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Clayton Williams Energy 10-K 2006

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-K

 

(Mark One)

ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

 

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2005

 

 

 

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

 

OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                 to                

 

Commission File Number 001-10924

 

CLAYTON WILLIAMS ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

75-2396863

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

Six Desta Drive - Suite 6500

 

 

Midland, Texas

 

79705-5510

(Address of principal executive offices)

 

(Zip code)

 

 

 

Registrant’s telephone number, including area code:

 

(432) 682-6324

 

 

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

None

 

 

 

Securities registered pursuant to Section 12(g) of the Act:

 

 

 

Common Stock - $.10 Par Value

(Title of Class)

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes                    ý No

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
o Yes                    ý No

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes   ý                        No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     ý

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer  o                               Accelerated filer  ý                             Non-accelerated filer  o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes        ý No

 

State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which common equity was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter.  $186,312,403.

 

There were 10,848,450 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 14, 2006.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the definitive proxy statement relating to the 2006 Annual Meeting of Stockholders, which will be filed with the Commission not later than April 30, 2006, are incorporated by reference in Part III of this Form 10-K.

 

 



 

CLAYTON WILLIAMS ENERGY, INC

TABLE OF CONTENTS

 

Part I

 

 

Item 1.

Business

 

 

General

 

 

Company Profile

 

 

Exploration and Development Activities

 

 

Marketing Arrangements

 

 

Natural Gas Services

 

 

Competition and Markets

 

 

Regulation

 

 

Environmental Matters

 

 

Title to Properties

 

 

Operational Hazards and Insurance

 

 

Executive Officers

 

 

Employees

 

 

Website Address

 

Item 1A.

Risk Factors

 

Item 1B.

Unresolved Staff Comments

 

 

 

 

Item 2.

Properties

 

 

Reserves

 

 

Exploration and Development Activities

 

 

Productive Well Summary

 

 

Volumes, Prices and Production Costs

 

 

Development, Exploration and Acquisition Expenditures

 

 

Acreage

 

 

Offices

 

 

 

 

Item 3.

Legal Proceedings

 

 

 

 

Item 4.

Submission of Matters to a Vote of Security Holders

 

 

 

 

Part II

 

 

Item 5.

Market for the Registrant’s Common Stock and Related

 

 

Stockholder Matters

 

 

Price Range of Common Stock

 

 

Dividend Policy

 

 

Securities Authorized for Issuance under Equity Compensation Plans

 

 

 

 

Item 6.

Selected Financial Data

 

 

 

 

Item 7.

Management’s Discussion and Analysis of Financial Condition and

 

 

Results of Operations

 

 

Overview

 

 

Key Factors to Consider

 

 

Recent Exploration and Developmental Activities

 

 

Proved Oil and Gas Reserves

 

 

1



 

 

Supplemental Information

 

 

Operating Results

 

 

Liquidity and Capital Resources

 

 

Known Trends and Uncertainties

 

 

Application of Critical Accounting Policies and Estimates

 

 

Recent Accounting Pronouncements

 

 

 

 

Item 7A.

Quantitative and Qualitative Disclosure About Market Risks

 

 

Oil and Gas Prices

 

 

Interest Rates

 

 

 

 

Item 8.

Financial Statements and Supplementary Data

 

 

 

 

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

 

 

 

Item 9A.

Controls and Procedures

 

 

Disclosure Controls and Procedures

 

 

Internal Control Over Financial Reporting

 

 

Changes in Internal Control Over Financial Reporting

 

 

Management’s Report on Internal Control Over Financial Reporting

 

 

 

 

Item 9B.

Other Information

 

 

 

 

Part III

 

 

Items 10-14.

Information Incorporated by Reference

 

 

 

 

Part IV

 

 

Item 15.

Exhibits, Financial Statement Schedules and Reports on Form 8-K

 

 

Financial Statements and Schedules

 

 

Exhibits

 

 

 

 

Glossary of Terms

 

 

 

 

Signatures

 

 

 

2



 

This Annual Report on Form 10-K contains forward-looking statements that are based on management’s current expectations.  Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions.  Forward-looking statements appear throughout this Form 10-K with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations.  Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Item 1 – Business – Risk Factors” and elsewhere in this report.  We disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

Definitions of terms commonly used in the oil and gas industry and in this Form 10-K can be found in the Glossary of Terms.

 

PART I

 

Item 1 -                  Business

 

General

 

Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in Texas, Louisiana and New Mexico.  Unless the context otherwise requires, references to the “Company”, “CWEI”, “we”, “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries.  On December 31, 2005, our estimated proved reserves were 293.8 Bcfe, of which 75% were proved developed.  We have a balanced portfolio of oil and natural gas reserves, with approximately 43% of our proved reserves at December 31, 2005 consisting of natural gas and approximately 57% consisting of oil and natural gas liquids.  During 2005, we added proved reserves of 17.7 Bcfe through extensions and discoveries, had upward revisions of previous estimates of 7.8 Bcfe, acquired 4.2 Bcfe through acquisitions and sold 3.5 Bcfe of reserves in place.  We also achieved average net production of 86.1 Mmcfe per day in 2005, which implies a reserve life of approximately 9.3 years.  CWEI held interests in 6,605 gross (899.7 net) producing oil and gas wells and owned leasehold interests in approximately 1.2 million gross (778,000 net) undeveloped acres at December 31, 2005.

 

Clayton W. Williams beneficially owns, either individually or through his affiliates, approximately 45% of the outstanding shares of our common stock.  Mr. Williams is also our Chairman of the Board and Chief Executive Officer.  As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of our Board members.  Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations.

 

In 2006, we plan to spend approximately $184.1 million on exploration and development activities, of which more than 90% relate to exploratory prospects.  Approximately 78% of these planned expenditures in 2006 have been allocated to exploration and development activities in Louisiana.

 

3



 

Company Profile

 

Domestic Operations

 

We conduct all of our drilling, exploration and production activities in the United States.  All of our oil and gas assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.

 

Exploration Program

 

Our primary business strategy is to grow our oil and gas reserves through exploration activities, consisting of generating exploratory prospects, leasing the acreage applicable to the prospects, drilling exploratory wells on these prospects to determine if recoverable oil and gas reserves exist, drilling developmental wells on prospects, and producing and selling any resulting oil and gas production.

 

To generate a typical exploratory prospect, we first identify geographical areas that we believe may contain undiscovered oil and gas reserves.  We then consider many other business factors related to those geographical areas, including proximity to our other areas of operations, our technical knowledge and experience in the area, the availability of acreage, and the overall potential for finding reserves.  Most of our current exploration efforts are concentrated in regions that have been known to produce oil and gas.  These regions include some of the larger producing regions in Texas and Louisiana.

 

In most cases, we then obtain and process seismic data using sophisticated geophysical technology to attempt to visualize underground structures and stratigraphic traps that may hold recoverable reserves.  Although this technology increases our expectations of a successful discovery, it does not and cannot assure us of success.  Many factors are involved in the interpretation of seismic data, including the field recording parameters of the data, the type of processing, the extent of attribute analyses, the availability of subsurface geological data, and the depth and complexity of the subsurface.  Significant judgment is required in the evaluation of seismic data, and differences of opinion often exist between experienced professionals.  These interpretations may turn out to be invalid and may result in unsuccessful drilling results.

 

Obtaining oil and gas reserves through exploration activities involves a higher degree of risk than through drilling developmental wells or purchasing proved reserves.  We often commit significant resources to identify a prospect, lease the drilling rights and drill a test well before we know if a well will be productive.  To offset this risk, our typical exploratory prospect is expected to offer a significantly higher reserve potential than a typical lower-risk development prospect might offer.  The reserve potential is determined by estimating the aerial extent of the structural or stratigraphic trap, the vertical thickness of the reservoir in the trap, and the recovery factor of the hydrocarbons in the trap.  The recovery factor is affected by a combination of factors including (i) the reservoir drive mechanism (water drive, depletion drive or a combination of both), (ii) the permeability and porosity of the reservoir, and (iii) the bottom hole pressure (in the case of gas reserves).

 

Due to the high risk/high reward nature of oil and gas exploration, we expect to spend money on prospects that are ultimately nonproductive.  However, over time, we believe our productive prospects will generate sufficient cash flow to provide us with an acceptable rate of return on our entire investment, both nonproductive and productive.

