UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) |
| OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the fiscal year ended December 31, 2005 |
| | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) |
| OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from to |
| Commission File Number 001-10924 |
CLAYTON WILLIAMS ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware | | 75-2396863 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | |
Six Desta Drive - Suite 6500 | | |
Midland, Texas | | 79705-5510 |
(Address of principal executive offices) | | (Zip code) |
| | |
Registrant’s telephone number, including area code: | | (432) 682-6324 |
| | |
Securities registered pursuant to Section 12(b) of the Act: |
| | |
None |
| | |
Securities registered pursuant to Section 12(g) of the Act: |
| | |
Common Stock - $.10 Par Value |
(Title of Class) |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes ý No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
o Yes ý No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ý No o
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. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer ý Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes ý No
State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter. $186,312,403.
There were 10,848,450 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 14, 2006.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement relating to the 2006 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2006, are incorporated by reference in Part III of this Form 10-K.
CLAYTON WILLIAMS ENERGY, INC
TABLE OF CONTENTS
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This Annual Report on Form 10-K contains forward-looking statements that are based on management’s current expectations. Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions. Forward-looking statements appear throughout this Form 10-K with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Item 1 – Business – Risk Factors” and elsewhere in this report. We disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
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
General
Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, Louisiana and New Mexico. Unless the context otherwise requires, references to the “Company”, “CWEI”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. On December 31, 2005, our estimated proved reserves were 293.8 Bcfe, of which 75% were proved developed. We have a balanced portfolio of oil and natural gas reserves, with approximately 43% of our proved reserves at December 31, 2005 consisting of natural gas and approximately 57% consisting of oil and natural gas liquids. During 2005, we added proved reserves of 17.7 Bcfe through extensions and discoveries, had upward revisions of previous estimates of 7.8 Bcfe, acquired 4.2 Bcfe through acquisitions and sold 3.5 Bcfe of reserves in place. We also achieved average net production of 86.1 Mmcfe per day in 2005, which implies a reserve life of approximately 9.3 years. CWEI held interests in 6,605 gross (899.7 net) producing oil and gas wells and owned leasehold interests in approximately 1.2 million gross (778,000 net) undeveloped acres at December 31, 2005.
Clayton W. Williams beneficially owns, either individually or through his affiliates, approximately 45% 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.
In 2006, we plan to spend approximately $184.1 million on exploration and development activities, of which more than 90% relate to exploratory prospects. Approximately 78% of these planned expenditures in 2006 have been allocated to exploration and development activities in Louisiana.
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Company Profile
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 primary business strategy is to grow our oil and gas reserves through exploration activities, consisting of generating exploratory prospects, leasing the acreage applicable 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 (i) the reservoir drive mechanism (water drive, depletion drive or a combination of both), (ii) the permeability and porosity of the reservoir, and (iii) the bottom hole pressure (in the case of gas reserves).
Due to the high risk/high reward 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.
We are presently concentrating our exploration efforts in South Louisiana, North Louisiana and East Texas. Approximately 90% of our planned expenditures for 2006 relate to exploratory prospects, as compared to approximately 73% of actual expenditures in 2005 and 81% of actual expenditures in 2004. During 2005, we spent $134.6 million on exploratory prospects, including $55.7 million on seismic and leasing activities and $78.9 million on drilling activities.
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Development Program
Complimentary to our higher risk/higher potential exploration program is our development program. We have an inventory of developmental projects available for drilling in the future. At December 31, 2005, we had proved developed nonproducing reserves and proved undeveloped reserves of 104.8 Bcfe. We currently estimate that we will be required to spend approximately $161.9 million in development costs to develop these reserves. Substantially all of these reserves are associated with leases that are held by production. Because current drilling activity is not required to maintain these leases, we have decided to limit expenditures on our developmental program in 2006 in order to preserve more capital resources for our exploratory activities in areas where we have leases that will expire unless commercial production is commenced before the end of their current lease terms. We expect to allocate a more significant portion of our capital expenditures to development activities in years after 2006.
Acquisition and Divestitures of Proved Properties
In addition to our exploration and development activities, we are also engaged in the business of acquiring proved reserves. 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, because the competition is intense, we cannot give any assurance that we will be successful in our efforts during 2006.
In 2005, we acquired a property in Ward County, Texas which consisted of ten producing wells and eight proved undeveloped locations. This acquisition added approximately 4.2 Bcfe of proved reserves for a purchase price of $5.6 million.
On May 21, 2004, we acquired all the outstanding common stock of Southwest Royalties, Inc. (“SWR”) through a merger. Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, production, development and acquisition activities in the United States. Most of SWR’s properties are located in the Permian Basin. Using reserve guidelines established by the SEC, the SWR acquisition added approximately 170.8 Bcfe to our proved oil and gas reserves on the effective date of the acquisition at an aggregate purchase price of $274.7 million.
From time to time, we decide to sell certain of our proved properties. In August 2005, we sold our interests in two leases in the Breton Sound area in the Gulf of Mexico (offshore Louisiana) for $21.3 million, subject to post-closing adjustments and realized a gain of $16.8 million on this sale. In November 2004, we sold our interest in the Jo-Mill Unit in Borden County, Texas for cash proceeds of $22.1 million, subject to normal post-closing adjustments. This property was acquired in connection with the SWR acquisition. We realized a gain on sale of this property of $2.1 million. In December 2004, we sold substantially all of our interests in the Romere Pass Unit in Plaquemines Parish, Louisiana for cash proceeds of $8.2 million, subject to normal post-closing adjustments. We retained drilling rights to five locations in the unit, of which two are proved undeveloped locations and three are exploratory locations. We realized a loss of $14.1 million on the sale of this property.
Exploration and Development Activities
In 2005, we spent $184.1 million on exploration and drilling activities, which was financed primarily by cash flow from operations and in part by proceeds from sales of oil and gas properties. We presently plan to spend approximately $184.1 million on exploration and drilling activities during 2006. We may increase or decrease our planned activities, depending upon drilling results, product prices, the availability of capital resources, and other factors affecting the economic viability of such activities.
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South Louisiana
Since 2000, we have been exploring for oil and gas reserves in South Louisiana and have developed this area into one of our key sources of production and cash flow. Most of the prospects we have generated in South Louisiana have been identified based on 3-D seismic data and technology and have generally consisted of multi-pay, Miocene-age sands.
We spent $41.2 million in South Louisiana during 2005 on exploration and development activities, of which $32.8 million was spent on drilling and completion activities and $8.4 million was spent on seismic and leasing activities.
Prior to 2005, we had drilled 47 gross (37.7 net) exploratory wells in South Louisiana, of which 20 gross (14.7 net) were completed as producers. The following table sets forth certain information about our exploratory well activities in South Louisiana in 2005.
Spud Date | | Well Name (Prospect) | | Working
Interest | | Current
Status |
| | | | | | |
February 2005 | | State Lease 18065 #1 (Alabama) | | 100 | % | Producing |
July 2005 | | Ransom #1 (Keck) | | 50 | % | Producing |
August 2005 | | State Lease 17636 #1 (Natalie) | | 30 | % | Dry |
August 2005 | | LL&E #1 (Andrea) | | 70 | % | Dry |
November 2005 | | Miami Corp #1 (Tara) | | 100 | % | Pending completion |
December 2005 | | State lease 195 QQ #1 (Floyd) | | 75 | % | Completion in progress |
More than half of the wells in our South Louisiana exploration program that were commenced in 2005 were productive and resulted in the addition of approximately 8.7 Bcfe of proved reserves in 2005. However, the LL&E #1 (Andrea) and the State Lease 17636 #1 (Natalie) were unsuccessful and resulted in aggregate abandonment charges of $10.7 million in 2005.
We currently plan to spend $56.3 million in South Louisiana in 2006 to generate and lease new exploratory prospects and to drill wells on existing exploratory prospects. We have begun a six-well program on our Floyd prospect in Plaquemines Parish targeting multi-pay objectives ranging in depths from 3,000 to 13,000 feet. The State Lease 195 QQ #1 was drilled to a total depth of 12,981 feet and is currently being completed. The State Lease 195 QQ #2 has been drilled to a total depth of 6,296 feet and is pending completion. The State Lease 195 QQ #3 has been drilled to a total depth of 9,170 feet, and is also pending completion. The State Lease 195 QQ #4 is currently drilling. Under the terms of a farmout agreement, we bear 100% of the costs on these wells before casing point to earn a 75% working interest in the drilled acreage.
We are currently drilling the Borah #1 (Cypress Isle), a 17,000-foot exploratory well in St. Martin Parish targeting the MA-11 and MA-12 sands, in which we own a 75% working interest.
North Louisiana
We have begun an exploration program in North Louisiana targeting the Cotton Valley/Hosston and Bossier formations. In this area, the Cotton Valley/Hosston 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. We believe that these tight sandstone formations have become more economically viable due to higher product prices, coupled with enhanced drilling and completion techniques.
We spent $18.9 million in North Louisiana during 2005 on exploration activities, of which $16.8 million was spent on seismic and leasing activities and $2.1 million was spent on drilling and completion activities on non-operated wells.
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We have accumulated more than 115,000 net acres in this area, and to date have participated in six non-operated wells on a small portion of this acreage, four of which are currently being completed and two are in progress. We are currently drilling the Harris #1, a 14,500-foot well in Jackson Parish targeting the Bossier formation, in which we own a 53% working interest. We plan to spend approximately $87.9 million in North Louisiana in 2006, consisting of $17.2 million to acquire leases and conduct seismic and exploration activities, and $70.7 million on drilling.
East Texas (Bossier)
We have also begun acquiring leases in East Texas targeting the Bossier formation which is encountered at depths ranging from 14,000 to 22,000 feet in this area. To date, we have acquired approximately 28,000 net acres and are actively seeking to add to our acreage position. We spent $4.9 million on acreage in East Texas in 2005 and plan to spend approximately $20 million for additional acreage in 2006. We anticipate drilling activity on this acreage to begin in 2007.
Permian Basin
We spent $84.5 million in the Permian Basin during 2005 on exploration and development activities, of which $74.5 million was spent on drilling and completion activities and $10 million was spent on seismic and leasing activities.
In 2005, we initiated an exploration program in West Texas seeking to extend the limits of the Wolfcamp formation that is encountered throughout a large segment of this region. We acquired more than 50,000 net acres and have drilled 11 wells across a wide portion of this acreage. While all of the wells were completed as producers, the oil and gas reserves derived from this drilling program were inadequate to recover our capitalized costs. As a result, we recorded an $18.3 million charge for impairment of proved properties and a $1.8 million charge for impairment of unproved property in 2005 related to our Wolfcamp program.
We also drilled the Leoncita #1, a 9,300-foot exploratory well in Pecos County, Texas targeting the Barnett Shale. This well was unsuccessful and resulted in a $4.5 million charge to exploration costs in 2005.
In addition, we drilled 24 gross (20.2 net) wells in the Permian Basin and conducted remedial operations on existing wells in 2005. While some of the drilling activities in 2005 did not result in the quantities of oil and gas reserves that we had expected, the Permian Basin continues to be a significant source of production and cash flow for us. We currently plan to spend $6.7 million on drilling activities in the Permian Basin in 2006.
Montana/Utah
We spent $11.8 million in Montana and Utah during 2005 on seismic and leasing activities. We initiated an exploration program in Sheridan County, Montana targeting the Bakken Shale which is encountered at depths ranging from 7,000 to 8,000 feet in this area. We are currently drilling the Ruegsegger 24H #1, an exploratory well which we plan to drill to a vertical depth of 7,600 feet, then drill 3,600 feet horizontally through the shale formation. We plan to spend approximately $3.5 million for drilling in this area in 2006.
In addition, we are participating in a joint exploration program with industry partners in the Overthrust play in central Utah in which we own a 33% interest. In 2006, we plan to spend approximately $2.5 million to participate in the drilling of a 14,400-foot exploratory well to test this acreage.
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Other Exploration and Development Activities
During 2005, we spent $22.8 million on exploration and development activities in other areas, including:
• $8 million in South Texas to drill the Deer-Hamilton #1 well, a 17,000-foot exploratory well in Nueces County targeting the Vicksburg formation, which was unsuccessful;
• $2.2 million of drilling activities related to the Catherine Destefano #1 well, a 14,600-foot exploratory well in Robertson County, Texas targeting the Knowles formation, which was unsuccessful; and
• $3.4 million in leasing activities in the Neal Shale prospect in Alabama.
In 2006, we currently plan to spend $7.2 million in other areas, including:
• $4.1 million for leasing and production enhancement activities in the Austin Chalk (Trend); and
• $3.1 million for leasing and drilling activities in Colorado and other areas.
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.
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
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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.
Regulation
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 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. 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.
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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 or in connection with drilling activities, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production, restrict or prohibit drilling 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 exploring for, developing, producing or processing oil and gas and may prevent or delay the commencement or continuation of a given project and thus generally could have a material 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 will 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 2006. 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 operating, as well as the oil and gas industry in general. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas production wastes as “hazardous wastes,” which reclassification would make exploration and production wastes subject to much more stringent handling, disposal and clean-up requirements. State initiatives to further regulate the disposal of oil and gas wastes and naturally occurring radioactive materials, if adopted, could have a similar impact on us.
The United States Oil Pollution Act of 1990 (“OPA ‘90”), and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA ‘90 and such similar legislation and related regulations impose on us a variety of obligations related to the prevention of oil spills and liability for damages resulting from such spills. OPA ‘90 imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil removal costs and a variety of public and private damages.
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
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neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.
The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws govern the handling and disposal of hazardous and solid wastes. Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal and reporting requirements. 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 EPA or state agencies as solid waste. 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.
The Clean Air Act, and comparable state and local requirements, contain provisions that may result in the imposition of pollution control requirements with respect to air emissions from certain of our operations. 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.
State water discharge regulations and federal waste discharge permitting requirements adopted pursuant to the Federal Water Pollution Control Act prohibit or are expected in the future to prohibit the discharge of produced water and sand and some other substances related to the oil and gas industry, into coastal waters. Although the costs to comply with such mandates under state or federal law may be significant, the entire industry will experience similar costs, and we do not believe that these costs will have a material adverse impact on our financial condition and operations.
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 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
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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.
Executive Officers
The following is a list, as of March 16, 2006 of the name, age and position with the Company of each person who is an executive officer of the Company:
CLAYTON W. WILLIAMS, age 74, 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 director of certain entities which are controlled directly or indirectly by Mr. Williams.
L. PAUL LATHAM, age 54, is Executive Vice President, Chief Operating Officer and a director of the Company, having served in such capacities since September 1991. Mr. Latham also serves as an officer and director of certain entities controlled by Mr. Williams.
MEL G. RIGGS, age 51, 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 53, is Vice President – New Ventures of the Company, having served in such capacity since 1993.
ROBERT C. LYON, age 69, is Vice President – Gas Gathering and Marketing of the Company, having served in such capacity since 1993.
MICHAEL L. POLLARD, age 56, 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 49, is Vice President and General Counsel of the Company, having served in such capacity since 1993.
GREGORY S. WELBORN, age 32, is Vice President – Land of the Company, having served in such capacity since 2006.
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Employees
At December 31, 2005, we had 174 full-time employees, none of whom is subject to a collective bargaining agreement. In our opinion, our relations with employees are good.
Website Address
The Company maintains an internet website at www.claytonwilliams.com. The Company makes available, free of charge, on its website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. The information contained in or incorporated in our website is not part of this report.
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.
Our exploration activities subject us to greater risks than development activities.
For 2006, approximately 90% of our planned capital expenditures relate to exploratory prospects. Exploration is a higher risk activity than development. 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.
Because 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 charged to expense $40 million in 2005 for abandonment and impairment, most of which was related to unsuccessful exploratory drilling activities in South Louisiana, the Black Warrior Basin of Mississippi and the Cotton Valley/Knowles area of East Texas. 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.
If we do not replace reserves we produce, our financial results will suffer.
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, 2005 is approximately 9.3 years, based on 2005 production levels.
Our oil and gas reserves will decline as they are produced unless we are able to conduct successful exploration and development activities or acquire properties with proved reserves. Because we are
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engaged to a large extent in exploration activities, our ability to replace produced reserves is subject to a higher level of risk than when we were drilling development wells in the Austin Chalk (Trend).
Volatility of oil and gas prices significantly affects our cash flow and capital resources and our ability to produce oil and gas economically.
Historically, the markets for oil and gas have been volatile, and we believe that they are likely to continue to be volatile. Significant changes in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control. We cannot predict, with any degree of certainty, future oil and natural gas prices. Changes in oil and natural gas prices significantly affect our revenues, operating results, profitability and the value of our oil and gas reserves. Those prices also affect the amount of cash flow available for capital expenditures, our ability to borrow money or raise additional capital and the amount of oil and natural gas that we can produce economically. The amount we can borrow under our senior revolving credit facility is subject to periodic redeterminations based in part on current prices for oil and natural gas at the time of the redetermination.
Changes in oil and gas prices impact both our estimated future net revenue and the estimated quantity of proved reserves. Price increases may permit additional quantities of reserves to be produced economically, and price decreases may render uneconomic the production of reserves previously classified as proved. Thus, we may experience material increases and decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance. We attempt to optimize the price we receive for our oil and gas production while maintaining a prudent hedging program to mitigate our exposure to declining product prices. Our management may elect to enter into and terminate hedges based on expectations of future market conditions. If prices continue to rise while our hedges are in place, we will forego revenue we would have otherwise received. If we terminate a hedge because we anticipate an increase in product prices that we would not realize with the hedge in place, and product prices do not increase as anticipated, we may be exposed to downside risk that would not have existed otherwise.
Our liquidity, including the availability of capital resources, is uncertain.
Our cash flow forecasts indicate that the amount of funds available to us under our revolving credit facility, when combined with our anticipated operating cash flow, will be sufficient to finance our capital expenditures and will provide us with adequate liquidity at least through 2006. Although we believe the assumptions and estimates made in our forecasts are reasonable, uncertainties exist which could cause the borrowing base to be less than expected, cash flow to be less than expected, or capital expenditures to be more than expected. Below is a discussion of uncertainties that are likely to have a material effect on our liquidity and capital resources if such uncertainties occur.
Adverse changes in reserve estimates or commodity prices could reduce the borrowing base. The banks establish the borrowing base at least twice annually by preparing a reserve report using price-risk assumptions they believe are proper under the circumstances. Any adverse changes in estimated quantities of reserves, the pricing parameters being used, or the risk factors being applied, since the date of the last borrowing base determination, could lower the borrowing base under the revolving credit facility.
Adverse changes in reserve estimates or commodity prices could reduce our cash flow from operating activities. We rely on estimates of reserves to forecast our cash flow from operating activities. If the production from those reserves is delayed or is lower than expected, our cash flow from operating activities may be lower than we anticipated. Commodity prices also impact our cash flow from operating activities. Based on December 31, 2005 reserve estimates, we project that a $1.00 drop in oil price and a $.50 drop in gas price would reduce our gross revenues in 2006 by approximately $2.3 million and $8.7 million, respectively.
