Item 2. Properties (see Item 1. Business and Properties)
Item 3.
Item 3. Legal Proceedings
We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. Where the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of our security holders during the last quarter of the fiscal year ended December 31, 2003.
Part II.
Item 5.
Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters
Our common stock is traded on the New York Stock Exchange under the symbol “THX.” The following table sets forth the range of high and low sales prices for each calendar quarterly period from January 1, 2002 through December 31, 2003 as reported on the New York Stock Exchange:
As of March 11, 2004, 31,786,097 shares of common stock were outstanding, and we had approximately 40 stockholders of record and approximately 4,500 beneficial owners.
Dividends
We have never declared or paid any cash dividends and do not anticipate declaring any dividends in the foreseeable future. We plan to retain our cash for the operation and expansion of our business, including exploration, development and acquisition activities. In addition, our revolving bank credit facility and the indenture governing our 7% senior subordinated notes due 2013 contain restrictions on the payment of dividends to holders of common stock. For more information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Item 6.
Item 6. Selected Financial Data
The following table shows selected financial data derived from our consolidated financial statements for each of the five years in the period ended December 31, 2003. You should read these financial data in conjunction with “Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to assist you in understanding our business and the results of operations together with our present financial conditions. This section should be read in conjunction with our Consolidated Financial Statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K.
Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. See “Forward-Looking Statements” at the beginning of this Annual Report and “Risk Factors Affecting Our Business” found on page 13 for additional discussion of some of these factors and risks.
Overview of Our Business
We are an independent natural gas and oil company engaged in the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. Natural gas is our primary focus. Our core areas of operations are South Texas, offshore in the shallow waters of the Gulf of Mexico, the Arkoma Basin of Oklahoma and Arkansas and the Appalachian Basin of West Virginia. During 2003, we commenced operations in the Rocky Mountain Region, with an initial focus in the Uinta Basin of northeastern Utah. We operate in one segment as each of our operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in SFAS 131.
Source of Our Revenues
We derive our revenues from the sale of natural gas and oil that is produced from our natural gas and oil properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of natural gas is the primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our natural gas production. The use of certain types derivative instruments may prevent us from realizing the benefit of upward price movements. At December 31, 2003, KeySpan held 55% of our common stock. KeySpan has indicated a desire to divest of its shares held in our company. In February 2003, KeySpan divested three million shares of our common stock. KeySpan has publicly announced it does not consider its investment in Houston Exploration a part of its core asset group and that it may sell or dispose of all or a portion of its non-core assets, including its investment in our company. Because market conditions are unpredictable, KeySpan is unable to determine if or when any additional dispositions of all or a portion of its remaining ownership interest in our company will take place.
Principal Components of Our Cost Structure
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Lifting Costs.The day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. These costs include: lease operating expense, severance tax and transportation expense.
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Depreciation, Depletion and Amortization (“DD&A”). The systematic expensing of the capital costs incurred to acquire, explore and develop natural gas and oil. As a full cost company, we capitalize all direct costs associated with our acquisition, exploration and development efforts, including interest and certain general and administrative costs, and apportion these costs to each unit of production sold through DD&A expense. Generally, if reserve quantities are revised up or down, the DD&A rate per unit of production will change inversely. When the depreciable base increases or decreases, the DD&A rate will move in the same direction.
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Asset Retirement Accretion Expense (“ARO”). The systematic, monthly accretion of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities.
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General and Administrative (“G&A”). Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, managing our production and development operations and legal compliance are included in our general and administrative expense (“G&A”). We capitalize G&A directly related to our acquisition, exploration and development activities.
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Interest. We typically finance acquisitions with borrowings under our revolving bank credit facility, and longer term, with public traded debt instruments. As a result, we incur substantial interest expense that correlates to both fluctuations in interest rates and our acquisition activity. Acquisitions are a critical element of our growth strategy. We expect to continue to incur significant interest expense as we continue to grow. We capitalize interest directly related to our unevaluated properties and certain properties under development, which are not being amortized.
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Income Taxes. We are generally subject to a 35% federal income tax rate. For income tax purposes, we are allowed deductions for accelerated depreciation, depletion and intangible drilling costs that reduce our current tax liability. Prior to 2003, all of our taxes, both federal and state, were deferred; however, during 2003, we utilized all of our net operating loss carryforwards and as a result, we recognized current income tax expense and will continue to recognized current tax expense as long as we are generating taxable income.
Industry Environment
We currently operate exclusively in North America. After over 100 years of active natural gas and oil exploration and production within the lower 48 states and Gulf of Mexico, the region has matured and production of natural gas and oil has declined. Numerous technological advances during this timeframe, including increasingly sophisticated geophysical tools that allow more accurate identification of reservoirs , horizontal and other drilling technologies that facilitate and enhance the extraction process, and advanced completion techniques have accelerated production rates and hastened depletion. While new discoveries are still being made in North America, the frequency and size of these discoveries is declining. As a result,
domestic natural gas and oil production as a whole may have peaked and is expected to decline in the future, with the exception of regions such as the Rocky Mountains, which we believe, continues to hold the prospect for production growth.
In this mature environment, companies will find it increasingly difficult to replace their reserves through traditional exploration and development efforts, and companies will increasingly be forced to rely on acquisitions to sustain their growth. Our future success growing our reserve base at an acceptable finding cost will depend in large part on our ability to acquire new proven reserves and unevaluated acreage on which we can explore for new discoveries. We maintain a very active acquisition program and will continue to devote significant resources to identifying and pursuing both tactical acquisitions that augment our existing property base as well as substantial, strategic acquisitions.
We anticipate that the continued decline of the North American gas basin will lead to higher cost structures throughout our industry. We believe that the cost of finding, developing and producing new natural gas and oil reserves will rise as the industry makes fewer discoveries of smaller reserve size. For full cost companies such as ours, this will result in higher finding and development costs and higher DD&A rates and ultimately the increased likelihood of a writedown in carrying value of our natural gas and oil properties. In addition, we think lease operating expenses will continue to rise as producers are forced to make operational enhancements to maintain aging fields.
Like any commodity, the price that we receive for the gas we produce is largely a function of supply and demand. Demand for natural gas is affected by general economic conditions, such as growth in the space heating, industrial and power generation segments, and seasonal conditions. Demand has also typically been impacted by seasonal fluctuations, with the peak demand during the winter heating season and summer air conditioning season. As natural gas is difficult to import, 80% to 85% of the United States’ natural gas demand in recent years has been supplied by domestic production. Imports from Canada have made up 10% to 15% of the United States’ natural gas needs and imports from a variety of other countries now make up for 1% to 2% of total supply in the form of liquefied natural gas, or LNG.
Situations involving over or under supply of natural gas can result in substantial price volatility. For example, concerns over the adequacy of natural gas in storage during the first quarter of 2003 resulted in prices exceeding $9.00 during the quarter and emerging concerns over the United States’ ability to meet its longer term gas needs from declining domestic supply have resulted in sustained prices above $5.00 throughout 2003 and into 2004. As a direct result, we were able to increase our net income, generate substantial cash flows to fund acquisitions, our capital budget and repay borrowings on our revolving bank credit facility. However, historically, commodity prices have been very volatile, and we expect the volatility to continue in the future. As a result, we cannot accurately predict future natural gas and oil prices, and, therefore, we cannot determine what effect increases or decreases will have on our future revenues and cash flows. A substantial or extended decline in natural gas and oil prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of natural gas and oil reserves that may be economically produced and our ability to access capital markets. Our continued growth and profitability depends on the strength of comodity prices our ability to acquire, find and develop new reserves at economical costs.
Critical Accounting Estimates
Proved Reserves. Our most significant financial estimates are based on estimates of proved natural gas and oil reserves. Estimates of proved reserves are key components of our unevaluated properties, our rate for recording depreciation, depletion and amortization, and our full cost ceiling limitation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is highly dependent on the quality and quantity of available data. Our reserves are fully engineered on an annual basis by independent petroleum engineers.
Asset Retirement Obligation. Asset retirement obligations represent the estimated future abandonment costs of tangible long-lived assets such as platforms, wells, service assets, pipelines, and other facilities. We estimate the fair value of an asset’s retirement obligation in the period in which the liability is incurred, if a reasonable estimate can be made. We employ a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions, including an inflation rate, the our credit adjusted risk free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability which we compute from third party quotes. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.
Derivative Instruments. Under SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we reflect the fair market value of our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes from third parties, as well as utilizing a Black-Scholes option valuation model that is based upon underlying forward price curve data, a risk-free interest rate and estimated volatility factors.
Recent Accounting Developments
SFAS 141, “Business Combinations” and SFAS 142, “Goodwill and Intangible Assets,” became effective on July 1, 2001 and January 1, 2002, respectively. These new standards emphasize a more precise evaluation of assets and their balance sheet classification as either tangible or intangible assets. We understand that the issue is under evaluation as to whether provisions of SFAS 141 and SFAS 142 may call for mineral rights held under lease or other contractual arrangements together with cash costs for the acquisition of natural gas and oil leasehold interests to be classified in the balance sheet as intangible assets. If these types of leasehold costs (both proved and unevaluated) are determined to be intangible assets, they would be classified separately from natural gas and oil properties as intangible assets on our balance sheets. This issue relates only to balance sheet classification and presentation and we do not believe it will have an effect on cash flows or results of operations. At December 31, 2003, if we applied the interpretation currently under discussion, undeveloped leasehold costs of $117.1 million and developed leasehold costs of $221.3 million, net of accumulated amortization, would be reclassified from tangibles to intangibles, representing costs incurred since June 30, 2001, the effective date of SFAS 141. At December 31, 2002, we had undeveloped leasehold costs of $49.5 million and developed leasehold costs of $111.5 million, net of accumulated amortization that would be reclassified from tangibles to intangibles. Consistent with current industry practice, we will continue to classify our natural gas and oil leasehold costs as tangible natural gas and oil properties until the Emerging Issues Task Force issues further guidance.
New Accounting Pronouncements
In November 2002, FASB issued Financial Interpretation No. (“FIN”) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN 45 requires certain guarantees to be recorded at fair value, which is different from the previous practice of recording a liability only when a loss is probable and reasonably estimable, as those terms are defined in SFAS 5, “Accounting for Contingencies.” FIN 45 has a dual effective date. The initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in the interpretation are effective for financial statements for interim or annual periods ending after December 15, 2002. As of our December 31, 2003, and December 31, 2002, balance sheet dates, we did not have any guarantees of indebtedness of others and as a result, our adoption of FIN 45 did not have an effect on our financial statements.
In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities - An Interpretation of Accounting Research Bulletin 51.” FIN 46 addresses consolidation by business enterprises of variable interest entities (VIEs) and the primary objective is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an entity to consolidate a VIE if the entity has a variable interest (or combination of variable interests) that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. However, on October 8, 2003, the FASB decided to grant a broader deferral of the implementation of FIN 46. Pursuant to this deferral, public companies must complete their evaluations of VIEs that existed prior to February 1, 2003, and the consolidation of those for which they are the primary beneficiary for financial statements issued for the first period ending after December 15, 2003. For calendar year companies, consolidation of previously existing VIEs will be required in their December 31, 2003, financial statements. We have completed our evaluation of FIN 46 and because we do not believe that we have any VIEs there is no impact to our consolidated financial statements.
Overview of 2003 Results
Strong energy commodity prices were the primary force behind a record year for operations, earnings and cash flows. The increase in our cash flows allowed for increased capital spending for drilling, acquisitions, and the repayment of debt, all of which improved our balance sheet. During 2003:
Operating and Financial Results for 2003 Compared to 2002
(1)
Average realized prices include the effect of hedges.
(2)
Mcfe is defined one million cubic feet equivalent of natural gas, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Operating Income
Higher natural gas prices were the primary factor contributing to our 86% increase in net income and our 84% increase in operating income in 2003 over 2002. Adding to the effects of higher commodity prices was an increase of 5% in production volume. Increased revenues were offset in part by a 24% increase in operating costs due primarily to the continued expansion of our operations combined with an increase in costs to maintain our existing production base together with higher DD&A rates for 2003.
Commodity Prices
Our average wellhead price during 2003, before the effects of our hedging program, was $5.23 per Mcfe up 66% over 2002. This increase in natural gas prices during 2003 accounted for $207 million, or approximately 89% of our $232 million increase, in revenues before the effects of our hedging program.
Our increase in natural gas and oil revenues was substantially offset by a $68.3 million loss from our hedging program, which lowered the price that we realized on our natural gas production by $0.68 Mcf during the period. The largest portion of this loss resulted from fixed price swaps for natural gas that we entered into during the fourth quarter of 2001 in connection with our acquisition of producing properties in South Texas. As a result of these swaps, we effectively fixed the price that we received on approximately 40 MMcf per day at $3.19, resulting in a loss of $32 million, or 47% of our total hedging loss for 2003.
