Clayton Williams Energy Inc. CEO CLAYTON W WILLIAMS bought 7384 shares on 3-3-2008 at 38.98
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 â€śCompanyâ€ť, â€śCWEIâ€ť, â€śweâ€ť, â€śusâ€ť or â€śourâ€ť 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.
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.
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.
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. (â€śWCEPâ€ť), 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.
In April 2006, we formed a joint venture (â€śLarclay JVâ€ť) with Lariat Services, Inc. (â€śLariatâ€ť) 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.
Since 2000, we have been exploring for oil and gas reserves in South Louisiana and have developed this area into one of our key sources of production and cash flow. Most of the prospects we have generated in South Louisiana have been identified based on 3-D seismic data and technology and have generally consisted of multi-pay, Miocene-age sands.
We spent $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.
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.
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.
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.
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.
We sell substantially all of our oil production under short-term contracts based on prices quoted on the New York Mercantile Exchange (â€śNYMEXâ€ť) 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.
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 (â€śFERCâ€ť) 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 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 (â€śCERCLAâ€ť), also known as the â€śSuperfundâ€ť 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 â€śhazardous substanceâ€ť 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 (â€śRCRAâ€ť), 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 (â€śEPAâ€ť) 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 (â€śClean Water Actâ€ť), 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 (â€śOPAâ€ť), 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 Earthâ€™s atmosphere. In response to these studies, many nations have agreed to limit emissions of â€śgreenhouse gasesâ€ť, pursuant to the United Nations Framework Convention of Climate Change, also known as the â€śKyoto Protocolâ€ť. 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 â€śgreenhouse gasesâ€ť 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 â€śCalifornia Global Warming Solutions Act of 2006â€ť, 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.
CLAYTON W. WILLIAMS, JR., 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 (the â€śWilliams Entitiesâ€ť). See â€śCertain Transactions and Relationships.â€ť
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 Williams Entities.
DAVIS L. FORD, age 69, is a director of the Company and a member of the Audit, Compensation and Nominating and Corporate Governance Committees of the Board of Directors. Dr. Ford has served as a director of the Company since his appointment in February 2004. Dr. Ford has been president of Davis L. Ford & Associates, an environmental engineering and consulting firm, for more than the past five years and is also an adjunct Professor at the University of Texas at Austin.
ROBERT L. PARKER, age 83, is a director of the Company and a member of the Audit, Compensation and Nominating and Corporate Governance Committees of the Board of Directors. Mr. Parker has served as a director of the Company since May 1993. Mr. Parker is Chairman, Emeritus of Parker Drilling Company, a publicly owned corporation providing contract drilling services, having served in such capacity for more than the past five years.
JORDAN R. SMITH, age 72, is a director of the Company and a member of the Audit, Compensation and Nominating and Corporate Governance Committees of the Board of Directors. Mr. Smith has served as a director of the Company since July 2000. Mr. Smith is President of Ramshorn Investments, Inc., a wholly owned subsidiary of Nabors Industries, having served in such capacity for more than the past five years. Mr. Smith serves as a director of Delta Petroleum Corporation, a publicly owned corporation in the energy business, and has served on the Board of the University of Wyoming Foundation and the Board of the Domestic Petroleum Council. Mr. Smith is also Founder and Chairman of the American Junior Golf Association.
STANLEY S. BEARD, age 66, is a director of the Company and a member of the Audit, Compensation and Nominating and Corporate Governance Committees. Mr. Beard has served as a director of the Company since September 1991. Mr. Beard has been engaged in private business related to the oil and gas industry for more than 20 years and has been involved in real estate development for more than 10 years.
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.
In 2006 the Compensation Committee consisted of Messrs. Beard, Ford, Parker and Smith, all of whom are independent directors under current SEC regulations and Nasdaq listing standards and are â€śoutside directorsâ€ť for purposes of Section 162(m) of the Tax Code. The Compensation Committee establishes the salaries of all corporate officers, including the named executive officers set forth in the Summary Compensation Table below, and directs and administers the Companyâ€™s incentive compensation plans other than the Outside Directors Stock Option Plan. The Compensation Committee also reviews with the Board its recommendations relating to the future direction of corporate compensation practices and benefit programs.
