|
$ | (117,415 | ) | $ | 140,534 | $ | 5,990 | |||||
|
Unrealized gain on marketable securities, net of tax
|
||||||||||||
|
of $2,015 in 2008 and $1,464 in 2007
|
- | 3,742 | 2,718 | |||||||||
|
Total comprehensive income (loss)
|
$ | (117,415 | ) | $ | 144,276 | $ | 8,708 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
|
Clayton Williams Energy, Inc. Stockholders’ Equity
|
||||||||||||||||||||||||
|
Accumulated
|
||||||||||||||||||||||||
|
Other
|
||||||||||||||||||||||||
|
Common Stock
|
Additional
|
Compre-
|
Non-
|
|||||||||||||||||||||
|
No. of
|
Par
|
Paid-In
|
Retained
|
hensive
|
Controlling
|
|||||||||||||||||||
|
Shares
|
Value
|
Capital
|
Earnings
|
Income
|
Interest
|
|||||||||||||||||||
|
BALANCE,
|
||||||||||||||||||||||||
|
December 31, 2006
|
11,152 | $ | 1,115 | $ | 113,965 | $ | 29,900 | $ | - | $ | 1,074 | |||||||||||||
|
Net income
|
- | - | - | 5,990 | - | 3,812 | ||||||||||||||||||
|
Unrealized gain on
|
||||||||||||||||||||||||
|
marketable securities,
|
||||||||||||||||||||||||
|
net of tax of $1,464
|
- | - | - | - | 2,718 | - | ||||||||||||||||||
|
Issuance of stock through
|
||||||||||||||||||||||||
|
compensation plans, including
|
||||||||||||||||||||||||
|
income tax benefits
|
202 | 20 | 7,098 | - | - | - | ||||||||||||||||||
|
BALANCE,
|
||||||||||||||||||||||||
|
December 31, 2007
|
11,354 | 1,135 | 121,063 | 35,890 | 2,718 | 4,886 | ||||||||||||||||||
|
Net income
|
- | - | - | 140,534 | - | 708 | ||||||||||||||||||
|
Unrealized gain on
|
||||||||||||||||||||||||
|
marketable securities,
|
||||||||||||||||||||||||
|
net of tax of $2,015
|
- | - | - | - | 3,742 | - | ||||||||||||||||||
|
Reclassification adjustment for
|
||||||||||||||||||||||||
|
securities gains included
|
||||||||||||||||||||||||
|
in income, net of tax of $3,479
|
- | - | - | - | (6,460 | ) | - | |||||||||||||||||
|
Issuance of stock through
|
||||||||||||||||||||||||
|
compensation plans, including
|
||||||||||||||||||||||||
|
income tax benefits
|
762 | 77 | 15,983 | - | - | - | ||||||||||||||||||
|
BALANCE,
|
||||||||||||||||||||||||
|
December 31, 2008
|
12,116 | 1,212 | 137,046 | 176,424 | - | 5,594 | ||||||||||||||||||
|
Net income (loss)
|
- | - | - | (117,415 | ) | - | 1,455 | |||||||||||||||||
|
Issuance of stock through
|
||||||||||||||||||||||||
|
compensation plans, including
|
||||||||||||||||||||||||
|
income tax benefits
|
30 | 3 | 173 | - | - | - | ||||||||||||||||||
|
Acquisition of noncontrolling
|
||||||||||||||||||||||||
|
interest
|
- | - | 14,832 | - | - | (7,049 | ) | |||||||||||||||||
|
BALANCE,
|
||||||||||||||||||||||||
|
December 31, 2009
|
12,146 | $ | 1,215 | $ | 152,051 | $ | 59,009 | $ | - | $ | - | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-7
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
Year Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
||||||||||||
|
Net income (loss)
|
$ | (115,960 | ) | $ | 141,242 | $ | 9,802 | |||||
|
Adjustments to reconcile net income (loss) to cash
|
||||||||||||
|
provided by operating activities:
|
||||||||||||
|
Depreciation, depletion and amortization
|
129,658 | 120,542 | 84,476 | |||||||||
|
Impairment of property and equipment
|
59,140 | 12,882 | 12,137 | |||||||||
|
Exploration costs
|
78,798 | 80,112 | 68,870 | |||||||||
|
(Gain) loss on sales of assets and impairment of inventory, net
|
4,486 | (42,381 | ) | (4,209 | ) | |||||||
|
Deferred income tax expense (benefit)
|
(64,220 | ) | 77,315 | 3,768 | ||||||||
|
Non-cash employee compensation
|
1,434 | 5,834 | 1,865 | |||||||||
|
Unrealized (gain) loss on derivatives
|
1,480 | (49,738 | ) | 24,249 | ||||||||
|
Settlements on derivatives with financing elements
|
- | 43,486 | 28,468 | |||||||||
|
Amortization of debt issue costs
|
1,458 | 1,354 | 1,281 | |||||||||
|
Accretion of abandonment obligations
|
3,120 | 2,355 | 2,508 | |||||||||
|
Excess tax benefit on exercise of stock options
|
- | - | (963 | ) | ||||||||
|
Changes in operating working capital:
|
||||||||||||
|
Accounts receivable
|
4,571 | 13,087 | (10,028 | ) | ||||||||
|
Accounts payable
|
(19,590 | ) | (4,946 | ) | 10,992 | |||||||
|
Other
|
20,336 | (19,164 | ) | 1,650 | ||||||||
|
Net cash provided by operating activities
|
104,711 | 381,980 | 234,866 | |||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
||||||||||||
|
Additions to property and equipment
|
(142,623 | ) | (351,789 | ) | (262,755 | ) | ||||||
|
Proceeds from sales of assets
|
729 | 117,226 | 22,773 | |||||||||
|
Change in equipment inventory
|
(26,675 | ) | (8,247 | ) | 18,166 | |||||||
|
Other
|
(29 | ) | 3,935 | (14,443 | ) | |||||||
|
Net cash used in investing activities
|
(168,598 | ) | (238,875 | ) | (236,259 | ) | ||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
||||||||||||
|
Proceeds from long-term debt
|
75,900 | 7,500 | 34,527 | |||||||||
|
Repayments of long-term debt
|
(39,375 | ) | (94,200 | ) | (13,125 | ) | ||||||
|
Proceeds from exercise of stock options
|
176 | 15,936 | 6,000 | |||||||||
|
Settlements on derivatives with financing elements
|
- | (43,486 | ) | (28,468 | ) | |||||||
|
Excess tax benefit on exercise of stock options
|
- | - | 963 | |||||||||
|
Net cash provided by (used in) financing activities
|
36,701 | (114,250 | ) | (103 | ) | |||||||
|
NET INCREASE (DECREASE) IN CASH AND
|
||||||||||||
|
CASH EQUIVALENTS
|
(27,186 | ) | 28,855 | (1,496 | ) | |||||||
|
CASH AND CASH EQUIVALENTS
|
||||||||||||
|
Beginning of period
|
41,199 | 12,344 | 13,840 | |||||||||
|
End of period
|
$ | 14,013 | $ | 41,199 | $ | 12,344 | ||||||
|
SUPPLEMENTAL DISCLOSURES
|
||||||||||||
|
Cash paid for interest, net of amounts capitalized
|
$ | 23,349 | $ | 24,027 | $ | 35,213 | ||||||
|
Cash paid for income taxes
|
$ | - | $ | 16,652 | $ | 348 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-8
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 the Company’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 25% is owned by a partnership in which Mr. Williams’ adult children are limited partners.
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 demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil exporting countries, trading activities in commodities futures markets, the strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.
2. Summary of Significant Accounting Policies
Estimates and Assumptions
The preparation of 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 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 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
|
|
·
|
Abandonment obligations are based on estimates regarding the timing and cost of future asset abandonments.
|
Principles of Consolidation
The consolidated financial statements include the accounts of CWEI and its wholly-owned subsidiaries. We also account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of these limited partnerships. Less than 5% of the Company’s consolidated total assets and total revenues are derived from oil and gas limited partnerships. All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.
F-9
Oil and Gas Properties
We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.
Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.
Natural Gas Systems and Other Property and Equipment
Natural gas gathering and processing systems consist primarily of gas gathering pipelines, compressors and gas processing plants. 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.
Depreciation of natural gas gathering and processing systems 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 20 years.
Contract Drilling
We conduct contract drilling operations through Desta Drilling (see Note 10), formerly referred to as Larclay JV. 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 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 7 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 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.
Abandonment 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 abandonment obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.
