SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| (Mark One) | ||
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) | |
| OF THE SECURITIES EXCHANGE ACT OF 1934 | ||
| For the fiscal year ended December 31, 2007 |
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) | |
| OF THE SECURITIES EXCHANGE ACT OF 1934 | ||
For the transition period from to | ||
Commission File Number 001-10924 |
CLAYTON WILLIAMS ENERGY, INC.
(Exact name of registrant as specified in its charter)
| Delaware | 75-2396863 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
| Six Desta Drive - Suite 6500 | ||
| Midland, Texas | 79705-5510 | |
| (Address of principal executive offices) | (Zip code) | |
| Registrant’s telephone number, including area code: | (432) 682-6324 |
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of each exchange on which registered | |
| Common Stock - $.10 Par Value | The NASDAQ Stock Market LLC |
Securities registered pursuant to Section 12(g) of the Act: None
| Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act | ||||
¨ Yes | x No | |||
| Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. | ||||
¨ Yes | x No | |||
| Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. | ||||
x Yes | ¨ No | |||
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x |
| Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. | ||||
Large accelerated filer ¨ | Accelerated filer x | |||
Non-accelerated filer ¨ | Smaller reporting company ¨ | |||
| Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). | ||||
¨ Yes | x No | |||
| State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter. $156,486,908. |
| There were 11,354,051 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 14, 2008. |
DOCUMENTS INCORPORATED BY REFERENCE
| Portions of the definitive proxy statement relating to the 2008 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2008, are incorporated by reference in Part III of this Form 10-K. |
CLAYTON WILLIAMS ENERGY, INC
TABLE OF CONTENTS
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This Annual Report on Form 10-K contains forward-looking statements that are based on management’s current expectations. Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions. Forward-looking statements appear throughout this Form 10-K with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Item 1 – Business – Risk Factors” and elsewhere in this report. We disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Definitions of terms commonly used in the oil and gas industry and in this Form 10-K can be found in the Glossary of Terms.
Item 1 - Business
Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, Louisiana and New Mexico. Unless the context otherwise requires, references to the “Company”, “CWEI”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. On December 31, 2007, our estimated proved reserves were 290.8 Bcfe, of which 76% were proved developed. We have a balanced portfolio of oil and natural gas reserves, with approximately 42% of our proved reserves at December 31, 2007 consisting of natural gas and approximately 58% consisting of oil and natural gas liquids. During 2007, we added proved reserves of 34.9 Bcfe through extensions and discoveries, had upward revisions of 20.9 Bcfe and had sales of minerals-in-place of .6 Bcfe. We also achieved average net production of 98.3 MMcfe per day in 2007, which implies a reserve life of approximately 8.1 years. CWEI held interests in 6,694 gross (918.0 net) producing oil and gas wells and owned leasehold interests in approximately 1.3 million gross (784,000 net) undeveloped acres at December 31, 2007.
Clayton W. Williams, Jr. beneficially owns, either individually or through his affiliates, approximately 20% of the outstanding shares of our common stock. In addition, The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership of which Mr. Williams’ adult children are the limited partners, owns an additional 27% of the outstanding shares of our common stock. Mr. Williams is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations.
Company Profile
Business Strategy
Our goal is to grow oil and gas reserves and increase shareholder value utilizing a flexible, opportunity-driven business strategy. We do not adhere to rigid guidelines for resource allocations, risk profiles, product mixes, financial measurements or other operating parameters. Instead, we try to identify exploratory and developmental projects that offer us the best possible opportunities for growth in oil and gas reserves and allocate our available resources to those projects. Our direction is heavily influenced by Mr. Williams based on his 50 years of experience and leadership in the oil and gas industry. Our business strategy consists of an aggressive exploration program, complimented by developmental drilling and proved property acquisitions. From year to year, our allocation of investment capital may vary between exploratory and developmental activities depending on our analysis of all available growth opportunities, but our long-term focus remains consistent with our goal of value enhancement for our shareholders.
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Domestic Operations
We conduct all of our drilling, exploration and production activities in the United States. All of our oil and gas assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.
Exploration Program
Our exploration program consists of generating exploratory prospects, leasing the acreage 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 higher risk/higher potential nature of oil and gas exploration, we expect to spend money on prospects that are ultimately nonproductive. However, over time, we believe our productive prospects will generate sufficient cash flow to provide us with an acceptable rate of return on our entire investment, both nonproductive and productive.
We are presently concentrating our exploration efforts in East Texas, Louisiana and Utah. Approximately 19% of our planned expenditures for 2008 relate to exploratory prospects, as compared to approximately 51% of actual expenditures in 2007 and 84% of actual expenditures in 2006. During 2007, we spent $118.6 million on exploratory prospects, including $16.7 million on seismic and leasing activities and $101.9 million on drilling activities.
Development Program
Complimentary to our higher risk/higher potential exploration program is our development program. A developmental well is a well drilled within the proved area of an oil and gas reservoir to a horizon known to be productive. We have an inventory of developmental projects available for drilling in the future, most of which are located in the Austin Chalk (Trend), the Permian Basin and North Louisiana. Some of the developmental wells in our inventory meet the engineering standards necessary to be classified as proved reserves. Our estimates of oil and gas reserves at December 31, 2007 include 93.6 Bcfe of proved reserves attributable to developmental projects that will require us to spend approximately $174.3 million over time to develop. In addition, many of the developmental wells in our inventory do not meet the engineering standards necessary to be defined as proved reserves and have not been included in our estimates of proved reserves at December 31, 2007.
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In most cases, our leasehold interests in developmental projects are held by the continuous production of other wells, meaning that our rights to drill these projects are not subject to near-term expiration. This provides us with a high degree of flexibility in the timing of developing these reserves. Consistent with our business strategy, we have chosen, in recent years, to limit our spending on developmental projects in order to maximize our exploration efforts. Due in large part to record high oil prices, we currently plan to spend approximately $208.1 million, or 81% of our planned expenditures for 2008, on developmental projects, most of which are in oil-prone areas. Approximately 37% of our developmental drilling in 2008 will be applicable to wells that have been assigned proved reserves at December 31, 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, we did not acquire any proved properties in 2007, and we cannot give any assurance that we will be successful in our efforts to acquire proved properties in 2008.
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. In 2007, we sold all of our leasehold interests in producing and non-producing properties in Pecos County, Texas for approximately $21 million, and recorded a gain on the sale of approximately $12.5 million. The leases sold were part of an exploratory project operated by an industry partner and were not integral to our other West Texas activities.
Investments
West Coast Energy Properties, L.P.
West Coast Energy Properties, L.P. (“WCEP”) is a Texas limited partnership formed in 2006 to facilitate the acquisition of certain producing oil and gas assets in California and Texas. We are the general partner of WCEP and an affiliate of GE Energy Financial Services is the limited partner. Our initial partnership interest is 5%, but our interest can increase to 37.63%, and ultimately to 49%, upon the achievement of certain target rates of return. During 2007, we contributed $336,000 of additional capital to the partnership to finance our share of drilling activity. We account for our interest in WCEP using the proportionate consolidation method, whereby our share of WCEP's assets, liabilities, revenues and expenses are consolidated with our other operations.
Larclay JV
In April 2006, we formed a joint venture (“Larclay JV”) with Lariat Services, Inc. (“Lariat”) to construct, own and operate 12 new drilling rigs. We and Lariat each own a 50% interest in Larclay JV. A lender provided a $75 million secured term loan to Larclay JV to finance most of the cost of constructing and initially equipping the rigs. The Larclay JV agreements require us to make loans to Larclay JV as needed to finance any costs to construct and initially equip the original 12 drilling rigs which are not otherwise financed under the secured term loan. Construction on 11 of the rigs is complete, and we loaned Larclay JV $4.6 million during the fourth quarter of 2007 in compliance with the agreements. The loan to Larclay JV is due on demand and bears interest, payable monthly, at the same rate as the secured term loan. However, the loan is subject to a subordination agreement with the secured lender that imposes restrictions on payments of principal and interest on the note. All components of the final Larclay JV drilling rig, a 2,000 horsepower rig designed primarily to drill deep gas wells, have been purchased, but the final assembly of the rig has been postponed while we evaluate the market for additional deep rigs in Larclay JV’s areas of operations. Upon making a final determination, Larclay JV will either proceed with the final assembly of the rig or it will sell the rig components. If the rig is assembled for operation, we may be required to make an additional subordinated loan to finance the costs to assemble the rig, the amount of which is expected to be less than $2 million.
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 program 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
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with other operators for the use of such rig, subject to certain restrictions. If a rig is idle, we 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. Our maximum potential obligation to pay idle rig rates over the term of this drilling contract, excluding any crew labor expenses, totals approximately $78.1 million at December 31, 2007.
Exploration and Development Activities
In 2007, we spent $230.7 million on exploration and development activities which was financed primarily by cash flow from operations. We presently plan to spend approximately $256.5 million on exploration and development activities during 2008, most of which will be financed by cash flow from operations, and the balance will be financed by borrowings on our revolving credit facility. 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.
Permian Basin
The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period. Although many fields in the Permian Basin have been heavily exploited in the past, higher product prices and improved technology (including deep horizontal drilling) continue to encourage high levels of current drilling and recompletion activities. We gained a significant position in the Permian Basin in 2004 when we acquired Southwest Royalties, Inc. This acquisition provided us with an inventory of potential drilling and recompletion activities that we are beginning to exploit.
We spent $34.2 million in the Permian Basin during 2007 on exploration and development activities, of which $33.6 million was spent on drilling and completion activities and $600,000 was spent on seismic and leasing activities. We drilled 6 gross (5.0 net) operated wells in the Permian Basin and conducted remedial operations on existing wells in 2007. In addition, we participated in the drilling of 25 gross (5.5 net) non-operated wells, with working interests ranging from 1% to 54%.
The Permian Basin continues to be a significant source of cash flow for us. We currently expect to spend $110.3 million on development activities in the Permian Basin in 2008. Most of the drilling activities relate to our War-Wink and Amacker-Tippett prospects in West Texas. In the War-Wink area, we are presently drilling horizontal wells targeting oil-prone sands in the Bone Spring formation, and have identified at least 10 other possible locations to further exploit this area. On the Amacker-Tippett prospect, we have identified 15 possible locations on which to drill vertical wells. These wells will target similar oil-prone sands in the Spraberry and Wolfcamp formations which are encountered at depths ranging from 7,000 to 10,500 feet. We have also identified several recompletion opportunities on existing vertical wells in the area.
Austin Chalk (Trend)
Prior to 1998, we concentrated our drilling activities in an oil-prone area we refer to as the Austin Chalk (Trend) in Robertson, Burleson, Brazos, Milam and Leon Counties, Texas. Most of our wells in this area were drilled as horizontal wells, many with multiple laterals in different producing horizons, including the Austin Chalk, Buda and Georgetown formations. The existing spacing between some of our wells in this area affords us the opportunity to tap additional oil and gas reserves by drilling new wells between existing wells, a technique referred to as in-fill drilling. These in-fill wells are considered lower risk as compared to exploratory wells and, with oil prices at historic highs, the rates of return are now attractive. In addition, we are conducting secondary water frac operations on existing wells in the Austin Chalk (Trend) area to improve production rates and add new reserves. We plan to spend $59.3 million on development activities and leasing in this area during 2008.
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 2007, we had drilled 67 gross (53.6 net) exploratory wells in South Louisiana, of which 34 gross (25.9 net) were completed as producers. The following table sets forth certain information about wells which were significant to our drilling and completion activities in South Louisiana subsequent to December 31, 2006.
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| Working | Current | |||||
| Spud Date | Well Name (Prospect) | Interest | Status | |||
| January 2007 | SL 195 QQ #7 (Floyd) | 100% | Producing | |||
| February 2007 | SL 195 QQ #10 (Floyd) | 75% | Producing | |||
| February 2007 | Orleans Levee District #2 (American Bay) | 45% | Producing | |||
| March 2007 | Bowie Lumber Co. #1 (Bayou Boeuf) | 100% | Dry | |||
| April 2007 | Pivach Agency #1 (Elsa) | 94% | Dry | |||
| June 2007 | SL 195 QQ #12 (Floyd) | 100% | Producing | |||
| June 2007 | SL 16849 #2 (Dolly) | 94% | Producing |
We spent $65.7 million in South Louisiana during 2007 on exploration and development activities, of which $60.6 million was spent on drilling and completion activities and $5.1 million was spent on seismic and leasing activities. We currently plan to spend approximately $13.4 million in South Louisiana in 2008 for drilling and leasing activities.
We completed development activities on our Floyd prospect in 2007, and do not expect to spend any additional capital in 2008 on new drilling in this area due primarily to lower than expected production performance and net downward reserve revisions of 11.2 Bcfe from our prior fiscal year.
In late 2007, we entered into an agreement with an industry partner, in which they have committed to drill five wells on certain of our prospects in South Louisiana during 2008. The industry partner will operate the wells, and we will have a 15% before casing point working interest and a 50% after casing point working interest in each well drilled. We expect to spend approximately $2.9 million for our portion of drilling activities under this agreement.
We currently plan to spend an additional $10.5 million in South Louisiana in 2008 to generate and lease new exploratory prospects and to drill wells on existing exploratory and developmental prospects not related to the five-well agreement described above.
North Louisiana
In 2005, we began an exploration program in North Louisiana targeting the Cotton Valley/Gray and Bossier formations. In this area, the Cotton Valley/Gray formations are encountered at depths ranging from 8,000 to 12,000 feet, and the Bossier formation is encountered at depths ranging from 11,000 to 15,500 feet. 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 wells which were significant to our drilling and completion activities in North Louisiana subsequent to December 31, 2006. This table does not include 21 gross (2.0 net) non-operated wells in which our working interests range from 1% to 29%.
| Working | Current | |||||
| Spud Date | Well Name (Prospect) | Interest | Status | |||
| October 2006 | P. Benoit #1 (Sarepta) | 91% | Dry | |||
| January 2007 | J.L. Hood #1 (Terryville) | 86% | Producing | |||
| February 2007 | J. Huey #1 (Terryville) | 86% | Producing | |||
| March 2007 | David Barton #1 (Winnsboro) | 100% | Dry | |||
| March 2007 | George Staton #1 (Sarepta) | 68% | Producing | |||
| April 2007 | C.M. Bice #1 (Terryville) | 86% | Producing | |||
| May 2007 | C. Dugdale #1 (Choudrant) | 99% | Dry | |||
| June 2007 | Stephenson #1 (Terryville) | 86% | Producing | |||
| June 2007 | John Warren #1 (Terryville) | 86% | Producing | |||
| July 2007 | Burks #1 (Terryville) | 86% | Producing | |||
| July 2007 | Henry #2 (Terryville) | 86% | Dry | |||
| July 2007 | Allen Estate #1 (Terryville) | 100% | Producing | |||
| August 2007 | McCrary #1 (Terryville) | 86% | Producing | |||
| August 2007 | Henry #1 (Terryville) | 86% | Producing | |||
| September 2007 | LA Minerals #1 (Ruston) | 66% | Producing | |||
| October 2007 | Barnett #1 (Terryville) | 86% | Producing | |||
| November 2007 | A. Lewis Estate #2 (Terryville) | 86% | Producing | |||
| January 2008 | Henry #3 (Terryville) | 86% | Producing | |||
| February 2008 | J.G. Mitchell #1 (Ruston) | 74% | Drilling |
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We spent $74.3 million in North Louisiana during 2007 on exploration and development activities, of which $69.9 million was spent on drilling and completion activities and $4.4 million was spent on seismic and leasing activities. Our drilling activities in North Louisiana resulted in the addition of approximately 19.1 Bcfe of proved reserves in 2007, most of which came from our Terryville prospect in Lincoln Parish.
To date, we have completed thirteen wells on the Terryville prospect as producers. These wells are currently producing at combined rates of approximately 10,730 Mcf of gas per day and 310 barrels of oil per day, net to the Company’s interest. We expect to drill five more development wells on our Terryville prospect in 2008.
Our first exploratory well on the Sarepta prospect in Webster Parish, the P. Benoit #1, targeted a hydrocarbon formation in the Gray sand, but that zone was non-productive and we recorded a pre-tax charge of $4.9 million related to the abandonment of this well. We also drilled the George Staton #1, a 12,200-foot exploratory well in the Sarepta prospect, which is currently producing.
We drilled the C. Dugdale #1 on our Choudrant prospect in Lincoln Parish to the Cotton Valley interval which was deemed non-commercial, thus resulting in a pre-tax charge of $7.1 million for the abandonment of this well. We do not plan to drill any additional wells on this prospect in 2008. Also in Lincoln Parish, on our Ruston prospect, we have drilled the LA Minerals #1 which is producing from the Gray sand. We are currently drilling the J.G. Mitchell #1 and plan to drill another 3 wells on this prospect in 2008.
We temporarily abandoned the David Barton #1, an exploratory well in the Winnsboro prospect in Richland Parish, prior to reaching the pressured Bossier interval. We recorded a pre-tax charge of $8.6 million related to the abandonment of this well in the second quarter of 2007. We may drill an offset to the Barton well in 2008 in order to test the pressured Bossier interval in this area.
We currently have approximately 170,000 net acres leased for Bossier drilling in North Louisiana. In 2007, we recorded a $9.3 million provision for impairment of certain acreage in the area in order to reduce the carrying value to its estimated fair value.
In 2008, we currently plan to spend approximately $47.9 million in North Louisiana in 2008 primarily to drill developmental wells on the Terryville and Choudrant prospects.
East Texas Bossier
We currently have approximately 142,000 net acres under lease in East Texas targeting the prolific deep Bossier sands which are encountered at depths ranging from 14,000 to 22,000 feet in this area. Of this acreage, approximately 70,000 net acres are held by production from existing Austin Chalk (Trend) wells. Exploration for deep Bossier gas sands in this area is in its early stages and involves a high degree of risk. The geological structures are complex, and limited drilling activity offers minimal subsurface control. Deep Bossier wells are expensive to drill, with completed wells costing approximately $18 million each. Although seismic data is helpful in identifying possible sand accumulations, the only way to determine if the deep Bossier sand will be commercially productive is to drill wells to the targeted structures.
During 2007, we drilled two wells in this area targeting the deep Bossier, the Big Bill Simpson #1, a 19,000-foot exploratory well in Leon County (70% working interest), and the Margarita #1, a 20,000-foot exploratory well in Robertson County (100% working interest). These wells were in progress at December 31, 2007 and were completed during the first quarter of 2008. The Big Bill Simpson well encountered a thick section of lower and middle Bossier sands, but these sands had limited porosity. The Margarita #1 well only encountered the upper Bossier sand.