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Adverse changes in the borrowing base may cause outstanding debt to equal or exceed the borrowing base. In this event, we will not be able to borrow any additional funds, and we will be required to repay the excess or convert the debt to a term note. Without availability under the revolving credit facility, we may be unable to meet our obligations as they mature.
Delays in bringing successful wells on production may reduce our liquidity. As a general rule, we experience a significant lag time between the initial cash outlay on a prospect and the inclusion of any value for such prospect in the borrowing base under the revolving credit facility. Until a well is on production, the banks may assign only a minimal borrowing base value to the well, and cash flows from the well are not available to fund our operating expense. Delays in bringing wells on production may reduce the borrowing base significantly, depending on the amounts borrowed and the length of the delays.
Hedging transactions may limit our potential gains and involve other risks.
From time to time, we use commodity derivatives, consisting of “swaps,” “collars” and “floors,” to attempt to optimize the price we receive for the sale of our oil and natural gas production. When using swaps to hedge our oil and natural gas production, we receive a fixed price for the hedged 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 at the settlement date. Collars are a combination of options that provide us with a put option (fixed floor price) in exchange for a call option (fixed ceiling price). If the market price for the hedged commodity exceeds the fixed ceiling price or falls below the fixed floor price, then we receive the fixed price and pay the market price. If the market price is between the fixed floor and the fixed ceiling prices, then no payments are due from either party. In addition, we may purchase put options in which we pay the counterparty the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed floor price over the floating market price.
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.
Information concerning our reserves and future net revenues estimates is inherently uncertain.
The accuracy of proved reserves estimates and estimated future net revenues 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 write down 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 reserve reporting requirements of the SEC, the
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estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. 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 our banks in establishing the borrowing base under our senior revolving credit facility and by our engineers for use in developing business plans and making various decisions. Such estimates may vary significantly from those of the independent engineers and have a material effect upon our business decisions and available capital resources.
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.
We plan to continue 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.
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:
• unexpected drilling conditions;
• title problems;
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• pressure or irregularities in formations;
• equipment failures or accidents;
• adverse weather conditions;
• compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and
• costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment and services.
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, 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 operation, operations which could result in 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 assure you of the continued availability of insurance at premium levels that justify its purchase.
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 and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.
A shortage 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
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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 personnel, none of whom are currently subject to an employment contract. 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 our principal stockholder.
Clayton W. Williams beneficially owns, either individually or through his affiliates, approximately 45% of the outstanding shares of our common stock. Mr. Williams is also the 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 board members, and in management decisions. Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Williams, or any change in the power to vote his shares, 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 assure you that we will not suffer any economic loss related to credit risks in the future.
Compliance with environmental and other government regulations 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,
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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 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. 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.
Our exploration and production 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
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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.
Item 1B - Unresolved Staff Comments
Not applicable.
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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, 2005, we had interests in 6,605 gross (899.7 net) oil and gas wells and owned leasehold interests in approximately 1.2 million gross (778,000 net) undeveloped acres.
Reserves
The following table sets forth certain information as of December 31, 2005 with respect to our estimated proved oil and gas reserves pursuant to SEC guidelines, present value of proved reserves and standardized measure of discounted future net cash flows.
| | Proved Developed | | Proved
Undeveloped | | Total
Proved | |
Producing | | Nonproducing |
| | (Dollars in thousands) | |
| | | | | | | | | |
Gas (MMcf) | | 74,209 | | 17,157 | | 35,392 | | 126,758 | |
Oil and natural gas liquids (MBbls) | | 19,120 | | 2,382 | | 6,333 | | 27,835 | |
Total (MMcfe) | | 188,929 | | 31,449 | | 73,390 | | 293,768 | |
Present value of proved reserves (a) | | | | | | | | $ | 1,117,886 | |
Standardized measure of discounted future net cash flows | | | | | | | | $ | 753,712 | |
(a) We believe that the present value of proved reserves (a non-GAAP measure) is a useful supplemental disclosure to the standardized measure of discounted future net cash flows. 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. Standardized measure of discounted future net cash flows differs from the present value of proved reserves by the amount of estimated future income taxes and net abandonment costs. Estimated future income taxes and future net abandonment costs (discounted at 10%) as of December 31, 2005 were $352.6 million and $11.6 million, respectively.
The following table sets forth certain information as of December 31, 2005 regarding our proved oil and gas reserves in each of our principal producing areas.
| |
Proved Reserves
| | Percent of
Total Gas
Equivalent | | Present
Value of
Proved
Reserves | | Percent
of Present
Value of
Proved
Reserves | |
Oil (a)
(MBbls) | | Gas
(MMcf) | | Total Gas
Equivalent
(MMcfe) |
| | | | | | | | | | (In thousands) | | | |
| | | | | | | | | | | | | |
Permian Basin (b) | | 18,504 | | 79,466 | | 190,490 | | 64.8 | % | $ | 575,616 | | 51.5 | % |
Louisiana | | 1,667 | | 20,883 | | 30,885 | | 10.5 | % | 226,603 | | 20.3 | % |
Austin Chalk (Trend) | | 7,467 | | 6,234 | | 51,036 | | 17.4 | % | 178,972 | | 16.0 | % |
Cotton Valley | | | | | | | | | | | | | |
Reef Complex | | — | | 15,396 | | 15,396 | | 5.3 | % | 97,388 | | 8.7 | % |
Other | | 197 | | 4,779 | | 5,961 | | 2.0 | % | 39,307 | | 3.5 | % |
Total | | 27,835 | | 126,758 | | 293,768 | | 100.0 | % | $ | 1,117,886 | | 100.0 | % |
(a) Includes natural gas liquids.
(b) Primarily West Texas and New Mexico.
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The estimates of proved reserves at December 31, 2005 and the present value of proved reserves were derived from reports prepared by Williamson Petroleum Consultants, Inc., independent petroleum engineers and Ryder Scott Company, L.P., petroleum consultants. The following table summarizes the reserve estimates derived from each report.
| | Proved Developed | | Proved
Undeveloped | | Total
Proved | |
Producing | | Nonproducing |
| | (Dollars in thousands) | |
Williamson Petroleum Consultants, Inc.: | | | | | | | | | |
| | | | | | | | | |
Gas (MMcf) | | 34,090 | | 10,036 | | 10,660 | | 54,786 | |
Oil and natural gas liquids (MBbls) | | 8,256 | | 833 | | 2,375 | | 11,464 | |
| | | | | | | | | |
Ryder Scott Company, L.P.: | | | | | | | | | |
| | | | | | | | | |
Gas (MMcf) | | 40,119 | | 7,121 | | 24,732 | | 71,972 | |
Oil and natural gas liquids (MBbls) | | 10,864 | | 1,549 | | 3,958 | | 16,371 | |
Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our hedging activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense or to depletion, depreciation and amortization.
In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the present value of proved reserves set forth herein are made using oil and gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and gas prices. The average prices utilized for the purposes of estimating our proved reserves and the present value of proved reserves as of December 31, 2005 were $57.85 per Bbl of oil and natural gas liquids and $10.65 per Mcf of gas, as compared to $41.48 per Bbl of oil and $5.59 per Mcf of gas as of December 31, 2004. We estimate that a $1.00 per Bbl change in oil price and a $.50 per Mcf change in gas price from those utilized in calculating the present value of proved reserves would change the present value by approximately $13.2 million and $32.7 million, respectively.
The reserve information shown is estimated. 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 present value are based on various assumptions, including those prescribed by the SEC, 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, 2005, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.
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Exploration and Development Activities
We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.
| | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003 | |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | |
| | (Excludes wells in progress at the end of any period) | |
| | | | | | | | | | | | | |
Development Wells: | | | | | | | | | | | | | |
Oil | | 49 | | 26.4 | | 39 | | 11.7 | | 6 | | 5.0 | |
Gas | | 10 | | 3.2 | | 2 | | 1.3 | | 2 | | 2.0 | |
Dry | | 1 | | .2 | | 2 | | .9 | | — | | — | |
Total | | 60 | | 29.8 | | 43 | | 13.9 | | 8 | | 7.0 | |
| | | | | | | | | | | | | |
Exploratory Wells: | | | | | | | | | | | | | |
Oil | | 2 | | 1.8 | | 1 | | .3 | | — | | — | |
Gas | | 7 | | 4.5 | | 7 | | 4.9 | | 9 | | 4.9 | |
Dry | | 10 | | 6.1 | | 13 | | 7.1 | | 18 | | 12.3 | |
Total | | 19 | | 12.4 | | 21 | | 12.3 | | 27 | | 17.2 | |
Total Wells: | | | | | | | | | | | | | |
Oil | | 51 | | 28.2 | | 40 | | 12.0 | | 6 | | 5.0 | |
Gas | | 17 | | 7.7 | | 9 | | 6.2 | | 11 | | 6.9 | |
Dry | | 11 | | 6.3 | | 15 | | 8.0 | | 18 | | 12.3 | |
Total | | 79 | | 42.2 | | 64 | | 26.2 | | 35 | | 24.2 | |
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.
As of December 31, 2005, we do not own any drilling rigs, and all of our current drilling activities are conducted by independent drilling contractors. We have entered into a letter agreement with a contract drilling company which calls for the formation of a joint venture in 2006 to acquire 12 new drilling rigs. We will own a 50% interest in the joint venture.
Productive Well Summary
The following table sets forth certain information regarding our ownership, as of December 31, 2005, of productive wells in the areas indicated.
| | Oil | | Gas | | Total | |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | |
| | | | | | | | | | | | | |
Permian Basin | | 5,496 | | 520.0 | | 705 | | 91.0 | | 6,201 | | 611.0 | |
Louisiana | | 5 | | 2.7 | | 19 | | 14.7 | | 24 | | 17.4 | |
Austin Chalk (Trend) | | 298 | | 227.8 | | 16 | | 8.8 | | 314 | | 236.6 | |
Cotton Valley | | — | | — | | 12 | | 11.1 | | 12 | | 11.1 | |
Other | | 20 | | 15.8 | | 34 | | 7.8 | | 54 | | 23.6 | |
Total | | 5,819 | | 766.3 | | 786 | | 133.4 | | 6,605 | | 899.7 | |
23
Volumes, Prices and Production Costs
The following table sets forth certain information regarding the production volumes of, average sales prices received from, and average production costs associated with our sales of oil and gas for the periods indicated.
| | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003 | |
Oil and Gas Production Data: | | | | | | | |
Gas (MMcf) | | 16,408 | | 17,938 | | 24,697 | |
Oil (MBbls) | | 2,258 | | 2,094 | | 1,505 | |
Natural gas liquids (MBbls) | | 246 | | 249 | | 234 | |
Total (MMcfe) | | 31,432 | | 31,996 | | 35,131 | |
| | | | | | | |
Average Realized Prices (a): | | | | | | | |
Gas ($Mcf) | | $ | 7.49 | | $ | 5.60 | | $ | 4.69 | |
Oil ($Bbl) | | $ | 53.37 | | $ | 40.65 | | $ | 27.74 | |
Natural gas liquids ($/Bbl) | | $ | 33.57 | | $ | 27.90 | | $ | 21.09 | |
| | | | | | | |
Average Production Costs | | | | | | | |
Production ($/Mcfe) (b) | | $ | 1.83 | | $ | 1.29 | | $ | .80 | |
(a) Includes the effects of hedging transactions designated as cash flow hedges under applicable accounting standards. In 2005 and 2004, no derivatives were designated as cash flow hedges.
(b) Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs, administrative costs of production offices, insurance and property and severance taxes.
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, | |
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
| | | | | | | |
Property Acquisitions: | | | | | | | |
Proved | | $ | 5,567 | | $ | 237,042 | | $ | — | |
Unproved | | 50,238 | | 33,826 | | 7,982 | |
Developmental Costs | | 42,292 | | 27,469 | | 12,465 | |
Exploratory Costs | | 86,304 | | 73,655 | | 49,277 | |
Total | | $ | 184,401 | | $ | 371,992 | | $ | 69,724 | |
24
Acreage
The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2005 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 | | 80,331 | | 44,533 | | 338,124 | | 149,874 | | 418,455 | | 194,407 | |
Trend/Cotton Valley | | 108,280 | | 106,267 | | 62,051 | | 34,140 | | 170,331 | | 140,407 | |
Louisiana | | 9,672 | | 7,418 | | 166,559 | | 156,115 | | 176,231 | | 163,533 | |
Other (a) | | 11,566 | | 3,996 | | 618,981 | | 438,011 | | 630,547 | | 442,007 | |
Total | | 209,849 | | 162,214 | | 1,185,715 | | 778,140 | | 1,395,564 | | 940,354 | |
(a) Net undeveloped acres are attributable to the following areas: Montana – 183,136; Mississippi – 96,657; Alabama - 50,133; Arizona - 39,445; Colorado - 28,980; East Texas - 19,041; Utah - 8,301; and other – 12,318.
Offices
We lease from a related partnership approximately 52,000 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 an unaffiliated third party.
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 - Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of our security holders during the fourth quarter of our fiscal year ended December 31, 2005.
25
PART II
Item 5 - Market for the Registrant’s Common Stock and Related Stockholder Matters
Price Range of Common Stock
Our Common Stock is quoted on the Nasdaq Stock Market’s National Market under the symbol “CWEI”. As of March 6, 2006, there were approximately 1,900 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 National Market:
| | High | | Low | |
Year Ended December 31, 2005: | | | | | |
Fourth Quarter | | $ | 44.96 | | $ | 32.18 | |
Third Quarter | | 43.25 | | 29.60 | |
Second Quarter | | 31.93 | | 21.66 | |
First Quarter | | 33.89 | | 20.62 | |
| | | | | |
Year Ended December 31, 2004: | | | | | |
Fourth Quarter | | $ | 24.69 | | $ | 18.65 | |
Third Quarter | | 26.95 | | 17.53 | |
Second Quarter | | 35.85 | | 22.26 | |
First Quarter | | 38.90 | | 28.20 | |
The quotations in the table above reflect inter-dealer prices without retail markups, markdowns or commissions and may not necessarily reflect actual transactions. The closing price of our common stock at March 14, 2006 was $39.18 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 the common stockholders in the foreseeable future. In addition, the terms of our secured bank credit facilities prohibit the payment of cash dividends.
Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information regarding options or warrants authorized for issuance under our equity compensation plans as of December 31, 2005.
| | Number of
securities to be
issued upon
exercise of
outstanding
options | | Weighted
average exercise
price of
outstanding
options | | Number of
securities
remaining
Available for
future issuance | |
Equity compensation plans approved by security holders (a) | | 1,338,551 | | $ | 19.53 | | 148,066 | |
Equity compensation plans not approved by security holders | | — | | — | | — | |
Total | | 1,338,551 | | $ | 19.53 | | 148,066 | |
(a) Consists of the 1993 Stock Compensation Plan and the Outside Directors Stock Option Plan.
26
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, 2005 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, | |
| | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
| | (In thousands, except per share) | |
Statement of Operations Data: | | | | | | | | | | | |
Revenues: | | | | | | | | | | | |
Oil and gas sales | | $ | 252,599 | | $ | 193,127 | | $ | 163,032 | | $ | 86,302 | | $ | 105,118 | |
Natural gas services | | 12,080 | | 9,083 | | 8,758 | | 5,568 | | 8,820 | |
Gain on sales of property and equipment | | 18,920 | | 4,120 | | 267 | | 2,241 | | 10,986 | |
Total revenues | | 283,599 | | 206,330 | | 172,057 | | 94,111 | | 124,924 | |
Costs and expenses: | | | | | | | | | | | |
Production | | 57,404 | | 41,163 | | 28,239 | | 21,857 | | 20,427 | |
Exploration: | | | | | | | | | | | |
Abandonment and impairments | | 39,957 | | 67,956 | | 35,120 | | 21,571 | | 29,412 | |
Seismic and other | | 10,780 | | 7,124 | | 8,755 | | 8,578 | | 12,868 | |
Natural gas services | | 11,212 | | 8,538 | | 8,279 | | 4,853 | | 7,467 | |
Depreciation, depletion and amortization | | 47,509 | | 44,040 | | 40,284 | | 29,656 | | 37,459 | |
Impairment of property and equipment | | 18,266 | | — | | 170 | | 349 | | 18,170 | |
Accretion of abandonment obligations | | 1,158 | | 1,044 | | 651 | | — | | — | |
General and administrative | | 15,410 | | 11,689 | | 10,934 | | 8,615 | | 7,456 | |
Loss on sales of property and equipment | | 209 | | 14,337 | | 68 | | 1,880 | | — | |
Other | | 1,353 | | — | | — | | — | | — | |
Total costs and expenses | | 203,258 | | 195,891 | | 132,500 | | 97,359 | | 133,259 | |
Operating income (loss) | | 80,341 | | 10,439 | | 39,557 | | (3,248 | ) | (8,335 | ) |
Other income (expense): | | | | | | | | | | | |
Interest expense | | (14,498 | ) | (7,877 | ) | (3,138 | ) | (4,006 | ) | (2,925 | ) |
Gain (loss) on derivatives | | (70,059 | ) | (25,329 | ) | (1,593 | ) | (1,581 | ) | 2,227 | |
Other income | | 4,022 | | 1,354 | | (1,662 | ) | 1,755 | | 66 | |
Total other income (expense) | | (80,535 | ) | (31,852 | ) | (6,393 | ) | (3,832 | ) | (632 | ) |
Income (loss) before income taxes | | (194 | ) | (21,413 | ) | 33,164 | | (7,080 | ) | (8,967 | ) |
Income tax expense (benefit) | | (451 | ) | (7,385 | ) | 10,515 | | (1,742 | ) | (3,421 | ) |
Income (loss) from continuing operations | | 257 | | (14,028 | ) | 22,649 | | (5,338 | ) | (5,546 | ) |
Cumulative effect of accounting change, net of tax | | — | | — | | 207 | | — | | (164 | ) |
Income from discontinued operations, including gain on sale of $1,196 in 2002, net of tax | | — | | — | | — | | 1,335 | | 406 | |
NET INCOME (LOSS) | | $ | 257 | | $ | (14,028 | ) | $ | 22,856 | | $ | (4,003 | ) | $ | (5,304 | ) |
Net income (loss) per common share: | | | | | | | | | | | |
Basic: | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | (.02 | ) | $ | (1.37 | ) | $ | 2.43 | | $ | (.58 | ) | $ | (.60 | ) |
Net income (loss) | | $ | (.02 | ) | $ | (1.37 | ) | $ | 2.45 | | $ | (.43 | ) | $ | (.58 | ) |
Diluted: | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | (.02 | ) | $ | (1.37 | ) | $ | 2.38 | | $ | (.58 | ) | $ | (.60 | ) |
Net income (loss) | | $ | (.02 | ) | $ | (1.37 | ) | $ | 2.40 | | $ | (.43 | ) | $ | (.58 | ) |
Weighted average common shares outstanding: | | | | | | | | | | | |
Basic | | 10,804 | | 10,213 | | 9,329 | | 9,241 | | 9,219 | |
Diluted | | 11,241 | | 10,213 | | 9,509 | | 9,241 | | 9,219 | |
Other Data: | | | | | | | | | | | |
Net cash provided by operating activities | | $ | 163,475 | | $ | 126,980 | | $ | 119,750 | | $ | 34,514 | | $ | 67,059 | |
| | December 31, | |
| | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
| | (In thousands) | |
Balance Sheet Data: | | | | | | | | | | | |
Working capital (deficit) | | $ | (35,812 | ) | $ | (27,566 | ) | $ | (13,119 | ) | $ | (18,843 | ) | $ | (17,779 | ) |
Total assets | | 587,335 | | 462,235 | | 224,433 | | 218,992 | | 183,279 | |
Long-term debt | | 235,700 | | 177,519 | | 53,295 | | 94,949 | | 62,000 | |
Stockholders’ equity | | 120,291 | | 117,596 | | 100,781 | | 68,781 | | 82,280 | |
| | | | | | | | | | | | | | | | |
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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.
