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, 2006, our estimated proved reserves were 271.5 Bcfe, of which 75% were proved developed. We have a balanced portfolio of oil and natural gas reserves, with approximately 44% of our proved reserves at December 31, 2006 consisting of natural gas and approximately 56% consisting of oil and natural gas liquids. During 2006, we added proved reserves of 29.4 Bcfe through extensions and discoveries, had downward revisions of 28.7 Bcfe and acquired 6.4 Bcfe through purchases of minerals-in-place. We also achieved average net production of 80.6 Mmcfe per day in 2006, which implies a reserve life of approximately 9.2 years. CWEI held interests in 6,626 gross (891.9 net) producing oil and gas wells and owned leasehold interests in approximately 1.3 million gross (865,000 net) undeveloped acres at December 31, 2006.
Clayton W. Williams beneficially owns, either individually or through his affiliates, approximately 47% 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 2007, we plan to spend approximately $170.1 million on exploration and development activities, of which 83% relate to exploratory prospects. More than 60% of these planned expenditures in 2007 have been allocated to exploration and development activities in Louisiana.
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 83% of our planned expenditures for 2007 relate to exploratory prospects, as compared to approximately 84% of actual expenditures in 2006 and 73% of actual expenditures in 2005. During 2006, we spent $210.2 million on exploratory prospects, including $58.6 million on seismic and leasing activities and $151.6 million on drilling activities.
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, 2006, we had proved developed nonproducing reserves and proved undeveloped reserves of 99.8 Bcfe. We currently estimate that we will be required to spend approximately $160.3 million in development costs to develop these reserves. Since the timing of developing these reserves is discretionary, we have decided to limit expenditures on our developmental program in 2007 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 may allocate a more significant portion of our capital expenditures to development activities in years after 2007.
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 2007.
In 2006, an affiliated partnership, West Coast Energy Properties, L.P. (“WCEP”), acquired certain producing oil and gas assets in California and Texas for aggregate cash consideration of $58 million. Approximately 75% of the purchase price related to properties in three fields in southern California, and the remaining 25% related primarily to properties located in Mitchell County, Texas. One of our subsidiaries is the general partner of WCEP, and an affiliate of GE Energy Financial Services is the limited partner. We contributed $6.2 million to WCEP for an initial general partner interest of 5%. Our general partner interest can increase to 37.63%, and ultimately to 49%, if the limited partner achieves certain target rates of return.
From time to time, we sell certain of our proved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them. We consider many factors in deciding to sell properties, including the need for liquidity, the risks associated with continuing to own the properties, our expectations for future development on the property, the fairness of the price offered, and other factors related to the condition and location of the property. We did not sell any proved properties in 2006, but we may elect to sell selected properties in 2007.
Drilling Rigs
In April 2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs, consisting of five 1,000 horsepower rigs, five 1,300 horsepower rigs and two 2,000 horsepower rigs. Our business purpose for Larclay JV was to provide us with a reliable source of drilling rigs to be used in our exploration and development drilling programs. At the time, the supply of suitable drilling rigs was tight, causing the availability of rigs to be uncertain and the contract terms under drilling contracts to be less favorable. To lessen our reliance on other contractors for drilling rigs, and to mitigate our exposure to high contract rates and terms, we decided to join with an established drilling contractor for the construction and ownership of the Larclay JV rigs.
The rigs are being constructed on behalf of Larclay JV by Lariat, as operations manager. All five of the 1,300 horsepower rigs and one of the 1,000 horsepower rigs were fully constructed at December 31, 2006. Subsequently, construction on three of the remaining four 1,000 horsepower rigs has been completed. The remaining three rigs are expected to be fully constructed June 2007. Total construction cost of all rigs, excluding capitalized interest, is expected to be approximately $79 million.
Our principal obligation as a partner in the Larclay JV is to provide the necessary credit support to finance the construction of the rigs. We arranged for a lender to provide a $75 million secured term loan to Larclay JV to finance most of the cost of constructing and initially equipping the rigs. The terms of the loan originally required us to issue a $19 million letter of credit to the lender as additional collateral during the construction period. In February 2007, the lender released the letter of credit in exchange for our limited guaranty in the amount of $19.5 million. After completion of the construction period, outstanding advances under the term loan must not exceed 75% of the appraised value of the rigs. If proceeds available to Larclay JV under the term loan are not sufficient to fully finance the cost of acquiring the rigs, we will be required to loan funds to Larclay JV at the same interest rate as the term loan.
Also in April 2006, we entered into a three-year drilling contract with Larclay JV assuring the availability of each rig for use in the ordinary course of our exploration and development drilling programs throughout the term of the drilling contract. The provisions of the drilling contract provide that we contract for each rig on a well-by-well basis at then current market rates. If we do not need a rig at any time during the term of the contract, Larclay JV may contract with other operators for the use of that rig, subject to certain restrictions. If a rig is idle, we are required to pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the rig.
Our maximum potential obligation to pay idle rig rates over the term of this drilling contract, excluding any crew labor expenses, totals $109 million; however, our obligation under the contract is mitigated as rigs are contracted to drill for other operators. Currently, two rigs are drilling for us, five rigs are drilling for an affiliate of Lariat, and two rigs are drilling for other operators. We currently plan to use at least one of the 1,300 horsepower rigs in our North Louisiana program and both of the 2,000 horsepower rigs in our East Texas Bossier program during 2007.
In addition to the Larclay JV rigs, we have placed orders for two additional 2,000 horsepower rigs for possible use in our North Louisiana Bossier and our East Texas Bossier programs. At December 31, 2006, we had invested $8.7 million in these rigs and were committed under firm purchase contracts for an additional $15.8 million. We estimate that the combined construction cost of both rigs will be approximately $27 million.
Exploration and Development Activities
In 2006, we spent $250.2 million on exploration and drilling activities, approximately 60% of which was financed by cash flow from operations and the remainder by borrowings on our revolving credit facility. We presently plan to spend approximately $170.1 million on exploration and drilling activities during 2007, most of which will be financed by cash flow from operations, and the balance will be financed by borrowings on the revolving credit facility and supplemented by proceeds from sales of assets, if needed. 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.
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.
Prior to 2006, we had drilled 53 gross (42.0 net) exploratory wells in South Louisiana, of which 24 gross (18.0 net) were completed as producers. The following table sets forth certain information about our exploratory well activities in South Louisiana subsequent to December 31, 2005.
We spent $118.5 million in South Louisiana during 2006 on exploration and development activities, of which $110 million was spent on drilling and completion activities and $8.5 million was spent on seismic and leasing activities. Our drilling activities in South Louisiana resulted in the addition of approximately 26.6 Bcfe of proved reserves in 2006, most of which came from our Floyd prospect in Plaquemines Parish. To date, we have completed seven productive wells on this prospect. Under the terms of a farmout agreement, we bear 100% of the cost of wells on this prospect to casing point and earn up to a 75% working interest in the drilled acreage.
In contrast to the successful drilling results on the Floyd prospect, we also recorded $33.7 million of exploration expense due primarily to four high-cost exploratory dry holes, the Borah #1 (Cypress Isle), the Apache Louisiana Minerals (Abigail), the Kyle Peterman Mgt #30-1 (Pigeon) and the Rose Chouest #1 (South Empire). First quarter 2007 exploration costs will include an additional $2.5 million of abandonment costs incurred subsequent to December 31, 2006 related to the Rose Chouest #1.
We are attempting to complete the Cobena #1 (Boa II), a 15,250-foot exploratory well in Acadia Parish, in a zone to which we have attributed approximately 2.3 Bcf of net gas reserves as of December 31, 2006. To date, we have incurred approximately $9 million in drilling and completion costs on this well, net to our interest.
We currently plan to spend approximately $39.3 million in South Louisiana in 2007 to generate and lease new exploratory prospects and to drill wells on existing exploratory and developmental prospects. Our plans include drilling two wells and upgrading production facilities on our Floyd prospect and drilling three development wells offsetting existing production.
North Louisiana
In 2005, we began 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.
The following table sets forth certain information about our exploratory well activities in North Louisiana subsequent to December 31, 2005. This table does not include 12 gross (1.3 net) non-operated wells in which our working interests range from 1% to 44%.
We spent $48.9 million in North Louisiana during 2006 on exploration activities, of which $20.4 million was spent on seismic and leasing activities and $28.5 million was spent on drilling and completion activities. Most of the costs incurred in this area at December 31, 2006 relate to prospects and wells that were in progress and had not been evaluated at that date. In 2007, we currently plan to spend approximately $54 million in North Louisiana in 2007 to generate and lease new exploratory prospects and to drill wells on existing exploratory prospects.
We drilled two exploratory wells on our Frazier Creek prospect in Claiborne Parish targeting the Cotton Valley/Hosston formations. The Atkins Estate #1 was completed as a marginal producer, and the Weyerhaeuser #1 was not productive, resulting in a pre-tax charge of $3.2 million in 2006 related to the abandonment of the well. We do not currently plan to drill additional wells in this area in 2007.
On our Terryville prospect in Lincoln Parish, we have drilled and completed three wells in the Cotton Valley interval. The Roberson #1 was a dry hole and resulted in a pre-tax charge of $5.7 million in 2006 related to the abandonment of the well. The Donald Woodard #1 was completed in the first quarter of 2007 and is currently producing at a rate of approximately 2.3 Mmcfe per day, net to our interest. The J.L. Hood #1 has been completed as a gas well and is waiting on pipeline connections. We currently plan to drill four additional wells on this prospect in 2007.