The Big Bill Simpson #1 is currently producing approximately 500 gross (263 net) Mcf of gas per day. The Margarita #1 is waiting on completion of pipeline facilities to begin production, but is expected to initially produce approximately 750 gross (563 net) Mcf of gas per day, based on well test data. We have not assigned any proved reserves to these wells since we do not have sufficient production history to permit us to make a reasonable estimate at this time. However, it appears to be unlikely that we will recover the $28 million of drilling and completion costs we incurred on these wells through future production from only these wells. Depending on our evaluations of these wells and our results of drilling activities in our deep Bossier play, we may record impairments of proved properties related to these wells in future periods.
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We currently plan to spend approximately $17.2 million in the East Texas Bossier area related primarily to leasing and seismic activities. Despite the disappointing results of the Big Bill Simpson #1 and the Margarita #1, we are optimistic that our acreage position in this area is prospective for potentially significant deep Bossier discoveries. As more wells are drilled and more subsurface control data is obtained, we believe our prospects for discoveries improve. We have begun a 3-D seismic shoot in Leon County, Texas over the Big Bill Simpson prospect in an attempt to high grade our next well’s position on this acreage. In addition, we are considering a proprietary 3-D shoot in Burleson County, Texas to help us select potential drill sites on other deep Bossier prospects in this area.
Other Exploration and Development Activities
In Utah, we plan to participate in the drilling of a 12,000-foot exploratory well, the Lamb #1 in the Overthrust prospect (33% working interest) in Sanpete County, Utah. The well will target the oil-prone Navajo sandstone formation.
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
Generally. Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our
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profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.
Regulations affecting production. All of the states in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.
In the event we conduct operations on federal, state or Indian oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or other relevant federal or state agencies.
Regulations affecting sales. The sales prices of oil, natural gas liquids and natural gas are not presently regulated, but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.
Under the Energy Policy Act of 2005, the Federal Energy Regulatory Commission (“FERC”) possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity.” The Commodity Futures Trading Commission (“CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas, natural gas liquids and crude oil, our gathering of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.
The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. The FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially differently than other natural gas producers in our areas of operation.
Interstate transportation rates for oil, natural gas liquids and other products is also regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.
Gathering regulations. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own certain natural gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is, however, the
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subject of substantial, on-going litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts or the U.S. Congress.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another.
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 2008. 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.
Hazardous Substances. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.
Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency (“EPA”) or state agencies as solid wastes. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes
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and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.
Air Emissions. The Federal Clean Air Act and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by us. We do not believe that our operations will be materially adversely affected by any such requirements.
Water Discharges. The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the United States Oil Pollution Act of 1990 (“OPA”) and similar legislation enacted in Texas, Louisiana and other coastal states impose oil spill prevention and control requirements and significantly expand liability for damages resulting from oil spills. OPA imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil spill response and removal costs and a variety of public and private damages.
Global Warming and Climate Change. In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth’s atmosphere, the current session of the U.S. Congress is considering adoption of climate change-related legislation that would restrict emissions of “greenhouse gases.” One bill recently approved by the Senate Committee on Environment and Public Works would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. In addition, at least 20 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. In California, for example, the California Global Warming Solutions Act of 2006 requires the California Air Resources Board to adopt regulations by 2012 that will achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.
Depending on the legislation or regulatory program that may be adopted to address emissions of greenhouse gases, we could be required to reduce greenhouse gas emissions resulting from our operations or we could be required to purchase and surrender allowances for greenhouse gas emissions associated with our operations or the oil and gas we produce. Although we would not be impacted to a greater degree than other similarly situated producers of oil and gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and gas we produce.
Pipeline Safety. Some of our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, natural gas liquids (“NGLs”) and condensate transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined to include areas with specified population densities, buildings containing populations with limited mobility, areas where people may gather along the route of a pipeline (such as athletic fields or campgrounds), environmentally sensitive areas, and commercially navigable waterways. Under the DOT’s regulations, integrity management programs are required to include baseline assessments to identify potential threats to each pipeline segment, implementation of mitigation measures to reduce the risk of pipeline failure, periodic reassessments, reporting and recordkeeping. The DOT also is required by the Pipeline Inspections, Protection,
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Enforcement, and Safety Act of 2006 to issue new regulations that set forth safety standards and reporting requirements applicable to low stress pipelines and gathering lines transporting hazardous liquids, including oil, NGLs and condensate. A final rule addressing safety standards for hazardous liquid low-stress pipelines and gathering lines is anticipated to be issued by PHMSA in 2008. Such new hazardous liquid pipeline safety standards may include applicable integrity management program requirements.
OSHA and Other Laws and Regulation. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Claims are sometimes made or threatened against companies engaged in oil and gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, in other jurisdictions in which we operate, courts have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.
As is customary in the oil and gas industry, we perform a minimal title investigation before acquiring undeveloped properties. A title opinion is obtained prior to the commencement of drilling operations on such properties. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. These title investigations and title opinions, while consistent with industry standards, may not reveal existing or potential title defects, encumbrances or adverse claims as we are subject from time to time to claims or disputes regarding title to properties. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our oil and gas properties are currently mortgaged to secure borrowings under our revolving credit facility and may be mortgaged under any future credit facilities entered into by us.
Operational Hazards and Insurance
Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.
We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.
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The following is a list, as of March 14, 2008 of the name, age and position with the Company of each person who is an executive officer of the Company:
CLAYTON W. WILLIAMS, JR., age 76, is Chairman of the Board, President, Chief Executive Officer and a director of the Company, having served in such capacities since September 1991. For more than the past five years, Mr. Williams has also been the chief executive officer and a director of certain entities which are controlled directly or indirectly by Mr. Williams.
L. PAUL LATHAM, age 56, is Executive Vice President, Chief Operating Officer and a director of the Company, having served in such capacities since September 1991. Mr. Latham is the sole general partner of The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership in which the adult children of Clayton W. Williams, Jr. are the limited partners. WCPL holds approximately 27% of the outstanding shares of our common stock. As the sole general partner, Mr. Latham has the power to vote or direct the voting of the shares of our common stock held by WCPL. Mr. Latham also serves as an officer and director of certain entities which are controlled directly or indirectly by Mr. Williams.
MEL G. RIGGS, age 53, 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 55, is Vice President – New Ventures of the Company, having served in such capacity since 1993.
ROBERT C. LYON, age 71, is Vice President – Gas Gathering and Marketing of the Company, having served in such capacity since 1993.
MICHAEL L. POLLARD, age 58, 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 51, is Vice President and General Counsel of the Company, having served in such capacity since 1993.
GREGORY S. WELBORN, age 34, is Vice President – Land of the Company, having served in such capacity since 2006.
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Employees
At December 31, 2007, we had 186 full-time employees, none of whom is subject to a collective bargaining agreement. In our opinion, our relations with employees are good.
The Company maintains an internet website at www.claytonwilliams.com. The Company makes available, free of charge, on its website, its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. The information contained in or incorporated in our website is not part of this report.
Item 1A - Risk Factors
There are many factors that affect our business, some of which are beyond our control. Our business, financial condition and results of operations could be materially adversely affected by any of these risks. The risks described below are not the only ones facing our company. Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations.
Our exploration activities subject us to greater risks than development activities.
As a general rule, our oil and gas exploration activities pose a higher economic risk to us than our development activities. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to increasing oil or natural gas production from an area that is known to be productive by drilling additional wells, working over and recompleting existing wells and other production enhancement techniques. Exploration projects are identified through subjective analysis of geological and geophysical data, including the use of 3-D seismic and other available technology. By comparison, the identification of development prospects is significantly based upon existing production surrounding or adjacent to the proposed drilling site.
For 2008, approximately 19% of our planned exploration and development activities relate to exploratory prospects, as compared to 51% in 2007. Although we currently plan to spend a much lesser portion of our investment capital on exploration activities in 2008 than in recent years, our on-going business strategy includes a heavy commitment to oil and gas exploration. To the extent we engage in exploration activities, we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or natural gas is present or can be produced economically. We charged to expense $68.9 million in 2007 for abandonment and impairment, most of which was related to unsuccessful exploratory drilling activities in North and South Louisiana. 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, 2007 is approximately 8.1 years, based on 2007 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 limited our efforts to developmental drilling activities.
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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 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 2008. 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 2008, approximately 19% 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 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 under our revolving credit facility. The lenders under our revolving credit facility establish the borrowing base under such facility 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 our revolving credit facility.
Failure to comply with covenants under our debt agreements could adversely impact our financial condition and results of operations. Our revolving credit facility contains financial covenants that require us to, among other things maintain positive working capital in accordance with computational guidelines contained in the related loan agreement and to maintain a ratio of indebtedness to cash flow of no more than 3 to 1. Although we are in compliance with these covenants at December 31, 2007, adverse changes in our leverage or liquidity could cause us to fail to comply with one or more of these covenants. If we fail to meet any of these loan covenant, the lenders under the revolving credit facility could accelerate the indebtedness and seek to foreclose on the pledged assets.
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
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we anticipated. Commodity prices also impact our cash flow from operating activities. Based on December 31, 2007 reserve estimates, we project that a $1 drop in oil price and a $.50 drop in gas price would reduce our gross revenues in 2008 by approximately $2.7 million and $9.7 million, respectively.
Adverse changes in the borrowing base under our revolving credit facility may cause outstanding debt to equal or exceed the borrowing base. If the borrowing base under our revolving credit facility is reduced due to adverse changes in reserve estimates or commodity prices or otherwise, the outstanding debt under our revolving credit facility may equal or exceed our 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 our 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 our revolving credit facility. Until a well is on production, the lenders under our revolving credit facility 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 2008 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.
We are also required to comply with anti-market manipulation laws and regulations enforced by the FERC and the CFTC. In the event of our failure to comply with such laws and regulations, we could face civil and criminal penalties and other liabilities.
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
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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 the lenders under our revolving credit facility in establishing the borrowing base under such credit facility and by our engineers for use in developing business plans and making various decisions. Such estimates may vary significantly from those of the independent engineers and have a material effect upon our business decisions and available capital resources.
Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.
Our on-going business strategy includes growing our reserves and drilling inventory through acquisitions. Acquired properties can be subject to significant unknown liabilities. Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired in an acquisition. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed.
Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders' equity.
Our failure to integrate acquired businesses successfully into our existing business could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.
The process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations.
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; |
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| · | 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, maintenance and repair 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.
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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 Clayton W. Williams, Jr. and his family limited partnership.
Clayton W. Williams, Jr. beneficially owns, either individually or through his affiliates, approximately 20% of the outstanding shares of our common stock. Mr. Williams is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Williams has significant influence over matters voted on by our shareholders, including the election of our Board members, and in all other facets of our business, including both our business strategy and daily operations.
WCPL, a limited partnership in which Mr. Williams’ adult children are the limited partners, owns an additional 27% of the outstanding shares of our common stock. L. Paul Latham, our Executive Vice President and Chief Operating Officer, is the sole general partner of WCPL and has the power to vote or direct the voting of the shares held by WCPL. In voting these shares, Mr. Latham will not be acting in his capacity as an officer and director of the Company and will consider the interests of WCPL and Mr. Williams’ children. They may have interests that differ from the interests of our other shareholders.
The retirement, incapacity or death of Mr. Williams, or any change in the power to vote shares beneficially owned by Mr. Williams or held by WCPL, could result in negative market or industry perception and could have a material adverse effect on our business.
By extending credit to our customers, we are exposed to potential economic loss.
We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. As appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. We cannot assure you that we will not suffer any economic loss related to credit risks in the future.
Compliance with laws and regulations governing our activities could be costly and could negatively impact production.
Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.
All of the states in which we operate generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from our properties.
The FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our
20
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 - Unresolved Staff Comments
Not applicable.
Item 2 - - Properties
Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. At December 31, 2007, we had interests in 6,694 gross (918.0 net) oil and gas wells and owned leasehold interests in approximately 1.3 million gross (784,000 net) undeveloped acres.
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The following table sets forth certain information as of December 31, 2007 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.
| Proved Developed | Proved | Total | ||||||||||||||
| Producing | Non-producing | Undeveloped | Proved | |||||||||||||
| (Dollars in thousands) | ||||||||||||||||
| Gas (MMcf) | 87,403 | 11,031 | 24,722 | 123,156 | ||||||||||||
| Oil and natural gas liquids (MBbls) | 18,299 | 2,328 | 7,319 | 27,946 | ||||||||||||
| Total (MMcfe) | 197,197 | 24,999 | 68,636 | 290,832 | ||||||||||||
| Standardized measure of discounted | ||||||||||||||||
| future net cash flows | $ | 925,969 | ||||||||||||||
| Present value of proved reserves (a) | $ | 1,331,110 | ||||||||||||||
| (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, 2007 were $381.4 million and $23.7 million, respectively. |
The following table sets forth certain information as of December 31, 2007 regarding our proved oil and gas reserves in each of our principal producing areas.
| Percent | ||||||||||||||||||||||||
| Proved reserves | Present | of Present | ||||||||||||||||||||||
| Total Gas | Percent of | Value of | Value of | |||||||||||||||||||||
Oil (a) | Gas | Equivalent | Total Gas | Proved | Proved | |||||||||||||||||||
| (MBbls) | (MMcf) | (MMcfe) | Equivalent | Reserves | Reserves | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
| Permian Basin | 17,318 | 65,248 | 169,156 | 58.2 | % | $ | 684,691 | 51.4 | % | |||||||||||||||
| North Louisiana | 319 | 14,046 | 15,960 | 5.5 | % | 72,240 | 5.5 | % | ||||||||||||||||
| South Louisiana | 1,117 | 27,196 | 33,898 | 11.7 | % | 204,231 | 15.3 | % | ||||||||||||||||
| Austin Chalk (Trend) | 7,530 | 5,387 | 50,567 | 17.4 | % | 305,185 | 22.9 | % | ||||||||||||||||
| Cotton Valley Reef Complex | - | 9,157 | 9,157 | 3.1 | % | 32,838 | 2.5 | % | ||||||||||||||||
| Other | 1,662 | 2,122 | 12,094 | 4.1 | % | 31,925 | 2.4 | % | ||||||||||||||||
| Total | 27,946 | 123,156 | 290,832 | 100.0 | % | $ | 1,331,110 | 100.0 | % | |||||||||||||||
| (a) | Includes natural gas liquids. |
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, 2007 were $91.30 per Bbl of oil and natural gas liquids and $7.37 per Mcf of gas, as compared to $57.18 per Bbl of oil and $5.24 per Mcf of gas as of December 31, 2006. We estimate that a $1
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per Bbl change in oil price and a $.50 per Mcf change in gas price from those utilized in calculating the present value of proved reserves would change the present value by approximately $13.6 million and $35.6 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, 2007, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.
Exploration and Development Activities
We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.
| Year Ended December 31, | ||||||||||||||||||||||||
| 2007 | 2006 | 2005 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| (Excludes wells in progress at the end of any period) | ||||||||||||||||||||||||
| Development Wells: | ||||||||||||||||||||||||
| Oil | 34 | 14.9 | 2 | 1.0 | 49 | 26.4 | ||||||||||||||||||
| Gas | 34 | 13.2 | 16 | 1.8 | 10 | 3.2 | ||||||||||||||||||
| Dry | - | - | 1 | .8 | 1 | .2 | ||||||||||||||||||
| Total | 68 | 28.1 | 19 | 3.6 | 60 | 29.8 | ||||||||||||||||||
| Exploratory Wells: | ||||||||||||||||||||||||
| Oil | - | - | 6 | 5.2 | 2 | 1.8 | ||||||||||||||||||
| Gas | 12 | 8.0 | 35 | 14.5 | 7 | 4.5 | ||||||||||||||||||
| Dry | 7 | 5.8 | 10 | 8.7 | 10 | 6.1 | ||||||||||||||||||
| Total | 19 | 13.8 | 51 | 28.4 | 19 | 12.4 | ||||||||||||||||||
| Total Wells: | ||||||||||||||||||||||||
| Oil | 34 | 14.9 | 8 | 6.2 | 51 | 28.2 | ||||||||||||||||||
| Gas | 46 | 21.2 | 51 | 16.3 | 17 | 7.7 | ||||||||||||||||||
| Dry | 7 | 5.8 | 11 | 9.5 | 11 | 6.3 | ||||||||||||||||||
| Total | 87 | 41.9 | 70 | 32.0 | 79 | 42.2 | ||||||||||||||||||
The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.
In 2006, we entered into a three-year drilling contract with Larclay JV, a joint venture between us and Lariat Services, Inc. described under “Business – Company Profile – Investments.” This contract assures us the availability of each of the 12 drilling rigs owned by Larclay JV, but also obligates us to pay an idle rig rate for each day that a completed rig is idle ranging from $8,100 per day to $10,300 per day (plus crew labor expenses, if applicable), depending on the size of the drilling rig. In 2008, we expect to use one of the 1,300 horsepower rigs in our North Louisiana Cotton Valley/Gray program, one in the Austin Chalk (Trend) and one in the Permian Basin. All other operational rigs are being used by an affiliate of Lariat Services, Inc.
In some cases, it is more advantageous for us to use a drilling contractor other than Larclay JV to drill our wells. None of the seven drilling rigs currently under contract, other than the Larclay JV rigs, are subject to long-term contracts.