 

We are presently concentrating our exploration efforts in South Louisiana, North Louisiana and East Texas.  Approximately 90% of our planned expenditures for 2006 relate to exploratory prospects, as compared to approximately 73% of actual expenditures in 2005 and 81% of actual expenditures in 2004.  During 2005, we spent $134.6 million on exploratory prospects, including $55.7 million on seismic and leasing activities and $78.9 million on drilling activities.

 

4



 

Development Program

 

Complimentary to our higher risk/higher potential exploration program is our development program.  We have an inventory of developmental projects available for drilling in the future.  At December 31, 2005, we had proved developed nonproducing reserves and proved undeveloped reserves of 104.8 Bcfe.  We currently estimate that we will be required to spend approximately $161.9 million in development costs to develop these reserves.  Substantially all of these reserves are associated with leases that are held by production.  Because current drilling activity is not required to maintain these leases, we have decided to limit expenditures on our developmental program in 2006 in order to preserve more capital resources for our exploratory activities in areas where we have leases that will expire unless commercial production is commenced before the end of their current lease terms.  We expect to allocate a more significant portion of our capital expenditures to development activities in years after 2006.

 

Acquisition and Divestitures of Proved Properties

 

In addition to our exploration and development activities, we are also engaged in the business of acquiring proved reserves.  Competition for the purchase of proved reserves is intense.  Sellers often utilize a bid process to sell properties.  This process usually intensifies the competition and makes it extremely difficult for us to acquire reserves without assuming significant price and production risks.  We are actively searching for opportunities to acquire proved oil and gas properties; however, because the competition is intense, we cannot give any assurance that we will be successful in our efforts during 2006.

 

In 2005, we acquired a property in Ward County, Texas which consisted of ten producing wells and eight proved undeveloped locations.  This acquisition added approximately 4.2 Bcfe of proved reserves for a purchase price of $5.6 million.

 

On May 21, 2004, we acquired all the outstanding common stock of Southwest Royalties, Inc. (“SWR”) through a merger.  Prior to the acquisition, SWR was a privately-held, Midland-based energy company engaged in oil and gas exploration, production, development and acquisition activities in the United States.  Most of SWR’s properties are located in the Permian Basin.  Using reserve guidelines established by the SEC, the SWR acquisition added approximately 170.8 Bcfe to our proved oil and gas reserves on the effective date of the acquisition at an aggregate purchase price of $274.7 million.

 

From time to time, we decide to sell certain of our proved properties.  In August 2005, we sold our interests in two leases in the Breton Sound area in the Gulf of Mexico (offshore Louisiana) for $21.3 million, subject to post-closing adjustments and realized a gain of $16.8 million on this sale.  In November 2004, we sold our interest in the Jo-Mill Unit in Borden County, Texas for cash proceeds of $22.1 million, subject to normal post-closing adjustments.  This property was acquired in connection with the SWR acquisition.  We realized a gain on sale of this property of $2.1 million.  In December 2004, we sold substantially all of our interests in the Romere Pass Unit in Plaquemines Parish, Louisiana for cash proceeds of $8.2 million, subject to normal post-closing adjustments.  We retained drilling rights to five locations in the unit, of which two are proved undeveloped locations and three are exploratory locations.  We realized a loss of $14.1 million on the sale of this property.

 

Exploration and Development Activities

 

In 2005, we spent $184.1 million on exploration and drilling activities, which was financed primarily by cash flow from operations and in part by proceeds from sales of oil and gas properties.  We presently plan to spend approximately $184.1 million on exploration and drilling activities during 2006.  We may increase or decrease our planned activities, depending upon drilling results, product prices, the availability of capital resources, and other factors affecting the economic viability of such activities.

 

5



 

South Louisiana

 

Since 2000, we have been exploring for oil and gas reserves in South Louisiana and have developed this area into one of our key sources of production and cash flow.  Most of the prospects we have generated in South Louisiana have been identified based on 3-D seismic data and technology and have generally consisted of multi-pay, Miocene-age sands.

 

We spent $41.2 million in South Louisiana during 2005 on exploration and development activities, of which $32.8 million was spent on drilling and completion activities and $8.4 million was spent on seismic and leasing activities.

 

Prior to 2005, we had drilled 47 gross (37.7 net) exploratory wells in South Louisiana, of which 20 gross (14.7 net) were completed as producers.  The following table sets forth certain information about our exploratory well activities in South Louisiana in 2005.

 

Spud Date

 

Well Name (Prospect)

 

Working
Interest

 

Current
Status

 

 

 

 

 

 

 

February 2005

 

State Lease 18065 #1 (Alabama)

 

100

%

Producing

July 2005

 

Ransom #1 (Keck)

 

50

%

Producing

August 2005

 

State Lease 17636 #1 (Natalie)

 

30

%

Dry

August 2005

 

LL&E #1 (Andrea)

 

70

%

Dry

November 2005

 

Miami Corp #1 (Tara)

 

100

%

Pending completion

December 2005

 

State lease 195 QQ #1 (Floyd)

 

75

%

Completion in progress

 

More than half of the wells in our South Louisiana exploration program that were commenced in 2005 were productive and resulted in the addition of approximately 8.7 Bcfe of proved reserves in 2005.  However, the LL&E #1 (Andrea) and the State Lease 17636 #1 (Natalie) were unsuccessful and resulted in aggregate abandonment charges of $10.7 million in 2005.

 

We currently plan to spend $56.3 million in South Louisiana in 2006 to generate and lease new exploratory prospects and to drill wells on existing exploratory prospects.  We have begun a six-well program on our Floyd prospect in Plaquemines Parish targeting multi-pay objectives ranging in depths from 3,000 to 13,000 feet.  The State Lease 195 QQ #1 was drilled to a total depth of 12,981 feet and is currently being completed.  The State Lease 195 QQ #2 has been drilled to a total depth of 6,296 feet and is pending completion.  The State Lease 195 QQ #3 has been drilled to a total depth of 9,170 feet, and is also pending completion.  The State Lease 195 QQ #4 is currently drilling.  Under the terms of a farmout agreement, we bear 100% of the costs on these wells before casing point to earn a 75% working interest in the drilled acreage.

 

We are currently drilling the Borah #1 (Cypress Isle), a 17,000-foot exploratory well in St. Martin Parish targeting the MA-11 and MA-12 sands, in which we own a 75% working interest.

 

North Louisiana

 

We have begun an exploration program in North Louisiana targeting the Cotton Valley/Hosston and Bossier formations.  In this area, the Cotton Valley/Hosston formations are encountered at depths ranging from 8,000 to 12,000 feet, and the Bossier formation is encountered at depths ranging from 11,000 to 15,500 feet.  We believe that these tight sandstone formations have become more economically viable due to higher product prices, coupled with enhanced drilling and completion techniques.

 

We spent $18.9 million in North Louisiana during 2005 on exploration activities, of which $16.8 million was spent on seismic and leasing activities and $2.1 million was spent on drilling and completion activities on non-operated wells.

 

6



 

We have accumulated more than 115,000 net acres in this area, and to date have participated in six non-operated wells on a small portion of this acreage, four of which are currently being completed and two are in progress.  We are currently drilling the Harris #1, a 14,500-foot well in Jackson Parish targeting the Bossier formation, in which we own a 53% working interest.  We plan to spend approximately $87.9 million in North Louisiana in 2006, consisting of $17.2 million to acquire leases and conduct seismic and exploration activities, and $70.7 million on drilling.

 

East Texas (Bossier)

 

We have also begun acquiring leases in East Texas targeting the Bossier formation which is encountered at depths ranging from 14,000 to 22,000 feet in this area.  To date, we have acquired approximately 28,000 net acres and are actively seeking to add to our acreage position.  We spent $4.9 million on acreage in East Texas in 2005 and plan to spend approximately $20 million for additional acreage in 2006.  We anticipate drilling activity on this acreage to begin in 2007.

 

Permian Basin

 

We spent $84.5 million in the Permian Basin during 2005 on exploration and development activities, of which $74.5 million was spent on drilling and completion activities and $10 million was spent on seismic and leasing activities.