Production Volume
The 5% increase in production for the current year is a result of newly developed production combined with additions from acquisitions made in 2003 and 2002.
Onshore, our daily production rates increased 12% from an average of 155 MMcfe/day during 2002 to 173 MMcfe/day during 2003. The increase in onshore production is primarily attributable to newly developed production in South Texas and Arkoma. In South Texas we drilled 56 successful wells and increased our average daily production rate to 140 MMcfe/day during 2003 from 123 MMcfe/day in 2002. In Arkoma, we more than doubled the number of wells drilled in 2002 by successfully drilling 46 wells during 2003. The impact of the newly developed production was seen in the fourth quarter of 2003 as our average daily rate in Arkoma increased to 25 MMcfe/day. For 2004, we expect our onshore daily production rate to grow by an estimated 5% or to average between 180 and 184 MMcfe/day.
Offshore, our production decreased 3% from an average of 126 MMcfe/day during 2002 to an average of 122 MMcfe/day during 2003. For the first nine months of 2003, offshore production averaged 117 MMcfe/day as production declines due to maturing reservoirs from existing key fields, Mustang Island A-31/32, High Island 39, West Cameron 587 and South Marsh Island 253, were greater than new production added from wells and facilities brought on-line throughout 2003. Specifically, we had disappointing results at South Timbalier 314/317 that was brought on-line in early 2003. Contributing to the year-over-year production decline was the effect of shifting approximately $40 million of our 2002 offshore capital expenditure budget to our onshore region to fund the May 2002 acquisition of producing properties in South Texas from Burlington Resources. During the fourth quarter of 2003, offshore production increased by approximately 16% to an average rate of 136 MMcfe/day as we began to absorb the properties acquired from Transworld in mid-October and experienced production increases from newly developed fields, in particular, High Island 115 and High Island 47. For 2004, we expect offshore production to increase by 25% to approximately 155 MMcfe/day, which will include an estimated 35 MMcfe per day from the Transworld properties.
Effects of Hedging
For 2003, we realized an average natural gas price of $4.55 per Mcf, which was 87% or $0.68 per Mcf lower than our average unhedged natural gas price or wellhead price of $5.23 for the period. Included in natural gas revenues is a loss of $67.9 million from natural gas hedging activities, which includes an unrealized loss of $1.9 million representing the ineffective portion of our derivative instruments that are not eligible for deferral under SFAS No. 133. The ineffectiveness was a result of changes during the period in the price differentials between the index price of the derivative contract, which uses a New York Mercantile Exchange (NYMEX) index, and the index price for the point of sale for the cash flow that is being hedged, the majority of which is the Houston Ship Channel index. For 2002, we realized an average gas price of $3.32 per Mcf, which was 105% of the average unhedged natural gas price of $3.16 for the period. This resulted in natural gas revenues that were $16.4 million higher than the revenues we would have achieved if hedges had not been in place during the period. For 2002, our natural gas revenues included a realized gain of $16.4 million from hedging activities.
For 2003, we realized an average oil price of $28.15 per Bbl, which was 99% or $0.31 per Bbl lower than the average unhedged price of $28.46 per Bbl for the period. As a result of oil hedging activities, oil revenues for 2003 were $0.4 million lower than the revenues we would have achieved if oil hedges had not been in place during the period. We had no oil hedges in place during 2002 and realized an average oil price of $23.99 per Bbl.
Operating Expenses
Lease Operating Expense. The increase in lease operating expenses for 2003 is attributable to the continued expansion of our operations both onshore and offshore. Our overall operating expenses are increasing as we add new wells and production facilities and continue to maintain production from existing, maturing properties. Specific increases for 2003 were incurred for production enhancement and compression, insurance and contract services. In addition, we incurred $2.6 million in non-recurring expenses associated with workovers.
The acquisition of the Transworld properties in October 2003 caused our lease operating expense on a per unit basis to increase from an average of $0.42 per Mcfe for the first nine months of 2003 to $0.47 per Mcfe during the fourth quarter of 2003. The majority of the Transworld fields were originally developed by major oil and gas producers and due to their age and complexity, lease operating expenses for these properties are expected to be significantly higher than that of our existing offshore fields. Our plan for 2004 is to reduce operating expenses per unit of production for these properties through integration and exploitation. We estimate that our lease operating expenses will average $0.54 per Mcfe during the first quarter of 2004.
Severance Tax. Severance tax is a function of volume and revenues generated from onshore production. The increase in severance tax expense and severance tax per Mcfe for 2003 is due to a 66% increase in average wellhead prices for natural gas during 2003 combined with a 12% increase in onshore production during 2003.
Depreciation, Depletion and Amortization. The increase in our DD&A expense for 2003 was primarily a result of a higher depletion rate combined with a 5% increase in production volumes for 2003. Our depletion rate increased as a result of:
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downward reserve revisions related to reservior performance of approximately 40 Bcfe;
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the addition of more costs to our depreciation base with fewer additions for reserves as our average finding and development cost increased from $1.75 per Mcfe during 2002 to $2.16 per Mcfe during 2003; and
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a 52% increase in our estimated future development costs at year end, the majority of which was due to the proved undeveloped classification of 68% of the reserves acquired from Transworld.
For 2004, based on our current reserve base, we expect our depreciation, depletion and amortization rate to average $2.00 per Mcfe.
General and Administrative Expenses, Net of Overhead Reimbursements and Capitalized General and Administrative.
The increase in aggregate general and administrative expense is due primarily to the expansion of our workforce that corresponds to the continued expansion of our operations. As our workforce expands, we have experienced an increase in salaries and related employee benefit expenses that include increases in our incentive compensation expense together with expense for stock compensation as we adopted the fair value expense provisions for stock options under SFAS No. 123, as amended, in January 2003. Our rent expense increased as we expanded our leased office space in downtown Houston to accommodate our growing workforce and opened an office in Denver to coordinate our expansion into the Rocky Mountains. Our legal, audit and accounting expenses increased as we implemented new corporate governance policies required by the Sarbanes Oxley Act of 2002 and engaged an outside firm to perform ongoing internal auditing functions.
The higher rate per Mcfe during 2003 reflects the increase in our aggregate general and administrative expenses combined with a proportional reduction in the amount of general and administrative expense capitalized during 2003. The mix of our capitalized expenses has changed as we incurred more costs during 2003 that were not directly related to our natural gas and oil exploration and development activities. We expect that as our company continues to grow and expand, our general and administrative expenses will increase. For 2004, we estimate that net general and administrative expenses will average between $0.19 and $0.20 per Mcfe.
Other Income and Expense, Interest and Taxes
Other Income and Expense. For 2003, Other Income and Expense includes two components: debt extinguishment expenses totaling $5.9 million ($3.9 million net of tax); and income of $21.6 million ($14.0 million net of tax) related to the recoupment of prior years’ severance tax expense. In July 2002, we applied for and received from the Railroad Commission of Texas a “high-cost/tight-gas formation” designation for a portion of our South Texas production. For qualifying wells, production is either exempt from tax or taxed at a reduced rate until certain capital costs are recovered. In 2002, we recognized as other income, $9.1 million ($5.9 million net of tax) related to the recoupment of prior years’ severance tax expense. For future periods, we do not expect to recognize additional refunds in excess of $1 million. The debt extinguishment expenses were incurred in June pursuant to the call and early redemption of our $100 million 8-5/8% notes and the issuance of $175 million of 7% senior subordinated notes. We paid a premium for early redemption of $4.3 million and incurred a non-cash charge of $1.6 million to write-off the balance of the unamortized costs associated with issuing the $100 million 8-5/8% senior subordinated notes.
Interest Expense, Net of Capitalized Interest.
During 2003, our average borrowings decreased and our average interest rate increased as we replaced our existing fixed debt of $100 million at 8-5/8% with new fixed debt of $175 million at 7% and used excess proceeds from the newly issued debt to repay outstanding borrowings under our revolving bank credit facility which bears interest at lower rates that averaged 3.4% during both 2003 and 2002. In addition, capitalized interest decreased during 2003. Our capitalized interest is a function of unevaluated properties and the decrease corresponds to the decrease in our average unevaluated property balance throughout 2003 prior to our October 2003 acquisition of producing properties from Transworld.
Income Tax Provision. During 2003, our current provision increased to $12.5 million as we depleted our net operating loss carryforwards and moved to a tax paying status where, as in prior years, all federal and state income taxes were deferred.
Operating and Financial Results for 2002 Compared to 2001
(1)
Average realized prices include the effect of hedges.
Operating Income
Significantly lower natural gas prices were the primary factor contributing to our 43% decrease in net income and our 44% decrease operating income in 2002 from 2001. Operating expenses increased by 21% due to a combination of the continued expansion of our operations, an increase in costs to maintain our existing production base and higher DD&A rates. Offsetting the effects of lower natural gas prices and higher operating expenses was an increase of 14% in production volume.
Commodity Prices
Our average wellhead price during 2002 was $3.16 per MMcfe, before the effects of our hedging program, down 24% over 2001. Natural gas and oil revenues, before effects of hedging, decreased by $46.3 million during 2002. The effect of the decrease in natural gas prices from 2001 levels accounted for $99.3 million of the decrease which was offset in part by an increase of $52 million attributable to the 14% increase in production volume and $1.0 million related to the increase in oil prices during 2002. For 2002, our natural gas and oil revenues were increased by a $16.4 million gain from our hedging program, which increased our average realized price for natural gas production by $0.32 Mcf during the period.
Production Volume
During 2002, our production increased 14%. The increase was primarily attributable to production added from properties acquired in South Texas since December 31, 2001 together with newly developed production generated from our subsequent development and workover programs initiated on these acquired properties during 2002. During 2002, we successfully drilled and completed a total of 84 new wells, consisting of 75 onshore wells and 9 offshore wells. Of the 75 wells drilled onshore, 54 were drilled in South Texas, of which 27 were drilled on our newly acquired acreage with the balance being drilled in our Charco Field.
Onshore, our daily production rates increased 32% from an average of 117 MMcfe/day during 2001 to an average of 155 MMcfe/day during 2002. Properties acquired from Conoco Inc. on December 31, 2001 accounted for 33 MMcfe/day of the increase for 2002 and properties acquired from Burlington Resources on May 30, 2002 accounted for 7 MMcfe/day of the increase for 2002. Production from our Charco Field in South Texas averaged 83 MMcfe/day during the current year and remained unchanged from 2001 rates. Production from all other onshore
areas (Arkoma, East Texas, West Virginia and South Louisiana) decreased 2 MMcfe/day or approximately 6% from an average of 34 MMcfe/day during 2001 to 32 MMcfe/day during 2002 primarily a result of a decrease in production in South Louisiana due principally to natural reservoir decline.
Offshore, our production decreased 2% from an average of 129 MMcfe/day during 2001 to an average of 126 MMcfe/day during 2002. During January 2002, we initiated production from our newly completed facilities at Vermilion 408. We
added new facilities and a series of new wells throughout 2002 at East Cameron 81, 82 and 83. During September and October 2002 we evacuated and shut-in offshore platforms and facilities due to Tropical Storms Faye and Isidore and Hurricane Lili. We estimate that we shut-in approximately 750 MMcfe or 2 MMcfe/day on an annualized basis. In October 2002, we acquired from KeySpan incremental working interests in 17 offshore wells that were initially developed under a joint exploration agreement with KeySpan (see Note 6 - Related Party Transactions - KeySpan Joint Venture) from 1999 through 2002. Overall, for the year 2002, increments in production growth resulting from our acquisition and our new exploration and development projects was offset by natural production declines in existing properties.
Effects of Hedging
As a result of hedging activities, we realized an average gas price of $3.32 per Mcf for 2002, which was $0.16 per Mcf or 105% greater than the average unhedged natural gas price of $3.16 that we otherwise would have received if hedges had not been in place during the year. For 2002, our hedging activities resulted in a gain of $16.4 million that is included in natural gas and oil revenues. For 2001, we realized an average gas price of $4.32 per Mcf, which was $0.14 per Mcf or 103% higher than the average unhedged natural gas price of $4.18. As a result, natural gas and oil revenues for 2001 include a realized gain of $12.9 million from hedging activities.
Operating Expenses
Lease Operating Expense. The increase in both lease operating expenses and lease operating expenses per unit is attributable to the continued expansion of our operations combined with an increase in expenses incurred during 2002. Onshore operations expanded with the acquisition of approximately 304 new producing wells in South Texas from the December 31, 2001 acquisition from Conoco Inc. and the May 30, 2002 acquisition from Burlington Resources. Excluding the incremental expenses relating to newly acquired properties, the increase in our onshore lease operating expenses is due primarily to increased ad valorem taxes and increased compression expenses. Ad valorem taxes increased as a result of the high natural gas prices experienced in 2001. Compression expenses increased during the second half of 2002 as we implemented a project in the Charco Field to boost production by adding compressors to streamline and lower gathering system pressure. Offshore, our lease operating expenses increased due to the addition of production facilities at Vermilion 408 and East Cameron 81, new processing fees attributable to oil production at Vermilion 408 where we have chosen to have a third party process our oil rather than constructing our own oil facilities, the implementation of compression projects to enhance production capabilities at several of our existing facilities and finally, an increase in well control insurance premiums during the current year.