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Productive Well Summary
The following table sets forth certain information regarding our ownership, as of December 31, 2007, of productive wells in the areas indicated.
| Oil | Gas | Total | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Permian Basin | 5,509 | 516.2 | 733 | 96.5 | 6,242 | 612.7 | ||||||||||||||||||
| North Louisiana | - | - | 51 | 17.9 | 51 | 17.9 | ||||||||||||||||||
| South Louisiana | 7 | 4.2 | 32 | 25.4 | 39 | 29.6 | ||||||||||||||||||
| Austin Chalk (Trend) | 293 | 224.8 | 17 | 9.3 | 310 | 234.1 | ||||||||||||||||||
| Cotton Valley | - | - | 14 | 11.6 | 14 | 11.6 | ||||||||||||||||||
| Other | 6 | 5.2 | 32 | 6.9 | 38 | 12.1 | ||||||||||||||||||
| Total | 5,815 | 750.4 | 879 | 167.6 | 6,694 | 918.0 | ||||||||||||||||||
Volumes, Prices and Production Costs
The following table sets forth certain information regarding the production volumes of, average sales prices received from, and average production costs associated with our sales of oil and gas for the periods indicated.
| Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| Oil and Gas Production Data: | ||||||||||||
| Gas (MMcf) | 20,649 | 15,198 | 16,408 | |||||||||
| Oil (MBbls) | 2,318 | 2,171 | 2,258 | |||||||||
| Natural gas liquids (MBbls) | 222 | 199 | 246 | |||||||||
| Total (MMcfe)�� | 35,889 | 29,418 | 31,432 | |||||||||
| Average Realized Prices (a): | ||||||||||||
| Gas ($/Mcf) | $ | 7.01 | $ | 6.68 | $ | 7.49 | ||||||
| Oil ($/Bbl) | $ | 70.36 | $ | 62.92 | $ | 53.37 | ||||||
| Natural gas liquids ($/Bbl) | $ | 43.74 | $ | 38.18 | $ | 33.57 | ||||||
| Average Production Costs | ||||||||||||
| Production ($/Mcfe) (b) | $ | 2.10 | $ | 2.15 | $ | 1.83 | ||||||
| (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.
| Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| (In thousands) | ||||||||||||
| Property Acquisitions: | ||||||||||||
| Proved | $ | - | $ | 6,432 | $ | 5,567 | ||||||
| Unproved | 15,746 | 54,437 | 50,238 | |||||||||
| Developmental Costs | 45,611 | 35,698 | 42,292 | |||||||||
| Exploratory Costs | 169,879 | 157,509 | 86,304 | |||||||||
| Total | $ | 231,236 | $ | 254,076 | $ | 184,401 | ||||||
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The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2007 in the areas indicated. This table excludes options to acquire leases and acreage in which our interest is limited to royalty, overriding royalty and similar interests.
| Developed | Undeveloped | Total | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Permian Basin | 84,296 | 46,099 | 341,162 | 150,781 | 425,458 | 196,880 | ||||||||||||||||||
| East Texas (a) | 110,545 | 107,442 | 135,668 | 95,997 | 246,213 | 203,439 | ||||||||||||||||||
| North Louisiana | 4,710 | 4,197 | 197,713 | 185,500 | 202,423 | 189,697 | ||||||||||||||||||
| South Louisiana | 8,865 | 7,001 | 24,310 | 22,542 | 33,175 | 29,543 | ||||||||||||||||||
| Other (b) | 11,924 | 4,147 | 567,589 | 329,268 | 579,513 | 333,415 | ||||||||||||||||||
| Total | 220,340 | 168,886 | 1,266,442 | 784,088 | 1,486,782 | 952,974 | ||||||||||||||||||
| (a) | Includes our acreage in the Austin Chalk (Trend), Cotton Valley and East Texas Bossier areas. |
| (b) | Net undeveloped acres are attributable to the following areas: Montana – 110,202; Mississippi – 80,070; Utah – 54,311; Alabama – 38,802; Colorado – 28,979; and other – 16,904. |
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. All of rigs, except for one of the 2,000 horsepower rigs, are fully constructed and are currently operating in Texas and Louisiana. In addition, we own two new 2,000 horsepower drilling rigs and related components that we are offering for sale.
We lease from a related partnership approximately 71,000 square feet of office space in Midland, Texas for our corporate headquarters. We also lease approximately 10,000 square feet of office space in Houston, Texas from unaffiliated third parties.
Item 3 - - Legal Proceedings
We are a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.
Item 4 - - 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 year ended December 31, 2007.
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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 12, 2008, there were approximately 1,732 beneficial stockholders as reflected in security position listings. The following table sets forth, for the periods indicated, the high and low sales prices for our Common Stock, as reported on the Nasdaq Global Market:
| High | Low | |||||||
| Year Ended December 31, 2007: | ||||||||
| Fourth Quarter | $ | 35.39 | $ | 27.12 | ||||
| Third Quarter | 34.54 | 21.33 | ||||||
| Second Quarter | 29.68 | 23.43 | ||||||
| First Quarter | 36.25 | 26.44 | ||||||
| Year Ended December 31, 2006: | ||||||||
| Fourth Quarter | $ | 43.87 | $ | 27.64 | ||||
| Third Quarter | 37.91 | 27.11 | ||||||
| Second Quarter | 43.50 | 33.97 | ||||||
| First Quarter | 55.33 | 37.12 | ||||||
The closing price of our common stock at March 12, 2008 was $38.61 per share.
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.
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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, 2007 was derived from our audited financial statements. The data set forth in this table should be read in conjunction with “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the accompanying consolidated financial statements, including the notes thereto.
| Year Ended December 31, | ||||||||||||||||||||
| 2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
| (In thousands, except per share) | ||||||||||||||||||||
| Statement of Operations Data: | ||||||||||||||||||||
Revenues: | ||||||||||||||||||||
Oil and gas sales | $ | 316,992 | $ | 245,967 | $ | 252,599 | $ | 193,127 | $ | 163,032 | ||||||||||
Natural gas services | 10,230 | 11,327 | 12,080 | 9,083 | 8,758 | |||||||||||||||
Drilling rig services | 52,649 | 6,937 | - | - | - | |||||||||||||||
Gain on sales of property and equipment | 14,024 | 1,767 | 18,920 | 4,120 | 267 | |||||||||||||||
Total revenues | 393,895 | 265,998 | 283,599 | 206,330 | 172,057 | |||||||||||||||
Costs and expenses: | ||||||||||||||||||||
Production | 75,319 | 63,298 | 57,404 | 41,163 | 28,239 | |||||||||||||||
Exploration: | ||||||||||||||||||||
Abandonment and impairments | 68,870 | 65,173 | 39,957 | 67,956 | 35,120 | |||||||||||||||
Seismic and other | 4,765 | 11,299 | 10,780 | 7,124 | 8,755 | |||||||||||||||
Natural gas services | 9,745 | 10,005 | 11,212 | 8,538 | 8,279 | |||||||||||||||
Drilling rig services | 32,964 | 4,538 | - | - | - | |||||||||||||||
Depreciation, depletion and amortization | 84,476 | 66,163 | 47,509 | 44,040 | 40,284 | |||||||||||||||
Impairment of property and equipment | 12,137 | 21,848 | 18,266 | - | 170 | |||||||||||||||
Accretion of abandonment obligations | 2,508 | 1,653 | 1,158 | 1,044 | 651 | |||||||||||||||
General and administrative | 19,266 | 16,676 | 15,410 | 11,689 | 10,934 | |||||||||||||||
Loss on sales of property and equipment | 9,815 | 99 | 209 | 14,337 | 68 | |||||||||||||||
Other | - | - | 1,353 | - | - | |||||||||||||||
Total costs and expenses | 319,865 | 260,752 | 203,258 | 195,891 | 132,500 | |||||||||||||||
Operating income | 74,030 | 5,246 | 80,341 | 10,439 | 39,557 | |||||||||||||||
Other income (expense): | ||||||||||||||||||||
Interest expense | (32,118 | ) | (20,895 | ) | (14,498 | ) | (7,877 | ) | (3,138 | ) | ||||||||||
Gain (loss) on derivatives | (31,968 | ) | 37,340 | (70,059 | ) | (25,329 | ) | (1,593 | ) | |||||||||||
Other income (expense) | 5,355 | (1,339 | ) | 4,022 | 1,354 | (1,662 | ) | |||||||||||||
Total other income (expense) | (58,731 | ) | 15,106 | (80,535 | ) | (31,852 | ) | (6,393 | ) | |||||||||||
Income (loss) before income taxes | 15,299 | 20,352 | (194 | ) | (21,413 | ) | 33,164 | |||||||||||||
Income tax (expense) benefit | (5,497 | ) | (1,979 | ) | 451 | 7,385 | (10,515 | ) | ||||||||||||
Minority interest, net of tax | (3,812 | ) | (574 | ) | - | - | - | |||||||||||||
Income (loss) from continuing operations | 5,990 | 17,799 | 257 | (14,028 | ) | 22,649 | ||||||||||||||
Cumulative effect of accounting change, net of tax | - | - | - | - | 207 | |||||||||||||||
NET INCOME (LOSS) | $ | 5,990 | $ | 17,799 | $ | 257 | $ | (14,028 | ) | $ | 22,856 | |||||||||
Net income (loss) per common share: | ||||||||||||||||||||
Basic: | ||||||||||||||||||||
Income (loss) from continuing operations | $ | .53 | $ | 1.64 | $ | .02 | $ | (1.37 | ) | $ | 2.43 | |||||||||
Net income (loss) | $ | .53 | $ | 1.64 | $ | .02 | $ | (1.37 | ) | $ | 2.45 | |||||||||
Diluted: | ||||||||||||||||||||
Income (loss) from continuing operations | $ | .52 | $ | 1.58 | $ | .02 | $ | (1.37 | ) | $ | 2.38 | |||||||||
Net income (loss) | $ | .52 | $ | 1.58 | $ | .02 | $ | (1.37 | ) | $ | 2.40 | |||||||||
Weighted average common shares outstanding: | ||||||||||||||||||||
Basic | 11,337 | 10,885 | 10,804 | 10,213 | 9,329 | |||||||||||||||
Diluted | 11,494 | 11,244 | 11,241 | 10,213 | 9,509 | |||||||||||||||
| Other Data: | ||||||||||||||||||||
Net cash provided by operating activities | $ | 234,866 | $ | 145,990 | $ | 163,475 | $ | 126,980 | $ | 119,750 | ||||||||||
| December 31, | ||||||||||||||||||||
| 2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Balance Sheet Data: | ||||||||||||||||||||
Working capital (deficit) | $ | (76,388 | ) | $ | (23,068 | ) | $ | (35,812 | ) | $ | (27,566 | ) | $ | (13,119 | ) | |||||
Total assets | 861,096 | 795,433 | 587,335 | 462,235 | 224,433 | |||||||||||||||
Long-term debt | 430,175 | 413,876 | 235,700 | 177,519 | 53,295 | |||||||||||||||
Stockholders’ equity | 160,806 | 144,980 | 120,291 | 117,596 | 100,781 | |||||||||||||||
27
Item 7 - - Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.
We are an oil and natural gas exploration, development, acquisition, and production company. Our basic business model is to increase shareholder value by finding and developing oil and gas reserves through exploration and development activities, and selling the production from those reserves at a profit. To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment. From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.
We believe that the economic climate in the domestic oil and gas industry continues to be suitable for our business model. Oil prices are currently at near-record levels, and gas prices are well above historic averages. Although oil and gas prices are typically volatile and are subject to market fluctuations, 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, despite near-record oil prices and higher natural gas prices, in recent years we have experienced shrinking profit margins related to rising drilling and production costs. While profit margins still remain favorable, operating metrics per Mcfe, such as finding costs, production costs and depreciation, depletion and amortization (“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 97% of our 2007 production through extensions and discoveries in 2007, most of which were derived from drilling activities in North Louisiana, South Louisiana and the Permian Basin. 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, remained constant from 2006 to 2007. Approximately 81% of our planned activities for 2008 relate to developmental prospects that are not expected to materially reduce our reported DD&A per Mcfe.
Key Factors to Consider
The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2007 and the outlook for 2008.
| · | Our oil and gas production for 2007 was 22% higher on an Mcfe basis than in the comparable period in 2006 and 14% higher than 2005. |
| · | Exploration costs related to abandonments and impairments were $68.9 million for 2007, of which approximately $52.1 million related to unsuccessful well costs and $16.8 million related to impairment of unproved acreage. Most of the abandonment and impairment costs in 2007 related to prospects in North and South Louisiana. |
| · | We recorded a non-cash charge during 2007 of $12.1 million for impairments pursuant to Statement of Financial Accounting Standards No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets” (“SFAS 144”), of which $7.1 million related to the write-down of two 2,000 horsepower drilling rigs and related components, and $1.1 million for well service equipment to their estimated fair market value. The remaining $3.9 million impairment is related to producing properties in the Permian Basin. |
| · | We spent $230.7 million on exploration and development activities during fiscal 2007, of which approximately 51% was on exploratory prospects. We currently plan to spend approximately $256.5 million on exploration and development for fiscal 2008, with approximately 19% applied to exploratory activities. |
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| · | Our expenditures on exploration and development activities for the year ended 2007 exceeded cash flow from operating activities, excluding cash flow from our contract drilling segment, by approximately $13.1 million. We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition would be adversely affected by unsuccessful exploratory drilling results. |
| · | During 2007, we increased borrowings under our revolving credit facility by $25.8 million from $140 million at December 31, 2006 to $165.8 million at December 31, 2007 to partially finance our exploration and development activities. |
| · | At December 31, 2007, our capitalized unproved oil and gas properties totaled $115.9 million, of which approximately $75.4 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 recorded a $32 million net loss on derivatives during 2007. We recorded a $7.7 million realized loss on settled contracts and a $24.3 million loss for changes in mark-to-market valuations. Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations. |
| · | Our proved oil and gas reserves at December 31, 2007 were 290.8 Bcfe compared to 271.5 Bcfe at December 31, 2006. We added 34.9 Bcfe through extensions and discoveries, had upward net revisions of 20.9 Bcfe and had sales of minerals-in-place of .6 Bcfe. |
Proved Oil and Gas Reserves
The following table summarizes changes in our proved reserves during 2007 on a Bcfe basis.
| Bcfe | ||||
| Total proved reserves, December 31, 2006 | 271.5 | |||
| Extensions and discoveries | 34.9 | |||
| Sales of minerals-in-place | (.6 | ) | ||
| Revisions | 20.9 | |||
| Production | (35.9 | ) | ||
| Total proved reserves, December 31, 2007 | 290.8 | |||
During 2007, we replaced 154% of the 35.9 Bcfe that we produced in 2007, computed by dividing the sum of all net reserve changes, other than production, by 2007 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 changes during 2007.
Extensions and discoveries. Our extensions and discoveries during 2007 consist of proved reserves attributable directly to the drilling of discovery wells primarily in North Louisiana, South Louisiana and the Permian Basin. Of the 34.9 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 2008 through extensions and discoveries.
Revisions. Our proved reserves were 20.9 Bcfe higher due to revisions of previous estimates. Upward revisions of 23.9 Bcfe were attributable to the effects of higher product prices on the estimated quantities of proved reserves net downward revisions of approximately 3 Bcfe were attributable to well performance and consisted primarily of net downward adjustments in South Louisiana, offset by upward adjustments in the Permian Basin, Austin Chalk (Trend) and California.
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Supplemental Information
The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-K with data that is not readily available from those statements.
| As of or for the Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| Oil and Gas Production Data: | ||||||||||||
Gas (MMcf) | 20,649 | 15,198 | 16,408 | |||||||||
Oil (MBbls) | 2,318 | 2,171 | 2,258 | |||||||||
Natural gas liquids (MBbls) | 222 | 199 | 246 | |||||||||
Total (MMcfe) | 35,889 | 29,418 | 31,432 | |||||||||
| Average Realized Prices (a): | ||||||||||||
Gas ($/Mcf) | $ | 7.01 | $ | 6.68 | $ | 7.49 | ||||||
Oil ($/Bbl) | $ | 70.36 | $ | 62.92 | $ | 53.37 | ||||||
Natural gas liquids ($/Bbl) | $ | 43.74 | $ | 38.18 | $ | 33.57 | ||||||
| Gain (Losses) on Settled Derivative | ||||||||||||
| Contracts (a): | ||||||||||||
Gas: Net realized gain (loss) | $ | 12,229 | $ | (679 | ) | $ | (7,301 | ) | ||||
Per unit produced ($/Mcf) | $ | .59 | $ | (.04 | ) | $ | (.44 | ) | ||||
Oil: Net realized gain (loss) | $ | (20,086 | ) | $ | (19,886 | ) | $ | (21,976 | ) | |||
Per unit produced ($/Bbl) | $ | (8.67 | ) | $ | (9.16 | ) | $ | (9.73 | ) | |||
| Average Daily Production: | ||||||||||||
Gas (Mcf): | ||||||||||||
Permian Basin | 14,649 | 14,260 | 15,893 | |||||||||
North Louisiana | 8,096 | 988 | - | |||||||||
South Louisiana | 24,025 | 13,638 | 10,865 | |||||||||
Austin Chalk (Trend) | 2,220 | 2,504 | 2,435 | |||||||||
Cotton Valley Reef Complex | 7,133 | 9,735 | 15,155 | |||||||||
Other | 450 | 513 | 605 | |||||||||
Total | 56,573 | 41,638 | 44,953 | |||||||||
Oil (Bbls): | ||||||||||||
Permian Basin | 3,212 | 3,172 | 3,245 | |||||||||
North Louisiana | 182 | 12 | - | |||||||||
South Louisiana | 1,139 | 943 | 994 | |||||||||
Austin Chalk (Trend) | 1,737 | 1,770 | 1,892 | |||||||||
Other | 81 | 51 | 55 | |||||||||
Total | 6,351 | 5,948 | 6,186 | |||||||||
Natural Gas Liquids (Bbls): | ||||||||||||
Permian Basin | 198 | 226 | 255 | |||||||||
North Louisiana | 1 | - | - | |||||||||
South Louisiana | 141 | 44 | - | |||||||||
Austin Chalk (Trend) | 259 | 269 | 322 | |||||||||
Other | 9 | 6 | 97 | |||||||||
Total | 608 | 545 | 674 | |||||||||
| Total Proved Reserves: | ||||||||||||
Gas (MMcf) | 123,156 | 119,167 | 126,758 | |||||||||
Oil and natural gas liquids (MBbls) | 27,946 | 25,381 | 27,835 | |||||||||
Total gas equivalent (MMcfe) | 290,832 | 271,453 | 293,768 | |||||||||
Standardized measure of discounted | ||||||||||||
future net cash flows | $ | 925,969 | $ | 514,800 | $ | 753,712 | ||||||
(Continued)
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| As of or for the Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| Total Proved Reserves by Area: | ||||||||||||
Gas (MMcf): | ||||||||||||
Permian Basin | 65,248 | 64,620 | 79,466 | |||||||||
North Louisiana | 14,046 | 12 | - | |||||||||
South Louisiana | 27,196 | 34,250 | 20,883 | |||||||||
Austin Chalk (Trend) | 5,387 | 4,789 | 6,234 | |||||||||
Cotton Valley Reef Complex | 9,157 | 11,562 | 15,396 | |||||||||
Other | 2,122 | 3,934 | 4,779 | |||||||||
Total | 123,156 | 119,167 | 126,758 | |||||||||
Oil and Natural Gas Liquids (MBbls): | ||||||||||||
Permian Basin | 17,318 | 15,679 | 18,504 | |||||||||
North Louisiana �� | 319 | - | - | |||||||||
South Louisiana | 1,117 | 2,231 | 1,667 | |||||||||
Austin Chalk (Trend) | 7,530 | 6,469 | 7,467 | |||||||||
Other | 1,662 | 1,002 | 197 | |||||||||
Total | 27,946 | 25,381 | 27,835 | |||||||||
Total Gas Equivalent (MMcfe): | ||||||||||||
Permian Basin | 169,156 | 158,694 | 190,490 | |||||||||
North Louisiana | 15,960 | 1,360 | 167 | |||||||||
South Louisiana | 33,898 | 46,288 | 30,718 | |||||||||
Austin Chalk (Trend) | 50,567 | 43,603 | 51,036 | |||||||||
Cotton Valley Reef Complex | 9,157 | 11,562 | 15,396 | |||||||||
Other | 12,094 | 9,946 | 5,961 | |||||||||
Total | 290,832 | 271,453 | 293,768 | |||||||||
| Exploration Costs (in thousands): | ||||||||||||
Abandonment and impairment costs: | ||||||||||||
South Louisiana | $ | 28,805 | $ | 33,695 | $ | 12,405 | ||||||
North Louisiana | 30,356 | 9,235 | - | |||||||||
Montana | 9 | 6,462 | - | |||||||||
Permian Basin | 1,322 | 5,638 | 7,411 | |||||||||
Utah | 4,062 | - | - | |||||||||
Mississippi | 1,148 | 328 | 4,306 | |||||||||
Colorado | 24 | 9,675 | - | |||||||||
Other (b) | 3,144 | 140 | 15,835 | |||||||||
Total | 68,870 | 65,173 | 39,957 | |||||||||
Seismic and other | 4,765 | 11,299 | 10,780 | |||||||||
Total exploration costs | $ | 73,635 | $ | 76,472 | $ | 50,737 | ||||||
| Oil and Gas Costs ($/Mcfe Produced): | ||||||||||||
Production | $ | 2.10 | $ | 2.15 | $ | 1.83 | ||||||
DD&A | $ | 2.12 | $ | 2.12 | $ | 1.42 | ||||||
| Net Wells Drilled (c): | ||||||||||||
Exploratory wells | 13.8 | 28.4 | 12.4 | |||||||||
Developmental wells | 28.1 | 3.6 | 29.8 | |||||||||
(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 an $8 million charge in South Texas for the Deer-Hamilton #1 in 2005. | ||||||||||||
(c) Excludes wells being drilled or completed at the end of each period. | ||||||||||||
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Operating Results
2007 Compared to 2006
The following discussion compares our results for the year ended December 31, 2007 to the year ended December 31, 2006. Unless otherwise indicated, references to 2007 and 2006 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales in 2007 increased $71 million, or 29%, from 2006, of which production variances accounted for a $45.6 million increase and price variances accounted for a $25.4 million increase. Production in 2007 (on an Mcfe basis) was 22% higher than 2006. Oil production increased 7% and gas production increased 36% in 2007 as compared to 2006 due primarily to production attributable to recent drilling activities in North and South Louisiana. In 2007, our realized oil price was 12% higher than 2006, while our realized gas price was 5% 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 19% in 2007 as compared to 2006 due to a combination of factors including increased oil and gas production, rising oilfield service costs, and higher repair and maintenance costs. After giving effect to a 22% increase in oil and gas production on an Mcfe basis, production costs per Mcfe decreased 2% from $2.15 per Mcfe in 2006 to $2.10 per Mcfe in 2007. It is likely that these factors will continue to contribute to higher production costs in future periods.