 

In 2005, we initiated an exploration program in West Texas seeking to extend the limits of the Wolfcamp formation that is encountered throughout a large segment of this region.  We acquired more than 50,000 net acres and have drilled 11 wells across a wide portion of this acreage.  While all of the wells were completed as producers, the oil and gas reserves derived from this drilling program were inadequate to recover our capitalized costs.  As a result, we recorded an $18.3 million charge for impairment of proved properties and a $1.8 million charge for impairment of unproved property in 2005 related to our Wolfcamp program.

 

We also drilled the Leoncita #1, a 9,300-foot exploratory well in Pecos County, Texas targeting the Barnett Shale.  This well was unsuccessful and resulted in a $4.5 million charge to exploration costs in 2005.

 

In addition, we drilled 24 gross (20.2 net) wells in the Permian Basin and conducted remedial operations on existing wells in 2005.  While some of the drilling activities in 2005 did not result in the quantities of oil and gas reserves that we had expected, the Permian Basin continues to be a significant source of production and cash flow for us.  We currently plan to spend $6.7 million on drilling activities in the Permian Basin in 2006.

 

Montana/Utah

 

We spent $11.8 million in Montana and Utah during 2005 on seismic and leasing activities.  We initiated an exploration program in Sheridan County, Montana targeting the Bakken Shale which is encountered at depths ranging from 7,000 to 8,000 feet in this area.  We are currently drilling the Ruegsegger 24H #1, an exploratory well which we plan to drill to a vertical depth of 7,600 feet, then drill 3,600 feet horizontally through the shale formation.  We plan to spend approximately $3.5 million for drilling in this area in 2006.

 

In addition, we are participating in a joint exploration program with industry partners in the Overthrust play in central Utah in which we own a 33% interest.  In 2006, we plan to spend approximately $2.5 million to participate in the drilling of a 14,400-foot exploratory well to test this acreage.

 

7



 

Other Exploration and Development Activities

 

During 2005, we spent $22.8 million on exploration and development activities in other areas, including:

 

              $8 million in South Texas to drill the Deer-Hamilton #1 well, a 17,000-foot exploratory well in Nueces County targeting the Vicksburg formation, which was unsuccessful;

 

              $2.2 million of drilling activities related to the Catherine Destefano #1 well, a 14,600-foot exploratory well in Robertson County, Texas targeting the Knowles formation, which was unsuccessful; and

 

              $3.4 million in leasing activities in the Neal Shale prospect in Alabama.

 

In 2006, we currently plan to spend $7.2 million in other areas, including:

 

              $4.1 million for leasing and production enhancement activities in the Austin Chalk (Trend); and

 

              $3.1 million for leasing and drilling activities in Colorado and other areas.

 

Marketing Arrangements

 

We sell substantially all of our oil production under short-term contracts based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate contracts, less agreed-upon deductions which vary by grade of crude oil.  The majority of our gas production is sold under short-term contracts based on pricing formulas which are generally market responsive.  From time to time, we may also sell a portion of our gas production under short-term contracts at fixed prices.  We believe that the loss of any of our oil and gas purchasers would not have a material adverse effect on our results of operations due to the availability of other purchasers.

 

Natural Gas Services

 

We own an interest in and operate natural gas service facilities in the states of Texas, Louisiana, Mississippi and New Mexico. These natural gas service facilities consist of interests in approximately 94 miles of pipeline, three treating plants, one dehydration facility, three compressor stations, and four wellhead type treating and/or compression facilities.  Most of our operated gas gathering and treating activities exist to facilitate the transportation and marketing of our operated oil and gas production.

 

Competition and Markets

 

Competition in all areas of our operations is intense.  We experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.  Our ability to increase reserves in

 

8



 

the future will depend on our success at selecting and acquiring suitable producing properties and prospects for future development and exploration activities.

 

In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.  The price and availability of alternative energy sources could adversely affect our revenue.

 

The market for our oil, gas and natural gas liquids production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

 

Regulation

 

Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

 

All of the states in which we operate generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from our properties.

 

The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production.  Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas.  These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed.  These FERC actions were designed to increase competition within all phases of the gas industry.  The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

 

Our sales of oil and natural gas liquids are not presently regulated and are made at market prices.  The price we receive from the sale of those products is affected by the cost of transporting the products to market.  The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations.  We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

 

9



 

Environmental Matters

 

Our operations pertaining to oil and gas exploration, production and related activities are subject to numerous and constantly changing federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection.  These laws and regulations may require the acquisition of certain permits prior to or in connection with drilling activities, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production, restrict or prohibit drilling activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources, require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells, and impose substantial liabilities for pollution resulting from our operations.  Such laws and regulations may substantially increase the cost of exploring for, developing, producing or processing oil and gas and may prevent or delay the commencement or continuation of a given project and thus generally could have a material adverse effect upon our capital expenditures, earnings, or competitive position.  Violation of these laws and regulations could result in significant fines or penalties.  We have experienced accidental spills, leaks and other discharges of contaminants at some of our properties, as have other similarly situated oil and gas companies, and some of the properties that we have acquired, operated or sold, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible.  Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas.  Some of our properties are located in areas particularly susceptible to hurricanes and other destructive storms, which may damage facilities and cause the release of pollutants. Our environmental insurance coverage may not fully insure all of these risks. Although the costs of remedying such conditions may be significant, we do not believe these costs will have a material adverse impact on our financial condition and operations.

 

We believe that we are in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2006.  We do not believe that we will be required to incur any material capital expenditures to comply with existing environmental requirements.  Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on our operating, as well as the oil and gas industry in general.  For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas production wastes as “hazardous wastes,” which reclassification would make exploration and production wastes subject to much more stringent handling, disposal and clean-up requirements.  State initiatives to further regulate the disposal of oil and gas wastes and naturally occurring radioactive materials, if adopted, could have a similar impact on us.

 

The United States Oil Pollution Act of 1990 (“OPA ‘90”), and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA ‘90 and such similar legislation and related regulations impose on us a variety of obligations related to the prevention of oil spills and liability for damages resulting from such spills.  OPA ‘90 imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil removal costs and a variety of public and private damages.

 

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment.  These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred.  Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for

 

10



 

neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  We are able to control directly the operation of only those wells with respect to which we act as operator.  Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us.  We are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

 

The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws govern the handling and disposal of hazardous and solid wastes. Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal and reporting requirements. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes.  However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes.  Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

 

The Clean Air Act, and comparable state and local requirements, contain provisions that may result in the imposition of pollution control requirements with respect to air emissions from certain of our operations. Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by us. We do not believe that our operations will be materially adversely affected by any such requirements.

 

State water discharge regulations and federal waste discharge permitting requirements adopted pursuant to the Federal Water Pollution Control Act prohibit or are expected in the future to prohibit the discharge of produced water and sand and some other substances related to the oil and gas industry, into coastal waters.  Although the costs to comply with such mandates under state or federal law may be significant, the entire industry will experience similar costs, and we do not believe that these costs will have a material adverse impact on our financial condition and operations.

 

Claims are sometimes made or threatened against companies engaged in oil and gas exploration and production by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, in other jurisdictions in which we operate, courts have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.

 

Title to Properties

 

As is customary in the oil and gas industry, we perform a minimal title investigation before acquiring undeveloped properties.  A title opinion is obtained prior to the commencement of drilling operations on such properties.  We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry.  These title investigations and title opinions, while consistent with industry standards, may not reveal existing or potential title defects, encumbrances or adverse claims as we are subject from time to time to claims or disputes regarding title to properties.  Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our oil and gas properties are currently mortgaged to secure

 

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borrowings under our revolving credit facility and may be mortgaged under any future credit facilities entered into by us.

 

Operational Hazards and Insurance

 

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires and pollution and other environmental risks.  These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation.  In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.

 

We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry.  We believe the coverage and types of insurance are adequate.  The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations.  We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.

 

Executive Officers

 

The following is a list, as of March 16, 2006 of the name, age and position with the Company of each person who is an executive officer of the Company:

 

CLAYTON W. WILLIAMS, age 74, is Chairman of the Board, President, Chief Executive Officer and a director of the Company, having served in such capacities since September 1991.  For more than the past five years, Mr. Williams has also been the chief executive officer and director of certain entities which are controlled directly or indirectly by Mr. Williams.