Severance Tax. The decrease in severance tax expense is primarily due to $1.3 million recorded during the fourth quarter of 2002 related to refunds of expense incurred during the current year. In July 2002, we applied for and received from the Railroad Commission of Texas a “high-cost/tight-gas formation” designation for a portion of our South Texas production (see Note 9 - Commitments and Contingencies - Severance Tax Refund). In addition to the $1.3 million recorded as a reduction to current year severance tax expense, we recognized as “other non-operating income” $9.1 million for refunds relating to prior periods. Excluding the effect for the $1.3 million, severance tax would have been $10.8 million and $0.11 per Mcfe during 2002 compared to $11.0 million and $0.12 per Mcfe for 2001. Expense is comparable because wellhead prices were 25% lower during 2002 as compared to wellhead prices received during 2001; however, our onshore production increased by 32% during 2002 which accounts for the decrease in the adjusted severance tax on a per unit basis.
Depreciation, Depletion and Amortization. The increase in depreciation, depletion and amortization expense was a result of higher production volumes combined with a higher depletion rate. Our depletion rate increased in 2002 as we completed the evaluation of several properties that were classified as unproved at December 31, 2001. As evaluation is completed, the costs associated with these properties were reclassified into our amortization base. The higher depletion rate is a result of a combination of adding costs to the full cost pool with fewer new reserves being added from exploration and developmental drilling together with an overall increase in our finding and development costs. We believe that higher finding costs are
being experienced across the industry, particularly for companies our size whose primary area of exploration is the Outer Continental Shelf or the shallow waters of the Gulf of Mexico.
General and Administrative Expenses, Net of Overhead Reimbursements and Capitalized General and Administrative Expenses
Included in aggregate and net administrative expenses during 2001 were payments totaling $5.2 million, $0.06 per Mcfe in 2001, made in connection with the termination of former executive officers’ employment contracts. Excluding the one-time charges during 2001, both aggregate and net general and administrative expenses for 2002 are comparable to 2001. Per unit expense were unchanged as aggregate dollars increased by 8% year over year (excluding the effect of the one-time charge in 2001) as a result of the 14% increase in production for 2002. Aggregate expenses incurred increased as a result of the overall expansion of our business, our workforce and our office space. Payroll and employee benefits, rent and utilities and legal, accounting and consulting expenses all increased during 2002. Overhead reimbursements increased due to an increase in the number of producing properties operated that have third party working interests. On a percentage basis, we capitalized approximately the same percentage of general and administrative expenses during both 2002 and 2001.
Other Income and Expense, Interest and Taxes
Other Income and Expense. For 2002, we recorded other income of $9.1 million relating to refund of severance tax paid in prior periods and recorded pursuant to our receipt of a “high-cost/tight sand” designation for a portion of our South Texas production (see Note 9 - Commitments and Contingencies - Severance Tax Refund). For 2001, we incurred an additional $0.1 million in expenses relating to a strategic review initiated in the fourth quarter of 1999 and completed in the first quarter of 2000. In September 1999, together with KeySpan, our majority stockholder, we had announced our intention to review strategic alternatives for our company and KeySpan’s investment in our company. Consideration was given to a full range of strategic transactions including the possible sale of all or a portion of our assets. On February 25, 2000, we announced, together with KeySpan, that the review of strategic alternatives for Houston Exploration had been completed.
Interest Expense, Net of Capitalized Interest.
During 2002, aggregate interest increased slightly by 2% as our average outstanding borrowing increased and our average interest rate decreased. Net interest expense increased substantially during 2002 as we capitalized 34% less interest as a result of a decrease in exploratory drilling during 2002. Our capitalized interest is a function of exploratory drilling and unevaluated properties, both of which were at lower levels during 2002.
Income Tax Provision. The provision for income taxes decreased due to the 42% decrease in pre-tax income during 2002 as a result of the combination of a decrease in natural gas revenues and increases in both operating expenses and net interest expense.
Liquidity
Capital Requirements
Our principal requirements for capital are to fund our capital investment program and to satisfy our contractual obligations, primarily the repayment of long-term debt. Our capital investments include the following:
•
Costs of acquiring and maintaining our lease acreage position and our seismic resources;
•
Costs of drilling and completing new natural gas and oil wells;
•
Costs of installing new production infrastructure;
•
Costs of maintaining, repairing, and enhancing existing natural gas and oil wells;
•
Costs related to plugging and abandoning unproductive or uneconomic wells; and
•
Indirect costs related to our exploration activities, including payroll and other expense attributable to our exploration professional staff.
Our capital expenditure budget for 2004 has been set at an initial level of $315 million. We are the designated operator of approximately 85% of our wells. Operating allows us the ability to exercise control over the magnitude and timing of our capital program and provides us significant latitude to increase or decrease our spending in response to changes in price, operational developments or acquisition opportunities. To maintain flexibility of our capital program, we do not enter into material long-term obligations with any of our drilling contractors or service providers with respect to our operated properties. We do not include property acquisition costs in our capital budget because the size and timing of capital requirements for acquisitions are inherently unpredictable. As the year progresses, we will continue to evaluate our capital spending. Actual levels may vary due to a variety of factors, including drilling results, natural gas prices, economic conditions and future acquisitions.
During 2003, we invested $459.9 million in natural gas and oil properties, which includes $175.4 million for the acquisition of producing properties, and $1.9 million for other property and equipment. Investments in non-natural gas and oil properties includes the expansion of our Houston office space together with upgrades to our information technology systems and equipment and compares to $2.4 million spent in 2002. For 2003, we spent 59% offshore and 36% onshore with the balance of 5% on capitalized interest and general and administrative costs. We completed the drilling of a record 147 gross wells (116.3 net) of which 77% or 113 (89.3 net) were successful and 38 (27.0 net) were unsuccessful with an additional 16 wells (12.2 net) in progress at the end to the year. The table below provides a five-year historical analysis of our capital expenditures for natural gas and oil properties, total net proved reserve additions and our average “all-in” finding and development costs.
Future Commitments
In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. We do not have off-balance sheet debt or other such unrecorded obligations, and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we were obligated to make based on agreements in place at December 31, 2003. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2003, reflects accrued interest payable on our revolving bank credit facility of $12,200 which is payable over the next 90-day period. We expect to make annual interest payments of $12.5 million per year on our $175 million of 7% senior subordinated notes due June 2013. And, we anticipate making income tax payments of approximately $30 million to $40 million in 2004.
Capital Resources
We intend to fund our capital expenditure program and contractual commitments through cash flows from our operations and borrowings under our revolving bank credit facility. To the extent we make a significant acquisition, we may also access public markets for debt. Our primary sources of cash during 2003 were from funds generated from operations and net proceeds received from the concurrent early redemption of our $100 million 8-5/8% senior subordinated notes and the issuance of $175 million 7% senior subordinated notes in June. Cash was used to fund acquisitions, exploration and development expenditures and to reduce debt under our revolving bank credit facility. We made aggregate cash payments of $18.4 million and $14.8 million, respectively, for interest and taxes. The table below summarizes the sources of cash during 2003 and 2002.
At December 31, 2003, we had a working capital deficit of $36,000, long-term debt of $302 million and $172.6 million of borrowing capacity available under our revolving bank credit facility. The working capital deficit was due to a current liability of $36.5 million representing the fair value of our derivative instruments. The fair value of our derivative instruments will fluctuate with commodity prices, and as commodity prices increase, our liquidity exposure tends to increase as a result of open derivative instruments. Consequently, we are more likely to have the largest unfavorable mark-
to-market position in a high commodity price environment. Our working capital balance fluctuates as a result of the timing and amount of cash receipts and disbursements for operating activities and borrowings or repayments under our revolving bank credit facility. As a result, we often have a working capital deficit or a relatively small amount of positive working capital.
The 60% increase in net cash provided by operating activities during 2003 was primarily attributable to the increase in net income as a result of a 37% increase in average realized natural gas price, which includes the effects of hedging, together with a 5% increase in production volume, offset in part by a 24% increase in operating expenses. The increase in non-cash charges for 2003 was primarily a result of the increase in depreciation, depletion and amortization and deferred tax expense combined with current year charges for debt extinguishment, ineffectiveness of our derivative instruments and the cumulative effect of adopting SFAS 143 for asset retirement obligations. The increase in cash from operations was reduced in part by a net increase in operating assets and liabilities. Fluctuations in operating assets and liabilities are caused by the timing of cash receipts and disbursements.
During 2003, we took advantage of lower long-term interest rates to increase our available borrowing capacity under our revolving bank credit facility. In June, we called and redeemed our $100 million 8-5/8% notes due 2008 and issued $175 million 7% senior subordinated notes. The net proceeds from the $175 million notes were used to repay the outstanding principal and interest on the $100 million notes together with a premium of $4.3 million for early redemption. We used the remaining net proceeds to repay outstanding borrowings under our revolving bank credit facility and by the end of the third quarter of 2003, we had reduced our bank borrowings from $157 million at December 31, 2002 to zero at September 30, 2003. In the fourth quarter of 2003, we increased our bank borrowings to $127 million of which $115 million was used in October to finance a portion of the Transworld net purchase price of $147.5 million with the balance borrowed in December to fund a portion of the $27.9 million net purchase price for the EnerVest properties. For 2003, total long-term debt increased by a net $50 million as we increased fixed debt by $75 million and reduced our bank debt by $25 million compared to an increase of $8 million in total long-term borrowings during 2002. We received cash proceeds of $10.2 million for the issuance of common stock from the exercise of stock options compared to $9.7 million received in 2002. And, during the first quarter of 2003, we sold 3 million newly issued shares of our common stock in a public offering for net proceeds of $79.2 million, and simultaneously repurchased the same number of shares from KeySpan for $79.2 million.
Revolving Bank Credit Facility. We maintain a revolving bank credit facility with a syndicate of lenders led by Wachovia Bank, National Association, as issuing bank and administrative agent, The Bank of Nova Scotia and Fleet National Bank as co-syndication agents and BNP Paribas as documentation agent. The credit facility provides us with a commitment of $300 million which may be increased at our request and with prior approval from Wachovia to a maximum of $350 million by adding one or more lenders or by allowing one or more lenders to increase their commitments. The credit facility is subject to borrowing base limitations. Our current borrowing base is $300 million and is redetermined semi-annually, with the next redetermination scheduled for April 1, 2004. Up to $25 million of the borrowing base is available for the issuance of letters of credit. The credit facility matures July 15, 2005, is unsecured and with the exception of trade payables, ranks senior to our 7% senior subordinated notes. At December 31, 2003, we were in compliance with all covenants. See Note 2 - Long-term Debt and Notes for a summary of material covenants.
At December 31, 2003, we had borrowings under our revolving bank credit facility of $127 million and $0.4 million in outstanding letter of credit obligations. Subsequent to December 31, 2003, we repaid a net $37 million in outstanding borrowing under the facility, the primary source of these funds was proceeds received from the sale of our South Louisiana properties in early February 2004. At March 12, 2004, the date of this report, outstanding borrowings and letter of credit obligations under our revolving bank credit facility total $90.4 million.
In an effort to increase our borrowing capacity for property acquisitions, we are in the process of amending our current revolving bank credit facility to increase the borrowing capacity from $300 million to $400 million. The lenders and the primary terms and conditions of the new facility are expected to be consistent with the existing facility. The commitment is expected to increase to $400 million with the capability to increase the commitment to $450 million and we expect to have $40 million of the borrowing base available for letters of credit. The new facility is expected to become effective on April 1, 2004. Our initial borrowing base is expected to be $375 million and is scheduled for redetermination October 1, 2004. Outstanding borrowings are expected to continue to be unsecured and with the exception of trade payables, the new facility is expected to rank senior to our $175 million 7% subordinated notes. The new facility is expected to mature on April 1, 2008.
Senior Subordinated Notes. On June 10, 2003, we issued $175 million 7% senior subordinated notes due June 15, 2013. The notes bear interest at a rate of 7% per annum with interest payable semi-annually on June 15 and December 15, beginning December 15, 2003. We may redeem the notes at our option, in whole or in part, at any time on or after June 15, 2008 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 3.5% in 2008 to 0% in 2011 and thereafter. In addition, at any time prior to June 15, 2006, we may redeem up to a maximum of 35% of the aggregate principal amount with the net proceeds of one or more equity
offerings at a price equal to 107% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any. The notes are general unsecured obligations and rank subordinate in right of payment to all existing and future senior debt, including the revolving bank credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness.