DD&A expense increased 28% from $66.2 million in 2006 to $84.5 million in 2007. DD&A expense attributable to oil and gas properties increased $13.6 million, primarily due to production increases. On an Mcfe basis, oil and gas depletion expense remained constant at $2.12 per Mcfe in 2006 and 2007. 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.
We recorded a provision for impairment of property and equipment under SFAS 144 of $12.1 million during 2007, of which $7.1 million related to write-downs of two 2,000 horsepower drilling rigs and related components and $1.1 million charge for well service equipment to reduce the carrying value to their estimated fair market value. The remaining $3.9 million impairment related to producing properties in the Permian Basin. We recorded a provision for impairment of proved properties of $21.8 million in 2006. We have capitalized $26.3 million of drilling and completion costs associated with two wells in our East Texas Bossier area that were in progress at December 31, 2007 and were completed as marginal producers during the first quarter of 2008. We have not assigned any proved reserves to these wells since we do not have sufficient production history to permit us to make a reasonable estimate at this time. However, it appears to be unlikely that we will recover our capitalized drilling and completion costs on these wells through future production from only these wells. Depending on our evaluations of these wells and the results of future drilling activities in our East Texas Bossier play, we may record impairments of proved properties related to these wells in future periods.
Gain on property sales
Gain on sales of property and equipment for 2007 was $14 million compared to $1.8 million in 2006. In 2007, we sold all of our producing and non-producing acreage in Pecos County, Texas for $21 million, net of closing costs, and recorded a gain of approximately $12.5 million in connection with this sale.
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 2007, we charged to expense $73.6 million of exploration costs, as compared to $76.5 million in 2006. Most of the 2007 costs were incurred in Louisiana.
At December 31, 2007, our capitalized unproved oil and gas properties totaled $115.9 million, of which approximately $75.4 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 $256.5 million on exploration and development activities in 2008, of which approximately 19% is expected to be allocated to exploration activities. Since exploratory drilling involves a high
32
degree of risk, it is likely that a significant portion of the costs we incur in 2008 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 (“Larclay JV”) with Lariat Services, Inc. to construct, own, and operate 12 new drilling rigs. We own a 50% interest in Larclay JV. 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. During the year ended December 31, 2007, we included contract drilling revenues of $52.6 million, other operating expenses of $30.9 million, depreciation expense and impairment of property and equipment of $14.3 million and interest expense of $4.3 million in our statement of operations (see Note 18 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 expenses
General and administrative (“G&A”) expenses increased 16% from $16.7 million in 2006 to $19.3 million in 2007. Excluding non-cash employee compensation, G&A expenses increased from $14 million in 2006 to $17.4 million in 2007 due primarily to higher professional fees and personnel costs. In 2007, we recorded a $1.8 million non-cash compensation charge related to our after payout incentive plan and $110,000 for stock-based employee compensation. In 2006, we recorded a $2.5 million non-cash charge related to our after payout incentive plan and a $128,000 non-cash charge for stock-based employee compensation.
Interest expense
Interest expense increased 54% from $20.9 million in 2006 to $32.1 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 $176.5 million compared to $89 million for 2006. Capitalized interest for 2007 was $4.2 million compared to $5.8 million in 2006. We also included $4.3 million of interest expense associated with our Larclay JV during 2007 compared to $668,000 in 2006.
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 2007, we reported a $32 million net loss on derivatives, consisting of an $24.3 million non-cash loss to mark our derivative positions to their fair value at December 31, 2007 and a $7.7 million realized loss on settled contracts. For 2006, we recorded a net gain on derivatives of $37.3 million, consisting of a $57.5 million non-cash gain related to changes in mark-to-market valuations and a $20.2 million realized loss on settled contracts.
Other
Loss on sale of assets for 2007 was $9.8 million compared to $99,000 for 2006. The 2007 charge was due to recording losses on inventory which included a charge of $8.9 million to write-down inventory to its estimated market value at March 31, 2007. The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007. Other income/expense for 2007 was income of $5.4 million compared to expense of $1.3 million for the 2006 period. The 2007 period included a $2.9 million gain on settlement of litigation. No lawsuit settlements or write-downs of inventory were recorded during the 2006 period.
Income tax expense (benefit)
Our effective income tax rate in 2007 of 35.9% 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.
33
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.
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.
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.
34
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.
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 on advances under the revolving credit facility to finance a portion of our exploration and development activities in 2007. At December 31, 2007, we had $165.8 million outstanding on the revolving credit facility.
Our 2007 expenditures on exploration and development activities exceeded cash flow from operating activities, excluding cash flow from our contract drilling segment, by approximately $13.1 million. Our 2008 expenditures may also exceed our cash flow from operating activities in 2008. 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.
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Capital expenditures
The following table summarizes, by area, our planned expenditures for exploration and development activities during 2008, as compared to our actual expenditures in 2007.
| Actual | Planned | |||||||||||
| Expenditures | Expenditures | 2008 | ||||||||||
| Year Ended | Year Ended | Percentage | ||||||||||
| December 31, 2007 | December 31, 2008 | of Total | ||||||||||
| (In thousands) | ||||||||||||
| North Louisiana | $ | 74,300 | $ | 47,900 | 19 | % | ||||||
| South Louisiana | 65,700 | 13,400 | 5 | % | ||||||||
| Permian Basin | 34,200 | 110,300 | 43 | % | ||||||||
| East Texas Bossier | 31,500 | 17,200 | 7 | % | ||||||||
| Austin Chalk (Trend) | 19,200 | 59,300 | 23 | % | ||||||||
| Utah/California | 5,300 | 8,300 | 3 | % | ||||||||
| Other | 500 | 100 | - | % | ||||||||
| $ | 230,700 | $ | 256,500 | 100 | % | |||||||
Our actual expenditures during fiscal 2008 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 2008.
Approximately 19% of the 2008 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 $230.7 million on exploration and development activities during 2007, of which approximately 51% was on exploratory prospects. We currently plan to spend approximately $256.5 million for the calendar year 2008, of which approximately 19% is estimated to be spent on exploratory prospects. The 2007 expenditures exceeded our cash flow from operating activities for the same period, excluding cash flows from our contract drilling segment, by approximately $13.1 million. Our 2008 expenditures may also exceed our cash flow from operating activities in 2008. To the extent possible, 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 2008. 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. In the event we lack adequate liquidity to finance our expenditures in 2008, we will consider options for alternative capital resources, including the sale of assets.
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, 2007 increased $88.9 million, or 61%, as compared to the corresponding period in 2006. Approximately $15.1 million of the increase in operating cash flow was attributable to Larclay JV. All of Larclay JV’s cash flow is dedicated to the repayment of a $75 million secured term loan facility (see “-Secured Term Loan of Larclay JV”). The remainder of the increase in operating cash flow was derived primarily from oil and gas producing activities, offset in part by increased interest expense on higher levels of indebtedness.
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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.
During 2007, we borrowed $25.8 million on the revolving credit facility to finance the excess of our exploration and development expenditures over cash flow from operating activities. At December 31, 2007, we had a borrowing base of $275 million, leaving $108.4 million available under the revolving loan facility after accounting for outstanding letters of credit.
Using the revolving credit facility for both our short-term liquidity and long-term financing needs can cause unusual fluctuations in our reported working capital, depending on the timing of cash receipts and expenditures. On a daily basis, we use most of our available cash to pay down our outstanding balance on the revolving credit facility, which is classified as a non-current liability since we currently have no required principal reductions. As we use cash to pay a non-current liability, our reported working capital decreases. Conversely, as we draw on the revolving credit facility for funds to pay current liabilities (such as payables for drilling and operating costs), our reported working capital increases. Also, volatility in oil and gas prices can cause significant fluctuations in reported working capital as we record changes in the fair value of derivatives from period to period. For these reasons, the working capital covenant related to the revolving credit facility requires us to (i) include the amount of funds available under this facility as a current asset, (ii) exclude current assets and liabilities related to the fair value of derivatives, and (iii) exclude current maturities of vendor finance obligations, if any, when computing the working capital ratio at any balance sheet date.
Working capital computed for loan compliance purposes differs from our working capital in accordance with generally accepted accounting principles (GAAP). Since compliance with financial covenants is a material requirement under the credit facilities, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of derivatives. Our reported working capital deficit increased from $23.1 million at December 31, 2006 to $76.4 million at December 31, 2007 due primarily to a combination of factors, including decreases in inventory and an increase in the net liability for the fair value for derivatives. After giving effect to the adjustments, our working capital computed for loan compliance purposes was a positive $103.2 million at December 31, 2007, as compared to a positive $36.9 million at December 31, 2006. The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2007 and December 31, 2006.
| December 31, | ||||||||
| 2007 | 2006 | |||||||
| (In thousands) | ||||||||
| Working capital (deficit) per GAAP | $ | (76,388 | ) | $ | (23,068 | ) | ||
| Add funds available under the revolving credit facility | 108,396 | 40,196 | ||||||
| Exclude fair value of derivatives classified as current assets or current liabilities | 49,738 | 5,993 | ||||||
| Exclude current assets and current liabilities of Larclay JV | 21,423 | 13,759 | ||||||
| Working capital per loan covenant | $ | 103,169 | $ | 36,880 | ||||
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, 2007, 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 2007 borrowing base review resulted in maintaining the borrowing base at $275 million. If
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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 2007.
7¾% Senior Notes due 2013
In July 2005, we issued, in a private placement, $225 million of aggregate principal amount of Senior Notes. The Senior Notes were issued at face value and bear interest at 7¾% per year, payable semi-annually on February 1 and August 1 of each year, beginning February 1, 2006. 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, 2007.
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, 2007 by payment due date.
Payments Due by Period | ||||||||||||||||||||
Total | 2008 | 2009 to 2010 | 2011 to 2012 | 2013 and Thereafter | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Contractual obligations: | ||||||||||||||||||||
| 7¾% Senior Notes (a) | $ | 225,000 | $ | - | $ | - | $ | - | $ | 225,000 | ||||||||||
| Secured bank credit facility (a) | 165,800 | - | 165,800 | - | - | |||||||||||||||
| Drilling contracts with Larclay JV | 78,146 | 37,997 | 40,149 | - | - | |||||||||||||||
| Larclay JV note | 61,875 | 22,500 | 33,750 | 5,625 | - | |||||||||||||||
| Purchase commitments (seismic) | 4,308 | 4,308 | - | - | - | |||||||||||||||
| Lease obligations | 5,157 | 1,642 | 2,523 | 992 | - | |||||||||||||||
| Total contractual obligations | $ | 540,286 | $ | 66,447 | $ | 242,222 | $ | 6,617 | $ | 225,000 | ||||||||||
| (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 $12.2 million on the secured bank credit facility (based on the balances and interest rates at December 31, 2007). |
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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, 2007, would mature as follows: 2008- $49.7 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. Prior to 2007 our production had been on a gradual decline since 2003 due to the effects of natural production decline, offset in part by reserve additions through exploration and development and acquisitions. In 2007, our production increased to 35.9 Bcfe from 29.4 Bcfe in 2006, and we replaced 97% of our 2007 oil and gas production through our drilling program. Production from these discoveries should contribute favorably to production in 2008, 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 2008. While we cannot predict the results of our exploration and development activities, we believe that oil and gas production levels in 2008 will be comparable to those in 2007.
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 $8.04 per Mcfe in 2005, $8.36 per Mcfe in 2006 and $8.83 per Mcfe in 2007. 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 have also been on an upward trend and are resulting in a narrowing profit margin. Our oil and gas DD&A per Mcfe has increased from $1.42 per Mcfe in 2005, to $2.12 per Mcfe in 2006 and in 2007. 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 97% of our production in 2007, 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 fluctuated from $1.83 per Mcfe in 2005, to $2.15 per Mcfe in 2006, to $2.10 per Mcfe in 2007. The fluctuation in production costs per Mcfe is a result of a combination of factors. Most of the increase in 2005 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.
| Accounting Policies | Estimates or Assumptions | Accounts Affected | ||
| Successful efforts accounting | ·Reserve estimates | ·Oil and gas properties | ||
for oil and gas properties | ·Valuation of unproved | ·Accumulated DD&A | ||
| properties | ·Provision for DD&A | |||
·Judgment regarding status of in progress exploratory wells | ·Impairment of unproved properties | |||
·Abandonment costs | ||||
(dry hole costs) |
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| Impairment of proved | ·Reserve estimates and related | ·Oil and gas properties | ||
properties | present value of future net | ·Accumulated DD&A | ||
revenues | ·Impairment of proved properties | |||
| Asset retirement obligations | ·Estimates of the present value | ·Abandonment obligations | ||
of future abandonment costs | (non-current liability) | |||
·Oil and gas properties | ||||
·Accretion of discount | ||||
expense |
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.
| Type of Reserves | �� | Nature of Available Data | Degree of Accuracy | |
| Proved undeveloped | Data from offsetting wells, seismic data | Least accurate | ||
| Proved developed non-producing | Logs, core samples, well tests, pressure data | More accurate | ||
| Proved developed producing | Production history, pressure data over time | Most accurate |
Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable reserves exceed the projected revenues from the reserves). But more significantly, the standardized measure of discounted future net cash flows is extremely sensitive to prices and costs, and may vary materially based on different assumptions. 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.
| Standardized | ||||||||||||||||||||
| Measure | ||||||||||||||||||||
| Proved Reserves | Average Price | of Discounted | ||||||||||||||||||
| Oil (a) | Gas | Oil (a) | Gas | Future | ||||||||||||||||
| (MMBbls) | (Bcf) | ($/Bbl) | ($/Mcf) | Net Cash Flows | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| As of December 31: | ||||||||||||||||||||
| 2007 | 27.9 | 123.2 | $ | 91.30 | $ | 7.37 | $ | 926.0 | ||||||||||||
| 2006 | 25.4 | 119.2 | $ | 57.18 | $ | 5.24 | $ | 514.8 | ||||||||||||
| 2005 | 27.8 | 126.8 | $ | 57.85 | $ | 10.65 | $ | 753.7 | ||||||||||||
(a) Includes natural gas liquids
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Valuation of unproved properties
Placing a fair market value on unproved properties (also known as prospects) is very subjective since there is no quoted market for undeveloped exploratory prospects. The negotiated price of any prospect between a willing seller and willing buyer depends on the specific facts regarding the prospect, including:
| · | The location of the prospect in relation to known fields and reservoirs, available markets and transportation systems for oil and gas production in the vicinity, and other critical services; |
| · | The nature and extent of geological and geophysical data on the prospect; |
| · | The terms of the leases holding the acreage in the prospect, such as ownership interests, expiration terms, delay rental obligations, depth limitations, drilling and marketing restrictions, and similar terms; |
| · | The prospect’s risk-adjusted potential for return on investment, giving effect to such factors as potential reserves to be discovered, drilling and completion costs, prevailing commodity prices, and other economic factors; and |
| · | The results of drilling activity in close proximity to the prospect that could either enhance or condemn the prospect’s chances of success. |
Asset Retirement Obligations
We are required by SFAS 143 “Accounting for Asset Retirement Obligations” to estimate the present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We compute our liability for asset retirement obligations by calculating the present value of estimated future cash flows related to each property. This requires us to use significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations.
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
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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 2007, we revised our estimated asset retirement obligations by $1.4 million based on a review of current plugging and abandonment costs. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion expense. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Recent Accounting Pronouncements
In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS 141R, “Business Combinations” (“SFAS 141R”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008. SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests, including any that arose before the effective date except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests, and provide other disclosures required by SFAS 160. The impact to us from adoption of SFAS 141R in 2009 will depend on future acquisition activity.