Overview
We are an oil and natural gas exploration, development, acquisition, and production company. Our basic business model is to find and develop oil and gas reserves through exploration and development activities, and sell 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.
We believe that the economic climate in the domestic oil and gas industry continues to be suitable for our business model. Oil and gas prices have remained strong. Supply and demand fundamentals continue to suggest that energy prices will remain high for the near term, providing us with the economic incentives necessary for us to assume the risks we face in our search for oil and gas reserves. However, we are also experiencing significant cost increases in almost all areas of our business activities, especially in drilling and production costs. High demand for oilfield services is resulting in shortage in equipment and trained personnel, resulting in rate increases. While profit margins still remain favorable, operating metrics per Mcfe, such as finding costs, production costs and overhead costs, are rising.
Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk. We replaced approximately 56% of our 2005 production through extensions and discoveries in 2005, most of which were derived from exploration activities. However, our Wolfcamp exploration program in West Texas failed to find sufficient reserves to cover our carrying costs, resulting in an $18.3 million impairment in 2005. Our ability to grow our reserves is highly dependent on our overall exploration successes. We will also continue to look for opportunities to complement our exploration program through the purchase of proved reserves.
Key Factors to Consider
The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2005 and the outlook for 2006.
• In July 2005, we significantly improved our liquidity by issuing $225 million of aggregate principal amount of 7¾% Senior Notes due 2013. We repaid all amounts outstanding at that time under our secured bank credit facilities with net proceeds from the Senior Notes of approximately $217 million, and had approximately $138.5 million of borrowing capacity available under our revolving credit facility at December 31, 2005.
• We recorded a $70.1 million loss on derivatives during 2005. Cash settlements to counterparties accounted for $29.7 million of this loss, and changes in mark-to-market valuations accounted for $40.4 million. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of
28
changing prices on mark-to-market valuations as a current charge or credit to our results of operations.
• Exploration costs related to abandonments and impairments totaled $40 million for 2005, most of which was in the Cotton Valley Reef Complex, South Texas, Louisiana and West Texas.
• Our proved oil and gas reserves at December 31, 2005 was 293.8 Bcfe compared to 299 Bcfe at December 31, 2004. We added 17.7 Bcfe through extensions and discoveries, purchased 4.2 Bcfe of reserves and added 7.8 Bcfe from net revisions.
• We currently plan to spend $184.1 million in 2006 on exploration and development activities, of which approximately 90% relates to exploratory prospects. We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.
• In October 2005, we entered into a letter agreement with a contract drilling company which calls for the formation of a joint venture to acquire 12 new drilling rigs. We will own a 50% interest in the joint venture, which is expected to be formed in March 2006.
Recent Exploration and Developmental Activities
South Louisiana
More than half of the wells in our South Louisiana exploration program that were commenced in 2005 were productive and resulted in the addition of approximately 8.7 Bcfe of proved reserves in 2005. However, the LL&E #1 (Andrea) and the State Lease 17636 #1 (Natalie) were unsuccessful and resulted in aggregate abandonment charges of $10.7 million in 2005.
We currently plan to spend $56.3 million in South Louisiana in 2006 to generate and lease new exploratory prospects and to drill wells on existing exploratory prospects. We have begun a six-well program on our Floyd prospect in Plaquemines Parish targeting multi-pay objectives ranging in depths from 3,000 to 13,000 feet. The State Lease 195 QQ #1 was drilled to a total depth of 12,981 feet and is currently being completed. The State Lease 195 QQ #2 has been drilled to a total depth of 6,296 feet and is pending completion. The State Lease 195 QQ #3 has been drilled to a total depth of 9,170 feet, and is also pending completion. The State Lease 195 QQ #4 is currently drilling. Under the terms of a farmout agreement, we bear 100% of the costs on these wells before casing point to earn a 75% working interest in the drilled acreage.
North Louisiana
We have begun an exploration program in North Louisiana targeting the Cotton Valley/Hosston and Bossier formations. In this area, the Cotton Valley/Hosston 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. We believe that these tight sandstone formations have become more economically viable due to higher product prices, coupled with enhanced drilling and completion techniques. We have accumulated more than 115,000 net acres in this area, and to date have participated in six non-operated wells on a small portion of this acreage, four of which are currently being completed and two are in progress. We are currently drilling the Harris #1, a 14,500-foot well in Jackson Parish targeting the Bossier formation, in which we own a 53% working interest. We plan to spend approximately $87.9 million in North Louisiana in 2006, consisting of $17.2 million to acquire leases and conduct seismic and exploration activities, and $70.7 million on drilling.
29
East Texas (Bossier)
We have also begun acquiring leases in East Texas targeting the Bossier formation which is encountered at depths ranging from 14,000 to 22,000 feet in this area. To date, we have acquired approximately 28,000 net acres and are actively seeking to add to our acreage position. We plan to spend approximately $20 million for acreage in East Texas in 2006 and expect to begin drilling on this acreage in 2007.
Permian Basin
In 2005, we initiated an exploration program in West Texas seeking to extend the limits of the Wolfcamp formation that is encountered throughout a large segment of this region. We acquired more than 50,000 net acres and have drilled 11 wells across a wide portion of this acreage. While all of the wells were completed as producers, the oil and gas reserves derived from this drilling program were inadequate to recover our capitalized costs. As a result, we recorded an $18.3 million charge for impairment of proved properties and a $1.8 million charge for impairment of unproved properties in 2005 related to our Wolfcamp program.
We also drilled the Leoncita #1, a 9,300-foot exploratory well in Pecos County, Texas targeting the Barnett Shale. This well was unsuccessful and resulted in a $4.5 million charge to exploration costs in 2005.
In addition, we drilled 24 gross (20.2 net) wells in the Permian Basin and conducted remedial operations on existing wells in 2005. While some of the drilling activities in 2005 did not result in the quantities of oil and gas reserves that we had expected, the Permian Basin continues to be a significant source of production and cash flow for us. We currently plan to spend $6.7 million on drilling activities in the Permian Basin in 2006.
Montana/Utah
In 2005, we initiated an exploration program in Sheridan County, Montana targeting the Bakken Shale which is encountered at depths ranging from 7,000 to 8,000 feet in this area. We are currently drilling the Ruegsegger 24H #1, a horizontal well at a vertical depth of 7,600 feet and a 3,600 foot lateral.
We are participating in a joint exploration program with industry partners in the Overthrust play in central Utah in which we own a 33% interest. In 2006, we plan to spend approximately $2.5 million to participate in the drilling of a 14,400-foot exploratory well to test this acreage.
Other
We currently plan to spend $7.2 million in 2006 to explore for oil and gas in other areas, including the Austin Chalk (Trend), Colorado and Alabama.
30
Proved Oil and Gas Reserves
The following table summarizes changes in our proved reserves during 2005 on a Bcfe basis.
| | Bcfe | |
Total proved reserves, December 31, 2004 | | 299.0 | |
Purchases of reserves in place | | 4.2 | |
Extensions and discoveries | | 17.7 | |
Revisions of previous estimates | | 7.8 | |
Sales of reserves in place | | (3.5 | ) |
Production | | (31.4 | ) |
Total proved reserves, December 31, 2005 | | 293.8 | |
During 2005, we replaced 94% of the 31.4 Bcfe that we produced in 2005, computed by dividing the sum of all reserve additions (purchases of reserves in place, extensions and discoveries, and revisions of previous estimates), by 2005 production. We use this reserve replacement ratio as a benchmark for determining the sources through which we have expanded or contracted our base of proved reserves. Following is a discussion of the important factors related to each source of reserve additions during 2005.
Purchases of reserves in place. We purchased 4.2 Bcfe of reserves in 2005 relating to properties in West Texas. Although we are continually looking for acquisitions, we cannot predict the likelihood of adding any reserves in 2006 through purchases of reserves in place.
Extensions and discoveries. Our extensions and discoveries during 2005 consist of proved reserves attributable directly to the drilling of discovery wells primarily in South Louisiana and the Permian Basin. Of the 17.7 Bcfe of additions, 4.8 Bcfe are proved undeveloped reserves that will require the expenditure of approximately $5.9 million before the reserves can ultimately be converted to cash flow. Due to the nature of exploratory drilling, we cannot predict the extent to which we will add any reserves in 2006 through extensions and discoveries.
Revisions of previous estimates. We added 7.8 Bcfe of proved reserves through revisions of previous estimates. Upward revisions of 17.5 Bcfe were attributable to the effects of higher product prices on the estimated quantities of proved reserves which were offset by downward revisions of approximately 9.7 Bcfe attributable to well performance, primarily from properties in West Texas.
As we discuss under “Application of Critical Accounting Policies and Estimates” elsewhere in this Item 7, reserve estimates are inherently imprecise. Proved undeveloped reserves are generally the least accurate due to limitations on available information. This increases the risk that the reserve additions in 2005 that are classified as proved undeveloped reserves could be subject to downward revisions in the future as economic conditions change and as more information is obtained through drilling.
31
Supplemental Information
The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-K with data that is not readily available from those statements.
| | As of or for the Year Ended December 31, | |
| | 2005 | | 2004 | | 2003 | |
Oil and Gas Production Data: | | | | | | | |
Gas (MMcf) | | 16,408 | | 17,938 | | 24,697 | |
Oil (MBbls) | | 2,258 | | 2,094 | | 1,505 | |
Natural gas liquids (MBbls) | | 246 | | 249 | | 234 | |
Total (MMcfe) | | 31,432 | | 31,996 | | 35,131 | |
| | | | | | | |
Average Realized Prices (a): | | | | | | | |
Gas ($/Mcf): | | | | | | | |
Before hedging losses | | $ | 7.49 | | $ | 5.60 | | $ | 5.35 | |
Hedging losses | | — | | — | | (.66 | ) |
Net realized price | | $ | 7.49 | | $ | 5.60 | | $ | 4.69 | |
Oil ($/Bbl): | | | | | | | |
Before hedging losses | | $ | 53.37 | | $ | 40.65 | | $ | 29.94 | |
Hedging losses | | — | | — | | (2.20 | ) |
Net realized price | | $ | 53.37 | | $ | 40.65 | | $ | 27.74 | |
| | | | | | | |
Natural gas liquids ($/Bbl): | | $ | 33.57 | | $ | 27.90 | | $ | 21.09 | |
| | | | | | | |
Average Daily Production: | | | | | | | |
Gas (Mcf): | | | | | | | |
Permian Basin | | 15,893 | | 9,458 | | 1,668 | |
Louisiana | | 10,865 | | 12,089 | | 17,570 | |
Austin Chalk (Trend) | | 2,435 | | 3,155 | | 3,667 | |
Cotton Valley Reef Complex | | 15,155 | | 23,131 | | 42,493 | |
Other | | 605 | | 1,312 | | 2,265 | |
Total | | 44,953 | | 49,145 | | 67,663 | |
Oil (Bbls): | | | | | | | |
Permian Basin | | 3,245 | | 2,410 | | 723 | |
Louisiana | | 994 | | 1,055 | | 608 | |
Austin Chalk (Trend) | | 1,892 | | 2,215 | | 2,715 | |
Other | | 55 | | 57 | | 77 | |
Total | | 6,186 | | 5,737 | | 4,123 | |
Natural Gas Liquids (Bbls): | | | | | | | |
Permian Basin | | 255 | | 213 | | 171 | |
Louisiana/Other | | 97 | | 185 | | 171 | |
Austin Chalk (Trend) | | 322 | | 284 | | 299 | |
Total | | 674 | | 682 | | 641 | |
| | | | | | | |
Total Proved Reserves: | | | | | | | |
Gas (MMcf) | | 126,758 | | 138,278 | | 62,916 | |
Oil and natural gas liquids (MBbls) | | 27,835 | | 26,793 | | 10,335 | |
Total gas equivalent (MMcfe) | | 293,768 | | 299,036 | | 124,926 | |
Standardized measure of discounted future net cash flows | | $ | 753,712 | | $ | 500,198 | | $ | 252,980 | |
32
Total Proved Reserves by Area: | | | | | | | |
Gas (MMcf): | | | | | | | |
Permian Basin | | 79,466 | | 85,243 | | 4,325 | |
Louisiana | | 20,883 | | 26,844 | | 24,465 | |
Austin Chalk (Trend) | | 6,234 | | 6,225 | | 5,593 | |
Cotton Valley Reef Complex | | 15,396 | | 19,116 | | 25,616 | |
Other | | 4,779 | | 850 | | 2,917 | |
Total | | 126,758 | | 138,278 | | 62,916 | |
Oil and Natural Gas Liquids (MBbls): | | | | | | | |
Permian Basin | | 18,504 | | 17,113 | | 1,980 | |
Louisiana | | 1,667 | | 1,942 | | 1,485 | |
Austin Chalk (Trend) | | 7,467 | | 7,586 | | 6,688 | |
Other | | 197 | | 152 | | 182 | |
Total | | 27,835 | | 26,793 | | 10,335 | |
Total Gas Equivalent (MMcfe): | | | | | | | |
Permian Basin | | 190,490 | | 187,921 | | 16,205 | |
Louisiana | | 30,885 | | 38,496 | | 33,375 | |
Austin Chalk (Trend) | | 51,036 | | 51,741 | | 45,721 | |
Cotton Valley Reef Complex | | 15,396 | | 19,116 | | 25,616 | |
Other | | 5,961 | | 1,762 | | 4,009 | |
Total | | 293,768 | | 299,036 | | 124,926 | |
| | | | | | | |
Exploration Costs (in thousands): | | | | | | | |
Abandonment and impairment costs: | | | | | | | |
South Louisiana | | $ | 12,405 | | $ | 32,760 | | $ | 17,904 | |
Cotton Valley Reef Complex | | 7,405 | | 205 | | 8,694 | |
Nevada, Arizona, California and Utah | | — | | 2,513 | | 4,172 | |
Mississippi (b) | | 4,306 | | 29,547 | | 3,773 | |
Permian Basin | | 7,411 | | 2,378 | | 361 | |
Other (c) | | 8,430 | | 553 | | 216 | |
Total | | 39,957 | | 67,956 | | 35,120 | |
| | | | | | | |
Seismic and other | | 10,780 | | 7,124 | | 8,755 | |
Total exploration costs | | $ | 50,737 | | $ | 75,080 | | $ | 43,875 | |
| | | | | | | |
Oil and Gas Costs ($/Mcfe Produced): | | | | | | | |
Production | | $ | 1.83 | | $ | 1.29 | | $ | .80 | |
Depletion | | $ | 1.42 | | $ | 1.28 | | $ | 1.10 | |
| | | | | | | |
Net Wells Drilled (d): | | | | | | | |
Exploratory wells | | 12.4 | | 12.3 | | 17.2 | |
Developmental wells | | 29.8 | | 13.9 | | 7.0 | |
(a) Includes the effects of hedging transactions designated as cash flow hedges under applicable accounting standards. In 2005 and 2004, no derivatives were designated as cash flow hedges.
(b) Includes a $13.7 million impairment of unproved acreage in the Black Warrior Basin in 2004 and $2.1 million in 2003.
(c) Includes an $8 million charge in South Texas for the Deer-Hamilton #1.
(d) Excludes wells being drilled or completed at the end of each period.
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Operating Results
The following discussion compares our results for the year ended December 31, 2005 to the two previous years. All references to 2005, 2004 and 2003 within this section refer to the respective annual periods.
Oil and gas operating results
Our oil and gas sales reached a record high again in 2005, exceeding the previous record in 2004. Both oil and gas prices continued to exceed previous year levels. Comparing 2005 to 2004, oil and gas sales increased $59.5 million, of which price variances accounted for a $61.3 million increase and production variances accounted for a $1.8 million decrease. Comparing 2004 to 2003, oil and gas sales increased $30.1 million, of which price variances accounted for a $45.2 million increase and production variances accounted for a $15.1 million decrease.
Production in 2005 (on a Mcfe basis) was 2% lower than 2004 and 11% lower than 2003. We increased our oil production in 2005 due primarily to additional well production from our SWR acquisition in May 2004, offset by lost production as a result of Hurricane Katrina. Our gas production decreased 9% in 2005 from 2004 due primarily to lost gas production from Hurricane Katrina and to higher than expected production declines in the Cotton Valley Reef Complex area due to formation performance.
In 2005, our realized gas price was 34% higher than 2004 and 60% higher than 2003, while our realized oil price was 31% higher than 2004 and 92% higher than 2003. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. We have very little control over the prices we receive for our production at the wellhead since most of our physical marketing arrangements are market-sensitive.
We cannot predict with accuracy future prices for oil and gas although currently we believe the fundamentals are in place for a continued strong oil and gas commodities market. However, we have not designated our current commodity derivatives, and do not currently intend to designate future commodity derivatives, as cash flow hedges under SFAS 133. This means that, in future periods as oil and gas prices fluctuate, our derivatives will be marked to market through our statement of operations as other income (loss) instead of through accumulated other comprehensive income on our balance sheet. Additionally, all realized gains or losses on these derivatives in future periods will be reported in other income (loss) instead of oil and gas sales. This accounting treatment affects the timing and classification of income (loss) from derivatives, but it has no effect on cash flow from operating activities. Since we cannot predict future oil and gas prices, we cannot predict the effect that this accounting treatment will have on oil and gas sales or other income (loss) in future periods.
Oil and gas production costs on an Mcfe basis in 2005 were 42% higher than 2004 and 129% higher than 2003. The increase in operating costs in 2005 and 2004 was due in part to higher oilfield service costs and an increase in workover activities. Also contributing to the added expense was the addition of higher cost oil properties acquired in connection with the SWR merger, as well as increased production tax costs related to higher product prices. It is likely that these factors will continue to contribute to higher production costs in future periods.