In addition, we have drilled the P. Benoit #1, the first exploratory well on our Sarepta prospect in Webster Parish. We attempted to complete the Benoit #1 in the Gray sand, but that zone was nonproductive. We are currently waiting on availability of a completion rig to attempt completion in the Cotton Valley interval. We currently plan to drill five additional wells on this prospect in 2007.
We are currently drilling the David Barton #1, a 17,000-foot exploratory well on our Winnsboro prospect in Richland Parish and currently plan to drill at least one additional well in this area in 2007.
East Texas Bossier
We have acquired a significant acreage position 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 54,000
net acres and hold up to 50,000 additional acres in the area of our Austin Chalk (Trend) production primarily in Burleson, Robertson, Brazos and Milam Counties, Texas. We spent $20.8 million on prospective Bossier acreage in East Texas in 2006.
In 2007, we currently plan to spend approximately $4.1 million to acquire additional acreage and $44.3 million to drill three exploratory wells. In April, we plan to spud the Big Bill Simpson #1, a 19,000-foot exploratory well in Leon County (70% working interest) targeting the Bossier formation. Both of the other Bossier wells are expected to be drilled to similar depths. These wells are very expensive to drill and involve a high degree of risk.
Permian Basin
We spent $40.6 million in the Permian Basin during 2006 on exploration and development activities, of which $39 million was spent on drilling and completion activities and $1.6 million was spent on seismic and leasing activities. We drilled 9 gross (7.6 net) operated wells in the Permian Basin and conducted remedial operations on existing wells in 2006. Of the operated wells drilled, two were dry holes and the rest are currently producing. In addition, we participated in the drilling of 24 gross non-operated wells (3.8 net), with working interests ranging from 2% to 50%. One of these was a dry hole, and the majority of the remaining wells were producers on the Davidson Ranch and Amacker-Tippet prospects. The Permian Basin continues to be a significant source of production and cash flow for us. We currently plan to spend $17.3 million on drilling activities in the Permian Basin in 2007.
Montana/Utah
We spent $7.1 million in Montana and Utah during 2006 on drilling, seismic, and leasing activities. In Montana, we drilled and abandoned the Ruegsegger 24H #1, a 7,600-foot exploratory vertical well with a 3,600-foot lateral in the Bakken shale formation, after it was determined to be nonproductive. We recorded a pre-tax charge of approximately $2.3 million in 2006 related to the abandonment of this well. We do not plan to spend any capital drilling in Montana in 2007.
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. We are currently participating in the drilling of the Vonda Christensen 35A31, a 13,500-foot non-operated exploratory well in Sanpete County. We currently plan to spend approximately $6.3 million for additional leasing activities and to participate in the drilling of another exploratory well to test this acreage.
Colorado
In 2006, we drilled two wells in Routt County, Colorado targeting the Niobraro formation at a depth of approximately 8,500 feet. The Focus Ranch Federal 12#1 and the Focus Ranch Federal 3-1 have been temporarily abandoned because we do not believe the discovered reserves justify the cost of production facilities and pipelines due to the remote location and rugged terrain in this area. As a result, we recorded a pre-tax charge of $9.7 million related to the abandonment of these wells in 2006.
Other Exploration and Development Activities
During 2006, we spent $3.8 million in the Austin Chalk (Trend) area of Texas primarily for production enhancement activities, and currently plan to spend approximately $3.1 million for similar activities in this area in 2007. In addition, we plan to spend approximately $1.8 million in 2007 to participate in an exploration project in the Sacramento and San Joaquin Basins of California.
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 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.
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 our operations, restrict or prohibit the types, quantities and concentration of substances that we can release into the environment, restrict or prohibit activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources, require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells, and impose substantial liabilities for pollution resulting from our operations. Such laws and regulations may substantially increase the cost of our operations and may prevent or delay the commencement or continuation of a given project and thus generally could have 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 would have a material adverse impact on our financial condition and operations.
We believe that we are in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2007. We do not believe that we will be required to incur any material capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on our operations, as well as the oil and gas industry in general. For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements could have a material adverse impact on our operations.
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.
The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency (“EPA”) or state agencies as solid wastes. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be
significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.
Our operations are subject to the federal Clean Air Act, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by us. We do not believe that our operations will be materially adversely affected by any such requirements.
The Federal Water Pollution Control Act (“Clean Water Act”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the United States Oil Pollution Act of 1990 (“OPA”), and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA 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 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.
Recent studies have suggested that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases”, pursuant to the United Nations Framework Convention of Climate Change, also known as the “Kyoto Protocol”. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and oil, and refined petroleum products, are “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change legislation, with multiple bills having been introduced in the Senate that propose to restrict greenhouse gas emissions. Several states have already adopted legislation, regulations and/or regulatory initiatives to reduce emissions of greenhouse gases. For instance, California adopted the “California Global Warming Solutions Act of 2006”, which requires the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. Additionally, on November 29, 2006, the U.S. Supreme Court heard arguments on and has since begun reviewing a decision made by the U.S. Circuit Court of Appeals for the District of Columbia in Massachusetts, et al v. EPA, a case in which the appellate court held that EPA had discretion under the Clean Air Act to refuse to regulate carbon dioxide emissions from mobile sources. Passage of climate change legislation by Congress or a Supreme Court reversal of the appellate decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our operations or financial condition.
Claims are sometimes made or threatened against companies engaged in oil and gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, in other jurisdictions in which we operate, courts have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.
Title to Properties
As is customary in the oil and gas industry, we perform a minimal title investigation before acquiring undeveloped properties. A title opinion is obtained prior to the commencement of drilling operations on such properties. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. These title investigations and title opinions, while consistent with industry standards, may not reveal existing or potential title defects, encumbrances or adverse claims as we are subject from time to time to claims or disputes regarding title to properties. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our oil and gas properties are currently mortgaged to secure borrowings under our revolving credit facility and may be mortgaged under any future credit facilities entered into by us.
Operational Hazards and Insurance
Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.
We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.
Executive Officers
The following is a list, as of March 15, 2007 of the name, age and position with the Company of each person who is an executive officer of the Company:
CLAYTON W. WILLIAMS, age 75, 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 55, 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 52, 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 54, is Vice President - New Ventures of the Company, having served in such capacity since 1993.
ROBERT C. LYON, age 70, is Vice President - Gas Gathering and Marketing of the Company, having served in such capacity since 1993.
MICHAEL L. POLLARD, age 57, 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 50, is Vice President and General Counsel of the Company, having served in such capacity since 1993.
GREGORY S. WELBORN, age 33, is Vice President - Land of the Company, having served in such capacity since 2006.
Employees
At December 31, 2006, we had 180 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
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 2007, approximately 83% 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 $65.2 million in 2006 for abandonment and impairment, most of which was related to unsuccessful exploratory drilling activities in North and South Louisiana, Colorado, Montana and the Permian Basin area of West 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, 2006 is approximately 9.2 years, based on 2006 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 engaged to a large extent in exploration activities, our ability to replace produced reserves is subject to a higher level of risk and is less predictable than it might be if we concentrated on developmental drilling activities.
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 2007. 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.
Our liquidity will suffer if our exploration activities are not successful. For 2007, approximately 83% of our planned capital expenditures relate to exploratory prospects, where we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically. Several of our exploratory prospects target deep formations, including the Bossier formation in North Louisiana and East Texas. Wells on these prospects are very expensive to drill and involve a very high degree of risk. If these exploratory wells are unsuccessful, our cash flow from operations and our liquidity will be adversely affected.
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, 2006 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 2007 by approximately $2.2 million and $8.5 million, respectively.
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.
Commitments under long-term drilling contracts may reduce our cash flow from operating activities. We have entered into long-term drilling contracts to ensure the availability of the drilling rigs we need to conduct our drilling program. If we contract for a rig and do not need the rig due to changes in our drilling program, we will be required to pay a daily rate specified in the contract while the rig is idle during the contract term. Long-term drilling commitments may also influence us to drill a well in 2007 that we may otherwise choose to defer until a later period in order to avoid paying for an idle rig. Our cash flow from operations may be less than expected and/or our capital expenditures may be more than expected if commitments on long-term drilling contracts result in the payment of idle rig costs and/or an increase in drilling costs related to wells not currently included in our drilling schedule.
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 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;
· 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 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 47% 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, 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 oil and gas exploration and production, and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.
Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate. Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.
We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs. Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation. Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas. Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants. In addition, claims are sometimes made or threatened against companies engaged in oil and gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired. Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.
Item 1B
Item 1B - Unresolved Staff Comments
Not applicable.
Item 2
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, 2006, we had interests in 6,626 gross (891.9 net) oil and gas wells and owned leasehold interests in approximately 1.3 million gross (865,000 net) undeveloped acres.
Reserves
The following table sets forth certain information as of December 31, 2006 with respect to our estimated proved oil and gas reserves pursuant to SEC guidelines, standardized measure of discounted future net cash flows and present value of proved reserves.
(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, 2006 were $180.8 million and $19.5 million, respectively.
The following table sets forth certain information as of December 31, 2006 regarding our proved oil and gas reserves in each of our principal producing areas.
(a) Includes natural gas liquids.
(b) Primarily West Texas and New Mexico.
Our estimated recoverable proved reserves have been determined 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, and does not include any economic impact that may result from our hedging activities.
Substantially all of our estimates of proved reserves are derived from reports prepared by Williamson Petroleum Consultants, Inc., independent petroleum engineers, and Ryder Scott Company, L.P., petroleum consultants.