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In February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (“SFAS 159”). SFAS 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. Unrealized gains and losses on items for which the fair value option has been elected are to be recognized in earnings at each subsequent reporting date. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The effect of adopting SFAS 159 is not expected to have a significant effect on our consolidated financial position or results of operations.
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” (“SFAS 157”), which will become effective for financial assets and liabilities of the company on January 1, 2008 and non-financial assets and liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the company from the adoption of SFAS 157 in 2009 will depend on the company’s assets and liabilities at that time that are required to be measured at fair value.
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, 2007 reserve estimates, we project that a $1 drop in the price per Bbl of oil and a $.50 drop in the price per Mcf of gas from year end 2007 would reduce our gross revenues for the year ending December 31, 2008 by $12.4 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
43
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, 2007. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Collars:
| Gas | Oil | |||||||||||||||||||||||
MMBtu (a) | Floor | Ceiling | Bbls | Floor | Ceiling | |||||||||||||||||||
| Production Period: | ||||||||||||||||||||||||
1st Quarter 2008 | 434,000 | $ | 4.00 | $ | 5.15 | 132,000 | $ | 23.00 | $ | 25.07 | ||||||||||||||
2nd Quarter 2008 | 426,000 | $ | 4.00 | $ | 5.15 | 132,000 | $ | 23.00 | $ | 25.07 | ||||||||||||||
3rd Quarter 2008 | 419,000 | $ | 4.00 | $ | 5.15 | 128,000 | $ | 23.00 | $ | 25.07 | ||||||||||||||
| 1,279,000 | 392,000 | |||||||||||||||||||||||
Swaps:
| Gas | Oil | |||||||||||||||
MMBtu (a) | Price | Bbls | Price | |||||||||||||
| Production Period: | ||||||||||||||||
1st Quarter 2008 | 1,800,000 | $ | 8.26 | 380,000 | $ | 91.85 | ||||||||||
2nd Quarter 2008 | 4,650,000 | $ | 9.20 | 330,000 | $ | 79.84 | ||||||||||
3rd Quarter 2008 | 4,200,000 | $ | 9.15 | 310,000 | $ | 78.96 | ||||||||||
4th Quarter 2008 | 4,200,000 | $ | 9.15 | 400,000 | $ | 82.21 | ||||||||||
| 2009 | 3,600,000 | $ | 9.33 | 1,440,000 | $ | 85.30 | ||||||||||
| 18,450,000 | 2,860,000 | |||||||||||||||
(a) One MMBtu equals one Mcf at a Btu factor of 1,000.
We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of our commodity derivatives. A $1 per barrel change in the price of oil and a $.50 per MMBtu change in the price of gas would change the fair value of our outstanding commodity derivatives at December 31, 2007 by approximately $4.7 million.
We are exposed to interest rate risk on our long-term debt with a variable interest rate. At December 31, 2007, our variable rate debt had a carrying value of $165.8 million, which approximated its fair value. At December 31, 2007, our fixed rate debt had a carrying value of $225 million and an approximate fair value of $196.9 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 $8.3 million.
We are a party to two interest rate swaps. Under these derivatives, we pay a fixed rate for the notional principal balances and receive a floating market rate based on LIBOR. The interest rate swaps are settled quarterly. The following summarizes information concerning our net positions in open interest rate swaps applicable to periods subsequent to December 31, 2007.
Interest Rate Swaps:
Principal | Fixed Libor | |||||||
| Balance | Rates | |||||||
| Period: | ||||||||
January 1, 2008 to September 24, 2008 | $ | 100,000,000 | 4.73 | % | ||||
January 1, 2008 to November 3, 2008 | $ | 45,000,000 | 5.73 | % | ||||
The interest rate swaps in the preceding table expose us to market risks for decreases in interest rates during the periods shown.
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Item 8 - Financial Statements and Supplementary Data
For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements included elsewhere in this Form 10-K.
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A - - Controls and Procedures
Disclosure Controls and Procedures
In September 2002, our Board of Directors adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that our management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the SEC and other communications with our stockholders. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.
With respect to our disclosure controls and procedures:
| · | 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.
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Changes in Internal Control Over Financial Reporting
No changes in internal control over financial reporting were made during the quarter ended December 31, 2007 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, 2007. 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, 2007, our internal control over financial reporting is effective based on those criteria.
KPMG LLP has issued an audit report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007, the contents of which are shown below.
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Clayton Williams Energy, Inc.:
We have audited Clayton Williams Energy, Inc.’s (Company) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission..
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2007 and 2006, 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, 2007, and our report dated March 14, 2008 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Dallas, Texas
March 14, 2008
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Item 9B - - Other Information
None.
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, 2008.
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, 2008.
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, 2008.
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, 2008.
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, 2008.
Item 15 - - Exhibits and Financial Statement Schedules
Financial Statements and Schedules
For a list of the consolidated financial statements and financial statement schedules filed as part of this Form 10-K, see the Index to Consolidated Financial Statements on page F-1.
The following exhibits are filed as a part of this Report, with each exhibit that consists of or includes a management contract or compensatory plan or arrangement being identified with a “†”:
| Exhibit | |||
| Number | Description of Exhibit | ||
| **2.1 | Agreement and Plan of Merger among Clayton Williams Energy, Inc. and Southwest Royalties, Inc. dated May 3, 2004, filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K filed with the Commission on June 3, 2004†† | ||
| **3.1 | Second Restated Certificate of Incorporation of the Company, filed as Exhibit 3.1 to the Company’s Form S-2 Registration Statement, Commission File No. 333-13441 |
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| **3.2 | Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as Exhibit 3.1 to the Company’s Form 10-Q for the period ended September 30, 2000†† | ||
| **3.3 | Corporate Bylaws of Clayton Williams Energy, Inc., as amended, filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 13, 2008†† | ||
| **4.1 | Stock Purchase Agreement dated May 19, 2004 by and among Clayton Williams Energy, Inc. and various institutional investors, filed as Exhibit 4 to the Company’s Current Report on Form 8-K filed with the Commission on June 2, 2004†† | ||
| **4.2 | Indenture, dated July 20, 2005, among Clayton Williams Energy, Inc., the Subsidiary Guarantors and Wells Fargo Bank, National Association, as Trustee, filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 22, 2005†† | ||
| **10.1 | Amended and Restated Credit Agreement dated as of May 21, 2004 among Clayton Williams Energy, Inc., et al, and Bank One, NA, et al, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed with the Commission on June 23, 2004†† | ||
| **10.2 | First Amendment to Amended and Restated Credit Agreement dated July 18, 2005, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 20, 2005†† | ||
| **10.3 | Second Amendment to Amended and Restated Credit Agreement dated December 30, 2005, filed as Exhibit 10.3 to the Company’s Form 10-K for the period ended December 31, 2005†† | ||
| **10.4 | Third Amendment to Amended and Restated Credit Agreement dated June 30, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on July 14, 2006†† | ||
| **10.5 | 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 | ||
49
| **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†† | ||
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| **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†† | ||
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| **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 March 21, 2007, issued in favor of Merrill Lynch Capital, as agent, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 27, 2007†† | ||
| **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 | Second Amendment to Term Loan and Security Agreement and Amendment to Limited Guaranty dated as of March 15, 2007 among Larclay, L.P., Clayton Williams Energy, Inc., Merrill Lynch Capital, as agent, and the other signatories thereto, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on March 27, 2007†† | ||
**10.44† | 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†† | ||
| **10.45† | 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†† | ||
| **10.46† | 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†† | ||
| **10.47† | 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†† | ||
| **10.48† | 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†† | ||
| **10.49† | 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†† | ||
| **10.50† | 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†† | ||
| **10.51† | 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†† |
52
| **10.52† | 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†† | ||
| **10.53† | Form of Notice of Bonus Award Under the Southwest Royalties Reward Plan, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on January 18, 2007†† | ||
| **10.54† | Participation Agreement relating to West Coast Energy Properties, L.P. dated December 11, 2006, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 14, 2006†† | ||
| **10.55† | Participation Agreement relating to RMS/Warnick dated April 10, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on April 13, 2007†† | ||
| **10.56† | Participation Agreement relating to East Texas Bossier – Big Bill Simpson dated December 17, 2007, filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2007†† | ||
| **10.57† | Participation Agreement relating to East Texas Bossier – Margarita dated December 17, 2007, filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2007†† | ||
| *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 | |||
| ***Furnished herewith | |||
| †Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement. | |||
| ††Filed under the Company’s Commission File No. 001-10924. | |||
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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.
54
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 non-producing 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 non-producing 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.
55
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.
56
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| CLAYTON WILLIAMS ENERGY, INC. | |
| (Registrant) | |
| By: | /s/ CLAYTON W. WILLIAMS * |
| Clayton W. Williams | |
| Chairman of the Board, President | |
| and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | ||
| /s/ CLAYTON W. WILLIAMS * | Chairman of the Board, | March 14, 2008 | ||
| Clayton W. Williams | President and Chief Executive | |||
| Officer and Director | ||||
| /s/ L. PAUL LATHAM | Executive Vice President, | March 14, 2008 | ||
| L. Paul Latham | Chief Operating Officer and | |||
| Director | ||||
| /s/ MEL G. RIGGS | Senior Vice President - | March 14, 2008 | ||
| Mel G. Riggs | Finance, Secretary, Treasurer, | |||
| Chief Financial Officer and Director | ||||
| /s/ MICHAEL L. POLLARD | Vice President – Accounting and | March 14, 2008 | ||
| Michael L. Pollard | Principal Accounting Officer | |||
| /s/ STANLEY S. BEARD * | Director | March 14, 2008 | ||
| Stanley S. Beard | ||||
| /s/ DAVIS L. FORD * | Director | March 14, 2008 | ||
| Davis L. Ford | ||||
| /s/ ROBERT L. PARKER * | Director | March 14, 2008 | ||
| Robert L. Parker | ||||
| /s/ JORDAN R. SMITH * | Director | March 14, 2008 | ||
| Jordan R. Smith | ||||
| * By: /s/ L. PAUL LATHAM | ||||
| L. Paul Latham | ||||
| Attorney-in-Fact |
57
CLAYTON WILLIAMS ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
| Page | ||
| F-2 | ||
| F-3 | ||
| F-5 | ||
| F-6 | ||
| F-7 | ||
| F-8 | ||
Financial Statement Schedule | S-1 |
F-1
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Clayton Williams Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2007 and 2006, 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, 2007. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, 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” and effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Clayton Williams Energy, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2008, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 14, 2008
F-2
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
| ASSETS | ||||||||
| December 31, | ||||||||
| 2007 | 2006 | |||||||
| CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 12,344 | $ | 13,840 | ||||
Accounts receivable: | ||||||||
Oil and gas sales | 36,698 | 23,398 | ||||||
Joint interest and other, net | 16,666 | 17,810 | ||||||
Affiliates | 308 | 2,436 | ||||||
Inventory | 14,348 | 40,392 | ||||||
Deferred income taxes | 3,581 | 505 | ||||||
Fair value of derivatives | 7,191 | 23,729 | ||||||
Assets held for sale | 17,281 | - | ||||||
Prepaids and other | 3,962 | 3,888 | ||||||
| 112,379 | 125,998 | |||||||
| PROPERTY AND EQUIPMENT | ||||||||
Oil and gas properties, successful efforts method | 1,374,090 | 1,226,761 | ||||||
Natural gas gathering and processing systems | 18,404 | 18,068 | ||||||
Contract drilling equipment | 89,956 | 66,418 | ||||||
Other | 14,505 | 15,848 | ||||||
| 1,496,955 | 1,327,095 | |||||||
Less accumulated depreciation, depletion and amortization | (765,877 | ) | (682,286 | ) | ||||
Property and equipment, net | 731,078 | 644,809 | ||||||
| OTHER ASSETS | ||||||||
Debt issue costs, net | 6,963 | 8,104 | ||||||
Fair value of derivatives | - | 1,785 | ||||||
Other | 10,676 | 14,737 | ||||||
| 17,639 | 24,626 | |||||||
| $ | 861,096 | $ | 795,433 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-3
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
| LIABILITIES AND STOCKHOLDERS' EQUITY | ||||||||
| December 31, | ||||||||
| 2007 | 2006 | |||||||
| CURRENT LIABILITIES | ||||||||
Accounts payable: | ||||||||
Trade | $ | 72,477 | $ | 75,815 | ||||
Oil and gas sales | 24,806 | 14,222 | ||||||
Affiliates | 1,747 | 1,407 | ||||||
Current maturities of long-term debt | 22,500 | 17,397 | ||||||
Fair value of derivatives | 56,929 | 29,722 | ||||||
Accrued liabilities and other | 10,308 | 10,503 | ||||||
| 188,767 | 149,066 | |||||||
| NON-CURRENT LIABILITIES | ||||||||
Long-term debt | 430,175 | 413,876 | ||||||
Deferred income taxes | 44,302 | 36,409 | ||||||
Fair value of derivatives | - | 21,281 | ||||||
Other | 37,046 | 29,821 | ||||||
| 511,523 | 501,387 | |||||||
| COMMITMENTS AND CONTINGENCIES | ||||||||
| STOCKHOLDERS’ EQUITY | ||||||||
Preferred stock, par value $.10 per share, authorized – 3,000,000 | ||||||||
shares; none issued | - | - | ||||||
Common stock, par value $.10 per share, authorized – 30,000,000 | ||||||||
shares; issued and outstanding – 11,354,051 shares in 2007 | ||||||||
and 11,152,051 shares in 2006 | 1,135 | 1,115 | ||||||
Additional paid-in capital | 121,063 | 113,965 | ||||||
Retained earnings | 35,890 | 29,900 | ||||||
Accumulated other comprehensive income, net of tax | 2,718 | - | ||||||
| 160,806 | 144,980 | |||||||
| $ | 861,096 | $ | 795,433 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share)
| Year Ended December 31, | ||||||||||||
| 2007 | 2006 | 2005 | ||||||||||
| REVENUES | ||||||||||||
Oil and gas sales | $ | 316,992 | $ | 245,967 | $ | 252,599 | ||||||
Natural gas services | 10,230 | 11,327 | 12,080 | |||||||||
Drilling rig services | 52,649 | 6,937 | - | |||||||||
Gain on sales of property and equipment | 14,024 | 1,767 | 18,920 | |||||||||
Total revenues | 393,895 | 265,998 | 283,599 | |||||||||
| COSTS AND EXPENSES | ||||||||||||
Production | 75,319 | 63,298 | 57,404 | |||||||||
Exploration: | ||||||||||||
Abandonments and impairments | 68,870 | 65,173 | 39,957 | |||||||||
Seismic and other | 4,765 | 11,299 | 10,780 | |||||||||
Natural gas services | 9,745 | 10,005 | 11,212 | |||||||||
Drilling rig services | 32,964 | 4,538 | - | |||||||||
Depreciation, depletion and amortization | 84,476 | 66,163 | 47,509 | |||||||||
Impairment of property and equipment | 12,137 | 21,848 | 18,266 | |||||||||
Accretion of abandonment obligations | 2,508 | 1,653 | 1,158 | |||||||||
General and administrative | 19,266 | 16,676 | 15,410 | |||||||||
Loss on sales of property and equipment | 9,815 | 99 | 209 | |||||||||
Other | - | - | 1,353 | |||||||||
Total costs and expenses | 319,865 | 260,752 | 203,258 | |||||||||
Operating income | 74,030 | 5,246 | 80,341 | |||||||||
| OTHER INCOME (EXPENSE) | ||||||||||||
Interest expense | (32,118 | ) | (20,895 | ) | (14,498 | ) | ||||||
Gain (loss) on derivatives | (31,968 | ) | 37,340 | (70,059 | ) | |||||||
Other | 5,355 | (1,339 | ) | 4,022 | ||||||||
Total other income (expense) | (58,731 | ) | 15,106 | (80,535 | ) | |||||||
| Income (loss) before income taxes and minority interest | 15,299 | 20,352 | (194 | ) | ||||||||
| Income tax (expense) benefit | (5,497 | ) | (1,979 | ) | 451 | |||||||
| Minority interest, net of tax | (3,812 | ) | (574 | ) | - | |||||||
| NET INCOME | $ | 5,990 | $ | 17,799 | $ | 257 | ||||||
| Net income per common share: | ||||||||||||
Basic | $ | .53 | $ | 1.64 | $ | .02 | ||||||
Diluted | $ | .52 | $ | 1.58 | $ | .02 | ||||||
| Weighted average common shares outstanding: | ||||||||||||
Basic | 11,337 | 10,885 | 10,804 | |||||||||
Diluted | 11,494 | 11,244 | 11,241 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
| Accumulated | ||||||||||||||||||||||||
| Other | Total | |||||||||||||||||||||||
| Common Stock | Additional | Compre- | Compre- | |||||||||||||||||||||
| No. of | Par | Paid-In | Retained | hensive | hensive | |||||||||||||||||||
| Shares | Value | Capital | Earnings | Income | Income | |||||||||||||||||||
| BALANCE, | ||||||||||||||||||||||||
December 31, 2004 | 10,787 | $ | 1,078 | $ | 104,674 | $ | 11,844 | $ | - | |||||||||||||||
Net income and total | ||||||||||||||||||||||||
comprehensive income | - | - | - | 257 | - | $ | 257 | |||||||||||||||||
Issuance of stock through | ||||||||||||||||||||||||
compensation plans, including | ||||||||||||||||||||||||
income tax benefits | 19 | 3 | 2,164 | - | - | |||||||||||||||||||
Restricted stock issued as | ||||||||||||||||||||||||
compensation | 9 | 1 | 270 | - | - | |||||||||||||||||||
| BALANCE, | ||||||||||||||||||||||||
December 31, 2005 | 10,815 | 1,082 | 107,108 | 12,101 | - | |||||||||||||||||||
Net income and total | ||||||||||||||||||||||||
comprehensive income | - | - | - | 17,799 | - | $ | 17,799 | |||||||||||||||||
Issuance of stock through | ||||||||||||||||||||||||
compensation plans, including | ||||||||||||||||||||||||
income tax benefits | 337 | 33 | 6,857 | - | - | |||||||||||||||||||
| BALANCE, | ||||||||||||||||||||||||
December 31, 2006 | 11,152 | 1,115 | 113,965 | 29,900 | - | |||||||||||||||||||
Net income | - | - | - | 5,990 | - | $ | 5,990 | |||||||||||||||||
Unrealized gain on | ||||||||||||||||||||||||
marketable securities, | ||||||||||||||||||||||||
net of tax of $1,464 | - | - | - | - | 2,718 | 2,718 | ||||||||||||||||||
Total comprehensive | ||||||||||||||||||||||||
income | $ | 8,708 | ||||||||||||||||||||||
Issuance of stock through | ||||||||||||||||||||||||
compensation plans, including | ||||||||||||||||||||||||
income tax benefits | 202 | 20 | 7,098 | - | - | |||||||||||||||||||
| BALANCE, | ||||||||||||||||||||||||
December 31, 2007 | 11,354 | $ | 1,135 | $ | 121,063 | $ | 35,890 | $ | 2,718 | |||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| Year Ended December 31, | ||||||||||||
2007 | 2006 | 2005 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
Net income | $ | 5,990 | $ | 17,799 | $ | 257 | ||||||
Adjustments to reconcile net income to cash | ||||||||||||
provided by operating activities: | ||||||||||||
Depreciation, depletion and amortization | 84,476 | 66,163 | 47,509 | |||||||||
Impairment of property and equipment | 12,137 | 21,848 | 18,266 | |||||||||
Exploration costs | 68,870 | 65,173 | 39,957 | |||||||||
Gain on sales of property and equipment, net | (4,209 | ) | (1,668 | ) | (18,711 | ) | ||||||
Deferred income taxes | 3,768 | 215 | (526 | ) | ||||||||
Non-cash employee compensation | 1,865 | 2,279 | 2,998 | |||||||||
Unrealized (gain) loss on derivatives | 24,249 | (57,568 | ) | 40,406 | ||||||||
Settlements on derivatives with financing elements | 28,468 | 29,407 | 27,731 | |||||||||
Amortization of debt issue costs | 1,281 | 1,308 | 2,631 | |||||||||
Accretion of abandonment obligations | 2,508 | 1,653 | 1,158 | |||||||||
Excess tax benefit on exercise of stock options | (963 | ) | (1,807 | ) | - | |||||||
Minority interest, net of tax | 3,812 | 574 | - | |||||||||
Changes in operating working capital: | ||||||||||||
Accounts receivable | (10,028 | ) | (8,101 | ) | (4,764 | ) | ||||||
Accounts payable | 10,992 | 3,543 | 1,707 | |||||||||
Other | 1,650 | 5,172 | 4,856 | |||||||||
Net cash provided by operating activities | 234,866 | 145,990 | 163,475 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
Additions to property and equipment | (233,453 | ) | (254,840 | ) | (172,987 | ) | ||||||
Additions to equipment of Larclay JV. | (29,302 | ) | (60,655 | ) | - | |||||||
Proceeds from sales of property and equipment | 22,773 | 4,451 | 23,252 | |||||||||
Change in equipment inventory | 18,166 | (662 | ) | (36,519 | ) | |||||||
Other | (14,443 | ) | 1,753 | (10,411 | ) | |||||||
Net cash used in investing activities | (236,259 | ) | (309,953 | ) | (196,665 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
Proceeds from long-term debt | 25,800 | 129,300 | 235,700 | |||||||||
Proceeds from long-term debt of Larclay JV | 8,727 | 66,254 | - | |||||||||
Repayments of long-term debt | - | - | (177,531 | ) | ||||||||
Repayments of long-term debt of Larclay JV | (13,125 | ) | - | - | ||||||||
Proceeds from sale of common stock | 6,000 | 3,914 | 292 | |||||||||
Settlements on derivatives with financing elements | (28,468 | ) | (29,407 | ) | (27,731 | ) | ||||||
Payment of debt issue costs | - | - | (7,964 | ) | ||||||||
Excess tax benefit on exercise of stock options | 963 | 1,807 | - | |||||||||
Net cash provided by (used in) financing activities | (103 | ) | 171,868 | 22,766 | ||||||||
| NET INCREASE (DECREASE) IN CASH AND | ||||||||||||
| CASH EQUIVALENTS | (1,496 | ) | 7,905 | (10,424 | ) | |||||||
| CASH AND CASH EQUIVALENTS | ||||||||||||
Beginning of period | 13,840 | 5,935 | 16,359 | |||||||||
End of period | $ | 12,344 | $ | 13,840 | $ | 5,935 | ||||||
| SUPPLEMENTAL DISCLOSURES | ||||||||||||
Cash paid for interest, net of amounts capitalized | $ | 35,213 | $ | 19,653 | $ | 4,343 | ||||||
Cash paid for income taxes | $ | 348 | $ | 196 | $ | 365 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-7
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations
Clayton Williams Energy, Inc. (a Delaware corporation) and its subsidiaries (collectively, the “Company” or “CWEI”) is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core areas in Texas, Louisiana and New Mexico. Approximately 20% of the Company’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 27% is owned by a partnership in which Mr. Williams’ adult children are limited partners.