Depletion on an Mcfe basis increased 11% from 2004 and 29% from 2003. Comparing 2005 to 2004, depletion expense increased $3.5 million, of which rate variances accounted for a $4.2 million increase and production variances accounted for a $700,000 decrease. Comparing 2004 to 2003, depletion expense increased $2.5 million, of which rate variances accounted for a $6 million increase and production variances accounted for a $3.5 million decrease. Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities. The rates for 2006 are expected to be similar to the 2005 rates.
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General and administrative (“G&A”) expenses, excluding non-cash stock-based employee compensation, were 8% higher than 2004 and 27% higher than 2003 due primarily to higher personnel costs, professional fees and insurance costs. G&A expenses for 2005 include a non-cash charge of $2.6 million for stock-based employee compensation required by Financial Accounting Standards Board Interpretation No. 44. A non-cash credit (reduction of expense) of $245,000 was required for the 2004 period and a charge of $797,000 was needed for 2003. In addition, we recognized $680,000 of non cash compensation expense for the estimated value of after payout working interests conveyed to incentive partnerships formed in 2005.
Exploration costs
In 2005, we charged to expense $50.7 million of exploration costs, as compared to $75.1 million in 2004 and $43.9 million in 2003. 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. Most of these costs were incurred in south Louisiana and Mississippi.
We plan to spend approximately $184.1 million on exploration and development activities in 2006. Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of this will be charged to exploration costs in 2006. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.
Gains and losses on property sales
Gain on sale of property and equipment for 2005 was $18.9 million. In August 2005, we sold our interests in two leases in the Breton Sound area in the Gulf of Mexico (offshore Louisiana) for $21.3 million, subject to post-closing adjustments and realized a gain of $16.8 million on this sale. In fiscal 2004 we recorded a gain of $4.1 million, including the sale of the Jo-Mill Unit in Borden County, Texas. Loss on sale of property and equipment for 2004 was $14.3 million including the sale of the Romere Pass Unit in Plaquemines Parish, Louisiana. Under EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations,” we determined that these sales do not qualify for discontinued operations reporting. We adopted EITF 03-13 during the fourth quarter of 2004.
Interest expense
Interest expense was $14.5 million in 2005 as compared to $7.9 million in 2004 and $3.1 million in 2003. Included in 2005 was a non-cash charge of $1.8 million of debt issue costs related to the early repayment of our senior term credit facility. In July 2005, we repaid all outstanding balances on our bank indebtedness using proceeds from the issuance of $225 million of Senior Notes which bear interest at a fixed rate of 7.75%. Higher effective interest rates on our revolving credit facility and our senior term credit facility also contributed to the increase in interest expense.
Loss on derivatives
We recorded a loss on derivatives of $70.1 million in 2005 compared to a loss of $25.3 million in 2004 and a loss of $1.6 million in 2003. We did not designate any derivative contracts in 2005 or 2004 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as losses on derivatives. Cash settlements were $29.7 million in 2005, as compared to $18.2 million in 2004, and non-cash mark-to-market losses were $40.4 million in 2005, as compared to $7.1 million in 2004.
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Other
At December 31, 2005, our cumulative tax loss carryforwards were approximately $7.1 million. Based upon current commodity prices and production volumes, as well as the availability of tax planning strategies (such as elective capitalization of intangible drilling costs), we believe that it is more likely than not that we will be able to utilize these tax loss carryforwards before they expire (beginning in 2008). Accordingly, no valuation allowance exists at December 31, 2005. A valuation allowance at December 31, 2002 was reversed during 2003.
Liquidity and Capital Resources
Overview
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 and, until July 2005, our senior term 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 program in replacing our existing oil and gas reserves. If product prices decrease, our operating cash flow may decrease and the banks may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. The effects of product prices on cash flow can be mitigated through the use of commodity derivatives. If we are unable to replace our oil and gas reserves through our exploration program, we may also suffer a reduction in our operating cash flow and access to funds under the revolving credit facility. Under extreme circumstances, product price reductions or exploration drilling failures could allow the banks to seek to foreclose on our oil and gas properties, thereby threatening our financial viability.
In July 2005, we reduced our dependence on the borrowing base established for the revolving credit facility by issuing $225 million of aggregate principal amount of 7¾% Senior Notes due 2013 (the “Senior Notes”) and using the net proceeds to repay all amounts outstanding on the revolving credit facility and the senior term credit facility.
In this section, we will describe our current plans for capital spending, identify the capital resources available to finance our capital spending, and discuss the principal factors that can affect our liquidity and capital resources.
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Capital Expenditures
Exploration and Development
Our planned expenditures for exploration and development activities during 2006 total $184.1 million, as summarized by area in the following table.
| | Total
Planned
Expenditures
Year Ended
December 31, 2006 | | Percentage
of Total | |
| | (In thousands) | | | |
| | | | | |
North Louisiana | | $ | 87,900 | | 48 | % |
South Lousiana | | 56,300 | | 30 | % |
East Texas (Bossier) | | 20,000 | | 11 | % |
Permian Basin | | 6,700 | | 4 | % |
Utah/Montana | | 6,000 | | 3 | % |
Austin Chalk (Trend) | | 4,100 | | 2 | % |
Other | | 3,100 | | 2 | % |
| | $ | 184,100 | | 100 | % |
Our actual expenditures during fiscal 2006 may be substantially higher or lower than these estimates since our plans for exploration and development activities may change during the year. Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during fiscal 2006.
Approximately 90% of our planned expenditures for 2006 relate to exploratory prospects, including $36.6 million of completion costs on exploratory wells to be drilled in North Louisiana and South Louisiana that are classified as exploratory wells but are considered likely to require the expenditure of completion costs. Exploratory prospects involve a higher degree of risk than developmental prospects. To offset this higher risk, we generally strive to achieve a higher reserve potential and rate of return on investments in exploratory prospects. We do not attempt to forecast our success rate on exploratory drilling. Accordingly, these current estimates may not include all costs that may be required to complete our successful exploratory wells and construct the required production facilities for these wells. Also, we are actively searching for other opportunities to increase our oil and gas reserves, including the evaluation of new prospects for exploratory and developmental drilling activities and potential acquisitions of proved oil and gas properties. Other factors, such as prevailing product prices and the availability of capital resources, could also increase or decrease the ultimate level of expenditures during 2006.
We project that most of the cash needed to finance our planned expenditures for exploration and development activities in fiscal 2006 will be provided by operating activities. To the extent that actual costs exceed our cash provided by operating activities, we plan to utilize the revolving credit facility to finance such excess.
Drilling Rig Joint Venture
In October 2005, we entered into a letter agreement with Lariat Services, Inc. (“Lariat”), a contract drilling company, which calls for the formation of a joint venture to acquire at least 12 new drilling rigs. We and Lariat will each own a 50% interest in the joint venture. Lariat will serve as the operations manager of the joint venture, and we will be responsible for financing the purchase of the rigs. The total acquisition cost, including construction and equipping of the rigs, is expected to be approximately $75 million.
The joint venture has received a proposal from a lender to provide financing for up to $75 million, depending on the appraised values of the drilling rigs upon completion of construction. During 2006, while the drilling rigs are being constructed, the proposal contemplates that we provide the lender a $19.5 million
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standby letter of credit as additional credit support. On or before December 31, 2006, we would terminate the letter of credit and provide an unconditional guaranty to the lender of the repayment and performance by the joint venture limited to $19.5 million of the outstanding balance of the loan facility. Under the terms of the proposal, we would also be required to contract with the joint venture to use the drilling rigs in our drilling program for a term of at least three years and to pay for idle, non-working rigs in amounts ranging from $8,000 to $11,000 per day. We expect to complete negotiations with the lender and to close the financing in March 2006.
At December 31, 2005, we had made advances on behalf of the joint venture of approximately $10.3 million for interim construction costs of the rigs and related equipment. The joint venture is to reimburse us for all advances once it has received the proceeds from the financing.
We are currently evaluating our investment in this joint venture to determine if we are the primary beneficiary under FIN 46R. If we determine that we are the primary beneficiary, we will be required to fully consolidate this entity in 2006.
Equipment Orders
As of December 31, 2005, we had placed firm orders for tubing, casing, pumping units and other equipment to be used in its exploration and development activities totaling approximately $8.6 million.
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, 2005 was 29% higher than 2004 due to the combined effects of several drivers. The positive benefits of a 31% increase in oil and gas sales, driven primarily by higher oil and gas prices, were offset in part by increases in production costs and interest expense. Our primary source of cash from operating activities is our oil and gas sales, net of production costs. Our cash flow provided by operating activities is subject to material variation from changes in oil and gas production levels and product prices. Interest expense increased in 2005 due primarily to higher levels of indebtedness.
Credit Facility
A group of banks have provided us with a revolving credit facility on which we have historically relied for both our short-term liquidity (working capital) and our long-term financing needs. The funds available to us at any time under this revolving credit facility are limited to the amount of the borrowing base established by the banks. As long as we have sufficient availability under this credit facility to meet our obligations as they come due, we will have sufficient liquidity and will be able to fund any short-term working capital deficit.
At the beginning of 2005, we had an outstanding balance under the revolving credit facility of $147.5 million, and the borrowing base was $195 million, providing us with available funds of $46.7 million after accounting for outstanding letters of credit. During the year ended December 31, 2005, we generated cash flow from operating activities of $163.5 million and received proceeds from sales of property and equipment of $23.3 million. We also spent $220 million on capital expenditures and other investments and paid $27.7 million to settle derivatives with financing elements. With the issuance of the Senior Notes in July 2005, we borrowed $217 million, net of financing costs, repaid the balance on the revolving credit facility and repaid the remaining $30 million balance on the senior term credit facility.
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Simultaneously, the borrowing base was reduced from $195 million to $132.5 million to give effect to the issuance of the Senior Notes. In December 2005 the borrowing base was increased to $150 million. The available funds under our revolving credit facility were $138.5 million at December 31, 2005, and our available cash at December 31, 2005 decreased by $10.4 million from December 31, 2004.
Using the revolving credit facility for both our short-term liquidity and long-term financing needs can cause unusual fluctuations in our reported working capital, depending on the timing of cash receipts and expenditures. On a daily basis, we use most of our available cash to pay down our outstanding balance on the revolving credit facility, which is classified as a non-current liability since we currently have no required principal reductions. As we use cash to pay a non-current liability, our reported working capital decreases. Conversely, as we draw on the revolving credit facility for funds to pay current liabilities (such as payables for drilling and operating costs), our reported working capital increases. Also, volatility in oil and gas prices can cause significant fluctuations in reported working capital as we record changes in the fair value of derivatives from period to period. For these reasons, the working capital covenant related to the revolving credit facility requires us to (i) include the amount of funds available under this facility as a current asset, (ii) exclude current assets and liabilities related to the fair value of derivatives, and (iii) exclude current maturities of vendor finance obligations, if any, when computing the working capital ratio at any balance sheet date.
Working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (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 reported working capital deficit increased from $27.6 million at December 31, 2004 to $35.8 million at December 31, 2005 due primarily to a combination of factors, including decreases in accounts payable, increases in inventory and increases in current liabilities related to the fair value of derivatives. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $136.2 million at December 31, 2005, as compared to a positive $32.9 million at December 31, 2004. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2005 and December 31, 2004.
| | December 31,
2005 | | December 31,
2004 | |
| | (In thousands) | |
Working capital (deficit) per GAAP | | $ | (35,812 | ) | $ | (27,566 | ) |
Add funds available under the revolving credit facility | | 138,496 | | 46,725 | |
Exclude fair value of derivatives classified as current assets or current liabilities | | 33,479 | | 13,693 | |
Working capital per loan covenant | | $ | 136,163 | | $ | 32,852 | |
Since we use this revolving credit facility for both short-term liquidity and long-term financing needs, it is important that we comply in all material respects with the loan agreement, including financial covenants that are computed quarterly. The working capital covenant requires us to maintain positive working capital using the computations described above. Another financial covenant under the credit facility requires us to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. While we were in compliance with all financial and non-financial covenants at December 31, 2005, 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 allow 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. However, the issuance
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of the Senior Notes described below significantly increases our liquidity and reduces our dependence on the revolving credit facility.
The banks redetermine the borrowing base under the revolving credit facility at least twice a year, in May and November. If at any time, the borrowing base is less than the amount of outstanding indebtedness, we will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement.
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 will bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006. After the payment of typical transaction expenses, net proceeds of approximately $217 million were used to repay amounts outstanding on our secured credit facilities and for general corporate purposes, including the funding of planned exploration and development activities.
At any time prior to August 1, 2008, we may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a redemption price of 107.75% of the principal amount, plus accrued and unpaid interest. In addition, prior to August 1, 2009, we may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. On and after August 1, 2009, 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 100.00% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.
The Indenture governing the Senior Notes restricts our ability and the ability of our restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business. These covenants are subject to a number of important exceptions and qualifications.
Since the Senior Notes have an eight-year maturity and bear interest at a fixed rate of 7¾%, we expect our effective annual interest rate to increase in future periods.
Alternative Capital Resources
Although our base of oil and gas reserves, as collateral for the 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 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.
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Contractual Obligations and Contingent Commitments
The following table summarizes our contractual obligations as of December 31, 2005 by payment due date.
| | Payments Due by Period | |
| |
Total
| | Less than
1 Year | |
1-3 Years
| |
3-5 Years
| | More than 5
Years | |
| | (In thousands) | |
Contractual obligations: | | | | | | | | | | | |
7¾% Senior Notes (a) | | $ | 225,000 | | $ | — | | $ | — | | $ | — | | $ | 225,000 | |
Secured bank credit facility (a) | | 10,700 | | — | | 10,700 | | — | | — | |
Drilling contracts | | 16,258 | | 10,858 | | 5,400 | | — | | — | |
Purchase commitments | | 8,587 | | 8,587 | | — | | — | | — | |
Abandonment obligations | | 19,447 | | — | | 9,051 | | — | | 10,396 | |
Lease obligations | | 1,847 | | 1,141 | | 694 | | 12 | | — | |
Other | | 19 | | 19 | | — | | — | | — | |
Total contractual obligations | | $ | 281,858 | | $ | 20,605 | | $ | 25,845 | | $ | 12 | | $ | 235,396 | |
(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 $803,000 on the secured bank credit facility (based on the balances and rates at December 31, 2005).
Excluded from the table above is our mark-to-market liability related to commodity and interest rate derivatives. Our derivative obligations, based on mark-to-market valuations at December 31, 2005, would mature as follows: 2006 - $33.5 million; 2007 - - $29.4 million; and 2008 - $20.2 million.
Known Trends and Uncertainties
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. Our production has 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. At the present time, we continue to have approximately 7,000 Mcfe of production shut-in due to hurricane damage to facilities suffered in 2005 that we expect to return to production in 2006. We also expect to add production from our exploration and development activities in North and South Louisiana. While we cannot predict the results of our exploration and development activities, we believe that oil and gas production levels in 2006 will be comparable to those in 2005.
Equipment and Personnel Shortages
Commodity prices for natural gas, natural gas liquids and oil have been on an upward trend since 2004. Higher prices have led to increased activity in the industry, which in turn has resulted in significant cost increases in almost all areas of our business activities, especially in drilling and production costs. Drilling rig counts are at historically high levels and qualified rig crews are in short supply. Equipment and labor shortages were further strained by hurricane damage in the Gulf of Mexico in August and September 2005.
Drilling rigs have recently been in short supply throughout the industry, and we do not foresee an end to this shortage in the near future. In order to secure rig availability for our exploration and development drilling, we have entered into a joint venture to acquire 12 drilling rigs (see “Liquidity and Capital
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Resources – Capital Expenditures – Drilling Rig Joint Venture”) and have entered into an 18-month contract with another drilling contractor for one rig to be utilized in North Louisiana.
Raw material shortages and strong global demand for steel have continued to tighten steel supplies and have caused supplies of casing, tubing and other surface and subsurface equipment to decrease and costs to increase. During 2005, we increased our equipment inventory by $38.6 million in an effort to secure the levels of inventory we need to conduct our drilling programs.
We cannot accurately predict the duration and extent of these equipment and personnel shortages; however, any significant escalation in shortages can have an adverse affect on our financial condition, results of operations and cash flows.
Application of Critical Accounting Policies and Estimates
Summary
In this section, we will identify the critical accounting policies we follow in preparing our 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.
The following table lists our critical accounting policies, the estimates and assumptions that can have a significant impact on the application of these accounting policies, and the financial statement accounts affected by these estimates and assumptions.
Accounting Policies | | Estimates or Assumptions | | Accounts Affected |
| | | | |
Successful efforts accounting for oil and gas properties | | • Reserve estimates • Valuation of unproved properties • Judgment regarding status of inprogress exploratory wells | | • Oil and gas properties • Accumulated DD&A* • Provision for DD&A • Impairment of unproved properties • Abandonment costs (dry hole costs) |
| | | | |
Impairment of proved properties | | • Reserve estimates and related present value of future net revenues | | • Oil and gas properties • Accumulated DD&A • Impairment of proved properties |
| | | | |
Valuation allowance for net deferred tax assets | | • Estimates related to utilizing net operating loss (NOL) carryforwards | | • Deferred tax assets • Deferred tax liabilities • Deferred income taxes |
| | | | |
Asset retirement obligations | | • Estimates of the present value of future abandonment costs | | • Abandonment obligations (non-current liability) • Oil and gas properties • Accretion of discount expense |
* DD&A means depreciation, depletion and amortization.
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
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available geological and engineering data, the precision of 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. While we believe this reconciliation process improves the accuracy of the reserve estimates by reducing the likelihood of a material error in judgment, it is possible that in exchanging information, our internal reservoir engineer could influence the independent engineer’s 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 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 nonproducing | | 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. SEC financial accounting and reporting standards require that pricing parameters be tied to the price received for oil and natural gas on the effective date of the reserve report. This requirement can result in significant changes from period to period given the volatile nature of oil and gas product prices, as illustrated in the following table.
| | Proved Reserves | | Average Price | | Standardized
Measure
of Discounted | |
| | Oil (a)
(MMBbls) | | Gas
(Bcf) | | Oil (a)
($/Bbl) | | Gas
($/Mcf) | | Future
Net Cash Flows | |
| | | | | | | | | | (In millions) | |
As of December 31: | | | | | | | | | | | |
2005 | | 27.8 | | 126.8 | | $ | 57.85 | | $ | 10.65 | | $ | 753.7 | |
2004 | | 26.8 | | 138.3 | | $ | 41.48 | | $ | 5.59 | | $ | 500.2 | |
2003 | | 10.3 | | 62.9 | | $ | 30.45 | | $ | 5.61 | | $ | 253.0 | |
(a) Includes natural gas liquids
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Valuation of unproved properties
Placing a fair market value on unproved properties (also known as prospects) is very subjective since there is no quoted market for undeveloped exploratory prospects. The negotiated price of any prospect between a willing seller and willing buyer depends on the specific facts regarding the prospect, including:
• The location of the prospect in relation to known fields and reservoirs, available markets and transportation systems for oil and gas production in the vicinity, and other critical services;
• The nature and extent of geological and geophysical data on the prospect;
• The terms of the leases holding the acreage in the prospect, such as ownership interests, expiration terms, delay rental obligations, depth limitations, drilling and marketing restrictions, and similar terms;
• The prospect’s risk-adjusted potential for return on investment, giving effect to such factors as potential reserves to be discovered, drilling and completion costs, prevailing commodity prices, and other economic factors; and
• The results of drilling activity in close proximity to the prospect that could either enhance or condemn the prospect’s chances of success.