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, 2006 were $57.18 per Bbl of oil and natural gas liquids and $5.24 per Mcf of gas, as compared to $57.85 per Bbl of oil and $10.65 per Mcf of gas as of December 31, 2005. 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 $12.7 million and $33.9 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, 2006, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.
Exploration and Development Activities
We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.
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.
We own a 50% interest in Larclay JV, a joint venture with Lariat Services, Inc. formed to construct, own and operate 12 drilling rigs, consisting of five 1,000 horsepower rigs, five 1,300 horsepower rigs and two 2,000 horsepower rigs. The rigs are being constructed on behalf of Larclay JV by Lariat, as operations manager. All five of the 1,300 horsepower rigs and one of the 1,000 horsepower rigs were fully constructed at December 31, 2006. Subsequently, construction on three of the remaining four 1,000 horsepower rigs has been completed. The remaining three rigs are expected to be fully constructed by June 2007. In addition to the Larclay JV rigs, we have placed orders for two additional 2,000 horsepower rigs for delivery later in 2007. We used four of the Larclay JV rigs during 2006 to drill certain wells in our exploration and development drilling program. In 2007, we expect to use at least one of the 1,300 horsepower rigs in our North Louisiana Cotton Valley/Hosston program and both of the 2,000 horsepower rigs in our East Texas Bossier program. In addition, we may use one or both of the additional 2,000 horsepower rigs in our Bossier drilling programs in North Louisiana and East Texas.
We also use other drilling contractors, as needed, to drill wells. At December 31, 2006, we had two barge rigs and one 2,000 horsepower land rig under long-term contracts for drilling wells in South Louisiana.
Productive Well Summary The following table sets forth certain information regarding our ownership, as of December 31, 2006, of productive wells in the areas indicated.
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.
(a) No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in gain/loss on derivatives.
(b) 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.
Acreage
The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2006 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.
(a) Net undeveloped acres are attributable to the following areas: Montana - 149,630; Mississippi - 112,057; East Texas - 61,417; Utah - 49,076; Alabama - 38,808; Colorado - 36,423; and other - 19,196.
Offices
We lease from a related partnership approximately 61,000 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
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
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, 2006.
PART II
Item 5
Item 5 - Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities
Price Range of Common Stock Our Common Stock is quoted on the Nasdaq Stock Market’s Global Market under the symbol “CWEI”. As of March 14, 2007, 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 Global Market:
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, 2007 was $27.34 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
For information concerning shares available for issuance under equity compensation plans, see Item 11, which is to be incorporated by reference to our proxy statement.
Item 6
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, 2006 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.
Item 7
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. Although oil prices have retreated from their peaks in mid-2006, and gas prices have been volatile, we believe that supply and demand fundamentals in the energy marketplace continue to provide 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 experiencing a shrinking profit margin related to rising drilling and production costs. While profit margins still remain favorable, operating metrics per Mcfe, such as finding costs, production costs and DD&A expense, 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 100% of our 2006 production through extensions and discoveries in 2006, most of which were derived from drilling activities on our Floyd prospect in South Louisiana. However, depreciation, depletion and amortization (“DD&A”) per Mcfe of oil and gas production, an operating metric that measures a company’s cumulative cost to find or purchase a unit of production, increased 49% from 2005 to 2006. Our planned exploration activities in 2007 offer us the opportunity to improve our DD&A rate through the drilling of several potentially high-impact wells, particularly in our East Texas Bossier area. However, these wells are very expensive to drill and involve a high degree of risk.
Key Factors to Consider
The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2006 and the outlook for 2007.
· We spent $250.2 million on exploration and development activities during 2006, of which approximately 84% was on exploratory prospects. We currently plan to spend approximately $170.1 million for the calendar year 2007, of which approximately 83% is estimated to be spent on exploratory prospects. The 2006 expenditures exceeded our cash flow from operating activities by more than $100 million. Our 2007 expenditures are also expected to exceed our cash flow from operating activities in 2007, although not by as large a margin. 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.
· During 2006, we increased borrowings under our revolving credit facility by $129.3 million from $10.7 million at December 31, 2005 to $140 million at December 31, 2006 to partially finance our exploration and development activities. As of February 28, 2007, our outstanding balance on the revolving credit facility had increased to $160 million due to additional borrowings to finance our exploration program and to pay interest on our Senior Notes.
· Despite our high level of capital spending in 2006, our oil and gas production for 2006 was 6% lower on an Mcfe basis than in 2005. A significant portion of our 2006 expenditures have not resulted in current production because they relate to (a) unproved exploratory prospects, (b) drilling or completion activities that are in progress, or (c) non-productive leasing and drilling activities.
· At December 31, 2006, our capitalized unproved oil and gas properties totaled $129.4 million, of which approximately $102.4 million was attributable to unproved acreage. Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value. Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.
· Exploration costs related to abandonments and impairments were $65.2 million in 2006, of which approximately $51.3 million related to unsuccessful well costs and $13.9 million related to impairment of unproved acreage. Over 50% of these costs were related to exploratory prospects in South Louisiana, and approximately 25% related to prospects in Colorado and Montana.
· We recorded a $37.3 million net gain on derivatives in 2006 as compared to a $70.1 million loss in 2005. For 2006, cash settlements to counterparties accounted for a $20.2 million loss and changes in mark-to-market valuations accounted for a $57.5 million gain. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.
· We recorded a $21.8 million impairment of proved properties in 2006 due to the combined effects of lower commodity prices and lower reserve estimates. The impairment applied to several areas in the Permian Basin and one prospect in South Louisiana.
· Our proved oil and gas reserves at December 31, 2006 were 271.5 Bcfe compared to 293.8 Bcfe at December 31, 2005. We added 29.4 Bcfe through extensions and discoveries, and lost 28.7 Bcfe through net downward revisions.
Proved Oil and Gas Reserves
The following table summarizes changes in our proved reserves during 2006 on a Bcfe basis.
During 2006, we replaced 24% of the 29.4 Bcfe that we produced in 2006, computed by dividing the sum of all net reserve additions (purchases of minerals-in-place, extensions and discoveries, and revisions), by 2006 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 net reserve additions during 2006.
Purchases of minerals-in-place. We purchased 6.4 Bcfe of reserves in 2006 relating to properties in California and West Texas. Although we are continually looking for acquisitions, we cannot predict the likelihood of adding any reserves in 2007 through purchases of minerals-in-place.
Extensions and discoveries. Our extensions and discoveries during 2006 consist of proved reserves attributable directly to the drilling of discovery wells primarily in South Louisiana and the Permian Basin. Of the 29.4 Bcfe of additions, substantially all are proved developed reserves. Due to the nature of exploratory drilling, we cannot predict the extent to which we will add any reserves in 2007 through extensions and discoveries.
Revisions. Our proved reserves were 28.7 Bcfe lower due to revisions of previous estimates. Downward revisions of 22 Bcfe were attributable to the effects of lower product prices on the estimated quantities of proved reserves, and downward revisions of approximately 6.7 Bcfe were attributable to lower well performance, primarily in the Permian Basin. Gas prices at December 31, 2006 were approximately half of the prices at
December 31, 2005, contributing to the downward price revision. In addition, higher projected operating costs were responsible for a portion of the decrease.
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.
(a) No derivatives were designated as cash flow hedges in the table above. All gains or losses on settled derivatives were included in gain/loss on derivatives.
(b) Includes a $13.7 million impairment of unproved acreage in the Black Warrior Basin in 2004.
(c) Includes an $8 million charge in South Texas for the Deer-Hamilton #1 in 2005.
(d) Excludes wells being drilled or completed at the end of each period.
Operating Results
2006 Compared to 2005
The following discussion compares our results for the year ended December 31, 2006 to the year ended December 31, 2005. Unless otherwise indicated, references to 2006 and 2005 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales in 2006 decreased $6.6 million, or 3%, from 2005, of which production variances accounted for a $16 million decrease and price variances accounted for a $9.4 million increase. Production in 2006 (on an Mcfe basis) was 6% lower than 2005. Oil production decreased 4% and gas production decreased 7% in 2006 as compared to 2005 due primarily to natural production declines, offset in part by new production from our exploration and development activities. In 2006, our realized oil price was 18% higher than 2005, while our realized gas price was 11% lower. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.
Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 10% in 2006 as compared to 2005 due primarily to higher oilfield service costs. After giving effect to a 6% decline in oil and gas production on an Mcfe basis, production costs per Mcfe increased 17% from $1.83 per Mcfe in 2005 to $2.15 per Mcfe in 2006. It is likely that these factors will continue to contribute to higher production costs in future periods.
DD&A expense increased 39% from $47.5 million in 2005 to $66.2 million in 2006. DD&A expense attributable to oil and gas properties increased $17.8 million, of which rate variances accounted for a $20.6 million increase and production variances accounted for a $2.8 million decrease. On an Mcfe basis, DD&A expense increased 49% from $1.42 per Mcfe in 2005 to $2.12 per Mcfe in 2006. DD&A per Mcfe of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. Unless our exploration activities result in an improvement in our finding costs in 2007, we may continue to realize higher DD&A rates in future periods.
We recorded a provision for impairment of proved properties under SFAS 144 of $21.8 million during 2006 due to the combination of production performance and lower commodity prices. This provision was attributable to two areas in the Permian Basin and one area in South Louisiana. We recorded a provision for impairment of proved properties of $18.3 million in 2005.