F-10
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 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 income in the period that includes the enactment date. We also recorded 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 Activities
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 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, 2009, 2008 and 2007, we capitalized interest totaling approximately $698,000, $3.8 million and $4.2 million, respectively. In addition, we capitalized interest relating to the construction of drilling rigs in Desta Drilling of $2 million in 2007.
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 2008 and 2007 include an increase in potential shares attributable to dilutive stock options.
Marketable Securities
All marketable equity securities are included in other non-current assets and are considered available-for-sale securities carried at fair value. The unrealized gains and losses related to these securities are included in accumulated other comprehensive income. The fair values are based on quoted market prices.
F-11
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 (“Black-Scholes 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.
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 natural gas liquids 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, 2009 or 2008. Revenues from natural gas services are recognized as services are provided.
Comprehensive Income
In 2008 and 2007, we reported an unrealized gain on marketable securities as comprehensive income. There were no differences between net income and comprehensive income in 2009.
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, 2009 and 2008 relate to amounts due from joint interest owners.
Reclassifications
To the extent necessary, reclassifications of prior year financial statement amounts are made to conform to current year presentations.
F-12
Adopted Accounting Pronouncements
Effective July 1, 2009, we adopted SFAS No. 168, “The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS 168”) superseded by topic 105-10-5 of the FASB Accounting Standards Codification (“ASC”). SFAS 168 establishes the ASC as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with Generally Accepted Accounting Principles ("GAAP"). Other than the manner in which new accounting guidance is referenced, the adoption did not have a material impact on our financial statements.
Effective January 1, 2009, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51” (“SFAS 160”) (superseded by ASC topic 810-10-65). Noncontrolling interests (previously referred to as minority interests) are ownership interests in a consolidated subsidiary held by parties other than the parent. SFAS 160 requires that noncontrolling interests be clearly identified and reported as a component of equity in the parent’s balance sheet. SFAS 160 also requires that the amount of net income or loss attributable to the parent and the noncontrolling interest be presented separately on the face of the consolidated statement of operations. The presentations of noncontrolling interest in our consolidated financial statements, as required by SFAS 160, have been applied retrospectively to prior periods.
Effective January 1, 2009, we adopted SFAS Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS 161”) (superseded by ASC topic 815-10-65). This statement is intended to improve transparency in financial reporting by requiring enhanced disclosures of an entity’s derivative instruments and hedging activities and their effects on the entity’s financial position, financial performance, and cash flows. SFAS 161 applies to all derivative instruments within the scope of SFAS No. 133, “Accounting for Derivatives and Hedging Activities” (“SFAS 133”) (superseded by ASC topic 815-10) as well as related hedged items, bifurcated derivatives, and non-derivative instruments that are designated and qualify as hedging instruments. The adoption of SFAS 161 did not have a material effect on our financial statements, other than disclosures.
Effective January 1, 2009, we adopted SFAS No. 141R, “Business Combinations” (“SFAS 141R”) (superseded by ASC topic 805-10). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. The adoption of SFAS 141R did not have a material impact on our financial statements.
Effective January 1, 2009, we adopted SFAS No. 157, “Fair Value Measurements (as amended)” (“SFAS 157”) (superseded by ASC topic 820-10), for nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis (see Note 7). SFAS 157 defines fair value, establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measures. We had previously adopted SFAS 157 for financial assets and liabilities that are measured at fair value and for nonfinancial assets and liabilities that are measured at fair value on a recurring basis.
Effective April 1, 2009, we adopted SFAS No. 165, “Subsequent Events” (“SFAS 165”) (superseded by ASC topic 855-10-5), which establishes principles and requirements for disclosure of subsequent events. It establishes the period after the balance sheet date during which events or transactions are to be evaluated for potential disclosure. It also establishes the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date. The adoption of SFAS 165 did not have a material impact on our disclosure of subsequent events.
In December 2008, the Securities and Exchange Commission (“SEC”) released Final Rule, “Modernization of Oil and Gas Reporting”. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (1) report the independence and qualifications of its reserves preparer or auditor, (2) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit, and (3) report oil and gas reserves using an
F-13
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
average price based upon the prior 12-month period rather than year-end prices. In January 2010, the FASB issued new accounting guidance to align the reserve estimation and disclosure requirements within generally accepted accounting principles with the Final Rule. All of these rule changes became effective December 31, 2009. We have adopted these changes and conformed our reserve estimation and disclosure practices in accordance with the guidance contained in the releases.
Recent Accounting Pronouncements
In June 2009, the FASB issued accounting guidance on the consolidation of variable interest entities (“VIEs”). This new guidance revises previous guidance by replacing the quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a VIE with a qualitative approach focused on identifying which enterprise has both the power to direct the activities of the VIE that most significantly impacts the entity’s economic performance and has the obligation to absorb losses or the right to receive benefits that could be significant to the entity. In addition, this guidance requires reconsideration of whether an entity is a VIE when any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of the entity that most significantly impact the entity’s economic performance. It also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE and additional disclosures about an enterprise’s involvement in variable interest entities. This guidance is effective for fiscal years beginning after November 15, 2009. Accordingly, we will adopt the provisions of the new guidance in the first quarter of 2010. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
3. Long-Term Debt
Long-term debt consists of the following:
|
December 31,
|
December 31,
|
|||||||
|
2009
|
2008
|
|||||||
|
(In thousands)
|
||||||||
|
7¾% Senior Notes due 2013
|
$ | 225,000 | $ | 225,000 | ||||
|
Secured bank credit facility, due May 2012
|
170,000 | 94,100 | ||||||
|
Secured term loan of Desta Drilling, due June 2011(a)
|
- | 39,375 | ||||||
|
Subordinated notes of Desta Drilling(b)
|
- | 7,500 | ||||||
| 395,000 | 365,975 | |||||||
|
Less current maturities(c)
|
- | (18,750 | ) | |||||
| $ | 395,000 | $ | 347,225 | |||||
|
(a)
|
In August 2009, we repaid all of the secured term loan of Desta Drilling with borrowings under our secured bank credit facility due May 2012.
|
|
(b)
|
Note payable to Lariat Services, Inc. by Desta Drilling that was converted to equity in April 2009 (see Note 10).
|
|
(c)
|
Amount relates to the current portion of the secured term loan of Desta Drilling.
|
Aggregate maturities of long-term debt at December 31, 2009 are as follows: 2012 - $170 million; and 2013 - $225 million.
7¾% Senior Notes due 2013
In July 2005, we issued $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (“Senior Notes”). The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006.
We may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on August 1, 2009, 101.938% for the twelve-month period beginning on August 1, 2010, and 100% beginning on August 1, 2011 or for any period thereafter, in each case plus accrued and unpaid interest.
The Indenture governing the Senior Notes 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 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)
F-14
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
exceeds 2.5 to 1 for the four most recently completed fiscal quarters. However, this restriction does not prevent us from borrowing funds under the revolving credit facility provided that our outstanding balance on the facility does not exceed the greater of $150 million and 30% of Adjusted Consolidated Net Tangible Assets (as defined 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, 2009.
Secured Bank Credit Facility
We have a revolving credit facility with a syndicate of banks based on a borrowing base 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 the revolving credit facility, we will be required to (1) pledge additional collateral, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the excess, or (3) prepay the excess in six equal monthly installments. In October 2009, the borrowing base was affirmed by the banks at $250 million. After allowing for outstanding letters of credit totaling $804,000, we had $79.2 million available under the credit facility at December 31, 2009.
The revolving credit facility is collateralized by substantially all of our assets, including at least 80% of the adjusted engineered value (as defined in the revolving credit facility) of our oil and gas interests evaluated in determining the borrowing base. The obligations under the revolving credit facility are guaranteed by each of CWEI’s material domestic subsidiaries.
In May 2009, the usage-based pricing formulas under the revolving credit facility were amended. The Eurodollar rate margin was increased to a range of 2% to 3% from a range of 1.5% to 2.25%. The alternate base rate margin was increased to a range of 1.125% to 2.125% from a range of .25% to 1%. We also pay a commitment fee on the unused portion of the revolving credit facility which increased to a flat rate of .5% from a range of .375% to .5%. Interest and fees are payable no less often than quarterly. The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the twelve months ended December 31, 2009 was 2.7%.
The revolving credit facility contains financial covenants that are computed quarterly. One financial covenant requires us to maintain a ratio of current assets to current liabilities of at least 1 to 1. Another financial covenant, which was amended in May 2009, 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 3.5 to 1 for any fiscal quarter ending on or prior to December 31, 2010, 3.25 to 1 for any fiscal quarter ending on or after March 31, 2011 through December 31, 2011, and 3 to 1 for any fiscal quarter thereafter. Prior to the amendment, this ratio could not exceed 3 to 1. The computations of current assets, current liabilities, EBITDAX and indebtedness are defined in the loan agreement. We were in compliance with all financial and non-financial covenants at December 31, 2009.