 

L. PAUL LATHAM, age 54, is Executive Vice President, Chief Operating Officer and a director of the Company, having served in such capacities since September 1991.  Mr. Latham also serves as an officer and director of certain entities controlled by Mr. Williams.

 

MEL G. RIGGS, age 51, is Senior Vice President and Chief Financial Officer of the Company, having served in such capacities since September 1991.  Mr. Riggs has served as a director of the Company since May 1994.

 

PATRICK C. REESBY, age 53, is Vice President – New Ventures of the Company, having served in such capacity since 1993.

 

ROBERT C. LYON, age 69, is Vice President – Gas Gathering and Marketing of the Company, having served in such capacity since 1993.

 

MICHAEL L. POLLARD, age 56, is Vice President – Accounting of the Company, having served in such capacity since 2003.  Prior to that, Mr. Pollard had served as Controller of the Company since 1993.

 

T. MARK TISDALE, age 49, is Vice President and General Counsel of the Company, having served in such capacity since 1993.

 

GREGORY S. WELBORN, age 32, is Vice President – Land of the Company, having served in such capacity since 2006.

 

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Employees

 

At December 31, 2005, we had 174 full-time employees, none of whom is subject to a collective bargaining agreement.  In our opinion, our relations with employees are good.

 

Website Address

 

The Company maintains an internet website at www.claytonwilliams.com.  The Company makes available, free of charge, on its website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC.  The information contained in or incorporated in our website is not part of this report.

 

Item 1A -       Risk Factors

 

There are many factors that affect our business, some of which are beyond our control.  Our business, financial condition and results of operations could be materially adversely affected by any of these risks.  The risks described below are not the only ones facing our company.  Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations.

 

Our exploration activities subject us to greater risks than development activities.

 

For 2006, approximately 90% of our planned capital expenditures relate to exploratory prospects. Exploration is a higher risk activity than development. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to increasing oil or natural gas production from an area that is known to be productive by drilling additional wells, working over and recompleting existing wells and other production enhancement techniques. Exploration projects are identified through subjective analysis of geological and geophysical data, including the use of 3-D seismic and other available technology. By comparison, the identification of development prospects is significantly based upon existing production surrounding or adjacent to the proposed drilling site.

 

Because we engage in exploration activities, we have a greater risk of drilling dry holes or not finding oil and natural gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or natural gas is present or can be produced economically. We charged to expense $40 million in 2005 for abandonment and impairment, most of which was related to unsuccessful exploratory drilling activities in South Louisiana, the Black Warrior Basin of Mississippi and the Cotton Valley/Knowles area of East Texas.  We cannot assure you that any of our future exploration efforts will be successful. If these activities are unsuccessful, it will have a significant adverse affect on our results of operations, cash flow and capital resources.

 

If we do not replace reserves we produce, our financial results will suffer.

 

In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. Historically, our oil and gas properties have had steep rates of decline and short estimated productive lives. The implied life of our proved reserves at December 31, 2005 is approximately 9.3 years, based on 2005 production levels.

 

Our oil and gas reserves will decline as they are produced unless we are able to conduct successful exploration and development activities or acquire properties with proved reserves. Because we are

 

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engaged to a large extent in exploration activities, our ability to replace produced reserves is subject to a higher level of risk than when we were drilling development wells in the Austin Chalk (Trend).

 

Volatility of oil and gas prices significantly affects our cash flow and capital resources and our ability to produce oil and gas economically.

 

Historically, the markets for oil and gas have been volatile, and we believe that they are likely to continue to be volatile. Significant changes in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control. We cannot predict, with any degree of certainty, future oil and natural gas prices. Changes in oil and natural gas prices significantly affect our revenues, operating results, profitability and the value of our oil and gas reserves. Those prices also affect the amount of cash flow available for capital expenditures, our ability to borrow money or raise additional capital and the amount of oil and natural gas that we can produce economically. The amount we can borrow under our senior revolving credit facility is subject to periodic redeterminations based in part on current prices for oil and natural gas at the time of the redetermination.

 

Changes in oil and gas prices impact both our estimated future net revenue and the estimated quantity of proved reserves. Price increases may permit additional quantities of reserves to be produced economically, and price decreases may render uneconomic the production of reserves previously classified as proved. Thus, we may experience material increases and decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance. We attempt to optimize the price we receive for our oil and gas production while maintaining a prudent hedging program to mitigate our exposure to declining product prices. Our management may elect to enter into and terminate hedges based on expectations of future market conditions. If prices continue to rise while our hedges are in place, we will forego revenue we would have otherwise received. If we terminate a hedge because we anticipate an increase in product prices that we would not realize with the hedge in place, and product prices do not increase as anticipated, we may be exposed to downside risk that would not have existed otherwise.

 

Our liquidity, including the availability of capital resources, is uncertain.

 

Our cash flow forecasts indicate that the amount of funds available to us under our revolving credit facility, when combined with our anticipated operating cash flow, will be sufficient to finance our capital expenditures and will provide us with adequate liquidity at least through 2006.  Although we believe the assumptions and estimates made in our forecasts are reasonable, uncertainties exist which could cause the borrowing base to be less than expected, cash flow to be less than expected, or capital expenditures to be more than expected.  Below is a discussion of uncertainties that are likely to have a material effect on our liquidity and capital resources if such uncertainties occur.

 

Adverse changes in reserve estimates or commodity prices could reduce the borrowing base.  The banks establish the borrowing base at least twice annually by preparing a reserve report using price-risk assumptions they believe are proper under the circumstances.  Any adverse changes in estimated quantities of reserves, the pricing parameters being used, or the risk factors being applied, since the date of the last borrowing base determination, could lower the borrowing base under the revolving credit facility.

 

Adverse changes in reserve estimates or commodity prices could reduce our cash flow from operating activities.  We rely on estimates of reserves to forecast our cash flow from operating activities.  If the production from those reserves is delayed or is lower than expected, our cash flow from operating activities may be lower than we anticipated.  Commodity prices also impact our cash flow from operating activities.  Based on December 31, 2005 reserve estimates, we project that a $1.00 drop in oil price and a $.50 drop in gas price would reduce our gross revenues in 2006 by approximately $2.3 million and $8.7 million, respectively.

 

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Adverse changes in the borrowing base may cause outstanding debt to equal or exceed the borrowing base.  In this event, we will not be able to borrow any additional funds, and we will be required to repay the excess or convert the debt to a term note.  Without availability under the revolving credit facility, we may be unable to meet our obligations as they mature.

 

Delays in bringing successful wells on production may reduce our liquidity.  As a general rule, we experience a significant lag time between the initial cash outlay on a prospect and the inclusion of any value for such prospect in the borrowing base under the revolving credit facility.  Until a well is on production, the banks may assign only a minimal borrowing base value to the well, and cash flows from the well are not available to fund our operating expense.  Delays in bringing wells on production may reduce the borrowing base significantly, depending on the amounts borrowed and the length of the delays.

 

Hedging transactions may limit our potential gains and involve other risks.

 

From time to time, we use commodity derivatives, consisting of “swaps,” “collars” and “floors,” to attempt to optimize the price we receive for the sale of our oil and natural gas production. When using swaps to hedge our oil and natural gas production, we receive a fixed price for the hedged commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty at the settlement date. Collars are a combination of options that provide us with a put option (fixed floor price) in exchange for a call option (fixed ceiling price). If the market price for the hedged commodity exceeds the fixed ceiling price or falls below the fixed floor price, then we receive the fixed price and pay the market price. If the market price is between the fixed floor and the fixed ceiling prices, then no payments are due from either party. In addition, we may purchase put options in which we pay the counterparty the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed floor price over the floating market price.

 

The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements. We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge.  If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received. If we terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.

 

Information concerning our reserves and future net revenues estimates is inherently uncertain.

 

The accuracy of proved reserves estimates and estimated future net revenues from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn could adversely affect our cash flow, results of operations and the availability of capital resources. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Downward adjustments to our estimated proved reserves could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity.

 

The present value of proved reserves will not necessarily equal the current fair market value of our estimated oil and gas reserves. In accordance with the reserve reporting requirements of the SEC, the

 

15



 

estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.