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.
F-8
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Natural Gas Systems and Other Property and Equipment
Natural gas gathering and processing systems consist primarily of gas gathering pipelines, compressors and gas processing plants. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income in the accompanying consolidated statements of operations.
Depreciation of natural gas gathering and processing systems and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 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 3 to 7 years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.
Valuation of Property and Equipment
The Company follows the provisions of Statement of Financial Accounting Standards (“SFAS”) 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, and contract drilling equipment, 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 difference 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. 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 SFAS 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.
F-9
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Taxes
The Company follows the asset and liability method prescribed by SFAS 109 “Accounting for Income Taxes” (“SFAS 109”). Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under SFAS 109, the effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in income in the period that includes the enactment date.
Hedging Activities
From time to time, the Company utilizes derivative instruments, consisting of swaps, floors and collars, to attempt to reduce its exposure to changes in commodity prices and interest rates. The Company accounts for its derivatives in accordance with SFAS 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 stated at the lower of average 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, 2007, 2006 and 2005, the Company capitalized interest totaling approximately $4.2 million, $5.8 million and $2.2 million, respectively. In addition, the Company capitalized interest relating to the construction of drilling rigs in the Larclay JV of $2 million in 2007.
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 2007, 2006 and 2005 include an increase in potential shares attributable to dilutive stock options.
Marketable Securities
All marketable equity securities are included in other non-current assets and are considered available-for-sale securities carried at fair value, in accordance with SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities”. The unrealized gains and losses related to these securities are included in accumulated other comprehensive income. The fair values are based on quoted market prices.
F-10
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Stock-Based Compensation
Effective January 1, 2006, the Company adopted SFAS 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, 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 and forfeiture 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, 2007 or 2006. Revenues from natural gas services are recognized as services are provided.
Comprehensive Income
SFAS 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. In 2007, the Company reported an unrealized gain on marketable securities as comprehensive income. There were no differences between net income and comprehensive income in 2006 and 2005.
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, 2007 and 2006 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 December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS 141R, “Business Combinations” (“SFAS 141R”) and SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 141R requires most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The Statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under SFAS 141R, all business combinations will be accounted for by applying the acquisition method. SFAS 141R is effective for periods beginning on or after December 15, 2008. SFAS 160 will require noncontrolling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for noncontrolling interests and transactions with noncontrolling interest holders in consolidated financial statements. SFAS 160 is effective for periods beginning on or after December 15, 2008 and will be applied prospectively to all noncontrolling interests,
F-11
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
including any that arose before the effective date except that comparative period information must be recast to classify noncontrolling interests in equity, attribute net income and other comprehensive income to noncontrolling interests, and provide other disclosures required by SFAS 160. The impact to the Company from the adoption of SFAS 141R in 2009 will depend on future acquisition activity.
In February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115” (“SFAS 159”). SFAS 159 permits an entity to choose to measure many financial instruments and certain other items at fair value. The fair value option established by SFAS 159 permits all entities to choose to measure eligible items at fair value at specified election dates. Unrealized gains and losses on items for which the fair value option has been elected are to be recognized in earnings at each subsequent reporting date. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The effect of adopting SFAS 159 is not expected to have a significant effect on the Company’s reported financial position or results of operations.
In September 2006, the FASB issued SFAS 157, “Fair Value Measurements” (“SFAS 157”), which will become effective for financial assets and liabilities of the company on January 1, 2008 and non-financial assets and liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements but would apply to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact, if any, to the company from the adoption of SFAS 157 in 2009 will depend on the Company’s assets and liabilities at that time that are required to be measured at fair value.
3. Long-Term Debt
Long-term debt consists of the following:
| December 31, | December 31, | |||||||
| 2007 | 2006 | |||||||
| (In thousands) | ||||||||
7¾% Senior Notes due 2013 | $ | 225,000 | $ | 225,000 | ||||
Secured bank credit facility, due May 2009 | 165,800 | 140,000 | ||||||
Secured term loan of Larclay JV, due June 2011 | 61,875 | 66,273 | ||||||
| 452,675 | 431,273 | |||||||
Less current maturities(a) | (22,500 | ) | (17,397 | ) | ||||
| $ | 430,175 | $ | 413,876 | |||||
(a) Amounts in both periods relate to the current portion of the term loan of Larclay JV.
Aggregate maturities of long-term debt at December 31, 2007 are as follows: 2008 - $22.5 million; 2009 - $184.6 million; 2010 - $15 million; 2011 - $5.6 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.
At any time prior to August 1, 2008, the Company may redeem up to 35% of the aggregate principal amount of the Senior Notes with the proceeds of certain equity offerings at a redemption price of 107.75% of the principal amount, plus accrued and unpaid interest. In addition, prior to August 1, 2009, the Company may redeem some or all of the Senior Notes at a redemption price equal to 100% of the principal amount of the Senior Notes to be redeemed, plus a make-whole premium, plus any accrued and unpaid interest. On and after August 1, 2009, the Company may redeem some or all of the Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 103.875% for the twelve-month period beginning on August 1, 2009, 101.938% for the twelve-month period beginning on August 1, 2010, and 100.00% beginning on August 1, 2011 or 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
F-12
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2007.
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, 2007, the borrowing base established by the banks was $275 million, with no monthly commitment reductions. After allowing for outstanding letters of credit totaling $804,000, the Company had $108.4 million available under the credit facility at December 31, 2007.
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, 2007 was 7.3%.
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, 2007.
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. In March 2007, the Company issued a $5 million letter of credit which expired in June 2007 as additional collateral under the term loan to cover any temporary shortfall in collateral value caused by delays in completing construction of the final drilling rigs being financed by the lender. Concurrently, the guaranty was amended to limit the Company’s combined credit exposure under the guaranty and the letter of credit to $19.5 million. Although the Company is not a maker on the Larclay JV term loan, it is providing partial 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 – an Interpretation of ARB No. 51 (as amended)” (“FIN 46R”).
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 June 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. At December 31, 2007, the effective interest rate on the Larclay JV term loan was 8.7%.
F-13
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Other Non-Current Liabilities
Other non-current liabilities at December 31, 2007 and 2006 consist of the following:
| 2007 | 2006 | |||||||
| (In thousands) | ||||||||
Abandonment obligations | $ | 30,994 | $ | 27,846 | ||||
Minority interest, net of tax | 4,886 | 1,074 | ||||||
Other taxes payable | 358 | - | ||||||
Other | 808 | 901 | ||||||
| $ | 37,046 | $ | 29,821 | |||||
Abandonment Obligations
Changes in abandonment obligations for 2007 and 2006 are as follows:
| 2007 | 2006 | |||||||
| (In thousands) | ||||||||
Beginning of year | $ | 27,846 | $ | 19,447 | ||||
Additional abandonment obligations from new wells | 936 | 1,074 | ||||||
Sales of properties | (1,726 | ) | (912 | ) | ||||
Accretion expense | 2,508 | 1,653 | ||||||
Abandonment obligations related to acquisitions | - | 98 | ||||||
Revisions of previous estimates | 1,430 | 6,486 | ||||||
End of year | $ | 30,994 | $ | 27,846 | ||||
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, 2007 and 2006 are as follows:
| 2007 | 2006 | |||||||
| (In thousands) | ||||||||
Deferred tax assets: | ||||||||
Fair value of derivatives | $ | 17,224 | $ | 8,757 | ||||
Alternative minimum tax credit carryforwards | 437 | 418 | ||||||
Statutory depletion carryforwards | 5,366 | 4,682 | ||||||
Other | 11,132 | 7,080 | ||||||
| 34,159 | 20,937 | |||||||
Deferred tax liabilities: | ||||||||
Property and equipment | (74,880 | ) | (56,841 | ) | ||||
Net deferred tax liabilities | $ | (40,721 | ) | $ | (35,904 | ) | ||
Components of net deferred tax assets (liabilities): | ||||||||
Current assets | $ | 3,581 | $ | 505 | ||||
Non-current liabilities | (44,302 | ) | (36,409 | ) | ||||
| $ | (40,721 | ) | $ | (35,904 | ) | |||
F-14
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2006 and 2005, the Company’s effective income tax rates were different than the statutory federal income tax rates for the following reasons:
| 2007 | 2006 | 2005 | ||||||||||
| (In thousands) | ||||||||||||
Income tax expense (benefit) at | ||||||||||||
statutory rate of 35% | $ | 5,355 | $ | 7,123 | $ | (68 | ) | |||||
Tax depletion in excess of basis | (700 | ) | (700 | ) | (613 | ) | ||||||
Revision of previous tax estimates | 16 | (152 | ) | 102 | ||||||||
State income taxes, net of federal tax effect | 738 | (4,429 | ) | (40 | ) | |||||||
Other | 88 | 137 | 168 | |||||||||
Income tax expense (benefit) | $ | 5,497 | $ | 1,979 | $ | (451 | ) | |||||
Current | $ | 1,729 | $ | 1,764 | $ | 75 | ||||||
Deferred | 3,768 | 215 | (526 | ) | ||||||||
Income tax expense (benefit) | $ | 5,497 | $ | 1,979 | $ | (451 | ) | |||||
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, 2007, the Company’s cumulative tax loss carryforwards were approximately $88,000 and consisted of unrecognized excess tax benefits derived from stock options exercised in 2007.
The Company and its subsidiaries file federal income tax returns with the United States Internal Revenue Service (“IRS”) and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for fiscal years after 2002 currently remain subject to examination by appropriate taxing authorities. None of the Company’s income tax returns are under examination at this time.
In June 2006, the FASB issued Interpretation No. 48, "Accounting for Uncertainty in Income Taxes "(“FIN 48”). Upon adoption of FIN 48, the Company recorded a liability for taxes payable related to unrecognized tax benefits arising from uncertain tax positions taken by the Company in previous periods. A reconciliation of the changes in this tax liability during the year ended December 31, 2007 is as follows:
| 2007 | ||||
| (In thousands) | ||||
| Balance at December 31, 2006 | $ | - | ||
Adoption of FIN 48 on January 1, 2007 | 1,585 | |||
Reductions for tax positions of prior years | (1,227 | ) | ||
| Balance at December 31, 2007 | $ | 358 | ||
No additional unrecognized tax benefits originated during 2007. Reductions in this tax liability resulted from changes in accounting methods which were submitted to the taxing authority during 2007. All of the remaining unrecognized tax benefits at December 31, 2007 relate to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. Because of the impact of deferred tax accounting, the disallowance of the shorter deduction period would not affect the annual effective tax rate but would only accelerate the payment of taxes to the taxing authority or change the amount of deferred tax assets related to net operating loss carryforwards.
The tax liability recorded under FIN 48 included in other non-current liabilities in the accompanying consolidated financial statements, and any interest and penalties accrued on unrecognized tax benefits are recorded as interest expense in the accompanying statements of operations. However, due to the Company’s net operating loss carryforwards, no interest or penalties have been accrued on the Company’s unrecognized tax benefits.
6. Assets Held For Sale
Included in assets held for sale is $15.8 million for the estimated fair value of two 2,000 horsepower drilling rigs and related components and $1.5 million for well service equipment that the Company has designated as held
F-15
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
for sale assets under SFAS 144. In connection with the determination to sell these assets, the Company recorded an $8.2 million charge which was included in impairment of property and equipment.
7. Derivatives
Commodity Derivatives
From time to time, the Company utilizes commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for its oil and gas production. When using swaps to hedge oil and natural gas production, the Company receives a fixed price for the respective commodity and pays a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. In floor transactions, the Company receives a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below 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. Commodity derivatives are settled monthly as the contract production periods mature.
The following summarizes information concerning the Company’s net positions in open commodity derivatives applicable to periods subsequent to December 31, 2007, including derivatives entered into after December 31, 2007. The settlement prices of commodity derivatives are based on NYMEX futures prices.
Collars:
| Gas | Oil | |||||||||||||||||||||||
MMBtu (a) | Floor | Ceiling | Bbls | Floor | Ceiling | |||||||||||||||||||
| Production Period: | ||||||||||||||||||||||||
1st Quarter 2008 | 434,000 | $ | 4.00 | $ | 5.15 | 132,000 | $ | 23.00 | $ | 25.07 | ||||||||||||||
2nd Quarter 2008 | 426,000 | $ | 4.00 | $ | 5.15 | 132,000 | $ | 23.00 | $ | 25.07 | ||||||||||||||
3rd Quarter 2008 | 419,000 | $ | 4.00 | $ | 5.15 | 128,000 | $ | 23.00 | $ | 25.07 | ||||||||||||||
| 1,279,000 | 392,000 | |||||||||||||||||||||||
Swaps:
| Gas | Oil | |||||||||||||||
MMBtu (a) | Price | Bbls | Price | |||||||||||||
| Production Period: | ||||||||||||||||
1st Quarter 2008 | 1,800,000 | $ | 8.26 | 380,000 | $ | 91.85 | ||||||||||
2nd Quarter 2008 | 4,650,000 | $ | 9.20 | 330,000 | $ | 79.84 | ||||||||||
3rd Quarter 2008 | 4,200,000 | $ | 9.15 | 310,000 | $ | 78.96 | ||||||||||
4th Quarter 2008 | 4,200,000 | $ | 9.15 | 400,000 | $ | 82.21 | ||||||||||
2009 | 3,600,000 | $ | 9.33 | 1,440,000 | $ | 85.30 | ||||||||||
| 18,450,000 | 2,860,000 | |||||||||||||||
In September 2007, the Company also terminated certain fixed-priced oil swaps covering 270,000 barrels at a price of $78.64 from January 2008 through March 2008 and a price of $76.65 from April 2008 through December 2008, resulting in an aggregate loss of approximately $3.3 million, which will be paid to the counterparty monthly during 2008.
Interest Rate Derivatives
The Company is a party to two interest rate swaps. 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, 2007.
F-16
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Interest Rate Swaps:
| Fixed | ||||||||
| Principal | Libor | |||||||
| Balance | Rates | |||||||
| Period: | ||||||||
January 1, 2008 to September 24, 2008 | $ | 100,000,000 | 4.73 | % | ||||
January 1, 2008 to November 3, 2008 | $ | 45,000,000 | 5.73 | % | ||||
Accounting For Derivatives
The Company accounts for its derivatives in accordance with SFAS 133. 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, 2007, the Company reported a $32 million net loss on derivatives, consisting of a $24.3 million loss related to changes in mark-to-market valuations and a $7.7 million cash charge for settled contracts. For the year ended December 31, 2006, the net gain on derivatives was $37.3 million, 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.