Asset Retirement Obligations
We are required by SFAS 143 “Accounting for Asset Retirement Obligations” to 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.
Valuation allowance for NOL Carryforwards
In computing our provision for income taxes, we must assess the need for a valuation allowance on deferred tax assets, which consist primarily of net operating loss (“NOL”) carryforwards. For federal income tax purposes, these NOL carryforwards, if unused, expire 15 to 20 years from the year of origination. Generally, we assess our ability to fully utilize these carryforwards by comparing expected future book income to expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report, under current economic conditions. If future book income does not exceed future taxable income by amounts sufficient to utilize NOLs before they expire, we must impair the resulting deferred tax asset. These computations are inherently imprecise due to the extensive use of estimates and assumptions. As a result, we may make additional impairments to allow for such uncertainties.
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.
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Provision for DD&A
We compute our provision for DD&A on a unit-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for each of our producing properties (or appropriate groups of properties based on geographical and geological similarities):
• DD&A Rate = Unamortized Cost ¸ Beginning of Period Reserves
• Provision for DD&A = DD&A Rate ´ Current Period Production
Reserve estimates have a significant impact on the DD&A rate. If reserve estimates for a property or group of properties are revised downward in future periods, the DD&A rate for that property or group of properties will increase as a result of the revision. Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease.
Impairment of Unproved Properties
Each quarter, we review our unproved oil and gas properties to determine if there has been, in our judgment, an impairment in value of each prospect that we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimated value, we make a provision for impairment of unproved properties, and record the provision as abandonments and impairments within exploration costs on our 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
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 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 that do not qualify as proved reserves. To the extent that the carrying cost for the affected property exceeds its estimated value, we make a provision for impairment of proved properties. If the 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 value. If the 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 G&G 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.
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Valuation allowance for NOL carryforwards
Each quarter, we assess our ability to utilize NOL carryforwards. An increase in the valuation allowance from one period to the next will result in a decrease in our net deferred tax assets and a decrease in earnings. Similarly, a decrease in the valuation allowance will result in an increase in our net deferred tax assets and an increase in earnings.
This process requires estimates and assumptions which are complex and may vary materially from our actual ability to utilize NOL carryforwards in the future. Also, the current tax laws in this area are complicated due to the impact of alternative minimum tax on the utilization of NOL carryforwards. As a mitigating factor, as long as we are actively drilling for new production, we have some tax planning strategies available to us, such as elective capitalization of intangible drilling costs, to help us utilize these NOL carryforwards before they expire.
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 2005, we increased our estimated asset retirement obligations by $2 million, or approximately 10% of the asset retirement obligations at December 31, 2004, 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 of discount. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Recent Accounting Pronouncements
In June 2005, the Emerging Issues Task Force (“EITF”) reached consensus on Issue 04-5, subject to ratification by the Financial Accounting Standards Board (“FASB”), regarding when a limited partnership should be consolidated by its general partner. The proposed framework presumes that a sole general partner in a limited partnership controls the limited partnership. The presumption of control can be overcome if the limited partners have (i) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (ii) substantive participating rights. The EITF has concluded that a general partner lacks control if the limited partners can remove the general partner with a simple majority vote. We are the general partner of several oil and gas limited partnerships and proportionately consolidate interest in these partnerships. We are currently reviewing the applicable provisions of the partnership agreements to determine the impact that EITF 04-5 may have on our consolidated financial statements. For existing partnerships, EITF 04-5 will be effective for our consolidated financial statements issued after January 1, 2006. EITF 04-5 is effective for newly created or modified limited partnerships subsequent to June 29, 2005. If we determine that the limited partners do not have the substantive ability to remove the general partner in accordance with EITF Issue 04-5, we will be required to fully consolidate the limited partnerships, with the interest we do not own reflected as minority interest. This would have no impact to our future net income from the current method of accounting for oil and gas limited partnerships using proportionate consolidation.
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments” (“SFAS 123R”). SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value. We currently use the intrinsic-value method to account for these share-based payments. For public companies, SFAS 123R is effective for fiscal years beginning after June 15, 2005. We will adopt the provisions of this statement in the first quarter of 2006. We have accounted for options which were repriced in 1999 as variable stock options whereby compensation expense has been recognized through December 31, 2005 for unexercised options. In accordance with SFAS 123R, we will cease accounting for these options as variable stock options upon the adoption date. Since all of our outstanding options are fully vested at December 31,
46
2005, no future compensation expense will be recognized under SFAS 123R unless the options are modified. Accordingly, future compensation expense to be recognized under SFAS 123R will be determined by the grant date fair value of future awards.
In April 2005, the FASB issued Staff Position No. 19-1 (“FSP 19-1”). FSP 19-1 amends the present guidance in SFAS 19, paragraphs 31 and 34, regarding when exploratory drilling costs pending determination of proved reserves can be carried as an asset of an oil and gas company that uses the successful efforts accounting method. We were required to adopt FSP 19-1, including its disclosures, effective July 1, 2005. The adoption of FSP 19-1 did not have a significant impact on our results of operations. At December 31, 2005 and December 31, 2004, we had capitalized $10.3 million and $5.4 million, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves. Substantially all of the December 31, 2004 capitalized costs were subsequently classified as non-productive.
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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 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, 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, 2005 reserve estimates, we project that a $1.00 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas would reduce our gross revenues for the year ending December 31, 2006 by $11 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.
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The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2005. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Collars:
| | Gas | | Oil | |
| | MMBtu (a) | | Floor | | Ceiling | | Bbls | | Floor | | Ceiling | |
Production Period: | | | | | | | | | | | | | |
1st Quarter 2006 | | 561,000 | | $ | 4.00 | | $ | 5.21 | | 157,000 | | $ | 23.00 | | $ | 25.32 | |
2nd Quarter 2006 | | 551,000 | | $ | 4.00 | | $ | 5.21 | | 156,000 | | $ | 23.00 | | $ | 25.32 | |
3rd Quarter 2006 | | 456,000 | | $ | 4.00 | | $ | 5.21 | | 150,000 | | $ | 23.00 | | $ | 25.32 | |
4th Quarter 2006 | | 456,000 | | $ | 4.00 | | $ | 5.21 | | 150,000 | | $ | 23.00 | | $ | 25.32 | |
2007 | | 1,831,000 | | $ | 4.00 | | $ | 5.18 | | 562,000 | | $ | 23.00 | | $ | 25.20 | |
2008 | | 1,279,000 | | $ | 4.00 | | $ | 5.15 | | 392,000 | | $ | 23.00 | | $ | 25.07 | |
| | 5,134,000 | | | | | | 1,567,000 | | | | | |
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.
We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our outstanding commodity derivatives at December 31, 2005 by approximately $3.7 million.
Interest Rates
All of our outstanding bank indebtedness at December 31, 2005 is subject to market rates of interest as determined from time to time by the banks pursuant to our credit facilities. We may designate borrowings under our revolving credit facility as either “Base Rate Loans” or “Eurodollar Loans.” Base Rate Loans bear interest at a fluctuating rate that is linked to the discount rates established by the Federal Reserve Board. Eurodollar Loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow.
We are a party to interest rate swaps that were acquired in connection with the SWR acquisition. Under these derivatives, we pay a fixed rate for the notional principal balances and receive a floating market rate based on LIBOR. The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to December 31, 2005.
Interest Rate Swaps:
| | Principal
Balance | | Fixed
Libor
Rates | |
Period: | | | | | |
January 1, 2006 to November 1, 2006 | | $ | 55,000,000 | | 4.29 | % |
November 1, 2006 to November 1, 2007 | | $ | 50,000,000 | | 5.19 | % |
November 1, 2007 to November 1, 2008 | | $ | 45,000,000 | | 5.73 | % |
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.
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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:
• management has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;
• this evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and
• it is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.
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:
• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
• provide reasonable assurance that transactions are recorded as necessary to permit preparation of 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
• 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
50
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, 2005 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, 2005. 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, 2005, our internal control over financial reporting is effective based on those criteria.
KPMG LLP has issued an attestation report on management’s assessment of internal control over financial reporting, the contents of which are printed below.
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Clayton Williams Energy, Inc.:
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Clayton Williams Energy, Inc. (Company) maintained effective internal control over financial reporting as of December 31, 2005, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
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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, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2005, and our report dated March 15, 2006, expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Dallas, Texas
March 15, 2006
Item 9B - Other Information
None.
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PART III
Item 10 - Directors and Executive Officers of the Registrant
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, 2006.
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, 2006.
Item 12 - Security Ownership of Certain Beneficial Owners and Management
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, 2006.
Item 13 - Certain Relationships and Related Transactions
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, 2006.
Item 14 - Principal Accountant 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, 2006.
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.
Exhibits
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 |
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Exhibit | | |
Number | | Description of Exhibit |
| | |
**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 June 1, 2005†† |
| | |
**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†† |
| | |
**4.3 | | Registration Rights Agreement dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and J.P. Morgan Securities Inc., filed as Exhibit 4.2 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 |
| | |
**10.4 | | Senior Term Credit Agreement dated as of May 21, 2004 among Clayton Williams Energy, Inc., et al, and Bank One, NA, et al, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K/A filed with the Commission on June 23, 2004 |
| | |
**10.5† | | 1993 Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 033-68318 |
| | |
**10.6† | | First Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.11 to the Company’s Form 10-K for the period ended December 31, 1995†† |
| | |
**10.7† | | Second Amendment to the 1993 Stock Compensation Plan, filed as Exhibit 10.2 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68318 |
| | |
**10.8† | | Third Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.4 to the Company’s Form S-8 Registration Statement, Commission File No. 333-47232 |
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Exhibit | | |
Number | | Description of Exhibit |
| | |
**10.9† | | Fourth Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.5 to the Company’s Form S-8 Registration Statement, Commission File No. 333-47232 |
| | |
**10.10† | | Fifth Amendment to 1993 Stock Compensation Plan |
| | |
**10.11† | | Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316 |
| | |
**10.12† | | 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†† |
| | |
*10.13† | | Second Amendment to Outside Directors Stock Option Plan |
| | |
**10.14† | | Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68320 |
| | |
**10.15† | | 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†† |
| | |
**10.16† | | 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, 2005†† |
| | |
**10.17† | | Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-92834 |
| | |
**10.18† | | First Amendment to Executive Incentive Stock Compensation Plan, filed as Exhibit 10.16 to the Company’s Form 10-K for the period ended December 31, 1996†† |
| | |
**10.19 | | 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 |
| | |
**10.20 | | 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†† |
| | |
**10.21 | | 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 |
| | |
**10.22 | | 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†† |
| | |
**10.23† | | East Texas/Chalk Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.21 to the Company’s Form 10-K for the period ended December 31, 2001†† |
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Exhibit | | |
Number | | Description of Exhibit |
| | |
**10.24† | | Louisiana Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.22 to the Company’s Form 10-K for the period ended December 31, 2001†† |
| | |
**10.25† | | New Mexico Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.23 to the Company’s Form
10-K for the period ended December 31, 2001†† |
| | |
**10.26† | | South Texas Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.24 to the Company’s Form
10-K for the period ended December 31, 2001†† |
| | |
**10.27† | | West Texas I Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.25 to the Company’s Form 10-K for the period ended December 31, 2001†† |
| | |
**10.28† | | West Texas II Working Interest Trust Agreement dated May 30, 2001, filed as Exhibit 10.26 to the Company’s Form 10-K for the period ended December 31, 2001†† |
| | |
**10.29† | | Agreement of Limited Partnership of CWEI South Louisiana I, L.P. dated October 1, 2002, filed as Exhibit 10.27 to the Company’s Form 10-K for the period ended December 31, 2002†† |
| | |
**10.30† | | Agreement of Limited Partnership of CWEI Cotton Valley I, L.P. dated October 1, 2002, filed as Exhibit 10.28 to the Company’s Form 10-K for the period ended December 31, 2002†† |
| | |
**10.31† | | Agreement of Limited Partnership of CWEI Romere Pass, L.P. dated October 1, 2002, filed as Exhibit 10.29 to the Company’s Form 10-K for the period ended December 31, 2002†† |
| | |
**10.32† | | 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†† |
| | |
**10.33† | | 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†† |
| | |
**10.34† | | Agreement of Limited Partnership of CWEI Mississippi I, L.P. effective as of January 1, 2004, filed as Exhibit 10.30 to the Company’s Form 10-K for the period ended December 31, 2004†† |
| | |
**10.35† | | 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†† |
| | |
**10.36† | | Agreement of Limited Partnership of CWEI Mississippi II, L.P. effective as of January 2, 2005, filed as Exhibit 10.32 to the Company’s Form 10-K for the period ended December 31, 2004†† |
| | |
**10.37† | | 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†† |
57
Exhibit | | |
Number | | Description of Exhibit |
| | |
**10.38† | | Agreement of Limited Partnership of CWEI Destefano, L.P. effective as of January 2, 2005, filed as Exhibit 10.34 to the Company’s Form 10-K for the period ended December 31, 2004†† |
| | |
**10.39† | | 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†† |
| | |
**10.40† | | 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†† |
| | |
**10.41† | | 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†† |
| | |
**10.42† | | 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 |
| | |
**10.43† | | 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 |
| | |
**10.44† | | Form of stock option agreement for 1993 Stock Compensation Plan, filed as Exhibit 10.32 to the Company’s Form
10-K for the period ended December 31, 2004 |
| | |
**10.45† | | 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 |
| | |
**10.46 | | Letter agreement dated October 20, 2005 between Clayton Williams Energy, Inc. and Lariat Services, Inc., filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on October 27, 2005†† |
| | |
**21 | | Subsidiaries of the Registrant, filed as Exhibit 21 to the Company’s Form S-4 Registration Statement, Commission File No 333-128065 |
| | |
*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 |
58
*32.1 | | Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350 |
* | | Filed herewith |
** | | Incorporated by reference to the filing indicated |
† | | 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. |
59
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.
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.
Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known 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.
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.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of natural gas equivalents.
60
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 acres or wells multiplied, in each case, by the percentage working interest owned by the Company.
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. 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.
Proved developed nonproducing reserves. Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves. Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.
Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.
Proved reserves. The estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Proved undeveloped reserves (PUD). Proved reserves 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.
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.
61
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 commercial quantities of oil and 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.
61
SIGNATURES
In accordance with 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 |
In accordance with 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 15, 2006 |
Clayton W. Williams | | President and Chief Executive | | |
| | Officer and Director | | |
| | | | |
/s/ L. PAUL LATHAM | | Executive Vice President, | | March 15, 2006 |
L. Paul Latham | | Chief Operating Officer and | | |
| | Director | | |
| | | | |
/s/ MEL G. RIGGS | | Senior Vice President - | | March 15, 2006 |
Mel G. Riggs | | Finance, Secretary, Treasurer, | | |
| | Chief Financial Officer and Director | | |
| | | | |
/s/ MICHAEL L. POLLARD | | Vice President – Accounting and | | March 15, 2006 |
Michael L. Pollard | | Principal Accounting Officer | | |
| | | | |
/s/ STANLEY S. BEARD * | | Director | | March 15, 2006 |
Stanley S. Beard | | | | |
| | | | |
/s/ DAVIS L. FORD * | | Director | | March 15, 2006 |
Davis L. Ford | | | | |
| | | | |
/s/ ROBERT L. PARKER * | | Director | | March 15, 2006 |
Robert L. Parker | | | | |
| | | | |
/s/ JORDAN R. SMITH * | | Director | | March 15, 2006 |
Jordan R. Smith | | | | |
| | | | |
|
* | By: | /s/ L. PAUL LATHAM | | | | |
L. Paul Latham | | | | |
Attorney-in-Fact | | | | |
| | | | | | |
62
CLAYTON WILLIAMS ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
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, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2005. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, 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, present fairly, in all material respects, the information set forth therein.
As discussed in Note 5 of the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for abandonment obligations in accordance with Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations”.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Clayton Williams Energy, Inc.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 15, 2006, expressed an unqualified opinion on management’s assessment of, and the effective operations of, internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 15, 2006
F-2
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
ASSETS
| | December 31, | |
| | 2005 | | 2004 | |
CURRENT ASSETS | | | | | |
Cash and cash equivalents | | $ | 5,935 | | $ | 16,359 | |
Accounts receivable: | | | | | |
Oil and gas sales | | 28,317 | | 25,573 | |
Joint interest and other, net | | 6,972 | | 4,653 | |
Affiliates | | 254 | | 553 | |
Inventory | | 43,753 | | 5,202 | |
Deferred income taxes | | 439 | | 625 | |
Fair value of derivatives | | 191 | | 2,333 | |
Prepaids and other | | 2,581 | | 1,401 | |
| | 88,442 | | 56,699 | |
PROPERTY AND EQUIPMENT | | | | | |
Oil and gas properties, successful efforts method | | 1,037,862 | | 909,095 | |
Natural gas gathering and processing systems | | 18,034 | | 17,286 | |
Other | | 12,396 | | 11,839 | |
| | 1,068,292 | | 938,220 | |
Less accumulated depreciation, depletion and amortization | | (594,225 | ) | (539,860 | ) |
Property and equipment, net | | 474,067 | | 398,360 | |
| | | | | |
OTHER ASSETS | | | | | |
Debt issue costs | | 8,557 | | 3,575 | |
Advances to drilling rig joint venture | | 10,329 | | — | |
Fair value of derivatives | | 127 | | — | |
Other | | 5,813 | | 3,601 | |
| | 24,826 | | 7,176 | |
| | $ | 587,335 | | $ | 462,235 | |
The accompanying notes are an integral part of these consolidated financial statements.