The $175 million 7% senior subordinated notes were issued in conjunction with the call and early redemption of our $100 million 8-5/8% senior subordinated notes due January 1, 2008. The redemption and payment of the call premium on the $100 million notes was funded with a portion of the proceeds received from the issuance of the $175 million 7% senior subordinated notes. Pursuant to the early redemption of the $100 million notes, we incurred debt extinguishment expenses totaling $5.9 million ($3.9 million net of tax) consisting of the call premium of $4.3 million together with a non-cash charge of $1.6 million for the write-off of the balance of the unamortized issue costs of the 8-5/8% notes. The debt extinguishment expenses of $5.9 million are included in the line item “Other (Income) Expense” on the Statement of Operations for the year ended December 31, 2003.
Access to Capital Markets. We currently have on file with the SEC a shelf registration statement covering the sale, from time to time, of our common stock, preferred stock, depositary shares and debt securities, or a combination of any of these securities. The shelf was filed in May 1999 and provided for an initial aggregate public offering price of up to $250 million. In February 2003, we sold 3,000,000 shares of our common stock to the public under the shelf registration statement and used the proceeds to concurrently repurchase three million shares of our common stock from KeySpan. Following that offering, we had approximately $169.8 million of capacity remaining under the shelf. In March 2004, we plan to terminate our existing shelf registration statement and replace it with a new shelf registration statement to be filed with the SEC covering the offering, from time to time, of up to $600 million of our common stock, preferred stock, depositary shares and debt securities, or a combination of any of these securities.
We believe that operating cash flow and our credit facility will be adequate to meet our capital and operating requirements for 2004. We continuously monitor our working capital and debt position as well as coordinate our capital expenditure program with expected cash flows and projected debt repayment schedules. Although we have no specific budget for property acquisitions, should attractive opportunities arise, we believe we could finance the additional capital expenditures with cash on hand, operating cash flow, additional borrowing under our revolving bank credit facility, issuances of additional equity or debt securities or development with industry partners.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Natural Gas and Oil Hedging
We utilize derivative commodity instruments to hedge future sales prices on a portion of our natural gas and oil production to achieve a more predictable cash flow, as well as to reduce our exposure to adverse price fluctuations of natural gas. Our derivatives are not held for trading purposes. While the use of hedging arrangements limits the downside risk of adverse price movements, it also limits increases in future revenues as a result of favorable price movements. The use of hedging transactions also involves the risk that the counterparties are unable to meet the financial terms of such transactions. Hedging instruments that we use are swaps, collars and options, which we generally place with major investment grade financial institutions that we believe are minimal credit risks. We believe that our credit risk related to our natural gas futures and swap contracts is no greater than the risk associated with the primary contracts and that the elimination of price risk reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk; however, as a result of our hedging activities we may be exposed to greater credit risk in the future.
Our hedges are cash flow hedges and qualify for hedge accounting under SFAS No.133 and, accordingly, we carry the fair market value of our derivative instruments on the balance sheet as either an asset or liability and defer unrealized gains or losses in accumulated other comprehensive income. Gains and losses are reclassified from accumulated other comprehensive income to the income statement as a component of natural gas and oil revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to other income or expense. In 2003, we recognized $1.9 million of ineffectiveness. The ineffectiveness was a result of changes during the period in the price differentials between the index price of the derivative contract, which uses a NYMEX index, and the index price for the point of sale for the cash flow that is being hedged, the majority of which is the Houston Ship Channel index. Ineffectiveness was not material prior to 2003.
Changes in Fair Value of Derivative Instruments
The following table summarizes the change in the fair value of our derivative instruments for each of the twelve-month periods from January 1 to December 31, 2003 and 2002 and provides the fair value at the end of each period.
Derivatives in Place as of the Date of Our Report
As of March 12, 2004, the date of this report, the following table summarizes, on a monthly basis, our natural gas hedges in place for 2004 and 2005. For each month of 2004, we have hedged approximately 70% of our estimated production or a total of 240,000 million British thermal units per day or MMBtu/day. For the three months January through March 2004, our floor price will average $4.472/MMBtu on 240,000 MMBtu/day and our ceiling price will average $5.021/MMBtu on 140,000 MMBtu/day, with no ceiling price on the remaining 100,000 MMBtu/day. For the remaining nine months of 2004, our floor price will average $4.264/MMBtu on 240,000 MMBtu/day and our ceiling price will average $5.845/MMBtu on 240,000 MMBtu/day. For each calendar month of 2005, we have 150,000 MMBtu/day hedged with an effective floor price of $4.589 and an effective ceiling price of $5.255. All amounts in the table below are in thousands, except for prices.
For natural gas, transactions are settled based upon the New York Mercantile Exchange or NYMEX price on the final trading day of the month. For oil, our swaps are settled against the average NYMEX price of oil for the calendar month rather than the last day of the month. In order to determine fair market value of our derivative instruments, we obtain mark-to-market quotes from external counterparties.
With respect to any particular swap transaction, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price for the transaction, and we are required to make payment to the counterparty if the settlement price for any settlement period is greater than the swap price for the transaction. For any particular collar transaction, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for the transaction, and we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for the transaction. We are not required to make or receive any payment in connection with a collar transaction if the settlement price is between the floor and the ceiling. For option contracts, we have the option, but not the obligation, to buy contracts at the strike price up to the day before the last trading day for that NYMEX contract.
Item 8.
Item 8. Financial Statements
For financial statements required by Item 8, see Item 15 in Part IV of this Annual Report.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports we file under the Securities Exchange Act of 1934, as amended (“Exchange Act”) is communicated, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. We carried out an evaluation under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-14 of the Exchange Act), as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that, as of December 31, 2003, our disclosure controls and procedures are functioning effectively as designed. There have been no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter prior to the end of the period covered by this report that have materially affected, or are reasonable likely to materially affect, our internal controls over financial reporting.
Part III.
Item 10.
Item 10. Directors and Executive Officers of Houston Exploration
The information required by Item 10 that relates to our directors and executive officers is incorporated by reference from the information appearing under the captions “Election of Directors,” “Executive Officers,” “Board Committees - Audit Committee,” “Board Committees - Nominating and Corporate Governance Committee” and “Compliance with Section 16(a)” in our definitive proxy statement that is to be filed with the SEC pursuant to the Exchange Act within 120 days of the end of our fiscal year on December 31, 2003.
Item 11.
Item 11. Executive Compensation
The information required by Item 11 that relates to compensation of our principal executive officers and our directors is incorporated by reference from the information appearing under the captions “Executive Compensation” and “Election of Directors - Director’s Meetings and Compensation” in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31, 2003. In addition and in accordance with Item 402(a)(8) of Regulation S-K, the information contained in our definitive proxy statement under the subheading “Report of the Compensation Committee of the Board of Directors” and “Performance Graph” shall not be deemed to be filed as part of, or incorporated by reference into, this Annual Report. For information concerning our code of ethics, see “Item 1. and 2. Business and Properties - Available Information.”
Item 12.
Item 12. Security Ownership of Beneficial Owners and Management
The information required by Item 12 that relates to the ownership of securities by management and others is incorporated by reference from the information appearing under the caption “Securities Authorized for Issuance Under Equity Compensation Plans” and “Security Ownership of Certain Beneficial Owners and Management” in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31, 2003.
Item 13.
Item 13. Certain Relationships and Related Transactions
The information required by Item 13 that relates to business relationships and transactions with our management and other related parties is incorporated by reference from the information appearing under the captions “Certain Relationships and Related Party Transactions” and “Compensation Committee Interlocks and Insider Participation” in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31, 2003.
Item 14.
Item 14. Principal Accounting Fees and Services
The information required by Item 14 that relates to services provided by our Independent Public Accountants and the fees incurred for services provided during 2003 and 2002 is incorporated by reference from the information appearing under the captions “Fees Billed by Independent Public Accountants” in our definitive proxy statement that is to be filed with the SEC within 120 days of the end of our fiscal year on December 31, 2003.
Part IV.
Item 15.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Documents Filed as a Part of this Report
1. Financial Statements:
All other schedules are omitted because they are not applicable, not required, or because the required information is included in the financial statements or related notes.
2. Exhibits:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
POWER OF ATTORNEY
Each person whose signature appears below hereby constitutes and appoints John H. Karnes and James F. Westmoreland, and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report of Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
Glossary of Oil and Gas Terms
The definitions set forth below apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.
Bbl/d. One barrel per day.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Developed acreage. The number of acres allocated or assignable to producing wells or wells capable of production.
Developed well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
Farm-in or farm-out. An agreement where the owner of a working interest in an natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Intangible Drilling and Development Costs. Expenditures made by an operator for wages, fuel, repairs, hauling, supplies, surveying, geological works etc., incident to and necessary for the preparing for and drilling of wells and the construction of production facilities and pipelines.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per day.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcfe/d. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids per day.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMbtu. One million Btus.
MMMbtu. One billion Btus.
G-1
MMcf. One million cubic feet.
MMcf/d. One million cubic feet per day.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
Oil. Crude oil and condensate.
Present value. When used with respect to natural gas and oil reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.
Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In addition, please refer to the definitions of proved oil and gas reserves as provided in Rule 4-10(a)(2)(3)(4). The rule is available at the SEC website, http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.
Proved undeveloped location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required from recompletion.
Recompletion. The completion for production of an existing well bore in another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest. An interest in a natural gas and oil property entitling the owner to a share of natural gas or oil production free of costs of production.
Tangible Drilling and Development Costs. Cost of physical lease and well equipment and structures. The costs of assets that themselves have a salvage value.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether the acreage contains proved reserves.
Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover. Operations on a producing well to restore or increase production.
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INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Stockholders of
The Houston Exploration Company
We have audited the accompanying consolidated balance sheets of The Houston Exploration Company (a Delaware corporation and an indirect 55% owned subsidiary of KeySpan Corporation) and subsidiary (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidences supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” and SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure,” on January 1, 2003.
DELOITTE & TOUCHE LLP
Houston, Texas
February 17, 2004
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
(in thousands, except share data)
(continued on next page)
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
(continued)
The accompanying notes are an integral part of these consolidated financial statements.
THE HOUSTON EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - Summary of Organization and Significant Accounting Policies
Our Business
We are an independent natural gas and oil company engaged in the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America. Natural gas is our primary focus. Our core areas of operations are South Texas, offshore in the shallow waters of the Gulf of Mexico, the Arkoma Basin of Oklahoma and Arkansas and the Appalachian Basin of West Virginia. During 2003, we began operations in the Rocky Mountain Region, with an initial focus in the Uinta Basin of northeastern Utah.
At December 31, 2003, our net proved reserves were 755 billion cubic feet equivalent or Bcfe, with a present value, discounted at 10% per annum, of cash flows before income taxes of $1.9 billion. Our reserves are fully engineered on an annual basis by independent petroleum engineers. Approximately 94% of our net proved reserves at December 31, 2003 were natural gas, approximately 68% of which were classified as proved developed. We operate approximately 85% of our producing wells.
We were founded in December 1985 as a Delaware corporation and began exploring for natural gas and oil on behalf of KeySpan Corporation. KeySpan, a member of the Standard & Poor’s 500 Index, is a diversified energy provider whose principal natural gas distribution and electric generation operations are located in the Northeastern United States. In September 1996 we completed our initial public offering and sold approximately 31% of our shares to the public. As of December 31, 2003, THEC Holdings Corp., an indirect wholly owned subsidiary of KeySpan, owned approximately 55% of the outstanding shares of our common stock.
Principles of Consolidation
The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiary, Seneca Upshur Petroleum Company, which is in the exploration and production business in West Virginia. All significant inter-company balances and transactions have been eliminated.
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principals generally accepted in the United States of America 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 dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Our most significant financial estimates are based on remaining proved natural gas and oil reserves. Estimates of proved reserves are key components of our depletion rate for natural gas and oil properties and our full cost ceiling test limitation. See Note 12 - Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited). Because there are numerous uncertainties inherent in the estimation process, actual results could differ materially from these estimates.
Reclassifications
Certain reclassifications have been made to prior year’s reported amounts in order to conform with current year presentations.
Business Segment Information
The Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 131, “Disclosures about Segments of an Enterprise and Related Information” establishes standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses. Separate financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.
Segment reporting is not applicable for us as each of our operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in SFAS 131. All of our operations involve the exploration, development and production of natural gas and oil and all of our operations are located in the United States. We have a single, company-wide management team that administers all properties as a whole rather than as discrete operating segments. We track only
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basic operational data by area. We do not maintain separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, we freely allocate capital resources on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas or segments.
Revenue Recognition and Gas Imbalances
We use the entitlements method of accounting for the recognition of natural gas and oil revenues. Under this method of accounting, income is recorded based on our net revenue interest in production or nominated deliveries. We incur production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over-and under deliveries or by cash settlement, as required by applicable contracts. Production imbalances are marked-to-market at the end of each month using market prices as of the end of the period. Our production imbalances represented a net asset of $1.8 million and $33,000 at December 31, 2003 and 2002, respectively. The increase in our imbalance position at December 31, 2003 was due primarily to imbalances associated with Gulf of Mexico properties acquired in October 2003 from Transworld Exploration and Production Inc. See Note 10 - Acquisitions - Transworld.