8. Financial Instruments
Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the secured bank credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive. The estimated fair value of the Company’s Senior Notes at December 31, 2007 and 2006 was approximately $196.9 million and $207.6 million, respectively.
The fair values of derivatives as of December 31, 2007 and 2006 are set forth below.
| 2007 | 2006 | |||||||
| (In thousands) | ||||||||
Assets (liabilities): | ||||||||
Commodity derivatives | $ | (48,696 | ) | $ | (25,289 | ) | ||
Interest rate derivatives | (1,044 | ) | (200 | ) | ||||
Net liabilities | $ | (49,740 | ) | $ | (25,489 | ) | ||
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, 2007 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. At December 31, 2007, 101,766 shares remain available for issuance under this plan.
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 48,000 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. At December 31, 2007, 38,300 shares remain available for issuance under this plan.
F-17
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 years ended December 31, 2007 and 2006:
| Weighted | ||||||||||||||||
| Weighted | Average | |||||||||||||||
| Average | Remaining | Aggregate | ||||||||||||||
| Exercise | Contractual | Intrinsic | ||||||||||||||
| Shares | Price | Term | Value (a) | |||||||||||||
| Outstanding at January 1, 2006 | 1,338,551 | $ | 19.53 | |||||||||||||
Granted | 4,000 | $ | 41.74 | |||||||||||||
Exercised (b) | (333,066 | ) | $ | 11.75 | ||||||||||||
| Outstanding at December 31, 2006 | 1,009,485 | $ | 22.27 | 6.5 | $ | 14,174,163 | ||||||||||
| Vested at December 31, 2006 | 1,009,485 | $ | 22.27 | 6.5 | $ | 14,174,163 | ||||||||||
| Exercisable at December 31, 2006 | 1,009,485 | $ | 22.27 | 6.5 | $ | 14,174,163 | ||||||||||
| Outstanding at January 1, 2007 | 1,009,485 | $ | 22.77 | |||||||||||||
Granted | 4,000 | $ | 36.31 | |||||||||||||
Exercised (b) | (202,000 | ) | $ | 29.70 | ||||||||||||
| Outstanding at December 31, 2007 | 811,485 | $ | 20.49 | 5.12 | $ | 8,660,396 | ||||||||||
| Vested at December 31, 2007 | 811,485 | $ | 20.49 | 5.12 | $ | 8,660,396 | ||||||||||
| Exercisable at December 31, 2007 | 811,485 | $ | 20.49 | 5.12 | $ | 8,660,396 | ||||||||||
(a) Based on closing price at December 31, 2007 of $31.16 per share and $36.31 per share at December 31, 2006. | ||||||||||||||||
| (b) Cash received for options exercised totaled $6 million in 2007 and $3.9 million in 2006. | ||||||||||||||||
The following table summarizes information with respect to options outstanding at December 31, 2007, all of which are currently exercisable.
| Outstanding and Exercisable Options | |||||
| Weighted | |||||
| Weighted | Average | ||||
| Average | Remaining | ||||
| Exercise | Life in | ||||
| Shares | Price | Years | |||
| Range of exercise prices: | |||||
$5.50 | 33,485 | $ 5.50 | 1.3 | ||
$10.00 - $19.74 | 460,000 | $ 17.50 | 4.3 | ||
$22.90 - $41.74 | 318,000 | $ 26.38 | 6.5 | ||
| 811,485 | $ 20.49 | 5.1 | |||
The following table presents certain information regarding stock-based compensation amounts for the years ended December 31, 2007, 2006 and 2005.
| 2007 | 2006 | 2005 | ||||||||||
| (In thousands, except per share) | ||||||||||||
| Weighted average grant date fair value of options granted per share | $ | 27.56 | $ | 31.91 | $ | 22.81 | ||||||
| Intrinsic value of options exercised | $ | 261 | $ | 9,725 | $ | 133 | ||||||
| Stock-based employee compensation expense | $ | 110 | $ | 128 | $ | 1,897 | ||||||
| Tax benefit | $ | (39 | ) | $ | (45 | ) | $ | (664 | ) | |||
| Net stock-based employee compensation expense | $ | 72 | $ | 83 | $ | 1,233 | ||||||
F-18
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Pro forma information, as required by SFAS 123 “Accounting for Stock-Based Compensation” (“SFAS 123”), as amended by SFAS 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.
| 2007 | 2006 | 2005 | |||
| Risk-free interest rate | 4.7% | 4.4% | 3.9% | ||
| Stock price volatility | 64% | 66% | 67% | ||
| Expected life in years | 10 | 10 | 10 | ||
| Dividend yield | - | - | - |
The SFAS 123 pro forma information for the year ended December 31, 2005 is as follows:
| 2005 | ||||
| (In thousands, | ||||
| except per share) | ||||
| Net income, as reported | $ | 257 | ||
Add: Stock-based employee compensation | ||||
expense included in net income, | ||||
net of tax | 1,233 | |||
Deduct: Stock-based employee compensation | ||||
expense determined under fair value based | ||||
method (SFAS 123R), net of tax | (2,920 | ) | ||
| Net loss, pro forma | $ | (1,430 | ) | |
| Basic: | ||||
Net income per common share, as reported | $ | .02 | ||
Net loss per common share, pro forma | $ | (.13 | ) | |
| Diluted: | ||||
Net income per common share, as reported | $ | .02 | ||
Net loss per common share, pro forma | $ | (.13 | ) | |
After-Payout Incentive Plan
The Compensation Committee of the Board of Directors has adopted an incentive plan for officers, key employees and consultants 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 it has recovered all of its costs, plus interest (“payout”). At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the APO 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. The Company recognized $1.8 million of non-cash compensation expense during 2007, $2.5 million in 2006 and $680,000 in 2005 for this plan.
SWR Reward Plan
In January 2007, the Company granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan designed to reward eligible employees and other service providers for continued quality service to the Company, and to encourage retention of those employees and service providers by providing them the opportunity to receive bonus payments that are based on certain profits derived from a portion of the Company’s working interest in the RS Windham C3 well in Upton County, Texas. Eligible participants in the
F-19
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
SWR Reward Plan include those officers, key employees and consultants, excluding Mr. Williams, who made significant contributions to the acquisition and development of Southwest Royalties, Inc.
The SWR Reward Plan provides for quarterly cash bonuses to the participants, as a group, equal to the after-payout cash flow from a 22.5% working interest in the RS Windham C3 well. Two-thirds of the quarterly bonus amount is payable to the participants until the full vesting date of October 25, 2011. After the full vesting date, the deferred portion of the quarterly bonus amount, with interest at 4.83% per year, as well as 100% of all subsequent quarterly bonus amounts, are payable to participants. The quarterly bonus amounts are allocated among the participants based on each participant’s bonus percentage.
To continue as a participant in the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date. Participants who remain in the employment or service of the Company through the full vesting date will continue as participants for the duration of the SWR Reward plan, subject to certain restrictions. The full vesting date may occur sooner than October 25, 2011 in the event of a change of control or sale transaction, as defined in the SWR Reward Plan.
The Company recognizes compensation expense related to the SWR Reward Plan over the vesting period. During fiscal 2007, the Company recorded compensation expense of $123,000 for the SWR Reward Plan.
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, 2007, 2006 and 2005.
| 2007 | 2006 | 2005 | ||||||||||
| (In thousands) | ||||||||||||
| Amounts received from the Williams Entities: | ||||||||||||
Service Agreement: | ||||||||||||
Services | $ | 299 | $ | 337 | $ | 224 | ||||||
Insurance premiums and benefits | 707 | 580 | 667 | |||||||||
Reimbursed expenses | 676 | 407 | 356 | |||||||||
| $ | 1,682 | $ | 1,324 | $ | 1,247 | |||||||
| Amounts paid to the Williams Entities: | ||||||||||||
Rent (a) | $ | 663 | $ | 619 | $ | 582 | ||||||
Service Agreement: | ||||||||||||
Business entertainment (b) | 113 | 113 | 113 | |||||||||
Other services | 150 | 150 | 150 | |||||||||
Reimbursed expenses | 122 | 118 | 122 | |||||||||
| $ | 1,048 | $ | 1,000 | $ | 967 | |||||||
(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.
F-20
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
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. A lender has provided a $75 million secured term loan to Larclay JV to finance most of the cost of constructing and initially equipping the rigs (see Note 3). The Larclay JV agreements require the Company to make loans to Larclay JV as needed to finance any costs to construct and initially equip the original 12 drilling rigs which are not otherwise financed under the secured term loan. Construction on 11 of the rigs is complete, and the Company loaned Larclay JV $4.6 million during the fourth quarter of 2007 in compliance with the agreements. The loan to Larclay JV will be due on demand and will bear interest, payable monthly, at the same rate as the secured term loan. However, the loan will be subject to a subordination agreement with the secured lender that imposes restrictions on payments of principal and interest on the note. All components of the final Larclay JV drilling rig, a 2,000 horsepower rig designed primarily to drill deep gas wells, have been purchased, but the final assembly of the rig has been postponed while management evaluates the market for additional deep rigs in Larclay JV’s areas of operations. Upon making a final determination, Larclay JV will either proceed with the final assembly of the rig or it will sell the rig components. If the rig is assembled for operation, the Company will be required to make an additional subordinated loan to finance the costs to assemble the rig, which is expected to be less than $2 million.
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 approximately $78.1 million at December 31, 2007.
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, 2007, Lariat’s equity ownership in the net assets of Larclay JV was $4.9 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.
Sandridge Energy Inc.
The Company owns 200,460 shares of common stock in Sandridge Energy Inc. (“Sandridge”). During the fourth quarter of 2007, Sandridge became publicly traded and listed its shares on the New York Stock Exchange. The Company’s original cost investment in Sandridge was increased to fair market value in 2007 and the change in fair market value of $4.2 million, net of tax of $1.5 million, was recorded in accumulated other comprehensive income. The fair market value of the investment was determined based on the closing price of the stock as of December 31, 2007. The fair value of the Company’s investment in Sandridge at December 31, 2007 is $7.2 million and is recorded in other non-current assets.
F-21
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Inventory
The Company maintains an inventory of tubular goods and other well equipment for use in its exploration and development drilling activities. Any gains or losses on disposition of inventory, and any losses on write-down of inventory to its estimated market value, are reported as gain or loss on sales of assets in the accompanying consolidated statements of operations. In 2007, the Company recorded a charge of $8.9 million to write-down inventory to its estimated market value at March 31, 2007. The write-down resulted primarily from the sale of certain surplus equipment at an auction in March 2007. The Company received $4.5 million of net proceeds from the auction in April 2007 when the auction sale was consummated.
13. Commitments and Contingencies
Leases
The Company leases office space from affiliates and nonaffiliates under noncancelable operating leases. Rental expense pursuant to the office leases amounted to $846,000, $791,000 and $779,000 for the years ended December 31, 2007, 2006 and 2005, respectively.
Future minimum payments under noncancelable leases at December 31, 2007, are as follows:
| Leases | ||||||||||||
| Capital (a) | Operating | Total | ||||||||||
| (In thousands) | ||||||||||||
| 2008 | $ | 545 | $ | 1,097 | $ | 1,642 | ||||||
| 2009 | 322 | 1,058 | 1,380 | |||||||||
| 2010 | 119 | 1,024 | 1,143 | |||||||||
| Thereafter | - | 992 | 992 | |||||||||
Total minimum lease payments | $ | 986 | $ | 4,171 | $ | 5,157 | ||||||
(a) Relates to vehicle leases.
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.
Purchase Commitments
In addition to the Larclay JV drilling contract discussed in Note 11, the Company also entered into an agreement with an industry partner for the use of 3-D seismic data in the deep Bossier play in Leon County, Texas. The Company is obligated to make payments under this agreement of $4 million in 2008.
14. Impairment of Property and Equipment
The Company has recorded provisions for impairment of proved properties under SFAS 144 of $12.1 million in 2007, $21.8 million in 2006, and $18.3 million in 2005. The 2007 provision included $7.1 million to write-down two 2,000 horsepower drilling rigs and related components, and $1.1 million for well service equipment to their estimated fair market value. The remaining $3.9 million impairment is related to producing properties in the Permian Basin. The 2006 and 2005 provisions related to production performance for properties in West Texas.
The Company has also recorded provisions for impairment of unproved properties aggregating $16.8 million, $12.9 million and $5.3 million in 2007, 2006 and 2005, 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.
F-22
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. Sales of Assets
Gain on sale of property and equipment for 2007 was $14 million due primarily to the sale of its oil and gas properties in Pecos County, Texas, for $21 million. The Company recorded a gain of approximately $12.5 million in the fourth quarter of 2007 in connection with this sale. Gain on sale of property and equipment for 2006 was $1.8 million compared to $18.9 million in 2005. The 2006 gain was due primarily to the sale of property and equipment. In 2005, the gain was due in part to the sale of its interests in two leases in the Breton Sound area in the Gulf of Mexico. 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.
16. Quarterly Financial Data (Unaudited)
The following table summarizes results for each of the four quarters in the years ended December 31, 2007 and 2006.
| First | Second | Third | Fourth | |||||||||||||||||
| Quarter | Quarter | Quarter | Quarter | Year | ||||||||||||||||
| (In thousands, except per share) | ||||||||||||||||||||
| Year ended December 31, 2007: | ||||||||||||||||||||
Total revenues | $ | 72,501 | $ | 92,564 | $ | 101,839 | $ | 126,991 | $ | 393,895 | ||||||||||
Operating income | $ | 6,242 | $ | 13,698 | $ | 13,749 | $ | 40,341 | $ | 74,030 | ||||||||||
Net income (loss) (a) | $ | (12,310 | ) | $ | 8,810 | $ | 986 | $ | 8,504 | $ | 5,990 | |||||||||
Net income (loss) per common share (b): | ||||||||||||||||||||
Basic | $ | (1.09 | ) | $ | .78 | $ | .09 | $ | .75 | $ | .53 | |||||||||
Diluted | $ | (1.09 | ) | $ | .77 | $ | .09 | $ | .74 | $ | .52 | |||||||||
Weighted average common shares outstanding: | ||||||||||||||||||||
Basic | 11,290 | 11,352 | 11,352 | 11,352 | 11,337 | |||||||||||||||
Diluted | 11,290 | 11,507 | 11,521 | 11,529 | 11,494 | |||||||||||||||
| Year ended December 31, 2006: | ||||||||||||||||||||
Total revenues | $ | 63,394 | $ | 70,341 | $ | 66,389 | $ | 65,874 | $ | 265,998 | ||||||||||
Operating income (loss) | $ | 10,487 | $ | 25,366 | $ | (11,476 | ) | $ | (19,131 | ) | $ | 5,246 | ||||||||
Net income (loss) (a) | $ | 3,376 | $ | 17,966 | $ | 5,349 | $ | (8,892 | ) | $ | 17,799 | |||||||||
Net income (loss) per common share (b): | ||||||||||||||||||||
Basic | $ | .31 | $ | 1.66 | $ | .49 | $ | (.81 | ) | $ | 1.64 | |||||||||
Diluted | $ | .30 | $ | 1.59 | $ | .48 | $ | (.81 | ) | $ | 1.58 | |||||||||
Weighted average common shares outstanding: | ||||||||||||||||||||
Basic | 10,841 | 10,850 | 10,850 | 11,000 | 10,885 | |||||||||||||||
Diluted | 11,351 | 11,286 | 11,205 | 11,000 | 11,244 | |||||||||||||||
| (a) | The Company recorded a $8.0 million charge for impairment of property and equipment in the third quarter of 2007 and a $3.1 million charge in the fourth quarter of 2007. 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. |
| (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. |
F-23
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Costs of Oil and Gas Properties
The following table sets forth certain information with respect to costs incurred in connection with the Company's oil and gas producing activities during the years ended December 31, 2007, 2006 and 2005.
| 2007 | 2006 | 2005 | ||||||||||
| (In thousands) | ||||||||||||
Property acquisitions: | ||||||||||||
Proved | $ | - | $ | 6,432 | $ | 5,567 | ||||||
Unproved | 15,746 | 54,437 | 50,238 | |||||||||
Developmental costs | 45,611 | 35,698 | 42,292 | |||||||||
Exploratory costs | 169,879 | 157,509 | 86,304 | |||||||||
Total | $ | 231,236 | $ | 254,076 | $ | 184,401 | ||||||
The following table sets forth the capitalized costs for oil and gas properties as of December 31, 2007 and 2006.
| 2007 | 2006 | |||||||
| (In thousands) | ||||||||
Proved properties | $ | 1,258,166 | $ | 1,097,341 | ||||
Unproved properties | 115,924 | 129,420 | ||||||
Total capitalized costs | 1,374,090 | 1,226,761 | ||||||
Accumulated depreciation, depletion and amortization | (727,739 | ) | (654,316 | ) | ||||
Net capitalized costs | $ | 646,351 | $ | 572,445 | ||||
At December 31, 2007 and December 31, 2006, the Company had capitalized $27.1 million and $27 million, respectively, of exploratory drilling costs applicable to wells that were pending determination of proved reserves. Of the $27 million costs at December 31, 2006, $24.3 million was subsequently deemed productive and the remaining $2.4 million of costs were associated with wells that were sold in 2007.
The Company capitalized $26.3 million of drilling and completion costs associated with two wells in the East Texas Bossier area that were in progress at December 31, 2007 and were completed as marginal producers during the first quarter of 2008. The Company has not assigned any proved reserves to these wells since sufficient production history does not exist to permit the Company to make a reasonable estimate at this time. However, it appears to be unlikely that the Company will recover its capitalized drilling and completion costs on these wells through future production from only these wells. Depending on its evaluations of these wells and the results of future drilling activities in its East Texas Bossier play, the Company may record impairments of proved properties related to these wells in future periods.
18. Segment Information
In accordance with SFAS 131, “Disclosures about Segments of an Enterprise and Related Information” (“SFAS 131”), the Company has two reportable operating segments, which is oil and gas exploration and production. Beginning in April 2006, the Company formed the Larclay JV, a contract drilling joint venture that the Company consolidates in its financial statements (see Note 11). Effective January 1, 2007, the contract drilling segment meets the quantitative thresholds under SFAS 131 to be considered a reportable operating segment and, accordingly, is shown as “Contract Drilling” in the tables below. Prior to 2006, the Company had no operating segments other than oil and gas exploration and production.