Gain on property sales
Gain on sales of property and equipment in 2006 was $1.8 million as compared to $18.9 million in 2005. The gain in 2006 was derived from the sale of other property and equipment. Most of the gain in 2005 related to the sale of our interests in two leases in the Breton Sound area of the Gulf of Mexico.
Exploration costs
Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2006, we charged to expense $76.5 million of exploration costs, as compared to $50.7 million in 2005. Most of the 2006 costs were incurred in Louisiana, the Permian Basin, Montana and Colorado.
At December 31, 2006, our capitalized unproved oil and gas properties totaled $129.4 million, of which approximately $102.4 million was attributable to unproved acreage. Unproved properties are subject to a valuation impairment to the extent the carrying cost of a prospect exceeds its estimated fair value. Therefore, our results of operations in future periods may be adversely affected by unproved property impairments.
We plan to spend approximately $170.1 million on exploration and development activities in fiscal 2007, of which approximately 83% is expected to be allocated to exploration activities. Since exploratory drilling involves a high degree of risk, it is likely that a significant portion of the costs we incur in fiscal 2007 will be charged to exploration costs. However, we cannot predict our success rates and, accordingly, cannot predict our exploration costs related to abandonment and impairment costs.
General and administrative expenses
General and administrative (“G&A”) expenses increased 8% from $15.4 million in 2005 to $16.7 million in 2006. Excluding non-cash employee compensation, G&A expenses increased from $12.8 million in 2005 to $14 million in 2006 due primarily to higher personnel costs and professional fees attributable to the increase in overall drilling and exploration activities. In 2006, we recorded a $2.5 million non-cash compensation charge related to our after payout incentive plan and $128,000 for stock-based employee compensation. In 2005, we recorded a $1.9 million non-cash charge for stock-based employee compensation and a $680,000 non-cash charge related to our after payout incentive plan.
Interest expense
Interest expense increased 44% from $14.5 million in 2005 to $20.9 million in 2006 due to several factors. In July 2005, we issued $225 million of Senior Notes which bear interest at a fixed rate of 7.75%, and used the proceeds to repay our then-outstanding bank indebtedness. As a result, the 2005 period included a non-cash charge of $1.8 million of debt issue costs related to the early repayment of our senior term credit facility and the reduction in our borrowing base under the revolving credit facility. In 2006, we used our revolving loan facility to partially finance our exploration and development activities. The average daily principal balance outstanding under our revolving credit facility for 2006 was $89 million compared to $101 million for 2005; however, the Senior Notes were outstanding for the entire 2006 period. Capitalized interest for 2006 was $5.8 million compared to $2.2 million in 2005.
Gain/loss on derivatives
We recorded a gain on derivatives of $37.3 million in 2006 compared to a loss of $70.1 million for 2005. We did not designate any derivative contracts in 2006 or 2005 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. Cash settlements were $20.2 million in 2006, as compared to $29.7 million in 2005. We recorded a gain on derivatives of $57.5 million in 2006 compared to a loss of $40.4 million in 2005 resulting from mark-to-market valuations.
Income tax expense (benefit)
Our effective income tax rate in 2006 of 9.7% differed from the statutory federal rate of 35% due primarily to a reduction in our state tax provision of $4.4 million related to the adoption of Texas House Bill 3 in May 2006. Our income tax benefit in 2005 of $451,000 differed from the statutory federal benefit due primarily to the utilization of tax depletion in excess of basis.
Compared to 2004
The following discussion compares our results for the year ended December 31, 2005 to the comparative period in 2004.
Oil and gas operating results
Oil and gas sales in 2005 increased $59.5 million, or 31%, from 2004, of which price variances accounted for a $61.3 million increase and production variances accounted for a $1.8 million decrease. Production in 2005 (on an Mcfe basis) was 2% lower than 2004. Oil production increased 8% in 2005 from 2004 due primarily to additional well production from our Southwest Royalties, Inc. (“SWR”) acquisition in May 2004, offset in part by lost production as a result of Hurricane Katrina. Gas production decreased 9% due primarily to lost production from the hurricane and declines in the Cotton Valley Reef Complex area due to formation performance. In 2005, our realized oil price was 31% higher than 2004, while our realized gas price was 34% higher. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.
Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, increased 39% in 2005 as compared to 2004 due primarily to higher oilfield service costs and increased workover activities. Also contributing to the added expense was the addition of higher cost oil properties acquired in connection with the SWR acquisition, as well as increased production tax costs related to higher product prices. After giving effect to a 2% decline in oil and gas production on an Mcfe basis, production costs per Mcfe increased 42% from $1.29 per Mcfe in 2004 to $1.83 per Mcfe in 2005.
DD&A expense increased from $44 million in 2004 to $47.5 million in 2005. DD&A expense attributable to oil and gas properties increased $3.5 million, of which rate variances accounted for a $4.2 million increase and production variances accounted for a $700,000 decrease. On an Mcfe basis, DD&A expense increased 11% from
$1.28 per Mcfe in 2004 to $1.42 per Mcfe in 2005. Depletion rates for each depletable group are a function of net capitalized costs and estimated reserve quantities.
We recorded a provision for impairment of proved properties under SFAS 144 of $18.3 million during 2005 due to the combination of production performance and lower commodity prices. This provision was attributable to the Wolfcamp exploration program in the Permian Basin.
Gain/loss on property sales
Gain on sales of property and equipment in 2005 was $18.9 million as compared to $4.1 million in 2004. The gain in 2005 was from the sale of our interests in two leases in the Breton Sound area in the Gulf of Mexico. The gain in 2004 related to the sale of the Jo-Mill Unit in Borden County, Texas. In 2004, we also recorded a loss on sale of property and equipment of $14.3 million, consisting primarily of the sale of the Romere Pass Unit in Plaquemines Parish, Louisiana.
Exploration costs
Since we follow the successful efforts method of accounting, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs, and unproved acreage impairments are expensed. In 2005, we charged to expense $50.7 million of exploration costs, as compared to $75.1 million in 2004. Most of the 2005 and 2004 costs were incurred in South Louisiana and Mississippi.
General and administrative expenses
G&A expenses increased 32% from $11.7 million in 2004 to $15.4 million in 2005. Excluding non-cash employee compensation, G&A expenses increased 8% from $11.9 million in 2004 to $12.8 million in 2005 due to higher personnel costs and professional fees attributable to the increase in overall drilling and exploration activities. In 2005, we recorded a $680,000 non-cash compensation charge related to our after payout incentive plan and $1.9 million for stock-based employee compensation. In 2004, we recorded a $245,000 non-cash credit for stock-based employee compensation.
Interest expense
Interest expense increased from $7.9 million in 2004 to $14.5 million in 2005 due to several factors. In July 2005, we issued $225 million of Senior Notes which bear interest at a fixed rate of 7.75%, and used the proceeds to repay our then-outstanding bank indebtedness. As a result, the 2005 period included a non-cash charge of $1.8 million of debt issue costs related to the early repayment of our senior term credit facility and the reduction in our borrowing base under the revolving credit facility. The average daily principal balance outstanding under our bank credit facility for 2005 was $101 million compared to $148.8 million for 2004; however, the Senior Notes were outstanding for almost half of the 2005 period. Higher effective interest rates on our bank credit facilities also contributed to the increase in interest expense. Capitalized interest for 2005 was $2.2 million compared to $877,000 in 2004.
Gain/loss on derivatives
We recorded a loss on derivatives of $70.1 million in 2005 compared to a loss of $25.3 million for 2004. 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. We recorded a loss on derivatives of $40.4 million in 2005 compared to a loss of $7.1 million in 2004 resulting from mark-to-market valuations.
Income tax expense (benefit)
Our income tax benefit in 2005 of $451,000 differed from the statutory federal benefit due primarily to the utilization of tax depletion in excess of basis. Our income benefit in 2004 was substantially equal to the statutory federal rate of 35% since the benefit derived from the utilization of tax depletion in excess of basis was offset by a provision for state taxes.
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. 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 2005, we issued $225 million of aggregate principal amount of Senior Notes and used the net proceeds to repay all amounts outstanding on the revolving credit facility at that time. However, we relied heavily on advances under the revolving credit facility to finance a significant portion of our exploration and development activities in 2006. At December 31, 2006, we had $140 million outstanding on the revolving credit facility.
Our 2006 expenditures exceeded cash flow from operating activities by more than $100 million. Our 2007 expenditures are also expected to exceed our cash flow from operating activities in 2007, although not by as large a margin. 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 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.
Capital expenditures
The following table summarizes, by area, our planned expenditures for exploration and development activities during 2007, as compared to our actual expenditures in 2006.
Our actual expenditures during fiscal 2007 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 2007.
Approximately 83% of the planned expenditures relate to exploratory prospects. Exploratory prospects involve a higher degree of risk than developmental prospects. To offset the 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 do not include costs we may incur to complete any future 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. 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.
We spent $250.2 million on exploration and development activities during 2006, of which approximately 84% was on exploratory prospects. We currently plan to spend approximately $170.1 million for the calendar year 2007, of which approximately 83% is estimated to be spent on exploratory prospects. The 2006 expenditures exceeded our cash flow from operating activities by more than $100 million. Our 2007 expenditures are also expected to exceed our cash flow from operating activities in 2007, although not by as large a margin. We intend to finance this shortfall by borrowings on the revolving credit facility. Our internal 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 2007. 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.