Net Income Per Share
Basic earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. No dilution for any potentially dilutive securities is included. Fully diluted earnings per share assumes the conversion of all potentially dilutive securities and is calculated by dividing net income by the sum of the weighted average number of shares of common stock outstanding plus all potentially dilutive securities.
For the years ended December 31, 2003, 2002 and 2001, the calculation of shares outstanding for fully diluted earnings per share does not include the effect of outstanding stock options to purchase 1,865,313, 1,880,029 and 1,182,843 shares respectively, because the exercise price of these shares was greater than the average market price for the year, which would have an antidulitive effect on earnings per share.
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Comprehensive Income
The table below summarizes our Comprehensive Income for the years ended December 31, 2003, 2002 and 2001, respectively. Amounts are in thousands.
Natural Gas and Oil Properties
Full Cost Accounting. We use the full cost method to account for our natural gas and oil properties. Under full cost accounting, all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are capitalized into a “full cost pool.” Capitalized costs include costs of all unproved properties, internal costs directly related to our natural gas and oil activities and capitalized interest. We amortize these costs using a unit-of-production method. We compute the provision for depreciation, depletion and amortization quarterly by multiplying production for the quarter by a depletion rate. The depletion rate is determined by dividing our total unamortized cost base by net equivalent proved reserves at the beginning of the quarter. Our total unamortized cost base is the sum of our:
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full cost pool; plus,
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estimates for future development costs; less,
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unevaluated properties and their related costs; less,
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estimates for salvage.
Costs associated with unevaluated properties are excluded from the amortization base until we have made a determination as the existence of proved reserves. We review our unevaluated properties at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and thereby subject to amortization. Sales of natural gas and oil properties are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a writedown or impairment of the full cost pool is required. A writedown of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a writedown is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. We use derivative financial instruments that qualify for cash flow hedge accounting under SFAS 133 to hedge against the volatility of natural gas prices, and in accordance with Securities and Exchange Commission guidelines, we include estimated future cash flows from our hedging program in our ceiling test calculation.
In calculating our ceiling test at December 31, 2003 and 2002, we estimated, using a wellhead price of $5.79 per Mcf and $4.35 per Mcf, respectively, that we had a full cost ceiling “cushion” at each of the respective balance sheet dates, whereby the carrying value of our full cost pool was less that the ceiling limitation by $440.7 million (after tax) for 2003 and by $279.4 million (after tax) for 2002. No writedown was required.
In calculating the ceiling test at December 31, 2001, we estimated, using a wellhead price of $2.38 per Mcf, that our capitalized costs exceeded the ceiling limitation by $6.2 million ($4.0 million after tax). As a result, we reduced or “wrote down” the carrying value of our full cost pool and incurred a charge to earnings of $6.2 million ($4.0 million, after tax).
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Natural gas prices continue to be volatile and the risk that we will be required to writedown our full cost pool increases when natural gas prices are depressed or if we have significant downward revisions in our estimated proved reserves.
Unevaluated Properties. The costs associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in-progress and wells pending determination together with interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base with the costs of drilling the related well or upon expiration of a lease. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with successful wells in-progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Of the $134.5 million of unevaluated property costs at December 31, 2003 that have been excluded from the amortization base, $78.9 million were incurred during 2003, $18.0 million were incurred in 2002, $21.4 million were incurred during 2001 and $ 16.2 were incurred prior to 2001. Of the $96.2 million of unevaluated property costs at December 31, 2002 that have been excluded from the amortization base, $38.8 million were incurred during 2002, $28.2 million were incurred in 2001, $6.9 million were incurred in 2000 and $22.3 million were incurred prior to 2000. We estimate these costs will be evaluated within a four-year period.
Classification of Intangible Leasehold Costs
SFAS 141, “Business Combinations” and SFAS 142, “Goodwill and Intangible Assets,” became effective on July 1, 2001 and January 1, 2002, respectively. These new standards emphasize a more precise evaluation of assets and their balance sheet classification as either tangible or intangible assets. We understand that the issue is under evaluation as to whether provisions of SFAS 141 and SFAS 142 may call for mineral rights held under lease or other contractual arrangements together with cash costs for the acquisition of natural gas and oil leasehold interests to be classified in the balance sheet as intangible assets. If these types of leasehold costs (both proved and unevaluated) are determined to be intangible assets, they would be classified separately from natural gas and oil properties as intangible assets on our balance sheets. This issue relates only to balance sheet classification and presentation and we do not believe it will not have an effect on cash flows or results of operations. At December 31, 2003, if we applied the interpretation currently under discussion, undeveloped leasehold costs of $117.1 million and developed leasehold costs of $221.3 million, net of accumulated amortization, would be reclassified from tangibles to intangibles, representing costs incurred since June 30, 2001, the effective date of SFAS 141. At December 31, 2002, we had undeveloped leasehold costs of $49.5 million and developed leasehold costs of $111.5 million, net of accumulated amortization that would be reclassified from tangibles to intangibles. Consistent with current industry practice, we will continue to classify our natural gas and oil leasehold costs as tangible natural gas and oil properties until the Emerging Issues Task Force issues further guidance.
Asset Retirement Obligations
On January 1, 2003, we adopted SFAS 143, “Accounting for Asset Retirement Obligations,” which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. For us, asset retirement obligations represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. SFAS 143 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized and an adjustment is made to the full cost pool. Under our previous accounting method, we included estimated future costs of abandonment and dismantlement in our full cost amortization base and amortized these costs as a component of our depletion expense.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pursuant to the January 1, 2003 adoption of SFAS 143 we:
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recognized a charge to income during the first quarter of 2003 of $2.8 million, net of tax, for the cumulative effect of the change in accounting principle;
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increased our total liabilities by $57.2 million to record the asset retirement obligations (“ARO”);
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increased our assets by $42.5 million to add the asset retirement costs to the carrying amount of our natural gas and oil properties; and
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reduced our accumulated depreciation, depletion and amortization by $10.4 million for the amount of expense previously recognized.
Adopting SFAS 143 had no impact on our reported cash flows. The following table describes on a pro forma basis our asset retirement liability as if SFAS 143 had been adopted on January 1, 2002. The ARO liability in the table below includes amounts classified as both current and long-term at December 31st.
The following table describes the pro forma effect on net income and earnings per share for the years ended December 31, 2002 and 2001 as if SFAS 143 had been adopted on January 1, 2001.
Other Property and Equipment
Other property and equipment includes the costs of various gathering facilities that are depreciated using the unit-of-production basis utilizing estimated proved reserves accessible to the facilities. Also included in other property and equipment are costs of office furniture, fixtures and computer equipment and other office equipment which are recorded at cost and depreciated using the straight-line method over estimated useful lives ranging between two to five years.
Cash and Cash Equivalents
We consider all highly liquid short-term investments with original maturities of 90 days or less to be cash equivalents.
Income Taxes
We determine deferred taxes based on the estimated future tax effect of differences between the financial statement and tax basis of assets and liabilities given the provisions of enacted tax laws as of the balance sheet dates. These differences relate primarily to
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intangible drilling and development costs associated with natural gas and oil properties, which are capitalized and amortized for financial reporting purposes and expensed as incurred for tax reporting purposes and
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provisions for depreciation and amortization for financial reporting purposes that differ from those used for income tax reporting purposes.
Inventories
Inventories consist primarily of tubular goods used in our operations and are stated at the lower of the specific cost of each inventory item or market value.
General and Administrative Costs and Expenses
Under the full cost method of accounting, we capitalize a portion of our general and administrative expenses that are directly identified with our acquisition, exploration and development activities. These capitalized costs include salaries, employee benefits, costs of consulting services and other specifically identifiable costs and do not include costs related to production operations, general corporate overhead or similar activities. We capitalized general and administrative costs directly related to our acquisition, exploration and development activities, during 2003, 2002 and 2001, of $12.9 million, $13.2 million and $12.8 million, respectively. We receive reimbursement for administrative and overhead expenses incurred on behalf of other working interest owners on properties we operate. These reimbursements totaling $1.6 million, $1.8 million and $1.2 million for the years ended December 31, 2002, 2001 and 2000, respectively, were allocated as reductions to general and administrative expenses incurred. Generally, we do not receive any excess of reimbursements or fees over the costs incurred; however, if we did, we would credit the excess to the full cost pool to be recognized through lower cost amortization as production occurs.
Capitalization of Interest
We capitalize interest related to our unevaluated natural gas and oil properties and certain properties under development that are not currently being amortized. For the years ended December 31, 2003, 2002 and 2001, we capitalized interest costs of $7.3 million, $8.0 million and $12.0 million, respectively.
Financial Instruments
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. On the balance sheet, we report cash and cash equivalents, accounts receivable and accounts payable at cost or carrying value, which approximates fair value due to the short maturity of these instruments. See Note 2 - Long-term Debt and Notes for fair value of our debt. Pursuant to our adoption of SFAS 133 on January 1, 2001, our derivative financial instruments are reported on the balance sheet at fair market value.
Derivative Instruments and Hedging Activities
To reduce our exposure to adverse price fluctuations, we generally hedge between 70 and 80 percent of our estimated future production volume. Our hedging policy does not permit us to hold derivative instruments for trading purposes. In our hedging program, we utilize a variety of derivative instruments, including swaps, collars and options. We generally place contracts with major financial institutions and other credit worthy counterparties. Although our hedging program protects a portion of our cash flows from downward price movements, certain hedging strategies, specifically the use of swaps and collars, may also limit our ability to realize the benefit of future price increases.
Our hedges are designated cash flow hedges and qualify for hedge accounting under SFAS 133, as amended, “Accounting for Derivative Instruments and Hedging Activities” and, accordingly, we carry the fair market value of our derivative instruments on the balance sheet as either an asset or liability and defer unrealized gains or losses in accumulated other comprehensive income. Gains and losses are reclassified from accumulated other comprehensive income to the income statement as a component of natural gas and oil revenues in the period the hedged production occurs. If any ineffectiveness occurs, amounts are recorded directly to the income statement. For 2003, our earnings include an unrealized loss of $1.9 million ($1.3 million net of tax) representing the ineffective portion of our derivative instruments that were not eligible for deferral. The ineffectiveness was a result of changes during the period in the price differentials between the index price of the derivative contract, which uses a New York Mercantile Exchange (“NYMEX”) index, and index price for the point of sale for the cash flow that is being hedged, the majority of which is the Houston Ship Channel index. See Note 7 - Derivative Instruments, for a detailed listing of our derivative contracts and the fair market value of those contracts as of December 31, 2003 and 2002.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Concentration of Credit Risk
Substantially all of our accounts receivable result from natural gas and oil sales or joint interest billings to third parties in the oil and gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, we have not experienced credit losses on these receivables. Based on the current demand for natural gas and oil, we do not expect that termination of sales to any of our current purchasers would have a material adverse effect on our ability to find replacement purchasers and to sell our production at favorable market prices.
Further, our derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We believe that our credit risk related to the natural gas futures and swap contracts is no greater than the risk associated with the primary contracts and that the elimination of price risk reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk; but, as a result of our hedging activities we may be exposed to greater credit risk in the future.
Accounting for Stock Options
On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123, “Accounting for Stock Based Compensation,” as amended by SFAS 148, “Accounting for Stock - Based Compensation - Transition and Disclosure” using the “prospective method” as defined by the SFAS 148. As a result, we now record as compensation expense the fair value of all stock options issued subsequent to January 1, 2003. No expense has been or will be recorded for grants made in previous years. For the year ended December 31, 2003, we incurred $0.9 million in compensation expense related to stock options issued during the year. Prior to 2003, we accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options was measured as the excess, if any, of the fair value of common stock at the date of the grant over the amount the employee must pay to acquire the common stock. If the exercise price of a stock option is equal to the fair market value at the time of grant, no compensation expense is incurred. As a result, we incurred no compensation expense during 2002 and 2001 relating to stock options. See Note 4 - Employee Benefit and Stock Plans - Fair Value of Employee Stock-Based Compensation for a pro-forma disclosure of net income had stock options been accounted for based upon the fair value provisions of the SFAS 123.
New Accounting Pronouncements
In November 2002, FASB issued Financial Interpretation (“FIN”) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN 45 requires certain guarantees to be recorded at fair value, which is different from the previous practice of recording a liability only when a loss is probable and reasonably estimable, as those terms are defined in SFAS 5, “Accounting for Contingencies.” FIN 45 has a dual effective date. The initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. The disclosure requirements in the interpretation are effective for financial statements for interim or annual periods ending after December 15, 2002. As of our December 31, 2003 and December 31, 2002 balance sheet dates, we did not have any guarantees of indebtedness of others and as a result, our adoption of FIN 45 did not have an effect on our financial statements.