Secured Term Loan of Desta Drilling
In 2006, Desta Drilling (formerly referred to as Larclay JV, see Note 10) obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs. In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under the revolving credit facility. All of the assets of Desta Drilling were pledged as collateral under our revolving credit facility.
4. Other Non-Current Liabilities
Other non-current liabilities at December 31, 2009 and 2008 consist of the following:
|
2009
|
2008
|
|||||||
|
(In thousands)
|
||||||||
|
Abandonment obligations
|
$ | 38,412 | $ | 31,737 | ||||
|
Other taxes payable
|
- | 144 | ||||||
|
Other
|
579 | 736 | ||||||
| $ | 38,991 | $ | 32,617 | |||||
F-15
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Our asset retirement obligation 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.
Abandonment Obligations
Changes in abandonment obligations for 2009 and 2008 are as follows:
|
2009
|
2008
|
|||||||
|
(In thousands)
|
||||||||
|
Beginning of year
|
$ | 31,737 | $ | 30,994 | ||||
|
Additional abandonment obligations from new properties
|
1,654 | 1,780 | ||||||
|
Sales or abandonments of properties
|
(293 | ) | (1,991 | ) | ||||
|
Accretion expense
|
3,120 | 2,355 | ||||||
|
Revisions of previous estimates
|
2,194 | (1,401 | ) | |||||
|
End of year
|
$ | 38,412 | $ | 31,737 | ||||
5. Income Taxes
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. Significant components of net deferred tax assets (liabilities) at December 31, 2009 and 2008 are as follows:
|
2009
|
2008
|
|||||||
|
(In thousands)
|
||||||||
|
Deferred tax assets:
|
||||||||
|
Net operating loss carryforwards
|
$ | 24,275 | $ | 9,033 | ||||
|
Fair value of derivatives
|
518 | - | ||||||
|
Statutory depletion carryforwards
|
6,589 | 6,096 | ||||||
|
Alternative minimum tax credit carryforwards
|
437 | 437 | ||||||
|
Abandonment obligations and other
|
10,952 | 11,315 | ||||||
| 42,771 | 26,881 | |||||||
|
Deferred tax liabilities:
|
||||||||
|
Property and equipment
|
(95,474 | ) | (108,903 | ) | ||||
|
Tax deferred derivative settlements
|
- | (34,755 | ) | |||||
| (95,474 | ) | (143,658 | ) | |||||
|
Net deferred tax liabilities
|
$ | (52,703 | ) | $ | (116,777 | ) | ||
|
Components of net deferred tax liabilities:
|
||||||||
|
Current assets
|
$ | 1,362 | $ | 3,637 | ||||
|
Non-current liabilities
|
(54,065 | ) | (120,414 | ) | ||||
| $ | (52,703 | ) | $ | (116,777 | ) | |||
For the years ended December 31, 2009, 2008 and 2007, effective income tax rates were different than the statutory federal income tax rates for the following reasons:
|
2009
|
2008
|
2007
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Income tax expense (benefit) at statutory rate of 35%
|
$ | (63,020 | ) | $ | 76,500 | $ | 5,355 | |||||
|
Tax depletion in excess of basis
|
(388 | ) | (700 | ) | (700 | ) | ||||||
|
Revision of previous tax estimates
|
(130 | ) | 55 | 16 | ||||||||
|
State income taxes, net of federal tax effect
|
(655 | ) | 1,375 | 738 | ||||||||
|
Other
|
97 | 97 | 88 | |||||||||
|
Income tax expense (benefit)
|
$ | (64,096 | ) | $ | 77,327 | $ | 5,497 | |||||
|
Current
|
$ | 124 | $ | 12 | $ | 1,729 | ||||||
|
Deferred
|
(64,220 | ) | 77,315 | 3,768 | ||||||||
|
Income tax expense (benefit)
|
$ | (64,096 | ) | $ | 77,327 | $ | 5,497 | |||||
F-16
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
We derive a tax deduction when employees and directors exercise options granted 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, 2009, our cumulative tax loss carryforwards were approximately $69.4 million, of which $32.7 million relates to excess tax benefits from exercise of stock options.
The Company and its subsidiaries file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for fiscal years after 2005 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time.
In December 2008, we made an estimated federal income tax payment of $16 million. Since we reported a net operating loss on our 2008 federal income tax return, we received a refund of $16 million in 2009.
In 2007, we recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods. A reconciliation of the changes in this tax liability during the years ended December 31, 2009 and December 31, 2008 is as follows in thousands:
|
Balance at December 31, 2007
|
$ | 358 | ||
|
Reductions for tax positions of prior years
|
(214 | ) | ||
|
Balance at December 31, 2008
|
144 | |||
|
Reductions for tax positions of prior years
|
(144 | ) | ||
|
Balance at December 31, 2009
|
$ | - |
No unrecognized tax benefits originated during 2009.
6. 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 NYMEX futures prices), resulting in a net amount due to or from the counterparty. In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature.
The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2009. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Swaps:
|
Oil
|
Gas
|
|||||||||||||||
|
Bbls
|
Price
|
MMBtu (a)
|
Price
|
|||||||||||||
|
Production Period:
|
||||||||||||||||
|
1st Quarter 2010
|
628,000 | $ | 76.70 | 2,280,000 | $ | 6.80 | ||||||||||
|
2nd Quarter 2010
|
574,000 | $ | 76.60 | 1,830,000 | $ | 6.80 | ||||||||||
|
3rd Quarter 2010
|
522,000 | $ | 76.40 | 1,750,000 | $ | 6.80 | ||||||||||
|
4th Quarter 2010
|
480,000 | $ | 76.24 | 1,680,000 | $ | 6.80 | ||||||||||
|
2011
|
1,656,000 | $ | 84.38 | 6,420,000 | $ | 7.07 | ||||||||||
| 3,860,000 | 13,960,000 | |||||||||||||||
|
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.
|
||||||||||||||||
F-17
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In March 2009, we terminated certain fixed-priced oil swaps covering 332,000 barrels at a price of $57.35 from January 2010 through December 2010, resulting in an aggregate loss of approximately $1.3 million, which will be paid to the counterparty monthly as the applicable contracts are settled.
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 statements of operations. For the year ended December 31, 2009, we reported a $17.4 million net loss on derivatives, consisting of a $15.9 million loss for settled contracts and a $1.5 million loss related to changes in mark-to-market valuations. For the year ended December 31, 2008, we reported a $74.7 million net gain on derivatives, consisting of a $25 million gain for settled contracts and a $49.7 million gain related to changes in mark-to-market valuations. At December 31, 2008, the Company had closed all of its then existing commodity and interest derivatives.
Effect of Derivative Instruments on the Consolidated Balance Sheets
|
Fair Value of Derivative Instruments as of December 31, 2009
|
||||||||||
|
Asset Derivatives
|
Liability Derivatives
|
|||||||||
|
Balance Sheet
|
Balance Sheet
|
|||||||||
|
Location
|
Fair Value
|
Location
|
Fair Value
|
|||||||
|
(In thousands)
|
(In thousands)
|
|||||||||
|
Derivatives not designated as
|
||||||||||
|
hedging instruments:
|
||||||||||
|
Commodity derivatives
|
Fair value of derivatives:
|
Fair value of derivatives:
|
||||||||
|
Current
|
$ | - |
Current
|
$ | 5,907 | |||||
|
Non-current
|
4,427 |
Non-current
|
- | |||||||
|
Total
|
$ | 4,427 | $ | 5,907 | ||||||
Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities
|
December 31, 2009
|
||||||||
|
Assets
|
Liabilities
|
|||||||
|
(In thousands)
|
||||||||
|
Fair value of derivatives – gross presentation
|
$ | 20,105 | $ | 21,585 | ||||
|
Effects of netting arrangements
|
(15,678 | ) | (15,678 | ) | ||||
|
Fair value of derivatives – net presentation
|
$ | 4,427 | $ | 5,907 | ||||
All of our derivative contracts are with JPMorgan Chase Bank, N.A., which has a credit rating of AA- as determined by a nationally recognized statistical ratings organization. We have elected to net the outstanding positions with this counterparty between current and noncurrent assets or liabilities.
