EX-99.1 3 prospectus.txt EXHIBIT 99.1 Forward-Looking Statements This exhibit contains statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. You generally can identify our forward-looking statements by the words "anticipate," "believe," "budgeted," "continue," "could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective," "plan," "potential," "predict," "projection," "scheduled," "should," "will" or other similar words. These forward-looking statements include, among others, statements regarding: o our growth strategies; o our ability to explore for and develop natural gas and oil resources successfully and economically; o anticipated trends in our business; o our future results of operations; o our liquidity and our ability to finance our exploration and development activities; o future market conditions in the oil and gas industry; o our ability to make and integrate acquisitions; o the impact of governmental regulation; and o future acquisitions. More specifically, our forward looking statements include: o our estimates of the timing and number of wells we expect to drill and other exploration activities; and o statements regarding our capital expenditure program. We have based our forward-looking statements on our management's beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements. Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under "Risk Factors" and in other sections of this exhibit. You should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement. Business Strategy Growth Through the Drillbit Our objective is to create shareholder value through the execution of a business strategy designed to capitalize on our strengths. Key elements of our business strategy include: o grow primarily through drilling; o focus on prolific and industry-proven trends; o aggressively evaluate 3-D seismic data and acquire acreage to maintain a large drillsite inventory; o maintain a balanced exploration drilling portfolio; o manage risk exposure by market testing prospects and optimizing working interests; and o retain and incentivize a highly qualified technical staff. Through the execution of this business strategy, we have achieved the following results from January 1, 2000 through December 31, 2003: o we drilled 117 wells in our onshore Gulf Coast area, 107 of which were classified as exploratory wells, with a 77% success rate; and o our annual production grew from 4.3 Bcfe in 1999 to 7.5 Bcfe in 2003, a compound annual growth rate of approximately 15%. In addition, we have achieved the following results over the three years ended December 31, 2002: o our average annual reserve replacement percentage was 222% and; o our proved reserves grew from 40.6 Bcfe at December 31, 1999 to 63.2 Bcfe at December 31, 2002, a compound annual growth rate of 16%. Summary Reserve and Production Data The following table sets forth summary information concerning our estimated proved natural gas and oil reserves at December 31, 2000, 2001 and 2002 based on reports prepared by Ryder Scott Company and Fairchild and Wells, Inc., Independent Petroleum Engineers. The PV-10 Value and the Standardized Measure attributable to our proved reserves, shown below, use prices and costs in effect as of December 31 of the year for which such information is presented.
At December 31, --------------------------------------- 2000 2001 2002 ----------- ----------- ----------- Estimated Net Proved Reserves: Natural gas (MMcf).......................................... 10,992 17,858 12,922 Oil (MBbls)................................................. 6,397 6,857 8,381 Natural gas equivalent (MMcfe)........................... 49,377 59,000 63,208 PV-10 Value (in thousands)(1)............................... $ 88,830 $ 49,582 $ 83,614 Standardized Measure (in thousands)......................... $ 70,106 $ 44,577 $ 65,297 Prices Used in Calculating Estimated Value of Proved Reserves: Natural gas (per Mcf)....................................... $ 10.34 $ 2.76 $ 4.70 Oil (per Bbl)............................................... 24.85 17.71 29.16 Other Reserve Data: Average all-sources finding cost (per Mcfe)(2).............. $ 1.01 $ 1.97 $ 1.89 Average reserve replacement percentage...................... 241% 279% 163% Proved developed reserves (MMcfe)........................... 16,452 20,702 21,184
Our average all-sources finding cost for the three years ended December 31, 2002 was $1.59 per Mcfe. The following table sets forth summary information concerning our production results, sales prices and costs and expenses for the years ended December 31, 2000, 2001 and 2002 and for the nine-month periods ended September 30, 2002 and 2003. 2
Nine Months Ended Year Ended September 30, ------------------------------ ------------------- 2000 2001 2002 2002 2003 -------- -------- -------- -------- -------- Net Production Volume: Oil (MBbls)...................... 198 160 401 261 363 Natural gas (MMcf)............... 5,460 4,432 4,801 3,543 3,432 Natural gas equivalent (MMcfe) 6,651 5,390 7,207 5,109 5,607 Average Pre-hedge Sales Prices: Oil (per Bbl).................... $ 28.64 $ 24.14 $ 25.63 $ 23.95 $ 31.02 Natural gas (per Mcf)............ 4.15 4.58 3.62 3.32 5.87 Average Post-hedge Sales Prices: Oil (per Bbl).................... $ 27.81 $ 24.28 $ 24.94 $ 23.34 $ 29.08 Natural gas (per Mcf)............ 3.90 5.04 3.50 3.24 5.56 Costs and Expenses (per Mcfe): Oil and natural gas operating expenses........................ $ 0.74 $ 0.77 $ 0.68 $ 0.72 $ 0.90 Depreciation, depletion and amortization.................... 1.08 1.20 1.47 1.44 1.56 General and administrative....... 0.47 0.62 0.57 0.60 0.77
---------- (1) The PV-10 Values are pre-tax and were determined by using the year-end sales prices, which averaged $24.85, $17.71 and $29.16 per Bbl of oil, and $10.34, $2.76 and $4.70 per Mcf of natural gas in 2000, 2001 and 2002, respectively. (2) Our all-sources finding cost excludes the coalbed methane unproved property costs we contributed as a minority investment to Pinnacle Gas Resources, Inc. in June 2003 and, accordingly, is no longer included in our consolidated operations. We believe our calculation of finding cost provides investors with an indication of our relative exploration efficiency. In addition, our management uses finding cost as a component of our individual well economic analysis. The table below reconciles our calculation of finding cost to our costs incurred in the purchase of proved and unproved properties and in development and exploration activities, excluding capitalized interest on unproved properties of $3.6 million, $3.2 million and $3.1 million for the years ended December 31, 2000, 2001 and 2002, respectively:
Year Ended December 31, ------------------------------------ 2000 2001 2002 ---------- ---------- ---------- (in thousands, except finding cost) Acquisition costs: Unproved properties contributed to Pinnacle....... -- $ 5,239 $ 1,323 Other unproved properties......................... $ 6,641 7,368 5,079 Proved properties................................. 337 800 660 Exploration......................................... 7,843 18,356 14,194 Development......................................... 1,361 3,065 2,351 ---------- ---------- ---------- Total costs incurred.............................. $ 16,182 $ 34,828 $ 23,607 ========== ========== ========== Less unproved properties contributed to Pinnacle.... -- $ 5,239 $ 1,323 ---------- ---------- ---------- Adjusted costs...................................... $ 16,182 $ 29,589 $ 22,284 ========== ========== ========== Total proved reserves added......................... 16,040 15,018 11,761 ---------- ---------- ---------- Average all-sources finding cost (per Mcfe)......... $ 1.01 $ 1.97 $ 1.89 ========== ========== ==========
Risk Factors Natural gas and oil drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us. Our success will be largely dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including: o unexpected or adverse drilling conditions; o elevated pressure or irregularities in geologic formations; 3 o equipment failures or accidents; o adverse weather conditions; o compliance with governmental requirements; and o shortages or delays in the availability of drilling rigs, crews and equipment. Because we identify the areas desirable for drilling from 3-D seismic data covering large areas, we may not seek to acquire an option or lease rights until after the seismic data is analyzed or until the drilling locations are also identified; in those cases, we may not be permitted to lease, drill or produce natural gas or oil from those locations. Even if drilled, our completed wells may not produce reserves of natural gas or oil that are economically viable or that meet our earlier estimates of economically recoverable reserves. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources. Because of the risks and uncertainties of our business, our future performance in exploration and drilling may not be comparable to our historical performance. We may not adhere to our proposed drilling schedule. Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including: o the results of our exploration efforts and the acquisition, review and analysis of the seismic data; o the availability of sufficient capital resources to us and the other participants for the drilling of the prospects; o the approval of the prospects by the other participants after additional data has been compiled; o economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability and prices of drilling rigs and crews; and o the availability of leases and permits on reasonable terms for the prospects. Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital budget may be based on statistical results of drilling activities in other 3-D project areas that we believe are geologically similar rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from those statistical results. In addition, our drilling schedule may vary from our expectations because of future uncertainties. Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future. There are numerous uncertainties inherent in estimating natural gas and oil reserves and their estimated value, including many factors beyond the control of the producer. The reserve data set forth in this exhibit represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The reserve data included in this exhibit represents estimates that depend on a number of factors and assumptions that may vary considerably from actual results, including: o historical production from the area compared with production from other areas; o the assumed effects of regulations by governmental agencies; o assumptions concerning future natural gas and oil prices; o future operating costs; 4 o severance and excise taxes; o development costs; and o workover and remedial costs. For these reasons, estimates of the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, classifications of those reserves based on risk of recovery and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. As of December 31, 2002, approximately 66% of our proved reserves were either proved undeveloped or proved nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 31, 2002 had produced for a relatively short period of time as of that date. Because most of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved. We have from time to time chosen to delay development of our proved undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing shorter-term exploration projects with higher potential rates of return, adding to our lease position in this field and further evaluating additional economic enhancements for this field's development. The discounted future net cash flows included in this exhibit are not necessarily the same as the current market value of our estimated natural gas and oil reserves. As required by the Securities and Exchange Commission (the SEC), the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate. Actual future net cash flows also will be affected by factors such as: o the actual prices we receive for natural gas and oil; o our actual operating costs in producing natural gas and oil; o the amount and timing of actual production; o supply and demand for natural gas and oil; o increases or decreases in consumption of natural gas and oil; and o changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board in Statement of Financial Accounting Standards No. 69 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future. In general, the volume of production from natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. The business of exploring for, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. In addition, we are dependent on finding partners for our 5 exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected. Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results. Our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of natural gas and oil. Historically, the markets for natural gas and oil prices have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future natural gas and oil price movements with certainty. Prices for natural gas and oil are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors beyond our control. These factors include: o the level of consumer product demand; o overall economic conditions; o weather conditions; o domestic and foreign governmental relations; o the price and availability of alternative fuels; o political conditions; o the level and price of foreign imports of oil and liquefied natural gas; and o the ability of the members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil price controls. Declines in natural gas and oil prices may materially adversely affect our financial condition, liquidity and ability to finance planned capital expenditures and results of operations. We face strong competition from other natural gas and oil companies. We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated natural gas and oil companies and numerous independent natural gas and oil companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the natural gas and oil business much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment. We may not be able to keep pace with technological developments in our industry. The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other natural gas and oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. We are subject to various governmental regulations and environmental risks. 6 Natural gas and oil operations are subject to various federal, state and local government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, plug and abandonment bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil. Other federal, state and local laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of natural gas and oil, by-products thereof and other substances and materials produced or used in connection with natural gas and oil operations. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities and may be required to incur substantial remediation costs. Further, we or our affiliates hold certain mineral leases in the State of Montana that require coalbed methane drilling permits, the issuance of which has been challenged in pending litigation. We may not be able to obtain new permits in an optimal time period or at all. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new or modified laws and regulations could have a material adverse effect on our business, financial condition and results of operations. We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues. The natural gas and oil business involves operating hazards such as: o well blowouts; o mechanical failures; o explosions; o uncontrollable flows of oil, natural gas or well fluids; o fires; o geologic formations with abnormal pressures; o pipeline ruptures or spills; o releases of toxic gases; and o other environmental hazards and risks. Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others. We may not have enough insurance to cover all of the risks we face. In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability. We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interests could 7 reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator's o timing and amount of capital expenditures; o expertise and financial resources; o inclusion of other participants in drilling wells; and o use of technology. The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues. The marketability of our production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. We generally deliver natural gas through gas gathering systems and gas pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our ability to produce and market natural gas on a commercial basis could be harmed by any significant change in the cost or availability of such markets, systems or pipelines. Our future acquisitions may yield revenues or production that varies significantly from our projections. In acquiring producing properties, we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations. Our business may suffer if we lose key personnel. We depend to a large extent on the services of certain key management personnel, including our executive officers and other key employees, the loss of any of whom could have a material adverse effect on our operations. We have entered into employment agreements with each of S.P. Johnson IV, our President and Chief Executive Officer, Paul F. Boling, our Chief Financial Officer, Jeremy T. Greene, our Vice President of Exploration Development, Kendell A. Trahan, our Vice President of Land, and J. Bradley Fisher, our Vice President of Operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel. We may experience difficulty in achieving and managing future growth. We have experienced growth in the past primarily through the expansion of our drilling program. Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including: o our ability to obtain leases or options on properties for which we have 3-D seismic data; o our ability to acquire additional 3-D seismic data; o our ability to identify and acquire new exploratory prospects; o our ability to develop existing prospects; o our ability to continue to retain and attract skilled personnel; 8 o our ability to maintain or enter into new relationships with project partners and independent contractors; o the results of our drilling program; o hydrocarbon prices; and o our access to capital. We may not be successful in upgrading our technical, operations and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations. We may continue to hedge the price risks associated with our production. Our hedge transactions may result in our making cash payments or prevent us from benefitting to the fullest extent possible from increases in prices for natural gas and oil. Because natural gas and oil prices are unstable, we periodically enter into price-risk-management transactions such as swaps, collars, futures and options to reduce our exposure to price declines associated with a portion of our natural gas and oil production and thereby to achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of natural gas and oil. Our hedging arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in natural gas and oil prices. These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of natural gas and oil or a sudden, unexpected event materially impacts natural gas or oil prices. We have substantial capital requirements that, if not met, may hinder operations. We have experienced and expect to continue to experience substantial capital needs as a result of our active exploration, development and acquisition programs. We expect that additional external financing will be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under existing or new credit facilities may not be available in the future. Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and thereby adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations. Our credit facility contains operating restrictions and financial covenants, and we may have difficulty obtaining additional credit. Over the past few years, increases in commodity prices and proved reserve amounts and the resulting increase in our estimated discounted future net revenue have allowed us to increase our available borrowing amounts. In the future, commodity prices may decline, we may increase our borrowings or our borrowing base may be adjusted downward, thereby reducing our borrowing capacity. Our credit facility is secured by a pledge of substantially all of our producing natural gas and oil properties assets, is guaranteed by our subsidiary and contains covenants that limit additional borrowings, dividends to nonpreferred shareholders, the incurrence of liens, investments, sales or pledges of assets, changes in control, repurchases or redemptions for cash of our common or preferred stock, speculative commodity transactions and other matters. The credit facility also requires that specified financial ratios be maintained. We may not be able to refinance our debt or obtain additional financing, particularly in view of our current credit agreement's restrictions on our ability to incur debt under our bank credit facility and the fact that substantially all of our assets are currently pledged to secure obligations under that facility. The restrictions of our credit facility and our difficulty in obtaining additional debt financing may have adverse consequences on our operations and financial results including: o our ability to obtain financing for working capital, capital expenditures, our drilling program, purchases of new technology or other purposes may be impaired; o the covenants in our credit facilities that limit our ability to borrow additional funds and dispose of assets may affect our flexibility in planning for, and reacting to, changes in business conditions; o because our indebtedness is subject to variable interest rates, we are vulnerable to increases in interest rates; 9 o any additional financing we obtain may be on unfavorable terms; o we may be required to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities; o a substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing portions of our drilling program, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing; and o we may become more vulnerable to downturns in our business or the economy generally. We may incur additional debt in order to fund our exploration and development activities. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, natural gas and oil prices and financial, business and other factors, many of which are beyond our control, affect our operations and our future performance. Our senior subordinated notes contain restrictive covenants similar to those under our credit facility. In addition, under the terms of our credit facility, our borrowing base is subject to redeterminations at least semiannually based in part on prevailing natural gas and oil prices. In the event the amount outstanding exceeds the redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell a portion of our assets. We may record ceiling limitation write-downs that would reduce our shareholders' equity. We use the full-cost method of accounting for investments in natural gas and oil properties. Accordingly, we capitalize all the direct costs of acquiring, exploring for and developing natural gas and oil properties. Under the full-cost accounting rules, the net capitalized cost of natural gas and oil properties may not exceed a "ceiling limit" that is based upon the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or the fair market value of unproved properties. If net capitalized costs of natural gas and oil properties exceed the ceiling limit, we must charge the amount of the excess to operations through depreciation, depletion and amortization expense. This charge is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities but does reduce our shareholders' equity. The risk that we will be required to write down the carrying value of our natural gas and oil properties increases when natural gas and oil prices are low or volatile. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues, as further discussed in "Risk Factors--Our reserve data and estimated discount future net cash flows are estimates based upon assumptions that may be inaccurate and are based on existing economic and operating conditions that may change in the future." Once incurred, a write-down of natural gas and oil properties is not reversible at a later date. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Critical Accounting Policies and Estimates" for additional information on these matters. Our affiliates control a majority of our outstanding common stock, which may affect your vote as a shareholder. As of December 31, 2003, our officers and directors and their affiliates beneficially owned approximately 86% of our outstanding common stock (60% after completion of the offering to which our prospectus dated February 5, 2004 relates). As a result, these shareholders, to the extent they act as a group, will be able to significantly influence or control the outcome of certain matters requiring a shareholder vote, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws, and the approval of mergers and other significant corporate transactions. The existence of these levels of ownership concentrated in a few persons makes it unlikely that any other holder of common stock will be able to affect our management or strategic direction. These factors may also have the effect of delaying, deterring or preventing a change in control and may adversely affect the voting and other rights of other shareholders. Our shares that are eligible for future sale may have an adverse effect on the price of our common stock. Future sales of substantial amounts of our common stock, or a perception that such sales could occur, could adversely affect the market price of our common stock and could impair our ability to raise capital through the sale of our equity securities. This risk is 10 compounded by the fact that a substantial portion of our common stock is owned by a relatively few number of individuals or entities. The major holders of shares of our common stock have piggyback and demand registration rights that provide for the registration of the resale of those shares at our expense which will allow those shares to be sold in the public market without restriction. The market price of our common stock is volatile. The trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following: o limited trading volume in our common stock; o quarterly variations in operating results; o our involvement in litigation; o general financial market conditions; o the prices of natural gas and oil; o announcements by us and our competitors; o our liquidity; o our ability to raise additional funds; o changes in government regulations; and o other events. We do not anticipate paying dividends on our common stock in the near future. We have not paid any dividends in the past and do not intend to pay cash dividends on our common stock in the foreseeable future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities. Any future dividend payments will be restricted by the terms of our credit agreement and our senior subordinated notes. Certain anti-takeover provisions may affect your rights as a shareholder. Our articles of incorporation authorize our board of directors to set the terms of and issue additional preferred stock without shareholder approval. Our board of directors could use the preferred stock as a means to delay, defer or prevent a takeover attempt that a shareholder might consider to be in our best interest. In addition, our outstanding Series B preferred stock, our senior credit facility and our senior subordinated notes contain terms that may restrict our ability to enter into change of control transactions, including requirements to redeem or repay the Series B preferred stock, our credit facility and our senior subordinated notes upon a change in control. These provisions, along with specified provisions of the Texas Business Corporation Act and our articles of incorporation and bylaws, may discourage or impede transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock. Management's Discussion and Analysis of Financial Condition and Results of Operations You should read this discussion together with the consolidated financial statements and other financial information included in our filings with the SEC. Unless explicitly stated otherwise, or the context otherwise requires, all references in this section to planned capital expenditures or planned drilling activities assume the completion of the offering described in our prospectus dated February 5, 2004. General Overview 11 For the year ended December 31, 2002 and for the first nine months of 2003, we achieved record drilling success rates, levels of production, natural gas and oil revenues and net income available to shareholders for any twelve- and nine-month period, respectively, in our history. In 2002, we produced a record 7.2 Bcfe compared to 5.4 Bcfe in 2001. In the first nine months of 2003, we produced 5.6 Bcfe, a record for any nine-month period and an improvement over production of 5.1 Bcfe in the first nine months of 2002. These increasing production levels in 2003 are due to our drilling success. In 2002, we drilled 20 wells (7.1 net) in the onshore Gulf Coast with a success rate of 85% compared to a success rate of 80% in 2001, in which we drilled 25 wells (7.6 net). During the first nine months of 2003, we drilled 22 wells (8.2 net) with a success rate of 86%. Between January 1, 2001 and September 30, 2003, 93% of our wells drilled were exploratory and 7% were development. In 2003, we drilled 38 wells, with 32 wells in the onshore Gulf Coast area. In 2002, both our revenues and our net income increased: our natural gas and oil revenues reached a record level at $26.8 million, and our net income available to common shareholders was $4.2 million, or $0.30 and $0.26 per basic and fully diluted share, respectively. In 2001, our natural gas and oil revenues were $26.2 million and our net income available to common shareholders was $9.5 million, or $0.68 and $0.57 per basic and fully diluted share, respectively. In the first nine months of 2003, our natural gas and oil revenues reached a nine-month record level of $29.6 million, as compared to $17.6 million during the first nine months of 2002. Our net income available to common shareholders was $6.3 million in the 2003 nine-month period, or $0.45 and $0.38 per basic and fully diluted share, respectively, as compared to $2.0 million, or $0.14 and $0.12 per basic and fully diluted share, respectively, for the first nine months of 2002. These increases in natural gas and oil revenues and net income were attributable partly to the high levels of production discussed above and to high commodity prices. Our financial results are largely dependent on a number of factors, including commodity prices. Commodity prices are outside of our control and historically have been and are expected to remain volatile. Natural gas prices in particular have remained volatile during the last few years. Commodity prices are affected by changes in market demands, 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, natural gas liquids and crude oil prices, and therefore, cannot accurately predict revenues. Including the effects of hedging activities, our realized natural gas price was 31% lower and our realized oil price was 3% higher in 2002 than in 2001, and our realized natural gas price was 72% higher and our realized oil price was 25% higher during the first nine months of 2003 than in the comparable period in 2002. Because natural gas and oil prices are unstable, we periodically enter into price-risk-management transactions such as swaps, collars, futures and options to reduce our exposure to price fluctuations associated with a portion of our natural gas and oil production and to achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of natural gas and oil. Our hedging arrangements may apply to only a portion of our production and provide only partial protection against declines in natural gas and oil prices. We have continued to reinvest a substantial portion of our operating cash flows into funding our drilling program and increasing the amount of 3-D seismic data available to us. In 2004, we expect capital expenditures to be approximately $40 to $45 million, as compared to $25.3 million in 2003. In the first nine months of 2003, we incurred $20.4 million in capital and exploration expenditures, as compared to $20.9 million in the first nine months of 2002. At September 30, 2003, our debt-to-total capitalization ratio was 31.0%, an improvement from 36.5% at the end of 2002. This improvement was primarily the result of the increased shareholders' equity from net income, a decrease in the outstanding debt on the Hibernia credit facility and a reduction in our nonrecourse note to Rocky Mountain Gas, Inc., both as described under "--Liquidity and Capital Resources--Financing Arrangements." During the second quarter of 2001, we acquired interests in natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane and subsequently began to drill wells on those leases. During the second quarter of 2003, we contributed our interests in certain of these leases to a newly formed company, Pinnacle Gas Resources, Inc. (Pinnacle). In exchange for this contribution, we received 37.5% of the common stock of Pinnacle and options to purchase additional Pinnacle common stock. We account for our interest in Pinnacle using the equity method. As a result, our contributed operations and reserves are no longer directly reflected in our financial statements. We retained our interests in approximately 189,000 gross acres in the Castle Rock project area in 12 Montana and the Oyster Ridge project area in Wyoming. See "Business and Properties--Pinnacle Transaction" for a description of this transaction. Our discussion of future drilling and capital expenditures does not reflect operations conducted through Pinnacle. Since our initial public offering, we have grown primarily through the exploration of properties within our project areas although we consider acquisitions from time to time and may in the future complete acquisitions that we find attractive. Recent Developments Fourth Quarter 2003 Operating Results During the fourth quarter of 2003, in our core areas in the onshore Gulf Coast of Texas and Louisiana, we participated in the drilling of 12 gross exploratory wells, 11 of which were successful. Also during the quarter, in our Barnett Shale Project we participated in the drilling of two gross (one net) exploratory wells and two gross (one net) development wells, all of which were successful. On a combined basis for these two areas, we had a 94% success rate for the quarter. Production during the fourth quarter of 2003 was estimated at 1.85 Bcfe, bringing our 2003 annual production to an estimated record level of 7.5 Bcfe, an increase of 3.5% over our 2002 production level. Approximately 72% of our production during the fourth quarter of 2003 and 64% of our production in the full year 2003 was natural gas. We estimate that fourth quarter 2003 sales prices, including the effect of hedging activities, averaged approximately $4.78 per Mcf and $29.61 per barrel. Based on our preliminary reserve estimates, we believe that in 2003 we more than replaced our production with proved reserve additions from our drilling activities. Potential Barnett Shale Acquisition We have entered into negotiations with a private company to purchase working interests and acreage in certain oil and gas wells located in Denton County, Texas in the Newark East Field in the Barnett Shale trend. This potential acquisition, with an expected purchase price of $7.2 million, includes non-operated working interests ranging from 12.5% to 45% over 3,800 acres. As of January 1, 2004, the 14 producing wells (5.0 net) that would be included in the acquisition were producing a net 1.4 MMcf/d with another five wells (1.3 net) waiting for pipeline hook-up. We expect the undeveloped acreage to contribute additional drilling locations, 13 of which will target proved undeveloped reserves and 18 of which will be exploratory. We expect that we would finance the acquisition with our current revolving credit facility or, alternatively, with a new project financing facility that we would seek to obtain. We currently have targeted a closing date of February 16, 2004 for the acquisition. There can be no assurance that the transaction described above will be completed on the terms or timing described above or at all. Regardless of whether this transaction is completed, we intend to continue to pursue growth opportunities in this geologic trend. Results of Operations The following table summarizes production volumes, average sales prices and operating revenues for our natural gas and oil operations for the years ended December 31, 2000, 2001 and 2002 and for the nine months ended September 30, 2002 and 2003: 13
Nine Months % Increase % Increase Ended Year Ended Year Ended (Decrease) Year Ended (Decrease) September 30, December 31, December 31, from 2000 December 31, from 2001 --------------------- 2000 2001 to 2001 2002 to 2002 2002 2003 ------------ ------------ ---------- ------------ ---------- --------- --------- Production volumes Oil and condensate (MBbls)................ 198 160 (20)% 401 151% 261 363 Natural gas (MMcf)...... 5,460 4,432 (19) 4,801 8 3,543 3,432 Natural gas equivalent (MMcfe).............. 6,651 5,390 (19) 7,207 34 5,109 5,607 Average sales prices(1) Oil and condensate (MBbls)............... $ 27.81 $ 24.28 (13)% $ 24.94 3% $ 23.34 $ 29.08 Natural gas (MMcf)..... 3.90 5.04 (29) 3.50 (31) 3.24 5.56 Operating revenues (in thousands)............. $ 26,834 $ 26,226 (2)% $ 26,802 2% $ 17,559 $ 29,615