F-3
LIABILITIES AND STOCKHOLDERS’ EQUITY
| | December 31, | |
| | 2005 | | 2004 | |
CURRENT LIABILITIES | | | | | |
Accounts payable: | | | | | |
Trade | | $ | 59,861 | | $ | 51,014 | |
Oil and gas sales | | 18,236 | | 11,223 | |
Affiliates | | 2,857 | | 2,954 | |
Current maturities of long-term debt | | 19 | | 31 | |
Fair value of derivatives | | 33,670 | | 16,026 | |
Accrued liabilities and other | | 9,611 | | 3,017 | |
| | 124,254 | | 84,265 | |
NON-CURRENT LIABILITIES | | | | | |
Long-term debt | | 235,700 | | 177,519 | |
Deferred income taxes | | 37,042 | | 36,897 | |
Fair value of derivatives | | 49,705 | | 28,958 | |
Other | | 20,343 | | 17,000 | |
| | 342,790 | | 260,374 | |
| | | | | |
COMMITMENTS AND CONTINGENCIES | | | | | |
| | | | | |
STOCKHOLDERS’ EQUITY | | | | | |
Preferred stock, par value $.10 per share, authorized – 3,000,000 shares; none issued | | — | | — | |
Common stock, par value $.10 per share, authorized – 30,000,000 shares; issued and outstanding – 10,815,575 shares in 2005 and 10,787,013 shares in 2004 | | 1,082 | | 1,078 | |
Additional paid-in capital | | 107,108 | | 104,674 | |
Retained earnings | | 12,101 | | 11,844 | |
| | 120,291 | | 117,596 | |
| | $ | 587,335 | | $ | 462,235 | |
| | | | | | | | | |
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, | |
| | 2005 | | 2004 | | 2003 | |
REVENUES | | | | | | | |
Oil and gas sales | | $ | 252,599 | | $ | 193,127 | | $ | 163,032 | |
Natural gas services | | 12,080 | | 9,083 | | 8,758 | |
Gain on sales of property and equipment | | 18,920 | | 4,120 | | 267 | |
Total revenues | | 283,599 | | 206,330 | | 172,057 | |
| | | | | | | |
COSTS AND EXPENSES | | | | | | | |
Production | | 57,404 | | 41,163 | | 28,239 | |
Exploration: | | | | | | | |
Abandonments and impairments | | 39,957 | | 67,956 | | 35,120 | |
Seismic and other | | 10,780 | | 7,124 | | 8,755 | |
Natural gas services | | 11,212 | | 8,538 | | 8,279 | |
Depreciation, depletion and amortization | | 47,509 | | 44,040 | | 40,284 | |
Impairment of property and equipment | | 18,266 | | — | | 170 | |
Accretion of abandonment obligations | | 1,158 | | 1,044 | | 651 | |
General and administrative | | 15,410 | | 11,689 | | 10,934 | |
Loss on sales of property and equipment | | 209 | | 14,337 | | 68 | |
Other | | 1,353 | | — | | — | |
Total costs and expenses | | 203,258 | | 195,891 | | 132,500 | |
| | | | | | | |
Operating income | | 80,341 | | 10,439 | | 39,557 | |
| | | | | | | |
OTHER INCOME (EXPENSE) | | | | | | | |
Interest expense | | (14,498 | ) | (7,877 | ) | (3,138 | ) |
Loss on derivatives | | (70,059 | ) | (25,329 | ) | (1,593 | ) |
Other | | 4,022 | | 1,354 | | (1,662 | ) |
Total other income (expense) | | (80,535 | ) | (31,852 | ) | (6,393 | ) |
| | | | | | | |
Income (loss) before income taxes | | (194 | ) | (21,413 | ) | 33,164 | |
Income tax expense (benefit) | | (451 | ) | (7,385 | ) | 10,515 | |
Income (loss) from continuing operations | | 257 | | (14,028 | ) | 22,649 | |
Cumulative effect of accounting change, net of tax | | — | | — | | 207 | |
| | | | | | | |
NET INCOME (LOSS) | | $ | 257 | | $ | (14,028 | ) | $ | 22,856 | |
| | | | | | | | | | |
Net income (loss) per common share: | | | | | | | |
Basic: | | | | | | | |
Income (loss) from continuing operations | | $ | .02 | | $ | (1.37 | ) | $ | 2.43 | |
Net income (loss) | | $ | .02 | | $ | (1.37 | ) | $ | 2.45 | |
| | | | | | | |
Diluted: | | | | | | | |
Income (loss) from continuing operations | | $ | .02 | | $ | (1.37 | ) | $ | 2.38 | |
Net income (loss) | | $ | .02 | | $ | (1.37 | ) | $ | 2.40 | |
| | | | | | | |
Weighted average common shares outstanding: | | | | | | | |
Basic | | 10,804 | | 10,213 | | 9,329 | |
Diluted | | 11,241 | | 10,213 | | 9,509 | |
The accompanying notes are an integral part of these consolidated financial statements.
F-5
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
| | | | | | | | | | Accumulated | | | |
| | | | | | | | | | Other | | Total | |
| | | | | | | | | | Compre- | | Compre- | |
| | Common Stocks | | Additional | | Retained | | hensive | | hensive | |
| | No. of | | Par | | Paid-In | | Earnings | | Income | | Income | |
| | Shares | | Value | | Capital | | (Loss) | | (Loss) | | (Loss) | |
BALANCE, | | | | | | | | | | | | | |
December 31, 2002 | | 9,277 | | $ | 928 | | $ | 72,787 | | $ | 3,016 | | $ | (7,950 | ) | | |
Net income | | — | | — | | — | | 22,856 | | — | | $ | 22,856 | |
Change in fair value of derivatives designated as cash flow hedges, net of tax | | — | | — | | — | | — | | 7,950 | | 7,950 | |
Total comprehensive income | | | | | | | | | | | | $ | 30,806 | |
Issuance of stock through compensation plans | | 91 | | 9 | | 1,185 | | — | | — | | | |
| | | | | | | | | | | | | |
BALANCE, | | | | | | | | | | | | | |
December 31, 2003 | | 9,368 | | 937 | | 73,972 | | 25,872 | | — | | | |
Net loss and total comprehensive loss | | — | | — | | — | | (14,028 | ) | — | | $ | (14,028 | ) |
Issuance of stock throughcompensation plans | | 38 | | 3 | | 853 | | — | | — | | | |
Issuance of common stock, net of offering costs of $1,773 | | 1,381 | | 138 | | 29,849 | | — | | — | | | |
| | | | | | | | | | | | | |
BALANCE, | | | | | | | | | | | | | |
December 31, 2004 | | 10,787 | | $ | 1,078 | | $ | 104,674 | | $ | 11,844 | | $ | — | | | |
Net income and total comprehensive income | | — | | — | | — | | 257 | | — | | $ | 257 | |
Restricted stock issued as compensation | | 9 | | 1 | | 270 | | — | | — | | | |
Issuance of stock through compensation plans | | 19 | | 3 | | 2,164 | | — | | — | | | |
BALANCE, | | | | | | | | | | | | | |
December 31, 2005 | | 10,815 | | $ | 1,082 | | $ | 107,108 | | $ | 12,101 | | $ | — | | | |
The accompanying notes are an integral part of these consolidated financial statements.
F-6
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| | Year Ended December 31, | |
| | 2005 | | 2004 | | 2003 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | |
Net income (loss) | | $ | 257 | | $ | (14,028 | ) | $ | 22,856 | |
Adjustments to reconcile net income (loss) to cash provided by operating activities | | | | | | | |
Depreciation, depletion and amortization | | 47,509 | | 44,040 | | 40,284 | |
Impairment of property and equipment | | 18,266 | | — | | 170 | |
Exploration costs | | 39,957 | | 67,956 | | 35,120 | |
Gain (loss) on sales of property and equipment, net | | (18,711 | ) | 10,217 | | (199 | ) |
Deferred income taxes | | (526 | ) | (7,645 | ) | 10,172 | |
Non-cash employee compensation | | 2,998 | | 536 | | 1,312 | |
Loss on derivatives | | 40,406 | | 7,104 | | 1,546 | |
Settlements on derivatives with financing elements | | 27,731 | | 9,890 | | — | |
Amortization of debt issue costs | | 2,631 | | — | | — | |
Accretion of abandonment obligations | | 1,158 | | 1,044 | | 651 | |
Cumulative effect of accounting change, net of tax | | — | | — | | (207 | ) |
| | | | | | | |
Changes in operating working capital: | | | | | | | |
Accounts receivable | | (4,764 | ) | 581 | | (1,787 | ) |
Accounts payable | | 1,707 | | 8,881 | | 8,655 | |
Other | | 4,856 | | (1,596 | ) | 1,177 | |
Net cash provided by operating activities | | 163,475 | | 126,980 | | 119,750 | |
| | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | |
Additions to property and equipment | | (172,987 | ) | (123,991 | ) | (62,889 | ) |
Investment in Southwest Royalties, Inc. | | — | | (168,204 | ) | — | |
Proceeds from sales of property and equipment | | 23,252 | | 35,020 | | 239 | |
Change in equipment inventory | | (36,519 | ) | — | | — | |
Other | | (10,411 | ) | 269 | | (2,120 | ) |
Net cash used in investing activities | | (196,665 | ) | (256,906 | ) | (64,770 | ) |
| | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | |
Proceeds from long-term debt | | 235,700 | | 172,500 | | — | |
Repayments of long-term debt | | (177,531 | ) | (60,530 | ) | (45,483 | ) |
Proceeds from sale of common stock | | 292 | | 30,018 | | 281 | |
Settlements on derivatives with financing elements | | (27,731 | ) | (9,890 | ) | — | |
Payment of debt issue costs | | (7,964 | ) | (4,156 | ) | — | |
Other | | — | | 2,889 | | — | |
Net cash provided by (used in) financing Activities | | 22,766 | | 130,831 | | (45,202 | ) |
| | | | | | | |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | | (10,424 | ) | 905 | | 9,778 | |
| | | | | | | |
CASH AND CASH EQUIVALENTS | | | | | | | |
Beginning of period | | 16,359 | | 15,454 | | 5,676 | |
End of period | | $ | 5,935 | | $ | 16,359 | | $ | 15,454 | |
| | | | | | | | | | |
SUPPLEMENTAL DISCLOSURES | | | | | | | |
Cash paid for interest, net of amounts capitalized | | $ | 4,343 | | $ | 7,246 | | $ | 2,941 | |
Cash paid for income taxes | | $ | 365 | | $ | 90 | | $ | — | |
The accompanying notes are an integral part of these consolidated financial statements.
F-7
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations
Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company”) is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in Texas, Louisiana and New Mexico. Approximately 45% of the Company’s outstanding common stock is beneficially owned by its Chairman of the Board and Chief Executive Officer, Clayton W. Williams (“Mr. Williams”). Oil and gas exploration and production is the only business segment in which the Company operates.
Substantially all of the Company’s oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, the Company’s financial condition, 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 the control of the Company. 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.
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 management of the Company 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 period. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:
• The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization, and to determine the amount of any impairment of proved properties;
• The valuation of unproved acreage and proved oil and gas properties to determine the amount of any impairments of oil and gas properties;
• Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment;
• Estimates regarding abandonment obligations; and
• Estimates regarding the future utilization of net operating loss carryforwards.
Principles of Consolidation
The consolidated financial statements include the accounts of Clayton Williams Energy, Inc. and its subsidiaries. The Company accounts for its undivided interest in oil and gas limited partnerships using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are consolidated with other operations. All significant intercompany transactions and balances associated with the consolidated operations have been eliminated.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its 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
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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 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 the costs of repairs and maintenance are charged to expense as incurred. The costs 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 other 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 12 years.
Valuation of Property and Equipment
The Company follows the provisions of Statement of Financial Accounting Standards No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS 144”). SFAS 144 requires that the Company’s long-lived assets, including its oil and gas properties, be 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 differences in the carrying value and estimated fair value of the impaired asset.
SFAS 144 provides for future revenue from the Company’s oil and gas production to be estimated based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to management’s estimates of future production or product prices could result in an impairment of the Company’s oil and gas properties in subsequent periods.
Unproved oil and gas properties with individually significant acquisition costs 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 amortizing the costs of such properties within appropriate groups based on the Company’s historical experience, acquisition dates and average lease terms. At December 31, 2005, the Company’s unproved oil and gas properties had an aggregate net book value of $79.9 million, including $10.3 million of exploratory drilling costs for which the determination of proved reserves had not been made. None of these costs are attributable to wells for which drilling activities have been completed for more than one year. The valuation of unproved properties is subjective and requires management of the Company to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.
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Abandonment Obligations
The Company follows the provisions of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), as amended. SFAS 143 requires the Company to 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.
Income Taxes
The Company follows the asset and liability method prescribed by Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”). 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. Under SFAS 109, 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.
Hedging Activities
From time to time, the Company utilizes derivative instruments, consisting of swaps, floors and collars, to attempt to reduce its exposure to changes in commodity prices and interest rates. The Company accounts for its derivatives in accordance with Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended. SFAS 133 requires that all derivative instruments be 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 of SFAS 133, 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 of SFAS 133 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 the Company plans to utilize in its ongoing exploration and development activities and is carried at the lower of cost or market value.
Capitalization of Interest
Interest costs associated with the Company’s 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, 2005, 2004 and 2003, the Company capitalized interest totaling approximately $2.2 million, $877,000 and $1.1 million, respectively.
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Cash and Cash Equivalents
The Company considers 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 earnings per share are computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflect the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted earnings per share calculations for 2005 and 2003 include an increase in potential shares attributable to dilutive stock options. Stock options were not considered in the diluted earnings per share calculations for 2004 as the effect would be anti-dilutive.
Stock-Based Compensation
The Company accounts for stock-based compensation utilizing the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) and related interpretations. The following pro forma information, as required by Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by Statement of Financial Accounting Standards No. 148 (“SFAS 148”), presents net income and earnings per share information as if the stock options issued since December 31, 1994 were accounted for using the fair value method. 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 estimated fair value of the stock options issued in 2005, 2004 and 2003 was approximately $4.5 million, $5.9 million and $3 million; respectively. The following weighted average assumptions were used in this model.
| | 2005 | | 2004 | | 2003 | |
| | | | | | | |
Risk-free interest rate | | 3.9 | % | 2.5 | % | 2.5 | % |
Stock price volatility | | 67 | % | 69 | % | 70 | % |
Expected life in years | | 10 | | 10 | | 10 | |
Dividend yield | | — | | — | | — | |
The SFAS 123 pro forma information for the years ended December 31, 2005, 2004 and 2003 is as follows:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands, except per share) | |
Net income (loss), as reported | | $ | 257 | | $ | (14,028 | ) | $ | 22,856 | |
Add: Stock-based employee compensation expense (credit) included in net income (loss), net of tax | | 1,233 | | (159 | ) | 518 | |
Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax | | (2,920 | ) | (3,840 | ) | (2,602 | ) |
Net income (loss), pro forma | | $ | (1,430 | ) | $ | (18,027 | ) | $ | 20,772 | |
| | | | | | | |
Basic: | | | | | | | |
Net income (loss) per common share, as reported | | $ | .02 | | $ | (1.37 | ) | $ | 2.45 | |
Net income (loss) per common share, pro forma | | $ | (.13 | ) | $ | (1.77 | ) | $ | 2.23 | |
| | | | | | | |
Diluted: | | | | | | | |
Net income (loss) per common share, as reported | | $ | .02 | | $ | (1.37 | ) | $ | 2.40 | |
Net income (loss) per common share, pro forma | | $ | (.13 | ) | $ | (1.77 | ) | $ | 2.18 | |
F-11
Revenue Recognition and Gas Balancing
The Company utilizes 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 the Company is entitled based on its revenue interests in the properties. The Company did not have any significant gas imbalance positions at December 31, 2005 or 2004. Revenues from natural gas services are recognized as services are provided.
Comprehensive Income
Statement of Financial Accounting Standards No. 130 “Reporting Comprehensive Income” (“SFAS 130”) established standards for reporting and displaying of comprehensive income and its components (revenue, expenses, gains and losses) in a full set of general-purpose financial statements. There were no differences between net income and comprehensive income in 2005 and 2004. A portion of the changes in fair value of derivatives required under SFAS 133 was reported in comprehensive income during 2003.
Concentration Risks
The Company sells its oil and natural gas production to various customers, serves as operator in the drilling, completion and operation of oil and gas wells, and enters into derivatives with various counterparties. When management deems appropriate, the Company obtains letters of credit to secure amounts due from its principal oil and gas purchasers and follows other procedures to monitor credit risk from joint owners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2005 and 2004 relate to amounts due from joint interest owners.
Reclassifications
Certain reclassifications of prior year financial statement amounts have been made to conform to current year presentations.
Recent Accounting Pronouncements
In June 2005, the Emerging Issues Task Force (“EITF”) reached consensus on Issue 04-5 regarding when a limited partnership should be consolidated by its general partner. The proposed framework presumes that a sole general partner in a limited partnership controls the limited partnership. The presumption of control can be overcome if the limited partners have (i) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (ii) substantive participating rights. The EITF has concluded that a general partner lacks control if the limited partners can remove the general partner with a simple majority vote. The Company is the general partner of several oil and gas limited partnerships and presently consolidates its proportionate interest in the accounts of these partnerships. The Company is currently reviewing the applicable provisions of the partnership agreements to determine the impact that EITF 04-5 may have on its consolidated financial statements. For existing partnerships, EITF 04-5 will be effective for consolidated financial statements issued by the Company after January 1, 2006. EITF 04-5 is effective for newly created or modified limited partnerships subsequent to June 29, 2005. If the Company determines that the limited partners do not have the substantive ability to remove the general partner in accordance with EITF Issue 04-5, the Company will be required to fully consolidate the limited partnerships results, with the interest not owned by the Company reflected as minority interest. This would have no impact to the Company’s future net income from the current method of accounting for oil and gas limited partnerships using proportionate consolidation.
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payments” (“SFAS 123R”). SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value. The Company currently uses the intrinsic-value method to account for these share-based payments. For public companies, SFAS 123R is effective for fiscal years beginning after June 15, 2005. The Company will adopt the provisions of this statement in the first quarter of 2006. The Company has accounted for options which
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were repriced in 1999 as variable stock options whereby compensation expense has been recognized through December 31, 2005 for unexercised options based on changes in the market value of the Company’s common stock. In accordance with SFAS 123R, the Company will cease accounting for these options as variable stock options upon the adoption date. Since all of the Company’s outstanding options are fully vested at December 31, 2005, no future compensation expense will be recognized under SFAS 123R unless the options are modified. Accordingly, future compensation expense to be recognized under SFAS 123R will be determined based on the grant date fair value of future awards.
In April 2005, the FASB issued Staff Position No. 19-1 (“FSP 19-1”). FSP 19-1 amends the present guidance in SFAS 19, paragraphs 31 and 34, regarding when exploratory drilling costs pending determination of proved reserves can be carried as an asset of an oil and gas company that uses the successful efforts accounting method. The Company was required to adopt FSP 19-1, including its disclosures, effective July 1, 2005. The adoption of FSP 19-1 did not have a significant impact on the Company’s results of operations. At December 31, 2005 and December 31, 2004, the Company had capitalized $10.3 million and $5.4 million, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves. Substantially all of the December 31, 2004 capitalized costs were subsequently classified as non-productive.
3. Acquisition of Southwest Royalties
On May 21, 2004, the Company acquired all the outstanding common stock of Southwest Royalties, Inc. (“SWR”) through a merger. Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, production, development and acquisition activities in the United States. Most of SWR’s properties are located in the Permian Basin of west Texas and southeastern New Mexico.
In connection with the acquisition of SWR, the Company paid $57.1 million to holders of SWR common stock and common stock warrants and assumed and refinanced approximately $113.9 million of SWR bank debt at closing. In addition, the Company incurred approximately $9.4 million of merger-related costs, including (i) the assumption of SWR’s obligations to its officers and employees pursuant to change of control arrangements and (ii) investment banking, legal, accounting and other direct transaction costs related to the acquisition of SWR.