We have placed orders for two 2,000 horsepower rigs for possible use in our Bossier drilling program in North Louisiana and East Texas. At December 31, 2006, we had invested $8.7 million in these rigs and were committed under firm purchase contracts for an additional $15.8 million. We estimate that the combined construction cost of both rigs will be approximately $27 million, and currently plan to seek financing for most of the remaining cost of these rigs.
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, 2006 decreased $17.5 million, or 11%, as compared to the corresponding period in 2005 due to the combined effects of several factors. Oil and gas sales, net of production costs, general and administrative costs and interest expense, were $20.2 million lower in 2006 as compared to the same period in 2005. 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. Settlements on derivative contracts, excluding those contracts that contain a financing element as in the case of the contracts assumed in our acquisition of Southwest Royalties, Inc. in May 2004, were substantially the same in both periods. Interest expense increased in 2006 due primarily to higher levels of indebtedness resulting from the issuance of the Senior Notes.
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 2006, we had an outstanding balance under the revolving credit facility of $10.7 million, and the borrowing base was $150 million, providing us with available funds of $138.5 million after accounting for outstanding letters of credit. In June 2006, the borrowing base was increased to $200 million. During 2006, we generated cash flow from operating activities of $146 million and received cash proceeds of $8.4 million from sales of assets and issuances of common stock. We also spent $254.8 million on capital expenditures (excluding Larclay JV) and paid $29.4 million to settle derivatives with financing elements. To finance the excess of expenditures over cash flow, we borrowed $129.3 million on the revolving credit facility.
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 decreased from $35.8 million at December 31, 2005 to $23.1 million at December 31, 2006 due primarily to a combination of factors, including increases in fair value of derivatives and increases in receivables, offset in part by increases in payables and current maturities of long-term debt. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $36.9 million at December 31, 2006, as compared to a positive $136.2 million at December 31, 2005. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2006 and December 31, 2005.
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, 2006, 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.
The banks redetermine the borrowing base under the revolving credit facility at least twice a year, in May and November. The November 2006 borrowing base review resulted in maintaining the borrowing base at $200 million. 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. We relied heavily on advances under the revolving credit facility to finance a significant portion of our exploration and development activities in 2006. At December 31, 2006, we had $140 million outstanding on the revolving credit facility, as compared to $160 million on February 28, 2007. The increased borrowings since December 31, 2006 were required to finance our exploration program and to pay interest on our Senior Notes.
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. We were in compliance with these covenants at December 31, 2006.
Alternative capital resources
Although our base of oil and gas reserves, as collateral for both of our credit facilities, has historically been our primary capital resource, we have in the past, and we believe we could in the future, use alternative capital resources, such as asset sales, vendor financing arrangements, and/or public or private issuances of common stock. We could also issue senior or subordinated debt or preferred stock in a public or a private placement if we choose to raise capital through either of these markets. While we believe we would be able to obtain funds through one or more of these alternatives, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.
Contractual Obligations and Contingent Commitments
The following table summarizes our contractual obligations as of December 31, 2006 by payment due date.
(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 $10.4 million on the secured bank credit facility (based on the balances and interest rates at December 31, 2006).
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, 2006, would mature as follows: 2007 - $6 million, and 2008 - $19.5 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. In 2006, we replaced more than 100% of our 2006 oil and gas production through our exploratory drilling program. Production from these discoveries should contribute favorably to production in 2007, and may help offset the natural production declines from our base of oil and gas reserves. Even
with this new production, we will need to discover new sources of production from our exploration and development activities in 2007. While we cannot predict the results of our exploration and development activities, we believe that oil and gas production levels in 2007 will be comparable to those in 2006.
Profit Margins
We analyze, on an Mcfe produced basis, those revenues and expenses that have a significant impact on our oil and gas profit margin. Our weighted average oil and gas sales per Mcfe have been on an upward trend, from $6.04 per Mcfe in 2004, $8.04 per Mcfe in 2005 and $8.36 per Mcfe in 2006. Higher product prices have provided us with a significant incentive to assume the risks associated with many of the exploratory prospects that we have initiated in the past three years. However, our expenses per Mcfe are also on an upward trend and is resulting in a narrowing profit margin. Our oil and gas DD&A per Mcfe has increased from $1.28 per Mcfe in 2004, to $1.42 per Mcfe in 2005, to $2.12 in 2006. An upward trend in DD&A per Mcfe indicates that our cost to find and/or acquire reserves is increasing at a faster rate than the reserves we are adding. Although we replaced approximately 100% of our 2006 production in 2006, our cost to find those reserves was higher than our historical combined rate. Also affecting our profit margin is the cost of producing our reserves. Our production costs per Mcfe have risen from $1.29 per Mcfe in 2004, to $1.83 per Mcfe in 2005, to $2.15 per Mcfe in 2006. Our rise in production costs per Mcfe is a result of a combination of factors. Most of the increase in 2004 was attributable to the acquisition of mature Permian Basin properties that had a higher production cost profile than our then-existing properties. Since the beginning of 2005, we have experienced significant increases in the cost of field services to maintain and produce our production.
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.
* 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 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.
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.
(a) Includes natural gas liquids
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.
Effects of Estimates and Assumptions on Financial Statements
Generally accepted accounting principles do not require, or even permit, the restatement of previously issued financial statements due to changes in estimates unless such estimates were unreasonable or did not comply with applicable SEC accounting rules. We are required to use our best judgment in making estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate. At each accounting period, we make a new estimate using new data, and continue the cycle. You should be aware that estimates prepared at various times may be substantially different due to new or additional information. While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available information or assumptions. In this section, we will discuss the effects of different estimates on our financial statements.
Provision for DD&A
We compute our provision for DD&A on a unit-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for each of our producing properties (or appropriate groups of properties based on geographical and geological similarities):
· 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 geological and geophysical and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the in-progress status and the proper accounting treatment is recorded.
Asset Retirement Obligations
Our asset retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to oil and gas properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statement of operations. During 2006, we revised our estimated asset retirement obligations by $6.5 million, or approximately 33% of the asset retirement obligations at December 31, 2005, based on a review of current plugging and abandonment costs. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion expense. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Recent Accounting Pronouncements
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”), which becomes effective beginning on January 1, 2007. SAB 108 provides guidance on the consideration of the effects of prior period misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires an entity to evaluate the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on current year financial statements. If a misstatement is material to the current year financial statements, the prior year financial statements should also be corrected, even though such revision was, and continues to be, immaterial to the prior year financial statements. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. Such correction should be made in the current period filings. The adoption of SAB 108 had no effect on our consolidated financial statements.
In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. SFAS 157 is effective for fiscal years beginning after December 15, 2007. We plan to adopt SFAS 157 beginning in the first quarter of fiscal 2008. We are currently evaluating the impact, if any, the adoption of SFAS 157 will have on our consolidated financial position, results of operations or cash flows.
Emerging Issues Task Force Issue 04-5 (“EITF 04-5”), which became effective January 1, 2006, requires companies to fully consolidate any limited partnerships that the company controls as general partner. EITF 04-5 presumes that a sole general partner in a limited partnership controls the limited partnership; however, 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. For this purpose, 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 have entered into contracts with 17 oil and gas limited partnerships of which we are the sole general partner. Generally, these contracts require us to abstain from voting any of our limited partnership units in matters related to our removal as general partner. As a result, the limited partners in all of the oil and gas partnerships in which we serve as general partner can remove us as general partner with a simple majority vote. Accordingly, we have continued consolidating our proportionate share of all of these limited partnerships. The adoption of EITF 04-5 had no effect on our consolidated financial statements.
In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”) to clarify the manner in which enterprises account for uncertainties in their provisions for income taxes. Generally, the standard presented by FIN 48 is a “more likely than not” standard and is intended to enhance the relevancy and comparability of financial reporting by companies. FIN 48 is effective for fiscal years beginning after December 31, 2006. The adoption of FIN 48 is not expected to have a significant impact on our consolidated financial statements.
Item 7A
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, 2006 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 from year end 2006 would reduce our gross revenues for the year ending December 31, 2007 by $10.7 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.
The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2006. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Collars:
Swaps:
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.
In January 2007, the Company terminated certain fixed-price oil swaps covering 450,000 barrels at a price of $55.35 per barrel, from March 2007 through August 2007, resulting in an aggregate realized gain of approximately $7.8 million, which will be collected from the counterparty monthly during 2007.
In July 2006, the Company also terminated certain fixed-price oil swaps covering 300,000 barrels at a price of $80.45 per barrel, from January 2007 through December 2007, resulting in an aggregate realized loss of approximately $2.4 million, which will be paid to the counterparty monthly during 2007.
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, 2006 by approximately $8.3 million.
Interest Rates
We are exposed to interest rate risk on our long-term debt with a variable interest rate. At December 31, 2006, our variable rate debt had a carrying value of $206.3 million, which approximated its fair value. At December 31, 2006, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $207.6 million, based on current market quotes. We estimate that the hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $9.4 million.
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, 2006.
Interest Rate Swaps:
Item 8
Item 8 - Financial Statements and Supplementary Data
For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements included elsewhere in this Form 10-K.
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A
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 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, 2006 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, 2006. 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, 2006, 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 shown below.
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, 2006, 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, 2006, 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, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2006 and 2005, 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, 2006, and our report dated March 15, 2007, expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Dallas, Texas
March 15, 2007
Item 9B
Item 9B - Other Information
None.
PART III
Item 10
Item 10 - Directors, Executive Officers and Corporate Governance
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2007.
Item 11
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, 2007.
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2007.