---------- (1) Includes impact of hedging activities. Nine Months Ended September 30, 2003 Compared to the Nine Months Ended September 30, 2002 Natural gas and oil revenues for the nine months ended September 30, 2003 increased 69% to $29.6 million from $17.6 million for the same period in 2002. Production volumes for natural gas during the nine months ended September 30, 2003 decreased 3% to 3.4 Bcf from 3.5 Bcf for the same period in 2002. Average natural gas prices increased 72% to $5.56 per Mcf in the first nine months of 2003 from $3.24 per Mcf in the same period in 2002. Production volumes for oil in the nine months ended September 30, 2003 increased 39% to 363 MBbls from 261 MBbls for the same period in 2002. Average oil prices increased 25% to $29.08 per barrel in the first nine months of 2003 from $23.34 per barrel in the same period in 2002. The increase in oil production was due primarily to the commencement of production at six wells offset by the natural decline in production from other wells. The decrease in natural gas production was primarily due to a workover at one well and natural production declines in other wells offset by the commencement of production at new wells. Natural gas and oil revenues include the impact of hedging activities as discussed below under "Management's Discussion and Analysis of Financial Condition and Results of Operations--Critical Accounting Policies and Estimates--Derivative Instruments and Hedging Activities." Natural gas and oil operating expenses for the nine months ended September 30, 2003 increased 38% to $5.1 million from $3.7 million for the same period in 2002 primarily due to higher severance taxes and other operating costs associated with the addition of new production. Operating expenses per equivalent unit increased 25% to $0.90 per Mcfe in the first nine months of 2003 from $0.72 per Mcfe in the same period in 2002 primarily as a result of the natural decline in production on older wells and the addition of a relatively higher cost new well. General and administrative (G&A) expense for the nine months ended September 30, 2003 increased 43% to $4.3 million from $3.0 million for the same period in 2002. The increase in G&A expense was due primarily to employee severance costs and the addition of contract staff to handle increased drilling and production activities, higher compensation costs and higher insurance. Depreciation, depletion and amortization (DD&A) expense for the nine months ended September 30, 2003 increased 19% to $8.7 million from $7.3 million for the same period in 2002. This increase was due to increased production and additional seismic and drilling costs. Interest income for the nine months ended September 30, 2003 increased to $50,000 from $44,000 in the first nine months of 2002 primarily as a result of higher cash balances during the first quarter of 2003. Capitalized interest was $2.2 million in the first nine months of 2003 and 2002. Provision for income taxes increased to $4.1 million for the nine months ended September 30, 2003 from $1.5 million for the same period in 2002 as a result of higher taxable income based on the factors described above. 14 We adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations," effective January 1, 2003 and recorded a cumulative effect of change in accounting principle of $0.1 million in the nine months ended September 30, 2003. Income before income taxes for the nine months ended September 30, 2003 increased to $11.1 million from $3.9 million in the same period in 2002. Net income for the nine months ended September 30, 2003 increased to $6.3 million from $2.0 million for the same period in 2002 primarily as a result of the factors described above. Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001 Our natural gas and oil revenues for 2002 increased 2% to $26.8 million from $26.2 million in 2001. Production volumes for natural gas in 2002 increased 8% to 4,801 MMcf from 4,432 MMcf in 2001, due primarily to the commencement of production at five wells, offset by natural production declines in other wells, primarily from the initial Matagorda County Project wells. Realized average natural gas prices decreased 31% to $3.50 per Mcf in 2002 from $5.04 per Mcf in 2001. Production volumes for oil in 2002 increased 151% to 401 MBbls from 160 MBbls in 2001, due primarily to the commencement of production at four wells, offset by natural production declines in other older wells. Natural gas and oil revenues include the impact of hedging activities as discussed below under "--Critical Accounting Policies and Estimates--Derivative Instruments and Hedging Activities." Average oil prices increased 3% to $24.94 per Bbl in 2002 from $24.28 per Bbl in 2001. Natural gas and oil operating expenses for 2002 increased 19% to $4.9 million from $4.1 million in 2001, primarily as a result of the addition of new natural gas and oil wells drilled and completed since December 31, 2001 and higher ad valorem taxes. Operating expenses per equivalent unit in 2002 decreased to $0.68 per Mcfe from $0.77 per Mcfe in 2001. The per-unit cost decreased primarily as a result of the addition of higher-production-rate, lower-cost-per-unit wells, offset by an increase in ad valorem taxes and decreased production of natural gas as wells naturally declined. DD&A expense for 2002 increased 63% to $10.6 million from $6.5 million in 2001. This increase was due primarily to increased production and the additional seismic and drilling costs added to the proved property cost base. G&A expense for 2002 increased 24% to $4.1 million from $3.3 million for 2001. The increase in G&A expense was due primarily to the addition of contract staff to handle increased drilling and production activities and higher insurance costs. Interest income for 2002 decreased to $0.1 million from $0.3 million in 2001 primarily as a result of lower interest rates during 2002. Capitalized interest decreased to $3.1 million in 2002 from $3.2 million in 2001 primarily due to lower interest costs during 2002. Provision for income taxes decreased to $2.8 million in 2002 from $5.3 million in 2001. Dividends and accretion of discount on preferred stock increased to $0.6 million in 2002 from none in 2001 as a result of our sale of preferred stock in the first quarter of 2002. Net income for 2002 decreased to $4.8 million from $9.5 million in 2001 primarily as a result of the factors described above. Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000 Natural gas and oil revenues for 2001 decreased 2% to $26.2 million from $26.8 million in 2000. Production volumes for natural gas in 2001 decreased 19% to 4,432 MMcf from 5,461 MMcf in 2000, due primarily to the sale of a project during 2000 and the natural decline in production at certain wells, offset by the commencement of production at other wells. Realized average natural gas prices increased 29% to $5.04 per Mcf in 2001 from $3.90 per Mcf in 2000. Production volumes for oil in 2001 decreased 20% to 160 MBbls from 199 MBbls in 2000 due to the natural decline in production at certain wells, offset by the commencement of production of another well. Natural gas and oil revenues include the cash effect of hedging activities as discussed below under "Critical Accounting Policies and Estimates--Derivative Instruments and Hedging Activities." Average oil prices decreased 13% to $24.28 per Bbl in 2001 from $27.81 per Bbl in 2000. Natural gas and oil operating expenses for 2001 decreased 16% to $4.1 million from $4.9 million in 2000, primarily as a result of the lower production taxes and the implementation of cost reduction measures in fields with decreased production. Operating expenses per 15 equivalent unit in 2001 increased to $0.77 per Mcfe from $0.74 per Mcfe in 2000. The per-unit cost increased primarily as a result of an increase in severance taxes and decreased production of natural gas as wells naturally declined. Depreciation, depletion and amortization expense for 2001 decreased 9% to $6.5 million from $7.2 million in 2000. This decrease was primarily due to the seismic and drilling costs added to the proved property cost base. G&A expense for 2001 increased 6% to $3.3 million from $3.1 million for 2000. The increase in G&A expense was due primarily to the addition of staff to handle increased drilling and production activities and also to stock option compensation expense, a noncash charge resulting from a decrease during 2001 and an increase during the last six months of 2000 in the stock price underlying the stock options that we repriced in February 2000. Interest expense, net of amounts capitalized, for 2001 decreased 47% to $6,873 from $13,003 in 2000. Provision for income taxes increased to $5.3 million in 2001 from $1.0 million in 2000 as a result of an adjusted noncash valuation allowance during 2000 on net operating loss carryforwards expected to be realized that resulted in a deferred income tax benefit adjustment of $3.6 million, which reduced our effective tax rate to 8% in 2000. Other income for the year ended December 31, 2001 included a gain on the sale of an investment in Michael Petroleum Corporation of $3.9 million, offset by: o a charge and related legal expenses of $1.4 million in respect of the final settlement of litigation with BNP Petroleum Corporation; and o a noncash valuation allowance of $0.8 million relating to certain hedge arrangements with Enron North America Corp. Net income for 2001 decreased to $9.5 million from $12.0 million in 2000 as a result of the factors described above. Liquidity and Capital Resources We have made and expect to make capital expenditures in excess of our net cash flows provided by operating activities. We will require additional sources of financing to fund drilling expenditures on properties we currently own and to fund leasehold costs and geological and geophysical costs on our exploration projects. While we believe that current cash balances and anticipated cash provided by operating activities for 2004 will provide sufficient capital to carry out our exploration plans for that time period, our management continues to seek financing for our capital program from a variety of sources. We may not be able to obtain additional financing on terms that would be acceptable to us. If we cannot obtain acceptable financing, we anticipate that we may be required to limit or defer our planned natural gas and oil exploration and development program, thereby adversely affecting the recoverability and ultimate value of our natural gas and oil properties. See "Risk Factors--We have substantial capital requirements that, if not met, may hinder operations." Our primary sources of liquidity have included funds generated by operations, proceeds from the issuance of various securities, including our common stock, preferred stock and warrants, and borrowings, primarily under revolving credit facilities and through the issuance of senior subordinated notes. Cash flows provided by operating activities were $17.1 million, $24.0 million and $19.9 million for 2000, 2001 and 2002, respectively, and $12.3 million and $23.5 million for the nine months ended September 30, 2002 and 2003, respectively. The increase in cash flows provided by operating activities in 2003 as compared to 2002 was due primarily to additional revenue resulting from higher natural gas and oil prices and higher oil and condensate production, offset by an increase in our working capital during the first nine months of 2003. Estimated maturities of long-term debt are $3.9 million in 2004, $8.5 million in 2005 and the remainder in 2007. Capital Expenditures We estimate capital expenditures in 2003 to have been approximately $25.3 million, of which we used $4.9 million to fund 3-D seismic surveys and acquire land and $20.4 million for drilling activities in our project areas. We have drilled 38 wells (10.2 net) in 16 2003. In 2004, we expect capital expenditures to be approximately $40 to $45 million (a 58 to 78% increase over our expected 2003 capital expenditures). We expect to drill 38 wells in 2004 (18.5 net), 30 of which we expect to operate. The actual number of wells drilled and the amount of capital expended depends on available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors. We have continued to reinvest a substantial portion of our cash flows into increasing our 3-D prospect portfolio, improving our 3-D seismic interpretation technology and funding our drilling program. Capital expenditures were $20.4 million for the nine months ended September 30, 2003, which included $2.2 million of capitalized interest and general and administrative costs. Our drilling efforts in the onshore Gulf Coast region resulted in the successful completion of 17 wells (6.0 net) in 2002 and 19 wells (5.2 net) in the nine months ended September 30, 2003. Of the 77 coalbed methane wells (29.0 net) we drilled or acquired in the Rocky Mountain region through September 30, 2003, 24 wells (8.0 net) are currently producing and 53 wells (21.0 net) are in various stages of evaluation. Pursuant to an exchange election provided in a letter agreement dated May 1, 2001, with some of the participants in the Carrizo 2001 Seismic and Acreage Program, we issued to those participants who exercised their election approximately 168,000 shares of our common stock in exchange for the participants' interest in that program, including interests in approximately 350 square miles of 3-D seismic data and working interests in specified producing properties. The exchange transaction was effective on October 10, 2003 and was valued at approximately $1.2 million using the closing price of our stock on that date. Financing Arrangements Hibernia Credit Facility On May 24, 2002, we entered into a credit agreement with Hibernia National Bank that matures on January 31, 2005, and repaid our prior facility with Compass Bank. The Hibernia credit facility provides a revolving line of credit of up to $30.0 million. It is secured by substantially all of our producing assets. The borrowing base will be determined by Hibernia National Bank at least semi-annually on each October 31 and April 30. The borrowing base as of January 31, 2004 was $16.0 million, of which $7.0 million was drawn as of that date. Each party to the credit agreement can request one unscheduled borrowing base determination subsequent to each scheduled determination. The borrowing base will at all times equal the borrowing base most recently determined by Hibernia National Bank, less quarterly borrowing base reductions required subsequent to such determination. If the outstanding principal balance of the Hibernia credit facility exceeds the borrowing base at any time, we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in Hibernia National Bank's opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity. The interest rate applicable to incremental borrowings under this credit facility will be, at our option, a eurodollar rate or a base rate, in each case plus an applicable margin based upon borrowing levels. We are subject to specified covenants under the terms of the Hibernia credit facility, including but not limited to maintaining a minimum current ratio, a minimum quarterly debt services coverage ratio and a minimum level of shareholders' equity. The Hibernia credit facility also places restrictions on additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, change of control, repurchase or redemption for cash of our common or preferred stock, speculative commodity transactions and other matters. Rocky Mountain Gas Note In June 2001, our subsidiary CCBM issued a nonrecourse promissory note in the amount of $7.5 million to Rocky Mountain Gas, Inc. (RMG) as consideration for specified interests in natural gas and oil leases held by RMG in Wyoming and Montana. At September 30, 2003, the outstanding principal balance of this note was $1.0 million. Capital Leases 17 We have entered into capital lease agreements, each secured by specified production equipment, with payment obligations of $0.4 million in 2004, $0.3 million in 2005 and $0.1 million in 2006. Senior Subordinated Notes and Related Securities In December 1999, we sold $22.0 million principal amount of 9% Senior Subordinated Notes due 2007. The senior subordinated notes were sold at a discount of $0.7 million, which is being amortized over the life of the notes. Interest is payable quarterly beginning March 31, 2000. We may elect, until December 2004, to increase the amount of the senior subordinated notes for up to 60% of the interest rate which would otherwise be payable in cash. As of December 31, 2002 and September 30, 2003, the outstanding balance of the senior subordinated notes had been increased by $3.9 million and $5.0 million, respectively, for such interest paid in kind. Concurrently with the sale of the senior subordinated notes, we sold 3,636,364 shares of our common stock at a price of $2.20 per share and warrants expiring in December 2007 to purchase up to 2,760,189 shares of our common stock at an exercise price of $2.20 per share. For accounting purposes, the warrants were valued at $0.25 each. We sold the warrants to CB Capital Investors, L.P. (now JPMorgan), Mellon, Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton. We are subject to specified covenants under the terms of the securities purchase agreement related to the senior subordinated notes, including but not limited to maintenance of a specified tangible net worth and a debt service coverage ratio and limits on our ability to incur indebtedness and to engage in certain transactions and activities. Series B Preferred Stock In February 2002, we sold 60,000 shares of our Series B preferred stock and warrants to purchase 252,632 shares of our common stock for an aggregate purchase price of $6.0 million. We sold $4.0 million of Series B preferred stock and 168,422 warrants to Mellon and $2.0 million of Series B preferred stock and 84,210 warrants to Steven A. Webster, our Chairman of the Board. The investors may convert the Series B preferred stock into common stock at a conversion price of $5.70 per share, subject to adjustment for transactions including issuance of common stock or securities convertible into or exercisable for common stock at less than the conversion price of the Series B preferred stock. The approximate $5.8 million net proceeds of this financing were used to fund our ongoing exploration and development program and for general corporate purposes. Dividends on the Series B preferred stock are payable either in cash at a rate of 8% per annum or, at our option, by payment in kind of additional shares of the Series B preferred stock at a rate of 10% per annum. At December 31, 2002 and September 30, 2003, the outstanding balance of the Series B preferred stock had been increased by $0.5 million (5,294 shares) and $0.9 million (8,559 shares), respectively, for dividends paid in kind. At September 30, 2003, we had accrued a dividend of $0.2 million that we paid on December 31, 2003. In addition to the foregoing, if we declare a cash dividend on our common stock, the holders of shares of Series B preferred stock are entitled to receive for each share of Series B preferred stock a cash dividend in the amount of the cash dividend that would be received by a holder of the common stock into which that share of Series B preferred stock is convertible on the record date for the cash dividend. Unless all accrued dividends on the Series B preferred stock shall have been paid and a sum sufficient for the payment thereof set apart, no distributions may be paid on any Junior Stock (as defined in the Statement of Resolutions for the Series B preferred stock) (which includes the common stock), and no redemption of any junior stock shall occur other than subject to specified exceptions. We must redeem the Series B preferred stock at any time after the third anniversary of its initial issuance upon request from any holder at a price per share equal to Purchase Price/Dividend Preference (as defined below). We may redeem the Series B preferred stock after the third anniversary of its issuance at a price per share equal to the Purchase Price/Dividend Preference and, prior to that time, at varying preferences to the Purchase Price/Dividend Preference. "Purchase Price/Dividend Preference" is defined to mean, generally, $100 plus all cumulative and accrued dividends. In the event of any dissolution, liquidation or winding up or specified mergers or sales or other disposition by us of all or substantially all of our assets, the holder of each share of Series B preferred stock then outstanding will be entitled to be paid per share of Series B preferred stock, prior to the payment to holders of our common stock and out of our assets available for distribution to our shareholders, the greater of: o $100 in cash plus all cumulative and accrued dividends; and 18 o in specified circumstances, the "as-converted" liquidation distribution, if any, payable in such liquidation with respect to each share of common stock. Upon the occurrence of specified events constituting a "Change of Control" (as defined in the Statement of Resolutions), we must make an offer to each holder of Series B preferred stock to repurchase all of that holder's Series B preferred stock at an offer price per share of Series B preferred stock in cash equal to 105% of the Change of Control Purchase Price, which is generally defined to mean $100 plus all cumulative and accrued dividends. The warrants issued in connection with the Series B preferred stock have a five-year term, entitle the holders to purchase up to 252,632 shares of our common stock at a price of $5.94 per share, subject to adjustment, and are exercisable at any time after issuance. For accounting purposes, the warrants are valued at $0.06 per warrant. Effects of Inflation and Changes in Price Our results of operations and cash flows are affected by changing natural gas and oil prices. If the price of natural gas and oil increases (decreases), there could be a corresponding increase (decrease) in the operating cost we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on us. Critical Accounting Policies and Estimates The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 2 to the Consolidated Financial Statements. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. The use of these estimates significantly affects natural gas and oil properties through depletion and the full cost ceiling test, as discussed in more detail below. Natural Gas and Oil Properties We account for investments in natural gas and oil properties using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. We proportionally consolidate our interests in natural gas and oil properties. We capitalized compensation costs for employees working directly on exploration activities of $0.7 million and $1.1 million for the nine months ended September 30, 2002 and 2003, respectively. We expense maintenance and repairs as they are incurred. We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities. We do not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until these investments are impaired. We periodically evaluate, on a property-by-property basis, unevaluated properties for impairment. If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil property costs to be amortized. The amortizable base includes estimated future development costs. The depletion rate per thousand cubic feet equivalent (Mcfe) for the nine months ended September 30, 2002 and 2003 was $1.40 and $1.51, respectively. We account for dispositions of natural gas and oil properties as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. We have not had any transactions that significantly alter that relationship. The net capitalized costs of proved natural gas and oil properties are subject to a ceiling test, which limits such costs to the estimated present value, discounted at a 10% interest rate, of future net revenues from proved reserves (the NPV) based on current economic and operating conditions (with reserve estimates calculated using SEC guidelines). This test is performed after any impairment of unproved properties are added to the property costs to amortize as discussed above. We include asset retirement obligation costs, liabilities and related discounted cash flows in our ceiling test calculations. If net capitalized costs exceed this limit, we charge the 19 excess to operations through depreciation, depletion and amortization. No write-down of our natural gas and oil assets was necessary for the nine months ended September 30, 2002 or 2003. In concert with this determination, a price sensitivity study also indicated that a 20% increase in commodity prices at September 30, 2003 would have increased our NPV by approximately $15.8 million. Conversely, a 20% decrease in commodity prices at September 30, 2003 would have reduced our NPV by approximately $18.4 million. This would have caused our unamortized cost of proved natural gas and oil properties to exceed the cost pool ceiling by approximately $18.1 million. Our aforementioned price sensitivity and NPV is as of September 30, 2003 and, accordingly, does not include any potential changes in reserves due to fourth quarter performance, such as commodity prices, reserve revisions and drilling results, including proved reserves associated with our recently discovered Shadyside #1 well. Based on natural gas and oil prices in effect on December 31, 2001, the unamortized cost of natural gas and oil properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing subsequent to December 31, 2001 removed the necessity to record a write-down. Using prices in effect on December 31, 2001 the pretax write-down would have been approximately $0.7 million. Because of the volatility of natural gas and oil prices, we cannot assure you that we will not experience a write-down in future periods. Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value and estimated future development costs to calculate the depletion expense. We have a significant amount of proved undeveloped reserves, which are primarily oil reserves. We had 41.9 Bcfe of proved undeveloped reserves, representing 66% of our total proved reserves at December 31, 2002. These reserves are primarily attributable to our Camp Hill properties we acquired in 1994. This ratio of proved undeveloped reserves to total proved reserves and the producing properties that have had an average productive life of 2.25 years since our inception, compared to the average 10 year depletable life for the total proved reserves, has resulted in a relatively low historical depletion rate and depreciation expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream. It has also resulted in the build-up of nondepleted capitalized costs associated with properties that have been completely produced out. We expect our low historical depletion rate to continue until the high level of nonproducing reserves to total proved reserves is reduced and the life of our proved developed reserves is extended through development drilling and/or the significant addition of new proved producing reserves through acquisition or exploration. If our level of total proved reserves and current prices were both to remain constant, this continued build-up of capitalized costs increases the probability of a ceiling test write-down. We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years. SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Intangible Assets," were issued by the FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS No. 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain other intangible assets are not amortized but rather are reviewed annually for impairment. Natural gas and oil mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds may have to be classified separately from natural gas and oil properties as intangible assets on our consolidated balance sheets. In addition, the disclosures required by SFAS No. 141 and 142 relative to intangibles would be included in the notes to the consolidated financial statements. Historically, we, like many other natural gas and oil companies, have included these rights as part of natural gas and oil properties, even after SFAS No. 141 and 142 became effective. As it applies to companies like us that have adopted full cost accounting for natural gas and oil activities, we understand that this interpretation of SFAS No. 141 and 142 would only affect our balance sheet classification of proved natural gas and oil leaseholds acquired after June 30, 2001 and all of our unproved natural gas and oil leaseholds. We would not be required to reclassify proved reserve leasehold acquisitions prior to June 30, 2001 because we did not separately value or account for these costs prior to the adoption date of SFAS No. 141. Our results of operations and cash flows would not be affected, since these natural gas and oil mineral rights held under lease and other contractual arrangements representing the right to extract natural gas and oil reserves would continue to be amortized in accordance with full cost accounting rules. 20 As of September 30, 2003, December 31, 2002 and December 31, 2001, we had leasehold costs incurred of approximately $3.4 million, $1.4 million and $1.4 million, respectively, that would be classified on our consolidated balance sheet as "intangible leasehold costs" if we applied the interpretation discussed above. We will continue to classify our natural gas and oil mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided. Natural Gas and Oil Reserve Estimates The reserve data included or incorporated in this exhibit are estimates prepared by Ryder Scott Company and Fairchild and Wells, Inc., Independent Petroleum Engineers. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as natural gas and oil prices and the present value discount rate. Proved reserve estimates prepared by others may be substantially higher or lower than our estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing and rates of production. You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we have based our estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Our rate of recording depreciation, depletion and amortization expense for proved properties is dependent on our estimate of proved reserves. If these reserve estimates decline, the rate at which we record these expenses will increase. Derivative Instruments and Hedging Activities In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and disclosures of derivative instruments and hedging activities. This statement requires all derivative instruments to be carried on the balance sheet at fair value with changes in a derivative instrument's fair value recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was effective for us beginning January 1, 2001 and we adopted it on that date. In accordance with the current transition provisions of SFAS No. 133, we recorded a cumulative effect transition adjustment of $2.0 million (net of related tax expense of $1.1 million) in accumulated other comprehensive income to recognize the fair value of our derivatives designated as cash flow hedging instruments at the date of adoption. Upon entering into a derivative contract, we designate the derivative instruments as a hedge of the variability of cash flow to be received (cash flow hedge). Changes in the fair value of a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income associated with the cash flow hedge are recognized in earnings as natural gas and oil revenues when the forecasted transaction occurs. All of our derivative instruments at December 31, 2002 and September 30, 2003 were designated and effective as cash flow hedges except for certain options described below under "--Qualitative and Quantitative Disclosures About Market Risk--Derivative Instruments and Hedging Activities." When we discontinue hedge accounting because it is probable that a forecasted transaction will not occur, we continue to carry the derivative on the balance sheet at its fair value and immediately recognize in earnings any gains and losses that were accumulated in other comprehensive income. In all other situations in which we discontinue hedge accounting, we will carry the derivative at fair value on our balance sheet and will recognize in future earnings any future changes in its fair value. We typically use fixed rate swaps and costless collars to hedge our exposure to material changes in the price of natural gas and oil. We formally document all relationships between hedging instruments and hedged items as well as our risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges 21 to forecasted transactions. We also formally assess, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. Our Board of Directors sets our hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. Management implements these policies through the execution of trades by either the President or Chief Financial Officer after consultation with and concurrence by the other as well as the Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly. Income Taxes Under SFAS No. 109, "Accounting for Income Taxes," we recognize deferred income taxes at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We establish valuation allowances when necessary to reduce the deferred tax asset to the amount expected to be realized. Contingencies We recognize liabilities and other contingencies upon our determination that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable. New Accounting Pronouncements The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities" (FIN 46), in January 2003. FIN 46 requires the consolidation of specified types of entities in which a company absorbs a majority of another entity's expected losses, receives a majority of the other entity's expected residual returns, or both, as a result of ownership, contractual or other financial interests in the other entity. These entities are called "variable interest entities." The provisions of FIN 46 were effective for us in the second quarter for new transactions or entities formed in 2003 and in the third quarter for transactions or entities formed prior to 2003. If an entity is determined to be a "variable interest entity" (VIE), the entity must be consolidated by the "primary beneficiary." The primary beneficiary is the holder of the variable interests that absorbs a majority of the variable interest entity's expected losses or receives a majority of the entity's residual returns in the event no holder has a majority of the expected losses. The primary beneficiary is determined based on projected cash flows at the inception of the variable interests. We have assessed whether to consolidate Pinnacle under FIN 46. Because Steven A. Webster, our Chairman, is also a managing director of Credit Suisse First Boston (whose interest in Pinnacle is described under "Business and Properties--Pinnacle Transaction") we could be defined as the primary beneficiary if the projected cash flows analysis indicated losses in excess of the equity invested. The initial determination of whether an entity is a VIE is to be reconsidered only when one or more of the following occur: o the entity's governing documents or the contractual arrangements among the parties involved change; o the equity investment of some part thereof is returned to the investors, and other parties become exposed to expected losses; or o the entity undertakes additional activities or acquires additional assets that increase the entity's expected losses. We have determined that we should not consolidate Pinnacle under FIN 46 because our current projected cash flow analysis of Pinnacle's operations at inception indicates that Pinnacle is not a VIE. Accordingly, our investment in Pinnacle has been recorded using the equity method of accounting. The reclassification of investments in contributed properties resulting from the transaction with Pinnacle is reflected on our balance sheet as of September 30, 2003 in accordance with the full cost method of accounting. 22 Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk Our major market risk exposure is the commodity pricing applicable to our natural gas and oil production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for oil and spot prices applicable to natural gas. Those prices are and are expected to continue to be volatile. See "Risk Factors--Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results." A 10% fluctuation in the price received for natural gas and oil production would have an approximate $2.7 million and $3.0 million impact on our annual revenues and operating income for the year ended December 31, 2002 and the nine months ended September 30, 2003, respectively. Derivative Instruments and Hedging Activities To mitigate some of our commodity price risk, we engage periodically in certain limited hedging activities but only to the extent of buying protection price floors. We record the costs and any benefits derived from these price floors as a reduction or increase, as applicable, in natural gas and oil sales revenue; these reductions and increases were not significant for any of the years 2000, 2001 and 2002. The costs to purchase put options are amortized over the option period. We do not hold or issue derivative instruments for trading purposes. We realized losses related to these instruments of $0.4 million and $1.8 million for the nine months ended September 30, 2002 and 2003, respectively. As of December 31, 2002 and September 30, 2003, $0.4 million and $67,000, net of tax of $0.2 million and $36,000, respectively, remained in accumulated other comprehensive income related to the valuation of our hedging positions. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our hedging transactions with two counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have some risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. Moreover, our hedging arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time. Our gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reporting settlement prices on the NYMEX for each trading day of a particular calendar month. For the month of December 2002 a $0.10 change in the price per Mcf of gas sold would have changed revenue by $44,000. A $0.70 change in the price per barrel of oil would have changed revenue by $41,000. The table below summarizes our total natural gas production volumes subject to derivative transactions during 2002 and the weighted average NYMEX reference price for those volumes.