Effect of Derivative Instruments on the Consolidated Statements of Operations
|
Amount of Gain or (Loss) Recognized in Earnings
|
||||||
|
Year Ended
|
||||||
|
Location of Gain or (Loss)
|
December 31,
|
|||||
|
Recognized in Earnings
|
2009
|
2008
|
||||
|
(In thousands)
|
||||||
|
Derivatives not designated as
|
||||||
|
hedging instruments:
|
||||||
|
Commodity derivatives
|
Other income (expense) -
|
|||||
|
Gain (loss) on derivatives
|
$ (17,416)
|
$ 74,743
|
||||
|
Total
|
$ (17,416)
|
$ 74,743
|
||||
F-18
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. 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 secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. The estimated fair value of our Senior Notes at December 31, 2009 and 2008 was approximately $198 million and $126 million, respectively, based on market valuations.
The only financial assets and liabilities measured on a recurring basis at December 31, 2009 were commodity derivatives. At December 31, 2008, the Company had closed all of its then existing commodity and interest derivatives. Information regarding these assets and liabilities at December 31, 2009 is summarized below:
|
Significant Other
|
||||
|
Observable Inputs
|
||||
|
Description
|
(Level 2)
|
|||
|
(In thousands)
|
||||
|
Assets:
|
||||
|
Fair value of commodity derivatives
|
$ | 4,427 | ||
|
Total assets
|
$ | 4,427 | ||
|
Liabilities:
|
||||
|
Fair value of commodity derivatives
|
$ | 5,907 | ||
|
Total liabilities
|
$ | 5,907 | ||
8. Compensation Plans
Stock-Based Compensation
Prior to the termination of the 1993 Stock Compensation Plan (“1993 Plan”) in December 2009, we had reserved 1,798,200 shares of common stock for issuance under the 1993 Plan for the issuance of nonqualified stock options with an exercise price which could not be less than the market value of our common stock on the date of grant. We issued new shares, not repurchased shares, to option holders that exercised stock options under the 1993 Plan. During 2009, all options that remained outstanding under the 1993 Plan as of December 31, 2008 were exercised and the plan was terminated.
Initially, we reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“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 10 years from the grant date and are fully exercisable upon issuance. No options were granted under the Directors Plan in 2009. At December 31, 2009, 24,000 options were outstanding under this plan. In December 2009, the Board of Directors reduced the number of shares available for issuance under the Directors Plan to a level sufficient to cover only the remaining outstanding shares.
The following table sets forth certain information regarding our stock option plans as of and for the year ended December 31, 2009:
|
Weighted
|
||||||||||||||||
|
Weighted
|
Average
|
|||||||||||||||
|
Average
|
Remaining
|
Aggregate
|
||||||||||||||
|
Exercise
|
Contractual
|
Intrinsic
|
||||||||||||||
|
Shares
|
Price
|
Term
|
Value(a)
|
|||||||||||||
|
Outstanding at January 1, 2009
|
53,638 | $ | 15.20 | |||||||||||||
|
Exercised (b)
|
(29,638 | ) | $ | 5.93 | ||||||||||||
|
Outstanding at December 31, 2009
|
24,000 | $ | 26.66 | 4.5 | $ | 224,850 | ||||||||||
|
Vested at December 31, 2009
|
24,000 | $ | 26.66 | 4.5 | $ | 224,850 | ||||||||||
|
Exercisable at December 31, 2009
|
24,000 | $ | 26.66 | 4.5 | $ | 224,850 | ||||||||||
|
(a) Based on closing price at December 31, 2009 of $35.03 per share.
|
||||||||||||||||
|
(b) Cash received for options exercised totaled $175,635.
|
||||||||||||||||
F-19
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes information with respect to options outstanding at December 31, 2009, all of which were granted under the Directors Plan are currently exercisable.
|
Outstanding and Exercisable Options
|
||||||||||||||
|
Weighted
|
||||||||||||||
|
Weighted
|
Average
|
|||||||||||||
|
Average
|
Remaining
|
|||||||||||||
|
Exercise
|
Life in
|
|||||||||||||
|
Shares
|
Price
|
Years
|
||||||||||||
|
Range of exercise prices:
|
||||||||||||||
| $10.00 - $19.74 | 6,000 | $ | 12.62 | 2.5 | ||||||||||
| $22.90 - $41.74 | 18,000 | $ | 31.34 | 5.2 | ||||||||||
| 24,000 | $ | 26.66 | 4.5 | |||||||||||
The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2009, 2008 and 2007.
|
2009
|
2008
|
2007
|
||||||||||
|
(In thousands, except per share)
|
||||||||||||
|
Weighted average grant date fair value of options granted per share
|
$ | - | $ | 23.06 | $ | 27.56 | ||||||
|
Intrinsic value of options exercised
|
$ | 586 | $ | 20,480 | $ | 261 | ||||||
|
Stock-based employee compensation expense
|
$ | - | $ | 92 | $ | 110 | ||||||
|
Tax benefit
|
- | (32 | ) | (38 | ) | |||||||
|
Net stock-based employee compensation expense
|
$ | - | $ | 60 | $ | 72 | ||||||
The fair value of stock options issued for each year was estimated at the date of grant using the Black-Scholes option pricing model. The following weighted average assumptions were used in this model.
|
2009
|
2008
|
2007
|
||||||||||
|
Risk-free interest rate
|
- | 4 | % | 4.7 | % | |||||||
|
Stock price volatility
|
- | 63 | % | 64 | % | |||||||
|
Expected life in years
|
- | 10 | 10 | |||||||||
|
Dividend yield
|
- | - | - | |||||||||
Non-Equity Award Plans
The Compensation Committee of the Board of Directors has adopted an after-payout (“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 (“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 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 authorized the formation of 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 four specified areas, each of which established a quarterly bonus amount equal to 7% 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 August 1, 2008. Under these four awards, 100% of the quarterly bonus amount is payable on a current basis to the participants, and the full vesting dates for future amounts payable under the plan for three of the awards is May 5, 2013 and under one award is November 4, 2011.
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 after-payout cash flow from a 22.5% working interest in one well. Under the plan, two-thirds of the quarterly bonus amount is payable to the participants until the full vesting date of October 25, 2011. After the full vesting date, the deferred portion of the quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all 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 plan. 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 fair value of the economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and SWR Reward Plan is recognized over the vesting periods, which range from two years to five years We recorded compensation expense of $2.8 million in 2009 and $6.2 million in 2008 in connection with all non-equity award plans.
9. 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, 2009, 2008 and 2007.
F-21
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
2009
|
2008
|
2007
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Amounts received from the Williams Entities:
|
||||||||||||
|
Service Agreement:
|
||||||||||||
|
Services
|
$ | 519 | $ | 581 | $ | 299 | ||||||
|
Insurance premiums and benefits
|
826 | 868 | 707 | |||||||||
|
Reimbursed expenses
|
300 | 467 | 676 | |||||||||
| $ | 1,645 | $ | 1,916 | $ | 1,682 | |||||||
|
Amounts paid to the Williams Entities:
|
||||||||||||
|
Rent(a)
|
$ | 895 | $ | 807 | $ | 663 | ||||||
|
Service Agreement:
|
||||||||||||
|
Business entertainment(b)
|
116 | 91 | 113 | |||||||||
|
Tax services(c)
|
- | - | 150 | |||||||||
|
Reimbursed expenses
|
128 | 197 | 122 | |||||||||
| $ | 1,139 | $ | 1,095 | $ | 1,048 | |||||||
|
|
(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 23.3%.
|
|
|
(b)
|
Consists of hunting and fishing rights pertaining to land owned by affiliates of Mr. Williams.
|
|
|
(c)
|
Prior to 2008, the Williams Entities provided tax preparation services and tax planning services for us.
|
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.
10. Desta Drilling
We formed a joint venture in 2006 with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. Initially, we referred to this joint venture as Larclay JV, but in June 2009, we changed the legal name of the operating entity in the joint venture to Desta Drilling, LP (“Desta Drilling”). In order to assure the availability of drilling rigs for our exploration and development activities, we provided credit support to permit Desta Drilling to finance the construction of the 12 drilling rigs and related equipment, consisting of (1) a subordinated loan of $4.6 million to finance excess construction costs, (2) a limited guaranty to the secured lender in the original amount of $19.5 million, and (3) a drilling contract that expired in 2009 under which we were obligated to use the drilling rigs or pay idle rig rates. During the term of the drilling contract, we paid Desta Drilling $24.4 million in idle rig fees. We and Lariat also made cash advances to Desta Drilling in the form of subordinated loans of $7.5 million each to provide additional financial support. Lariat was designated as the operator of the rigs and provided all management services on behalf of Desta Drilling.