Item 13
Item 13 - Certain Relationships and Related Transactions, and Director Independence
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2007.
Item 14
Item 14 - Principal Accounting Fees and Services
Information required by this Item is incorporated by reference to our definitive proxy statement, which will be filed with the SEC no later than April 30, 2007.
PART IV
Item 15
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.
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
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 March 8, 2007
**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, filed as Exhibit 10.3 to the Company’s Form 10-K for the period ended December 31, 2005
**10.4
Third Amendment to Amended and Restated Credit Agreement dated June 30, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 14, 2006
**10.5
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
**10.6
1993 Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 033-68318
**10.7
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
**10.8
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
**10.9
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
Exhibit
Number
Description of Exhibit
**10.10
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
**10.11
Fifth Amendment to 1993 Stock Compensation Plan, filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 2005
**10.12
Outside Directors Stock Option Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68316
**10.13
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
**10.14
Second Amendment to Outside Directors Stock Option Plan, filed as Exhibit 10.13 to the Company’s Form 10-K for the period ended December 31, 2005
**10.15
Bonus Incentive Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-68320
**10.16
First Amendment to Bonus Incentive Plan, filed as Exhibit 10.9 to the Company’s Form 10-K for the period ended December 31, 1997
**10.17
Scudder Trust Company Prototype Defined Contribution Plan adopted by Clayton Williams Energy, Inc. effective as of August 1, 2004, filed as Exhibit 10.12 to the Company’s Form 10-K for the period ended December 31, 2004
**10.18
Executive Incentive Stock Compensation Plan, filed as Exhibit 10.1 to the Company’s Form S-8 Registration Statement, Commission File No. 33-92834
**10.19
First Amendment to Executive Incentive Stock Compensation Plan, filed as Exhibit 10.16 to the Company’s Form 10-K for the period ended December 31, 1996
**10.20
Consolidation Agreement dated May 13, 1993 among Clayton Williams Energy, Inc., Warrior Gas Co. and the Williams Entities, filed as Exhibit 10.1 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350
**10.21
Amendment to Consolidation Agreement dated August 7, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams Companies, filed as Exhibit 10.1 to the Company’s Form 10-Q for the period ended September 30, 2000
**10.22
Agreement dated April 23, 1993 between the Company and Robert C. Lyon, filed as Exhibit 10.42 to the Company’s Form S-1 Registration Statement, Commission File No. 033-43350
**10.23
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
**10.24
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
Exhibit
Number
Description of Exhibit
**10.25
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
**10.26
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
**10.27
Agreement of Limited Partnership of CWEI West Pyle/McGonagill, L.P. effective as of January 2, 2005, filed as Exhibit 10.33 to the Company’s Form 10-K for the period ended December 31, 2004
**10.28
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
**10.29
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
**10.30
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
**10.31
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
**10.32
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
**10.33
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
**10.34
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
**10.35
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
**10.36
Limited Liability Company Agreement, dated April 21, 2006, by and between Clayton Williams Energy, Inc. and Lariat Services, Inc., with respect to the formation of Larclay GP, LLC, a Texas limited liability company, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006
**10.37
Agreement of Limited Partnership, dated April 21, 2006, by and among Larclay GP, LLC, Clayton Williams Energy, Inc. and Lariat Services, Inc., with respect to the formation of Larclay, L.P., a Texas limited partnership, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006
Exhibit
Number
Description of Exhibit
**10.38
Drilling Contract for Multiple Rigs, dated April 21, 2006, by and between Clayton Williams Energy, Inc. and Larclay, L.P., filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006
**10.39
Subordination Agreement, dated April 21, 2006, by and among Clayton Williams Energy, Inc., Lariat Services, Inc. and Merrill Lynch Capital, as agent, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006
**10.40
Consent and Agreement, dated April 21, 2006, by and among Clayton Williams Energy, Inc., Lariat Services, Inc. and Merrill Lynch Capital, as agent, filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006
**10.41
Letter of Credit, dated April 21, 2006, issued in favor of Merrill Lynch Capital, as agent, filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006
**10.42
Form of Unconditional Limited Guaranty, to be issued by Clayton Williams Energy, Inc. in favor of Merrill Lynch Capital, as agent, filed as Exhibit 10.7 to the Company’s Current Report on Form 8-K filed with the Commission on April 26, 2006
**10.43
Agreement of Limited Partnership of Floyd Prospect II, L.P. dated May 15, 2006., filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 17, 2006
**10.44
Participation Agreement relating to South Louisiana IV dated August 2, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006
**10.45
Participation Agreement relating to North Louisiana - Hosston/Cotton Valley dated August 2, 2006, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006
**10.46
Participation Agreement relating to North Louisiana - Bossier dated August 2, 2006, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on August 7, 2006
**10.47
Participation Agreement relating to Floyd Prospect III dated November 15, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006
**10.48
Participation Agreement relating to North Louisiana - Bossier II dated November 15, 2006, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006
**10.49
Participation Agreement relating to North Louisiana - Hosston/Cotton Valley II dated November 15, 2006, filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006
**10.50
Participation Agreement relating to South Louisiana V dated November 15, 2006, filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the Commission on November 17, 2006
Exhibit
Number
Description of Exhibit
**10.51
Southwest Royalties Reward Plan dated January 15, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with Commission on January 18, 2007
**10.52
Participation Agreement relating to West Coast Energy Properties, L.P. dated December 11, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 14, 2006
*21
Subsidiaries of the Registrant
*23.1
Consent of KPMG LLP
*23.2
Consent of Williamson Petroleum Consultants, Inc.
*23.3
Consent of Ryder Scott Company, L.P.
*24.1
Power of Attorney
*31.1
Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
*31.2
Certification by the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934
*32.1
Certifications by the Chief Executive Officer and Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350
*
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.
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.
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.
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.
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.
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, 2007
Clayton W. Williams
President and Chief Executive
Officer and Director
/s/ L. PAUL LATHAM
Executive Vice President,
March 15, 2007
L. Paul Latham
Chief Operating Officer and
Director
/s/ MEL G. RIGGS
Senior Vice President -
March 15, 2007
Mel G. Riggs
Finance, Secretary, Treasurer,
Chief Financial Officer and Director
/s/ MICHAEL L. POLLARD
Vice President - Accounting and
March 15, 2007
Michael L. Pollard
Principal Accounting Officer
/s/ STANLEY S. BEARD *
Director
March 15, 2007
Stanley S. Beard
/s/ DAVIS L. FORD *
Director
March 15, 2007
Davis L. Ford
/s/ ROBERT L. PARKER *
Director
March 15, 2007
Robert L. Parker
/s/ JORDAN R. SMITH *
Director
March 15, 2007
Jordan R. Smith
CLAYTON WILLIAMS ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Financial Statement Schedule
Schedule II-Valuation and Qualifying Accounts
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, 2006 and 2005, 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, 2006. 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 2 of the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) “Share Based Payment”.
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, 2006, 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, 2007, 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, 2007
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share)
The accompanying notes are an integral part of these consolidated financial statements.
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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 47% 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”).
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; and
· Estimates regarding abandonment obligations.
Principles of Consolidation
The consolidated financial statements include the accounts of Clayton Williams Energy, Inc., its subsidiaries and the accounts of the Larclay JV (see Note 11). 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 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.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
Contract Drilling
The Company consolidates the accounts of Larclay JV (see Note 11), a joint venture engaged in contract drilling of oil and gas wells. Larclay recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable.
Property and equipment, including major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of three to seven years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.
Valuation of Property and Equipment
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, 2006, the Company’s unproved oil and gas properties had an aggregate net book value of $129.4 million, including $27 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.
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
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 estimated 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, 2006, 2005 and 2004, the Company capitalized interest totaling approximately $5.8 million, $2.2 million and $877,000, respectively. In addition, the Company capitalized interest relating to the construction of drilling rigs in the Larclay JV of $1.8 million in 2006.
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 net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted net income per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted net income per share calculations for 2006 and 2005 include an increase in potential shares attributable to dilutive stock options. Stock options were not considered in the diluted net loss per share calculations for 2004 as the effect would be anti-dilutive.
Stock-Based Compensation
Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004) “Share-Based Payment,” (“SFAS 123R”) which requires the measurement and recognition of compensation expense for all share-based payment awards, including employee stock options, based on estimated fair values. The value of the portion of the award that is ultimately expected to vest is recognized as expense on a straight-line basis over the requisite service periods. SFAS 123R supersedes the Company’s previous accounting under Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB 25”) for periods beginning in 2006. The Company adopted SFAS 123R using the modified prospective transition method,
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
which requires the application of the accounting standard prospectively as of January 1, 2006 and does not require restatement of previously issued financial statements.
SFAS 123R requires the Company to estimate the fair value of stock option awards on the date of grant using an option-pricing model. The Company uses the Black-Scholes option-pricing model (“Black-Scholes Model”) as its method of valuation for share-based awards granted on or after January 1, 2006, which is the same model used for the Company’s pro forma information required under SFAS 123. The Company’s determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables. These variables include, but are not limited to, the Company’s expected stock price volatility over the term of the awards, as well as actual and projected exercise activity.
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, 2006 or 2005. 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 2006, 2005 and 2004.