Natural Gas Swaps ----------------------------- Volumes (MMBtu).............. 2,131,000 Average price ($/MMBtu)...... $ 3.20 Volumes (MMBtu).............. 183,000 Average price ($/MMBtu) Floor...................... $ 3.50 Ceiling.................... $ 4.52
The table below summarizes our total crude oil production volumes subject to derivative transactions during 2002 and the weighted average NYMEX reference price for those volumes.
Crude Oil Swaps ------------------------- Volumes (Bbls)........... 131,600 Average price ($/Bbls)... $ 25.52
23 Total oil purchased and sold under swaps and collars during the three months ended September 30, 2002 and 2003 were 33,600 Bbls and 24,400 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the three months ended September 30, 2002 and 2003 was 731,000 MMBtu and 828,000 MMBtu, respectively. Total oil purchased and sold under swaps and collars during the nine months ended September 30, 2002 and 2003 was 79,100 Bbls and 150,700 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the nine months ended September 30, 2002 and 2003 was 3,094,000 MMBtu and 2,187,000 MMBtu, respectively. We realized net losses under these hedging arrangements of $0.1 million and $0.1 million for the three months ended September 30, 2002 and 2003, respectively, and $0.4 million and $1.7 million for the nine months ended September 30, 2002 and 2003, respectively. At December 31, 2002 and September 30, 2003, we had the following outstanding hedge positions:
December 31, 2002 ------------------------------------------------------------------------------------------ Contract Volumes --------------------- Average Average Average Quarter Bbls MMBtu Fixed Price Floor Price Ceiling Price ---------------------- -------- ---------- ----------- ----------- ------------- First Quarter 2003.... 27,000 $ 24.85 First Quarter 2003.... 36,000 $ 23.50 $ 26.50 First Quarter 2003.... 540,000 3.40 5.25 Second Quarter 2003... 27,300 24.85 Second Quarter 2003... 36,000 23.50 26.50 Second Quarter 2003... 546,000 3.40 5.25 Third Quarter 2003.... 552,000 3.40 5.25 Fourth Quarter 2003... 552,000 3.40 5.25
September 30, 2003 ------------------------------------------------------------------------------------------ Contract Volumes --------------------- Average Average Average Quarter Bbls MMBtu Fixed Price Floor Price Ceiling Price ---------------------- -------- ---------- ----------- ----------- ------------- ` Fourth Quarter 2003... 30,700 $ 30.22 Fourth Quarter 2003... 552,000 $ 3.40 $ 5.25 First Quarter 2004.... 546,000 4.10 7.00 Second Quarter 2004... 273,000 4.00 5.20 Third Quarter 2004.... 276,000 4.00 5.20 Fourth Quarter 2004... 93,000 4.00 5.20
From October 1, 2003 through January 12, 2004, we entered into swap arrangements covering 51,500 Bbls of oil for November 2003 through May 2004 production with an average fixed price of $30.33. We also entered into swap arrangements covering 180,000 MMBtu of natural gas for January 2004 through February 2004 production with an average fixed price of $6.67 and costless collar arrangements covering 825,000 MMBtu of natural gas production for April 2004 through December 2004 with a floor of $4.00 and a ceiling of $6.00. In addition to the hedge positions above, during the second quarter of 2003, we acquired call options to sell 6,000 MMBtu of natural gas per day for the period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for approximately $119,000. We acquired these options to protect our cash position against potential margin calls on certain natural gas derivatives due to large increases in the price of natural gas. We expensed $119,000 related to the expiration of these options during the nine months ended September 30, 2003. Interest Rate Risk Our floating rate debt exposes us to changes in interest rates. With regard to our revolving credit facility, a 10% fluctuation in short-term interest rates would have impacted our 2002 cash flow by approximately $32,000. Financial Instruments and Debt Maturities Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowing, senior subordinated notes payable and Series B redeemable preferred stock. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the bank and vendor borrowings approximate the carrying amounts as of September 30, 2002 and 2003, and were determined based upon interest rates currently available to us for borrowings with similar terms. Maturities of the debt are $1.6 million in 2003, $3.9 million in 2004, $8.5 million in 2005 and the balance in 2007. 24 Business and Properties Unless explicitly stated otherwise, or the context otherwise requires, all references in this section to planned capital expenditures or planned drilling activities assume the completion of the offering described in our prospectus dated February 5, 2004. General We are an independent energy company engaged in the exploration, development and production of natural gas and oil. Our current operations are focused in proven, producing natural gas and oil geologic trends along the onshore Gulf Coast in Texas and Louisiana, primarily in the Miocene, Wilcox, Frio and Vicksburg trends. Our other interests include properties in East Texas, a coalbed methane investment in the Rocky Mountains and, recently, the Barnett Shale trend in North Texas. Additionally, in 2003 we obtained licenses to explore in the U.K. North Sea. We have grown our production through our 3-D seismic-driven exploratory drilling program. Our compound production growth rate for the period December 31, 1999 through December 31, 2003 on an annualized basis was 15%. From our inception through December 31, 2003, we participated in the drilling of 295 wells (89.9 net) with a success rate of approximately 68% in our onshore Gulf Coast core area. Exploratory wells accounted for 97% of the total wells we drilled. Our total proved reserves as of December 31, 2002 were an estimated 63.2 Bcfe with a PV-10 Value of $83.6 million. During 2002, we added 11.4 Bcfe to proved reserves and produced 7.2 Bcfe. As a main component of our business strategy, we have acquired licenses for over 8,700 square miles of 3-D seismic data for processing and evaluation. Since 2001, we have been able to increase the size of our 3-D seismic holdings in our onshore Gulf Coast core area by approximately 75% to over 6,650 square miles, in large part by taking advantage of very favorable pricing available for nonproprietary data. One of our primary strengths is the experience of our management and technical staff in the development, processing and analysis of this 3-D seismic data to generate and drill natural gas and oil prospects. Our technical and operating employees have an average of over 20 years of industry experience, in many cases with major and large independent oil and gas companies, including Shell Oil, ARCO, Conoco, Vastar Resources, Pennzoil and Tenneco. Using our 3-D seismic database, our highly qualified technical staff is continually adding to and refining our substantial inventory of drilling locations. We believe that our utilization of large-scale 3-D seismic surveys and related technology allows us to create and maintain a multiyear inventory of high-quality exploration prospects. As of September 30, 2003, we had 85,678 gross acres in Texas and Louisiana under lease or lease option, almost all of which is covered by 3-D seismic data. On this leased acreage, we have identified over 120 potential exploratory drilling locations, including over 45 additional extension opportunities, depending on the success of our initial drilling activities on those locations. The vast majority of our 3-D seismic data covers productive geological trends in our onshore Gulf Coast core area, where we have made 192 completions as a result of our utilization and evaluation of this data. Business Strategy Growth Through the Drillbit Our objective is to create shareholder value through the execution of a business strategy designed to capitalize on our strengths. Key elements of our business strategy include: o Grow Primarily Through Drilling. We are pursuing an active technology-driven exploration drilling program. We generate exploration prospects through geological and geophysical analysis of 3-D seismic and other data. Our ability to successfully define and drill exploratory prospects is demonstrated by our exploratory drilling success rate in the onshore Gulf Coast core area of 73% over the last three years. We are drilling or plan to drill approximately 36 wells (16.6 net) in the onshore Gulf Coast area during 2004. We have budgeted approximately $40 to $45 million for capital expenditures in 2004, $39.4 million of which we expect to use for drilling activities in the onshore Gulf Coast area. o Focus on Prolific and Industry-Proven Trends. We focus our activities primarily in the prolific onshore Gulf Coast area where our management, our technical staff and our field operations teams have significant prior experience. Although we have broadened our areas of operations to include the Rocky Mountains and have purchased interests in the Barnett Shale trend and the U.K. North Sea, we plan to focus a majority of our near-term capital expenditures in the onshore Gulf Coast region, where we believe our accumulated data and knowledge base provide a competitive advantage. 25 o Aggressively Evaluate 3-D Seismic Data and Acquire Acreage to Maintain a Large Drillsite Inventory. We have accumulated and continue to add to a multiyear inventory of 3-D seismic and geologic data along the prolific producing trends of our onshore Gulf Coast region. In 2003, we added approximately 1,050 square miles of newly released 3-D and seismic data. We believe our utilization of large-scale 3-D seismic surveys and related technology provides us with the opportunity to maximize our exploration success. As of September 30, 2003, we had accumulated licenses for approximately 8,700 square miles of 3-D seismic data and identified over 210 drilling locations and extension opportunities, including 123 currently under lease or in the process of being leased. o Maintain a Balanced Exploration Drilling Portfolio. We seek to balance our drilling program between projects with relatively lower risk and moderate potential and drilling prospects that have relatively higher risk and substantial potential. We will continue to expand our exploratory drilling portfolio, including possibly through acquisitions with exploration potential. o Manage Risk Exposure by Market Testing Prospects and Optimizing Working Interests. We seek to limit our financial and operating risks by varying our level of participation in drilling prospects with differing risk profiles and by seeking additional technical input and economic review from knowledgeable industry participants regarding our prospects. Additionally, we rely on advanced technologies, including 3-D seismic analysis, to better define geologic risks, thereby enhancing the results of our drilling efforts. We also seek to operate our projects in order to better control drilling costs and the timing of drilling. o Retain and Incentivize a Highly Qualified Technical Staff. We employ 18 natural gas and oil professionals, including geophysicists, petrophysicists, geologists, petroleum engineers and production and reserve engineers, who have an average of over 20 years of experience. This level of expertise and experience gives us a unique in-house ability to apply advanced technologies to our drilling and production activities. Our technical staff is granted stock options and participates in an incentive bonus pool based on production resulting from our exploratory successes. Significant Areas For the period from January 1, 2000 through December 31, 2002, we completed 61 wells (18.8 net) in 84 attempts for a success rate of 73%. Total exploration, development and acquisition activities from January 1, 2000 through December 31, 2002 resulted in the addition of approximately 26.4 Bcfe, net to our interest. We have budgeted approximately $40 to $45 million to drill approximately 36 wells (16.6 net) and to purchase and reprocess 3-D seismic surveys during 2004. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." The following chart summarizes our properties by region and focus area as of September 30, 2003 unless otherwise noted.