Initially, we and Lariat each owned a 50% equity interest in Desta Drilling, but effective April 15, 2009, we entered into an agreement with Lariat whereby Lariat assigned to us their 50% equity interest (the “Assignment”). The Assignment from Lariat also included all of Lariat’s right, title and interest in the subordinated loans previously made by Lariat to Desta Drilling. As consideration for the Assignment, CWEI assumed all of the obligations and liabilities of Lariat relating to Desta Drilling from and after the effective date, including Lariat’s obligations as operator of Desta Drilling’s rigs. Upon consummation of the Assignment, CWEI contributed all of the subordinated loans to Desta Drilling’s capital. In August 2009, we repaid in full all amounts outstanding under the secured term loan of Desta Drilling with borrowings of approximately $27.2 million under our revolving credit facility. All of the assets of Desta Drilling were pledged as collateral under our revolving credit facility.
Upon consummation of the Assignment, we adopted a plan of disposition whereby we committed to sell eight of the 12 drilling rigs owned by Desta Drilling. The plan of disposition met the criteria under applicable accounting standards for the designated assets to be classified as held for sale. We are required to value the designated assets at the lower of their carrying value or fair value, less cost to sell, as of the date the plan of disposition was adopted. To estimate the fair value of the drilling rigs and related equipment owned by Desta Drilling on the measurement date of April 15, 2009, we used a weighting of the market approach and the discounted cash flow approach. Level 3 inputs used in the determination of discounted cash flow included estimated rig utilization rates, gross profits from drilling operations, future capital costs required for equipment replacements, useful lives for the equipment and discount rates. We weighted the values obtained through the market approach by 67% and the values obtained through the discounted cash flow approach by 33% to give greater emphasis to the lack of demand for drilling equipment on the measurement date. We estimated the fair value of the designated assets to be approximately $18.8 million and recorded a related charge for impairment of property and equipment of approximately $32.1 million in our
F-22
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
statement of operations during the second quarter of 2009. Under applicable accounting standards, this plan of disposition did not qualify for discontinued operations reporting.
In December 2009, we modified the prior plan of disposition established in April 2009. Since oil prices improved, we escalated our developmental drilling program and put six of the drilling rigs previously held for sale back to work and transferred their estimated fair value of $11.4 million to property and equipment. Assets held for sale at December 31, 2009 consist of the remaining two 2,000 horsepower drilling rigs at an estimated fair value of $7.4 million.
11. Sales of Assets and Impairments of Inventory
Net gains and losses on sales of assets and impairments of inventory for the years ended December 31, 2009, 2008 and 2007 are as follows:
|
2009
|
2008
|
2007
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Gain on sales of assets
|
$ | 796 | $ | 44,503 | $ | 14,024 | ||||||
|
Loss on sales of assets and impairment
|
||||||||||||
|
of inventory:
|
||||||||||||
|
Loss on sales of assets
|
(348 | ) | (2,122 | ) | (837 | ) | ||||||
|
Impairment of inventory
|
(4,934 | ) | - | (8,978 | ) | |||||||
| (5,282 | ) | (2,122 | ) | (9,815 | ) | |||||||
|
Net gain (loss)
|
$ | (4,486 | ) | $ | 42,381 | $ | 4,209 | |||||
In 2008, we sold our interests in 16 producing wells for proceeds of $89.2 million and recorded a gain of approximately $33.1 million in the transaction. We also sold two 2,000 horsepower drilling rigs and a well servicing unit for aggregate proceeds of $23.6 million and recorded an aggregate gain of $5.7 million. Also in 2008, we sold our interest in a prospect in North Louisiana for proceeds of $3.1 million and recorded a gain of $3 million. In 2007, we recorded a $12.5 million gain for the sale of certain oil and gas properties in Pecos County, Texas.
We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities. Inventory is carried at the lower of average cost or estimated fair market value. We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards. To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment. We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory. If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.
12. 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 $1.1 million, $997,000 and $846,000 for the years ended December 31, 2009, 2008 and 2007, respectively.
Future minimum payments under noncancelable leases at December 31, 2009, are as follows:
|
Leases
|
||||||||||||
|
Capital(a)
|
Operating
|
Total
|
||||||||||
|
(In thousands)
|
||||||||||||
|
2010
|
$ | 629 | $ | 1,142 | $ | 1,771 | ||||||
|
2011
|
402 | 944 | 1,346 | |||||||||
|
2012
|
193 | 196 | 389 | |||||||||
|
Thereafter
|
- | 24 | 24 | |||||||||
|
Total minimum lease payments
|
$ | 1,224 | $ | 2,306 | $ | 3,530 | ||||||
F-23
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Legal Proceedings
CWEI is a defendant in several 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.
13. 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: discounted cash flow method, flowing daily production method and 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 of $27 million in 2009, $12.9 million in 2008, and $12.1 million in 2007. The 2009 provision related primarily to $21.6 million for certain properties in South Louisiana. The 2008 provision related primarily to oil and gas proved property impairments of $11.3 million for the Margarita #1 well on our East Texas Bossier prospect. The 2007 provision included $7.1 million to write-down two 2,000 horsepower drilling rigs and related components, and $1.1 million for well service equipment to their estimated fair market value. The remaining $3.9 million impairment for 2007 is related to producing properties in the Permian Basin. For a description of inputs used to determine the estimated fair value of drilling rigs, see Note 11.
We 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. 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 location 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. We recorded provisions for impairment of unproved properties aggregating $36.1 million, $51.2 million and $16.8 million in 2009, 2008 and 2007, respectively, and charged these impairments to exploration costs in the accompanying statements of operations.
F-24
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. Quarterly Financial Data (Unaudited)
The following table summarizes results for each of the four quarters in the years ended December 31, 2009 and 2008.
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||||||
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
Year
|
||||||||||||||||
|
(In thousands, except per share)
|
||||||||||||||||||||
|
Year ended December 31, 2009:
|
||||||||||||||||||||
|
Total revenues
|
$ | 57,782 | $ | 60,503 | $ | 62,426 | $ | 75,250 | $ | 255,961 | ||||||||||
|
Operating loss
|
$ | (31,620 | ) | $ | (33,462 | ) | $ | (19,571 | ) | $ | (56,772 | ) | $ | (141,425 | ) | |||||
|
Net loss(a)
|
$ | (22,315 | ) | $ | (38,608 | ) | $ | (13,600 | ) | $ | (42,892 | ) | $ | (117,415 | ) | |||||
|
Net loss per common share(b):
|
||||||||||||||||||||
|
Basic
|
$ | (1.84 | ) | $ | (3.18 | ) | $ | (1.12 | ) | $ | (3.53 | ) | $ | (9.67 | ) | |||||
|
Diluted
|
$ | (1.84 | ) | $ | (3.18 | ) | $ | (1.12 | ) | $ | (3.53 | ) | $ | (9.67 | ) | |||||
|
Weighted average common shares outstanding:
|
||||||||||||||||||||
|
Basic
|
12,122 | 12,142 | 12,144 | 12,144 | 12,138 | |||||||||||||||
|
Diluted
|
12,122 | 12,142 | 12,144 | 12,144 | 12,138 | |||||||||||||||
|
Year ended December 31, 2008:
|
||||||||||||||||||||
|
Total revenues
|
$ | 136,858 | $ | 191,268 | $ | 146,985 | $ | 90,406 | $ | 565,517 | ||||||||||
|
Operating income (loss)
|
$ | 64,415 | $ | 119,001 | $ | 18,126 | $ | (39,261 | ) | $ | 162,281 | |||||||||
|
Net income (loss)(a)
|
$ | 7,179 | $ | (21,171 | ) | $ | 94,629 | $ | 59,897 | $ | 140,534 | |||||||||
|
Net income (loss) per common share(b):
|
||||||||||||||||||||
|
Basic
|
$ | .63 | $ | (1.75 | ) | $ | 7.81 | $ | 4.94 | $ | 11.78 | |||||||||
|
Diluted
|
$ | .62 | $ | (1.75 | ) | $ | 7.79 | $ | 4.93 | $ | 11.67 | |||||||||
|
Weighted average common shares outstanding:
|
||||||||||||||||||||
|
Basic
|
11,387 | 12,111 | 12,114 | 12,114 | 11,932 | |||||||||||||||
|
Diluted
|
11,643 | 12,111 | 12,141 | 12,148 | 12,039 | |||||||||||||||
|
(a)
|
The Company recorded a $32.1 million charge for impairment of property and equipment in the second quarter of 2009 and a $27 million charge in the fourth quarter of 2009. The Company recorded a $10 million charge for impairment of property and equipment in the third quarter of 2008 and a $2.9 million charge in the fourth quarter of 2008.
|
|
(b)
|
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.
|
15. 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, 2009, 2008 and 2007.