The Company has accounted for the acquisition of SWR using the purchase method of accounting for business combinations. Under this method of accounting, the Company is deemed to be the acquirer for accounting purposes. SWR’s assets and liabilities were revalued under the purchase method of accounting and recorded at their estimated fair values.
Pursuant to SFAS 149, which amended SFAS 133, the derivative instruments assumed in connection with the SWR acquisition are deemed to contain a significant financing element, and all cash flow associated with these positions are reported as a financing activity in the statement of cash flows.
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The following table sets forth the calculation of the purchase price for SWR and the related allocation of the purchase price to the assets acquired (in thousands):
Purchase price: | | | |
Acquisition of outstanding common stock and warrants | | $ | 57,139 | |
Long-term debt assumed and refinanced | | 113,949 | |
Assumption of other non-current liabilities | | 31,024 | |
Transaction costs incurred | | 9,355 | |
Current liabilities assumed | | 26,546 | |
Deferred income taxes | | 36,655 | |
| | $ | 274,668 | |
Allocation of purchase price: | | | |
Current assets | | $ | 23,436 | |
Proved oil and gas properties | | 229,238 | |
Unproved oil and gas properties | | 18,130 | |
Other property and equipment | | 3,494 | |
Other assets | | 370 | |
| | $ | 274,668 | |
The revaluation of SWR’s assets and liabilities under the purchase method of accounting created significant differences between the carrying value for financial reporting purposes and those used for income tax reporting purposes, resulting in federal and state deferred tax liabilities of $36.6 million on the effective date of the acquisition.
The following table reflects the unaudited pro forma results of operations for the years ended December 31, 2004 and 2003 as though the acquisition of SWR had occurred on January 1, 2003. The pro forma amounts are not necessarily indicative of the results that may be reported in the future.
| | Year Ended | |
| | December 31, | |
| | 2004 | | 2003 | |
| | (In thousands, except per share data) | |
Revenues | | $ | 230,163 | | $ | 226,297 | |
Net income (loss) from continuing operations | | $ | (25,233 | ) | $ | 19,434 | |
| | | | | |
Net income (loss) from continuing operations per share: | | | | | |
Basic | | $ | (2.34 | ) | $ | 1.81 | |
Diluted | | $ | (2.34 | ) | $ | 1.78 | |
| | | | | | | | |
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4. Long-Term Debt
Long-term debt at December 31, 2005 and 2004 consists of the following:
| | 2005 | | 2004 | |
| | (In thousands) | |
7¾% Senior Notes due 2013 | | $ | 225,000 | | $ | — | |
Secured bank credit facilities: | | | | | |
Revolving loan, due May 2007 | | 10,700 | | 147,500 | |
Senior term loan, due May 2008 | | — | | 30,000 | |
Other | | 19 | | 50 | |
| | 235,719 | | 177,550 | |
Less current maturities | | (19 | ) | (31 | ) |
| | $ | 235,700 | | $ | 177,519 | |
| | | | | | | | | |
Aggregate maturities of long-term debt at December 31, 2005 are as follows: 2006 — $19,000; 2007 - $10.7 million; and 2013 - $225 million.
7¾% Senior Notes due 2013
In July 2005, the Company issued, in a private placement, $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. After the payment of typical transaction expenses, net proceeds of approximately $217 million were used to repay all amounts outstanding under the secured bank credit facilities and for general corporate purposes, including the funding of planned exploration and development activities.
At any time prior to August 1, 2008, the Company may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a redemption price of 107.75% of the principal amount, plus accrued and unpaid interest. In addition, prior to August 1, 2009, the Company may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. On and after August 1, 2009, the Company 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 100.00% beginning on August 1, 2011, for any period thereafter, in each case plus accrued and unpaid interest.
The Indenture governing the Senior Notes restricts the ability of the Company and its restricted subsidiaries to: (i) borrow money; (ii) issue redeemable and preferred stock; (iii) pay distributions or dividends; (iv) make investments; (v) create liens without securing the Senior Notes; (vi) enter into agreements that restrict dividends from subsidiaries; (vii) sell certain assets or merge with or into other companies; (viii) enter into transactions with affiliates; (ix) guarantee indebtedness; and (x) enter into new lines of business.
Secured Bank Credit Facility
The Company’s secured bank credit facility provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually in May and November, and is made at the discretion of the banks. If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five
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equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. Substantially all of the Company’s oil and gas properties are pledged to secure advances under the credit facility. At December 31, 2005, the borrowing base established by the banks was $150 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $804,000, the Company had $138.5 million available under the credit facility at December 31, 2005.
The revolving credit facility provides for interest at rates based on the agent bank’s prime rate plus margins ranging from .25% to 1%, or if elected by the Company, based on LIBOR plus margins ranging from 1.5% to 2.25%. The Company also pays a commitment fee on the unused portion of the revolving credit facility. Initially, the senior term credit facility provided for interest at rates based on the agent bank’s prime rate plus a margin of 3.5%, or if elected by the Company based on LIBOR plus a margin of 5%. Subsequently, the prime rate margin was reduced to 2.5%, and the LIBOR margin was reduced to 4%. Interest and fees are payable at least quarterly. The effective annual interest rate on borrowings under the credit facility, including bank fees for the year ended December 31, 2005 was 7.5%. Included in interest expense for 2005 is a non-cash charge to write off $1.8 million of debt issue costs related to the early repayment of the senior term credit facility and the reduction in the borrowing base on the revolving credit facility.
The loan agreement applicable to the revolving credit facility contains financial covenants that are computed quarterly. The working capital covenant requires the Company to maintain a ratio of current assets to current liabilities of at least 1 to 1. Another financial covenant under the credit facility requires the Company to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. The computations of current assets, current liabilities, cash flow and indebtedness are defined in the loan agreement. The Company was in compliance with all financial and non-financial covenants at December 31, 2005.
5. Other Non-Current Liabilities
Other non-current liabilities at December 31, 2005 and 2004 consist of the following:
| | 2005 | | 2004 | |
| | (In thousands) | |
Abandonment obligations | | $ | 19,447 | | $ | 16,147 | |
Other | | 896 | | 853 | |
| | $ | 20,343 | | $ | 17,000 | |
Abandonment Obligations
Upon adoption of SFAS 143 on January 1, 2003, the Company increased abandonment obligations by $4.1 million, increased asset costs by $1.5 million, reduced accumulated depreciation, depletion and amortization by $2.9 million, and recorded an after-tax credit of $207,000 for the cumulative effect of adoption on prior years.
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Changes in abandonment obligations for 2005 and 2004 are as follows:
| | 2005 | | 2004 | |
| | (In thousands) | |
Beginning of year | | $ | 16,147 | | $ | 8,849 | |
Abandonment obligations related to the acquisition of SWR | | — | | 8,512 | |
Additional abandonment obligations from new wells | | 796 | | 411 | |
Sales of properties | | (617 | ) | (2,711 | ) |
Accretion expense | | 1,158 | | 1,044 | |
Revisions of previous estimates | | 1,963 | | 42 | |
End of year | | $ | 19,447 | | $ | 16,147 | |
6. 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, 2005 and 2004 are as follows:
| | 2005 | | 2004 | |
| | (In thousands) | |
Deferred tax assets: | | | | | |
Net operating loss carryforwards | | $ | 2,497 | | $ | 7,915 | |
Accrued stock-based compensation | | — | | 240 | |
Fair value of derivatives | | 28,906 | | 14,930 | |
Credits related to alternative minimum tax | | 395 | | 279 | |
Statutory depletion carryforwards | | 3,861 | | 3,209 | |
Other | | 5,748 | | 5,058 | |
| | 41,407 | | 31,631 | |
Deferred tax liabilities: | | | | | |
Property and equipment | | (78,010 | ) | (67,903 | ) |
Net deferred tax liabilities | | $ | (36,603 | ) | $ | (36,272 | ) |
| | | | | |
Components of net deferred tax liabilities: | | | | | |
Current assets | | $ | 439 | | $ | 625 | |
Non-current liabilities | | (37,042 | ) | (36,897 | ) |
| | $ | (36,603 | ) | $ | (36,272 | ) |
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For the years ended December 31, 2005, 2004 and 2003, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
| | | | | | | |
Income tax expense (benefit) at statutory rate of 35% | | $ | (68 | ) | $ | (7,495 | ) | $ | 11,608 | |
Tax depletion in excess of basis | | (613 | ) | (447 | ) | (210 | ) |
Revision of previous tax estimates | | 102 | | (51 | ) | (12 | ) |
Change in valuation allowance | | — | | — | | (871 | ) |
State income taxes, net of federal tax effect | | (40 | ) | 608 | | — | |
Other | | 168 | | — | | — | |
Income tax expense (benefit) | | $ | (451 | ) | $ | (7,385 | ) | $ | 10,515 | |
| | | | | | | |
Current | | $ | 75 | | $ | 260 | | $ | 343 | |
Deferred | | (526 | ) | (7,645 | ) | 10,172 | |
Income tax expense (benefit) | | $ | (451 | ) | $ | (7,385 | ) | $ | 10,515 | |
The Company derives an income tax benefit when employees and directors exercise options granted under the Company’s stock compensation plans (see Note 10). Employee stock options that are classified as fixed stock options under APB 25 do not result in a charge against book income when the option price is equal to or greater than the market price at date of grant. Therefore, any tax benefit from the exercise of fixed stock options results in a permanent difference, which is recorded to additional paid-in capital when the tax benefit is realized.
In connection with the SWR merger, the Company acquired $29.3 million of tax loss carryforwards that are subject to limitations under Internal Revenue Code Section 382 from a prior change in control that occurred in April 2002 and from the change in control of SWR that occurred in connection with the Company’s acquisition of SWR in May 2004. The Company has completed a review of the facts surrounding these changes in control and presently believes that it will be able to utilize all of SWR’s tax loss carryforwards.
At December 31, 2005, the Company’s cumulative tax loss carryforwards were approximately $7.1 million. Based upon current commodity prices and production volumes, as well as the availability of tax planning strategies (such as elective capitalization of intangible drilling costs), the Company believes that it is more likely than not that the Company will be able to utilize these tax loss carryforwards before they expire (beginning in 2008). Accordingly, no valuation allowance has been provided at December 31, 2005.
7. Derivatives
Commodity Derivatives
From time to time, the Company utilizes commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for its oil and gas production. When using swaps to hedge oil and natural gas production, the Company receives a fixed price for the respective commodity and pays 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, the Company receives 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
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the put strike price, then the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike prices, no payments are due from either party.
The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2005. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Collars:
| | Gas | | Oil | |
| | MMBtu (a) | | Floor | | Ceiling | | Bbls | | Floor | | Ceiling | |
Production Period: | | | | | | | | | | | | | |
1st Quarter 2006 | | 561,000 | | $ | 4.00 | | $ | 5.21 | | 157,000 | | $ | 23.00 | | $ | 25.32 | |
2nd Quarter 2006 | | 551,000 | | $ | 4.00 | | $ | 5.21 | | 156,000 | | $ | 23.00 | | $ | 25.32 | |
3rd Quarter 2006 | | 456,000 | | $ | 4.00 | | $ | 5.21 | | 150,000 | | $ | 23.00 | | $ | 25.32 | |
4th Quarter 2006 | | 456,000 | | $ | 4.00 | | $ | 5.21 | | 150,000 | | $ | 23.00 | | $ | 25.32 | |
2007 | | 1,831,000 | | $ | 4.00 | | $ | 5.18 | | 562,000 | | $ | 23.00 | | $ | 25.20 | |
2008 | | 1,279,000 | | $ | 4.00 | | $ | 5.15 | | 392,000 | | $ | 23.00 | | $ | 25.07 | |
| | 5,134,000 | | | | | | 1,567,000 | | | | | |
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.
The Company is a party to interest rate swaps that were acquired in connection with the SWR acquisition. Under these derivatives, the Company pays a fixed rate for the notional principal balances and receives a floating market rate based on LIBOR. The following summarizes information concerning the Company’s net positions in open interest rate swaps applicable to periods subsequent to December 31, 2005.
Interest Rate Swaps:
| | | | Fixed | |
| | Principal | | Libor | |
| | Balance | | Rates | |
Period: | | | | | |
January 1, 2006 to November 1, 2006 | | $ | 55,000,000 | | 4.29 | % |
November 1, 2006 to November 1, 2007 | | $ | 50,000,000 | | 5.19 | % |
November 1, 2007 to November 1, 2008 | | $ | 45,000,000 | | 5.73 | % |
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Accounting For Derivatives
The Company accounts for its derivatives in accordance with SFAS 133, as amended. The following table sets forth, for the year ended December 31, 2003, the components of accumulated other comprehensive income, as reported in stockholders’ equity, all of which is related to derivatives designated as cash flow hedges under SFAS 133. There was no activity in this account during 2004 or 2005.
| | Accumulated Other | |
| | Comprehensive Income (Loss) | |
| | Commodity | | Interest Rate | | | |
| | Derivatives | | Derivatives | | Total | |
| | (In thousands) | |
| | | |
Balance, December 31, 2002 | | (7,290 | ) | (660 | ) | (7,950 | ) |
Loss on derivatives, net of tax | | (5,429 | ) | (50 | ) | (5,479 | ) |
Reclassifications to earnings, net of tax | | 12,719 | | 710 | | 13,429 | |
Net changes during the period | | 7,290 | | 660 | | 7,950 | |
Balance, December 31, 2003 | | $ | — | | $ | — | | $ | — | |
| | | | | | | | | | |
The Company did not designate any of its currently open positions in commodity hedges 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 the Company’s statements of operations. For 2005, loss on derivatives related to undesignated contracts consisted of net realized losses of $29.7 million and losses related to changes in mark-to-market valuations of $40.4 million. For 2004, loss on derivates related to undesignated contracts consisted of net realized losses of $18.2 million and losses related to changes in mark-to-market valuations of $7.1 million.
8. Financial Instruments
Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive.
The fair values of derivatives as of December 31, 2005 and 2004 are set forth below.
| | 2005 | | 2004 | |
| | (In thousands) | |
Assets (liabilities): | | | | | |
Commodity derivatives | | $ | (82,635 | ) | $ | (41,162 | ) |
Interest rate derivatives | | (422 | ) | (1,489 | ) |
Net assets (liabilities) | | $ | (83,057 | ) | $ | (42,651 | ) |
| | | | | | | | |
9. Common Stock
In a series of seven monthly transactions from February 2005 through August 2005, the Company issued a total of 9,268 shares of restricted common stock to Mr. Williams in lieu of net cash compensation aggregating $270,000.
In May 2004, the Company sold 1,380,869 shares of its common stock to certain institutional investors at a price of $23.00 per share in a private placement for proceeds of approximately
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$31.8 million. After the payment of typical transaction expenses, net proceeds of approximately $30 million were used to repay a portion of the bank indebtedness incurred to finance the acquisition of SWR (see Note 3).
10. Compensation Plans
1993 Plan
The Company has reserved 1,798,200 shares of common stock for issuance under the 1993 Stock Compensation Plan (“1993 Plan”). The 1993 Plan provides for the issuance of nonqualified stock options with an exercise price which is not less than the market value of the Company’s common stock on the date of grant. All options granted through December 31, 2005 expire 10 years from the date of grant and become exercisable based on varying vesting schedules.
The following table reflects activity in the 1993 Plan for 2005, 2004 and 2003.
| | 2005 | | 2004 | | 2003 | |
| | | | Weighted | | | | Weighted | | | | Weighted | |
| | | | Average | | | | Average | | | | Average | |
| | Shares | | Price | | Shares | | Price | | Shares | | Price | |
Beginning of year | | 1,117,136 | | $ | 17.75 | | 821,042 | | $ | 14.66 | | 680,850 | | $ | 12.29 | |
Granted | | 200,000 | | $ | 29.39 | | 300,000 | | $ | 26.06 | | 200,000 | | $ | 19.74 | |
Exercised | | (3,585 | ) | $ | 5.50 | | (3,906 | ) | $ | 5.50 | | (59,808 | ) | $ | 4.03 | |
End of year | | 1,313,551 | | $ | 19.56 | | 1,117,136 | | $ | 17.75 | | 821,042 | | $ | 14.66 | |
| | | | | | | | | | | | | |
Exercisable | | 1,313,551 | | $ | 19.56 | | 1,117,136 | | $ | 17.75 | | 821,042 | | $ | 14.66 | |
Available for grant | | 101,766 | | | | 301,766 | | | | 601,766 | | | |
The following table summarizes information with respect to options outstanding at December 31, 2005, all of which are currently exercisable.
| | Outstanding and Exercisable Options | |
| | | | | | Weighted | |
| | | | Weighted | | Average | |
| | | | Average | | Remaining | |
| | | | Exercise | | Life in | |
| | Shares | | Price | | Years | |
Range of exercise prices: | | | | | | | |
$5.50 | | 162,551 | | $ | 5.50 | | 2.3 | |
$14.50 - $29.39 | | 1,151,000 | | $ | 21.54 | | 5.3 | |
| | 1,313,551 | | $ | 19.56 | | 4.2 | |
Directors Plan
The Company has reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”). Since inception of the Directors Plan, the Company has issued options covering 40,000 shares of common stock at option prices ranging from $3.25 to $28.93 per share. All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance. At December 31, 2005, options to purchase 25,000 shares were outstanding, and 46,300 shares remain available for future grants.
Bonus Incentive Plan
The Company has reserved 115,500 shares of common stock for issuance under the Bonus Incentive Plan. The plan provides that the Board of Directors each year may award bonuses in cash, common stock of
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the Company, or a combination thereof. At December 31, 2005, 106,190 shares remain available for issuance under this plan.
Executive Stock Compensation Plan
The Company has a compensation plan which permits the Company to pay all or part of selected executives’ salaries and bonuses in shares of common stock in lieu of cash. The Company reserved an aggregate of 500,000 shares of common stock for issuance under this plan. During 2005, 2004 and 2003, the Company issued 1,728, 18,609, and 15,275 shares, respectively, of common stock to Mr. Williams in lieu of cash salary and bonuses aggregating $36,000, $463,000, and $270,000, respectively. The amounts of such compensation are included in general and administrative expense in the accompanying consolidated financial statements. The plan terminated in February 2005.
401(k) Plan
Employees who have met certain age and length of employment requirements are eligible to participate in a 401(k) plan sponsored by the Company. Each participant may make annual contributions to the plan in amounts not to exceed the lesser of (i) 100% of the participant’s pre-tax annual earnings and (ii) the maximum amount of annual contributions allowed by law. The Company may, in its sole discretion, provide a matching contribution equal to a percentage of the participants’ contributions. The plan permits the Company to make its matching contributions in common stock of the Company. There are no vesting requirements in the plan. During 2005, 2004 and 2003, the Company contributed $379,000, $318,000 and $247,000, respectively, in market value of common stock to the 401(k) plan.