Three Months Ended September 30, 2003 At September 30, 2003 ------------------ ------------------------------------------------ Average Productive 3-D Net Daily Net % Wells Seismic Options/ Drilling Capital Expenditures Production Nat. --------------------- Data Leased ------------------------------ (MMcfe/d) Gas Gross Net (Sq. Miles) Acres Estimated 2003 Budgeted 2004 ---------- ----- --------- --------- ----------- ---------- -------------- ------------- (millions) Onshore Gulf Coast: Wilcox.............. 1.6 94 28 8.2 1,793 18,741 $ 5.9 $ 8.0 Frio/Vicksburg...... 8.4 58 137 43.3 2,102 8,615 6.1 11.0 Southeast Texas..... 8.8 78 11 3.8 900 3,729 2.9 11.1 South Louisiana..... 2.4 58 7 1.3 1,864 2,028 4.0 9.3 East Texas............ 0.4 -- 45 5.9 472 2,816 -- 0.5 Rocky Mountain........ -- -- -- -- 473 27,140 0.6 -- Barnett Shale......... -- -- -- -- -- 1,409 0.9 1.2 North Sea............. -- -- -- -- 153 209,613 -- -- Other Areas........... -- -- -- -- 980 -- -- -- ---------- ----- --------- --------- ----------- ---------- -------------- ------------- Total................. 21.6 68 228 62.5 8,737 274,091 $ 20.4 $ 41.1 ========== ===== ========= ========= =========== ========== ============== =============
Core Project Area--The Onshore Gulf Coast Region The onshore Gulf Coast region is a prolific proven hydrocarbon trend with complex structural and stratigraphic targets that are optimally explored through the use of 3-D seismic data. We believe our approximately 6,650 square miles of data located in key producing onshore Gulf Coast trends is comparable to the volume of data some major oil and gas companies hold for this area. Of this volume, approximately 2,870 square miles of 3-D seismic data was acquired or reprocessed in the last 18 months. Our exploration 26 staff, with an average of over 20 years experience, analyzes the data seeking to provide multiple opportunities which we prioritize and add to our onshore Gulf Coast exploration prospect portfolio. Wilcox Trend We have licenses for approximately 1,800 square miles of 3-D seismic data and 18,741 acres of leasehold in the Wilcox trend in Texas. From January 1, 2000 through December 31, 2003, we drilled and completed 32 wells (9.8 net) on 40 attempts in this area. We invested $5.9 million to drill and complete eight wells (2.3 net) in the Texas Wilcox area in 2003 and expect to devote approximately $8.0 million to drill seven wells (3.9 net) in this area in 2004. Currently, we have identified over 30 exploratory drilling locations, with an additional 22 potential extension opportunities, in the Wilcox trend over which we have licenses for 3-D seismic data and leased acreage. Approximately 18 of the 30 exploratory locations we have identified are relatively lower risk and generally shallower with the remainder being relatively higher risk and deeper with greater upside potential. Greater Cabeza Creek. Since January 1, 2000, our exploration efforts in the Wilcox area largely have been focused in the greater Cabeza Creek area centered in Goliad, Lavaca and Dewitt Counties, where we have licenses for over 950 square miles of 3-D seismic data and 5,700 net acres of leasehold. From January 1, 2000 through December 31, 2003, we have drilled 14 wells (7.1 net) with an 86% success rate in this area. Our most notable discovery was the Riverdale Field in 2001, where we have 68.8% working interest. The Riverdale Field was delineated with two extension wells. The greater Cabeza Creek area continues to be a primary focus area in the middle and lower Wilcox intervals which have relatively higher potential and risk. We have a significant acreage position to either explore ourselves or sell to third parties while retaining a promoted interest. Texas Frio/Vicksburg Trend Area This combined trend area sometimes overlaps but is generally closer to the Texas Gulf Coast than the Wilcox areas discussed above. In any particular target or prospect in this area, the Frio is the shallower formation, above the deeper Vicksburg and still deeper Yegua formations. We have licenses for a total of 2,100 miles of 3-D seismic data and 8,615 net leasehold acres over this trend. Since 1999, we have focused primarily in Matagorda County, the location of the Providence Field, and in Brooks County, the location of the Encinitas Field. Currently, we have identified over 23 exploratory drilling locations with an additional 12 potential extension opportunities (depending on the success of our initial drilling activities on those locations) in the Frio/ Vicksburg trend area over which we have licenses for 3-D seismic data and leased acreage. Approximately 15 of the 23 exploratory locations we have identified are relatively lower risk and generally shallower with the remaining eight being relatively higher risk and deeper with greater upside potential. From January 1, 2000 through December 31, 2003, we have drilled and completed 38 wells (10.0 net) in 45 attempts in this trend. We invested $6.1 million to drill and complete 16 wells (3.4 net) in the Frio/ Vicksburg trend area in 2003 and expect to devote approximately $11.0 million to drill 12 wells (5.0 net) in this area in 2004. Providence Field. We have licenses for over 540 square miles of 3-D data (including 450 square miles of newly reprocessed data delivered in 2003) in and surrounding the Providence Field we discovered in 2001. Since the discovery well commenced production in January 2002, five wells have been drilled and successfully completed. Four of the wells had average production rates ranging from 14,309 to 17,669 Mcfe per day per well during the first 90 full days of production. The field has cumulative production as of September 30, 2003 of 10.2 Bcfe. We have working interests ranging from 35% to 45% in the leases in this field and operate three of the six wells. We anticipate participating in two additional extension wells (1.0 net) in the field in first quarter 2004. Encinitas Field. This field, the site of our first 3-D seismic survey in 1995, has 24 wells currently producing. Since 1996, we have participated in the drilling of 24 wells (4.0 net) in this area, 22 (3.5 net) of which were successfully completed. During 2003, we participated in the drilling of nine wells, all of which were successfully completed. We expect to drill between four and eight wells in 2004, with an additional six to 10 well locations to be drilled thereafter. We will have a 27.5% working interest in those wells. Southeast Texas Area The Southeast Texas area contains similar objective levels found in the Frio/Vicksburg trend area. We separate this as a focus area because of the geographic concentration of our 3-D seismic data and because reservoirs in this area can display seismic amplitude anomalies. Seismic amplitude anomalies can be interpreted as an indicator of hydrocarbons, although these anomalies are not necessarily reliable as to hydrocarbon presence or productivity. We have acquired licenses for approximately 900 square miles of 3-D 27 data (including 400 square miles of newly released data delivered in 2003) over our Southeast Texas project area which is focused primarily on the Frio, Yegua, Cook Mountain and Vicksburg formations. The project area is split into the Cedar Point and Liberty County areas. Currently, we have identified over 15 exploratory drilling locations with an additional 10 potential extension locations in the Southeast Texas area over which we have licenses for 3-D seismic data. Approximately 12 of the 15 exploratory locations we have identified are relatively lower risk and generally shallower with the remaining three being relatively higher risk and deeper with greater upside potential. From January 1, 2000 to December 31, 2003, we participated in the drilling and completion of 12 wells (4.3 net)in 17 attempts in this area. We invested $2.9 million to drill and complete five wells (1.3 net) in the Southeast Texas area in 2003 and expect to devote approximately $11.1 million to drill 11 wells (4.8 net) in this area in 2004. The Liberty Project Area and Cedar Point Project Area have proven to be successful for us, and we expect that the Liberty Project Area will constitute a significant portion of our drilling program for the remainder of 2003 and for 2004. Cedar Point Area. The Cedar Point Project Area is located in Chambers County, Texas, adjacent to Trinity Bay. The 30-square-mile 3-D survey targets the lower Frio and Vicksburg formations. Since 1999, five of six wells drilled have been successful. In 2003, we drilled one well that produced an average of 15,789 Mcfe per day during the first 90 full days of production. In December 2003, we completed an extension well that encountered approximately 41 feet of logged pay. Our working interest in leases in this project area is approximately 28% in the first well drilled in 2003 and 25% in the extension well. Liberty County Area. We have identified and leased prospects ranging from the Frio to the Cook Mountain formations within the 500 square miles of 3-D seismic data in the Liberty Project Area which, along with 290 square miles of newly released 3-D seismic data licensed in early 2003, now covers significant areas of Liberty and Hardin Counties, Texas. Since January 1, 2000, we have been successful on six of eight wells drilled, including one Yegua well, one Frio well and five Cook Mountain wells. In 2002, we completed one well that produced an average of 9,787 Mcfe per day during the first 90 full days of production. We operate this well and own a 40% working interest. In 2003, we had another drilling success in this area with a well producing an average of 13,030 Mcfe per day during the first 90 full days of production. We operate this well and own a 46.3% working interest. South Louisiana Area The South Louisiana area primarily contains objectives in the Middle and Lower Miocene intervals. We have acquired licenses for approximately 1,850 square miles of 3-D data (including 1,416 square miles of newly released data delivered in 2003), and over 2,000 acres of leasehold. The 3-D seismic data sets are concentrated in one general area including St. Mary, Terrebonne and LaFourche Parishes. Currently, we have identified over eight exploratory drilling locations with an additional three potential extension locations in the South Louisiana area over which we have licenses for 3-D seismic data. Two of the eight exploratory locations we have identified are relatively lower risk and generally shallower with the other six being relatively higher risk and deeper with greater upside potential. From January 1, 2000 to December 31, 2003, we drilled and completed seven wells (1.7 net) on 14 attempts in this area. We invested $4.0 million to drill three wells (0.7 net) in the South Louisiana area in 2003 and expect to devote approximately $9.3 million to drill five wells (2.5 net) in this area in 2004. LaRose Area. During 2002, we successfully drilled and completed an offset well to the discovery well in this area. We operate the two wells and own a 40% working interest. The discovery well produced at an average of 15,581 Mcfe per day during the first 90 full days of production. We plan to participate in three to four additional wells (1.3 to 1.8 net) in the general area during 2004. Patterson Area. In December 2003, we announced the discovery of Shadyside #1 well in this area, which logged over 77 feet of pay. We operate the well and have an approximate 35% working interest. We believe there are two potential extension wells in the Patterson area. 28 Other Areas of Interest East Texas Area The East Texas area encompasses multiple objectives, including the Wilcox and Cotton Valley intervals. We are focused on the Camp Hill Field, a Wilcox steam flood project in Anderson County, and the Tortuga Grande Prospect, a Cotton Valley sand opportunity. We have licenses for over 470 square miles of 3-D seismic data in the East Texas area and 2,816 net acres under leasehold. We expect to invest $0.5 million to drill one (0.5 net) well in this region in 2004. Camp Hill Field. We own interests in eight leases totaling approximately 600 gross acres in the Camp Hill field in Anderson County, Texas. We currently operate seven of these leases. During the year ended December 31, 2002, the project produced an average of 58 Bbls/d of 19 API gravity oil. The wells produce from a depth of 500 feet and utilize a tertiary steam drive as an enhanced oil recovery process. Although efficient at maximizing oil recovery, the steam drive process is relatively expensive to operate because natural gas or produced crude is burned to create the steam injectant. Lifting costs during the year ended December 31, 2002 averaged $14.99 per barrel ($2.50 per Mcfe). In response to high fuel gas prices, steam injection was reduced in mid-2000. Because profitability increases when natural gas prices drop relative to oil prices, the project is a natural hedge against decreases in natural gas prices relative to oil prices. The oil produced, although viscous, commands a higher price (an average premium of $1.00 per Bbl during the year ended December 31, 2002) than West Texas intermediate crude due to its suitability as a lube oil feedstock. As of December 31, 2002, we had 7.7 MMBbls of proved oil reserves in this project, with 750 MBbls of oil reserves currently developed. We have from time to time chosen to delay development of our proved undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing shorter-term exploration projects with potential higher rates of return, adding to our lease position in this field and further evaluating additional economic enhancements for this field's development. The proved undeveloped reserves at the Camp Hill Field constitute 66% of our proved reserves and account for 34% of our present value of net future revenues from proved reserves as of December 31, 2002. We anticipate drilling additional wells and increasing steam injection to develop the proved undeveloped reserves in this project, with the timing and amount of expenditures dependent on the relative prices of oil and natural gas. We have an average working interest of approximately 90% in this field and an average net revenue interest of 74%. Tortuga Grande Prospect. In November 2003 we finalized an agreement to operate the re-entry of an abandoned Cotton Valley test well that calculates on logs to have over 230 feet of sands with possible production. At the time of drilling, the operator perforated the objective interval and tested gas but in uneconomic volumes. This well was drilled before newer fracturing technology that can increase flow rates was developed and when gas prices were significantly lower. Following successful testing of this re-entry, there are over 10 potential extension locations on our acreage that may be prospective. Barnett Shale Trend We began active participation in the Barnett Shale play in the Fort Worth Basin on acreage located west of the city of Fort Worth, Texas in mid-2003. Since that time, we have acquired leases on 2,178 net acres and have transactions pending on additional acreage. We have invested $0.9 million to drill six wells (2.6 net), two of which are completed and producing and four of which are awaiting pipeline hookup. Net production from the two wells (0.6 net) drilled to date that are on-line was a combined 360 Mcf per day and 384 Mcfe per day as of November 21, 2003. We have received permits for the first proposed well for which we will act as operator, a horizontal well expected to be drilled in the first quarter of 2004. We are continuing to expand our leasehold acquisition in this trend. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Recent Developments--Potential Barnett Shale Acquisition." Rocky Mountain Region As discussed below under "--Pinnacle Transaction," in the second quarter of 2003, we contributed to Pinnacle our interests in leases in the Clearmont, Kirby, Arvada and Bobcat project areas and natural gas and oil reserves in the Bobcat project in the Powder River Basin in southwestern Wyoming and Montana. We also own direct interests in approximately 189,000 gross acres of coalbed methane properties in the Castle Rock project area in Montana and the Oyster Ridge project area in Wyoming that were not contributed to Pinnacle, but we currently have no proved reserves of, and are no longer receiving revenue from, coalbed methane gas other than through Pinnacle. As of the closing of the Pinnacle transaction in June 2003, we had participated in the acquisition and/or drilling of 77 wells (29.0 net); we had invested $0.6 million to drill and complete two wells in the Rocky Mountain region from January 1, 2003 to that date. All of 29 the wells encountered coal accumulations and are in various stages of development and/or stages of production. Coalbed methane wells typically first produce water in a process called dewatering and then, as the water production declines, begin producing methane gas at an increasing rate. As the wells mature, the production peaks and begins declining. We continue to own a 26.9% interest in Pinnacle on a fully diluted basis. We are not required to make any further capital contributions to Pinnacle. Of the approximately 318,740 gross and 90,250 net mineral acres held by us and Pinnacle, respectively, as of September 30, 2003, approximately 193,250 and 20,970 net mineral acres, respectively, are located in the State of Montana. The issuance of new coalbed methane drilling permits in Montana was halted temporarily pending the Federal Bureau of Land Management's approval of a final record of decision on Montana's Resource Management Plan environmental impact statement and the Montana Department of Environmental Quality's approval of a statewide oil and gas environmental impact statement. These two program approvals were obtained in April and August of 2003, respectively. Accordingly, the Montana Board of Oil and Gas Conservation has begun accepting new coalbed methane drilling permit applications. Environmental groups have initiated two lawsuits, each challenging one of these program approvals. We believe that the decisions by the Federal Bureau of Land Management and the State of Montana ultimately will be upheld and new coalbed methane development will continue to be authorized in Montana. Pinnacle holds approximately 56 grandfathered drilling permits in Montana that were contributed by our joint venture partner RMG at the time of Pinnacle's formation, and RMG holds approximately 56 grandfathered drilling permits in Montana for acreage in which CCBM also has an interest. There can be no assurance that any new permits will be obtained in a given time period or at all. U.K. North Sea Region We have been awarded seven acreage blocks, consisting of one "Traditional" and three "Promote" licenses, in the United Kingdom's 21st Round of Licensing. The awarded blocks, to explore for natural gas and oil totaling approximately 209,000 acres, are located within mature producing areas of the Central and Southern North Sea in water depths of 30 to 350 feet. The Promote licenses do not have drilling commitments and have two-year terms. The Traditional license will be canceled after four years if we or our assignee elects not to commit to drilling a well. We believe our U.K. North Sea interest is a natural extension to our technical analyses, portfolio and business plan. The U.K. North Sea includes proven hydrocarbon trends with established technological expertise, available large 3-D seismic datasets and significant exploration potential. We plan to promote our interests to other parties experienced in drilling and operating in this region. Geological and geophysical costs will be incurred in an attempt to maximize the value of our retained interest. Our estimated project commitments from commencement through mid-2005 are $0.9 million, comprised of $0.2 million for seismic data, $0.2 million for leasehold costs and $0.2 million for data processing in 2003 and $0.3 million for seismic data processing in 2004. Working Interest and Drilling in Project Areas The actual working interest we ultimately will own in a well will vary based upon several factors, including the depth, cost and risk of each well relative to our strategic goals, activity levels and budget availability. From time to time, some fraction of these wells may be sold to industry partners either on a prospect-by-prospect basis or on a program basis. In addition, we may also contribute acreage to larger drilling units, thereby reducing prospect working interest. We have, in the past, retained less than 100% working interest in our drilling prospects. References to our interests are not intended to imply that we have or will maintain any particular level of working interest. Our success will be materially dependent upon the success of our exploratory drilling program. In addition, although we currently are pursuing prospects within the project areas described above, there can be no assurance that these prospects will be drilled at all or within the expected time frame. See "Risk Factors--Natural gas and oil drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us" and "Risk Factors--We may not adhere to our proposed drilling schedule." Natural Gas and Oil Reserves The following table sets forth our estimated net proved natural gas and oil reserves and the PV-10 Value of such reserves as of December 31, 2002. The reserve data and the present value as of December 31, 2002 were prepared by Ryder Scott Company and Fairchild and Wells, Inc., Independent Petroleum Engineers. The PV-10 Value was prepared using constant prices as of the calculation date, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated natural gas and oil reserves we own. For further information concerning the present value of future net revenue from these proved reserves, 30 see Note 13 of the notes to our consolidated financial statements for the year ended December 31, 2002, which are included in our annual report on Form 10-K for the year ended December 31, 2002.
Proved Reserves --------------------------------------- Developed Undeveloped Total ----------- ----------- ----------- Natural gas (MMcf)................... 12,826 96 12,922 Oil and condensate (MBbls)........... 1,393 6,988 8,381 Natural gas equivalent (MMcfe)..... 21,184 42,024 63,208 PV-10 Value (in thousands)(1)........ $ 55,235 $ 28,379 $ 83,614
---------- (1) The PV-10 Value as of December 31, 2002 is pretax and was determined by using the December 31, 2002 sales prices, which averaged $29.16 per Bbl of oil, $4.70 per Mcf of natural gas. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC. For a discussion of the uncertainties inherent in estimating natural gas and oil reserves and their estimated values, see "Risk Factors--Our reserve data and estimated discounted future net cash flows are estimates based on assumptions that may be inaccurate and on existing economic and operating conditions that may differ from future conditions." Volumes, Prices and Natural Gas & Oil Operating Expense The following table sets forth certain information regarding the production volumes of, average sales prices received for and average production costs associated with our sales of natural gas and oil for the periods indicated. The table includes the cash impact of hedging activities and the effect of certain hedge positions with an affiliate of Enron Corp. reclassified as derivatives during November 2001.
Year Ended December 31, ------------------------------------ 2000 2001 2002 ---------- ---------- ---------- Production volumes: Natural gas (MMcf).......................................... 5,460 4,432 4,801 Oil (MBbls)................................................. 198 160 401 Natural gas equivalent (MMcfe)........................... 6,651 5,390 7,207 Average sales prices:(1) Natural gas (per Mcf)....................................... 3.90 5.04 3.50 Oil (per Bbl)............................................... $ 27.81 $ 24.28 $ 24.94 Natural gas and oil operating expenses (per Mcfe):(2) Operating expenses in all areas excluding Camp Hill......... $ 0.59 $ 0.43 $ 0.44 Operating expenses in Camp Hill............................. 3.08 2.14 2.50 Total operating expenses................................. $ 0.74 $ 0.77 $ 0.68
---------- (1) Includes impact of hedging activities. (2) Includes direct operating costs (labor, repairs and maintenance, materials and supplies), workover costs and the administrative costs of production offices, insurance and property and severance taxes. Development, Exploration and Acquisition Capital Expenditures The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities. 31
Year Ended December 31, --------------------------------------- 2000 2001 2002 ----------- ----------- ----------- (in thousands) Acquisition costs: Unproved properties(1)...... $ 6,641 $ 12,607 $ 6,402 Proved properties........... 337 800 660 Exploration................... 7,843 18,356 14,194 Development................... 1,361 3,065 2,351 ----------- ----------- ----------- Total costs incurred(2).. $ 16,182 $ 34,828 $ 23,607 =========== =========== ===========
---------- (1) Includes unproved property costs of $9.0 million in 2001 and $2.2 million in 2002 in the coalbed methane properties we contributed as a minority interest to Pinnacle in June 2003. (2) Excludes capitalized interest on unproved properties of $3.6 million, $3.2 million and $3.1 million for the years ended December 31, 2000, 2001 and 2002, respectively. Drilling Activity The following table sets forth our drilling activity for the years ended December 31, 2000, 2001 and 2002. In the table, "gross" refers to the total wells in which we have a working interest and "net" refers to gross wells multiplied by our working interest therein. Our drilling activity from January 1, 1996 to December 31, 2002 has resulted in a commercial success rate of approximately 66%.
Year Ended December 31, --------------------------------------------- 2000 2001 2002 ------------- ------------- ------------- Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- Exploratory wells: Productive...... 19 4.7 18 5.9 16 5.6 Nonproductive... 15 3.4 5 1.4 3 1.1 ----- ----- ----- ----- ----- ----- Total........ 34 8.1 23 7.3 19 6.7 ===== ===== ===== ===== ===== ===== Development wells: Productive...... 5 1.9 2 0.3 1 0.4 Nonproductive... -- -- -- -- -- -- ----- ----- ----- ----- ----- ----- Total........ 5 1.9 2 0.3 1 0.4 ===== ===== ===== ===== ===== =====
The above table excludes 75 gross (28 net) wells drilled or acquired by CCBM through 2002. At December 31, 2002, we have ownership in 11 gross (2.7 net) wells with dual completion in single bore holes. Productive Wells The following table sets forth the number of productive natural gas and oil wells in which we owned an interest as of December 31, 2002.
Company Operated Other Total ------------- ------------- ------------- Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- Oil........ 49 46 18 6 67 52 Natural Gas 36 19 59 15 95 34 ----- ----- ----- ----- ----- ----- Total...... 85 65 77 21 162 86 ===== ===== ===== ===== ===== =====
Acreage Data The following table sets forth certain information regarding our developed and undeveloped lease acreage as of September 30, 2003. Developed acres refers to acreage within producing units and undeveloped acres refers to acreage that has not been placed in producing units. Leases covering substantially all of the undeveloped acreage in the following table will expire within the next three years. In general, our leases will continue past their primary terms if natural gas or oil in commercial quantities is being produced from a well on such leases. 32
Developed Acreage Undeveloped Acreage Total --------------------- --------------------- --------------------- Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Onshore Gulf Coast.... 40,449 14,767 44,182 18,675 84,631 33,442 East Texas............ 360 220 687 342 1,047 562 Rocky Mountain........ -- -- 145,376 16,710 145,376 16,710 U.K. North Sea........ -- -- 209,613 209,613 209,613 209,613 --------- --------- --------- --------- --------- --------- Total............... 40,809 14,987 399,858 245,340 440,667 260,327 ========= ========= ========= ========= ========= =========
The table does not include 7,422 gross acres (3,334 net) that we had a right to acquire in Texas pursuant to various seismic options or agreements at September 30, 2003. Under the terms of our option agreements, we typically have the right for a period of one year, subject to extensions, to exercise our option to lease the acreage at predetermined terms. Our lease agreements generally terminate if producing wells have not been drilled on the acreage within a period of three years. Further, the table does not include 28,511 gross and 10,403 net acres in Wyoming that we have the right to earn pursuant to specified drilling obligations and other predetermined terms. Marketing Our production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus a bonus and natural gas is sold under contract at a negotiated price based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply and demand conditions. Our marketing objective is to receive the highest possible wellhead price for our product. We are aided by the presence of multiple outlets near our production in the Texas and Louisiana onshore Gulf Coast. We take an active role in determining the available pipeline alternatives for each property based on historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability. There are a variety of factors that affect the market for natural gas and oil, including: o the extent of domestic production and imports of natural gas and oil; o the proximity and capacity of natural gas pipelines and other transportation facilities; o demand for natural gas and oil; o the marketing of competitive fuels; and o the effects of state and federal regulations on natural gas and oil production and sales. See "Risk Factors--Natural gas and oil prices are highly volatile, and lower prices will negatively affect our financial results," "Risk Factors--We are subject to various governmental regulations and environmental risks" and "Risk Factors--The marketability of our natural gas production depends on facilities that we typically do not own or control, which could result in a curtailment of production and revenues." We from time to time market our own production where feasible with a combination of market-sensitive pricing and forward-fixed pricing. We utilize forward pricing to take advantage of anomalies in the futures market and to hedge a portion of our production deliverability at prices exceeding forecast. All of these hedging transactions provide for financial rather than physical settlement. For a discussion of these matters, our hedging policy and recent hedging positions, see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Critical Accounting Policies and Estimates--Derivative Instruments and Hedging Activities" and "Management's Discussion and Analysis of Financial Condition and Results of Operations--Qualitative and Quantitative Disclosures About Market Risk--Derivative Instruments and Hedging Activities." Competition and Technological Changes We encounter competition from other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Many of our competitors are large, well-established companies that have been engaged in 33 the natural gas and oil business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. We may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment. See "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Risk Factors--We face strong competition from larger natural gas and oil companies" and "Risk Factors--We have substantial capital requirements that, if not met, may hinder operations." The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. See "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Risk Factors--We may not be able to keep pace with technological developments in our industry," "Risk Factors--We may experience difficulty in achieving and managing future growth" and "Risk Factors--We have substantial capital requirements that, if not met, may hinder operations." Regulation Natural gas and oil operations are subject to various federal, state and local environmental regulations that may change from time to time, including regulations governing natural gas and oil production, federal and state regulations governing environmental quality and pollution control and state limits on allowable rates of production by well or proration unit. These regulations may affect the amount of natural gas and oil available for sale, the availability of adequate pipeline and other regulated transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The following discussion summarizes the regulation of the United States oil and gas industry. We believe we are in substantial compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although we cannot assure you that this is or will remain the case. Moreover, those statutes, rules, regulations and government orders may be changed or reinterpreted from time to time in response to economic or political conditions, and any such changes or reinterpretations could materially adversely affect our results of operations and financial condition. The following discussion is not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our operations may be subject. Regulation of Natural Gas and Oil Exploration and Production Our operations are subject to various types of regulation at the federal, state and local levels that: o require permits for the drilling of wells; o mandate that we maintain bonding requirements in order to drill or operate wells; and o regulate the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. Our operations are also subject to various conservation laws and regulations. These regulations govern the size of drilling and spacing units or proration units, the density of wells that may be drilled in natural gas and oil properties and the unitization or pooling of natural gas and oil properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose specified requirements regarding the ratability of production. The effect of these regulations may limit the amount of natural gas and oil we can produce from our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the natural gas and oil industry increases our costs of doing business and, consequently, affects our 34 profitability. Because these laws and regulations are frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with such regulations. Regulation of Sales and Transportation of Natural Gas Federal legislation and regulatory controls have historically affected the price of natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the Federal Energy Regulatory Commission (FERC) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act (the Decontrol Act) deregulated natural gas prices for all "first sales" of natural gas, including all of our sales of our own production. As a result, all of our domestically produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. The FERC's jurisdiction over interstate natural gas transportation, however, was not affected by the Decontrol Act. Under the NGA, facilities used in the production or gathering of natural gas are exempt from the FERC's jurisdiction. We own certain natural gas pipelines that we believe satisfy the FERC's criteria for establishing that these are all gathering facilities not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements but does not generally entail rate regulation. Although we therefore do not own or operate any pipelines or facilities that are directly regulated by the FERC, its regulations of third-party pipelines and facilities could indirectly affect our ability to market our production. Beginning in the 1980s the FERC initiated a series of major restructuring orders that required pipelines, among other things, to perform open access transportation, "unbundle" their sales and transportation functions, and allow shippers to release their pipeline capacity to other shippers. As a result of these changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. It remains to be seen, however, what effect the FERC's other activities will have on access to markets, the fostering of competition and the cost of doing business. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. In the past, Congress has been very active in the area of natural gas regulation. However, the more recent trend has been in favor of deregulation or "lighter handed" regulation and the promotion of competition in the gas industry. There regularly are other legislative proposals pending in the federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted. Oil Price Controls and Transportation Rates Our sales of oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to specified conditions and limitations. These regulations may tend to increase the cost of transporting natural gas and oil liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations generally have been approved on judicial review. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The first such review was completed in 2000 and on December 14, 2000, the FERC reaffirmed the current index. Following a successful court challenge of these orders by an association of oil pipelines, on February 24, 2003 the FERC increased the index slightly for the current five-year period, effective July 2001. We are not able at this time to predict the effects, if any, of these regulations on the transportation costs associated with oil production from our oil-producing operations. Environmental Regulations Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the 35 environment in connection with drilling and production activities, limit or prohibit drilling activities on specified lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and drilling operations. The failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of investigatory or remedial obligations or the issuance of injunctions prohibiting or limiting the extent of our operations. Public interest in the protection of the environment has increased dramatically in recent years. The trend of applying more expansive and stricter environmental legislation and regulations to the natural gas and oil industry could continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected. We generate wastes that may be subject to the federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The U.S. Environmental Protection Agency (EPA) and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Furthermore, certain wastes generated by our natural gas and oil operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes" and therefore become subject to more rigorous and costly operating and disposal requirements. We currently own or lease numerous properties that for many years have been used for the exploration and production of natural gas and oil. Although we believe that we have implemented appropriate operating and waste disposal practices, prior owners and operators of these properties may not have used similar practices, and hydrocarbons or other wastes may have been disposed of or released on or under the properties we own or lease or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), RCRA and analogous state laws as well as state laws governing the management of natural gas and oil wastes. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. See "Risk Factors--We are subject to various governmental regulations and environmental risks." CERCLA, also known as the "Superfund" law, and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on specified classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These classes of persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Our operations may be subject to the Clean Air Act (CAA) and comparable state and local requirements. In 1990 Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed and continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, we do not believe our operations will be materially adversely affected by any such requirements. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control, countermeasure (SPCC) and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 (OPA) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. The OPA also requires owners and operators of offshore facilities that could be the source of an oil spill into federal or state waters, including wetlands, to post a bond, letter of credit or other form of financial assurance in amounts ranging from $10 million in specified state waters to $35 million in federal outer continental shelf waters to cover costs that could be incurred by governmental authorities in responding to an oil spill. These financial assurances may be increased by as much as $150 million if a formal risk assessment indicates that the increase is warranted. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Our operations are also subject to the federal Clean Water Act (CWA) and analogous state laws. In 36 accordance with the CWA, the State of Louisiana issued regulations prohibiting discharges of produced water in state coastal waters effective July 1, 1997. Pursuant to other requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits or seek coverage under an EPA general permit. Like OPA, the CWA and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground. We also are subject to a variety of federal, state and local permitting and registration requirements relating to protection of the environment. We believe we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on us. As further described in "--Significant Areas--Other Areas of Interest--Rocky Mountain Region," the issuance of new coalbed methane drilling permits and the continued viability of existing permits in Montana have been challenged in lawsuits filed in state and federal court. Operating Hazards and Insurance The natural gas and oil business involves a variety of operating hazards and risks that could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. See "Risk Factors--We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues." In addition, we may be liable for environmental damages caused by previous owners of property we purchase and lease. As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties. See "Risk Factors--We are subject to various governmental regulations and environmental risks." In accordance with customary industry practices, we maintain insurance against some, but not all, potential losses. We do not carry business interruption insurance or protect against loss of revenues. We cannot assure you that any insurance we obtain will be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. We may elect to self-insure if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. See "Risk Factors--We may not have enough insurance to cover all of the risks we face." We participate in a substantial percentage of our wells on a nonoperated basis, and may be accordingly limited in our ability to control the risks associated with natural gas and oil operations. See "Risk Factors-- We cannot control the activities on properties we do not operate and are unable to ensure their proper operation and profitability." Title to Properties; Acquisition Risks We believe we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect the value of these properties. As is customary in the industry in the case of undeveloped properties, we make little investigation of record title at the time of acquisition (other than a preliminary review of local records). Investigations, including a title opinion of local counsel, are generally made before commencement of drilling operations. Our revolving credit facility is secured by substantially all of our natural gas and oil properties. In acquiring producing properties, we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a 37 material adverse effect on our financial condition and future results of operations See "Risk Factors -- Our future acquisitions may yield revenues or production that varies significantly from our projections." Employees At September 30, 2003, we had 37 full-time employees, including six geoscientists and six engineers. We believe that our relationships with our employees are good. In order to optimize prospect generation and development, we utilize the services of independent consultants and contractors to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition of leases and lease options, construction, design, well site surveillance, permitting and environmental assessment. Independent contractors generally provide field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testings. We believe that this use of third-party service providers has enhanced our ability to contain general and administrative expenses. We depend to a large extent on the services of certain key management personnel, the loss of, any of which could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. See "Risk Factors--Our business may suffer if we lose key personnel." Pinnacle Transaction Formation and Operations During the second quarter of 2003, we and Rocky Mountain Gas, Inc. (RMG) each contributed our interests in certain natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane to a newly formed joint venture, Pinnacle Gas Resources, Inc. In exchange for the contribution of these assets, we received 37.5% of the common stock of Pinnacle and options to purchase additional Pinnacle common stock. We retained our interests in approximately 189,000 gross acres in the Castle Rock project area in Montana and the Oyster Ridge project area in Wyoming. We no longer have a drilling obligation in connection with the oil and natural gas leases contributed to Pinnacle. Simultaneously with the contribution of these assets, affiliates and related parties of CSFB Private Equity (CSFB) contributed approximately $17.6 million of cash to Pinnacle in return for redeemable preferred stock of Pinnacle, 25% of Pinnacle's common stock as of the closing date and warrants to purchase Pinnacle common stock. The CSFB parties also agreed to contribute additional cash, under specified circumstances, of up to approximately $11.8 million to Pinnacle to fund future drilling, development and acquisitions. The CSFB parties currently have greater than 50% of the voting power of the Pinnacle capital stock through their ownership of Pinnacle common and preferred stock. Currently, on a fully diluted basis, assuming that all parties exercised their Pinnacle warrants and options, the CSFB parties would have an ownership interest in Pinnacle of 46.2%, and we and RMG each would own 26.9%. On a fully diluted basis, assuming the additional $11.8 million of cash were contributed by the CSFB parties and all warrants and options were exercised by all parties, the CSFB parties would own 54.6% of Pinnacle and RMG and we each would own 22.7% of Pinnacle. Immediately following its formation, Pinnacle acquired an approximate 50% working interest in existing leases and approximately 36,529 gross acres prospective for coalbed methane development in the Powder River Basin of Wyoming from an unaffiliated party for $6.2 million. The leases include 95 producing coalbed methane wells currently in the early stages of dewatering, a process that occurs prior to achieving stabilized production. At the time of the Pinnacle transaction, these wells were producing at a combined gross rate of approximately 2.5 MMcfd, or an estimated 1 MMcfd net to Pinnacle. Pinnacle also agreed to fund up to $14.9 million of future drilling and development costs on these properties on behalf of the third party prior to December 31, 2005. The drilling and development work will be done under the terms of an earn-in joint venture agreement between Pinnacle and Gastar. As of September 30, 2003, Pinnacle owned interests in approximately 131,000 gross acres in the Powder River Basin. Certain Relationships and Agreements Our Chairman, Steven A. Webster, is also Chairman of Global Energy Partners, Ltd., an affiliate of CSFB Private Equity and could be deemed a related party with respect to the Pinnacle transaction. 38 We provide specified accounting, treasury, tax, insurance and financial reporting functions to Pinnacle through the end of 2003 under a transition services agreement for a monthly fee equal to our actual cost to provide these services. After December 31, 2003, the agreement will automatically renew on a quarterly basis unless one of the parties gives notice of its intent to terminate the agreement. We have mutually agreed with RMG, its majority shareholder and the CSFB parties to provide Pinnacle the right until June 23, 2008 to acquire at cost any interest in natural gas and oil leases or mineral interests in the Powder River Basin in Wyoming and Montana, but excluding most of Powder River County, Montana, that such parties may have acquired in the covered area, subject to specified exceptions. We, the CSFB parties, RMG, RMG's parent company, Peter G. Schoonmaker, Gary W. Uhland and Pinnacle also entered into a securityholders' agreement providing for an initial eight person board of directors, which initially includes four directors nominated by the CSFB parties and two nominated by each of us and RMG, subject to change as their respective ownership percentages change. Each party to the securityholders' agreement also granted to the others a right of first offer and co-sale rights. If the CSFB parties propose to sell all of their Pinnacle shares to a third party, under specified circumstances the CSFB parties may require the other securityholders to include all of their Pinnacle shares in that sale. In event of such a sale, the Pinnacle preferred stock will have a preferred right to receive an amount equal to its liquidation value (as defined below) per share plus accrued and unpaid dividends prior to distributions to the holders of shares of Pinnacle common stock and common stock equivalents. Pinnacle also granted the securityholders pre-emptive rights to purchase additional securities in order to maintain their proportionate ownership of Pinnacle. The securityholders' agreement also provides generally for multiple demand registration rights with respect to the Pinnacle common stock in favor of the CSFB parties and certain piggyback registration rights for us and RMG subject to the satisfaction of specified conditions. Pinnacle Preferred Stock and Warrants Held by the CSFB Parties The Pinnacle redeemable preferred stock issued to the CSFB parties generally has the right to vote together with the Pinnacle common stock and has a class vote on specified matters, including specified extraordinary transactions. In the event of any dissolution, liquidation, or winding up by Pinnacle, the holder of each share of Pinnacle preferred stock will be entitled to be paid a liquidation value of $100 per share out of the assets of Pinnacle available for distribution to its shareholders. Dividends on the Pinnacle preferred stock are payable either in cash at a rate of 10.5% per annum through June 23, 2011 and 12.5% thereafter or, at Pinnacle's option, by payment in kind of additional shares of the Pinnacle preferred stock. For each additional share of Pinnacle preferred stock distributed to a holder as an in-kind dividend, Pinnacle will also deliver to that holder one Pinnacle warrant, which will have an exercise price equal to the exercise price of the outstanding Pinnacle warrants on the date of such distribution. On or after July 1, 2005, Pinnacle may redeem all or any portion of the Pinnacle preferred stock, provided that if any Pinnacle warrants are still outstanding, Pinnacle may redeem all but a single share; if the redemption occurs at any time before July 1, 2009, the redemption price will be at a premium to the liquidation value of the shares. Pinnacle is required to redeem its preferred stock upon: o specified changes of control, at a price per share equal to 101% of its liquidation value; or o specified events of default, at a price per share equal to 110% of the liquidation value prior to June 30, 2005 and, thereafter, equal to an optional redemption price that decreases over time. The Pinnacle warrants entitle the holders to purchase up to 130,000 shares of Pinnacle common stock at a price of $100 per share and are exercisable at any time until June 30, 2013. The Pinnacle warrants can be exercised in cash, by tender of the Pinnacle preferred stock and on a cashless net exercise basis. The Pinnacle warrants are subject to adjustments, including, in specified cases, an adjustment of the exercise price to equal the lowest price at which Pinnacle common stock is sold if such shares are sold below the then-current exercise price. 39