 

The estimated proved reserve information is based upon reserve reports prepared by independent engineers. From time to time, estimates of our reserves are also made by our banks in establishing the borrowing base under our senior revolving credit facility and by our engineers for use in developing business plans and making various decisions. Such estimates may vary significantly from those of the independent engineers and have a material effect upon our business decisions and available capital resources.

 

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.

 

We plan to continue growing our reserves and drilling inventory through acquisitions. Acquired properties can be subject to significant unknown liabilities. Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired in an acquisition. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed.

 

Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity.

 

Our failure to integrate acquired businesses successfully into our existing business could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

 

The process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations.

 

Drilling oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.

 

Drilling oil and natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive oil or natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we often are uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

    unexpected drilling conditions;

 

    title problems;

 

16



 

    pressure or irregularities in formations;

 

    equipment failures or accidents;

 

    adverse weather conditions;

 

    compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and

 

    costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment and services.

 

We may not be insured against all of the operating hazards to which our business is exposed.

 

Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as windstorms, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, severe weather and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operation, operations which could result in substantial loss. We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot assure you of the continued availability of insurance at premium levels that justify its purchase.

 

Our business depends on oil and natural gas transportation facilities, most of which are owned by others.

 

The marketability of our oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

 

A shortage of available drilling rigs, equipment and personnel may delay or restrict our operations.

 

The oil and natural gas industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or personnel. During these periods, the costs and delivery times of drilling rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or personnel may increase drilling costs or delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

 

Our industry is highly competitive.

 

Competition in all areas of our operations is intense. We experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of

 

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properties and prospects than our financial or human resources permit. Our ability to increase reserves in the future will depend on our success at selecting and acquiring suitable producing properties and prospects for future development and exploration activities.

 

In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue.

 

The market for our oil, gas and natural gas liquids production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

 

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

 

Our success is highly dependent on our senior management personnel, none of whom are currently subject to an employment contract. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

 

We are primarily controlled by our principal stockholder.

 

Clayton W. Williams beneficially owns, either individually or through his affiliates, approximately 45% of the outstanding shares of our common stock. Mr. Williams is also the Chairman of the Board and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of board members, and in management decisions. Mr. Williams actively participates in all facets of our business and has a significant impact on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Williams, or any change in the power to vote his shares, could result in negative market or industry perception and could have a material adverse effect on our business.

 

By extending credit to our customers, we are exposed to potential economic loss.

 

We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. As appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. We cannot assure you that we will not suffer any economic loss related to credit risks in the future.

 

Compliance with environmental and other government regulations could be costly and could negatively impact production.

 

Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

 

All of the states in which we operate generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters,

 

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including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from our properties.

 

The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

 

Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

 

Our exploration and production activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.

 

Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances.  Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate.  Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws.  Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share.  Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

 

We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future.  Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs.  Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation.  Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas.  Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants.  In addition, claims are sometimes made or threatened against companies engaged in oil and gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired.  Compliance with, and liabilities

 

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for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect our business, financial condition and results of operations.

 

Item 1B -       Unresolved Staff Comments

 

Not applicable.

 

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Item 2 -          Properties

 

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped.  At December 31, 2005, we had interests in 6,605 gross (899.7 net) oil and gas wells and owned leasehold interests in approximately 1.2 million gross (778,000 net) undeveloped acres.

 

Reserves

 

The following table sets forth certain information as of December 31, 2005 with respect to our estimated proved oil and gas reserves pursuant to SEC guidelines, present value of proved reserves and standardized measure of discounted future net cash flows.

 

 

 

Proved Developed

 

Proved
Undeveloped

 

Total
Proved

 

Producing

 

Nonproducing

 

 

(Dollars in thousands)

 

 

 

 

 

 

 

 

 

 

 

Gas (MMcf)

 

74,209

 

17,157

 

35,392

 

126,758

 

Oil and natural gas liquids (MBbls)

 

19,120

 

2,382

 

6,333

 

27,835

 

Total (MMcfe)

 

188,929

 

31,449

 

73,390

 

293,768

 

Present value of proved reserves (a)

 

 

 

 

 

 

 

$

1,117,886

 

Standardized measure of discounted future net cash flows

 

 

 

 

 

 

 

$

753,712

 

 


(a)           We believe that the present value of proved reserves (a non-GAAP measure) is a useful supplemental disclosure to the standardized measure of discounted future net cash flows. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each company, the present value of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis. Standardized measure of discounted future net cash flows differs from the present value of proved reserves by the amount of estimated future income taxes and net abandonment costs.  Estimated future income taxes and future net abandonment costs (discounted at 10%) as of December 31, 2005 were $352.6 million and $11.6 million, respectively.

 

The following table sets forth certain information as of December 31, 2005 regarding our proved oil and gas reserves in each of our principal producing areas.

 

 

 


Proved Reserves

 

Percent of
Total Gas
Equivalent

 

Present
Value of
Proved
Reserves

 

Percent
of Present
Value of
Proved
Reserves

 

Oil (a)
(MBbls)

 

Gas
(MMcf)

 

Total Gas
Equivalent
(MMcfe)

 

 

 

 

 

 

 

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin (b)

 

18,504

 

79,466

 

190,490

 

64.8

%

$

575,616

 

51.5

%

Louisiana

 

1,667

 

20,883

 

30,885

 

10.5

%

226,603

 

20.3

%

Austin Chalk (Trend)

 

7,467

 

6,234

 

51,036

 

17.4

%

178,972

 

16.0

%

Cotton Valley

 

 

 

 

 

 

 

 

 

 

 

 

 

Reef Complex

 

 

15,396

 

15,396

 

5.3

%

97,388

 

8.7

%

Other

 

197

 

4,779

 

5,961

 

2.0

%

39,307

 

3.5

%

Total

 

27,835

 

126,758

 

293,768

 

100.0

%

$

1,117,886

 

100.0

%

 


(a)           Includes natural gas liquids.

(b)           Primarily West Texas and New Mexico.

 

21



 

The estimates of proved reserves at December 31, 2005 and the present value of proved reserves were derived from reports prepared by Williamson Petroleum Consultants, Inc., independent petroleum engineers and Ryder Scott Company, L.P., petroleum consultants.  The following table summarizes the reserve estimates derived from each report.

 

 

 

Proved Developed

 

Proved
Undeveloped

 

Total
Proved

 

Producing

 

Nonproducing

 

 

(Dollars in thousands)

 

Williamson Petroleum Consultants, Inc.:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas (MMcf)

 

34,090

 

10,036

 

10,660

 

54,786

 

Oil and natural gas liquids (MBbls)

 

8,256

 

833

 

2,375

 

11,464

 

 

 

 

 

 

 

 

 

 

 

Ryder Scott Company, L.P.:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas (MMcf)

 

40,119

 

7,121

 

24,732

 

71,972

 

Oil and natural gas liquids (MBbls)

 

10,864

 

1,549

 

3,958

 

16,371

 

 

Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our hedging activities.  These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.  The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense or to depletion, depreciation and amortization.

 

In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the present value of proved reserves set forth herein are made using oil and gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and gas prices.  The average prices utilized for the purposes of estimating our proved reserves and the present value of proved reserves as of December 31, 2005 were $57.85 per Bbl of oil and natural gas liquids and $10.65 per Mcf of gas, as compared to $41.48 per Bbl of oil and $5.59 per Mcf of gas as of December 31, 2004.  We estimate that a $1.00 per Bbl change in oil price and a $.50 per Mcf change in gas price from those utilized in calculating the present value of proved reserves would change the present value by approximately $13.2 million and $32.7 million, respectively.

 

The reserve information shown is estimated.  The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment.  The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise.  Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.  Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

 

Since January 1, 2005, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.

 

22



 

Exploration and Development Activities

 

We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.