In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities - An Interpretation of Accounting Research Bulletin 51.” FIN 46 addresses consolidation by business enterprises of variable interest entities (VIEs) and the primary objective is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an entity to consolidate a VIE if the entity has a variable interest (or combination of variable interests) that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur or both. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. However, on October 8, 2003, the FASB decided to grant a broader deferral of the implementation of FIN 46. Pursuant to this deferral, public companies must complete their evaluations of VIEs that existed prior to February 1, 2003, and the consolidation of those for which they are the primary beneficiary for financial statements issued for the first period ending after December 15, 2003. For calendar year companies, consolidation of previously existing VIEs will be required in their December 31, 2003 financial statements. We have completed our
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evaluation of FIN 46 and because we do not believe that we have any VIEs there is no impact to our consolidated financial statements.
NOTE 2 - Long-Term Debt and Notes
The carrying amount of borrowings outstanding under the revolving bank credit facility approximates fair value as the interest rates are tied to current market rates. At December 31, 2003, the quoted market value of our $175 million of 7% senior subordinated notes was 103% of the $175 million carrying value or $180.3 million. At December 31, 2002, the quoted market value of our $100 million of 8-5/8% senior subordinated notes was 103.8% of the $100 million carrying value or $103.8 million. At December 31, 2003, principle payments due over the next five-year period and thereafter are as follows.
Revolving Bank Credit Facility
We maintain a revolving bank credit facility with a syndicate of lenders led by Wachovia Bank, National Association, as issuing bank and administrative agent, The Bank of Nova Scotia and Fleet National Bank as co-syndication agents and BNP Paribas as documentation agent. The credit facility provides us with a commitment of $300 million which may be increased at our request and with prior approval from Wachovia to a maximum of $350 million by adding one or more lenders or by allowing one or more lenders to increase their commitments. The credit facility is subject to borrowing base limitations. Our current borrowing base is $300 million and is redetermined semi-annually, with the next redetermination scheduled for April 1, 2004. Up to $25 million of the borrowing base is available for the issuance of letters of credit. The credit facility matures July 15, 2005, is unsecured and with the exception of trade payables, ranks senior to our 7% senior subordinated notes. At December 31, 2003, we had $127 million in outstanding borrowings under the credit facility and $0.4 million in outstanding letter of credit obligations.
Interest is payable on borrowings under our revolving bank credit facility, as follows:
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on base rate loans, at a fluctuating rate, or base rate, equal to the sum of (a) the greater of the Federal funds rate plus 0.5% or Wachovia’s prime rate plus (b) a variable margin between 0% and 0.50%, depending on the amount of borrowings outstanding under the credit facility, or
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on fixed rate loans, a fixed rate equal to the sum of (a) a quoted LIBOR rate divided by one minus the average maximum rate during the interest period set for certain reserves of member banks of the Federal Reserve System in Dallas, Texas plus (b) a variable margin between 1.25% and 2.00%, depending on the amount of borrowings outstanding under the credit facility.
Interest is payable on base rate loans on the last day of each calendar quarter. Interest on fixed rate loans is generally payable at maturity or at least every 90 days if the term of the loan exceeds three months. In addition to interest, we must pay a quarterly commitment fee of between 0.30% and 0.50% per annum on the unused portion of the borrowing base.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Our revolving bank credit facility contains customary negative covenants that place restrictions and limits on, among other things, the incurrence of debt, guaranties, liens, leases and certain investments. The credit facility also restricts and limits our ability to pay cash dividends, to purchase or redeem our stock and to sell or encumber our assets. Financial covenants require us to, among other things:
At December 31, 2003 and 2002, we were in compliance with all covenants.
Senior Subordinated Notes
7% Senior Subordinated Notes due June 15, 2013. On June 10, 2003, we issued $175 million of 7% senior subordinated notes due June 15, 2013. The notes bear interest at a rate of 7% per annum with interest payable semi-annually on June 15 and December 15, beginning December 15, 2003. We may redeem the notes at our option, in whole or in part, at any time on or after June 15, 2008 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium which decreases yearly from 3.5% in 2008 to 0% in 2011 and thereafter. In addition, at any time prior to June 15, 2006, we may redeem up to a maximum of 35% of the aggregate principal amount with the net proceeds of one or more equity offerings at a price equal to 107% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any. The notes are general unsecured obligations and rank subordinate in right of payment to all existing and future senior debt, including the revolving bank credit facility, and will rank senior or equal in right of payment to all existing and future subordinated indebtedness.
The indenture governing the notes contains covenants that, among other things, restrict or limit:
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incurrence of additional indebtedness and issuance of preferred stock;
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repayment of certain other indebtedness;
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payment of dividends or certain other distributions;
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investments and repurchases of equity;
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use of the proceeds of assets sales;
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transactions with affiliates;
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creation, incurrence or assumption of liens;
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merger or consolidation and sales or other dispositions of all or substantially all of our assets;
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entering into agreements that restrict the ability of our subsidiary to make certain distributions or payments; or
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guarantees by our subsidiary of certain indebtedness.
In addition, upon the occurrence of a change of control, we will be required to offer to purchase the notes at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest and liquidated damages, if any.
A “change of control” is:
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the direct or indirect acquisition by any person, other than KeySpan or its affiliates, of beneficial ownership of 35% or more of total voting power as long as KeySpan and its affiliates own less than the acquiring person;
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the sale, lease, transfer, conveyance or other disposition, other than by way of merger or consolidation, in one or a series of related transactions, of all or substantially all of our assets to a third party other than KeySpan or its affiliates;
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the adoption of a plan relating to our liquidation or dissolution; or
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if, during any period of two consecutive years, individuals who at the beginning of the period constituted our board of directors, including any new directors who were approved by a majority vote of directors then in office who were either directors at the beginning of the two-year period or who were previously so approved, cease for any reason to constitute a majority of the members then in office.
We received $170.3 million in net proceeds from the issuance of the $175 million of 7% senior subordinated notes. A portion of the net proceeds was used to repay the aggregate principal of $100 million on the 8-5/8% senior subordinated notes
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together with a premium of $4.3 million for early redemption. The remaining portion of the net proceeds was used to repay $60 million in outstanding borrowings on our revolving bank credit facility with the balance of approximately $6.1 million being applied to working capital, a portion of which was utilized in July 2003 to fund the payment of $4.6 million in accrued interest due on the $100 million 8 5/8% notes.
8 5/8% Senior Subordinated Notes due January 1, 2008. On July 11, 2003, we redeemed our $100 million 8 5/8% senior subordinated notes due January 1, 2008. The $100 million 8 5/8% senior subordinated notes were issued on March 2, 1998. The notes bore interest at a rate of 8 5/8% per annum with interest payable semi-annually on January 1 and July 1. The $100 million 8 5/8% notes were redeemable, at our option, in whole or in part, at any time on or after January 1, 2003 at a price equal to 100% of the principal amount plus accrued and unpaid interest, if any, plus a specified premium of 4.313%. The redemption and payment of the call premium were funded with a portion of the proceeds received from our June 10, 2003 issuance of the $175 million 7% senior subordinated notes due June 15, 2013. Upon closing of the $175 million 7% senior subordinated notes on June 10, 2003, the $100 million 8 5/8% notes were called. During the second quarter of 2003 and pursuant to the early redemption of the $100 million notes, we incurred debt extinguishment expenses totaling $5.9 million ($3.9 million net of tax) consisting of the call premium of $4.3 million together with a non-cash charge of $1.6 million for the write-off of the balance of the unamortized issue costs of the 8 5/8% notes. The debt extinguishment expenses of $5.9 million are included in the line item “Other (Income) Expense” on the Statement of Operations for the year ended December 31, 2003.
NOTE 3 - Stockholders’ Equity
Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of 3,000,000 Shares from KeySpan
In connection with our initial public offering in September 1996, we entered into a registration rights agreement with KeySpan pursuant to which we are obligated, at KeySpan’s election, to facilitate KeySpan’s sale of its shares of Houston Exploration stock by registering the shares under the Securities Act of 1933 and assisting in KeySpan’s selling efforts. During February of 2003, KeySpan notified us of its desire to sell 3,000,000 shares of their Houston Exploration stock. For the mutual convenience of the parties, we elected to complete KeySpan’s sale through our pre-existing shelf registration statement rather than filing a separate, new registration statement for KeySpan. To accomplish the transaction, we simultaneously sold 3,000,000 newly issued shares of Houston Exploration stock in a public offering for net proceeds of $26.40 per share, or an aggregate $79.2 million, and bought a like number of KeySpan’s shares of Houston Exploration stock for the same price per share. We cancelled the 3,000,000 shares acquired from KeySpan immediately following the repurchase. KeySpan reimbursed us for all costs and expenses, and the transaction had no impact on our capitalization. The transaction was evidenced in a stock purchase agreement, dated February 26, 2003. Our Board of Directors approved the transaction in principle and delegated to a special, independent committee of the Board plenary authority to negotiate the terms of, and finally approve or veto the transaction. In finally approving the terms of the stock purchase agreement, the independent committee determined that the agreement was consistent with our pre-existing obligations under our registration rights agreement and that issuing the shares under our existing shelf registration statement was in the best interests of our public stockholders to facilitate the prompt and orderly disposition of the shares. As a result of the transactions, KeySpan’s interest in our outstanding shares decreased from 66% to 55%.
NOTE 4 - Employee Benefit and Stock and Option Plans
401(k) Plan
We maintain a tax-qualified defined contribution plan under Section 401(k) of the Internal Revenue Code for our employees. All employees are eligible to participate in the plan upon reaching 21 years of age and completing one month of service. Participants may elect to have us contribute on their behalf up to 12.5% of their total compensation (subject to limitations imposed under the current Internal Revenue Code) on a before tax basis. We make a matching contribution of $1.00 for each $1.00 of employee deferral, subject to limitations imposed by the 401(k) plan and the Internal Revenue Code. The amounts contributed under the 401(k) plan are held in a trust and invested at the direction of each participant among various investment funds, including the common stock of our company. An employee’s salary deferral contributions to the 401(k) plan are 100% vested. Our matching contributions vest at the rate of 20% per year of service. Participants are entitled to distribution of their vested account balances upon termination of employment. We made contributions to the 401(k) plan of $1.3 million, $1.2 million and $0.7 million, respectively, for the years ended December 31, 2003, 2002 and 2001.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred Compensation Plan
In November 2002, we implemented a deferred compensation plan for the benefit of our employees. The plan is a non-qualified plan and is intended to supplement our 401(k) plan by allowing highly compensated employees to save on a tax deferred basis a portion of their eligible compensation subject to limitations imposed by the plan. Under the terms of the plan, employees who have made the maximum allowable contribution to their 401(k) accounts for any year ($12,000 and $11,000 per year, respectively, for 2003 and 2002, with an additional $2,000 in 2003 and $1,000 in 2002 for employees 50 years of age or older) may elect to defer an additional portion of their compensation into the deferred compensation plan. We match 100% of each employee’s deferral up to an aggregate contribution of 12.5% under both the 401(k) plan and the deferred compensation plan. During 2003 and 2002, we made matching contributions totaling $ 0.7 million and $0.5 million, respectively, to the deferred compensation plan. Employer contributions vest 20% per year and become fully vested after a five-year period. Notional accounts are maintained for each eligible employee to record salary deferrals, matching contributions and earnings and losses. We make contributions to a grantor trust to fund plan benefits, but the assets of the trust are subject to the claims of our general creditors. Assets of the grantor trust are invested, at the direction of the employee, in various investment funds, including our common stock. Income on trust assets is treated as our income. Participants are entitled to a benefit attributable to their deferrals and the vested portion of our matching contributions at predetermined future dates or upon termination of their employment. At December 31, 2003 and 2002, the fair market value of the assets held in the trust of $3.4 million and $1.0 million, respectively, are carried on our balance sheet as a non-current asset together with a corresponding non-current liability for the same amount and are located in the line items “Other Non-Current Assets” and “Other Deferred Liabilities.”
Supplemental Executive Retirement Plan
We maintain an unfunded, non-qualified supplemental executive retirement plan. Currently, the only beneficiary is our former President and Chief Executive Officer, James G. Floyd. Upon Mr. Floyd’s retirement March 31, 2001, he became entitled to receive payment of $100,000 per year for life. If Mr. Floyd predeceases his spouse, 50% of his retirement plan benefit will continue to be paid to his surviving spouse for her life. We incurred expenses of approximately $105,000, $105,000, and $113,000, respectively, during the years ended December 31, 2003, 2002 and 2001 related to this retirement plan. Annual expense incurred is greater than annual distribution due to the actuarial estimate of the future liability.
Employee Annual Incentive Compensation Plan
We maintain an Annual Incentive Compensation Plan that provides an annual incentive bonus to all full-time employees if certain performance goals are met during the year. The plan is administered by our Chief Executive Officer on behalf of our Board of Directors and the Compensation Committee. Annual objectives and incentive opportunity levels are established and approved by the Compensation Committee. Incentive awards are earned based on our actual performance in relation to pre-established objectives and on an assessment of individual contribution during the year. We incurred incentive compensation costs of approximately $4.8 million, $3.7 million and $6.8 million in 2003, 2002 and 2001.