Compensation Philosophy and Principles
The Compensation Committee acknowledges that the oil and gas exploration and production industry is highly competitive and that experienced professionals have significant career mobility. The Company competes for executive talent with a large number of exploration and production companies, some of which have significantly larger market capitalization than the Company. Comparatively, the Company is a smaller company in a highly competitive industry, and its ability to attract, retain and reward its executive officers and other key employees is essential to maintaining a competitive position in the oil and gas business. The Companyâ€™s comparatively smaller size within its industry and its relatively small executive management team provide unique challenges in this industry, and therefore, are substantial factors in the design of the executive compensation program. The Compensation Committeeâ€™s goal is to maintain compensation programs that are competitive within the independent oil and gas industry. Each year, the Compensation Committee reviews the executive compensation program to assess whether the program remains competitive with those of similar companies, considers the programâ€™s effectiveness in creating adequate incentives for executives to find, acquire, develop and produce oil and gas reserves in a cost-effective manner, and determines what changes, if any, are appropriate.
The Compensation Committee has adopted a compensation policy which it believes to be a balance between fair and reasonable cash compensation and incentives linked to the Companyâ€™s performance, taking into consideration compensation of individuals with similar duties who are employed by its industry peers. The policy takes into account the cyclical nature of the oil and gas business, which may result in traditional performance standards being skewed due to erratic product prices. An analysis of the Companyâ€™s goals has resulted in a policy which places emphasis on increasing the Companyâ€™s proved oil and gas reserves and production, coupled with maintaining an acceptable balance between its overhead and profit margin. As described more fully below, the Compensation Committee may, in addition to base salaries, award bonuses, stock options and direct participation incentives based upon the performance of the Company and the efforts of individual executives and key employees.
In determining the form and amount of compensation payable to the Companyâ€™s executive officers, the Compensation Committee is guided by the following objectives and principles:
â€˘ Compensation levels should be sufficiently competitive to attract and retain key executives. The Compensation Committee aims to ensure that the Companyâ€™s executive compensation program attracts, motivates and retains outstanding talent and rewards them for the Company achieving and maintaining a competitive position in its industry. Total compensation ( i.e. , maximum achievable compensation) should increase with position and responsibility.
â€˘ Compensation should relate directly to performance, and incentive compensation should constitute a substantial portion of total compensation . The Compensation Committee aims to foster a pay-for-performance culture, with a significant portion of total compensation being â€śat risk.â€ť Accordingly, a substantial portion of total compensation should be tied to and vary with the Companyâ€™s financial, operational and strategic performance, as well as individual performance. Executives with greater roles in particular projects and the ability to directly impact the Companyâ€™s strategic goals and long-term results should bear a greater proportion of the risk if these goals and results are not achieved.
â€˘ Long-term incentive compensation should align executivesâ€™ interests with the Companyâ€™s shareholders. Awards of long-term incentive compensation encourage executives to focus on the Companyâ€™s long-term strategic growth and prospects and incentivize executives to manage the Company from the perspective of its shareholders.
â€˘ Retirement benefits should comprise an element of executive compensation. The Company does not offer retirement benefits to its executive officers other than through its tax-qualified 401(k) plan. Therefore, the Compensation Committee has designed the Companyâ€™s long-term incentive compensation to also provide a competitive level of replacement income upon retirement.
The Companyâ€™s executive compensation program is designed to reward the achievement of initiatives regarding Company growth and productivity, but it also takes into consideration the role and responsibilities of individual executive officers within the Company and internal pay equity. Therefore, the Companyâ€™s executive compensation is designed:
â€˘ To encourage the Companyâ€™s executive officers to maintain a thorough and dynamic understanding of the competitive environment and to position the Company as a competitive force within its industry.
â€˘ To incentivize the Companyâ€™s executive officers to develop strategic opportunities which benefit the Company and its shareholders.
â€˘ To sustain an internal culture focused on performance and the development of the Companyâ€™s assets into producing properties.
â€˘ To require the Companyâ€™s executive officers and other key employees to share the risks facing its shareholders, but to enable them to share in the rewards associated with the successful development of the Companyâ€™s assets into producing properties.
â€˘ To implement a culture of compliance and unwavering commitment to operate the Companyâ€™s business with the highest standards of professional conduct and compliance.