 

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

(Excludes wells in progress at the end of any period)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

49

 

26.4

 

39

 

11.7

 

6

 

5.0

 

Gas

 

10

 

3.2

 

2

 

1.3

 

2

 

2.0

 

Dry

 

1

 

.2

 

2

 

.9

 

 

 

Total

 

60

 

29.8

 

43

 

13.9

 

8

 

7.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

2

 

1.8

 

1

 

.3

 

 

 

Gas

 

7

 

4.5

 

7

 

4.9

 

9

 

4.9

 

Dry

 

10

 

6.1

 

13

 

7.1

 

18

 

12.3

 

Total

 

19

 

12.4

 

21

 

12.3

 

27

 

17.2

 

Total Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

51

 

28.2

 

40

 

12.0

 

6

 

5.0

 

Gas

 

17

 

7.7

 

9

 

6.2

 

11

 

6.9

 

Dry

 

11

 

6.3

 

15

 

8.0

 

18

 

12.3

 

Total

 

79

 

42.2

 

64

 

26.2

 

35

 

24.2

 

 

The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.

 

As of December 31, 2005, we do not own any drilling rigs, and all of our current drilling activities are conducted by independent drilling contractors.  We have entered into a letter agreement with a contract drilling company which calls for the formation of a joint venture in 2006 to acquire 12 new drilling rigs.  We will own a 50% interest in the joint venture.

 

Productive Well Summary

 

The following table sets forth certain information regarding our ownership, as of December 31, 2005, of productive wells in the areas indicated.

 

 

 

Oil

 

Gas

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

5,496

 

520.0

 

705

 

91.0

 

6,201

 

611.0

 

Louisiana

 

5

 

2.7

 

19

 

14.7

 

24

 

17.4

 

Austin Chalk (Trend)

 

298

 

227.8

 

16

 

8.8

 

314

 

236.6

 

Cotton Valley

 

 

 

12

 

11.1

 

12

 

11.1

 

Other

 

20

 

15.8

 

34

 

7.8

 

54

 

23.6

 

Total

 

5,819

 

766.3

 

786

 

133.4

 

6,605

 

899.7

 

 

23



 

Volumes, Prices and Production Costs

 

The following table sets forth certain information regarding the production volumes of, average sales prices received from, and average production costs associated with our sales of oil and gas for the periods indicated.

 

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

Oil and Gas Production Data:

 

 

 

 

 

 

 

Gas (MMcf)

 

16,408

 

17,938

 

24,697

 

Oil (MBbls)

 

2,258

 

2,094

 

1,505

 

Natural gas liquids (MBbls)

 

246

 

249

 

234

 

Total (MMcfe)

 

31,432

 

31,996

 

35,131

 

 

 

 

 

 

 

 

 

Average Realized Prices (a):

 

 

 

 

 

 

 

Gas ($Mcf)

 

$

7.49

 

$

5.60

 

$

4.69

 

Oil ($Bbl)

 

$

53.37

 

$

40.65

 

$

27.74

 

Natural gas liquids ($/Bbl)

 

$

33.57

 

$

27.90

 

$

21.09

 

 

 

 

 

 

 

 

 

Average Production Costs

 

 

 

 

 

 

 

Production ($/Mcfe) (b)

 

$

1.83

 

$

1.29

 

$

.80

 

 


(a)           Includes the effects of hedging transactions designated as cash flow hedges under applicable accounting standards.  In 2005 and 2004, no derivatives were designated as cash flow hedges.

(b)           Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs, administrative costs of production offices, insurance and property and severance taxes.

 

Development, Exploration and Acquisition Expenditures

 

The following table sets forth certain information regarding the costs we incurred in our development, exploration and acquisition activities during the periods indicated.

 

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

 

 

(In thousands)

 

 

 

 

 

 

 

 

 

Property Acquisitions:

 

 

 

 

 

 

 

Proved

 

$

5,567

 

$

237,042

 

$

 

Unproved

 

50,238

 

33,826

 

7,982

 

Developmental Costs

 

42,292

 

27,469

 

12,465

 

Exploratory Costs

 

86,304

 

73,655

 

49,277

 

Total

 

$

184,401

 

$

371,992

 

$

69,724

 

 

24



 

Acreage

 

The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2005 in the areas indicated.  This table excludes options to acquire leases and acreage in which our interest is limited to royalty, overriding royalty and similar interests.

 

 

 

Developed

 

Undeveloped

 

Total

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

80,331

 

44,533

 

338,124

 

149,874

 

418,455

 

194,407

 

Trend/Cotton Valley

 

108,280

 

106,267

 

62,051

 

34,140

 

170,331

 

140,407

 

Louisiana

 

9,672

 

7,418

 

166,559

 

156,115

 

176,231

 

163,533

 

Other (a)

 

11,566

 

3,996

 

618,981

 

438,011

 

630,547

 

442,007

 

Total

 

209,849

 

162,214

 

1,185,715

 

778,140

 

1,395,564

 

940,354

 

 


(a)           Net undeveloped acres are attributable to the following areas:  Montana – 183,136; Mississippi – 96,657; Alabama - 50,133; Arizona - 39,445; Colorado - 28,980; East Texas - 19,041; Utah - 8,301; and other – 12,318.

 

Offices

 

We lease from a related partnership approximately 52,000 square feet of office space in Midland, Texas for our corporate headquarters.  We also lease approximately 10,000 square feet of office space in Houston, Texas from an unaffiliated third party.

 

Item 3 -          Legal Proceedings

 

We are a defendant in several lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on our consolidated financial condition or results of operations.

 

Item 4 -          Submission of Matters to a Vote of Security Holders

 

No matter was submitted to a vote of our security holders during the fourth quarter of our fiscal year ended December 31, 2005.

 

25



 

PART II

 

Item 5 -          Market for the Registrant’s Common Stock and Related Stockholder Matters

 

Price Range of Common Stock

 

Our Common Stock is quoted on the Nasdaq Stock Market’s National Market under the symbol “CWEI”.  As of March 6, 2006, there were approximately 1,900 beneficial stockholders as reflected in security position listings.  The following table sets forth, for the periods indicated, the high and low sales prices for our Common Stock, as reported on the Nasdaq National Market:

 

 

 

High

 

Low

 

Year Ended December 31, 2005:

 

 

 

 

 

Fourth Quarter

 

$

44.96

 

$

32.18

 

Third Quarter

 

43.25

 

29.60

 

Second Quarter

 

31.93

 

21.66

 

First Quarter

 

33.89

 

20.62

 

 

 

 

 

 

 

Year Ended December 31, 2004:

 

 

 

 

 

Fourth Quarter

 

$

24.69

 

$

18.65

 

Third Quarter

 

26.95

 

17.53

 

Second Quarter

 

35.85

 

22.26

 

First Quarter

 

38.90

 

28.20

 

 

The quotations in the table above reflect inter-dealer prices without retail markups, markdowns or commissions and may not necessarily reflect actual transactions.  The closing price of our common stock at March 14, 2006 was $39.18 per share.

 

Dividend Policy

 

We have never paid any cash dividends on our Common Stock, and our Board of Directors does not currently anticipate paying any cash dividends to the common stockholders in the foreseeable future.  In addition, the terms of our secured bank credit facilities prohibit the payment of cash dividends.

 

Securities Authorized for Issuance under Equity Compensation Plans

 

The following table provides information regarding options or warrants authorized for issuance under our equity compensation plans as of December 31, 2005.

 

 

 

Number of
securities to be
issued upon
exercise of
outstanding
options

 

Weighted
average exercise
price of
outstanding
options

 

Number of
securities
remaining
Available for
future issuance

 

Equity compensation plans approved by security holders (a)

 

1,338,551

 

$

19.53

 

148,066

 

Equity compensation plans not approved by security holders

 

 

 

 

Total

 

1,338,551

 

$

19.53

 

148,066

 

 


(a)           Consists of the 1993 Stock Compensation Plan and the Outside Directors Stock Option Plan.

 

26



 

Item 6 -          Selected Financial Data

 

The following table sets forth selected consolidated financial data for CWEI as of the dates and for the periods indicated.  The consolidated financial data for each of the years in the five-year period ended December 31, 2005 was derived from our audited financial statements.  The data set forth in this table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the accompanying consolidated financial statements, including the notes thereto.