Incentive Compensation Plan for Non-Employee Directors
We maintain an incentive compensation plan for non-employee, non-affiliated directors, which was adopted by our Board of Directors in October 1997 and under which participants may defer current compensation in the form of phantom stock rights that are tied to the market price of the common stock on the date services are performed. The term “phantom stock rights” refers to units of value that track the performance of our company’s common stock. These units are not convertible to stock and do not possess any voting rights. Phantom stock rights are exchanged for a cash distribution upon retirement.
Stock and Option Plans
We have three stock options plans, together our (“Stock Plans”): (i) 1996 Stock Option Plan which was adopted at the completion of our initial public offering in September 1996, amended and approved by the stockholders in 1997; (ii) 1999 Non-Qualified Stock Option Plan adopted by our Board of Directors in October 1999; and (iii) 2002 Long-Term Incentive Plan adopted in January 2002, approved by the stockholders in May 2002 and amended by our Board in October 2003. All our employees, directors, consultants and advisors are eligible to participate in our Stock Plans, with the exception of executive officers who are not eligible to participate in the 1999 Plan. Options granted under our Stock Plans expire 10 years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date, with the exception of options granted to directors whose options vest immediately upon grant. All grants are made at the closing
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
price of our common stock as reported on the NYSE on the date of grant. The 1996 and 2002 Plans allow for the grant of both incentive stock options and non-qualified stock options.
Common stock issued through the exercise of non-qualified options will result in a tax deduction for us which is equal to the taxable gain recognized by the optionee. Generally, we will not receive an income tax deduction for incentive based options. For financial reporting purposes, the tax effect of this deduction is accounted for as a credit to additional paid-in-capital rather than as a reduction of income tax expense. The exercise of stock options during 2003, 2002 and 2001 resulted in a current tax benefit to us of approximately $1.4 million, $4.8 million and $1.3 million, respectively.
In addition to stock options, the 2002 Plan allows for the grant of up to 300,000 shares of restricted stock. Restricted stock carries voting and dividend rights; however, the sale or transfer of the shares is restricted. During 2003, we granted and issued 22,000 shares of restricted stock to non-employee directors and affiliated directors at an average grant price of $35.08 per share. The shares were issued as part of each director’s annual compensation. The shares vest and become freely transferable at the earlier of retirement from our Board of Directors or at the end of five years from the date of grant. For 2003, we incurred $0.8 million to shareholders’ equity for the unearned compensation expense, the cost of which will be amortized, on a straight-line basis and recognized in earnings as compensation expense over the stock’s five-year vesting period. During 2003, we recognized stock compensation expense of $26,000 related to these grants of restricted stock made pursuant to the 2002 Plan. In addition, during 2003, 2002 and 2001, we incurred stock compensation expense of $85,000, $85,000 and $64,000 for the amortization of restricted stock granted to our Chief Executive Officer upon his employment with our company in April 2001. See Note 6 - Related Party Transaction - Transactions with Executives.
The table below summarizes all of our Stock Plans as of December 31, 2003.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below sets forth a summary of activity for stock options during the respective years for all of our stock plans.
(1) Weighted average price. For all grants, the grant price equal to closing market price on the NYSE on date of grant.
The table below sets forth a summary of options granted and outstanding, their remaining contractual lives, a weighted average exercise price and the number vested and exercisable as of December 31, 2003.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value of Employee Stock-Based Compensation
On January 1, 2003, we adopted the fair value expense recognition provisions of SFAS 123, as amended by SFAS 148, “Accounting for Stock-Based Compensation - Transition and Disclosure using the “Prospective Method” as defined by the SFAS 148. As a result, we now record as compensation expense the fair value of all stock options issued subsequent to January 1, 2003. No expense has been or will be recorded for grants made in previous years. For the year ended December 31, 2003, we incurred $0.9 million in gross compensation expense related to stock options issued during the year of which $0.2 million was capitalized.
Prior to 2003, we accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) Opinion 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options was measured as the excess, if any, of the fair value of common stock at the date of the grant over the amount the employee must pay to acquire the common stock. If the exercise price of a stock option is equal to the fair market value at the time of grant, no compensation expense is incurred. As a result, we incurred no compensation expense during 2002 and 2001 relating to stock options. Had stock options been accounted for using the fair value method as recommended in SFAS 123, compensation expense would have had the following pro forma effect on our net income and earnings per share for the years ended December 31, 2003, 2002 and 2001.
The effects of applying SFAS 123 in this pro forma disclosure may not be representative of future amounts. The weighted average fair values of options at their grant date during 2003, 2002 and 2001, where the exercise price equaled the market price on the grant date were $13.82, $14.08 and $13.45, respectively. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for grants in 2003, 2002 and 2001:
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 - Income Taxes
The components of the federal income tax provision (benefit) are:
For 2002 and 2001, the credit in the current provision primarily represents Section 29 tax credits (see Note 6-Related Party Transactions - Section 29 Tax Credits). At December 31, 2003, we had no net operating loss carryforwards remaining for federal income tax purposes. At of December 31, 2002, we had net operating loss carryforwards of approximately $47.5 million. Net operating loss carryforwards may be used in future years to offset taxable income.
The following is a reconciliation of statutory federal income tax expense (benefit) to our income tax provision:
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred Income Taxes
Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below. The change in the balance of our deferred income taxes for the current year comprised of deferred tax expense of $59.7 million, a tax benefit of $1.5 million pursuant to the cumulative effect of the change in accounting principle for the adoption of SFAS 143, a tax benefit of $1.4 million from the exercise of non-qualified employee stock options and a tax benefit of $1.2 million due to the change in the fair value of our derivative instruments that are deferred in accumulated other comprehensive income.
NOTE 6 - Related Party Transactions
Transactions With KeySpan
Issuance of 3,000,000 Shares to the Public and Concurrent Repurchase of 3,000,000 Shares from KeySpan (See Note 3- Stockholders’ Equity.)
KeySpan’s Investment in Our Company
KeySpan has publicly announced that it considers its investment in Houston Exploration a non-core asset and that it continues to review strategic alternatives for its investment in our company including the sale of all or a portion of its investment in our common stock. At December 31, 2003, KeySpan held approximately 55% of the common shares outstanding or 17.4 million shares with a value of approximately $635 million.
Sale of Section 29 Tax Credits
In June 2003, we repurchased, for $2.6 million, certain interests in producing wells that were sold in January 1997 to a subsidiary of KeySpan under an agreement designed to monetize tax credits available under Section 29 of the Internal Revenue Code. Section 29 provides for a tax credit from non-conventional fuel sources such as oil produced from shale and tar sands and natural gas produced from geopressured brine, Devonian shale, coal seams and tight sands formations. The wells subject to the agreement are located in West Virginia, Oklahoma and East Texas and produce from formations that qualify for Section 29 tax credits. Pursuant to the agreement, KeySpan acquired an economic interest in wells that qualified for the tax credits and, in exchange, we:
•
retained a volumetric production payment and a net profits interest of 100% in the properties;
•
received a cash down payment of $1.4 million; and
•
receive a quarterly payment of $0.75 for every dollar of tax credit utilized.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During the term of the agreement, we managed and administered the daily operations of the properties in exchange for an annual management fee of $100,000. The agreement expired December 31, 2002 and as a result, we were required to repurchase the interests in the producing wells from KeySpan. Subsequent to the repurchase, ownership of the tax credits reverted back to us. The income statement effect, representing benefits received from Section 29 tax credits, was a benefit of $0.8 million both during 2002 and 2001, with no benefit during 2003.
Acquisition of KeySpan Joint Venture Assets
In October 2002, we purchased from KeySpan a portion of the assets developed under the joint exploration agreement with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan (see below discussion of KeySpan Joint Venture). The acquisition consisted of interests averaging between 11.25% and 45% in 17 wells covering eight of the twelve blocks that were developed under the joint exploration agreement from 1999 through 2002. KeySpan retained a 45% interest in four blocks: South Timbalier 314 and 317 and Mustang Island 725 and 726 as these blocks were in various stages of development at the time of the acquisition. KeySpan committed to continued participation in the ongoing development of these blocks which included the completion of the platform and production facilities at South Timbalier 314/317 together with possible further developmental drilling. Both Houston Exploration and KeySpan farmed - out their interest in Mustang Island 725/726 during 2003. At September 1, 2002, the effective date of the purchase, the estimated proved reserves associated with the interests acquired were 13.5 Bcfe. The $26.5 million purchase price was paid in cash and financed with borrowings under our revolving credit facility. Subsequent purchase price adjustments reduced our acquisition price by $1.2 million. The purchase price was adjusted for various closing items in the normal course of business, including revenues received by and expenditures made by the seller related to the properties acquired for the period between the effective date of the transaction (September 1, 2002) and the closing date (October 11, 2002). Our acquisition of the properties was accounted for as a transaction between entities under common control. As a result, the excess fair value of the properties acquired of $3.1 million ($2.0 million net of tax) was treated as a capital contribution from KeySpan and recorded as an increase to additional paid-in capital during the fourth quarter of 2002.
KeySpan Joint Venture
Effective January 1, 1999, we entered into a joint exploration agreement with KeySpan Exploration & Production, LLC, a subsidiary of KeySpan, to explore for natural gas and oil over an initial two-year term expiring December 31, 2000. Under the terms of the joint venture, we contributed all of our then undeveloped offshore acreage to the joint venture and we agreed that KeySpan would receive 45% of our working interest in all prospects drilled under the program. KeySpan paid 100% of actual intangible drilling costs for the joint venture up to a specified maximum. Further, KeySpan paid 51.75% of all additional intangible drilling costs incurred and we paid 48.25%. Revenues are shared 55% to Houston Exploration and 45% to KeySpan.
Effective December 31, 2000, KeySpan and Houston Exploration agreed to end the primary or exploratory term of the joint venture. As a result, KeySpan has not participated in any of our offshore exploration prospects unless the project involved the development or further exploitation of discoveries made during the initial term of the joint venture. During 2003, KeySpan spent approximately $9.5 million for capital costs associated with its working interests in properties developed under the joint venture. Costs incurred during 2003 were related to the installation of production facilities at South Timbalier 314/317, the completion of the initial two exploratory wells that were brought on-line during the first quarter of 2003 and participation in a third well, a development well on the property during the second quarter of 2003.
From the inception of the joint venture in January 1999 through December 31, 2003, we drilled a total of 29 wells: 21 exploratory wells of which 17 were successful and eight development wells of which seven were successful. KeySpan spent a total of $127.8 million, with $9.5 million, $19.0 million and $17.2 million, respectively being spent during 2003, 2002 and 2001.
Transactions With Our Executive Officers and Directors
Restricted Stock Grant to President and Chief Executive
On April 4, 2001, our Board of Directors appointed William G. Hargett to serve as our President and Chief Executive Officer and to serve on its Board of Directors. Pursuant to an employment agreement entered into on April 4, 2001 between us and Mr. Hargett, Mr. Hargett received a grant of 10,000 restricted shares of Houston Exploration common stock with a fair market value of approximately $256,000 at the time of grant. Until vested, the stock is restricted from transfer and
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
subject to forfeiture in the event Mr. Hargett’s employment is terminated. The shares vest, become nonforfeitable and freely transferable in equal one-third increments on each anniversary of the grant date. The cost of the restricted stock will be recognized in earnings as compensation expense over the stock’s three-year vesting period. During 2003, 2002 and 2001 we recognized stock compensation expense of $85,000, $85,000 and $64,000, respectively related to this restricted stock grant.
Employment Contracts
We have entered into employment contracts with all nine of our executive officers. Contracts are initially set for a three year period and automatically extended one year on each anniversary unless either party gives notice within a specified number of days prior to the anniversary of the employment agreement. Executive officers receive annual salary and bonus payments pursuant to their employment contracts and if we terminate an employment agreement without cause or if the employee terminates an employment agreement with good reason, as defined in the employment agreements, we are obligated to pay the employee a lump-sum severance payment of 2.99 times the employee’s then current annual rate of total compensation, as defined in the agreement, in addition to the continuation of certain insurance benefits for a specified time period.
Termination of Employment Agreements for Former Executives
During 2001, we recognized $5.2 million in general and administrative expenses pursuant to lump-sum payments made for the termination of employment contracts of our former President and Chief Executive Officer and Director, James G. Floyd, our Senior Vice President of Exploration and Production, Randall J. Fleming and our Chief Financial Officer, Thomas W. Powers. Each received lump sums of $2.3 million, $1.4 million and $1.5 million, respectively.