Managementâ€™s Role in the Compensation-Setting Process
Mr. Williams, the Companyâ€™s Chief Executive Officer, with the assistance of L. Paul Latham, its Chief Operating Officer and Mel G. Riggs, its Chief Financial Officer, evaluates all executive officers, including the named executive officers other than himself, and makes recommendations to the Compensation Committee regarding base salary levels, and the amounts of any incentive bonus payments and long-term incentive awards to be granted to all executive officers. Additionally, Messrs. Williams, Latham and Riggs regularly attend Compensation Committee meetings and upon the Compensation Committeeâ€™s request, provide compensation and other information to the Compensation Committee, including historical and prospective breakdowns of primary compensation components for each executive officer, internal pay equity analyses and information regarding the compensation paid to similarly situated executive officers within the Companyâ€™s peer group of industry competitors, as described in greater detail below.
Use of Independent Consultants
The Compensation Committee Charter provides the Compensation Committee with the authority to retain and terminate any compensation consulting firm or other adviser it deems appropriate. Historically, the Compensation Committee has not utilized independent advisors and compensation consultants in determining the appropriate level of the compensation for the Companyâ€™s executive officers; however, the Compensation Committee has relied, and anticipates it will continue to rely, on the Companyâ€™s legal, accounting and human resources departments in compiling public information to be utilized in determining the appropriate compensation package for the Companyâ€™s named executive officers. For 2006, the Compensation Committee relied upon publicly available information compiled under the supervision of Mr. Latham with respect to the peer group of competitor companies described below.
Market Compensation Analysis
To provide a frame of reference in evaluating the reasonableness and competitiveness of compensation, senior management determines similarly situated companies who are competitors with the Company in attracting and retaining management and obtains market pay levels for such companies from public filings. While the Compensation Committee reviews market pay for all of the named executive officers within the Companyâ€™s peer group of industry competitors, historically the Compensation Committee has only explicitly considered peer data in analyzing and setting compensation for its Chief Executive Officer and its directors. In 2006, the Compensation Committee reviewed a comparative analysis of the compensation paid to the directors, chief executive officer and other executive officers by a peer group of independent exploration and production companies. The analysis for directors consisted of compensation for 2003 and 2004, and the analysis for officers consisted of 2001 through 2004 compensation The peer group was determined by senior management, and the comparative analysis was prepared by Company personnel under the supervision of Mr. Latham. The Compensation Committee concluded that the group of companies selected was an appropriate peer group for the comparison of salary and other compensation payable to the Companyâ€™s Chief Executive Officer and directors. The peer companies represented a wide range of independent exploration and production companies, including both small and larger companies that operate in the same area of operations as the Company. The group of peer companies included in the compensation analysis reviewed by the Compensation Committee in 2006 was comprised of Brigham Exploration Co., Comstock Resources, Delta Petroleum, Denbury Resources, Inc., Edge Petroleum, Energy Partners, Houston Exploration, Parallel Petroleum, Petroquest Energy, Plains Exploration and Production, Range Resources Corp., Stone Energy, Swift Energy and Whiting Petroleum. The objective of the Compensation Committee in reviewing market pay levels is to ensure that compensation payable to its executive officers is not out of market. As noted, however, market pay levels are only one factor considered, with pay decisions ultimately reflecting an evaluation of individual contributions of an executive officer and the executiveâ€™s value to the Company.
The Compensation Committee does not believe that it is appropriate to establish compensation levels based exclusively or primarily on benchmarking to the Companyâ€™s peers. The Compensation Committee looks to external market data only as a reference point in reviewing and establishing individual pay components and total compensation and ensuring that the Companyâ€™s executive compensation is competitive in the marketplace. The Compensation Committee does not attempt to set total compensation or any component of compensation within a specific percentile of the Companyâ€™s peer group.
Determining Compensation Levels
The Compensation Committee annually determines the individual pay components of the Companyâ€™s executive officers. In making such determinations, the Compensation Committee reviews and considers (1) the compensation analysis referred to above prepared by Company personnel, (2) recommendations of the Companyâ€™s Chief Executive Officer, based on individual responsibilities and performance, (3) historical compensation levels for each executive officer, (4) industry conditions and the Companyâ€™s future objectives and challenges, and (5) the overall effectiveness of the executive compensation program.
Historically, the base compensation of the Companyâ€™s executive officers has been less than 50% of the total compensation of the executive officers, with the bulk of the remainder of compensation consisting of discretionary bonuses and long-term incentives, and with other annual compensation consisting of less than 10% of the total compensation. This is not due to any specific policy, practice or formula regarding the proper allocation between different elements of total compensation but does reflect the desire of the Compensation Committee to emphasize variable components of compensation to foster a pay-for-performance culture.