|
2009
|
2008
|
2007
|
||||||||||
|
|
(In thousands)
|
|||||||||||
|
Property acquisitions:
|
||||||||||||
|
Proved
|
$ | - | $ | - | $ | - | ||||||
|
Unproved
|
12,558 | 36,397 | 15,746 | |||||||||
|
Developmental costs
|
86,672 | 260,073 | 45,611 | |||||||||
|
Exploratory costs
|
32,758 | 51,237 | 169,879 | |||||||||
|
Total
|
$ | 131,988 | $ | 347,707 | $ | 231,236 | ||||||
F-25
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the capitalized costs for oil and gas properties as of December 31, 2009 and 2008.
|
2009
|
2008
|
|||||||
|
(In thousands)
|
||||||||
|
Proved properties
|
$ | 1,532,508 | $ | 1,435,718 | ||||
|
Unproved properties
|
47,156 | 90,755 | ||||||
|
Total capitalized costs
|
1,579,664 | 1,526,473 | ||||||
|
Accumulated depreciation, depletion and amortization
|
(945,047 | ) | (791,507 | ) | ||||
|
Net capitalized costs
|
$ | 634,617 | $ | 734,966 | ||||
16. Segment Information
We have two reportable operating segments, which are oil and gas exploration and production and contract drilling services. The following tables present selected financial information regarding our operating segments for 2009, 2008 and 2007.
|
Contract
|
Intercompany
|
Consolidated
|
||||||||||||||
|
For the Year Ended December 31, 2009
|
Oil and Gas
|
Drilling
|
Eliminations
|
Total
|
||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Revenues
|
$ | 249,280 | $ | 27,000 | $ | (20,319 | ) | $ | 255,961 | |||||||
|
Depreciation, depletion and amortization (a)
|
154,328 | 38,027 | (3,557 | ) | 188,798 | |||||||||||
|
Other operating expenses (b)
|
214,282 | 11,054 | (16,748 | ) | 208,588 | |||||||||||
|
Interest expense
|
22,267 | 1,491 | - | 23,758 | ||||||||||||
|
Other expense
|
14,873 | - | - | 14,873 | ||||||||||||
|
Loss before income taxes
|
(156,470 | ) | (23,572 | ) | (14 | ) | (180,056 | ) | ||||||||
|
Income tax benefit
|
(55,864 | ) | (8,232 | ) | - | (64,096 | ) | |||||||||
|
Net loss
|
(100,606 | ) | (15,340 | ) | (14 | ) | (115,960 | ) | ||||||||
|
Less (income) loss attributable to
|
||||||||||||||||
|
noncontrolling interest, net of tax
|
783 | (2,238 | ) | - | (1,455 | ) | ||||||||||
|
Net loss attributable to Clayton
|
||||||||||||||||
|
Williams Energy, Inc.
|
$ | (99,823 | ) | $ | (17,578 | ) | $ | (14 | ) | $ | (117,415 | ) | ||||
|
Total assets
|
$ | 773,631 | $ | 42,623 | $ | (31,650 | ) | $ | 784,604 | |||||||
|
Additions to property and equipment
|
$ | 133,860 | $ | 4,696 | $ | - | $ | 138,556 | ||||||||
F-26
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
Contract
|
Intercompany
|
Consolidated
|
||||||||||||||
|
For the Year Ended December 31, 2008
|
Oil and Gas
|
Drilling
|
Eliminations
|
Total
|
||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Revenues
|
$ | 514,686 | $ | 64,153 | $ | (13,322 | ) | $ | 565,517 | |||||||
|
Depreciation, depletion and amortization (a)
|
124,874 | 10,651 | (2,101 | ) | 133,424 | |||||||||||
|
Other operating expenses (b)
|
232,047 | 47,493 | (9,728 | ) | 269,812 | |||||||||||
|
Interest expense
|
21,134 | 3,860 | - | 24,994 | ||||||||||||
|
Other income
|
(81,282 | ) | - | - | (81,282 | ) | ||||||||||
|
Income (loss) before income taxes
|
217,913 | 2,149 | (1,493 | ) | 218,569 | |||||||||||
|
Income tax expense
|
76,546 | 781 | - | 77,327 | ||||||||||||
|
Net income (loss)
|
141,367 | 1,368 | (1,493 | ) | 141,242 | |||||||||||
|
Less (income) loss attributable to
|
||||||||||||||||
|
noncontrolling interest, net of tax
|
381 | (1,089 | ) | - | (708 | ) | ||||||||||
|
Net income (loss) attributable to Clayton
|
||||||||||||||||
|
Williams Energy, Inc.
|
$ | 141,748 | $ | 279 | $ | (1,493 | ) | $ | 140,534 | |||||||
|
Total assets
|
$ | 864,260 | $ | 85,006 | $ | (5,857 | ) | $ | 943,409 | |||||||
|
Additions to property and equipment
|
$ | 350,184 | $ | 1,195 | $ | (1,493 | ) | $ | 349,886 | |||||||
|
Contract
|
Intercompany
|
Consolidated
|
||||||||||||||
|
For the Year Ended December 31, 2007
|
Oil and Gas
|
Drilling
|
Eliminations
|
Total
|
||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Revenues
|
$ | 341,246 | $ | 64,551 | $ | (11,902 | ) | $ | 393,895 | |||||||
|
Depreciation, depletion and amortization (a)
|
82,240 | 16,060 | (1,687 | ) | 96,613 | |||||||||||
|
Other operating expenses (b)
|
192,334 | 39,138 | (8,220 | ) | 223,252 | |||||||||||
|
Interest expense
|
27,818 | 4,300 | - | 32,118 | ||||||||||||
|
Other expense
|
26,613 | - | - | 26,613 | ||||||||||||
|
Income (loss) before income taxes
|
12,241 | 5,053 | (1,995 | ) | 15,299 | |||||||||||
|
Income tax expense
|
3,305 | 2,192 | - | 5,497 | ||||||||||||
|
Net income (loss)
|
8,936 | 2,861 | (1,995 | ) | 9,802 | |||||||||||
|
Less (income) loss attributable to
|
||||||||||||||||
|
noncontrolling interest, net of tax
|
2,053 | (5,865 | ) | - | (3,812 | ) | ||||||||||
|
Net income (loss) attributable to Clayton
|
||||||||||||||||
|
Williams Energy, Inc.
|
$ | 10,989 | $ | (3,004 | ) | $ | (1,995 | ) | $ | 5,990 | ||||||
|
Total assets
|
$ | 753,480 | $ | 114,849 | $ | (7,233 | ) | $ | 861,096 | |||||||
|
Additions to property and equipment
|
$ | 235,679 | $ | 23,538 | $ | (1,995 | ) | $ | 257,222 | |||||||
|
(a)
|
Includes impairment of property and equipment.
|
|
(b)
|
Includes the following expenses: production, exploration, natural gas services, accretion of abandonment obligations, general and administrative and loss on sales of assets and impairment of inventory.
|
17. Guarantor Financial Information
In July 2005, CWEI (“Issuer”) issued $225 million of Senior Notes (see Note 3). All of the Issuer’s wholly-owned and active subsidiaries which have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes are referred to as “Guarantor Subsidiaries” in the following condensed consolidating financial statements. Prior to August 2009, neither Desta Drilling nor WCEP, LLC, the general partner of West Coast Energy Properties, L.P., an affiliated limited partnership, were guarantors of the Senior Notes, but in August 2009, Desta Drilling became a guarantor of the Senior Notes. As a result, we have reclassified the condensed consolidating financial statements prior to December 31, 2009 in this Note 17 to include the accounts of Desta Drilling in the Guarantor Subsidiaries column and to reflect only the accounts of WCEP, LLC in the Non-Guarantor Subsidiary column.
F-27
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The financial information on the following pages sets forth the Company’s condensed consolidating financial statements as of and for the periods indicated.