Transactions Involving Companies with Common Directors
John U. Clarke, a member of our Board of Directors and Chairman of the Audit Committee serves as a director of NATCO Group, a publicly traded oil field services and equipment company. During 2003, 2002 and 2001 we purchased services and supplies from NATCO of $1.1 million, $1.1 million and $0.9 million, respectively. Gordon F. Ahalt, also a member of our Board and Audit Committee serves as a director of Cal Dive International, a publicly traded offshore oil field service company that provides subsea construction, inspection, maintenance, repair and salvage services. During 2003 and 2002, we purchased services totaling $1.9 million and $0.3 million, respectively, from Cal Dive, with no purchases for 2001.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 7 - Derivative Instruments
As of December 31, 2003, we had entered into commodity price hedging contracts with respect to our production for 2004 and 2005 as listed in the tables below. Volumes and fair values are stated in thousands. The total estimated fair value of our natural gas and oil derivative instruments at December 31, 2003 was a negative $36.9 million ($27.4 million net of taxes of which $26.1 million was deferred in accumulated other comprehensive income and $1.3 million was recognized in current earnings as a reduction to natural gas and oil revenues.)
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2002, we had entered into commodity price hedging contracts with respect to our production for 2003 and 2004 as listed in the tables below. Volumes and fair values are stated in thousands. The total estimated fair value of our natural gas and oil derivative instruments at December 31, 2002 was a deferred loss of $38.8 million ($25.2 million net of taxes).
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For natural gas, transactions are settled based upon the NYMEX price on the final trading day of the month. For oil, our swaps are settled against the average NYMEX price of oil for the calendar month rather than the last day of the month. Fair market value is calculated for the respective months using prices derived from NYMEX futures contract prices existing at December 31st and from market quotes received from counterparties.
These hedging transactions are settled based upon the average of the reported settlement prices on the NYMEX for the last three trading days of a particular contract month or the NYMEX price on the final trading day of the month (the “settlement price”). With respect to any particular swap transaction, the counterparty is required to make a payment to us in the event that the settlement price for any settlement period is less than the swap price for the transaction, and we are required to make payment to the counterparty in the event that the settlement price for any settlement period is greater than the swap price for the transaction. For any particular collar transaction the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for the transaction, and we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for the transaction. We are not required to make or receive any payment in connection with a collar transaction if the settlement price is between the floor and the ceiling.
NOTE 8 - Sales To Major Customers
We sold natural gas and oil production representing 10% or more of our natural gas and oil revenues for the years ended December 31, 2003, 2002 and 2001 as listed below. In the exploration, development and production business, production is normally sold to relatively few customers. However, based on the current demand for natural gas and oil, we believe that the loss of any of our major purchasers would not have a material adverse effect on our operations.
Note:
Amounts disclosed that are less than 10% are presented for information and comparison purposes only.
NOTE 9 - Commitments and Contingencies
Legal Proceedings
We are involved from time to time in various claims and lawsuits incidental to our business. In the opinion of management, the ultimate liability, if any, will not have a material adverse effect on our financial position or results of operations.
Severance Tax Refund
During July 2002, we applied for and received from the Railroad Commission of Texas a “high-cost/tight-gas formation” designation for a portion of our South Texas production. For qualifying wells, production is either exempt from tax or taxed at a reduced rate until certain capital costs are recovered For the year ended December 31, 2003, we recognized as “other income” refunds of prior period severance tax payments of $21.6 million ($14.0 million net of tax). For the year ended December 31, 2002, we recognized a total of $10.4 million ($6.8 million net of tax), of which $1.3 million related to refund of 2002 severance tax expense and $9.1 related to refunds of prior period expense. At December 31, 2003 and 2002, our current receivables include $12.9 million and $14.8 million, respectively, in gross refunds of which we estimate, approximately 70%, or $9.0 million and $10.4 million, respectively, relate to our net revenue interest. We expect to collect our current receivable prior to the end of the third quarter of 2004. Beginning September 1, 2003, all refunds issued by the State of Texas are to be made in the form of a reduction to or credit against our current severance tax liability rather than in the form of a cash reimbursement. For future periods, we do not expect to recognize as income future refunds of prior
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
years’ severance tax in excess of $1 million.
Leases
We have entered into non-cancelable operating lease agreements in the ordinary course of our business activities. These leases include those for our office space at 1100 Louisiana in Houston, Texas and at 700 17th Street in Denver, Colorado together with various types of office equipment (telephones, copiers and faxes). The terms of these agreements have various expiration dates from 2004 through 2009. Rental expense related to these leases was $1.3 million, $1.2 million and $0.6 million, respectively, for the years ended December 31, 2003, 2002 and 2001. At December 31, 2003, our total commitment under these non-cancelable operating leases was $8.3 million. Minimum rental commitments under the terms of our operating leases are as follows (in thousands):
NOTE 10 - Acquisitions
EnerVest Acquisition
On December 31, 2003, we completed the purchase of certain producing natural gas and oil properties and associated gathering pipelines and equipment located in the Appalachian Basin of West Virginia and Pennsylvania from EnerVest East Limited Partnership. The properties acquired are adjacent to our existing producing properties in West Virginia. The $28 million purchase price was reduced by $0.2 million for various customary closing items, including revenues received by and expenditures made by the seller related to the properties acquired for the period between the effective date of the transaction, December 1, 2003, and the closing date, December 31, 2003. The net purchase price of $27.9 million was paid in cash and financed by borrowings under our revolving bank credit facility. The properties purchased cover approximately 146,000 gross (83,950 net) acres. The properties acquired include working interests in approximately 774 producing wells Our average working interest is 74% and we will we operate approximately 85% of the wells acquired. In addition, the interests acquired include approximately 300 wells in which we will have an overriding royalty interest. Total proved reserves associated with the interests acquired were 23.4 Bcfe, as of the December 31, 2003.
Transworld Exploration and Production Inc. Acquisition
On October 15, 2003, we completed the acquisition of Transworld Exploration and Production Inc.’s shallow-water Gulf of Mexico natural gas and oil producing properties and undeveloped acreage. At closing, the $155 million purchase price was reduced by $7.5 million for various customary closing items, including revenues received by and expenditures made by the seller related to the properties acquired for the period between the effective date of the transaction, July 1, 2003, and the closing date, October 15, 2003. The net purchase price of $147.5 million was paid in cash and financed in part by cash on hand and in part by borrowings under our revolving bank credit facility. The properties are located primarily in the central Gulf of Mexico in less than 320 feet of water and include 21 blocks covering 86,237 gross (64,394 net) acres. As of the October 15, 2003 closing date, proved reserves are an estimated 88.5 Bcfe, of which 75% is natural gas. Current production is from 11 fields and is estimated at approximately 35 MMcfe per day, net to our interest. We operate properties representing 97% of the proved reserves with an average working interest of 65%.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Acquisition of KeySpan Joint Venture Assets (See Note 6 - Related Party Transaction - Transactions with KeySpan).
Burlington Acquisition
On May 30, 2002, we completed the purchase of natural gas and oil producing properties and associated gathering pipelines, together with undeveloped acreage, from Burlington Resources Inc. located in the Webb, Jim Hogg, Wharton and Calhoun counties of South Texas. The properties purchased cover approximately 24,800 gross (10,800 net) acres located in the Northeast Thompsonville, South Laredo, McFarlan and Maude Traylor Fields. The properties purchased represent interests in approximately 145 producing wells and total proved reserves of 42 Bcfe as of January 1, 2002, the effective date of the transaction. Our average working interest is 35% and we are the operator of approximately 23% of the producing wells acquired. The $44.5 million purchase price, which is net of a purchase price adjustment of $3.9 million, was financed by borrowings under our revolving bank credit facility. The purchase price was reduced for various closing items in the normal course of business, including revenues received by and expenditures made by the seller related to the properties acquired for the period between the effective date of the transaction (January 1, 2002) and the closing date (May 30, 2002).
On July 16, 2002, we sold those interests acquired from Burlington in the McFarlan and Maude Traylor Fields for approximately $5.0 million, which was net of a purchase price adjustment of $1.1 million. The effective date of this transaction was January 1, 2002. These two fields, located in Wharton and Calhoun counties, respectively, are outside our current area of focus in South Texas. The sale represented interests in 22 producing wells with reserves of approximately 5 Bcfe. Proceeds from the sale were used to repay borrowings under our revolving bank credit facility.
We retained the Northeast Thompsonville Field, located in Jim Hogg County, and the South Laredo Field, located in Webb County. The Northeast Thompsonville Field has 10 wells producing from the Wilcox formation, all of which we operate, and representing approximately 70% of the proved reserves and 75% of the current production associated with the acquisition from Burlington. The South Laredo Field, located in Webb County and in the Lobo Trend, contains 113 wells, all operated by a third party.
Conoco Acquisition
On December 31, 2001, we completed the purchase of certain natural gas and oil properties and associated gathering pipelines and equipment, together with developed and undeveloped acreage, located in Webb and Zapata counties of South Texas, from Conoco Inc. The $69 million purchase price was paid in cash and financed by borrowings under our revolving bank credit facility. The properties purchased cover approximately 25,274 gross (16,885 net) acres located in the Alexander, Haynes, Hubbard and South Trevino Fields, which are in close proximity to our existing operations in the Charco Field, and represent interests in approximately 159 producing wells. We operate approximately 95% of the producing wells acquired and our average working interest is 87%. Total proved reserves associated with the interests acquired were 85 Bcfe, as of the October 1, 2001, the effective date of the transaction.
NOTE 11 -Subsequent Event
Sale of Onshore South Louisiana Properties
On February 4, 2003, we completed the sale of our onshore South Louisiana producing properties. The sale was effective November 1, 2003 and the properties represented 12.3 Bcfe proved reserves as of December 31, 2003, and included interests in 33 gross (9.5 net) producing wells and covered approximately 6,300 gross (2,300 net) acres. The sale price of $15 million was reduced by $2.2 million for various customary closing items, including revenues received by and expenditures made by us related to the properties sold for the period between the effective date of the transaction, January 1, 2004, and the closing date, February 4, 2003. The net proceeds from the sale of $12.8 million were used to repay borrowings under our revolving bank credit facility.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13- Supplemental Information On Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)
The following information concerning our natural gas and oil operations has been provided pursuant to Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities.” Our natural gas and oil producing activities are conducted onshore within the continental United States and offshore in federal and state waters of the Gulf of Mexico. Our natural gas and oil reserves were estimated by independent reserve engineers.
Capitalized Costs of Natural Gas and Oil Properties
Capitalized Costs Incurred
Costs incurred for natural gas and oil exploration, development and acquisition are summarized below. Costs incurred during the years ended December 31, 2003, 2002 and 2001 include interest expense and general and administrative costs related to acquisition, exploration and development of natural gas and oil properties of $20.2 million, $21.1 million and $24.9 million, respectively.
(1)
Unevaluated amounts represent costs we incurred during the year and excluded from the amortization base until proved reserves are established or impairment is determined. We estimate that these costs will be evaluated within four years.
(2)
Asset retirement obligation costs incurred during 2003 exclude the cumulative effect of the change for prior years of $42.5 million pursuant to our adoption of SFAS 143 on January 1, 2003.
During the years ended December 2003, 2002 and 2001, we spent $46.0 million, $11.0 million and $19.9 million, respectively, to develop our proved undeveloped reserves. At December 31, 2003, our Standardized Measure of Discounted Future Net Cash Flows includes estimated future development costs for our proved undeveloped reserves for the next three years of $96.3 million, $126.4 million, and $10.5 million, respectively, for 2004, 2005 and 2006.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves (unaudited)
The following summarizes the policies we used in the preparation of the accompanying natural gas and oil reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by the Statement of Financial Accounting Standards No. 69 is an attempt to present the information in a manner comparable with industry peers.
The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of December 31 of the years presented. These estimates were prepared by independent petroleum consultants. Proved reserves are estimated quantities of natural gas and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:
1.
Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.
2.
The estimated future cash flows are compiled by applying year-end prices of natural gas and oil relating to our proved reserves to the year-end quantities of those reserves.
3.
The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions.
4.
Future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the natural gas and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves.
5.
Future net cash flows are discounted to present value by applying a discount rate of 10%.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows and does not include cash flows associated with hedges outstanding at each of the respective reporting dates and is unaudited.
The following table summarizes changes in the standardized measure of discounted future net cash flows and is unaudited.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Estimated Net Quantities of Natural Gas and Oil Reserves
The following table sets forth our net proved reserves, including changes, and proved developed reserves (all within the United States) at the end of each of the three years in the period ended December 31, 2003, 2002 and 2001. All amounts are unaudited.
THE HOUSTON EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 13- Quarterly Financial Information (Unaudited)
(1)
Quarterly earnings per share is based on the weighted average number of shares outstanding during the quarter. Because of the increase in the number of shares outstanding during the quarters due to the exercise of stock options, the sum of quarterly earnings per share may not equal earnings per share for the year.
INDEX TO EXHIBITS
INDEX TO EXHIBITS
(1)
Filed herewith.
(2)
Management contract or compensation plan.