The components of compensation paid to executive officers in 2006 were:
â€˘ Base salary;
â€˘ Discretionary bonus;
â€˘ Long-term incentive awards; and
â€˘ Other annual compensation.
Compensation of executive officers has generally consisted of these elements since 2001.
The Compensation Committee has reviewed all components of the compensation of the Chief Executive Officer and the executive officers, including salary, bonus, equity and long-term compensation, accumulated realized and unrealized stock option gains, the dollar value to the executive and the cost to the Company of all perquisites and other personal benefits, and the projected future payouts under non-equity awards described below. In addition, the Compensation Committee has reviewed components of compensation of executive officers of the other peer companies in the industry with such components including salary, bonus, stock options, restricted stock awards, life insurance, vehicle allowances and other compensation. The Compensation Committee has reviewed the compensation policies of the Company and discussed the increased competition encountered by the Company in attracting and retaining qualified employees.
Based upon recommendations of Messrs. Williams and Latham, and upon its own judgment, the Compensation Committee approved the base salary, discretionary bonus, long-term incentive awards and other annual compensation of each of the Companyâ€™s executive officers in 2006. The Compensation Committee believes these approved forms and levels of compensation are reasonable, appropriate and consistent with the Companyâ€™s compensation philosophy and principles.
Base salary is set by the Compensation Committee at a level based on each executive officerâ€™s position, level of responsibility, and individual performance. As indicated above, base salary is typically less than 50% of each executive officerâ€™s total compensation. Although this result cannot occur explicitly by design, due to the nature of the Companyâ€™s long-term incentive compensation program discussed in greater detail below, it is the general intent of the Compensation Committee that a significant portion of the total compensation paid to the named executive officers be attributable to variable compensation, either in the form of discretionary bonuses or long-term incentive awards. The Compensation Committee believes that this mix of total compensation fosters a pay-for-performance culture by tailoring annual compensation to the individual performance of a named executive officer, while ensuring that the executive will continue to receive a consistent base amount of compensation. Historically, the Compensation Committee has annually increased the base salary of its named executive officers other than Mr. Williams, whose base salary has remained unchanged since 2001.
Bonuses are discretionary and are paid if and when the Compensation Committee determines they are necessary to reward exceptional individual performance and to encourage loyalty to the Company and the interests of its shareholders. The Compensation Committee believes that such bonuses serve both as a reward for performance and an incentive for future extraordinary performance in anticipation of such recognition. All officers also received Christmas bonuses relative to their annual salaries in 2006.
Executive officers of the Company, including Messrs. Williams and Latham, may recommend bonuses to the Compensation Committee for their approval to reward individual performance. Annual bonuses may also be used to compensate particular executives and key employees who the Compensation Committee determines are less than fully compensated at a particular point in time due to the failure of the long-term incentive awards granted to the employee to result in payment. As is described in greater detail below, the nature of the Companyâ€™s long-term incentive award program is such that an award could fail to ever result in payment through no lack of effort by the executive and in circumstances where the performance of the Company as a whole is very good. Although as a general policy, the Compensation Committee believes that executives should share the risks and rewards of the Companyâ€™s shareholders, if over a period of time an executive is undercompensated due to the nature of the Companyâ€™s long-term incentive program, the Compensation Committee will consider paying additional cash bonuses to the executive.
Long-Term Incentive Compensation
Long-term incentive compensation available to the Companyâ€™s executive officers consists of both equity-based awards and non-equity awards. Following is a discussion of each long-term incentive award used by the Company.
MANAGEMENT DISCUSSION FROM LATEST 10K
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 (â€śDD&Aâ€ť) per Mcfe of oil and gas production, an operating metric that measures a companyâ€™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.
â€˘ 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.
â€˘ 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.
â€˘ 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.
â€˘ 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.
â€˘ 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.
â€˘ 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.
â€˘ 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.
â€˘ 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.
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.
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.
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 (â€śG&Aâ€ť) 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 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.
MANAGEMENT DISCUSSION FOR LATEST QUARTER
Operating Results â€“ Three-Month Periods
The following discussion compares our results for the three months ended September 30, 2007 to the comparative period in 2006. Unless otherwise indicated, references to 2007 and 2006 within this section refer to the respective quarterly period.