 

 

 

Year Ended December 31,

 

 

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

(In thousands, except per share)

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

252,599

 

$

193,127

 

$

163,032

 

$

86,302

 

$

105,118

 

Natural gas services

 

12,080

 

9,083

 

8,758

 

5,568

 

8,820

 

Gain on sales of property and equipment

 

18,920

 

4,120

 

267

 

2,241

 

10,986

 

Total revenues

 

283,599

 

206,330

 

172,057

 

94,111

 

124,924

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

Production

 

57,404

 

41,163

 

28,239

 

21,857

 

20,427

 

Exploration:

 

 

 

 

 

 

 

 

 

 

 

Abandonment and impairments

 

39,957

 

67,956

 

35,120

 

21,571

 

29,412

 

Seismic and other

 

10,780

 

7,124

 

8,755

 

8,578

 

12,868

 

Natural gas services

 

11,212

 

8,538

 

8,279

 

4,853

 

7,467

 

Depreciation, depletion and amortization

 

47,509

 

44,040

 

40,284

 

29,656

 

37,459

 

Impairment of property and equipment

 

18,266

 

 

170

 

349

 

18,170

 

Accretion of abandonment obligations

 

1,158

 

1,044

 

651

 

 

 

General and administrative

 

15,410

 

11,689

 

10,934

 

8,615

 

7,456

 

Loss on sales of property and equipment

 

209

 

14,337

 

68

 

1,880

 

 

Other

 

1,353

 

 

 

 

 

Total costs and expenses

 

203,258

 

195,891

 

132,500

 

97,359

 

133,259

 

Operating income (loss)

 

80,341

 

10,439

 

39,557

 

(3,248

)

(8,335

)

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(14,498

)

(7,877

)

(3,138

)

(4,006

)

(2,925

)

Gain (loss) on derivatives

 

(70,059

)

(25,329

)

(1,593

)

(1,581

)

2,227

 

Other income

 

4,022

 

1,354

 

(1,662

)

1,755

 

66

 

Total other income (expense)

 

(80,535

)

(31,852

)

(6,393

)

(3,832

)

(632

)

Income (loss) before income taxes

 

(194

)

(21,413

)

33,164

 

(7,080

)

(8,967

)

Income tax expense (benefit)

 

(451

)

(7,385

)

10,515

 

(1,742

)

(3,421

)

Income (loss) from continuing operations

 

257

 

(14,028

)

22,649

 

(5,338

)

(5,546

)

Cumulative effect of accounting change, net of tax

 

 

 

207

 

 

(164

)

Income from discontinued operations, including gain on sale of $1,196 in 2002, net of tax

 

 

 

 

1,335

 

406

 

NET INCOME (LOSS)

 

$

257

 

$

(14,028

)

$

22,856

 

$

(4,003

)

$

(5,304

)

Net income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

Basic:

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from continuing operations

 

$

(.02

)

$

(1.37

)

$

2.43

 

$

(.58

)

$

(.60

)

Net income (loss)

 

$

(.02

)

$

(1.37

)

$

2.45

 

$

(.43

)

$

(.58

)

Diluted:

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from continuing operations

 

$

(.02

)

$

(1.37

)

$

2.38

 

$

(.58

)

$

(.60

)

Net income (loss)

 

$

(.02

)

$

(1.37

)

$

2.40

 

$

(.43

)

$

(.58

)

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

10,804

 

10,213

 

9,329

 

9,241

 

9,219

 

Diluted

 

11,241

 

10,213

 

9,509

 

9,241

 

9,219

 

Other Data:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

163,475

 

$

126,980

 

$

119,750

 

$

34,514

 

$

67,059

 

 

 

 

December 31,

 

 

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

(In thousands)

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Working capital (deficit)

 

$

(35,812

)

$

(27,566

)

$

(13,119

)

$

(18,843

)

$

(17,779

)

Total assets

 

587,335

 

462,235

 

224,433

 

218,992

 

183,279

 

Long-term debt

 

235,700

 

177,519

 

53,295

 

94,949

 

62,000

 

Stockholders’ equity

 

120,291

 

117,596

 

100,781

 

68,781

 

82,280

 

 

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.

 

Overview

 

We are an oil and natural gas exploration, development, acquisition, and production company.  Our basic business model is to find and develop oil and gas reserves through exploration and development activities, and sell the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.  From time to time, we may also acquire producing properties if we believe the acquired assets offer us the potential for reserve growth through additional developmental or exploratory drilling activities.

 

We believe that the economic climate in the domestic oil and gas industry continues to be suitable for our business model.  Oil and gas prices have remained strong.  Supply and demand fundamentals continue to suggest that energy prices will remain high for the near term, providing us with the economic incentives necessary for us to assume the risks we face in our search for oil and gas reserves.  However, we are also experiencing significant cost increases in almost all areas of our business activities, especially in drilling and production costs.  High demand for oilfield services is resulting in shortage in equipment and trained personnel, resulting in rate increases.  While profit margins still remain favorable, operating metrics per Mcfe, such as finding costs, production costs and overhead costs, are rising.

 

Finding quality domestic oil and gas reserves through exploration is a significant challenge and involves a high degree of risk.  We replaced approximately 56% of our 2005 production through extensions and discoveries in 2005, most of which were derived from exploration activities.  However, our Wolfcamp exploration program in West Texas failed to find sufficient reserves to cover our carrying costs, resulting in an $18.3 million impairment in 2005.  Our ability to grow our reserves is highly dependent on our overall exploration successes.  We will also continue to look for opportunities to complement our exploration program through the purchase of proved reserves.

 

Key Factors to Consider

 

The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2005 and the outlook for 2006.

 

        In July 2005, we significantly improved our liquidity by issuing $225 million of aggregate principal amount of 7¾% Senior Notes due 2013.  We repaid all amounts outstanding at that time under our secured bank credit facilities with net proceeds from the Senior Notes of approximately $217 million, and had approximately $138.5 million of borrowing capacity available under our revolving credit facility at December 31, 2005.

 

        We recorded a $70.1 million loss on derivatives during 2005. Cash settlements to counterparties accounted for $29.7 million of this loss, and changes in mark-to-market valuations accounted for $40.4 million.  Since we do not presently designate our derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of

 

28



 

changing prices on mark-to-market valuations as a current charge or credit to our results of operations.

 

        Exploration costs related to abandonments and impairments totaled $40 million for 2005, most of which was in the Cotton Valley Reef Complex, South Texas, Louisiana and West Texas.

 

        Our proved oil and gas reserves at December 31, 2005 was 293.8 Bcfe compared to 299 Bcfe at December 31, 2004.  We added 17.7 Bcfe through extensions and discoveries, purchased 4.2 Bcfe of reserves and added 7.8 Bcfe from net revisions.

 

        We currently plan to spend $184.1 million in 2006 on exploration and development activities, of which approximately 90% relates to exploratory prospects.  We cannot predict our drilling success on exploratory prospects, and our future results of operations and financial condition could be adversely affected by unsuccessful exploratory drilling results.

 

        In October 2005, we entered into a letter agreement with a contract drilling company which calls for the formation of a joint venture to acquire 12 new drilling rigs.  We will own a 50% interest in the joint venture, which is expected to be formed in March 2006.

 

Recent Exploration and Developmental Activities

 

South Louisiana

 

More than half of the wells in our South Louisiana exploration program that were commenced in 2005 were productive and resulted in the addition of approximately 8.7 Bcfe of proved reserves in 2005.  However, the LL&E #1 (Andrea) and the State Lease 17636 #1 (Natalie) were unsuccessful and resulted in aggregate abandonment charges of $10.7 million in 2005.

 

We currently plan to spend $56.3 million in South Louisiana in 2006 to generate and lease new exploratory prospects and to drill wells on existing exploratory prospects.  We have begun a six-well program on our Floyd prospect in Plaquemines Parish targeting multi-pay objectives ranging in depths from 3,000 to 13,000 feet.  The State Lease 195 QQ #1 was drilled to a total depth of 12,981 feet and is currently being completed.  The State Lease 195 QQ #2 has been drilled to a total depth of 6,296 feet and is pending completion.  The State Lease 195 QQ #3 has been drilled to a total depth of 9,170 feet, and is also pending completion.  The State Lease 195 QQ #4 is currently drilling.  Under the terms of a farmout agreement, we bear 100% of the costs on these wells before casing point to earn a 75% working interest in the drilled acreage.