Condensed Consolidating Balance Sheet
December 31, 2009
|
(Dollars in thousands)
|
Non-
|
|||||||||||||||||||
|
Guarantor
|
Guarantor
|
Adjustments/
|
||||||||||||||||||
|
Issuer
|
Subsidiaries
|
Subsidiary
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Current assets
|
$ | 205,950 | $ | 146,443 | $ | 920 | $ | (249,716 | ) | $ | 103,597 | |||||||||
|
Property and equipment, net
|
326,149 | 337,566 | 6,331 | - | 670,046 | |||||||||||||||
|
Investments in subsidiaries
|
112,018 | - | - | (112,018 | ) | - | ||||||||||||||
|
Other assets
|
10,348 | 613 | - | - | 10,961 | |||||||||||||||
|
Total assets
|
$ | 654,465 | $ | 484,622 | $ | 7,251 | $ | (361,734 | ) | $ | 784,604 | |||||||||
|
Current liabilities
|
$ | 153,505 | $ | 180,357 | $ | 127 | $ | (249,716 | ) | $ | 84,273 | |||||||||
|
Non-current liabilities:
|
||||||||||||||||||||
|
Long-term debt
|
395,000 | - | - | - | 395,000 | |||||||||||||||
|
Other
|
31,039 | 61,883 | 136 | (2 | ) | 93,056 | ||||||||||||||
| 426,039 | 61,883 | 136 | (2 | ) | 488,056 | |||||||||||||||
|
Equity
|
74,921 | 242,382 | 6,988 | (112,016 | ) | 212,275 | ||||||||||||||
|
Total liabilities and equity
|
$ | 654,465 | $ | 484,622 | $ | 7,251 | $ | (361,734 | ) | $ | 784,604 | |||||||||
Condensed Consolidating Balance Sheet
December 31, 2008
|
(Dollars in thousands)
|
Non-
|
|||||||||||||||||||
|
Guarantor
|
Guarantor
|
Adjustments/
|
||||||||||||||||||
|
Issuer
|
Subsidiaries
|
Subsidiary
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Current assets
|
$ | 178,349 | $ | 188,538 | $ | 847 | $ | (242,250 | ) | $ | 125,484 | |||||||||
|
Property and equipment, net
|
388,189 | 415,220 | 6,619 | - | 810,028 | |||||||||||||||
|
Investments in subsidiaries
|
72,082 | - | - | (72,082 | ) | - | ||||||||||||||
|
Other assets
|
19,629 | 583 | - | (12,315 | ) | 7,897 | ||||||||||||||
|
Total assets
|
$ | 658,249 | $ | 604,341 | $ | 7,466 | $ | (326,647 | ) | $ | 943,409 | |||||||||
|
Current liabilities
|
$ | 83,288 | $ | 281,734 | $ | 105 | $ | (242,250 | ) | $ | 122,877 | |||||||||
|
Non-current liabilities:
|
||||||||||||||||||||
|
Long-term debt
|
319,100 | 40,225 | - | (12,100 | ) | 347,225 | ||||||||||||||
|
Other
|
95,619 | 57,302 | 113 | (3 | ) | 153,031 | ||||||||||||||
| 414,719 | 97,527 | 113 | (12,103 | ) | 500,256 | |||||||||||||||
|
Equity
|
160,242 | 225,080 | 7,248 | (72,294 | ) | 320,276 | ||||||||||||||
|
Total liabilities and equity
|
$ | 658,249 | $ | 604,341 | $ | 7,466 | $ | (326,647 | ) | $ | 943,409 | |||||||||
F-28
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Operations
Year Ended December 31, 2009
|
(Dollars in thousands)
|
Non-
|
|||||||||||||||||||
|
Guarantor
|
Guarantor
|
Adjustments/
|
||||||||||||||||||
|
Issuer
|
Subsidiaries
|
Subsidiary
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Total revenue
|
$ | 148,347 | $ | 108,098 | $ | 617 | $ | (1,101 | ) | $ | 255,961 | |||||||||
|
Costs and expenses
|
254,655 | 142,807 | 1,025 | (1,101 | ) | 397,386 | ||||||||||||||
|
Operating income (loss)
|
(106,308 | ) | (34,709 | ) | (408 | ) | - | (141,425 | ) | |||||||||||
|
Other income (expense)
|
(42,820 | ) | 4,043 | 146 | - | (38,631 | ) | |||||||||||||
|
Income tax (expense) benefit
|
64,096 | - | - | - | 64,096 | |||||||||||||||
|
Noncontrolling interest,
|
||||||||||||||||||||
|
net of tax
|
(1,455 | ) | - | - | - | (1,455 | ) | |||||||||||||
|
Net income (loss)
|
$ | (86,487 | ) | $ | (30,666 | ) | $ | (262 | ) | $ | - | $ | (117,415 | ) | ||||||
Condensed Consolidating Statement of Operations
Year Ended December 31, 2008
|
(Dollars in thousands)
|
Non-
|
|||||||||||||||||||
|
Guarantor
|
Guarantor
|
Adjustments/
|
||||||||||||||||||
|
Issuer
|
Subsidiaries
|
Subsidiary
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Total revenue
|
$ | 346,570 | $ | 237,307 | $ | 1,033 | $ | (19,393 | ) | $ | 565,517 | |||||||||
|
Costs and expenses
|
254,093 | 166,310 | 733 | (17,900 | ) | 403,236 | ||||||||||||||
|
Operating income (loss)
|
92,477 | 70,997 | 300 | (1,493 | ) | 162,281 | ||||||||||||||
|
Other income (expense)
|
65,414 | (9,362 | ) | 236 | - | 56,288 | ||||||||||||||
|
Income tax (expense) benefit
|
(77,327 | ) | - | - | - | (77,327 | ) | |||||||||||||
|
Noncontrolling interest,
|
||||||||||||||||||||
|
net of tax
|
(708 | ) | - | - | - | (708 | ) | |||||||||||||
|
Net income (loss)
|
$ | 79,856 | $ | 61,635 | $ | 536 | $ | (1,493 | ) | $ | 140,534 | |||||||||
Condensed Consolidating Statement of Operations
Year Ended December 31, 2007
|
(Dollars in thousands)
|
Non-
|
|||||||||||||||||||
|
Guarantor
|
Guarantor
|
Adjustments/
|
||||||||||||||||||
|
Issuer
|
Subsidiaries
|
Subsidiary
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Total revenue
|
$ | 224,743 | $ | 181,759 | $ | 690 | $ | (13,297 | ) | $ | 393,895 | |||||||||
|
Costs and expenses
|
198,535 | 132,046 | 587 | (11,303 | ) | 319,865 | ||||||||||||||
|
Operating income (loss)
|
26,208 | 49,713 | 103 | (1,994 | ) | 74,030 | ||||||||||||||
|
Other income (expense)
|
(46,373 | ) | (12,513 | ) | 155 | - | (58,731 | ) | ||||||||||||
|
Income tax (expense) benefit
|
(5,497 | ) | - | - | - | (5,497 | ) | |||||||||||||
|
Noncontrolling interest,
|
||||||||||||||||||||
|
net of tax
|
(3,812 | ) | - | - | - | (3,812 | ) | |||||||||||||
|
Net income (loss)
|
$ | (29,474 | ) | $ | 37,200 | $ | 258 | $ | (1,994 | ) | $ | 5,990 | ||||||||
F-29
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2009
|
(Dollars in thousands)
|
Non-
|
|||||||||||||||||||
|
Guarantor
|
Guarantor
|
Adjustments/
|
||||||||||||||||||
|
Issuer
|
Subsidiaries
|
Subsidiary
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Operating activities
|
$ | (28,867 | ) | $ | 129,934 | $ | 113 | $ | 3,531 | $ | 104,711 | |||||||||
|
Investing activities
|
(186,872 | ) | 21,872 | (67 | ) | (3,531 | ) | (168,598 | ) | |||||||||||
|
Financing activities
|
192,197 | (155,516 | ) | 20 | - | 36,701 | ||||||||||||||
|
Net increase (decrease) in
|
||||||||||||||||||||
|
cash and cash equivalents
|
(23,542 | ) | (3,710 | ) | 66 | - | (27,186 | ) | ||||||||||||
|
Cash at the beginning of
|
||||||||||||||||||||
|
the period
|
35,381 | 5,054 | 764 | - | 41,199 | |||||||||||||||
|
Cash at end of the period
|
$ | 11,839 | $ | 1,344 | $ | 830 | $ | - | $ | 14,013 | ||||||||||
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2008
|
(Dollars in thousands)
|
Non-
|
|||||||||||||||||||
|
Guarantor
|
Guarantor
|
Adjustments/
|
||||||||||||||||||
|
Issuer
|
Subsidiaries
|
Subsidiary
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Operating activities
|
$ | 319,182 | $ | 59,737 | $ | 960 | $ | 2,101 | $ | 381,980 | ||||||||||
|
Investing activities
|
(126,079 | ) | (110,366 | ) | (329 | ) | (2,101 | ) | (238,875 | ) | ||||||||||
|
Financing activities
|
(163,047 | ) | 48,797 | - | - | (114,250 | ) | |||||||||||||
|
Net increase (decrease) in
|
||||||||||||||||||||
|
cash and cash equivalents
|
30,056 | (1,832 | ) | 631 | - | 28,855 | ||||||||||||||
|
Cash at the beginning of
|
||||||||||||||||||||
|
the period
|
5,325 | 6,886 | 133 | - | 12,344 | |||||||||||||||
|
Cash at end of the period
|
$ | 35,381 | $ | 5,054 | $ | 764 | $ | - | $ | 41,199 | ||||||||||
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2007
|
(Dollars in thousands)
|
Non-
|
|||||||||||||||||||
|
Guarantor
|
Guarantor
|
Adjustments/
|
||||||||||||||||||
|
Issuer
|
Subsidiaries
|
Subsidiary
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
Operating activities
|
$ | 149,216 | $ | 83,299 | $ | 664 | $ | 1,687 | $ | 234,866 | ||||||||||
|
Investing activities
|
(189,626 | ) | (44,842 | ) | (604 | ) | (1,187 | ) | (236,259 | ) | ||||||||||
|
Financing activities
|
39,620 | (39,223 | ) | - | (500 | ) | (103 | ) | ||||||||||||
|
Net increase (decrease) in
|
||||||||||||||||||||
|
cash and cash equivalents
|
(790 | ) | (766 | ) | 60 | - | (1,496 | ) | ||||||||||||
|
Cash at the beginning of
|
||||||||||||||||||||
|
the period
|
6,116 | 7,651 | 73 | - | 13,840 | |||||||||||||||
|
Cash at end of the period
|
$ | 5,326 | $ | 6,885 | $ | 133 | $ | - | $ | 12,344 | ||||||||||
18. Subsequent Events
We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2009. We did not have any material subsequent events that would require recognition in the financial statements or disclosures in these notes to the consolidated financial statements.