After-Payout Working Interest Incentive Plans
In September 2002, the Compensation Committee of the Board of Directors adopted an incentive plan for officers, key employees and consultants, excluding Mr. Williams, who promote the Company’s drilling and acquisition programs. Management’s objective in adopting this plan is to further align the interests of the participants with those of the Company by granting the participants an after-payout working interest in the production developed, directly or indirectly, by the participants. The plan provides for the creation of a series of limited partnerships to which the Company, as general partner, contributes a portion of its working interest in wells drilled within certain areas, and the key employee and consultants, as limited partners, contribute cash. The Company pays all costs and receives all revenues until payout of its costs, plus interest. At payout, the limited partners receive at least 99% of all subsequent revenues and pay at least 99% of all subsequent expenses attributable to the partnerships’ interests.
From 3% to 6% of the Company’s working interests in certain specified wells drilled by the Company subsequent to October 2002 are subject to this arrangement. The Company consolidates its proportionate share of the assets, liabilities, revenues, expenses and oil and gas reserves of these partnerships in its consolidated financial statements. In April 2004, one of the partnerships achieved payout, and the Company’s interest in the partnership was reduced to 1%. Aggregate cash distributions of approximately $292,000 were paid to the limited partners during 2005. During 2005, the Company recognized $680,000 of non-cash compensation expense for the estimated value of the after-payout interests contributed to the partnerships formed during the year.
11. Transactions with Affiliates
The Company and other entities (the “Williams Entities”) controlled by Mr. Williams are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, the Company provides legal, payroll, benefits administration, 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 tax preparation services, tax planning services, and business entertainment to or for the benefit of the
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Company. The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2005, 2004 and 2003.
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Amounts received from the Williams Entities: | | | | | | | |
Service Agreement: | | | | | | | |
Services | | $ | 224 | | $ | 314 | | $ | 288 | |
Insurance premiums and benefits | | 667 | | 691 | | 682 | |
Reimbursed expenses | | 356 | | 388 | | 357 | |
| | $ | 1,247 | | $ | 1,393 | | $ | 1,327 | |
Amounts paid to the Williams Entities: | | | | | | | |
Rent (a) | | $ | 582 | | $ | 493 | | $ | 402 | |
Service Agreement: | | | | | | | |
Business entertainment (b) | | 113 | | 113 | | 79 | |
Other services | | 150 | | 85 | | 45 | |
Reimbursed expenses | | 122 | | 105 | | 73 | |
| | $ | 967 | | $ | 796 | | $ | 599 | |
(a) Rent amounts were paid to the Partnership discussed in Note 12. 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.
Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for customary charges by the Company as operator of certain wells in which affiliates own an interest.
12. Investments
In May 2001, the Company invested approximately $1.6 million as a limited partner in ClayDesta Buildings, L.P. (“CDBLP”). The general partner of CDBLP is owned and controlled by Mr. Williams. CDBLP purchased and presently operates two commercial office buildings in Midland, Texas, one of which is the location of the Company’s corporate headquarters. The Company’s ownership interest in CDBLP is 31.9% before payout (as defined in the partnership agreement) and 33.4% after payout. The Company is not liable for any indebtedness of CDBLP. Since the Company does not control CDBLP or manage the operations of these buildings, and since CDBLP does not meet the characteristics of a variable interest entity under FIN 46R, the Company utilizes the equity method of accounting for its investment in CDBLP. For the years ended December 31, 2005, 2004 and 2003, the Company recorded pretax income of $10,000, $60,000, and $47,000, respectively, from the partnership.
In October 2003, the Company invested $1.5 million in a privately-held company organized by a third party to acquire and expand a CO2 distribution system in Pecos County, Texas. Of the total investment, 50% was for the purchase of common stock, representing 6.3% of the equity interests of the investee. The balance was a subordinated loan to the investee bearing interest at 6% per year. The Company accounts for the stock portion of its investment at cost. In December 2005, the Company exchanged its equity investment and note receivable for common stock of the entity’s parent company. The Company recorded the value of common stock received based upon the cash consideration paid for other interests acquired in the exchange offer. The Company recognized a gain of approximately $1.2 million upon the exchange, which is included in other income in the accompanying statement of operations.
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13. Commitments and Contingencies
Leases
The Company leases office space from affiliates and nonaffiliates under noncancelable operating leases. Rental expense pursuant to the office leases amounted to $779,000, $678,000 and $578,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
Future minimum payments under noncancelable leases at December 31, 2005, are as follows:
| | Leases | | | |
| | Capital (a) | | Operating | | Total | |
| | (In thousands) | |
2006 | | $ | 398 | | $ | 743 | | $ | 1,141 | |
2007 | | 307 | | 247 | | 554 | |
2008 | | 122 | | 18 | | 140 | |
Thereafter | | — | | 12 | | 12 | |
Total minimum lease payments | | $ | 827 | | $ | 1,020 | | $ | 1,847 | |
(a) Relates to vehicle leases.
Drilling Rig Joint Venture
In October 2005, the Company entered into a letter agreement with Lariat Services, Inc. (“Lariat”), a contract drilling company, which calls for the formation of a joint venture to acquire at least 12 new drilling rigs. The Company and Lariat will each own a 50% interest in the joint venture. Lariat will serve as the operations manager of the joint venture, and the Company will be responsible for financing the purchase of the rigs. The total acquisition cost, including construction and equipping of the rigs, is expected to be approximately $75 million.
The joint venture has received a proposal from a lender to provide financing for up to $75 million, depending on the appraised values of the drilling rigs upon completion of construction. During 2006, while the drilling rigs are being constructed, the proposal contemplates that the Company provide the lender a $19.5 million standby letter of credit as additional credit support. On or before December 31, 2006, the Company would terminate the letter of credit and provide an unconditional guaranty to the lender of the repayment and performance by the joint venture limited to $19.5 million of the outstanding balance of the loan facility. Under the terms of the proposal, the Company would also be required to contract with the joint venture to use the drilling rigs in its drilling program for a term of at least three years and to pay for idle, non-working rigs in amounts ranging from $8,000 to $11,000 per day. The Company expects to complete negotiations with the lender and to close the financing in March 2006.
At December 31, 2005, the Company had made advances on behalf of the joint venture of approximately $10.3 million for interim construction costs of the rigs and related equipment. The joint venture is to reimburse the Company for all advances once it has received the proceeds from the financing.
The Company is currently evaluating its investment in this joint venture to determine if the Company is the primary beneficiary under FIN 46R. If the Company determines that it is the primary beneficiary, the Company will be required to fully consolidate this entity in 2006.
Equipment Orders
As of December 31, 2005, the Company has placed firm orders for tubing, casing, pumping units and other equipment to be used in its exploration and development activities totaling approximately $8.6 million.
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Legal Proceedings
The Company 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 the Company’s consolidated financial condition or results of operations.
14. Impairment of Property and Equipment
The Company has recorded provisions for impairment of proved properties under SFAS 144 of $18.3 million in 2005 and $170,000 in 2003. The 2005 provision relates to production performance on prospects in West Texas. The 2003 provision relates to the Sweetlake area in south Louisiana. No provision was recorded in 2004.
The Company has also recorded provisions for impairment of unproved properties aggregating $5.3 million, $20.4 million and $7.3 million in 2005, 2004 and 2003, respectively, and charged these impairments to exploration costs in the accompanying statements of operations. The impairments of unproved properties recorded were based on drilling results and management’s plans for future drilling activities.
15. Sales of Assets
Gain on sale of property and equipment for 2005 was $18.9 million. In August 2005, the Company sold its interests in two leases in the Breton Sound area in the Gulf of Mexico (offshore Louisiana) for $21.3 million, subject to post-closing adjustments and realized a gain of $16.8 million on this sale. Gain on sale of property and equipment for 2004 was $4.1 million, including the sale of the Jo-Mill Unit in Borden County, Texas. Loss on sale of property and equipment for 2004 was $14.3 million including the sale of the Romere Pass Unit in Plaquemines Parish, Louisiana. Under EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations”, the Company has determined that these sales do not qualify for discontinued operations reporting. The Company applied the guidance of EITF 03-13 beginning in the fourth quarter of 2004.
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16. Quarterly Financial Data (Unaudited)
The following table summarizes results for each of the four quarters in the years ended December 31, 2005 and 2004.
| | First | | Second | | Third | | Fourth | | | |
| | Quarter | | Quarter | | Quarter | | Quarter | | Year | |
| | (In thousands, except per share) | |
Year ended December 31, 2005: | | | | | | | | | | | |
Total revenues | | $ | 65,689 | | $ | 66,318 | | $ | 85,143 | | $ | 66,449 | | $ | 283,599 | |
Operating income | | $ | 23,522 | | $ | 26,283 | | $ | 29,284 | | $ | 1,252 | | $ | 80,341 | |
Net income (loss) (a) | | $ | (8,992 | ) | $ | 9,950 | | $ | (2,040 | ) | $ | 1,339 | | $ | 257 | |
| | | | | | | | | | | |
Net income (loss) per common share (b): | | | | | | | | | | | |
Basic | | $ | (.83 | ) | $ | .92 | | $ | (.19 | ) | $ | .12 | | $ | .02 | |
Diluted | | $ | (.83 | ) | $ | .90 | | $ | (.19 | ) | $ | .12 | | $ | .02 | |
| | | | | | | | | | | | | | | | |
Weighted average common shares outstanding: | | | | | | | | | | | |
Basic | | 10,792 | | 10,800 | | 10,810 | | 10,814 | | 10,804 | |
Diluted | | 10,792 | | 11,089 | | 10,810 | | 11,254 | | 11,241 | |
| | | | | | | | | | | |
Year ended December 31, 2004: | | | | | | | | | | | |
Total revenues | | $ | 38,864 | | $ | 43,552 | | $ | 54,679 | | $ | 69,235 | | $ | 206,330 | |
Operating income | | $ | 11,000 | | $ | 6,005 | | $ | 13,233 | | $ | (19,799 | ) | $ | 10,439 | |
Net income (loss) (a) | | $ | 4,813 | | $ | 2,869 | | $ | (9,188 | ) | $ | (12,522 | ) | $ | (14,028 | ) |
| | | | | | | | | | | | | | | | |
Net income (loss) per common share (b): | | | | | | | | | | | |
Basic | | $ | .51 | | $ | .29 | | $ | (.85 | ) | $ | (1.16 | ) | $ | (1.37 | ) |
Diluted | | $ | .50 | | $ | .28 | | $ | (.85 | ) | $ | (1.16 | ) | $ | (1.37 | ) |
| | | | | | | | | | | | | | | | |
Weighted average common shares outstanding: | | | | | | | | | | | |
Basic | | 9,371 | | 9,923 | | 10,769 | | 10,780 | | 10,213 | |
Diluted | | 9,720 | | 10,230 | | 10,769 | | 10,780 | | 10,213 | |
(a) The Company recorded a $18.3 million charge for impairment of proved properties in the fourth quarter of 2005. The Company recorded a $10.2 million loss on sales of property and equipment and a $38.7 million loss for abandonments and impairments in the fourth quarter of 2004.
(b) The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year due to each period’s computation based on the weighted average number of common shares outstanding during each period.
17. Costs of Oil and Gas Properties
The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2005, 2004 and 2003.
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Property acquisitions: | | | | | | | |
Proved | | $ | 5,567 | | $ | 237,042 | | $ | — | |
Unproved | | 50,238 | | 33,826 | | 7,982 | |
Developmental costs | | 42,292 | | 27,469 | | 12,465 | |
Exploratory costs | | 86,304 | | 73,655 | | 49,277 | |
Total | | $ | 184,401 | | $ | 371,992 | | $ | 69,724 | |
| | | | | | | | | | | | | |
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The following table sets forth the capitalized costs for oil and gas properties as of December 31, 2005 and 2004.
| | 2005 | | 2004 | |
| | (In thousands) | |
Proved properties | | $ | 957,962 | | $ | 873,939 | |
Unproved properties | | 79,900 | | 35,156 | |
Total capitalized costs | | 1,037,862 | | 909,095 | |
Accumulated depreciation, depletion and amortization | | (570,386 | ) | (518,787 | ) |
Net capitalized costs | | $ | 467,476 | | $ | 390,308 | |
18. 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 Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under economic and operating conditions existing at the registrant’s year end with no provision for price and cost escalations except by contractual arrangements. Future cash inflows were computed by applying year-end prices to the year-end quantities of proved reserves. Future development, abandonment and production costs were computed by estimating the expenditures to be incurred in developing, producing, and abandoning proved oil and gas reserves at the end of the year, based on year-end costs. Future income taxes were computed by applying statutory tax rates to the estimated net pre-tax cash flows after consideration of tax basis and tax credits and carryforwards. All of the Company’s reserves are located in the United States. For information about the Company’s results of operations from oil and gas producing activities, see the accompanying consolidated statements of operations.
The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of the Company’s 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 proved oil and gas reserves together with the changes therein (oil in MBbls, gas in MMcf, oil converted to MMcfe at six MMcf per MBbl) for the years ended December 31, 2005, 2004 and 2003.
| | 2005 | | 2004 | | 2003 | |
| | Oil | | Gas | | MMcfe | | Oil | | Gas | | MMcfe | | Oil | | Gas | | MMcfe | |
Proved reserves: | | | | | | | | | | | | | | | | | | | |
Beginning of period | | 26,793 | | 138,278 | | 299,036 | | 10,335 | | 62,916 | | 124,926 | | 11,884 | | 86,912 | | 158,216 | |
Revisions | | 2,193 | | (5,333 | ) | 7,825 | | 1,603 | | 6,962 | | 16,580 | | (84 | ) | (7,323 | ) | (7,827 | ) |
Extensions and discoveries | | 868 | | 12,476 | | 17,684 | | 3,966 | | 23,034 | | 46,828 | | 274 | | 8,024 | | 9,668 | |
Sales of minerals-in-place | | (101 | ) | (2,922 | ) | (3,528 | ) | (3,359 | ) | (7,967 | ) | (28,121 | ) | — | | — | | — | |
Purchases of minerals-in-place | | 586 | | 667 | | 4,183 | | 16,591 | | 71,271 | | 170,819 | | — | | — | | — | |
Production | | (2,504 | ) | (16,408 | ) | (31,432 | ) | (2,343 | ) | (17,938 | ) | (31,996 | ) | (1,739 | ) | (24,697 | ) | (35,131 | ) |
End of period | | 27,835 | | 126,758 | | 293,768 | | 26,793 | | 138,278 | | 299,036 | | 10,335 | | 62,916 | | 124,926 | |
| | | | | | | | | | | | | | | | | | | |
Proved developed reserves: | | | | | | | | | | | | | | | | | | | |
Beginning of period | | 19,799 | | 95,224 | | 214,018 | | 9,349 | | 62,514 | | 118,806 | | 9,349 | | 76,224 | | 132,318 | |
End of period | | 21,503 | | 91,366 | | 220,384 | | 19,799 | | 95,224 | | 214,018 | | 9,349 | | 62,514 | | 118,606 | |
Net revisions of 7.8 Bcfe in 2005 consisted of approximately 17.5 Bcfe of upward revisions attributable to the effects of higher product prices on the estimated quantities of proved reserves, net of downward revisions of approximately 9.7 Bcfe attributable to well performance primarily from properties in West Texas.
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The standardized measure of discounted future net cash flows relating to proved reserves as of December 31, 2005, 2004 and 2003 was as follows:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Future cash inflows | | $ | 2,910,325 | | $ | 1,867,242 | | $ | 661,862 | |
Future costs: | | | | | | | |
Production | | (811,529 | ) | (569,999 | ) | (179,500 | ) |
Development | | (161,921 | ) | (119,807 | ) | (17,446 | ) |
Income taxes | | (612,771 | ) | (336,030 | ) | (118,869 | ) |
Future net cash flows | | 1,324,104 | | 841,406 | | 346,047 | |
10% discount factor | | (570,392 | ) | (341,208 | ) | (93,067 | ) |
Standardized measure of discounted net cash flows | | $ | 753,712 | | $ | 500,198 | | $ | 252,980 | |
Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2005, 2004 and 2003 were as follows:
| | 2005 | | 2004 | | 2003 | |
| | (In thousands) | |
Standardized measure, beginning of period | | $ | 500,198 | | $ | 252,980 | | $ | 293,698 | |
Net changes in sales prices, net of production costs | | 458,744 | | 43,178 | | 28,745 | |
Revisions of quantity estimates | | 35,741 | | 37,629 | | (21,212 | ) |
Accretion of discount | | 58,095 | | 51,870 | | 38,252 | |
Changes in future development costs, including | | | | | | | |
development costs incurred that reduced future | | | | | | | |
development costs | | (21,368 | ) | (2,489 | ) | 10,106 | |
Changes in timing and other | | (20,024 | ) | (16,297 | ) | (5,938 | ) |
Net change in income taxes | | (154,401 | ) | (119,605 | ) | 10,282 | |
Future abandonment cost, net of salvage | | (4,657 | ) | (3,395 | ) | (3,579 | ) |
Extensions and discoveries | | 100,302 | | 149,680 | | 37,419 | |
Sales, net of production costs | | (195,195 | ) | (151,963 | ) | (134,793 | ) |
Sales of minerals-in-place | | (13,781 | ) | (56,142 | ) | — | |
Purchases of minerals-in-place | | 10,058 | | 314,752 | | — | |
Standardized measure, end of period. | | $ | 753,712 | | $ | 500,198 | | $ | 252,980 | |
The estimated present value of future cash flows relating to 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, 2005, 2004 and 2003 were as follows:
| | Average Price | |
| | Oil (a) | | Gas | |
As of December 31: | | | | | |
2005 | | $ | 57.85 | | $ | 10.65 | |
2004 | | $ | 41.48 | | $ | 5.59 | |
2003 | | $ | 30.45 | | $ | 5.61 | |
(a) Includes natural gas liquids
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CLAYTON WILLIAMS ENERGY INC
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, 2005: | | | | | | | | | |
Allowance for doubtful accounts - Joint interest and other | | $ | 1,013 | | $ | 89 | | $ | (15 | ) | $ | 1,087 | |
| | $ | 1,013 | | $ | 89 | | $ | (15 | ) | $ | 1,087 | |
Year Ended December 31, 2004: | | | | | | | | | |
Allowance for doubtful accounts - Joint interest and other | | $ | 1,338 | | $ | 50 | | $ | (375 | ) | $ | 1,013 | |
| | $ | 1,338 | | $ | 50 | | $ | (375 | ) | $ | 1,013 | |
Year Ended December 31, 2003: | | | | | | | | | |
Allowance for doubtful accounts - Joint interest and other | | $ | 400 | | $ | 1,002 | | $ | (64 | ) | $ | 1,338 | |
Allowance for doubtful accounts - Oil and gas sales | | 286 | | — | | (286 | ) | — | |
| | $ | 686 | | $ | 1,002 | | $ | (350 | ) | $ | 1,338 | |
(a) Additions relate to provisions for doubtful accounts
(b) Deductions relate to the write-off of accounts receivable deemed uncollectible
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