F-24
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables present selected financial information regarding the Company’s operating segments for 2007 and 2006.
| Contract | Intercompany | Consolidated | ||||||||||||||
| For the Year Ended December 31, 2007 | Oil and Gas | Drilling | Eliminations | Total | ||||||||||||
| (In thousands) | ||||||||||||||||
| Revenues | $ | 341,246 | $ | 64,551 | $ | (11,902 | ) | $ | 393,895 | |||||||
| Depreciation, depletion and amortization (a) | 82,240 | 16,060 | (1,687 | ) | 96,613 | |||||||||||
| Other operating expenses (b) | 192,334 | 39,138 | (8,220 | ) | 223,252 | |||||||||||
| Interest expense | 27,818 | 4,300 | - | 32,118 | ||||||||||||
| Other (income) expense | 26,613 | - | - | 26,613 | ||||||||||||
| Income before income taxes | 12,241 | 5,053 | (1,995 | ) | 15,299 | |||||||||||
| Income tax expense | 3,305 | 2,192 | - | 5,497 | ||||||||||||
| Minority interest, net of tax | 2,053 | (5,865 | ) | - | (3,812 | ) | ||||||||||
| Net income (loss) | $ | 10,989 | $ | (3,004 | ) | $ | (1,995 | ) | $ | 5,990 | ||||||
| Total assets | $ | 753,480 | $ | 114,849 | $ | (7,233 | ) | $ | 861,096 | |||||||
| Additions to property and equipment | $ | 235,679 | $ | 23,538 | $ | (1,995 | ) | $ | 257,222 | |||||||
| Contract | Intercompany | Consolidated | ||||||||||||||
| For the Year Ended December 31, 2006 | Oil and Gas | Drilling | Eliminations | Total | ||||||||||||
| (In thousands) | ||||||||||||||||
| Revenues | $ | 259,061 | $ | 11,180 | $ | (4,243 | ) | $ | 265,998 | |||||||
| Depreciation, depletion and amortization (a) | 86,887 | 1,646 | (522 | ) | 88,011 | |||||||||||
| Other operating expenses (b) | 168,359 | 7,100 | (2,718 | ) | 172,741 | |||||||||||
| Interest expense | 20,227 | 668 | - | 20,895 | ||||||||||||
| Other (income) expense | (36,001 | ) | - | - | (36,001 | ) | ||||||||||
| Income before income taxes | 19,589 | 1,766 | (1,003 | ) | 20,352 | |||||||||||
| Income tax expense | (1,361 | ) | (618 | ) | - | (1,979 | ) | |||||||||
| Minority interest, net of tax | - | (574 | ) | - | (574 | ) | ||||||||||
| Net income | $ | 18,228 | $ | 574 | $ | (1,003 | ) | $ | 17,799 | |||||||
| Total assets | $ | 720,660 | $ | 76,946 | $ | (2,173 | ) | $ | 795,433 | |||||||
| Additions to property and equipment | $ | 261,508 | $ | 66,418 | $ | (1,003 | ) | $ | 326,923 | |||||||
(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.
19. 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 19 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.
F-25
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Balance Sheet
December 31, 2007
| (Dollars in thousands) | Non- | |||||||||||||||||||
| Guarantor | Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Entities | Eliminations | Consolidated | ||||||||||||||||
| Current assets | $ | 127,668 | $ | 109,010 | $ | 21,225 | $ | (145,524 | ) | $ | 112,379 | |||||||||
| Property and equipment, net | 369,421 | 275,609 | 86,048 | - | 731,078 | |||||||||||||||
| Investments in subsidiaries | 81,583 | - | - | (81,583 | ) | - | ||||||||||||||
| Other assets | 21,354 | 340 | 545 | (4,600 | ) | 17,639 | ||||||||||||||
| Total assets | $ | 600,026 | $ | 384,959 | $ | 107,818 | $ | (231,707 | ) | $ | 861,096 | |||||||||
| Current liabilities | $ | 112,536 | $ | 179,243 | $ | 42,512 | $ | (145,524 | ) | $ | 188,767 | |||||||||
| Non-current liabilities: | ||||||||||||||||||||
| Long-term debt | 390,800 | - | 43,975 | (4,600 | ) | 430,175 | ||||||||||||||
| Fair value of derivatives | - | - | - | - | - | |||||||||||||||
| Other | 24,708 | 56,528 | 112 | - | 81,348 | |||||||||||||||
| 415,508 | 56,528 | 44,087 | (4,600 | ) | 511,523 | |||||||||||||||
| Stockholders’ equity | 71,982 | 149,188 | 21,219 | (81,583 | ) | 160,806 | ||||||||||||||
| Total liabilities and | ||||||||||||||||||||
| stockholders’ equity | $ | 600,026 | $ | 384,959 | $ | 107,818 | $ | (231,707 | ) | $ | 861,096 | |||||||||
Condensed Consolidating Balance Sheet
December 31, 2006
| (Dollars in thousands) | Non- | |||||||||||||||||||
| Guarantor | Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Entities | Eliminations | Consolidated | ||||||||||||||||
| Current assets | $ | 160,772 | $ | 96,386 | $ | 11,781 | $ | (142,941 | ) | $ | 125,998 | |||||||||
| Property and equipment, net | 293,775 | 279,913 | 71,121 | - | 644,809 | |||||||||||||||
| Investments in subsidiaries | 72,171 | - | - | (72,171 | ) | - | ||||||||||||||
| Other assets | 23,638 | 358 | 630 | - | 24,626 | |||||||||||||||
| Total assets | $ | 550,356 | $ | 376,657 | $ | 83,532 | $ | (215,112 | ) | $ | 795,433 | |||||||||
| Current liabilities | $ | 89,704 | $ | 176,876 | $ | 25,427 | $ | (142,941 | ) | $ | 149,066 | |||||||||
| Non-current liabilities: | ||||||||||||||||||||
| Long-term debt | 365,000 | - | 48,876 | - | 413,876 | |||||||||||||||
| Fair value of derivatives | 313 | 20,968 | - | - | 21,281 | |||||||||||||||
| Other | 10,257 | 55,870 | 103 | - | 66,230 | |||||||||||||||
| 375,570 | 76,838 | 48,979 | - | 501,387 | ||||||||||||||||
| Stockholders’ equity | 85,082 | 122,943 | 9,126 | (72,171 | ) | 144,980 | ||||||||||||||
| Total liabilities and | ||||||||||||||||||||
| stockholders’ equity | $ | 550,356 | $ | 376,657 | $ | 83,532 | $ | (215,112 | ) | $ | 795,433 | |||||||||
F-26
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Operations
Year Ended December 31, 2007
| (Dollars in thousands) | Non- | |||||||||||||||||||
| Guarantor | Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Entities | Eliminations | Consolidated | ||||||||||||||||
| Total revenue | $ | 224,743 | $ | 117,208 | $ | 65,241 | $ | (13,297 | ) | $ | 393,895 | |||||||||
| Costs and expenses | 198,535 | 83,947 | 48,686 | (11,303 | ) | 319,865 | ||||||||||||||
| Operating income (loss) | 26,208 | 33,261 | 16,555 | (1,994 | ) | 74,030 | ||||||||||||||
| Other income (expense) | (46,373 | ) | (8,213 | ) | (4,145 | ) | - | (58,731 | ) | |||||||||||
| Income tax expense | (5,497 | ) | - | - | - | (5,497 | ) | |||||||||||||
| Minority interest, net of tax | (3,812 | ) | - | - | - | (3,812 | ) | |||||||||||||
| Net income (loss) | $ | (29,474 | ) | $ | 25,048 | $ | 12,410 | $ | (1,994 | ) | $ | 5,990 | ||||||||
Condensed Consolidating Statement of Operations
Year Ended December 31, 2006
| (Dollars in thousands) | Non- | |||||||||||||||||||
| Guarantor | Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Entities | Eliminations | Consolidated | ||||||||||||||||
| Total revenue | $ | 154,159 | $ | 106,550 | $ | 11,397 | $ | (6,108 | ) | $ | 265,998 | |||||||||
| Costs and expenses | 176,951 | 79,456 | 9,450 | (5,105 | ) | 260,752 | ||||||||||||||
| Operating income (loss) | (22,792 | ) | 27,094 | 1,947 | (1,003 | ) | 5,246 | |||||||||||||
| Other income (expense) | 4,453 | 11,281 | (628 | ) | - | 15,106 | ||||||||||||||
| Income tax expense | (1,979 | ) | - | - | - | (1,979 | ) | |||||||||||||
| Minority interest, net of tax | (574 | ) | - | - | - | (574 | ) | |||||||||||||
| Net income (loss) | $ | (20,892 | ) | $ | 38,375 | $ | 1,319 | $ | (1,003 | ) | $ | 17,799 | ||||||||
Condensed Consolidating Statement of Operations
Year Ended December 31, 2005
| (Dollars in thousands) | Non- | |||||||||||||||||||
| Guarantor | Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Entities | Eliminations | Consolidated | ||||||||||||||||
| Total revenue | $ | 179,443 | $ | 105,927 | $ | - | $ | (1,771 | ) | $ | 283,599 | |||||||||
| Costs and expenses | 137,837 | 67,192 | - | (1,771 | ) | 203,258 | ||||||||||||||
| Operating income (loss) | 41,606 | 38,735 | - | - | 80,341 | |||||||||||||||
| Other income (expense) | (18,077 | ) | (62,458 | ) | - | - | (80,535 | ) | ||||||||||||
| Income tax benefit | 451 | - | - | - | 451 | |||||||||||||||
| Net income (loss) | $ | 23,980 | $ | (23,723 | ) | $ | - | $ | - | $ | 257 | |||||||||
F-27
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2007
| (Dollars in thousands) | Non- | |||||||||||||||||||
| Guarantor | Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Entities | Eliminations | Consolidated | ||||||||||||||||
| Operating activities | $ | 149,216 | $ | 60,738 | $ | 23,225 | $ | 1,687 | $ | 234,866 | ||||||||||
| Investing activities | (189,626 | ) | (21,303 | ) | (24,143 | ) | (1,187 | ) | (236,259 | ) | ||||||||||
| Financing activities | 39,620 | (39,445 | ) | 222 | (500 | ) | (103 | ) | ||||||||||||
| Net decrease in | ||||||||||||||||||||
| cash and cash equivalents | (790 | ) | (10 | ) | (696 | ) | - | (1,496 | ) | |||||||||||
| Cash at the beginning of | ||||||||||||||||||||
| the period | 6,116 | 1,298 | 6,426 | - | 13,840 | |||||||||||||||
| Cash at end of the period | $ | 5,326 | $ | 1,288 | $ | 5,730 | $ | - | $ | 12,344 | ||||||||||
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2006
| (Dollars in thousands) | Non- | |||||||||||||||||||
| Guarantor | Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Entities | Eliminations | Consolidated | ||||||||||||||||
| Operating activities | $ | 50,130 | $ | 65,343 | $ | 30,229 | $ | 288 | $ | 145,990 | ||||||||||
| Investing activities | (215,405 | ) | (22,007 | ) | (72,753 | ) | 212 | (309,953 | ) | |||||||||||
| Financing activities | 167,089 | (43,671 | ) | 48,950 | (500 | ) | 171,868 | |||||||||||||
| Net increase (decrease) in | ||||||||||||||||||||
| cash and cash equivalents | 1,814 | (335 | ) | 6,426 | - | 7,905 | ||||||||||||||
| Cash at the beginning of | ||||||||||||||||||||
| the period | 4,302 | 1,633 | - | - | 5,935 | |||||||||||||||
| Cash at end of the period | $ | 6,116 | $ | 1,298 | $ | 6,426 | $ | - | $ | 13,840 | ||||||||||
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2005
| (Dollars in thousands) | Non- | |||||||||||||||||||
| Guarantor | Guarantor | Adjustments/ | ||||||||||||||||||
| Issuer | Subsidiaries | Entities | Eliminations | Consolidated | ||||||||||||||||
| Operating activities | $ | 141,878 | $ | 21,597 | $ | - | $ | - | $ | 163,475 | ||||||||||
| Investing activities | (154,102 | ) | (42,563 | ) | - | - | (196,665 | ) | ||||||||||||
| Financing activities | 13,794 | 8,972 | - | - | 22,766 | |||||||||||||||
| Net increase (decrease) in | ||||||||||||||||||||
| cash and cash equivalents | 1,570 | (11,994 | ) | - | - | (10,424 | ) | |||||||||||||
| Cash at the beginning of | ||||||||||||||||||||
| the period | 2,732 | 13,627 | - | - | 16,359 | |||||||||||||||
| Cash at end of the period | $ | 4,302 | $ | 1,633 | $ | - | $ | - | $ | 5,935 | ||||||||||
F-28
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20. Oil and Gas Reserve Information (Unaudited)
The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the SEC and the FASB, 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 2007 and 2006, see Note 18, and for 2005, 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, 2007, 2006 and 2005.
| Oil | Gas | MMcfe | ||||||||||
| Proved reserves: | ||||||||||||
| December 31, 2004 | 26,793 | 138,278 | 299,036 | |||||||||
Revisions | 2,193 | (5,333 | ) | 7,825 | ||||||||
Extensions and discoveries | 868 | 12,476 | 17,684 | |||||||||
Sales of minerals-in-place | (101 | ) | (2,922 | ) | (3,528 | ) | ||||||
Purchases of minerals-in-place | 586 | 667 | 4,183 | |||||||||
Production | (2,504 | ) | (16,408 | ) | (31,432 | ) | ||||||
| December 31, 2005 | 27,835 | 126,758 | 293,768 | |||||||||
Revisions | (2,383 | ) | (14,402 | ) | (28,700 | ) | ||||||
Extensions and discoveries | 1,367 | 21,204 | 29,406 | |||||||||
Purchases of minerals-in-place | 932 | 805 | 6,397 | |||||||||
Production | (2,370 | ) | (15,198 | ) | (29,418 | ) | ||||||
| December 31, 2006 | 25,381 | 119,167 | 271,453 | |||||||||
Revisions | 3,194 | 1,761 | 20,925 | |||||||||
Extensions and discoveries | 1,902 | 23,533 | 34,945 | |||||||||
Sales of minerals-in-place | - | (624 | ) | (624 | ) | |||||||
Production | (2,531 | ) | (20,681 | ) | (35,867 | ) | ||||||
| December 31, 2007 | 27,946 | 123,156 | 290,832 | |||||||||
| Proved developed reserves: | ||||||||||||
| December 31, 2005 | 21,503 | 91,366 | 220,384 | |||||||||
| December 31, 2006 | 18,872 | 90,217 | 203,450 | |||||||||
| December 31, 2007 | 20,627 | 98,434 | 222,196 | |||||||||
Net upward revisions of 20.9 Bcfe in 2007 consisted of approximately 23.9 Bcfe of upward revisions attributable to the effects of higher product prices on the estimated quantities of proved reserves and downward revisions of approximately 3 Bcfe attributable to lower well performance, primarily in South Louisiana partially offset by upward revisions in the Permian Basin, the Austin Chalk (Trend) and California.
F-29
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| 2007 | 2006 | 2005 | ||||||||||
| (In thousands) | ||||||||||||
| Future cash inflows | $ | 3,363,271 | $ | 1,991,628 | $ | 2,910,325 | ||||||
| Future costs: | ||||||||||||
Production | (999,945 | ) | (685,021 | ) | (811,529 | ) | ||||||
Development | (174,264 | ) | (160,264 | ) | (161,921 | ) | ||||||
Income taxes | (653,808 | ) | (293,870 | ) | (612,771 | ) | ||||||
| Future net cash flows | 1,535,254 | 852,473 | 1,324,104 | |||||||||
| 10% discount factor | (609,285 | ) | (337,673 | ) | (570,392 | ) | ||||||
| Standardized measure of discounted net cash flows | $ | 925,969 | $ | 514,800 | $ | 753,712 | ||||||
Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2007, 2006 and 2005 were as follows:
| 2007 | 2006 | 2005 | ||||||||||
| (In thousands) | ||||||||||||
| Standardized measure, beginning of period | $ | 514,800 | $ | 753,712 | $ | 500,198 | ||||||
| Net changes in sales prices, net of production costs | 483,032 | (356,919 | ) | 458,744 | ||||||||
| Revisions of quantity estimates | 82,451 | (76,332 | ) | 35,741 | ||||||||
| Accretion of discount | 70,844 | 111,789 | 58,095 | |||||||||
| Changes in future development costs, including | ||||||||||||
| development costs incurred that reduced future | ||||||||||||
| development costs | 2,665 | 11,665 | (21,368 | ) | ||||||||
| Changes in timing and other | 24,497 | (37,086 | ) | (20,024 | ) | |||||||
| Net change in income taxes | (203,369 | ) | 174,488 | (154,401 | ) | |||||||
| Future abandonment cost, net of salvage | (4,204 | ) | (7,880 | ) | (4,657 | ) | ||||||
| Extensions and discoveries | 197,219 | 113,110 | 100,302 | |||||||||
| Sales, net of production costs | (240,733 | ) | (181,280 | ) | (195,195 | ) | ||||||
| Sales of minerals-in-place | (1,233 | ) | - | (13,781 | ) | |||||||
| Purchases of minerals-in-place | - | 9,533 | 10,058 | |||||||||
| Standardized measure, end of period. | $ | 925,969 | $ | 514,800 | $ | 753,712 | ||||||
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, 2007, 2006 and 2005 were as follows:
| Average Price | ||||||||
| Oil (a) | Gas | |||||||
As of December 31: | ||||||||
2007 | $ | 91.30 | $ | 7.37 | ||||
2006 | $ | 57.18 | $ | 5.24 | ||||
2005 | $ | 57.85 | $ | 10.65 | ||||
(a) Includes natural gas liquids
F-30
CLAYTON WILLIAMS ENERGY, INC.
| Schedule II – Valuation and Qualifying Accounts | ||||||||||||||||
| Balance at | Balance at | |||||||||||||||
| Beginning of | End of | |||||||||||||||
| Description | Period | Additions(a) | Deductions(b) | Period | ||||||||||||
| (In thousands) | ||||||||||||||||
| Year Ended December 31, 2007: | ||||||||||||||||
Allowance for doubtful accounts - Joint interest and other | $ | 1,044 | $ | 343 | $ | - | $ | 1,387 | ||||||||
| Year Ended December 31, 2006: | ||||||||||||||||
Allowance for doubtful accounts - Joint interest and other | $ | 1,087 | $ | - | $ | (43 | ) | $ | 1,044 | |||||||
| Year Ended December 31, 2005: | ||||||||||||||||
Allowance for doubtful accounts - Joint interest and other | $ | 1,013 | $ | 89 | $ | (15 | ) | $ | 1,087 | |||||||
(a) Additions relate to provisions for doubtful accounts. | ||||||||||||||||
(b) Deductions relate to the write-off or recovery of the provisions for doubtful accounts. | ||||||||||||||||
S-1