F-30
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
19. Oil and Gas Reserve Information (Unaudited)
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 SEC 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.
In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the FASB adopted conforming changes to 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:
|
·
|
amends the definition of proved reserves to require the use of average commodity prices based upon the prior 12-month period rather than year-end prices;
|
|
·
|
expands the type of technologies available to establish reserve estimates and categories;
|
|
·
|
modifies certain definitions used in estimating proved reserves;
|
|
·
|
permits disclosure of probable and possible reserves;
|
|
·
|
requires disclosure of internal controls over reserve estimations and the qualifications of technical persons primarily responsible for the preparation or audit of reserve estimates;
|
|
·
|
permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts; and
|
|
·
|
requires disclosure of material changes in proved undeveloped reserves, including a discussion of investments and progress made to convert proved undeveloped reserves to proved developed reserves.
|
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.
The following table sets forth estimated proved oil and gas reserves together with the changes therein (oil in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended December 31, 2009, 2008 and 2007.
|
Oil
|
Gas
|
MBOE
|
||||||||||
|
Proved reserves:
|
||||||||||||
|
December 31, 2006
|
25,381 | 119,167 | 45,242 | |||||||||
|
Revisions
|
3,194 | 1,761 | 3,488 | |||||||||
|
Extensions and discoveries
|
1,902 | 23,533 | 5,824 | |||||||||
|
Purchases of minerals-in-place
|
- | (624 | ) | (104 | ) | |||||||
|
Production
|
(2,531 | ) | (20,681 | ) | (5,978 | ) | ||||||
|
December 31, 2007
|
27,946 | 123,156 | 48,472 | |||||||||
|
Revisions
|
(5,620 | ) | (15,938 | ) | (8,276 | ) | ||||||
|
Extensions and discoveries
|
2,057 | 23,824 | 6,028 | |||||||||
|
Purchases of minerals-in-place
|
(473 | ) | (8,560 | ) | (1,900 | ) | ||||||
|
Production
|
(3,134 | ) | (18,553 | ) | (6,226 | ) | ||||||
|
December 31, 2008
|
20,776 | 103,929 | 38,098 | |||||||||
|
Revisions
|
297 | (15,898 | ) | (2,353 | ) | |||||||
|
Extensions and discoveries
|
2,985 | 4,021 | 3,655 | |||||||||
|
Production
|
(3,105 | ) | (15,949 | ) | (5,763 | ) | ||||||
|
December 31, 2009
|
20,953 | 76,103 | 33,637 | |||||||||
|
Proved developed reserves:
|
||||||||||||
|
December 31, 2007
|
20,627 | 98,434 | 37,033 | |||||||||
|
December 31, 2008
|
16,815 | 87,340 | 31,372 | |||||||||
|
December 31, 2009
|
16,779 | 70,840 | 28,586 | |||||||||
F-31
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. Net upward revisions of 67 MBOE were attributable to the effects of higher product prices on the estimated quantities of proved reserves.
The standardized measure of discounted future net cash flows relating to estimated proved reserves as of December 31, 2009, 2008 and 2007 was as follows:
|
2009
|
2008
|
2007
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Future cash inflows
|
$ | 1,311,330 | $ | 1,374,684 | $ | 3,363,271 | ||||||
|
Future costs:
|
||||||||||||
|
Production
|
(588,564 | ) | (569,053 | ) | (999,945 | ) | ||||||
|
Development
|
(86,918 | ) | (104,223 | ) | (174,264 | ) | ||||||
|
Income taxes
|
(119,343 | ) | (126,819 | ) | (653,808 | ) | ||||||
|
Future net cash flows
|
516,505 | 574,588 | 1,535,254 | |||||||||
|
10% discount factor
|
(152,232 | ) | (169,423 | ) | (609,285 | ) | ||||||
|
Standardized measure of discounted net cash flows
|
$ | 364,273 | $ | 405,166 | $ | 925,969 | ||||||
Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended December 31, 2009, 2008 and 2007 were as follows:
|
2009
|
2008
|
2007
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Standardized measure, beginning of period
|
$ | 405,166 | $ | 925,969 | $ | 514,800 | ||||||
|
Net changes in sales prices, net of production costs
|
12,007 | (600,719 | ) | 483,032 | ||||||||
|
Revisions of quantity estimates
|
(34,419 | ) | (101,889 | ) | 82,451 | |||||||
|
Accretion of discount
|
51,123 | 131,824 | 70,844 | |||||||||
|
Changes in future development costs, including
|
||||||||||||
|
development costs incurred that reduced future
|
||||||||||||
|
development costs
|
33,217 | 69,466 | 2,665 | |||||||||
|
Changes in timing and other
|
(31,567 | ) | (9,385 | ) | 24,497 | |||||||
|
Net change in income taxes
|
15,457 | 299,193 | (203,369 | ) | ||||||||
|
Future abandonment cost, net of salvage
|
(5,075 | ) | (548 | ) | (4,204 | ) | ||||||
|
Extensions and discoveries
|
89,546 | 155,006 | 197,219 | |||||||||
|
Sales, net of production costs
|
(171,182 | ) | (373,988 | ) | (240,733 | ) | ||||||
|
Sales of minerals-in-place
|
- | (89,763 | ) | (1,233 | ) | |||||||
|
Standardized measure, end of period.
|
$ | 364,273 | $ | 405,166 | $ | 925,969 | ||||||
The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period. The average prices used for each commodity for the years ended December 31, 2009, 2008 and 2007 were as follows:
|
Average Price
|
||||||||
|
Oil (a)
|
Gas
|
|||||||
|
As of December 31:
|
||||||||
|
2009 (b)
|
$ | 54.81 | $ | 3.71 | ||||
|
2008
|
$ | 42.03 | $ | 5.90 | ||||
|
2007
|
$ | 91.30 | $ | 7.37 | ||||
(a) Includes natural gas liquids.
(b) Average prices for 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.
F-32
|
Schedule II – Valuation and Qualifying Accounts
|
||||||||||||||||
|
Balance at
|
Balance at
|
|||||||||||||||
|
Beginning of
|
End of
|
|||||||||||||||
|
Description
|
Period
|
Additions(a)
|
Deductions(b)
|
Period
|
||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Year Ended December 31, 2009:
|
||||||||||||||||
|
Allowance for doubtful accounts - Joint interest and other
|
$ | 1,387 | $ | - | $ | (114 | ) | $ | 1,273 | |||||||
|
Year Ended December 31, 2008:
|
||||||||||||||||
|
Allowance for doubtful accounts - Joint interest and other
|
$ | 1,387 | $ | - | $ | - | $ | 1,387 | ||||||||
|
Year Ended December 31, 2007:
|
||||||||||||||||
|
Allowance for doubtful accounts - Joint interest and other
|
$ | 1,044 | $ | 343 | $ | - | $ | 1,387 | ||||||||
|
(a) Additions relate to provisions for doubtful accounts.
|
||||||||||||||||
|
(b) Deductions relate to the write-off or recovery of the provisions for doubtful accounts.
|
||||||||||||||||
S-1