 

North Louisiana

 

We have begun an exploration program in North Louisiana targeting the Cotton Valley/Hosston and Bossier formations.  In this area, the Cotton Valley/Hosston formations are encountered at depths ranging from 8,000 to 12,000 feet, and the Bossier formation is encountered at depths ranging from 11,000 to 15,500 feet.  We believe that these tight sandstone formations have become more economically viable due to higher product prices, coupled with enhanced drilling and completion techniques.  We have accumulated more than 115,000 net acres in this area, and to date have participated in six non-operated wells on a small portion of this acreage, four of which are currently being completed and two are in progress.  We are currently drilling the Harris #1, a 14,500-foot well in Jackson Parish targeting the Bossier formation, in which we own a 53% working interest.  We plan to spend approximately $87.9 million in North Louisiana in 2006, consisting of $17.2 million to acquire leases and conduct seismic and exploration activities, and $70.7 million on drilling.

 

29



 

East Texas (Bossier)

 

We have also begun acquiring leases in East Texas targeting the Bossier formation which is encountered at depths ranging from 14,000 to 22,000 feet in this area.  To date, we have acquired approximately 28,000 net acres and are actively seeking to add to our acreage position.  We plan to spend approximately $20 million for acreage in East Texas in 2006 and expect to begin drilling on this acreage in 2007.

 

Permian Basin

 

In 2005, we initiated an exploration program in West Texas seeking to extend the limits of the Wolfcamp formation that is encountered throughout a large segment of this region.  We acquired more than 50,000 net acres and have drilled 11 wells across a wide portion of this acreage.  While all of the wells were completed as producers, the oil and gas reserves derived from this drilling program were inadequate to recover our capitalized costs.  As a result, we recorded an $18.3 million charge for impairment of proved properties and a $1.8 million charge for impairment of unproved properties in 2005 related to our Wolfcamp program.

 

We also drilled the Leoncita #1, a 9,300-foot exploratory well in Pecos County, Texas targeting the Barnett Shale.  This well was unsuccessful and resulted in a $4.5 million charge to exploration costs in 2005.

 

In addition, we drilled 24 gross (20.2 net) wells in the Permian Basin and conducted remedial operations on existing wells in 2005.  While some of the drilling activities in 2005 did not result in the quantities of oil and gas reserves that we had expected, the Permian Basin continues to be a significant source of production and cash flow for us.  We currently plan to spend $6.7 million on drilling activities in the Permian Basin in 2006.

 

Montana/Utah

 

In 2005, we initiated an exploration program in Sheridan County, Montana targeting the Bakken Shale which is encountered at depths ranging from 7,000 to 8,000  feet in this area.  We are currently drilling the Ruegsegger 24H #1, a horizontal well at a vertical depth of 7,600 feet and a 3,600 foot lateral.

 

We are participating in a joint exploration program with industry partners in the Overthrust play in central Utah in which we own a 33% interest.  In 2006, we plan to spend approximately $2.5 million to participate in the drilling of a 14,400-foot exploratory well to test this acreage.

 

Other

 

We currently plan to spend $7.2 million in 2006 to explore for oil and gas in other areas, including the Austin Chalk (Trend), Colorado and Alabama.

 

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Proved Oil and Gas Reserves

 

The following table summarizes changes in our proved reserves during 2005 on a Bcfe basis.

 

 

 

Bcfe

 

Total proved reserves, December 31, 2004

 

299.0

 

Purchases of reserves in place

 

4.2

 

Extensions and discoveries

 

17.7

 

Revisions of previous estimates

 

7.8

 

Sales of reserves in place

 

(3.5

)

Production

 

(31.4

)

Total proved reserves, December 31, 2005

 

293.8

 

 

During 2005, we replaced 94% of the 31.4 Bcfe that we produced in 2005, computed by dividing the sum of all reserve additions (purchases of reserves in place, extensions and discoveries, and revisions of previous estimates), by 2005 production.  We use this reserve replacement ratio as a benchmark for determining the sources through which we have expanded or contracted our base of proved reserves. Following is a discussion of the important factors related to each source of reserve additions during 2005.

 

Purchases of reserves in place.  We purchased 4.2 Bcfe of reserves in 2005 relating to properties in West Texas.  Although we are continually looking for acquisitions, we cannot predict the likelihood of adding any reserves in 2006 through purchases of reserves in place.

 

Extensions and discoveries.  Our extensions and discoveries during 2005 consist of proved reserves attributable directly to the drilling of discovery wells primarily in South Louisiana and the Permian Basin.  Of the 17.7 Bcfe of additions, 4.8 Bcfe are proved undeveloped reserves that will require the expenditure of approximately $5.9 million before the reserves can ultimately be converted to cash flow.  Due to the nature of exploratory drilling, we cannot predict the extent to which we will add any reserves in 2006 through extensions and discoveries.

 

Revisions of previous estimates.  We added 7.8 Bcfe of proved reserves through revisions of previous estimates. Upward revisions of 17.5 Bcfe were attributable to the effects of higher product prices on the estimated quantities of proved reserves which were offset by downward revisions of approximately 9.7 Bcfe attributable to well performance, primarily from properties in West Texas.

 

As we discuss under “Application of Critical Accounting Policies and Estimates” elsewhere in this Item 7, reserve estimates are inherently imprecise.  Proved undeveloped reserves are generally the least accurate due to limitations on available information.  This increases the risk that the reserve additions in 2005 that are classified as proved undeveloped reserves could be subject to downward revisions in the future as economic conditions change and as more information is obtained through drilling.

 

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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,

 

 

 

2005

 

2004

 

2003

 

Oil and Gas Production Data:

 

 

 

 

 

 

 

Gas (MMcf)

 

16,408

 

17,938

 

24,697

 

Oil (MBbls)

 

2,258

 

2,094

 

1,505

 

Natural gas liquids (MBbls)

 

246

 

249

 

234

 

Total (MMcfe)

 

31,432

 

31,996

 

35,131

 

 

 

 

 

 

 

 

 

Average Realized Prices (a):

 

 

 

 

 

 

 

Gas ($/Mcf):

 

 

 

 

 

 

 

Before hedging losses

 

$

7.49

 

$

5.60

 

$

5.35

 

Hedging losses

 

 

 

(.66

)

Net realized price

 

$

7.49

 

$

5.60

 

$

4.69

 

Oil ($/Bbl):

 

 

 

 

 

 

 

Before hedging losses

 

$

53.37

 

$

40.65

 

$

29.94

 

Hedging losses

 

 

 

(2.20

)

Net realized price

 

$

53.37

 

$

40.65

 

$

27.74

 

 

 

 

 

 

 

 

 

Natural gas liquids ($/Bbl):

 

$

33.57

 

$

27.90

 

$

21.09

 

 

 

 

 

 

 

 

 

Average Daily Production:

 

 

 

 

 

 

 

Gas (Mcf):

 

 

 

 

 

 

 

Permian Basin

 

15,893

 

9,458

 

1,668

 

Louisiana

 

10,865

 

12,089

 

17,570

 

Austin Chalk (Trend)

 

2,435

 

3,155

 

3,667

 

Cotton Valley Reef Complex

 

15,155

 

23,131

 

42,493

 

Other

 

605

 

1,312

 

2,265

 

Total

 

44,953

 

49,145

 

67,663

 

Oil (Bbls):

 

 

 

 

 

 

 

Permian Basin

 

3,245

 

2,410

 

723

 

Louisiana

 

994

 

1,055

 

608

 

Austin Chalk (Trend)

 

1,892

 

2,215

 

2,715

 

Other

 

55

 

57

 

77

 

Total

 

6,186

 

5,737

 

4,123

 

Natural Gas Liquids (Bbls):

 

 

 

 

 

 

 

Permian Basin

 

255

 

213

 

171

 

Louisiana/Other

 

97

 

185

 

171

 

Austin Chalk (Trend)

 

322

 

284

 

299

 

Total

 

674

 

682

 

641

 

 

 

 

 

 

 

 

 

Total Proved Reserves:

 

 

 

 

 

 

 

Gas (MMcf)

 

126,758

 

138,278

 

62,916

 

Oil and natural gas liquids (MBbls)

 

27,835

 

26,793

 

10,335

 

Total gas equivalent (MMcfe)

 

293,768

 

299,036

 

124,926

 

Standardized measure of discounted future net cash flows

 

$

753,712

 

$

500,198

 

$

252,980

 

 

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Total Proved Reserves by Area: