ITEM 1. BUSINESS
Overview
Petrohawk Energy Corporation (Petrohawk or the Company), a Delaware corporation, is an independent oil and gas company engaged in the acquisition, development, production and exploration of natural gas and oil properties located in North America. We were formed in June 1997 as a Nevada corporation and were reincorporated in the state of Delaware during 2004. Our properties are concentrated in the Anadarko, South Texas, Permian Basin, East Texas, Arkoma and Gulf Coast regions.
At December 31, 2004, our estimated total proved oil and gas reserves were approximately 219 Bcfe, consisting of 9.7 million barrels of oil and 160.9 Bcf of natural gas. Proved reserves are approximately 73% gas on an equivalent basis and approximately 78% were classified as proved developed. Year-end prices used to determine proved reserves were $40.25 per barrel of oil and $6.18 per Mmbtu of gas.
We have increased our proved reserves and production principally through acquisitions. We focus on properties within our core operating areas that have a significant proved reserve component and which management believes have additional development and exploration opportunities.
Recent Developments
We have recently completed several transactions:
Proton Oil & Gas Corporation
On February 25, 2005, we completed the purchase of Proton Oil & Gas Corporation (Proton) for approximately $53 million. This privately negotiated transaction included estimated proved reserves of approximately 28 Bcfe and had an economic effective date of January 1, 2005. The Proton properties are located in South Louisiana and South Texas. Additional transaction highlights include the following estimates:
• 5.0 Mmcfe of production per day
• 46% natural gas
• 47% proved developed
• 97% operated
• 15 year reserves-to-production ratio
Major properties in the asset base include interests in the Gueydan Field in Vermilion Parish, Louisiana, with 16 Bcfe of estimated proved reserves, 1,018 gross acres and nine PUD locations. In South Texas, significant properties include interests in the Heard Ranch Field in Bee County, Texas with approximately 7 Bcfe of estimated proved reserves, 4,230 gross acres and fifteen Proved Undeveloped (PUD) locations. The acquisition also included 3-D seismic data covering all major properties.
Sale of Royalty Interest Properties
On February 25, 2005, we completed the disposition of certain royalty interest properties previously acquired from Wynn-Crosby to Noble Royalties, Inc. (Noble) d/b/a Brown Drake Royalties for approximately $80 million in cash. We sold estimated proved reserves of approximately 26 Bcfe with current estimated production of approximately 5.0 Mmcfe per day.
Wynn-Crosby Transaction
On November 23, 2004, we acquired Wynn-Crosby Energy, Inc. and eight of the limited partnerships it managed (Wynn-Crosby) for a purchase price of approximately $425 million. The transaction was funded with proceeds from a $200 million private equity placement, $210 million in borrowings from our commercial bank group, and cash.
In connection with the acquisition, Netherland, Sewell & Associates, Inc., our independent petroleum engineering consultants (Netherland, Sewell), evaluated the proved reserves associated with working interest properties, and our reserve engineers evaluated proved reserves associated with royalty interest properties, resulting in approximately 200 Bcfe of total estimated proved reserves at July 1, 2004, the effective date of the transaction. At December 31, 2004, Wynn-Crosby had estimated proved reserves of approximately 190 Bcfe of which 74% and 26% were related to natural gas and oil, respectively. Approximately 76% were classified as proved developed.
The properties we acquired are primarily located in the South Texas, East Texas, Anadarko, Arkoma and Permian Basin regions and include approximately 75,000 net undeveloped acres in the Arkoma Basin region, as well as what we believe to be significant exploration opportunities in South Louisiana, South Texas and the Anadarko Basin.
Major properties in the Wynn-Crosby asset base include interests in La Reforma, a significant Vicksburg formation field in South Texas, the Dry Hollow and Provident City fields in the Wilcox trend of Lavaca County, Texas, and the Los Indios, Nabors, Ann Mag and McAllen Ranch fields in South Texas. In the East Texas basin, significant properties include interests in the South Carthage, North Beckville and Blocker fields. Other key properties include interests in the Waddell Ranch, Teague and ROC fields in the Permian Basin, the Kinta, Cedars, and Pine Hollow fields in the Arkoma Basin and the Lipscomb and Eakly-Weatherford fields in the Anadarko Basin.
PHAWK, LLC Transaction
On August 11, 2004, we acquired from PHAWK, LLC certain oil and gas properties in the Breton Sound area, Plaquemines Parish, Louisiana and in the West Broussard field in Lafayette Parish, Louisiana having approximately 2.9 Bcfe of estimated proved reserves. This purchase included the acquisition of 79 square miles of recently reprocessed 3-D seismic data and a 25% working interest in eight leased drilling prospects covering 2,528 gross acres in the Breton Sound/Main Pass area as well as two producing wells, pipelines and associated production facilities in Breton Sound Blocks 11 and 23. A 14% working interest (approximately 10% net revenue interest) was acquired in the Montesano #1 well in the West Broussard field. The Montesano #1 well was placed on production in August 2004. The purchase price for all of the proved reserves, seismic data, undeveloped acreage, pipelines, production facility and other assets was $8.5 million in cash. The effective date of the acquisition was June 1, 2004 and the effects of this transaction were first reported in our results for the quarter ended September 30, 2004.
Recapitalization by PHAWK, LLC
On May 25, 2004, PHAWK, LLC (PHAWK) (formerly known as Petrohawk Energy, LLC), which is owned by affiliates of EnCap Investments, L.P., Liberty Energy Holdings LLC, Floyd C. Wilson and other members of the Company’s management, recapitalized the Company with $60 million in cash. The $60 million investment was structured as the purchase by PHAWK of 7.576 million new shares of our common stock for $25 million, a $35 million five-year 8% subordinated note convertible into approximately 8.75 million shares of common stock and warrants to purchase 5.0 million shares of our common stock at a price of $3.30 per share. At the annual stockholders meeting held July 15, 2004, the stockholders approved changing the name of the Company to Petrohawk Energy Corporation (from Beta Oil & Gas, Inc.), reincorporating the company in Delaware, and the adoption of new stock option plans. Since the Company and PHAWK, LLC are under common control, the assets were recorded by the Company at the net book value of PHAWK, LLC at the time of the sale. The purchase price exceeded the net book value by approximately $5.6 million. The excess is reflected as a return of capital to PHAWK, LLC in the financial statements.
A special committee of one disinterested director was formed by the Company’s board of directors to evaluate, negotiate and complete the purchase. The Special Committee hired an independent reservoir engineering firm to provide a reserve evaluation and engaged an independent financial advisor to evaluate the fairness, from a financial point of view, to the Company. The independent financial advisor has rendered a fairness opinion to the Special Committee.
Business Strategy
We are an independent oil and gas company engaged in the acquisition, development, production and exploration of natural gas and oil properties located in North America. Our primary objective is to increase shareholder value. To accomplish this objective, our business strategy is focused on the following:
• Pursuit of Strategic Acquisitions. We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects. We seek to acquire operational control of properties that we believe have significant exploitation and exploration potential. Our strategy includes a significant focus on increasing our holdings in fields and basins in which we already own an interest.
• Further Development of Existing Properties. We seek to add proved reserves and increase production through the use of advanced technologies, including detailed reservoir engineering analysis, drilling development wells utilizing sophisticated techniques and selectively recompleting existing wells. We believe our properties have substantial additional reserve potential and we plan to drill step-out wells to expand known field limits. We intend to enhance the cost efficiency and quality control of these activities by operating the majority of our properties. We believe that many of the properties included in the Wynn-Crosby acquisition have significant development potential and in certain cases have not been actively developed in the past.
• Growth Through Exploration. We intend to conduct an active technology-driven exploration program that is designed to complement our property acquisition and development drilling activities with moderate to high risk exploration projects that have greater reserve potential. We generate exploration prospects through the analysis of geological and geophysical data and the interpretation of 3-D seismic data. We intend to manage our exploration risk and expenditures through the optimal scheduling of our drilling program and by selectively reducing our capital exposure in certain exploratory prospects through sales of interests to industry partners.
• Property Portfolio Management. We continually evaluate our property base to identify opportunities to divest higher cost, less productive properties with limited development potential. This rationalization strategy, if successful, will allow our technical staff to more efficiently focus their efforts on a portfolio of core properties with significant potential to increase our proved reserves and production. We also seek to increase the number of fields we operate as a percentage of our total properties through our property management strategy, as evident with the recent sale of the royalty properties that were acquired from Wynn-Crosby.
• Maintenance of Financial Flexibility. We intend to maintain substantial unused borrowing capacity under our bank revolving credit facility by periodically refinancing our bank debt in the capital markets when conditions are favorable. A significant part of our financial management strategy will involve the use of hedges to secure product prices for a substantial portion of our expected production. We believe our expanded base of internally generated cash flow and other information resources will provide us with the financial flexibility to pursue additional acquisitions of producing properties and leasehold acreage and to develop our project inventory in an optimal fashion.
• Benefit from the Transactional Nature of Our Industry. The independent exploration and production industry has been consolidating for a number of years. Our business strategy embraces this trend. We intend to assemble a portfolio of quality proved reserves and drilling opportunities within a core group of operated properties that may potentially be desirable as a strategic acquisition target by larger industry participants. Our management team has significant and successful experience in starting, building and selling companies in this industry sector.
Natural Gas and Crude Oil Reserves
The December 31, 2004 proved reserve estimates presented here were prepared by Netherland, Sewell with the exception of 26.2 Bcfe of proved reserves associated with royalty interest properties acquired from Wynn-Crosby and subsequently sold on February 25, 2005 which were not part of Netherland, Sewell’s report. For additional information regarding estimates of proved reserves, the review of such estimates by Netherland, Sewell and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on economic producing rates. Our reserves are based on oil and gas index prices in effect on the last day of December 2004.
There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control, such as commodity pricing. Therefore, the reserve information in this Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately
recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.
The following table presents certain information as of December 31, 2004 and includes the recently acquired PHAWK and Wynn-Crosby properties, all as of the periods indicated above. We acquired the PHAWK properties in August 2004 and the Wynn-Crosby properties in November 2004. Shut-in wells currently not capable of production are excluded from the producing well information.
(1) Reserve Life Index is equal to year-end reserves divided by estimated annual production.
(2) The term net as used in net production throughout this document refers to amounts that include only
acreage or production that is owned by Petrohawk Energy Corporation and produced to its interest, less royalties and production due to others. Net Wells represents our working interest share of each well.
(3) Includes the impact of non-operated royalty properties. Excluding royalty interest properties, our total percent proved reserves operated is 51%.
Anadarko Basin. The West Edmond Hunton Lime Unit (WEHLU) is our largest property in this region, covering 30,000 acres (approximately 47 square miles) primarily in Oklahoma County, Oklahoma. The WEHLU field, originally discovered in 1942, is the largest Hunton Lime formation field in the state of Oklahoma. The field has 58 oil and natural gas wells (28 currently producing) with stable production holding the entire unit. We own a 98% working interest at WEHLU and currently operate the field. We have an agreement with Avalon Exploration, Inc. of Tulsa, Oklahoma to jointly develop additional reserves and production in WEHLU. The area of mutual interest created by our agreement with Avalon covers 5,680 acres located in the central-northwest area of the field.
Other significant properties in this area include interests in the Lipscomb field in Lipscomb County, Texas where our working interests range from 75% to 100% and the Eakly-Weatherford field in Caddo County, Oklahoma, where working interests range from 1% to 26%. Production in these fields is from the Cleveland, Atoka, Morrow and Springer formations.
South Texas. Our properties in South Texas produce primarily from the Vicksburg, Wilcox and Frio formations which range in depth from approximately 5,500 feet to 12,500 feet. The La Reforma field, located in Starr and Hidalgo Counties, is the largest field in the Wynn-Crosby property base. La Reforma is a significant Vicksburg formation field and we own between 25% and 50% working interest in this area. We are conducting an active drilling program at La Reforma with one well currently being completed, one well currently drilling, and four locations expected to be drilled in 2005. The Vicksburg formation in this area is complexly faulted and 3-D seismic is extensively utilized to identify optimal structural targets. Wells in this field typically produce at initial rates of over 10.0 Mmcfe per day. Other Vicksburg/Frio fields in which we own a significant interest include Los Indios, Nabors, Ann Mag and McAllen Ranch. In the Wilcox trend of Lavaca County, we own between 20% and 25% working interest in the Dry Hollow field, which produces from 12,500 to 15,000 feet in depth. At Dry Hollow, we have identified three proved undeveloped locations and one probable location, which we expect to drill in 2005. We also own interests in the Provident City and North Borchers fields in Lavaca County.
Permian Basin. In the Permian Basin, our principal properties are in the Waddell Ranch field in Crane County, Texas, the ROC field in Ward County, Texas, and the Teague field in Lea County, New Mexico. Waddell Ranch is the largest field in West Texas and produces primarily from the Grayburg, San Andres and Clear Fork formations at depths from 3,000 to 4,000 feet. We own a 3.5% working interest in this property. The ROC field produces from the Ellenberger and Montoya formations at measured depths of 13,000 to 17,000 feet. We have identified four proved undeveloped locations in this field, where we own a working interest of between 5% and 25%. In the Teague field, production is from the Devonian and Seven Rivers, Queen and Grayburg formations at a depth of 4,000 to 8,000 feet. We own a 94% working interest in this property and have identified two proved undeveloped locations.
East Texas. Our properties in East Texas produce primarily from the Cotton Valley and Travis Peak formations which range in depth from approximately 6,500 to 10,000 feet. We own significant interests in the South Carthage, North Beckville and Blocker fields in Panola and Harrison Counties, Texas. Our working interest in these fields is between 47% and 100%. The producing formations of this area tend to contain multiple producing horizons and are typically low permeability sands that require fracture stimulation to achieve optimal producing rates. This type of fracture stimulation usually results in relatively high initial production rates that decline rapidly during the first year of production and subsequently stabilize at fairly low, more easily predictable annual decline rates. Much of our production in this area is from wells that have been producing for several years and are in the latter, more stable stage of production, resulting in a relatively long reserves to production ratio.
Arkoma Basin. In the Arkoma Basin, our properties produce primarily from the Atoka formation at depths of 2,500 to 6,000 feet. We own significant interests in the Kinta, Cedars and Pine Hollow fields in Pittsburg and Haskell Counties, Oklahoma. Our working interest in these fields is between 23% and 100%. Portions of our acreage in this region are near the Pine Hollow South field, where a new shale gas drilling play is currently evolving. In addition, we own approximately 55,100 net undeveloped acres in Logan, Scott and Yell Counties, Arkansas.
Gulf Coast. Our largest property in the Gulf Coast region is the West Broussard field, which is located in Lafayette Parish, Louisiana. In 2003, the Failla #1 well was drilled and completed, with the well being placed on production in September 2003. During 2004, the well produced approximately 15.0 gross Mmcf of natural gas and 350 gross barrels of oil per day. We have an approximate 9% working interest in this well. An additional development well, the Montesano #1, was drilled and completed during the third quarter of 2004. The well was placed on production in August 2004 and produced approximately 10.2 gross Mmcf of natural gas and 290 gross barrels of oil per day during the fourth quarter of 2004. We own a 23.1% working interest in this well, which will increase to approximately 29.6% working interest after payout. The Montesano #1 is projected to reach payout during the fourth quarter of 2005. The Failla #1 and Montesano #1 wells produce from the Bol Mex 3 formation at approximately 15,830 feet.
We also have properties in the Breton Sound/Main Pass area in Louisiana state waters, including a 25% working interest in 6 leased drilling prospects covering approximately 2,100 acres, as well as two producing wells, pipelines and associated production facilities. We possess 79 square miles of recently reprocessed 3-D seismic data covering this area. The main objective formation is the Tex W at a depth of 11,500 feet. Wells in this area generally produce at high rates and are short lived.
We have between 5% and 12% working interest in the Ship Shoal 208/239 field located in federal waters, offshore Louisiana. In South Louisiana, we also own minor interests in the South Lake Arthur field, Vermilion Parish, which has produced over 1 Tcfe from the Myogyp formation. In addition, we own interests in Old Ocean, a large Frio formation field in Brazoria County, Texas.
Royalty Interest Properties. At December 31, 2004, we own royalty interests in approximately 1,500 wells located in various oil and gas producing basins, producing an estimated 5.0 Mmcfe per day. On February 25, 2005, we sold these properties for $80 million. The agreement had an effective date of January 1, 2005.
Risk Management
From time to time, when we believe that market conditions are favorable, we use certain financial instruments called derivatives to manage price risks associated with our production. While there are many different types of derivatives available, we primarily use natural gas and oil price swap and collar agreements to attempt to manage price risk more effectively. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place. The collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling
and payments from the counterparties if the index price is below the floor. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A Quantitative and Qualitative Disclosures about Market Risk.
NATURAL GAS AND CRUDE OIL OPERATIONS
Our principal properties consist of developed and undeveloped natural gas and oil leases and the reserves associated with these leases. Generally, developed natural gas and oil leases remain in force so long as production is maintained. Undeveloped natural gas and oil leaseholds are generally for a primary term of three to five years. In most cases, the term of our undeveloped leases can be extended by paying delay rentals or by producing reserves that are discovered under those leases. Our revolving credit facility is collateralized by our proved developed reserves associated with our oil and gas properties and gas gathering system.
The table below sets forth the results of our drilling activities for the periods indicated:
(1) Although a well may be classified as productive upon completion, future production may deem the well to be uneconomical, particularly for exploration wells where there is little or no production history.
We own interest in developed and undeveloped natural gas and oil acreage in the locations set forth in the table below. These ownership interests generally take the form of working interest in natural gas and oil leases or licenses that have varying terms. The following table presents a summary of our acreage interests as of December 31, 2004 and includes the recently acquired Wynn-Crosby and PHAWK properties.
At December 31, 2004, we had estimated proved reserves of approximately 161 Bcf of natural gas and 9,701 MBbls of oil. These reserves are located entirely within the United States. The following table sets forth, at December 31, 2004, these reserves.
For purposes of determining the above cash flows, estimates were made of quantities of proved reserves and the periods during which they are expected to produce in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a). Future cash flows were computed by applying year-end prices to estimated annual future production from our proved oil and gas reserves. The year-end prices for natural gas and crude oil used in the estimation were $6.18 per MMbtu, based on a December 31, 2004, Henry Hub spot market price and $40.25 per Bbl, based on a December 31, 2004, West Texas Intermediate posted price. These prices were adjusted by lease for quality or energy content, transportation fees and regional price differentials. Future development and production costs were computed by applying year-end costs expected to be incurred in producing and further developing the proved reserves. The estimated future net revenues were discounted using a 10% per annum discount factor. The calculations assume the continuation of existing economic, operating and contractual conditions. Other assumptions of equal validity could give rise to substantially different results.
For additional information on our natural gas and crude oil reserves, please refer to the supplementary natural gas and oil information.
We account for our natural gas and crude oil producing activities using the full cost method of accounting as prescribed by the SEC. Accordingly, all costs incurred in the acquisition, exploration, and development of proved natural gas and oil properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general corporate costs are expensed as incurred. Sales or other dispositions of natural gas and oil properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated natural gas and oil properties is computed on the units of production method based on all proved reserves on a country-by-country basis. Unevaluated natural gas and oil properties are assessed quarterly for impairment either individually or on an aggregate basis. The net capitalized costs of evaluated natural gas and oil properties are subject to a full cost ceiling limitation in which the costs, net of tax considerations, are not allowed to exceed their related estimated future net revenues discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of tax considerations.
Capitalized costs of our evaluated and unevaluated properties at December 31, 2004 and 2003 are summarized as follows:
Our natural gas and oil production volumes and average sales price are as follows:
The 2004 average natural gas and crude oil sales prices above do not reflect the impact of derivatives as these amounts are reflected as other income and expenses in the consolidated financial statements consistent with our decision not to elect hedge accounting in 2004. The average natural gas and crude oil prices above for 2002 and 2003 reflect the impact of any hedges. The 2003 average natural gas price was reduced by $0.59 per Mcf and average crude oil price was reduced by $1.80 per Bbl due to our hedges. In 2002, the impact of hedges reduced our average natural gas price by $0.25 per Mcf and our average crude oil price by $1.76 per Bbl.
COMPETITIVE CONDITIONS IN THE BUSINESS
The natural gas and petroleum industry is highly competitive and we compete with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market petroleum and natural gas, as well as, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing natural gas and crude oil properties, and obtaining purchasers and transporters of the natural gas and crude oil we produce. There is also competition between natural gas and petroleum producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and Canada; however, it is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing natural gas and oil and may prevent or delay the commencement or continuation of a given operation. The exact effect of these risk factors cannot be accurately predicted.
OTHER BUSINESS MATTERS
Markets and Major Customers
In 2004, there were no individual customers accounting for more than 10% of our total sales. In 2003 and 2002, approximately 53% and 54%, respectively, of our total sales were made to three individual customers. We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce. We believe other purchasers are available in our areas of operations.
Seasonality of Business
Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of results, which may be realized on an annual basis.
Operational Risks
Oil and gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that we will discover or acquire additional oil and gas in commercial quantities. Oil and gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other circumstances that may cause accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property may occur. In such event, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could substantially reduce available cash and possibly result in loss of oil and gas properties. Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities. We are not aware of any of these instances that have occurred to date that need to be accrued for.
As is common in the natural gas and crude oil industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. For further discussion on risks see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
REGULATIONS
Domestic exploration for, and production and sale of, natural gas and oil are extensively regulated at both the federal and state levels. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas and oil industry that often are costly to comply with and that carry substantial penalties for failure to comply. In addition, production operations are affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.
State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations. Most states in which we operate also have statutes and regulations governing a number of environmental and conservation matters, including the unitization or pooling of natural gas and oil properties and establishment of maximum rates of production from natural gas and oil wells. Many states also restrict production to the market demand for natural gas and oil. Such statutes and regulations may limit the rate at which natural gas and oil and could otherwise be produced from our properties.
We are subject to extensive and evolving environmental laws and regulations. These regulations are administered by the United States Environmental Protection Agency and various other federal, state, and local environmental, zoning, health and safety agencies, many of which periodically examine our operations to monitor compliance with such laws and regulations. These regulations govern the release of waste materials into the environment, or otherwise relating to the protection of the environment, human, animal and plant health, and affect our operations and costs. In recent years, environmental regulations have taken a cradle to grave approach to waste management, regulating and creating liabilities for the waste at its inception to final disposition. Our natural gas and oil exploration, development and production operations are subject to numerous environmental programs, some of which include solid and hazardous waste management, water protection, air emission controls and situs controls affecting wetlands, coastal operations and antiquities.
Environmental programs typically regulate the permitting, construction and operations of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent. Under appropriate circumstances, an administrative agency can request a cease and desist order to terminate operations.
New programs and changes in existing programs are anticipated, some of which include Natural Occurring Radioactive Materials, natural gas and oil exploration and production waste management and underground injection of waste materials.
Each state in which we operate has laws and regulations governing solid waste disposal, water and air pollution. Many states also have regulations governing oil and gas exploration, development and production operations.
We are also subject to Federal and State Hazard Communications and Community Right to Know statutes and regulations. These regulations govern record keeping and reporting of the use and release of hazardous substances. We believe we are in compliance with these requirements in all material respects.
We may be required in the future to make substantial outlays to comply with environmental laws and regulations. The additional changes in operating procedures and expenditures required to comply with future laws dealing with the protection of the environment cannot be predicted.
EMPLOYEES
As of December 31, 2004, we employed 43 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory.
ACCESS TO COMPANY REPORTS
Our SEC filings are available to the public at the SEC’s web site at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference rooms located at 450 Fifth Street, N.W., Washington D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and their copy charges. In addition, through our website, www.petrohawk.com, you can access electronic copies of documents we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K and any amendments to those reports free of charge. Access to those electronic filings is available as soon as practical after filing with the SEC.
CORPORATE GOVERNANCE MATTERS
The Company’s Corporate Governance Guidelines, Code of Conduct, Nominating Committee Charter, Compensation Committee Charter and Audit Committee Charter are available on the Company’s website at www.petrohawk.com , under the Investor Relations section and a copy will be provided, without charge, to any shareholder upon request.
RISK FACTORS
Natural gas and crude oil prices are volatile, and low prices could have a material adverse impact on our business.
Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing natural gas and crude oil prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow under our revolving credit facility will be subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and crude oil that we can economically produce and have an adverse effect on the value of our properties.
Prices for natural gas and crude oil have continued to remain high over the past twelve months. Historically, the markets for natural gas and crude oil have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause volatility:
• the domestic and foreign supply of natural gas and crude oil;
• the ability of members of the Organization of Petroleum Exporting Countries (OPEC) and other producing countries to agree upon and maintain crude oil prices and production levels;
• political instability, armed conflict and terrorist attacks, whether or not in natural gas and crude oil producing regions;
• the level of consumer product demand;
• the growth of consumer product demand in emerging markets, such as China;
• labor unrest in natural gas and oil producing regions;
• weather conditions;
• the price and availability of alternative fuels;
• the price of foreign imports;
• worldwide economic conditions; and
• the availability of liquid natural gas imports.
These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of natural gas and crude oil.
In general, the volume of production from natural gas and crude oil properties declines as reserves are depleted. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities. Our future natural gas and crude oil production is highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.
The successful acquisition of producing properties requires an assessment of a number of factors. These factors include recoverable reserves, future natural gas and crude oil prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties that we believe is thorough. However, there is no assurance that such a review will reveal all existing or potential problems or allow us to fully assess the deficiencies and capabilities of such properties. We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing natural gas and crude oil properties is particularly intense at this time and many of our competitors have financial and other resources which are substantially greater than those available to us.
Our bank lenders can limit our borrowing capabilities, which may materially impact our operations.
As of December 31, 2004, our total debt was $240 million and we had approximately $51 million of cash and additional available borrowing capacity under our revolving credit facility. The borrowing base limitation under our revolving credit facility is semi-annually redetermined. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. The next redetermination date is expected to occur in May 2005. Upon a redetermination, we could be required to repay a portion of our bank debt. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the loan agreement and an acceleration of the loan. We intend to finance our development, acquisition and exploration activities with cash flows from operations, bank borrowings and other financing activities. In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet debt obligations and to reduce our level of debt depends on our future performance which is affected by general economic conditions and other financial and business factors. Many of these factors are beyond our control. Our level of debt affects our operations in several important ways, including the following:
• a portion of our cash flow from operations is used to pay interest on borrowings;
• the covenants contained in the agreements governing our debt limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in business conditions;
• a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisition, general corporate or other purposes;
• a leveraged financial position would make us more vulnerable to economic downturns and could limit our ability to withstand competitive pressures; and
• any debt that we incur under our revolving credit facility will be at variable rates which makes us vulnerable to increases in interest rates.
Our ability to finance our business activities will require us to generate substantial cash flow.
We may not be able to replace production with new reserves through our drilling or acquisition activities.
Our business activities require substantial capital. We have budgeted total capital expenditures in 2005 of approximately $70 million. We intend to finance our capital expenditures in the future through cash flows from operations, the incurrence of additional indebtedness and / or the issuance of additional equity securities. We cannot be sure that our business will continue to generate cash flow at or above current levels. Future cash flows and the availability of financing will be subject to a number of variables, such as:
• the level of production from existing wells;
• prices of natural gas and crude oil;
• our results in locating and producing new reserves;
• the success and timing of development of proved undeveloped reserves; and
• general economic, financial, competitive, legislative, regulatory and other factors beyond our control.
If we are unable to generate sufficient cash flow from operations to service our debt, we may have to obtain additional financing through the issuance of financial securities. We cannot be sure that any additional financing will be available to us on acceptable terms. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. The level of our debt financing could also materially affect our operations.
If our revenues were to decrease due to lower natural gas and crude oil prices, decreased production or other reasons, and if we could not obtain capital through our revolving credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves or maintain production levels could be greatly limited.
We may not be able to replace production with new reserves through our drilling or acquisition activities.
In general, the volume of production from natural gas and crude oil properties declines as reserves are depleted. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities. Our future natural gas and crude oil production is highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.
The successful acquisition of producing properties requires an assessment of a number of factors. These factors include recoverable reserves, future natural gas and crude oil prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties that we believe is thorough. However, there is no assurance that such a review will reveal all existing or potential problems or allow us to fully assess the deficiencies and capabilities of such properties. We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing natural gas and crude oil properties is particularly intense at this time and many of our competitors have financial and other resources which are substantially greater than those available to us.
Drilling wells is speculative, often involves significant costs and may not result in additions to our production or reserves.
Developing and exploring for natural gas and crude oil reserves involves a high degree of operating and financial risk. The actual costs of drilling, completing and operating wells often exceeds our budget for such costs and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, mechanical difficulties, and faulty assumptions about geological features. Moreover, the drilling of a productive natural gas and crude oil well does not ensure a profitable investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, including geological and market-related factors, can cause a well to become uneconomical or only marginally economic. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.
Estimates of natural gas and crude oil reserves are uncertain and inherently imprecise and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.
Our estimates of proved natural gas and crude oil reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions required by the SEC relating to natural gas and crude oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas and crude oil reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Actual future production, natural gas and crude oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and crude oil reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and crude oil prices and other factors, many of which are beyond our control.
At December 31, 2004, approximately 22% of our estimated proved reserves were undeveloped. Estimates of undeveloped reserves are less certain than estimates of developed reserves. Recovery of undeveloped reserves required significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of these natural gas and crude oil reserves and the costs associated with development of these reserves in accordance with SEC regulations, we cannot assure you that the estimated costs or estimated reserves are accurate, that development will occur as scheduled or that the actual results will be as estimated.
In addition, you should not construe our estimate of standardized measure of discounted future net cash flows relating to proved oil and gas reserves included in the Supplemental Oil and Gas Information as the current market value of the estimated oil and natural gas reserves attributable to our properties. We have based the estimated discounted future net cash flows from proved reserve on prices and costs as of the date of the estimate, in accordance with applicable SEC regulations, whereas actual future prices and costs may be significantly higher or lower. Many factors will affect future net cash flow, including:
• prices of natural gas and crude oil;
• the amount and timing of actual production;
• the cost, timing and success in developing proved undeveloped reserves;
• supply and demand for natural gas and crude oil;
• curtailments or increases in consumption by natural gas and crude oil purchasers; and
• changes in governmental regulations or taxation.
The timing of the production of natural gas and crude oil properties and of the related expense affect the timing of actual future net cash flow from proved reserves and, thus, their actual value. In addition, the 10% discount factor used is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business or the natural gas and crude oil industry in general are subject.
We depend on the skill, ability and decisions of third party operators to a significant extent.
We operate approximately 45% of our working interest estimated proved reserves. The success of the drilling, development and production of the natural gas and crude oil properties in which we have or expect to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties. The failure of any third party operator to perform the following in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs:
• make decisions;
• perform their services;
• discharge their obligations;
• deal with regulatory agencies; and
• comply with laws, rules and regulations, including environmental laws and regulations.
Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations.
We depend substantially on the continued presence of key personnel for critical management decision and industry contacts.
Our management team changed significantly with the acquisition of control by PHAWK in May 2004. We have six new directors, all new management, and many new technical personnel. Our future performance will be substantially dependent on retaining key members of this group. The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse affect on our business, operating results, financial condition and cash flows. We currently do not have employment agreements with any of our employees.
Our business is highly competitive.
The natural gas and crude oil industry is highly competitive in many respects, including identification of attractive natural gas and crude oil properties for acquisition, exploration and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities. In seeking suitable opportunities, we compete with a number of other companies, including large natural gas and crude oil companies and other independent operators with greater financial resources and, in some cases, with more expertise. There can be no assurance that we will be able to compete effectively with these entities.
Hedging transactions may limit our potential gains.
In order to manage our exposure to price risks in the marketing of our natural gas and crude oil production, we have entered into natural gas and crude oil price hedging arrangements with respect to a portion of our expected production. We will most likely enter into additional hedging transactions in the future. While intended to reduce the effects of volatile natural gas and crude oil prices, such transactions may limit our potential gains and increase our potential losses if natural gas and crude oil prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:
• our production is less than expected;
• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or
• the counterparties to our hedging agreements fail to perform under the contracts.
Our natural gas and crude oil activities are subject to various risks which are beyond our control.
Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling natural gas and crude oil. Although we may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances. Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce natural gas and crude oil in commercial quantities, the rate of production and the economics of the development of, and our investment in, the prospects in which we have or will acquire an interest. Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows. Such risks and hazards include:
• human error, accidents, labor force and other factors beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;
• blowouts, fires, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;
• unavailability of materials and equipment;
• engineering and construction delays;
• unanticipated transportation costs and delays;
• unfavorable weather conditions;
• hazards resulting from unusual or unexpected geological or environmental conditions;
• environmental regulations and requirements;
• accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment;
• changes in laws and regulations, including laws and regulations applicable to natural gas and crude oil activities or markets for the natural gas and crude oil produced;
• fluctuations in supply and demand for oil and gas causing variations of the prices we receive for our natural gas and crude oil production; and
• the internal and political decisions of OPEC and natural gas and crude oil producing nations and their impact upon natural gas and crude oil prices.
As a result of these risks, expenditures, quantities and rates of production, revenues and cash operating costs may be materially adversely affected and may differ materially from those anticipated by us.
Governmental and environmental regulations could adversely affect our business.
Our business is subject to federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of natural gas and crude oil and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties and other matters. These laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our natural gas and crude oil wells and other facilities. In addition, these laws and regulations and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues.
Our operations are also subject to complex environmental laws and regulations adopted by the various jurisdictions in which we have natural gas and crude oil operations. We could incur liability to governments or third parties for any unlawful discharge of natural gas, crude oil, or other pollutants into the air, soil or water, including responsibility for remedial costs.
We could potentially discharge these materials into the environment in any of the following ways:
• from a well or drilling equipment at a drill site;
• from gathering systems, pipelines, transportation facilities and storage tanks;
• damage to oil and natural gas wells resulting from accidents during normal operations; and
• blowouts, hurricanes, cratering and explosions.
Because the requirements imposed by laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. In addition, because we acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage caused by the former operators.
We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses which may be sustained in connection with all oil and gas activities.
We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards. These policies generally cover:
• personal injury;
• bodily injury;
• third party property damage;
• medical expenses;
• legal defense costs;
• pollution in some cases;
• well blowouts in some cases; and
• workers compensation.
There can be no assurance that this insurance coverage will be sufficient to cover every claim made against us in the future. A loss in connection with our natural gas and crude oil properties could have a materially adverse effect on our financial position and results of operation to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.
Title to the properties in which we have an interest may be impaired by title defects.
We generally obtain title opinions on properties that we drill or acquire. However, there is no assurance that we will not suffer a monetary loss from title defects or failure. Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
We have not paid, and do not anticipate paying, any dividends on our common stock in the foreseeable future.
We have never paid any cash dividends on our common stock. We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock. Holders of our Series A preferred stock are entitled to receive cumulative dividends at the annual rate of $0.74 per share when and as declared by our board of directors. No dividends may be paid on our common stock unless all cumulative dividends due on all of our Series A preferred stock have been declared and paid. Our existing revolving credit facility restricts our ability to pay cash dividends on our preferred stock and common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict our ability to declare cash dividends on our preferred stock and common stock.
ITEM 2.
ITEM 2. PROPERTIES
A description of our properties is included in Item 1. Business and is incorporated herein by reference.
We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On November 23, 2004, we acquired Wynn-Crosby Energy, Inc. and eight of the limited partnerships it for a cash purchase price of approximately $425 million. To finance a portion of the purchase price, we issued $200 million of our Series B 8% Automatically Convertible Preferred Stock (Series B preferred stock) to a group of qualified institutional buyers which were convertible into an approximate aggregate of 25,806,450 shares of our common stock. We obtained an additional $210 million in debt financing through a new revolving credit facility and a second-lien term loan facility with BNP Paribas as the lead bank and administrative agent. In order to accommodate the issuance of our common stock upon conversion of the Series B preferred stock, our board of directors approved an amendment to our certificate of incorporation to increase the number of our authorized shares of common stock from 50 million to 75 million shares. In addition, our board of directors approved an amendment to our 2004 Employee Incentive Plan to increase the aggregate number of shares that can be issued under the plan from 750,000 to 2,750,000.
PHAWK, LLC, which held a majority of our outstanding common stock at the time, approved the conversion of the Series B preferred stock into common stock, the amendment of our certificate of incorporation to increase our authorized shares of common stock from 50 million to 75 million shares and the amendment of our 2004 Employee Incentive Plan to increase the aggregate number of shares of common stock that may be issued under the plan to a total of 2,750,000, each by written consent as permitted by the Delaware General Corporation Law and our bylaws. The action approved by PHAWK became effective on December 31, 2004, which was twenty days after we mailed an information statement to our shareholders describing the actions taken by written consent.
No other matters were submitted to a vote of our shareholders during the fourth quarter of the fiscal year ended December 31, 2004.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock began trading July 16, 2004 on the Nasdaq National Market under the symbol HAWK. Prior to July 16, 2004, our common stock traded on the Nasdaq National Market under the symbol BETA. The following table sets forth for the calendar periods indicated the high and low closing bid prices per share of our common stock as reported on the Nasdaq National Market. The high and low bid amounts for periods prior to May 26, 2004 have been adjusted to reflect the one-for-two reverse split of our common stock effective on that date. The bid information reflects inter-dealer prices, without retail markups, mark-downs, or commissions and may not necessarily represent actual transactions.
We have never paid cash dividends on our common stock. We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future. Holders of our Series A preferred stock are entitled to receive cumulative dividends at the annual rate of $0.74 per share when and as declared by the board of directors. No dividends may be paid on common stock unless all cumulative dividends due on Series A preferred stock have been declared and paid. Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including our prospects, and such other factors, as the board of directors deems relevant. We are also restricted from paying cash dividends on common stock under our credit facilities.
Approximately 209 shareholders of record as of February 2, 2005 held our common stock. In many instances, a registered shareholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.
A description of our equity compensation plan information is incorporated by reference from our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Executive Compensation.
Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities
We did not purchase any equity securities during the fourth quarter of 2004. At December 31, 2004, we held 8,382 treasury shares.
ITEM 6.
ITEM 6. SELECTED HISTORICAL FINANCIAL DATA
The following tables presents selected historical financial data derived from our financial statements. The following data is only a summary and should be read with our historical financial statements and related notes contained in this document. The acquisition of Wynn-Crosby in 2004 and Red River Energy, Inc. in 2000 affects the comparability between the Financial Data for the periods presented.
(1) On May18, 2004, the Company’s Board of Directors approved a one-for-two reverse stock split that was effective May 26, 2004. The reverse stock split was implemented to effect the conditional approval by the NASDAQ National Market of the Company’s listing application, which was later formally approved. As a result, all prior year common stock share amounts have been restated to reflect this reverse stock split in the chart above.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations and our present financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.
Overview
Petrohawk Energy Corporation is an independent oil and gas company engaged in the acquisition, development, production and exploration of natural gas and crude oil. Our exploration activities are concentrated in areas with known hydrocarbons resources, which are conducive to multi-well, repeatable drilling programs.
We have increased our proved reserves and production principally through acquisitions. We focus on properties within our core operating areas that have a significant proved reserve component and which management believes have additional development and exploration opportunities.
Our financial results depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production. Commodity prices are affected by changes in market demands, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas and crude oil prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.
At December 31, 2004, our estimated total proved oil and gas reserves were 219 billion cubic feet of natural gas equivalent (Bcfe), consisting of 161 billion cubic feet of natural gas and 9.7 million barrels of crude oil. Proved reserves are approximately 73% natural gas on an equivalent basis and approximately 78% were classified as proved developed. Year-end prices used to determine proved reserves were $6.18 per Mmbtu of gas and $40.25 per barrel of crude oil.
We have assembled an experienced management team and technical staff with significant experience and expertise in property acquisitions, development and divestments, reservoir engineering, production operations, exploration and financial management. Most of the members of this team have worked together for several years with other companies.
We believe that our cash flow from operations and other financial resources will provide us with the ability to fully develop our existing properties, to finance our current exploration projects and to pursue new acquisition opportunities.
Capital Resources and Liquidity
Our primary source of cash in 2004 was from funds obtained from financing activities. Proceeds from the issuance of long term debt and Series B preferred securities was offset by cash used in investing activities as the Company completed the acquisition of certain oil and gas properties from Wynn-Crosby as well as the acquisition of PHAWK, LLC. In addition to these funds, the Company generated cash flows from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for natural gas and crude have historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout the recent years. Working capital is substantially influenced by these variables. Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures. See Results of Operations for a review of the impact of prices and volumes on sales. Cash flows provided by operating activities were primarily used to fund exploration and development expenditures. See below for additional discussion and analysis of cash flow.
Operating Activities. Net cash provided by operating activities in 2004 increased $14 million from 2003. This increase is primarily due to higher commodity prices and an increase in overall sales volumes in conjunction with the acquisitions discussed above in 2004. Average realized prices increased 38% from $4.78 Mcfe in 2003 to $6.61 Mcfe in 2004. Production volumes increased 91% from 2,632 Mmcfe to 5,030 Mmcfe. We expect 2005 production to increase, but we are unable to predict future commodity prices. As a result, we cannot provide any assurance about future levels of net cash provided by operating activities.
Net cash provided by operating activities in 2003 increased $1.4 million from 2002. This increase was primarily due to a 52% increase in the average equivalent price per Mcfe.
Investing Activities. The primary driver of cash used in investing activities is capital spending, inclusive of acquisitions. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices, our budget may be periodically adjusted during any given year. Cash used in investing activities in 2004 increased $398 million from 2003 to $402. This increase was primarily driven by the acquisition of Wynn-Crosby of approximately $385 million, as well as the acquisition of certain natural gas and oil properties from PHAWK, LLC for approximately $3 million. The remaining increase from prior year was due to an increase in overall capital spending and exploration costs of approximately $11 million. In 2004, we drilled 71 gross wells compared to 28 in 2003. Cash flows used in investing activities decreased from 2002 to 2003 due to a decrease in capital expenditures offset by a decrease in proceeds from sales of certain properties.
Financing Activities. Net cash provided by financing activities in 2004 was $386 million compared to a use of $1 million in 2003. Net cash provided by financing activities in 2004 was primarily driven by the following long-term debt issuances:
• In connection with the acquisition of Wynn-Crosby, we entered into a new revolving credit facility with BNP Paribas as the lead bank that is due in November 2008. The revolving credit facility has an initial borrowing base of $200 million and a threshold amount of $180 million. At December 31, 2004, $155 million is outstanding;
• A second lien facility in the amount of $50 million was also provided by BNP Paribas and a group of lenders that is due February 24, 2009. At December 31, 2004, $50 million is outstanding; and
• In connection with the recapitalization of the Company by PHAWK, LLC, we issued a $35 million five-year unsecured subordinated convertible note payable to PHAWK, LLC.
The Company also received net proceeds of approximately $200 million for the issuance of 2,580,645 share of Series B 8% automatically convertible preferred stock in 2004. The proceeds from this offering and the related financing transactions discussed above were used to fund a portion of the purchase price of Wynn-Crosby.
These cash receipts were offset by the repayment of long-term debt of $69 million, including approximately $41 million for the repayment outstanding long-term debt of Wynn-Crosby assumed in the closing of the transaction as well as the repayment of approximately $13 million of long-term debt upon the closing of the recapitalization of the Company in 2004.
During 2004, we paid $0.6 million in dividends on our Series A Preferred Securities.
Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including acquisitions.
Contractual Obligations
We have no material long-term commitments associated with our capital expenditure plans or operating agreements. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental and exploration activities, gas and oil price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transaction with unconsolidated, limited-purpose entities.
The following table summarizes our contractual obligations and commitments by payment periods.
(1) Future interest expense was calculated based on interest rates and amounts outstanding at December 31, 2004 less required annual repayments.
Amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 2004 is $12.7 million.
Senior Revolving Credit Facility
A senior revolving credit facility in the approximate amount of $400 million has been provided by BNP Paribas and a group of lenders. Availability under the revolver is restricted to the borrowing base. The initial borrowing base is $200 million, and is subject to review and adjustment on a semi-annual basis. Amounts outstanding under the revolver bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.25% to 2.50%. Such margins will fluctuate based on the utilization of the facility. At December 31, 2004, we had a commitment fee of 0.38% on the unused portion of the initial borrowing base. Borrowings under the revolver are secured by first priority liens on substantially all of our assets, including equity interests in subsidiaries. We are subject to certain financial covenants pertaining to minimum working capital levels, minimum coverage of interest expenses, and a maximum leverage ratio. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. All amounts drawn under the revolver are due and payable on November 23, 2008. At December 31, 2004, there were borrowings of $155 million on the senior revolving credit facility.
Second Lien Term Loan Facility
A second lien term loan facility in the amount of $50 million has been provided by BNP Paribas and a group of lenders. Any amounts repaid under the term loan may not be reborrowed. Borrowings under the term loan initially bear interest at LIBOR + 4.00%, increasing by 0.25% on a quarterly basis thereafter, subject to a ceiling of LIBOR + 5.00%. Borrowings under the term loan are secured by second priority liens on all of the assets (including equity interests) that secure the revolver. We are subject to certain financial covenants pertaining to a minimum asset coverage ratio and a maximum leverage ratio. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We are obligated to repay 1% per annum of the original principal balance, with the remaining 96% of the original principal balance due and payable on February 24, 2009. At December 31, 2004, there were borrowings of $50 million under the second lien term loan facility.
Off-balance Sheet Arrangements
At December 31, 2004 and December 31, 2003, the Company did not have any off-balance sheet arrangements.
Plan of Operation for 2005
On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year. We have budgeted $70 million in capital expenditures for 2005.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our financial statements, some of which are subject to alternative treatments under generally accepted accounting principles. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Results of Operations above and Note 1, Organization and Summary of Significant Accounting Policies, to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
Oil and Gas Activities
Accounting for oil and gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and gas activities are available - successful efforts and full cost. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. The successful efforts method requires exploration costs to be expensed as they are incurred while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using period-end prices and costs and a 10% discount rate.
Full Cost Method
We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into the cost centers (the amortization base) that are established on a country-by-country basis. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. Costs associated with production and general corporate activities are expensed in the period incurred. The capitalized costs of our oil and gas properties, plus an estimate of our future development and abandonment costs, are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas activities.
Proved Oil and Gas Reserves
Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the full cost ceiling limitation. Proved oil and gas reserves are the estimated quantities of natural gas and crude oil reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.
In 2004, all of the Company’s reserves, except 26.2 Bcfe related to royalty interest properties, were prepared by Netherland, Sewell & Associates, Inc., an independent oil and gas reservoir engineering consulting firm. Additionally, in 2004, the
Company did not have a significant reserve revision recorded. For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8 Consolidated Financial Statements and Supplementary Data, Supplemental Oil and Gas Disclosure.
Depreciation, Depletion and Amortization
The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test write-down.
Full Cost Ceiling Limitation
Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the quarter are held constant. However, we may not be subject to a write-down if prices increase subsequent to the end of a quarter in which a write-down might otherwise be required. If natural gas and oil prices decline, even if for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of our oil and gas properties could occur in the future.
Costs Withheld From Amortization
Unevaluated costs are excluded from our amortization base until we have evaluated the properties associated with these costs. The costs associated with unevaluated leasehold acreage and seismic data and wells currently drilling are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed quarterly for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred
In addition, a portion of incurred (if not previously included in the amortization base) and future development costs associated with qualifying major development projects may be temporarily excluded from amortization. To qualify, a project must require significant costs to ascertain the quantities of proved reserves attributable to the properties under development (e.g., the installation of an offshore production platform from which development wells are to be drilled). Incurred and future costs are allocated between completed and future work. Any temporarily excluded costs are included in the amortization base upon the earlier of when the associated reserves are determined to be proved or impairment is indicated.
Future Development and Abandonment Costs
Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis.
The accounting for future abandonment costs changed on January 1, 2003 with the adoption of SFAS No. 143. This new standard requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Holding all other factors constant, if our estimate of future abandonment and development costs is revised upward, earnings would decrease due to higher DD&A expense. Likewise, if these estimates are revised downward, earnings would increase due to lower DD&A expense.
Allocation of Purchase Price in Business Combinations
As part of our growth strategy, we actively pursue the acquisition of oil and gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. To the extent the consideration paid exceeds the fair value of the net assets acquired, we are required to record the excess as an asset called goodwill. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value allocated to the recoverable oil and gas reserves and unproved properties is subject to the cost center ceiling as described above.
Accounting for Derivative Instruments and Hedging Activities
Periodically, we utilize and may continue to utilize derivative instruments with respect to a portion of our natural gas and crude oil production to achieve a more predictable cash flow as well as to reduce our exposure to price fluctuations. These transactions generally are price swaps or price collars and are entered into with commodities trading institutions. Derivative financial instruments are intended to reduce the Company’s exposure to declines in the market price of natural gas and crude oil.
Stock Based Compensation
In accordance with current accounting standards, there are two alternative methods that can be used to account for stock-based compensation. The first method, the intrinsic value method, recognizes compensation cost as the excess, if any, of the quoted market price of our stock at the grant date over the amount an employee must pay to acquire the stock. Under the second method, the fair value method, compensation cost is measured at the grant date based on the value of an award and is recognized over the service period, which is usually the vesting period. Currently, we use the fair value method as required by Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123) and related interpretations in accounting for our employee and director stock options. See Item 8 Consolidated Financial Statements and Supplementary Data , Note 1 Summary of Significant Events and Accounting Polices for more information.
Forward-Looking Information
The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, and other factors detailed in this document and in our other Securities and Exchange Commission (SEC) filings. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document.
Comparison of Results of Operations
Year Ended December 31, 2004 and Compared to Year Ended December 31, 2003
We had net income of $8.1 million for the year ended December 31, 2004 compared to $1.0 million for 2003. The acquisition of Wynn-Crosby and the recapitalization by PHAWK, LLC as well as continued increases in natural gas and crude oil prices were the primary reasons for the increase in net income.
The following table summarizes key items of comparison and their related increase (decrease) for the year ended December 31 for the periods indicated.
(1) 2004 amounts exclude the impact of derivatives as the Company did not elect to apply hedge accounting.
For the year ended December 31, 2004, natural gas and crude oil sales increased $20.6 million, from the same period in 2003, to $33.2 million. The increase for the year was primarily due to the increase in volumes of approximately 2,398 Mmcfe that was comprised of a 684 Mmcfe increase for Petrohawk and a 1,714 Mmcfe increase due to the acquisition of Wynn-Crosby. Higher commodity prices led to an approximate $9.2 million increase in revenues from the prior year as our realized average
price per Mcfe increased $1.83 in 2004 to $6.61 from $4.78 in 2003. Continued lower natural storage levels, supply uncertainty due to global events and a weaker U.S. dollar, which impacts the OPEC basket price, favorably impacted crude oil prices again in 2004.
Lease operating expenses increased $3.3 million for the year ended December 31, 2004 as compared to the same period in 2003. The increase was primarily due to the acquisition of Wynn-Crosby and an increase in overall activity in 2004 as we drilled 71 gross wells in 2004 compared to only 28 gross wells in 2003, as well as higher operating costs associated with our offshore Louisiana properties and other recently drilled wells in Kansas and Oklahoma.
Production tax expense increased $1.4 for the year ended December 31, 2004 as compared to the same period in 2003 due to higher natural gas and crude oil revenues. Production taxes are generally assessed as a percentage of gross oil and/or natural gas sales.
General and administrative expense for the twelve months ended December 31, 2004 increased $5.1 million to $7.8 million compared to the same period in 2003. This increase was primarily due to changes in the following items primarily as a result of the Wynn-Crosby acquisition and the recapitalization of the Company by PHAWK, LLC:
In 2004, the Company paid out $1.3 million in bonuses compared to $0.3 million in 2003.
The $0.6 million increase in severance paid in 2004 is due to the recapitalization of the Company by PHAWK, LLC and the transition of the Company’s headquarters from Tulsa, Oklahoma to Houston, Texas.
The increase in salaries and benefits noted above is due to the overall increase in headcount. At December 31, 2004, the Company had 43 full-time employees as compared to 12 full-time employees at December 31, 2003.
During 2004, the Company made the decision to outsource its primary accounting function. This led to the increase in contract services noted above from prior year of $0.8 million. In January 2005, we made the decision to bring these functions back in house.
Stock-based compensation expense increased $3.3 million from prior year to $3.5 million as compared to $0.2 million during the same period in 2003. This increase is due to the $1.8 million recorded during the second quarter of 2004 as a result of the modification of stock options held by certain former employees, as well as $1.7 million recognized by the Company for current year stock option issuances under the fair value accounting method the Company follows.
No impairments were recorded by the Company during 2004 as compared to $0.1 million in 2003.
Accretion expense increased $0.1 million from prior year. This increase is primarily due to the acquisition of Wynn-Crosby in 2004 that led to an increase of $0.1 million from prior year. The remaining increase is due to current year additions.
Depletion expense increased $4.4 million from the same period in 2003 to $9.1 million for the year ended December 31, 2004. Depletion for oil and gas properties is calculated using the Unit of Production method, which essentially amortizes the capitalized costs associated with the evaluated properties based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. On a per unit basis, depletion expense remained relatively flat
increasing 2.3% from $1.77 to $1.81.
Depreciation expense for other assets includes depreciation associated with the gathering assets, which is calculated on a unit of revenue method. The unit of revenue method amortizes the capitalized costs associated with the gathering assets based on the ratio of gross actual revenues for the current period to the total remaining gross revenues for the gathering assets. Depreciation expense for the twelve-month periods ended December 31, 2004 and 2003 was $0.1 million and $0.2 million, respectively.
Interest expense increased $2.5 million for the year ended December 31, 2004 compared to the same period 2003. This increase is primarily due to the issuance of the $35 million 8% subordinated convertible note payable issued in the recapitalization of the Company by PHAWK, LLC and the $210 million debt that was incurred in association with the acquisition of Wynn-Crosby.
Amortization expense represents the amortization of certain debt issue costs associated with the PHAWK transaction and the acquisition of Wynn-Crosby. At December 31, 2004, we had approximately $4 million of deferred issue costs. These costs are being amortized over the lives of the respective long-term debt.
Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. At December 31, 2004, we had a $8.3 million derivative receivable and a $2.1 million derivative liability. The change in the unrealized fair value of these derivative positions are included in earnings as a component of other income and expense along with all realized gains and losses. The Company had realized losses of $1.2 million in 2004 and an unrealized gain at December 31, 2004 of approximately $8.6 million.
Other income at December 31, 2004 is primarily consists of interest income earned on cash available between the recapitalization of the Company by PHAWK, LLC and the Wynn-Crosby acquisition.
Income tax expense increased approximately $1.1 million from prior year. This increase is primarily due to the increase in net income offset by valuation allowance adjustments of $2.4 million.
Year Ended December 31, 2003 and Compared to Year Ended December 31, 2002
We had net income of $1.0 million for the twelve months ended December 31, 2003 compared to a net loss of ($6.9 million) for the same period ended 2002. A significantly higher natural gas and crude oil price environment and lower operating expenses were the primary reasons for the increase in net income. The increase was partially offset by a decrease in our oil and gas production and higher general and administrative expenses during the first nine months of this year when compared to same period for last year. Our results of operations for 2002 included a fourth quarter full cost ceiling impairment of $5.2 million.
The following table summarizes key items of comparison and their related increase (decrease) for the twelve months ended December 31 for the periods indicated.
For the twelve months ended December 31, 2003, natural gas and crude oil sales increased $3.1 million, or 33%, from the same period in 2002, to $12.6 million. The increase for the twelve months was a direct result of higher natural gas and crude oil prices. Lower natural gas inventory levels and normal to above-normal winter demand in the first quarter contributed significantly to the higher natural gas prices. Lower national storage levels, supply uncertainty due to global events and a weaker U.S. dollar, which impacts the OPEC basket price, favorably impacted crude oil prices. The higher commodity prices resulted in an increase in oil and gas revenues of $4.1 million, with higher natural gas prices comprising 82% of the increase. However, lower natural gas volume for the twelve months ended December 31, 2003, as compared to the same period in 2002, partially offset this increase. Our natural gas production was 17% lower when compared to the same period in 2002. The
lower natural gas and crude oil production was primarily due to natural production decline associated with our South Texas, Brookshire, Lapeyrouse and Oklahoma coalbed methane properties. Lower natural gas production volumes resulted in a reduction to natural gas sales of $1.1 million. Our crude oil production volume for the twelve months ended December 31, 2003 was 3% higher when compared to the same period in 2002. The increase in production was a result of our drilling activity in the Brookshire Dome, Texas properties and drilling and recompletion activity on the WEHLU, Oklahoma properties.
Generally, we sell our natural gas and crude oil to various purchasers on an indexed-based or spot price. The indices for natural gas are generally affected by the NYMEX - Henry Hub spot prices while the posted prices for crude oil are generally affected by the NYMEX-Crude Oil West Texas Intermediate prices. From time to time, we use hedges on a limited basis to lessen the impact of price volatility. Hedges covered approximately 28% of our production on an equivalent MMbtu basis for the year ended December 31, 2003. For the twelve months ended December 31, 2003, the average sales price received for our natural gas was reduced by approximately $.59 per Mcf from our natural gas hedges and the average sales price received for our crude oil was reduced by approximately $1.80 per Bbl from our crude oil hedges. For further discussion please refer to Item 8. Financial Statements and Supplementary Data, Note 7. Derivative and Hedging Activities.
Lease operating expenses, excluding production taxes, decreased $0.5 million, or 18%, to $2.4 million for the twelve months ended December 31, 2003 compared to the same period for 2002. The decrease was primarily due to lower operating expense associated with the Brookshire Dome, Texas properties, the Peace Creek and Zenith Field, Kansas properties and the 2002 divestment of certain low margin non-core properties. Lower expenses in the Brookshire Dome area were primarily due to lower salt water disposal expense as a result of injection well availability and lower workover expense in 2003 on the Wade Crawford #1 and Kathleen Pickett #1.
Production and other tax expense increased $0.3 million, or 64%, for the twelve months ended December 31, 2003 as compared to the same period ended in 2002, due to higher natural gas and crude oil revenues. Production taxes are generally assessed as a percentage of gross oil and/or natural gas sales.
General and administrative expense for the twelve months ended December 31, 2003 increased $0.6 million, or 30%, to $2.7 million compared to $2.1 million for the same period in 2002. The increase was due primarily to the following items:
The $0.4 million executive bonus related to the hiring of a new chief executive officer in late 2002 and was paid in the first and third quarters of 2003. Bonuses approved by our Compensation Committee were awarded to the employees for 2003 but were not paid until February 2004 and accordingly were accrued in 2003. Directors’ fees increased in 2003 primarily due to the increased activity related to the proposed Petrohawk transaction in the fourth quarter of 2003. In 2002, we recorded a reserve for bad debt expense related to the uncertainty of recoupment of a portion of a gas contracts settlement. There was no comparable expense in 2003.
Compensation expense from stock options is the expense related to the issuance of common stock options issued to employees and directors during 2003. The Company recognizes compensation expense related to these instruments in accordance with the fair value provisions of SFAS 123. For further discussion, refer to Item 8. Financial Statements and Supplementary Data, Note 8 Stockholders’ Equity.
At December 31, 2003, we had approximately $0.2 million of deferred costs associated with the pending Petrohawk transaction. Had we not consummated the Petrohawk transaction, these costs would have been reflected in our general and administrative cost at that time. These deferred costs were recorded as a reduction to our paid in capital at December 31, 2003.
In August 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS 143). The Company was required to adopt this new standard beginning January 1, 2003. This resulted in accretion expense of $0.1 million in 2003.
Depletion and depreciation expense decreased $0.3 million, or 5%, from the same period in 2002 to $4.9 million for the twelve months ended December 31, 2003. Depletion associated with evaluated oil and gas properties comprised 90% of the decrease. Depletion for oil and gas properties is calculated using the Unit of Production method, which essentially amortizes the capitalized costs associated with the evaluated properties based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. Lower production volumes for 2003, as compared to 2002, and a lower depletion rate for the fourth quarter due a significant increase in our December 31, 2003 reserves from our December 31, 2002 proved reserves were the primary reasons for the decrease in depletion expense. However, the total decrease in depletion expense was partially offset due primarily to a decrease in our December 31, 2002 proved reserves related to our West Broussard prospect, which increased our depletion rate per Mcfe for the first nine months of 2003 to $1.90 as compared to $1.44 for the same period in 2002. Depreciation expense for other assets includes depreciation associated with the gathering assets, which is calculated on a unit of revenue method. The unit of revenue method amortizes the capitalized costs associated with the gathering assets based on the ratio of gross actual revenues for the current period to the total remaining gross revenues for the gathering assets. Depreciation expense for the twelve-month periods ended December 31, 2003 and 2002 was $0.2 million.
At December 31, 2002, we recorded a non-cash impairment charge of $5.2 million on our U.S. domestic evaluated properties due to the transfer of $4.9 million from unevaluated properties related to our Jackson County, Texas area. Additionally, our proved reserves decreased in the fourth quarter of 2002 due to the reclassification of the proved undeveloped reserves associated with the West Broussard prospect, to a less certain reserve category. There was no comparable impairment for our U.S. domestic evaluated properties in 2003.
Interest expense decreased for twelve months ended December 31, 2003, compared to the same period 2002, as a result of lower interest rates and a lower outstanding debt balance.
Related Party Transactions
As previously noted, on August 11, 2004 the Company purchased working interests in certain oil and gas properties and various other assets from PHAWK, LLC for $8.5 million. The effective date of the acquisition is June 1, 2004. Since the Company and PHAWK, LLC are under common control, the assets were recorded by the Company at the net book value of PHAWK, LLC at the time of the sale. The purchase price exceeded the net book value by approximately $5.6 million. The excess is reflected as a return of capital to PHAWK, LLC in the financial statements.
A special committee of one disinterested director was formed by the Company’s board of directors to evaluate, negotiate and complete the purchase. The Special Committee hired an independent reservoir engineering firm to provide a reserve evaluation and engaged an independent financial advisor to evaluate the fairness, from a financial point of view, to the Company. The independent financial advisor has rendered a fairness opinion to the Special Committee.
Recently Issued Accounting Standards
In June 2001, the Financial Accounting Standards Board (FASB) approved for issuance Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations (SFAS 143). SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures. SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The adoption of SFAS 143 resulted in (1) an increase of total liabilities, because more retirement obligations are required to be recognized, (2) an increase in the recognized cost of assets, because the retirement costs are added to the carrying amount of the long-lived assets, and (3) an increase in operating expense, because of the accretion of the retirement obligation and additional depreciation and depletion. The asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells and dismantlement of platforms. The Company adopted the statement on January 1, 2003. The transition adjustment resulting from the adoption of SFAS 143 has been reported as a cumulative effect of a change in accounting principle in January 2003.
In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106 (SAB 106) that provides guidance to oil and gas companies following the full cost accounting method regarding the application of SFAS 143. SAB 106 requires companies calculating the full cost ceiling test to exclude future cash outflows associated with asset retirement obligations that have been accrued on the balance sheet as required by SFAS 143. However, estimated dismantlement and abandonment costs related to future development activities, which are not required to be accrued under SFAS 143, should continue to be included in the full cost ceiling test. The SEC staff has also recommended that companies discuss how the adoption of SFAS 143 has affected their accounting for oil and gas operations. The accounting and disclosure requirements of SAB 106 are to be applied prospectively beginning with the first quarter of 2005. The Company is currently evaluating the effect of SAB 106 on the consolidated financial statements.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure (SFAS 148). SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation (SFAS 123), to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 are effective for financial statements for fiscal years ending after December 15, 2002.
In January 2003, the FASB issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities - An Interpretation of ARB 51 (FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research Bulletin 51, Consolidated Financial Statements, and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. At December 31, 2003 we did not have any entities that would qualify for consolidation in accordance with the provisions of FIN 46. Therefore, the adoption of FIN 46 did not have an impact on our consolidated financial statements.
In April 2003, the FASB issued SFAS No. 149, Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities (SFAS 149). SFAS 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and hedging activities under SFAS 133. The amendments set forth in SFAS 149 require that contracts with comparable characteristics be accounted for similarly. SFAS 149 is generally effective for contracts entered into or modified after June 30, 2003 (with a few exceptions) and for hedging relationships designated after June 30, 2003. The guidance is to be applied prospectively only. The adoption of SFAS 149 did not have an impact on our consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS 150 or the Statement). The Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. The Statement was developed in response to concerns expressed by preparers, auditors, regulators, investors, and other users of financial statements about issuers´ classification in the statement of financial position of certain financial instruments that have characteristics of both liabilities and equity but that have been presented either entirely as equity or between the liabilities section and the equity section of the statement of financial position. The Statement also addresses questions about the classification of certain financial instruments that embody obligations to issue equity shares.
In accordance with SFAS 150, companies with consolidated entities that will terminate by a specified date, such as limited-life partnerships, will have to measure the liabilities for the other owners’ interests in those limited-life entities based on the fair values of the limited-life entities’ assets. Period-to-period changes in the liabilities are to be reported in the consolidated income statement as interest costs. As a result of SFAS 150, liability amounts and related interest costs may be significantly greater than the minority interests previously recognized. The Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this standard did not have an impact on our consolidated financial statements.
On December 16, 2004, the FASB issued Statement No. 153, Exchanges of Nonmonetary Assets (SFAS 153), an amendment of APB Opinion No. 29, to clarify the accounting for nonmonetrary exchanges of similar productive assets. SFAS 153 eliminates the exception from the fair value measurement for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be applied prospectively and is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We do not have any nonmonetary transactions for any period presented that this Statement would apply. We do not expect the adoption of SFAS 153 to have a material impact on our financials statements.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (SFAS 123R). SFAS 123R revises SFAS No. 123, Accounting for Stock-Based Compensation, and focuses on accounting for share-based payments for services by employer to employee. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123R are effective for financial statements for fiscal periods ending June 15, 2005. We are currently evaluating the method of adoption and the impact on our operating results. Our future cash flows will not be impacted by the adoption of this standard. Refer to Item 8 Consolidated Financial Statements and Supplementary Data, Note 1 Summary of Recent Events and Accounting Policies for further information.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural gas and crude oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, crude oil. Declines in natural gas and crude oil prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower natural gas and crude oil prices may also reduce the amount of natural gas and crude oil that we can produce economically. Historically, natural gas and crude oil prices and markets have been volatile, with prices fluctuating widely and they are likely to continue to be volatile.
Prices for natural gas and crude oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and crude oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
• The domestic and foreign supply of natural gas and crude oil;
• The level of consumer product demand;
• Weather conditions;
• Political conditions in crude oil producing regions, including the Middle East;
• The ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain crude oil price and production controls;
• The price of foreign imports;
• Actions of governmental authorities;
• Domestic and foreign governmental regulations;
• The price, availability and acceptance of alternative fuels; and
• Overall economic conditions.
These factors make it impossible to predict with any certainty the future prices of natural gas and crude oil.
We use hedges to reduce price volatility, help ensure that we have adequate cash flow to fund our capital programs and manage price risks and returns on some of our acquisitions and drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. Based on the actual production for the twelve months ended December 31, 2004, approximately 20% of our natural gas production and approximately 11% of our crude oil production was hedged for 2004 as compared to 30% and 23%, respectively, in 2003.
Derivative Instruments and Hedging Activity
Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. At December 31, 2004, we had 90 open positions: 35 natural gas price collar arrangements, 12 natural gas price swap arrangements, 7 natural gas put options, 9 crude oil price swap arrangements and 27 crude oil collar
arrangements. During 2004, we elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, record the change in mark-to-market of these derivative contracts as gains or losses in the income statement net with actual settlements.
At December 31, 2004, we had a $8.3 million derivative receivable and a $2.1 million derivative liability for a net unrealized gain of $6.2 million. In addition, we had a $2.4 million unrealized gain as a result of the purchase price allocation recorded for the acquisition of Wynn-Crosby. These net unrealized gains were offset by $1.2 million of realized losses in 2004, resulting in a net $7.4 million gain in 2004.
For the years ended December 31, 2003 and 2002, the Company designated its derivative positions as hedges against the variability in cash flows associated with the forecasted sale of future natural gas and oil and accounted for them under the guidelines stipulated by SFAS 133. At December 31, 2003, the Company had no open positions but recognized an unrealized gain in 2003 of $0.7 million related to the open positions at December 31, 2002. The Company also recognized a realized loss of $1.3 million that reduced the Company’s average price received by $0.59 per Mcf of natural gas and $1.80 per Bbl of crude oil.
At December 31, 2002, the Company’s open positions had a negative fair value of $0.7 million and accordingly the Company recorded a derivative liability for such amount. The Company also had realized losses of $0.8 million that reduced the Company’s average price received by $0.25 per Mcf of natural gas and $1.76 per Bbl of crude oil.
Natural Gas
At December 31, 2004, we had the following natural gas costless collar positions:
At December 31, 2004, we had the following natural gas swap positions:
In addition to the above positions, the Company had put options covering 360,000 Mmbtu’s a month from January 2005 through March 2005 at a weighted average price of $5.39 per Mmbtu.
Crude Oil
At December 31, 2004, we had the following crude oil costless collar positions:
At December 31, 2004, we had the following crude oil swap positions:
At December 31, 2003, we had no outstanding positions. For more information, refer to Item 8
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Reports of Independent Registered Public Accounting Firms
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002
Consolidated Balance Sheets at December 31, 2004 and 2003
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003 and 2002
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2004, 2003 and 2002
Notes to the Consolidated Financial Statements
Supplemental Oil and Gas Information (Unaudited)
Quarterly Financial Information (Unaudited)
REPORT OF MANAGEMENT
The management of Petrohawk Energy Corporation is responsible for the preparation and integrity of all information contained in the annual report. The consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America and, accordingly, include certain informed judgments and estimates of management.
Management maintains a system of internal accounting and managerial controls and engages internal audit representatives who monitor and test the operation of these controls. Although no system can ensure the elimination of all errors and irregularities, the system is designed to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management’s authorization, and accounting records are reliable for financial statement preparation.
An Audit Committee of the Board of Directors, consisting of directors who are not employees of the Company, meets periodically with management, the independent accountants and internal audit representatives to obtain assurances to the integrity of the Company’s accounting and financial reporting and to affirm the adequacy of the system of accounting and managerial controls in place. The independent accountants and internal audit representatives have full and free access to the Audit Committee to discuss all appropriate matters.
We believe that the Company’s policies and system of accounting and managerial controls reasonably assure the integrity of the information in the consolidated financial statements and in the other sections of the annual report.
Floyd C. Wilson
Chairman, President and Chief Executive Officer
March 31, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Petrohawk Energy Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheet of Petrohawk Energy Corporation and subsidiaries (the “Company”) as of December 31, 2004, and the related consolidated statement of operations, stockholders’ equity, cash flows, and comprehensive income (loss) for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Houston, Texas
March 31, 2005
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
of Beta Oil & Gas, Inc.
We have audited the accompanying consolidated balance sheet of Beta Oil & Gas, Inc. as of December 31, 2003, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Beta Oil & Gas, Inc. at December 31, 2003, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.
As discussed in Notes 1 and 5 to the consolidated financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations. In addition, as also discussed in Note 1, effective January 1, 2003, the Company adopted, prospectively, the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
March 19, 2004
Report of Independent Registered Public Accounting Firm
To the Board of Directors
Petrohawk Energy Corporation
Houston, TX
We have audited the consolidated statements of operations, stockholders’ equity, cash flows and comprehensive income for the year ended December 31, 2002 of Petrohawk Energy Corporation (formerly Beta Oil and Gas, Inc.) and subsidiaries. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provided a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Petrohawk Energy Corporation and subsidiaries for the year ended December 31, 2002, in conformity with U.S. generally accepted accounting principles.
/s/ Hein & Associates LLP
Orange, CA
February 14, 2003
PETROHAWK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
PETROHAWK ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
PETROHAWK ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (Continued)
The accompanying notes are an integral part of these consolidated financial statements.
PETROHAWK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
PETROHAWK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
PETROHAWK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
The accompanying notes are an integral part of these consolidated financial statements.
PETROHAWK ENERGY CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Events and Accounting Policies
Basis of Presentation and Principles of Consolidation
Petrohawk Energy Corporation (Petrohawk or the Company) is an independent oil and gas company engaged in the acquisition, development, production and exploration of natural gas and oil properties located in North America. The Company operates in one segment, natural gas and oil exploration and exploitation almost exclusively within the continental United States. The consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries. All significant intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to the current year presentation.
On May 18, 2004, the Company’s Board of Directors approved a one-for-two reverse stock split that was effective May 26, 2004. The reverse stock split was implemented to effect the conditional approval by the NASDAQ National Market of the Company’s listing application, which was later formally approved. Share and per share data (except par value) for periods presented have been restated to reflect the reverse stock split.
On November 23, 2004, the Company acquired Wynn-Crosby Energy, Inc. and eight of the limited partnerships (Wynn-Crosby) it managed. The acquisition was accounted for using the purchase method of accounting. As a result, the assets and liabilities of Wynn-Crosby are included in the December 31, 2004 consolidated balance sheet and consolidated statements of operations and cash flows for 2004 include 39 days (November 23, to December 31, 2004) of activity for Wynn-Crosby.
Information regarding reserves, working interest, acreage and well head counts, to the extent disclosed, are unaudited.
Use of Estimates
The preparation of the Company’s consolidated financial statements in conformity with generally accepted accounting principles requires the Company’s management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The estimates include oil and gas reserve quantities which form the basis for the calculation of amortization and impairment of natural gas and crude oil properties. Management emphasizes that reserve estimates are inherently imprecise and that estimates of more recent reserve discoveries are more imprecise than those for properties with long production histories. Actual results could materially differ from these estimates.
Cash and Cash Equivalents
The Company considers short-term investments with an original maturity of less than three months to be cash equivalents. Any cash in bank accounts that is unavailable for immediate withdrawal, that is subject to limitations on its use, or that is considered a compensative balance, is classified as restricted cash.
Allowance for Doubtful Accounts
The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. The Company regularly reviews collectibility and establishes or adjusts the allowance as necessary using the specific identification method. There is no allowance for doubtful accounts at December 31, 2004 and December 31, 2003.
Natural Gas and Crude Oil Properties
The Company accounts for its natural gas and oil producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (SEC). Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. All general corporate costs are expensed as incurred. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and gas properties is computed on the units of production method based on all proved reserves on a country-by-country basis. Unproved oil and gas properties are assessed quarterly for impairment either individually or on an aggregate basis, if the properties have similar
characteristics. The net capitalized costs of proved oil and gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. Any impairments to unproved properties are recorded as transfers to the full cost pool.
Property, Plant and Equipment Other than Natural Gas and Crude Oil Properties
Other operating property and equipment are stated at the lower of cost or fair market value. Provision for depreciation and amortization on property and equipment is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 10 years) of the respective assets. Depreciation of the gas gathering assets is computed on a units of revenue method based on the total future gross revenues. The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures, which increase the life of an asset, are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of properties sold, or otherwise disposed of, and the related accumulated depreciation or amortization are removed from the accounts and any gains or losses are reflected in current operations.
Impairment of Long-Lived Assets
In the event that facts and circumstances indicate that the costs of long-lived assets, other than oil and gas properties, may be impaired, an evaluation of recoverability would be performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset’s carrying amount to determine if a write-down to market value or discounted cash flow value is required. Impairment of oil and gas properties is evaluated subject to the full cost ceiling as described under Natural Gas and Crude Oil Properties Section above.
Joint Ventures
Exploration and production activities may be conducted jointly with others and, accordingly, the consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Revenue Recognition
The Company recognizes oil and gas sales upon delivery to the purchaser. Under the sales method, the Company and other joint owners may sell more or less than their entitled share of the natural gas volume produced. Should the Company’s excess sales of natural gas exceed its share of estimated remaining recoverable reserves, a liability is recorded by the Company and revenue is deferred.
Concentrations of Credit Risk
In 2004, there were no individual customers accounting for more than 10% of our total sales. In 2003 and 2002, approximately 53% and 54%, respectively, of the Company’s total sales were made to three individual customers. The Company does not believe the loss of any one of its purchasers would materially affect the Company’s ability to sell the natural gas and crude oil it produces. We believe other purchasers are available in the Company’s areas of operations.
Price Risk Management Activities
On January 1, 2001, we adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133 and as amended by SFAS No. 149, Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities (SFAS 149). All derivatives are recorded in current earnings unless specific hedge accounting criteria are met, including formally designating and assessing the effectiveness of the transactions that receive hedge accounting treatment. From time to time, the Company may hedge a portion of its natural gas and/or crude oil production. Derivative contracts entered into by the Company have consisted of cash flow hedge transactions in which the Company hedges the variability of cash flow related to a forecasted transaction. Changes in the fair value of these derivative instruments are recorded in other comprehensive income and are reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. As of December 31, 2004, and for the year then ended, the Company has elected to not designate any of its positions for hedge accounting.
Income Taxes
The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing
assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Asset Retirement Obligation
In August 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS 143). The Company was required to adopt this new standard beginning January 1, 2003. SFAS 143 requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Upon adoption, the Company recorded an asset retirement obligation to reflect the Company’s legal obligations related to future plugging and abandonment of its oil and gas wells. The Company estimated the expected cash flow associated with the obligation and discounted the amount using a credit-adjusted, risk-free interest rate. The transition adjustment resulting from the adoption of SFAS 143 was reported as a cumulative effect of a change in accounting principle. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggests the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new natural gas and oil wells as these obligations are incurred.
Fair Value of Financial Instruments
The estimated fair values for financial instruments under FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of long-term debt approximates its carrying value because the debt carries interest rates that approximate current market rates with the exception of the 8% subordinated convertible note payable as its fair value cannot be determined because it is due to a related party, PHAWK, LLC. Refer to Note 2 Acquisitions and Divestitures for more information on this instrument.