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, 2006 and 2005 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 September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”), which becomes effective beginning on January 1, 2007. SAB 108 provides guidance on the consideration of the effects of prior period misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires an entity to evaluate the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on current year financial statements. If a misstatement is material to the current year financial statements, the prior year financial statements should also be corrected, even though such revision was, and continues to be, immaterial to the prior year financial statements. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. Such correction should be made in the current period filings. The adoption of SAB 108 had no effect on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS No. 157 “Fair Value Measurements” (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. SFAS 157 is effective for fiscal years beginning after December 15, 2007. The Company plans to adopt SFAS 157 beginning in the first quarter of fiscal 2008. The Company is currently evaluating the impact, if any, the adoption of SFAS 157 will have on its consolidated financial position, results of operations or cash flows.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Emerging Issues Task Force Issue 04-5 (“EITF 04-5”), which became effective January 1, 2006, requires companies to fully consolidate any limited partnerships that the company controls as general partner. EITF 04-5 presumes that a sole general partner in a limited partnership controls the limited partnership; however, 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. For this purpose, 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 has entered into contracts with 17 oil and gas limited partnerships of which the Company is the sole general partner. Generally, these contracts require the Company to abstain from voting any of its limited partnership units in matters related to the removal of the Company as general partner. As a result, the limited partners in all of the oil and gas partnerships in which the Company serves as general partner can remove the Company as general partner with a simple majority vote. Accordingly, the Company has continued consolidating its proportionate share of all of these limited partnerships. The adoption of EITF 04-5 had no effect on the Company’s consolidated financial statements.
In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”) to clarify the manner in which enterprises account for uncertainties in their provisions for income taxes. Generally, the standard presented by FIN 48 is a “more likely than not” standard and is intended to enhance the relevancy and comparability of financial reporting by companies. FIN 48 is effective for fiscal years beginning after December 31, 2006. The adoption of FIN 48 is not expected to have a significant impact on the Company’s consolidated financial statements.
3. Long-Term Debt
Long-term debt consists of the following:
(a) Includes current portion of term loan of Larclay JV of $17,397 at December 31, 2006.
Aggregate maturities of long-term debt at December 31, 2006 are as follows: 2007 - $17.4 million; 2008 - $18.2 million; 2009 - $156.6 million; 2010 - $11.6 million; 2011 - $2.5 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. The Company was in compliance with these covenants at December 31, 2006.
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 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, 2006, the borrowing base established by the banks was $200 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $19.8 million, the Company had $40.2 million available under the credit facility at December 31, 2006. Subsequent to December 31, 2006, a letter of credit for $19 million was cancelled.
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. Interest and fees are payable at least quarterly. The effective annual interest rate on borrowings under the combined credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2006 was 7.4%.
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, 2006.
Secured Term Loan of Larclay JV
In connection with the Company’s investment in Larclay JV (see Note 11), Larclay JV obtained a $75 million secured term loan facility from a lender to finance the construction and equipping of 12 new drilling rigs. The Larclay JV term loan is secured by substantially all of the assets of Larclay JV. Initially, the Company pledged additional collateral in the form of a $19 million letter of credit. In February 2007, the letter of credit was cancelled and replaced by a $19.5 million guaranty from the Company. Although the Company is not a maker on the Larclay JV term loan, it has provided additional credit support for the Larclay JV term loan and is required to fully consolidate the accounts of Larclay JV under FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities - or Interpretation of ARB No. 51 (as amended)” (“FIN 46R”). At December 31, 2006, the effective interest rate on the Larclay JV term loan was 8.6%.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Other Non-Current Liabilities
Other non-current liabilities at December 31, 2006 and 2005 consist of the following:
Abandonment Obligations
Changes in abandonment obligations for 2006 and 2005 are as follows:
5. Income Taxes
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. Significant components of net deferred tax assets (liabilities) at December 31, 2006 and 2005 are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2006, 2005 and 2004, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:
In May 2006, the State of Texas adopted House Bill 3, which modified the state’s franchise tax structure, replacing the previous tax based on capital or earned surplus with a margin tax (the “Texas Margin Tax”) effective with franchise tax reports filed on or after January 1, 2008. The Texas Margin Tax is computed by applying the applicable tax rate (1% for the Company’s business sector) to the profit margin, which is generally determined by total revenue less either cost of goods sold or compensation, as applicable. Although House Bill 3 states that the Texas Margin Tax is not an income tax, the Company believes that Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”) applies to the Texas Margin Tax. Accordingly, the Company has computed its consolidated deferred tax liability based on its current interpretation of the Texas Margin Tax, resulting in a reduction of deferred tax expense during 2006 of $4.4 million.
The Company derives a tax deduction when employees and directors exercise options granted under the Company’s stock option plans. To the extent these tax deductions are used to reduce currently payable taxes in any period, the Company records a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements.
At December 31, 2006, the Company’s cumulative tax loss carryforwards were approximately $2.5 million and consisted of unrecognized excess tax benefits derived from stock options exercised in 2006.
6. 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 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2006. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Collars:
Swaps:
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.
In January 2007, the Company terminated certain fixed-price oil swaps covering 450,000 barrels at a price of $55.35 per barrel, from March 2007 through August 2007, resulting in an aggregate realized gain of approximately $7.8 million, which will be collected from the counterparty monthly during 2007.
In July 2006, the Company also terminated certain fixed-price oil swaps covering 300,000 barrels at a price of $80.45 per barrel, from January 2007 through December 2007, resulting in an aggregate realized loss of approximately $2.4 million, which will be paid to the counterparty monthly during 2007.
Interest Rate Derivatives The Company is a party to interest rate swaps that were acquired in connection with the acquisition of Southwest Royalties, Inc. in May 2004. Under these derivatives, the Company pays a fixed rate for the notional principal balances and receives a floating market rate based on LIBOR. The interest rate swaps are settled quarterly. The following summarizes information concerning the Company’s net positions in open interest rate swaps applicable to periods subsequent to December 31, 2006.
Interest Rate Swaps:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Accounting For Derivatives
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. The Company did not designate any of its currently open commodity or interest rate derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, are recorded as other income (expense) in the Company’s statements of operations. For the year ended December 31, 2006, the Company reported a $37.3 million net gain on derivatives, consisting of a $57.5 million gain related to changes in mark-to-market valuations and a $20.2 million cash charge for settled contracts. For the year ended December 31, 2005, the net loss on derivatives was $70.1 million, consisting of a $40.4 million non-cash charge related to changes in mark-to-market valuations and a $29.7 million cash charge for settled contracts.
7. 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 estimated fair value of the Company’s Senior Notes at December 31, 2006 and 2005 was approximately $207.6 million and $216.8 million, respectively.
The fair values of derivatives as of December 31, 2006 and 2005 are set forth below.
8. 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.
9. Compensation Plans
Stock-Based Compensation
The Company has reserved 1,798,200 shares of common stock for issuance under the 1993 Stock Compensation Plan (“1993 Plan”). The 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, 2006 expire 10 years from the date of grant and become exercisable based on varying vesting schedules. The Company issues new shares, not repurchased shares, to option holders that exercise stock options under the plans.
The Company has reserved 86,300 shares of common stock for issuance under the Outside Directors Stock Option Plan (“Directors Plan”). Since the inception of the Directors Plan, the Company has issued options covering 44,000 shares of common stock at option prices ranging from $3.25 to $41.74 per share. All outstanding options expire 10 years from the grant date and are fully exercisable upon issuance.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth certain information regarding the Company’s stock option plans as of and for the year ended December 31, 2006:
(a) Based on closing price at December 31, 2006 of $36.31 per share.
(b) Cash received for options exercised totaled $3.9 million and tax benefit realized totaled $1.8 million.
The following table summarizes information with respect to options outstanding at December 31, 2006, all of which are currently exercisable.
Prior to the adoption of SFAS 123R, the Company accounted for options which were repriced in 1999 as variable stock options under APB 25 whereby compensation expense was 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 ceased accounting for these options as variable stock options upon the adoption date. The Company adopted SFAS 123R using the modified prospective application method. Since all of the Company’s outstanding options were fully vested at January 1, 2006, no future compensation expense will be recognized for these options under SFAS 123R unless the options are modified, and the Company did not recognize any cumulative effect of a change in accounting principles upon adoption of SFAS 123R.
The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2006, 2005 and 2004.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 under SFAS 123. The fair value of stock options issued for each year was estimated at the date of grant using the Black-Scholes option pricing model. The following weighted average assumptions were used in this model.
The SFAS 123 pro forma information for the year ended December 31, 2005 and 2004 is as follows:
After-Payout Incentive Plan
The Compensation Committee of the Board of Directors has 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 interest in the production developed, directly or indirectly, by the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements (“APO Arrangements”) between the Company and the participants to which the Company contributes a portion of its economic interest in wells drilled or acquired within certain areas. Generally, the Company pays all costs and receives all revenues until payout of its costs, plus interest. At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the APO Arrangements.
Between 3% and 7.5% of the Company’s economic interests in specified wells drilled or acquired by the Company subsequent to October 2002 are subject to APO Arrangements (excluding properties acquired in a merger with Southwest Royalties, Inc. in May 2004). The Company records its allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Arrangements in its consolidated financial statements. To date, two of these APO Arrangements have achieved payout. Aggregate cash distributions of approximately $735,000 were paid to the participants during the year ended December 31, 2006. The Company recognized $2.5 million of non-cash compensation expense during the year ended December 31, 2006 for the estimated fair value of the APO Arrangements granted in 2006 and $680,000 in 2005.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. 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 Company. The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2006, 2005 and 2004.
(a) Rent amounts were paid to a Partnership within the Williams Entities. The Company owns 31.9% of the Partnership and affiliates of the Company own 23.3%.