Oil and gas operating results
Oil and gas sales in 2007 increased $23.1 million, or 38%, from 2006, of which production variances accounted for a $16.9 million increase and price variances accounted for a $6.2 million increase. Production in 2007 (on an Mcfe basis) was 33% higher than 2006. Oil production increased 9% and gas production increased 55% in 2007 from 2006 due primarily to incremental production attributable to drilling activity in North and South Louisiana. In 2007, our realized oil price was 7% higher than 2006, while our realized gas price was 9% 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 27% in 2007 as compared to 2006 due primarily to higher oilfield service costs and higher repair and maintenance costs. After giving effect to a 33% increase in oil and gas production on an Mcfe basis, production costs per Mcfe decreased 5% from $2.28 per Mcfe in 2006 to $2.17 per Mcfe in 2007. It is likely that production costs will continue to increase in future periods.
Oil and gas depletion expense increased $4.1 million, of which production variances accounted for a $5.3 million increase and rate variances accounted for a $1.2 million decrease. On an Mcfe basis, depletion expense decreased 6% from $2.30 per Mcfe in 2006 to $2.16 per Mcfe in 2007 due in part to a lower depletable cost basis in 2007 compared to the 2006 period in two areas where we recorded an impairment of proved property under SFAS No. 144 in the last half of 2006. Depletion expense 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. We may realize higher oil and gas depletion rates in future periods if our exploration activities result in higher finding costs.
We recorded a provision for impairment of property and equipment under SFAS 144 of $8 million during the third quarter of 2007, of which $5.1 million related to a write-down of two 2,000 horsepower drilling rigs and related components to their estimated fair market value. The remaining $2.9 million impairment related to producing properties in West Texas.
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 2007, we charged to expense $20 million of exploration costs, as compared to $23.3 million in 2006. Most of the 2007 costs were incurred in Louisiana.
At September 30, 2007, our capitalized unproved oil and gas properties totaled $151.9 million, of which approximately $89.8 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 $251.4 million on exploration and development activities in fiscal 2007, of which approximately 52% 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.
Contract Drilling Services
In April 2006, we formed a joint venture (â€śLarclay JVâ€ť) with Lariat Services, Inc. to construct, own, and operate 12 new drilling rigs. We own a 50% interest in Larclay JV. The rigs were constructed on behalf of Larclay JV by Lariat, as operations manager. Although the Company and Lariat own equal interests in Larclay JV, the Company meets the definition of the primary beneficiary of Larclay JVâ€™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 Companyâ€™s consolidated financial statements. During the three months ended September 30, 2007, we included contract drilling revenues of $14.8 million, net other operating expenses of $8.5 million, depreciation expense of $2 million and interest expense of $1.3 million in our statement of operations (see Note 14 to the consolidated financial statements). Since the Larclay JV drilling rigs are partially utilized by us, the reported amounts are net of any intercompany profits eliminated in consolidation.
General and Administrative
General and administrative (â€śG&Aâ€ť) expenses increased 39% from $3.1 million in 2006 to $4.3 million in 2007 due primarily to increases in professional fees and personnel costs. Excluding non-cash employee compensation, G&A expenses increased from $2.6 million in 2006 to $3.8 million in 2007. In 2007 and 2006, we recorded a $500,000 non-cash compensation charge related to our after payout incentive plan.
Interest expense increased 59% from $5.3 million in 2006 to $8.4 million in 2007 due to a combination of factors. In 2006 and 2007, 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 2007 was $186.2 million compared to $102.6 million for 2006. Capitalized interest for 2007 was $1.1 million compared to $1.6 million in 2006. We also included $1.3 million of interest expense associated with our Larclay JV during 2007 compared to zero in the 2006 period.
Gain/loss on derivatives
We did not designate any derivative contracts in 2007 or 2006 as cash flow hedges; therefore all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on derivatives. For the three months ended September 30, 2007, we reported a $2.3 million net loss on derivatives, consisting of a $3.9 million non-cash loss to mark our derivative positions to their fair value at September 30, 2007 and a $1.6 million realized gain on settled contracts. For the three months ended September 30, 2006, we recorded a net gain on derivatives of $26.7 million, consisting of a $28.4 million non-cash gain related to changes in mark-to-market valuations and a $1.7 million realized loss on settled contracts.
Income tax expense
Our effective income tax rate in 2007 of 34.7% differed from the statutory federal rate of 35% due primarily to increases in the tax provision related primarily to the effects of the recently-enacted Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from statutory depletion deductions.