Stock-Based Compensation
On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123) and related interpretations in accounting for its employee and director stock options and applies the fair value based method of accounting to such options. Under SFAS 123, the fair value of each option granted is estimated on the date of grant using a option-pricing model such as the Black-Scholes model. Under Statement of Financial Accounting Standards No. 148 Accounting for Stock-Based Compensation - Transition and Disclosure , an amendment to SFAS 123, certain transitional alternatives were available for a voluntary change to the fair value based method of accounting for stock-based employee compensation if adopted in a fiscal year beginning before December 16, 2003. The Company used the prospective method which applies prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted. Previous to the adoption, the Company elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and related interpretations in accounting for its employee stock options. However, as required by SFAS 123, the Company disclosed on a pro forma basis the impact of the fair value accounting for employee stock options. Transactions in equity instruments with non-employees for goods or services have been accounted for using the fair value method as prescribed by SFAS 123.
Since the Company adopted the fair value recognition provisions of SFAS 123 prospectively for all employee awards granted, modified or settled after January 1, 2003, the cost related to stock-based compensation included in the determination of income for the years ended December 31, 2003 and 2002, is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS 123. For the year ended December 31, 2004, these costs were accounted for based on the requirements of SFAS 123 due to a modification of the terms granted to employees prior to January 1, 2003.
Awards vest over periods ranging from one to three years. The following table illustrates the effect on net income (loss) and earnings (loss) per share as if the fair value based method had been applied to all outstanding and unvested awards in each period.
The fair value of each grant is estimated on the date of grant using the Black-Scholes option-pricing model. The fair value of stock options included in the pro forma results of each of the two years above is not necessarily indicative of future effects of net income and earnings per share.
The assumptions used in the fair value method calculation are disclosed in the following table:
Earnings per Share
Basic EPS is calculated by dividing the income or loss available to common shareholders by the weighted average number of shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.
Savings Investment Plan
The Company maintains a Savings Investment Plan (SIP) during which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $0.3 million in 2004 and less than $0.1 million in both 2003 and 2002. The Company began matching employee contributions dollar-for-dollar on the first 10% in September 2004. Prior contributions were matched dollar-for-dollar on the first 3% of an employee’s pretax earnings.
Recently Issued Accounting Pronouncements
In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106 (SAB 106) that provides guidance to oil and gas companies following the full cost accounting method regarding the application of SFAS 143. SAB 106 requires companies calculating the full cost ceiling test to exclude future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet as required by SFAS 143. However, estimated dismantlement and abandonment costs related to future development activities, which are not required to be accrued under SFAS 143, should continue to be included in the full cost ceiling test. The SEC staff has also recommended that companies discuss how the adoption of SFAS 143 has affected their accounting for oil and gas operations. The accounting and disclosure requirements of SAB 106 are to be applied prospectively beginning with the first quarter of 2005. The Company is currently evaluating the effect of SAB 106 on the consolidated financial statements.
In January 2003, the FASB issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities - An Interpretation of ARB 51 (FIN 46 or Interpretation). FIN 46 is an interpretation of Accounting Research Bulletin 51, Consolidated Financial Statements, and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. At December 31, 2003 and December 31, 2004, we did not have any entities that would qualify for consolidation in accordance with the provisions of FIN 46. Therefore, the adoption of FIN 46 did not have an impact on our consolidated financial statements.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS 150). This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. This statement was developed in response to concerns expressed by preparers, auditors, regulators, investors, and other users of financial statements about issuers´ classification in the statement of financial position of certain financial instruments that have characteristics of both liabilities and equity but that have been presented either entirely as equity or between the liabilities section and the equity section of the statement of financial position. This statement also addresses questions about the classification of certain financial instruments that embody obligations to issue equity shares.
In accordance with SFAS 150, companies with consolidated entities that will terminate by a specified date, such as limited-life partnerships, will have to measure the liabilities for the other owners’ interests in those limited-life entities based on the fair values of the limited-life entities’ assets. Period-to-period changes in the liabilities are to be reported in the consolidated income statement as interest costs. As a result of SFAS 150, liability amounts and related interest costs may be significantly greater than the minority interests previously recognized. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of this standard did not have an impact on our consolidated financial statements.
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment (SFAS 123R). SFAS 123R revises SFAS No. 123, Accounting for Stock-Based Compensation, and focuses on accounting for share-based payments for services by employer to employee. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123R are effective for financial statements for fiscal periods ending June 15, 2005. We are currently evaluating the method of adoption and the impact on our operating results. Our future cash flows will not be impacted by the adoption of this standard. See Note 1 Summary of Recent Events and Accounting Policies for further information.
In December 2004, the FASB issued SFAS 153, Exchanges of Nonmonetary Assets - an amendment of APB Opinion No. 29 (SFAS 153). The statement requires that nonmonetary exchanges must be recorded at fair value and the appropriate gain or loss must be recognized so long as the fair value is determinable and the transaction has commercial substance. According to this statement, companies can no longer use the similar productive assets concept to account for nonmonetary exchanges at book value with no gain or loss being recognized. SFAS 153 will be effective for fiscal periods beginning after June 15, 2005. The adoption of this statement may impact the Company’s operating results, financial position or cash flows in future periods if such a nonmonetary exchange occurs.
2. ACQUISITIONS AND DIVESTITURES
Wynn-Crosby Transaction
On November 23, 2004, the Company acquired Wynn-Crosby Energy, Inc. and eight of the limited partnerships it managed for a purchase price of approximately $425 million after closing adjustments (the Acquisition or Wynn-Crosby). The transaction was funded with proceeds from a $200 million private equity placement, $210 million in borrowings from its commercial bank group, and cash.
In connection with the Acquisition, Netherland, Sewell & Associates, Inc., the Company’s independent petroleum engineering consultants, evaluated the proved reserves associated with working interest properties, and the Company’s reserve engineers evaluated proved reserves associated with royalty interest properties, resulting in approximately 200 Bcfe of total estimated proved reserves at July 1, 2004. Additionally, 74% of the proved reserves are natural gas and 76% are classified as proved developed.
The properties we acquired in the Acquisition are primarily located in the South Texas, East Texas, Anadarko, Arkoma and Permian Basin regions. The acquired properties include approximately 75,000 net undeveloped acres in the Arkoma Basin in Arkansas, as well as what the Company believes to be significant exploration opportunities in South Louisiana, South Texas and the Anadarko Basin.
Major properties in the Wynn-Crosby asset base include interests in La Reforma, a significant Vicksburg formation field in South Texas, the Dry Hollow and Provident City fields in the Wilcox trend of Lavaca County, Texas, and the Los Indios, Nabors, Ann Mag and McAllen Ranch fields in South Texas. In the East Texas basin, significant properties include interests in the South Carthage, North Beckville and Blocker fields. Other key properties include interests in the Waddell Ranch, Teague and ROC fields in the Permian Basin, the Kinta, Cedars, and Pine Hollow fields in the Arkoma Basin and the Lipscomb and Eakly-Weatherford fields in the Anadarko Basin.
The Acquisition was accounted for using the purchase method of accounting. As a result, the assets and liabilities of Wynn-Crosby were included in the Company’s December 31, 2004 consolidated balance sheet. The Company’s consolidated statements of operations and cash flows for 2004 included 39 days (November 23 to December 31, 2004) of activity for Wynn-Crosby. The total purchase price of approximately $434 million was allocated to specific assets and liabilities based on estimates of fair values resulting in approximately $386 million allocated to proved property, $48 million to unproved property and a net $8 million liability allocated to working capital items. The purchase price allocation is preliminary and subject to change as additional information becomes available. Management does not expect the final purchase price to differ materially from the preliminary allocation.
The following represents the calculation of the Wynn-Crosby purchase price:
(1) Represents Wynn-Crosby credit facility settlements at the closing of the Acquisition.
The Company’s unaudited pro forma results are presented below for the years ended December 31, 2004 and 2003. The unaudited pro forma results have been prepared to illustrate the effects of the Wynn-Crosby acquisition on the Company’s results of operations under the purchase method of accounting as if the Company had acquired Wynn-Crosby on January 1, 2003.
The unaudited pro forma results do not purport to represent what the results of operations would actually have been if the acquisition had in fact occurred on such date or to project the Company’s results of operations for any future date or period.
PHAWK, LLC Transaction
On August 11, 2004, the Company acquired from PHAWK, LLC certain oil and gas properties in the Breton Sound area, Plaquemines Parish, Louisiana and in the West Broussard field in Lafayette Parish, Louisiana having approximately 2.9 Bcfe of estimated proved reserves. This purchase included the acquisition of 79 square miles of recently reprocessed 3-D seismic data and a 25% working interest in eight leased drilling prospects covering 2,528 gross acres in the Breton Sound/Main Pass area as well as two producing wells, pipelines and associated production facilities in Breton Sound Blocks 11 and 23. A 14% working interest (approximately 10% net revenue interest) was acquired in the Montesano #1 well in the West Broussard field. The Montesano #1 well was placed on production in August 2004. The purchase price for all of the proved reserves, seismic data, undeveloped acreage, pipelines, production facility and other assets was $8.5 million. The effective date of the acquisition was June 1, 2004 and the effects of this transaction were first reported in results for the quarter ended September 30, 2004.
Recapitalization by PHAWK, LLC
On May 25, 2004, PHAWK, LLC (formerly known as Petrohawk Energy, LLC), which is owned by affiliates of EnCap Investments, L.P., Liberty Energy Holdings LLC, Floyd C. Wilson and other members of the Company’s management recapitalized the Company with $60 million in cash. The $60 million investment was structured as the purchase by PHAWK of 7.576 million new shares of common stock for $25 million, a $35 million five year 8% subordinated note convertible into approximately 8.75 million shares of common stock and warrants to purchase 5.0 million shares of common stock at a price of
$3.30 per share. At the annual stockholders meeting held July 15, 2004, the stockholders approved changing the name of the Company to Petrohawk Energy Corporation (from Beta Oil & Gas, Inc.), reincorporating the Company in Delaware, and the adoption of new stock option plans.
3. OIL AND GAS PROPERTIES
Oil and gas properties are comprised of the following:
4. LONG-TERM DEBT
Long-term debt as of December 31, 2004 and December 31, 2003 consisted of the following:
(1) Prior year amount represents previous revolving credit facility that was paid off in conjunction with the recapitalization of the Company by PHAWK, LLC in May of 2004 for $60 million. See Note 2 Acquisition and Divestitures for more details.
(2) Convertible into 8.75 million shares of common stock that is issuable upon conversion of this note based on a conversion price of $4.00. In addition, accrued and unpaid interest may be converted into common stock at the same conversion price.
(3) $500,000 of the total $50 million facility has been classified as current on the December31, 2004 balance sheet.
Revolving Credit Facility
In connection with the acquisition of Wynn-Crosby, the Company entered into a new revolving credit facility with BNP Paribas as the lead bank and administrative agent which is due in November 2008. The revolving credit facility has an initial borrowing base of $200 million and a threshold amount of $180 million. Amounts outstanding under the revolving credit facility bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.25% to 2.5%. Such margins will fluctuate based on the utilization of the facility. Borrowings under the credit facility are secured by a first priority lien on substantially all of the Company’s assets and are due on November 23, 2008.
The available credit line is subject to adjustment semi-annually based upon a number of factors, including commodity prices and reserve levels. The next redetermination date is scheduled to occur during the second quarter of 2005. Upon a redetermination, the Company could be required to repay a portion of the bank debt.
The revolving credit facility requires the Company to maintain certain financial covenants pertaining to minimum working capital levels, minimum coverage of interest expense, and a maximum leverage ratio. The Company may not permit its ratio of reserves to total debt to be less than 1.5 to 1.0 after March 31, 2005. The Company may not permit its ratio of total debt to
EBITDA for the period of four fiscal quarters immediately preceding the date of redetermination for which financial statements are available to be greater than 4.0 to 1.0. In addition, the Company is subject to covenants limiting dividends, and other restricted payments, transactions with affiliates, incurrence of debt, changing of control, asset sales, and liens on properties. At December 31, 2004, the Company is in compliance with all of its debt covenants.
Second Lien Term Loan Facility
A second lien facility in the amount of $50 million was provided by BNP Paribas and a group of lenders which is due on February 25, 2009. Amounts outstanding under the term loan may only be drawn at closing, and any amounts repaid may not be reborrowed. Borrowings under the term loan will initially bear interest at LIBOR plus 4.00%, increasing 0.25% on a quarterly basis thereafter, subject to a ceiling of LIBOR plus 5.00%. Borrowings under the second lien facility are secured by a second priority lien on substantially all of the assets securing the revolving credit facility. The Company is subject to certain financial covenants pertaining to minimum asset coverage ratio and a maximum leverage ratio as discussed above under the revolving credit facility. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. The Company is obligated to repay 1% per annum of the original principal balance, with the remaining 96% of the original principal balance due and payable on February 24, 2009. At December 31, 2004, the Company is in compliance with all of its debt covenants.
Subordinated Convertible Note Payable
On May 25, 2004 and in connection with the recapitalization of the Company by PHAWK, LLC, the Company issued a $35 million five-year unsecured subordinated convertible note payable to PHAWK, LLC. The note bears interest at 8%, is payable quarterly until maturity and is convertible after two years to common stock of the Company at a conversion price of $4.00. The full amount of the principal and accrued and unpaid interest will be payable on May 25, 2009.
Previous Revolving Credit Facility
During the year ended December 31, 2003, the Company’s revolving credit facility with a commercial bank was re-determined and its maturity extended to April 1, 2005. The $25 million credit facility had a borrowing base of approximately $14 million, which was subject to an automatic monthly reduction of $88 thousand that commenced July 31, 2003 and was collateralized by the Company’s oil and gas properties and gas gathering system and related assets. The Company paid a fee equal to 0.25% on the unused portion of the borrowing base due quarterly in arrears. This facility was replaced in 2004 with the new revolving credit facility discussed above.
Aggregate maturities required on long-term debt at December 31, 2004 are due in future years as follows:
5. ASSET RETIREMENT OBLIGATION
As discussed in Note 1, the Company adopted SFAS 143 effective January 1, 2003. SFAS 143 requires that the fair value of an asset retirement cost and corresponding liability, should be recorded, as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Upon adoption, the Company recorded an asset retirement obligation of $1.0 million to reflect the Company’s legal obligations related to future plugging and abandonment of its wells. The Company estimated the expected cash flow associated with the obligation and discounted the amount using a credit-adjusted, risk-free interest rate of eight percent. The transition adjustment resulting from the adoption of SFAS 143 and reported as a cumulative effect of a change in accounting principle during 2003, was an increase to income of $2 thousand.
Subsequent to the implementation of SFAS 143, the Company recorded the following activity related to the liability for the year ended December 31, 2003 and December 31, 2004:
(1) Refer to Note 2 Acquisitions and Divestitures for more details on the acquisition.
Had the provisions of SFAS 143 been adopted on January 1, 2002 the asset retirement obligation would have been $1.0 million at December 31, 2002, and the Company’s net loss and loss per share would have been as follows:
6. COMMITMENTS AND CONTINGENCIES
Lease Commitments
The Company leases office space in Houston, Texas and certain vehicles under long-term operating leases. Future minimum lease payments for all non-cancelable operating leases are as follows:
Rent expense was $0.3 million, $0.2 million and $0.2 million for the years ended December 31, 2004, 2003 and 2002, respectively.
Contingencies
From time to time, the Company is a party to ordinary and routine litigation incidental to the Company’s business. The Company is currently not a party to any pending litigation, and is not aware of any threatened litigation that would in the opinion of the Company’s legal counsel, have a significant impact on the consolidated financial statements. The Company has not been a party to any bankruptcy, receivership, reorganization, adjustment or similar proceeding.
7. DERIVATIVE AND HEDGING ACTIVITIES
Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. At December 31, 2004, we had 90 open positions: 35 natural gas price collar arrangements, 12 natural gas price swap arrangements, 7 natural gas put options, 9 crude oil price swap arrangements and 27 crude oil collar arrangements. During 2004, we elected not to designate any positions as cash flow hedges for accounting purposes, and accordingly, record the change in mark-to-market of these derivative contracts as gains or losses in the income statement net with actual settlements.
At December 31, 2004, we had a $8.3 million derivative receivable and a $2.1 million derivative liability for a net unrealized gain of $6.2 million. In addition, we had a $2.4 million unrealized gain as a result of the purchase price allocation recorded for the acquisition of Wynn-Crosby. These net unrealized gains were offset by $1.2 million of realized losses in 2004, resulting in a net $7.4 million gain in 2004.
For the years ended December 31, 2003 and 2002, the Company designated its derivative positions as hedges against the variability in cash flows associated with the forecasted sale of future natural gas and oil and accounted for them under the guidelines stipulated by SFAS 133. At December 31, 2003, the Company had no open positions but recognized an unrealized gain in 2003 of $0.7 million related to the open positions at December 31, 2002. The Company also recognized a realized loss of $1.3 million that reduced the Company’s average price received by $0.59 per Mcf of natural gas and $1.80 per Bbl of crude oil.
At December 31, 2002, the Company’s open positions had a negative fair value of $0.7 million and accordingly the Company recorded a derivative liability for such amount. The Company also had realized losses of $0.8 million that reduced the Company’s average price received by $0.25 per Mcf of natural gas and $1.76 per Bbl of crude oil.
Natural Gas
At December 31, 2004, the Company had the following natural gas costless collar positions:
At December 31, 2004, the Company had the following natural gas swap positions:
In addition to the above positions, the Company had put options covering 360,000 Mmbtu’s a month from January 2005 through March 2005 at a weighted average price of $5.39 per Mmbtu.
Crude Oil
At December 31, 2004, the Company had the following crude oil costless collar positions:
At December 31, 2004, the Company had the following crude oil swap positions:
At December 31, 2003, the Company had no outstanding positions.
8. STOCKHOLDERS’ EQUITY
Series A Preferred Stock
On June 29, 2001 the Company completed its Private Placement Offering of Series A 8% convertible preferred stock and common stock purchase warrants, offered as units of one preferred share and one-half of one warrant at $18.50 per unit. Net proceeds received from the offering were approximately $5.0 million net of estimated offering expenses, including brokers’ commissions and other fees and expenses of $0.5 million. The Company issued 302,136 preferred shares and 151,070 warrants to purchase a like number of shares of the Company’s common stock at a price equal to the offering price or $18.50 per share. Brokers were issued 29,888 non-callable warrants as part of their commission. All investors participating in the offering were accredited. The proceeds were used by the Company to help meet its capital requirements, including drilling costs and for other general corporate purposes.
The preferred shares may be converted by the holder at any time at an exchange rate of one share of the Company’s common stock for each one preferred share converted. The preferred shares will automatically convert into shares of the Company’s common stock on a one-share for one-share basis effective the first trading day after the reported high selling price for the Company’s common stock is at least 150% of the per unit offering price of $18.50 per share or $27.75 per share for any 10 trading days.
The preferred shares pay quarterly cash dividends commencing in the quarter that the preferred shares are issued, at an annual rate of 8% per annum, simple interest, or $0.74 per year.
The Company has the unilateral right to redeem all or any of the outstanding preferred shares from the date of issuance but must pay a premium if redeemed within the first five years. The holders of the preferred shares will be entitled to a liquidation preference equal to the stated value of the preferred shares plus any unpaid and accrued dividends through the date of any liquidation or dissolution of the Company.
In July of 2004, the Company acquired 6,000 shares of the outstanding Series A Preferred Securities.
At December 31, 2004, the liquidation preference was approximately $5,533,890. Warrants are non-transferable and may be exercised at any time through June 29, 2006.
Series B Preferred Stock
In connection with the acquisition of Wynn-Crosby on November 23, 2004, the Company issued and sold 2,580,645 shares of Series B 8% Automatically Convertible Preferred Stock for $77.50 per share, for an aggregate offering amount of approximately $200 million. The Company received approximately $185 million in net proceeds from the offering. The Series B preferred stock was offered and sold pursuant to the private placement exception from registration provided in Regulation D, Rule 506, under Section 4(2) of the Securities Act of 1933, as amended (the Act). Shares of the Series B preferred stock were offered and sold only to qualified institutional buyers as defined in Rule 144A of the Act with whom the placement agent had pre-existing relationships in reliance on applicable exemptions from registration provided under the Act. The placement agent received a commission of 6.0% in connection with the offering.
On December 31, 2004 each outstanding share of the Series B 8% Automatically Convertible Preferred Stock converted into ten shares of common stock. Accordingly, 2,580,645 shares of the Company’s Series B preferred stock converted into 25,806,450 shares of common stock. In addition, the Company’s Certificate of Incorporation was amended to increase the number of authorized shares of common stock from 50,000,000 to 75,000,000 effective December 31, 2004.
Treasury Stock
Effective January 14, 2003, the Company’s Board of Directors authorized a stock repurchase program for up to an aggregate of 50,000 shares of the Company’s common stock. Purchases may be made in the open market, at prevailing market prices, or in privately negotiated transactions from time to time, and will depend on market conditions, business opportunities and other factors. Any purchases are expected to be made in compliance with the safe harbor provisions of Rule 10b-18 promulgated by the Securities and Exchange Commission under the Securities and Exchange Act of 1934, as amended. During 2004, the Company did not purchase any shares of common stock. During 2003, the Company purchased 5,375 shares for $8,275 or approximately $1.54 per share. In August 2004, the Company’s Board of Directors terminated the stock repurchase program.
On September 19, 2001 the Company’s Board of Directors authorized a stock repurchase program for up to an aggregate of $1.0 million of the Company’s common stock to be effective from September 19, 2001 to January 19, 2002. The authorization to repurchase shares was facilitated in part by an order issued by the Securities and Exchange Commission on September 14, 2001. The order temporarily increased the flexibility with respect to certain SEC rules pertaining to issuer stock repurchases. At December 31, 2001, the Company had reacquired 21,250 shares for a total cost of $198,920 or $9.36 per share. In January 2002, the Company reissued 18,243 shares with a public market value of approximately $170,767 for geological and geophysical services associated with certain of its unevaluated properties.
At December 31, 2004, the Company held 8,382 treasury shares.
Warrants and Options
The following table summarizes the number of shares reserved for the exercise of common stock purchase warrants and non-qualified options under the Company’s 1999 Amended Incentive and Non-statutory Stock Option Plan (1999 Plan) and 2004 Employee Incentive Plan as of December 31, 2004:
At December 31, 2004, 5,702,057 warrants, or 100% of the warrants, and 307,500 non-qualifying options were exercisable.
If not exercised, the outstanding warrants and non-qualified options expire as follows:
During the second quarter of 2004, and in connection with the recapitalization of the Company by PHAWK, LLC transaction, the Company issued PHAWK, LLC 5,000,000 million five-year common stock purchase warrants at a price of $3.30 per share. The warrants are exercisable at any time and expire on May 25, 2009.
During 2003, the Company issued non-qualified stock options covering 102,500 shares of common stock to attract certain new employees. These options will equally vest over a three-year period beginning in 2004. The options have exercise prices ranging from $1.70 to $2.86 per share and will expire in 2013.
On December 30, 2002, the Company’s Board of Directors approved the extensions of the expiration dates of certain outstanding common stock purchase warrants with expiration dates ranging from December 30, 2002 through December 31, 2003. The extensions were for an additional two years past the original expiration dates and affected 456,589 common stock purchase warrants. The affected warrants have exercise prices ranging from $7.50 per share to $15.00 per share. The charge to the Company’s 2002 earnings was $14,842.
Effective October 21, 2002, David A. Wilkins was appointed as the Company’s President and CEO and joined the Company’s Board of Directors. As partial consideration for the forfeiture of his incentive common stock options (vested and unvested) with his former employer, Mr. Wilkins was granted an option to purchase 250,000 shares of the Company’s stock at an exercise price of $2.60 per share. The Company also committed to grant, and did grant to him on December 31, 2003 (if he is employed by the Company at that time) an option to purchase 50,000 shares at a price equal to the Company’s common stock closing price on The NASDAQ Stock Market for the preceding business day. These options will have a term of ten years and vest over a three-year period from the date of grant, with one third (1/3) becoming exercisable on the first anniversary of the grant, one third (1/3) becoming exercisable on the second anniversary of the grant and the remaining one third (1/3) becoming exercisable on the third anniversary of the grant.
Stock Option Plans
2004 Employee Incentive Plan
Effective December 31, 2004, the Company’s 2004 Employee Incentive Plan (the 2004 Plan) was amended to increase the aggregate number of shares that can be issued under the 2004 Plan from 750,000 to 2,750,000. The 2004 Plan permits the Company to grant to management and other employees shares of common stock with no restrictions, shares of common stock with restrictions, and options to purchase shares of common stock. Consent of majority shareholder, PHAWK, LLC (PHAWK), to the amendment of the 2004 Plan was obtained on November 29, 2004.
On July 12, 2004, the Company granted stock options covering 687,500 shares of common stock to employees of the Company. The options will vest over a two-year period with one-third vesting on the date of grant, one-third in one year from the date of the grant and the remaining one-third in two years from the date of the grant. The options have an exercise price of $7.50 per share and will expire on July 12, 2014.
On September 27, 2004, the Company granted stock options covering 15,000 shares of common stock to an employee of the Company. The options will vest over a two-year period with one-third vesting on the date of grant, one-third in one year from the date of the grant and the remaining one-third in two years from the date of the grant. The options have an exercise price of $7.99 per share and will expire on September 27, 2014.
On December 8, 2004, the Company granted stock options covering 15,000 shares of common stock to an employee of the Company. The options will vest over a two-year period with one-third vesting on the date of grant, one-third in one year from the date of the grant and the remaining one-third in two years from the date of the grant. The options have an exercise price of $8.54 per share and will expire on December 8, 2014.
The following table sets forth activity for options granted under the 2004 Plan.
If not previously exercised, the outstanding plan options will expire as follows:
At December 31, 2004, 239,167 options were fully vested and exercisable at prices ranging from $7.50 to $8.54 per share. The remaining 478,333 options outstanding will vest over the period from 2005 through 2006 as follows:
At December 31, 2004, 2,032,500 options were available under the Plan for future issuance.
2004 Non-Employee Director Incentive Plan
In July 2004 the Company adopted the 2004 Non-Employee Director Incentive Plan covering 200,000 shares. The plan provides for the grant of both incentive stock options and restricted shares of the Company's stock. This plan was designed to attract and retain the services of directors. At the adoption of the plan each non-employee director received 7,500 restricted shares of the Company's common stock. Under this plan each new non-employee director will receive 7,500 shares of the Company's common stock. Additional grants of 5,000 restricted shares of the Company's common stock are expected to be issued to each non-employee director on each anniversary of his or her service. For the year-ended December 31, 2004, 45,000 shares were issued under this plan and there had been no forfeited or cancelled shares.
1999 Employee Incentive Plan
In August 2000, the Company adopted the 1999 Plan covering 350,000 shares that had previously been approved by the Board of Directors in August 1999. The 1999 Plan is a “dual plan” which provides for the grant of both incentive stock options and non-qualified stock options and was designed to attract and retain the services of employees, officers, directors, and consultants. The price of the options granted pursuant to the plan shall not be less than 100% of the fair market value of the shares on the date of grant. Prices for incentive options granted to employees who own 10% or more of the Company’s stock is at least 110% of market value at date of grant. The Plan is administered by the Compensation Committee consisting of two or more disinterested non-employee board members who will decide the vesting period of the options, if any, and no option will be exercisable after ten years from the date granted. The stock option plan will continue in effect for 10 years from August 20, 1999, unless sooner terminated by the Board of Directors. Unless otherwise provided by the Board of Directors, the stock options granted under the Plan will terminate immediately prior to the consummation of a proposed dissolution or liquidation of the Company. On June 20, 2003, at the Annual Shareholder Meeting the shareholders approved a proposal for an amendment to the 1999 Plan to increase the maximum number of shares of common stock that may be issued under the 1999 Plan to 725,000 from 350,000, or a 375,000 share-increase.
In 2003, the Company issued common stock options under the 1999 Plan covering 157,292 shares of common stock to its directors for services rendered to the Company. These options vested immediately and will expire in 2013. The exercise prices, which were at least 110% of the Company’s common stock price on the date of grant, range from $2.00 to $4.34 per share.
In April, 2003, an outside director returned qualified stock options covering 37,500 shares of common stock to the Company for cancellation. The options were fully vested and had exercise prices of $20.00 per share (25,000 shares) and $10.44 per share (12,500 shares). An additional 62,500 options held by former employees expired in 2003.
Additionally in 2003, the Company issued qualified common stock options covering 100,000 shares of common stock to Company officers, which will vest ratably over a three-year period beginning in 2003 and 2004, with 50,000 options expiring in 2009 and the remaining 50,000 options expiring in 2013. The options have exercise prices ranging from $2.00 to $3.80 per share, which was equal to or greater than the price of the Company’s stock on the grant dates.
For the twelve months ending December 31, 2002, the Company granted 17,500 options with an exercise price of $6.60 per share to certain employees. Of the 17,500 options, one-third (33.3%) of the options vested upon grant, the next one-third will vest on the first anniversary date of the grant and the remaining one-third will vest on the second anniversary date of the grant. Outside directors were granted 50,000 options with the exercise prices ranging from $2.84 to $10.44 per share and vested immediately. The exercise prices were based on 110% of market price of the common stock on the grant dates. All of the options issued in 2002 were for a term of five years and will expire in 2007.
The following table sets forth activity for options under the 1999 Plan in 2004, 2003 and 2002.
If not exercised, the outstanding plan options will expire as follows:
At December 31, 2004, 276,500 options, or 100%, were fully vested and exercisable at prices ranging from $2.00 to $20.50 per share. At December 31, 2004, there were no options available under the Plan for future issuance.
9. INCOME TAXES
Income tax expense for the indicated periods is comprised of the following:
The actual income tax benefit (expense) differs from the expected tax benefit (expense) as computed by applying the U.S. Federal corporate income tax rate of 34% for each period as follows:
The components of the net deferred tax asset recognized are as follows:
As of December 31, 2004, we had available, to reduce future taxable income, a U.S. federal regular net operating loss (NOL) carryforward of approximately $30.8 million, and a U.S. federal alternative minimum tax NOL carryforward of approximately $27.9 million, which expire in the years 2018 through 2024. Utilization of the tax net operating loss carryforward may be limited in the event a 50% or more change of ownership occurs within a three-year period. The estimated limitation for the June 2004 change of ownership is $2.3 million. The tax net operating loss carryforward may be limited by other factors as well. We also had various state NOL carryforwards totaling approximately $28.3 million at December 31, 2004, with varying lengths of allowable carryforward periods ranging from five to 20 years and can be used to offset future state taxable income. It is expected that these deferred tax benefits will be utilized prior to their expiration.
10. OTHER
Related Party Transactions
On August 11, 2004, the Company purchased working interests in certain oil and gas properties and various other assets from PHAWK, LLC for $8.5 million. The effective date of the acquisition is June 1, 2004. Since the Company and PHAWK, LLC are under common control, the assets were recorded by the Company at the net book value of PHAWK, LLC at the time of the purchase. The purchase price exceeded the net book value by approximately $5.6 million. The excess is reflected as a return of capital to PHAWK, LLC in the consolidated financial statements.
A Special Committee of one disinterested director was formed by the Company’s board of directors to evaluate, negotiate and complete the purchase. The Special Committee hired an independent reservoir engineering firm to provide a reserve evaluation and engaged an independent financial advisor to evaluate the fairness, from a financial point of view, to the Company. The independent financial advisor has rendered a fairness opinion to the Special Committee.
11. NET INCOME (LOSS) PER COMMON SHARE
The following represents the calculation of net income (loss) per common share:
The following common stock equivalents were not included in the computation for diluted earnings (loss) per share because their effects were antidilutive.
12. SUBSEQUENT EVENTS (UNAUDITED)
Proton Oil & Gas Corporation
On February 25, 2005, the Company completed the purchase Proton Oil & Gas Corporation for $53 million. This privately negotiated transaction included estimated proved reserves of 28 Bcfe and had an effective date of January 1, 2005. The properties acquired are located in South Louisiana and South Texas. Additional transaction highlights include the following estimates:
• 5.0 Mmcfe of production per day
• 46% natural gas
• 47% proved developed
• 97% operated
• 15 year reserves-to-production ratio
• Probable and possible reserves of over 100 Bcfe
Major properties in the asset base include interests in a multi-pay field in South Louisiana, with 16 Bcfe of estimated proved reserves, 1,018 gross acres and nine PUD locations. In South Texas, significant properties include interests in a multi-pay Frio sand field with 7 Bcfe of estimated proved reserves, 4,230 gross acres and fifteen proved undeveloped locations. The acquisition also included 3-D seismic data covering all major properties.
Sale of Royalty Interest Properties
On February 25, 2005, we completed the disposition of certain royalty interest properties previously acquired from Wynn-Crosby to Noble Royalties, Inc. (Noble) d/b/a Brown Drake Royalties for approximately $80 million in cash. We sold estimated proved reserves of approximately 26 Bcfe with current estimated production of approximately 5.0 Mmcfe per day.
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of proved and proved developed natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made.
Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.
Estimates of proved and proved developed reserves at December 31, 2004 and 2003 were based on studies performed by the Company’s petroleum engineering staff. The estimates were prepared by Netherland, Sewell & Associates, Inc., the Company’s independent consulting petroleum engineers. All the Company’s proved reserves are located in the United States of America.
The following table illustrates the Company’s net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by the Company’s engineering staff.
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows:
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed utilizing SFAS 69, Disclosures about Oil and Gas Producing Activities, procedures and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
• future costs and selling prices will probably differ from those required to be used in these calculations;
• due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;
• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and
• future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying year end oil and gas prices to the estimated future production of year end proved reserves. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor. Use of a 10% discount rate and year end prices are required by SFAS No. 69.
The Standardized Measure is as follows:
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Company’s proved oil and gas reserves during each of the years in the three year period ended December 31, 2004.
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table presents selected quarterly financial data derived from our financial statements. The following data is only a summary and should be read with our historical financial statements and related notes contained in this document. The acquisition of Wynn-Crosby in 2004 and Red River Energy, Inc. in 2000 affects the comparability between the Financial Data for the periods presented.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
On July 20, 2004, the Company appointed Deloitte & Touche LLP as independent auditors to perform the audit of the Company’s consolidated financial statements for fiscal year 2004. Concurrent with the appointment of Deloitte & Touche LLP, the Company dismissed Ernst & Young LLP who audited the consolidated financial statement for fiscal year 2003 and had been the Company’s auditor since June 30, 2003. The Company engaged Deloitte & Touche LLP for fiscal year 2004 as a result of the move from Tulsa, Oklahoma to Houston, Texas in 2004. The Company had previously been audited by Hein & Associates LLP, but switched to Ernst & Young LLP based on the desire to have independent auditors with an office and presence in Tulsa, Oklahoma where the Company’s corporate office had been located at the time. The decisions to replace Ernst & Young LLP and engage Deloitte & Touche LLP, as well as the decision to replace Hein & Associates LLP with Ernst & Young LLP, were approved by the Audit Committee of the Board of Directors.
There were no disagreements with Deloitte & Touche LLP, Ernst & Young LLP or Hein & Associates LLP on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Deloitte & Touche LLP, Ernst & Young LLP or Hein & Associates LLP, would have caused it to make reference thereto in its report on our consolidated financial statements for such time periods. Also during those time periods, there were no reportable events as such term is used in Item 304(a)(1)(v) of Regulation SK.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Based on their evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report on Form 10-K are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.
During the fourth fiscal quarter of the fiscal year covered by this report on Form 10-K, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Directors and Executive Officers of the Registrant.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Executive Compensation.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Principal Stockholders and Security Ownership of Management.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Certain Transactions.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Ratification of Appointments of Independent Auditors.
ITEM 15.
ITEM 15. SECTION 16 COMPLIANCE
The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Section 16 Compliance.
ITEM 16. CODE OF ETHICS
The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Code of Ethics.
PART IV
ITEM 17. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(1) Consolidated Financial Statements:
The consolidated financial statements of the Company and its subsidiaries and report of independent public accountants listed in Section 8 of this Form 10-K are filed as a part of this Form 10-K
(2) Consolidated Financial Statements Schedules:
All schedules are omitted because they are inapplicable or because the required information is contained in the financial statements or included in the notes thereto.
(3) Exhibits:
The following documents are included as exhibits to this Form 10-K.
EXHIBIT NUMBER
DESCRIPTION
2.1
Agreement and Plan of Merger, dated October 13, 2004, among Petrohawk Energy Corporation, Wynn-Crosby Energy, Inc., Ronald W. Crosby and Paige L. Crosby, incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed on November 24, 2004.
2.2
Agreement and Plan of Mergers, dated October 13, 2004, among Petrohawk Energy Corporation, Wynn-Crosby Energy, Inc., Wynn-Crosby 1994, Ltd.; Wynn-Crosby 1995, Ltd.; Wynn-Crosby 1996, Ltd.; Wynn-Crosby 1997, Ltd.; Wynn-Crosby 1998, Ltd.; Wynn-Crosby 1999, Ltd.; Wynn-Crosby 2000, Ltd.; Wynn-Crosby 2002, Ltd.; WCOG Properties, Ltd.; Kara Nicole Limited; Kristen Lee Limited; Eric Wynn Limited; Christopher David Limited; Paige Lee Limited; Bernadien Wynn Limited; Roger Lee Limited; and George Heaps Limited, and Ronald W. Crosby incorporated by reference to Exhibit 2.2 of our Current Report on Form 8-K filed on November 24, 2004.
2.3
Amendment to Agreement and Plan of Mergers among Petrohawk Energy Corporation, Wynn-Crosby Energy, Inc., Wynn-Crosby 1994, Ltd.; Wynn-Crosby 1995, Ltd.; Wynn-Crosby 1996, Ltd.; Wynn-Crosby 1997, Ltd.; Wynn-Crosby 1998, Ltd.; Wynn-Crosby 1999, Ltd.; Wynn-Crosby 2000, Ltd.; Wynn-Crosby 2002, Ltd.; WCOG Properties, Ltd.; Kara Nicole Limited; Kristen Lee Limited; Eric Wynn Limited; Christopher David Limited; Paige Lee Limited; Bernadien Wynn Limited; Roger Lee Limited; and George Heaps Limited, and Ronald W. Crosby, dated October 26, 2004, incorporated by reference to Exhibit 2.3 of our Current Report on Form 8-K filed on November 24, 2004.
3.1
Certificate of Incorporation for Petrohawk Energy Corporation, incorporated by reference to Exhibit 3.1 to the Form S-8 that we filed on July 29, 2004.
3.2
Certificate of Amendment of Certificate of Incorporation of Petrohawk Energy Corporation, incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed on November 24, 2004.
3.3
Amended and Restated Bylaws of Petrohawk Energy Corporation, incorporated by reference to Exhibit 3.2 of our Third Quarter 2004 Form 10-Q filed on August 13, 2004.
4.1
Form of Warrant Agreement covering warrants issued to employees as employment inducements incorporated by reference to Exhibit 4.1 of Beta Oil & Gas, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2003 filed on March 26, 2004.
4.2
Warrant Agreement between Beta Oil & Gas, Inc. and Brookstreet Securities dated July 30, 1999, incorporated by reference to Exhibit 4.2 of Beta Oil & Gas, Inc.’s Annual Report for the year ended December 31, 2003 Form 10K filed on March 26, 2004.
4.3
Form of Warrant Agreement with suppliers, service providers and other third parties, incorporated by reference to Exhibit 4.3 of Beta Oil & Gas, Inc.’s Annual Report for the year ended December 31, 2003 Form 10K filed on March 26, 2004.
4.4
Certificate of Designation of Beta Oil & Gas, Inc.’s 8% Cumulative Convertible Preferred Stock, incorporated by reference to Exhibit 3.1 of Beta’s Form 8-K filed on July 3, 2001.
4.5
Warrant Agreement between Beta Oil & Gas, Inc. and its preferred shareholders, including Warrant Certificates A and B, incorporated by reference to Exhibit 4.1 of Beta Oil & Gas, Inc.’s Form 8-K filed on July 3, 2001.
4.6
Certificate of Designation, Preferences, Rights and Limitations of Series B 8% Automatically Convertible Preferred Stock of Petrohawk Energy Corporation, incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed on November 24, 2004.
4.7
Registration Rights Agreement dated November 23, 2004, among Petrohawk Energy Corporation and Friedman, Billings, Ramsey & Co., Inc. incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K filed on November 24, 2004.
4.8
Registration Rights Agreement, dated May 25, 2004, between Beta and PHAWK, LLC, incorporated by reference to Exhibit 4.11 to our Registration Statement No. 333-120881 on Form S-3 filed December 1, 2004.
10.1
The Petrohawk Energy Corporation Amended and Restated 1999 Incentive and Nonstatutory Stock Option Plan, incorporated by reference to Exhibit 99.3 of our Current Report on Form 8-K filed on August 18, 2004.
10.2
The Petrohawk Energy Corporation Amended and Restated 2004 Non-Employee Director Incentive Plan (Form 10-K for 2004)
10.3
Form of Stock Option Agreement for the Amended and Restated 2004 Non-Employee Director Incentive Plan. (Form 10-K for 2004)
10.4
Form of Restricted Stock Agreement for the Amended and Restated 2004 Non-Employee Director Incentive Plan. (Form 10-K for 2004)
10.5
Form of Incentive Stock Agreement for the Amended and Restated 2004 Non-Employee Director Incentive Plan. (Form 10-K for 2004)
10.6
The Petrohawk Energy Corporation Amended and Restated 2004 Employee Incentive Plan, incorporated by reference to Exhibit 99.2 of our Current Report on Form 8-K filed on August 18, 2004.
10.7
Amendment No. 1 to the Petrohawk Energy Corporation Amended and Restated 2004 Employee Incentive Plan, incorporated by reference to Appendix B to our Definitive Information Statement filed on Schedule 14C on December 14, 2004.
10.8
Form of Stock Option Agreement for the Amended and Restated 2004 Employee Incentive Plan. (Form 10-K for 2004)
10.9
Form of Restricted Stock Agreement for the Amended and Restated 2004 Employee Incentive Plan. (Form 10-K for 2004)
10.10
Form of Incentive Stock Agreement for the Amended and Restated 2004 Employee Incentive Plan. (Form 10-K for 2004)
10.11
Form of Director and Officer Indemnity Agreement. (Form 10-K for 2004)
10.12
Securities Purchase Agreement dated December 12, 2003 between Beta Oil & Gas, Inc. and Petrohawk Energy, LLC, incorporated by reference to Appendix A to Beta’s Preliminary Proxy Statement filed on Schedule 14A on January 9, 2004.
10.13
Senior Revolving Credit Facility dated November 23, 2004, among Petrohawk Energy Corporation, as Borrower, and BNP Paribas, as Administrative Agent, Fleet National Bank, as Syndication Agent, Fortis Capital Corp., U.S. Bank National Association and KeyBank National Association as Co-Documentation Agent, and the lenders party thereto, incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on November 24, 2004.
10.14
Second Lien Term Loan Agreement dated November 23, 2004, among Petrohawk Energy Corporation, as Borrower, and BNP Paribas, as Administrative Agent, and the lenders party thereto, incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on November 24, 2004.
10.15
Guarantee and Collateral Agreement dated November 23, 2004, made by Petrohawk Energy Corporation and each of its subsidiaries, as Grantors, in favor of BNP Paribas, as Administrative Agent, incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed on November 24, 2004.
10.16
Convertible Promissory Note dated May 25, 2004 between PHAWK, LLC f/k/a Petrohawk Energy, LLC and the Company. (Form 10-K for 2004)
10.17
Purchase and Sale Agreement executed January 14, 2005, by and between Wynn-Crosby 1994, Ltd., et al and Noble Royalties, Inc. d/b/a Brown Drake Royalties incorporated by reference to Exhibit 2.1 to our Current Form 8-K filed on March 3, 2005
10.18
Amendment to Purchase and Sale Agreement executed on February 15, 2005, by and between Wynn-Crosby 1994, Ltd., et al and Noble Royalty, Inc. d/b/a Brown Drake Royalties incorporated by reference to Exhibit 2.2 to our Current Form 8-K filed on March 3, 2005
10.19
Stock Purchase Agreement dated February 4, 2005 by and among the Company and Proton Oil & Gas Corporation, et al incorporated by reference to Exhibit 2.3 to our Current Form 8-K filed on March 3, 2005
10.20
Agreement of Sale and Purchase dated August 11, 2004, by and between the Company and PHAWK, LLC. (Form 10-K for 2004)
14.1
Code of Ethics, incorporated by reference to Exhibit D of Beta Oil & Gas, Inc.’s Definitive Proxy on Schedule 14A filed on June 23, 2004.
16.1
Letter of HEIN & Associates LLP is incorporated by reference to Exhibit 16 Beta Oil & Gas, Inc.’s Current Report on Form 8-K/A filed on May 19, 2003.
16.2
Letter of Ernst & Young LLP is incorporated by reference to Exhibit 16.1 our Current Report on Form 8-K/A filed on July 27, 2004
21.1
List of Subsidiaries (Form 10-K for 2004)
23.1
Consent of Hein & Associates, LLP dated March 31, 2005 (Form 10-K for 2004)
23.2
Consent of Deloitte & Touche LLP dated March 31, 2005 (Form 10-K for 2004)
23.3
Consent of Ernst & Young LLP dated March 28, 2005 (Form 10-K for 2004)
23.4
Consent of Netherland, Sewell & Associates, Inc .dated March 31, 2005 (Form 10-K for 2004)
31.1
Certificate of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002 (Form 10-K for 2004)
31.2
Certificate of Chief Financial Officer under Section 302 of Sarbanes-Oxley Act of 2002 (Form 10-K for 2004)
32.1
Certificate of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002 (Form 10-K for 2004)
32.2
Certificate of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002 (Form 10-K for 2004)
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Floyd C. Wilson
Chairman of the Board of Directors,
March 31, 2005
Floyd C. Wilson
Chief Executive Officer and President
/s/ Shane M. Bayless
Chief Financial Officer, Vice President and
March 31, 2005
Shane M. Bayless
Treasurer (Principal Accounting Officer)
/s/ Tucker S. Bridwell
Director
March 31, 2005
Tucker S. Bridwell
/s/ James L. Irish III
Director
March 31, 2005
James L. Irish III
/s/ David B. Miller
Director
March 31, 2005
David B. Miller
/s/ D. Martin Phillips
Director
March 31, 2005
D. Martin Phillips
/s/ Daniel Rioux
Director
March 31, 2005
Daniel Rioux
/s/ Robert C. Stone, Jr.
Director
March 31, 2005
Robert C. Stone, Jr.