(b) Consists of hunting and fishing rights pertaining to land owned by affiliates of Mr. Williams.
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.
11. Investments
West Coast Energy Properties, L.P.
In August 2006, an affiliated partnership, West Coast Energy Properties, L.P. (“WCEP”), acquired certain producing oil and gas assets in California and Texas for aggregate cash consideration of approximately $58 million. Approximately 75% of the purchase price relates to properties in three fields in southern California, and the remaining 25% relates primarily to properties located in Mitchell County, Texas.
WCEP is a Texas limited partnership formed to facilitate this acquisition, the general partner of which is a limited liability company owned by the Company and the limited partner of which is an affiliate of GE Energy Financial Services. Under the partnership agreement, the general partner contributed approximately $6.2 million to the partnership for an initial partnership interest of 5%, which interest can increase to 37.63%, and ultimately to 49%, upon the achievement of certain target rates of return.
The Company financed its equity contribution to the general partner through borrowings on its revolving credit facility.
Larclay JV
In April 2006, the Company formed a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. The Company and Lariat each own a 50% interest in Larclay JV. The rigs are being constructed on behalf of Larclay JV by Lariat, as operations manager. Six of the rigs were fully constructed at December 31, 2006. Subsequently, construction on three additional rigs has been completed. The remaining three rigs are expected to be fully constructed by June 2007. The total construction cost of all rigs, excluding capitalized interest, is expected to be approximately $79 million. A lender has provided a $75 million
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
secured term loan to Larclay JV to finance most of the cost of constructing and initially equipping the rigs. Pursuant to the term loan, the Company originally issued a $19 million letter of credit to the lender as additional collateral during the construction period. In February 2007, the lender released the letter of credit in exchange for a $19.5 million guaranty from the Company. After completion of the construction period, outstanding advances under the term loan must not exceed 75% of the appraised value of the rigs. If proceeds available to Larclay JV under the term loan are not sufficient to fully finance the cost of acquiring the rigs, the Company will be required to loan funds to Larclay JV at the same interest rate as the term loan. The Larclay JV term loan, as amended, bears interest at a floating rate based on a LIBOR average, plus 3.25%, and provides for monthly interest payments through March 2007 and monthly principal and interest payments thereafter sufficient to retire the principal balance by 35% in the first year, 25% in each of the next two years, and 15% in the fourth year. Two voluntary prepayments of $10 million each may be made in 2008 and 2009 without a prepayment penalty. The Larclay JV term loan prohibits Larclay JV from making any cash distributions to the Company or Lariat until the balance on the term loan is fully repaid, and repayments by Larclay JV of any loans by the Company or Lariat are subordinated to the loans outstanding under the term loan and are subject to other restrictions.
Also in April 2006, the Company entered into a three-year drilling contract with Larclay JV assuring the availability of each rig for use in the ordinary course of the Company’s exploration and development drilling program throughout the term of the drilling contract. The provisions of the drilling contract provide that the Company contract for each rig on a well-by-well basis at then current market rates. If a rig is not needed by the Company at any time during the term of the contract, Larclay JV may contract with other operators for the use of such rig, subject to certain restrictions. If a rig is idle, the Company will pay Larclay JV an idle rig rate ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the rig. The Company’s maximum potential obligation to pay idle rig rates over the term of this drilling contract, excluding any crew labor expenses, totals $109 million.
Although the Company and Lariat own equal interests in Larclay JV, the Company meets the definition of the primary beneficiary of Larclay JV’s expected cash flows under FIN 46R. As the primary beneficiary under FIN 46R, the Company is required to include the accounts of Larclay JV in the Company’s consolidated financial statements. As of December 31, 2006, Lariat’s equity ownership in the net assets of Larclay JV was $1.1 million, which is recorded as minority interest and included in other non-current liabilities in the accompanying consolidated financial statements. The Company’s intercompany accounts with Larclay JV have been eliminated in consolidation.
12. 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 $791,000, $779,000 and $678,000 for the years ended December 31, 2006, 2005 and 2004, respectively.
Future minimum payments under noncancelable leases at December 31, 2006, are as follows:
(a) Relates to vehicle leases.
Purchase Commitments
The Company is presently obligated under firm orders for two drilling rigs and related equipment in an aggregate amount of $24.5 million, for which cash deposits totaling $8.1 million have been paid to the equipment suppliers as of December 31, 2006. The total cost of the rigs, when completed and fully equipped, is estimated to be
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
approximately $27 million. The rigs are scheduled for delivery in mid-2007 and are expected to be utilized to drill the Company’s deep Bossier prospects in East Texas and North Louisiana.
In addition to the Larclay JV drilling contract discussed in Note 11, the Company has also entered into three drilling contracts with third party drilling contractors and is obligated to make payments under these contracts totaling $19.7 million in 2007.
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.
13. Impairment of Property and Equipment
The Company has recorded provisions for impairment of proved properties under SFAS 144 of $21.8 million in 2006 and $18.3 million in 2005. The 2006 and 2005 provisions related to production performance for properties in West Texas. No impairment was deemed necessary in 2004.
The Company has also recorded provisions for impairment of unproved properties aggregating $12.9 million, $5.3 million and $20.4 million in 2006, 2005 and 2004, 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.
14. Sales of Assets
Gain on sale of property and equipment for 2006 was $1.8 million due primarily to the sale of other property and equipment. 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Quarterly Financial Data (Unaudited)
The following table summarizes results for each of the four quarters in the years ended December 31, 2006 and 2005.
(a) The Company recorded a $12.9 million charge for impairment of proved properties in the third quarter of 2006 and a $8.9 million charge in the fourth quarter of 2006. The Company also recorded a $18.3 million charge for impairment of proved properties in the fourth quarter of 2005.
(b) The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.
16. Costs of Oil and Gas Properties
The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2006, 2005 and 2004.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the capitalized costs for oil and gas properties as of December 31, 2006 and 2005.
In April 2005, the Financial Accounting Standards Board issued Staff Position No. 19-1 (“FSP 19-1”). FSP 19-1 amends the present guidance in Statement of Financial Accounting Standards No. 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 method of accounting. 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, 2006 and December 31, 2005, the Company had capitalized $27 million and $10.3 million, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves. Of the $10.3 million costs at December 31, 2005, $1.2 million was expensed as a dry hole during the year ended December 31, 2006 and the remaining $9.1 million was subsequently deemed productive.
During the year ended December 31, 2006, the Company recorded a provision for impairment of proved properties of $21.8 million compared to $18.3 million in 2005 under Statement of Financial Accounting Standards No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS 44”) due to a combination of production performance and lower commodity prices. The provision for both periods was attributable to two areas in West Texas and one area in South Louisiana. No provision was recorded in 2004.
17. Segment Information
In accordance with Statement of Financial Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”), the Company has one reportable operating segment, which is oil and gas exploration and production. Beginning in 2006, the Company formed the Larclay JV, a contract drilling joint venture that the Company consolidates in its financial statements (see Note 11). The contract drilling segment does not meet the quantitative thresholds under SFAS 131 to be considered a reportable operating segment and, accordingly, is included in “Other”. Prior to 2006, the Company had no operating segments other than oil and gas exploration and production.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents selected financial information regarding the Company’s operating segments for 2006.
(a) Includes impairment of property and equipment.
(b) Includes the following expenses: production, exploration, natural gas services, accretion of abandonment obligations, general and administrative and loss on sales of property and equipment.
18. Guarantor Financial Information
In July 2005, Clayton Williams Energy, Inc. (“Issuer”) issued $225 million of Senior Notes (see Note 3). Other than West Coast Energy Properties GP, LLC (“WCEP LLC”), the general partner of WCEP (see Note 11), all of the Issuer’s wholly-owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the Senior Notes. Larclay JV, a 50%-owned drilling rig joint venture formed in April 2006, and WCEP, LLC have not guaranteed the Senior Notes and are referred to in this Note 18 as Non-Guarantor Entities.
The financial information on the following pages sets forth the Company’s condensed consolidating financial statements as of and for the periods indicated.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Balance Sheet
December 31, 2006
(Dollars in thousands)
Condensed Consolidating Balance Sheet
December 31, 2005
(Dollars in thousands)
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Operations
Year Ended December 31, 2006
(Dollars in thousands)
Condensed Consolidating Statement of Operations
Year Ended December 31, 2005
(Dollars in thousands)
Condensed Consolidating Statement of Operations
Year Ended December 31, 2004
(Dollars in thousands)
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2006
(Dollars in thousands)
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2005
(Dollars in thousands)
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2004
(Dollars in thousands)
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
19. Oil and Gas Reserve Information (Unaudited)
The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the 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 activities for 2006, see Note 17, and for 2005 and 2004, 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, 2006, 2005 and 2004.
Net downward revisions of 28.7 Bcfe in 2006 consisted of approximately 22 Bcfe of downward revisions attributable to the effects of lower natural gas prices on the estimated quantities of proved reserves and approximately 6.7 Bcfe attributable to lower well performance, primarily from properties in the Permian Basin.
The standardized measure of discounted future net cash flows relating to proved reserves as of December 31, 2006, 2005 and 2004 was as follows:
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2006, 2005 and 2004 were as follows:
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, 2006, 2005 and 2004 were as follows:
(a) Includes natural gas liquids
CLAYTON WILLIAMS ENERGY, INC.
Schedule II - Valuation and Qualifying Accounts
(a) Additions relate to provisions for doubtful accounts.
(b) Deductions relate to the write-off or recovery of the provisions for doubtful accounts.
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