ITEM 3. LEGAL PROCEEDINGS
The properties purchased in the TransTexas Acquisition are subject to a judgment lien imposed on substantially all of TransTexas' properties in the aggregate amount of $18 million. TransTexas has agreed to indemnify the Company with respect to any loss arising from such judgment lien. TransTexas has appealed the judgment to which such liens relate, and has posted a bond to ensure payment of such judgment pending the completion of such appeal. The bond, in the approximate amount of $18 million, is secured by an irrevocable letter of credit. The $18 million judgment against TransTexas has been reversed, a decision which, if upheld, will result in the release of the related judgment lien. As a result of such arrangements, the Company believes that the properties purchased in the TransTexas Acquisition are not subject to any material risk that any such judgment against TransTexas will not be paid.
The Company is not a party to any other pending legal proceedings, other than ordinary routine litigation incidental to its business that management believes will not have a material adverse effect on its 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 the Company's security holders during the last quarter of the fiscal year ended December 31, 1997.
PART II.
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock (symbol: THX) is traded on the New York Stock Exchange. The following table sets forth the range of high and low sales prices for each calendar quarterly period from September 20, 1996 through December 31, 1997 as reported on the New York Stock Exchange:
As of February 5, 1997, 23,360,903 shares of Common Stock were outstanding and the Company had approximately 68 shareholders of record and approximately 2,800 beneficial owners.
DIVIDENDS
The Company currently intends to retain its cash for the operation and expansion of its business, including exploration, development and acquisition activities. The Company's Credit Facility (as defined in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources") contains restrictions on the payment of dividends to holders of Common Stock. Accordingly, the Company's ability to pay dividends will depend upon such restrictions and the Company's results of operations, financial condition, capital requirements and other factors deemed relevant by the Board of Directors. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below with respect to the Company's combined statements of operations for each of the five years in the period ended December 31, 1997 and with respect to the Company's combined balance sheets as of December 31, 1993, 1994, 1995, 1996 and 1997 are derived from the financial statements of the Company that have been audited by Arthur Andersen LLP, independent public accountants. The financial data should be read in conjunction with the "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's Combined Financial Statements and Notes thereto included elsewhere and incorporated by reference in this Annual Report on Form 10-K.
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(1) Represents a nonrecurring non-cash charge incurred in connection with the reorganization effective in February 1996. See Note 11 to the Company's Combined Financial Statements.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of the Company's historical financial position and results of operations for each year of the three-year period ended December 31, 1997. The Company's historical combined financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K contain detailed information that should be referred to in conjunction with the following discussion.
GENERAL
Houston Exploration was incorporated in December 1985 to conduct certain of the natural gas and oil exploration and development activities of Brooklyn Union. The Company initially focused primarily on the exploration and development of high potential prospects in the Gulf of Mexico. Effective February 29, 1996, Brooklyn Union implemented a reorganization of its exploration and production assets by transferring to Houston Exploration certain onshore producing properties and developed and undeveloped acreage. Subsequent to the reorganization, the Company has expanded its focus to include lower risk exploitation and development drilling on the onshore properties transferred or acquired, in addition to seeking opportunistic acquisitions both onshore and offshore. On July 2, 1996, the Company acquired certain natural gas and oil properties and associated pipelines located in Zapata County, Texas (the "TransTexas Acquisition") from TransTexas. In September 1996, the Company completed its IPO of 7,130,000 shares of its Common Stock at $15.50 per share, resulting in net cash proceeds of approximately $101.0 million. Concurrently with the completion of the IPO, the Company completed the acquisition of substantially all of the natural gas and oil properties and related assets of Soxco (the "Soxco Acquisition"). As of December 31, 1997, THEC Holdings Corp., a wholly owned subsidiary of Brooklyn Union, owned approximately 65% of the outstanding shares of Common Stock. At December 31, 1997, the Company had net proved reserves of 337 Bcfe, 98% of which were natural gas and 78% of which were classified as proved developed.
The Company's revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas, oil and condensate, which are dependent upon numerous factors beyond the Company's control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been highly volatile, and future decreases in natural gas and oil prices could have a material adverse effect on the Company's financial position, results of operations, quantities of natural gas and oil reserves that may be economically produced, and access to capital.
The Company uses the full cost method of accounting for its investment in natural gas and oil properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of natural gas and oil reserves are capitalized into a "full cost pool" as incurred, and properties in the pool are depleted and charged to operations using the unit-of-production method based on the ratio of current production to total proved natural gas and oil reserves. To the extent that such capitalized costs (net of accumulated depreciation, depletion and amortization) less deferred taxes exceed the present value (using a 10% discount rate) of estimated future net cash flows from proved natural gas and oil reserves and the lower of cost or fair value of unproved properties, such excess costs are charged to operations. If a write-down is required, it would result in a charge to earnings but would not have an impact on cash flows from operating activities. Once incurred, a write-down of oil and gas properties is not reversible at a later date even if oil and gas prices increase.
As of December 31, 1997, the Company estimates, using prices in effect as of such date, that the ceiling limitation imposed under full cost accounting rules on total capitalized natural gas and oil property costs exceeded actual capitalized costs. Natural gas prices have fluctuated substantially since December 31, 1997. The Company may be required to write down the carrying value of its natural gas and oil properties at the end of the first quarter of 1998, depending upon natural gas prices and the results of the Company's drilling programs.
In February 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 128, "Earnings Per Share." The statement specifies the computation, presentation, and disclosure requirements for earnings per share ("EPS") and is designed to improve the EPS information provided in the financial statements by simplifying the existing computation. Primary EPS has been replaced with Basic EPS which is calculated by dividing net income by the
weighted average number of shares of common stock outstanding during the year. No dilution for any potentially dilutive securities is included. Fully diluted EPS is now called Diluted EPS and assumes the conversion of all options, contingent shares and other potentially dilutive securities. The Company adopted SFAS No. 128 in its December 31, 1997 financial statements and has presented Diluted EPS for the years 1995 and 1996 which were previously not required as the dilutive effect of options and contingent shares was less than 3%. See Note 1 to the Company's Combined Financial Statements.
In February 1997, the FASB issued SFAS No. 129, "Disclosure of Information About Capital Structure," which consolidates the existing requirements to disclose certain information about an entity's capital structure, for both public and nonpublic entities. In June 1997, FASB issued SFAS No. 130, "Reporting Comprehensive Income," which establishes standards for reporting and display of comprehensive income and its components. Also issued in June of 1997 was SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information," which specifies and revises guidelines for determining an entity's operating and geographic segments and the type and level of financial information about those segments to be disclosed. The Company adopted the provisions of SFAS Nos. 129, 130 and 131 in its 1997 financial statements. The adoption of SFAS Nos. 129, 130 and 131 did not have a material effect on its results of operations or the calculation of net income.
The Company incurs certain production gas volume imbalances in the ordinary course of business and utilizes the entitlements method to account for its gas imbalances. Under this method, income is recorded based on the Company's net revenue interest in production or nominated deliveries. Deliveries in excess of these amounts are recorded as liabilities, while under deliveries are reflected as assets. Production imbalances are valued using market value. Management does not believe that the Company has any material overproduced gas balances.
The Company receives reimbursement for administrative and overhead expenses incurred on the behalf of other working interest owners of properties operated by the Company. In addition, the Company capitalizes general and administrative costs and interest expense directly related to its acquisition, exploration and development activities.
The Company's combined historical financial statements include the historical results of operations associated with the onshore producing properties and developed and undeveloped acreage transferred to the Company by Fuel Resources Inc. ("FRI"), a subsidiary of Brooklyn Union, in the February 1996 reorganization implemented by Brooklyn Union. Accordingly, the Company's historical results of operations reflect a nonrecurring charge of $12 million incurred in the year ended December 31, 1995 with respect to remuneration to which certain employees of FRI were entitled for the increase in the value of the transferred properties prior to the reorganization. See Notes 1 and 11 to the Company's Combined Financial Statements.
RESULTS OF OPERATIONS
The following table sets forth the Company's historical natural gas and oil production data during the periods indicated:
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(1) Reflects the effects of hedging. Absent the effects of hedging, average realized natural gas prices would have been $1.53, $2.35 and $2.45 per Mcf for the years ended December 31, 1995, 1996 and 1997, respectively.
RECENT FINANCIAL AND OPERATING RESULTS
COMPARISON OF YEARS ENDED DECEMBER 31, 1996 AND 1997
Production. Houston Exploration's production increased 61% from 31,923 MMcfe in 1996 to 51,336 MMcfe in 1997. The increase in production was attributable to added production from both the TransTexas and the Soxco Acquisitions, which were completed during the second half of 1996, combined with newly developed offshore production brought on-line during the second and third quarters of 1997 and the successful development drilling and workover programs begun in the latter half of 1996 and continuing through the fourth quarter of 1997 on the Charco Field properties acquired in the TransTexas Acquisition. Production in the Charco Field increased 179% from approximately 33,000 Mcfe per day in December 1996 to approximately 92,000 Mcfe per day in December 1997 as 22 development wells were successfully completed and brought on-line during 1997.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased 79% from $64.9 million in 1996 to $116.3 million in 1997 as a result of the 61% increase in production combined with a 13% increase in average realized natural gas prices, from $2.00 per Mcf in 1996 to $2.25 per Mcf for the year ended 1997.
As a result of hedging activities, the Company realized an average gas price of $2.25 per Mcf for 1997, which was 92% of the $2.45 per Mcf that otherwise would have been received, resulting in a $9.9 million decrease in natural gas revenues for the year ended December 31, 1997. During 1996, the average realized gas price was $2.00 per Mcf which was 85% of the unhedged average gas price of $2.35, resulting in a decrease in natural gas revenues of $11.1 million for the year ended 1996.
Lease Operating Expenses and Severance Tax. Lease operating expenses increased 31% from $10.8 million in 1996 to $14.1 million in 1997. On an Mcfe basis, lease operating expenses decreased from $0.34 in 1996 to $0.28 in 1997. The increase in lease operating expenses during 1997 is primarily attributable to properties acquired in the
TransTexas Acquisition and the significant expansion of operations in the Charco Field combined with the effects of an industry-wide increase in operating costs. The decrease in the lease operating expenses per Mcfe resulted from the substantial increase in production during 1997. Severance tax, which is a function of volume and revenues generated from onshore production, increased 202% from $1.4 million, or $0.04 per Mcfe, in 1996 to $4.2 million, or $0.08 per Mcfe, in 1997. The increase in severance tax is due to the increase in production from the onshore Charco Field properties combined with higher gas prices in 1997 compared to 1996.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased 75% from $33.7 million in 1996 to $59.1 million in 1997. Depreciation, depletion and amortization expense per Mcfe increased 9% from $1.06 in 1996 to $1.15 in 1997. The increase in depreciation, depletion and amortization expense was a result of the increased production from acquired as well as newly developed properties combined with an increased depletion rate. The increase in the depletion rate is attributable partly to the industry-wide increase in costs of drilling goods and services, platform and facilities construction combined with a relatively modest increase in reserves given the increased capital expenditures from the Company's exploration and development activities during 1997.
General and Administrative Expenses. General and administrative expenses, net of overhead reimbursements received from other working interest owners of $1.0 million and $0.9 million, in 1996 and 1997, respectively, decreased 7% from $6.2 million in 1996 to $5.8 million in 1997. After excluding the one-time charge of $0.8 million taken in September 1996 in conjunction with the IPO for the buyout and termination of stock options granted to certain officers and directors of Brooklyn Union, general and administrative expense increased 7% from $5.4 million in 1996 to $5.8 million in 1997. The increase in general and administrative expense reflects the overall growth and expansion of the Company and its operations since the second half of 1996 and continuing through the end of 1997. The Company capitalized general and administrative expenses directly related to oil and gas exploration and development activities of $5.3 million and $7.2 million, respectively, in 1996 and 1997. The increase in capitalized general and administrative expense directly corresponds with the growth of the Company's technical workforce and the implementation of an incentive compensation plan. On an Mcfe basis, general and administrative expenses decreased 45% from $0.20 in 1996 to $0.11 in 1997. The lower rate per Mcfe during 1997 reflects the increase in the Company's production.
Income Tax Provision. The provision for income taxes increased from an expense of $2.2 million in 1996 to an expense of $10.2 million in 1997 due to the increase in pretax income offset by the benefit received from Section 29 tax credits.
Operating Income and Net Income. Operating income increased 151% to $34.4 million in 1997 from $13.7 million in 1996. Net income increased 171% from $8.6 million in 1996 to $23.3 million in 1997. The significant increase in operating income and net income was attributable primarily to higher production volumes and higher net realized natural gas prices combined with lower lease operating expenses.
COMPARISON OF YEARS ENDED DECEMBER 31, 1995 AND 1996
Production. Houston Exploration's production increased 47% from 21,677 MMcfe in 1995 to 31,923 MMcfe in 1996. The 1996 production increase is attributed to commencement of production from newly developed offshore properties during the first half of the year and the Company's two significant acquisitions during the second half of the year: (i) the TransTexas Acquisition, which was completed on July 2, 1996, and (ii) the Soxco Acquisition, which was completed on September 25, 1996 concurrently with the closing of the IPO.
Natural Gas and Oil Revenues. Natural gas and oil revenues increased 65% from $39.4 million in 1995 to $64.9 million in 1996 as a result of the 47% increase in production and an increase in average realized natural gas prices of 12% from $1.79 per Mcf in 1995 to $2.00 Mcf in 1996.
As a result of hedging activities, the Company realized an average gas price of $2.00 per Mcf for 1996, compared to an average price of $2.35 per Mcf that otherwise would have been received, resulting in a $11.1 million decrease in natural gas revenues for the year ended December 31, 1996. During 1995, the average realized gas price
was $1.79 per Mcf compared to an unhedged average gas price of $1.53, resulting in an increase in natural gas revenues of $5.6 million for the year ended December 31, 1995.
Lease Operating Expenses and Severance Tax. Lease operating expenses increased 116% from $5.0 million in 1995 to $10.8 million in 1996. On an Mcfe basis, lease operating expenses increased from $0.23 in 1995 to $0.34 in 1996. Of the $5.8 million increase in lease operating expenses during 1996, $2.2 million relates directly to properties acquired in the TransTexas Acquisition at the beginning of the third quarter and includes certain one-time expenses incurred in taking over operations of these properties, and the remaining $3.6 million reflects higher initial operating costs associated with bringing new facilities and wells on-line. Severance tax, which is a function of volume and revenues generated from onshore production, increased 180% from $0.5 million, or $0.02 per Mcfe, in 1995 to $1.4 million, or $0.04 per Mcfe, in 1996. The increase in severance tax resulted from the addition of production from the onshore Charco Field properties combined with an increase in net realized natural gas prices during the fourth quarter of 1996.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased 53% from $22.0 million in 1995 to $33.7 million in 1996. The increase was attributable to the increase in production during 1996. Depreciation, depletion and amortization expense per Mcfe increased from $1.01 in 1995 to $1.06 in 1996, primarily as a result of exploratory drilling which did not add significant new reserves during the period.
General and Administrative Expenses. General and administrative expenses, net of overhead reimbursements received from other working interest owners of $1.2 million and $1.0 million for 1995 and 1996, respectively, increased 77% from $3.5 million in 1995 to $6.2 million in 1996. The Company capitalized general and administrative expenses directly related to oil and gas exploration and development activities of $4.1 million and $5.3 million, respectively, in 1995 and 1996. The increase in net general and administrative expenses during 1996 is a result of certain one-time expenses incurred in conjunction with the combination of offshore and onshore operations and an $0.8 million charge taken in conjunction with the IPO for the buyout and termination of options to purchase Common Stock granted to certain officers and directors of Brooklyn Union under the Company's 1994 Incentive Plan. On an Mcfe basis, general and administrative expenses increased from $0.16 in 1995 to $0.20 in 1996, or $0.17 per Mcfe excluding the $0.8 million buyout of the options issued under the 1994 Incentive Plan.
Nonrecurring Charge. During 1995, the Company incurred a $12.0 million nonrecurring charge to reflect the amount of remuneration paid to former employees of FRI. During 1996 the Company did not incur additional charges related to the remuneration paid to former FRI employees. See "--General" and Note 11 to the Company's Combined Financial Statements.
Income Tax Provision. Income tax expense increased from a benefit of $3.8 million in 1995 to an expense of $2.2 million in 1996. Included in the provision for 1995 was a credit of $4.2 million related to the $12.0 million nonrecurring charge. For 1996, the primary difference between the Company's statutory tax rate of 35% and its effective rate of 20% was due to the utilization of Section 29 credits received for specific onshore properties.
Net Income. The Company's net income increased from a loss of $0.3 million in 1995 to net income of $8.6 million in 1996. Excluding the effects of the $12.0 million charge ($7.8 million net of tax), the Company's net income increased 15% from $7.5 million in 1995 to $8.6 million in 1996. The increase in net income resulted from increased production from newly developed properties and production from properties acquired in the TransTexas and Soxco Acquisitions, combined with an increase in realized natural gas prices. Both lease operating and general and administrative expenses increased from the prior year due to certain one-time charges and interest expense reflects third quarter borrowings, which were repaid with proceeds from the IPO.
LIQUIDITY AND CAPITAL RESOURCES
The Company has historically funded its operations, acquisitions, capital expenditures and working capital requirements from cash flows from operations, bank borrowings and, prior to the IPO, capital contributions from Brooklyn Union. See also "Risk Factors -- Effects of Leverage."
As of December 31, 1997, the Company had a working capital deficit of $5.4 million (which includes the accrued liability of $8.8 million for the Soxco minimum deferred purchase price which is payable in shares of Common Stock during the first quarter of 1998) and $15.4 million of available borrowing base under its Credit Facility (defined below). Net cash provided by operating activities for the year ended December 31, 1997 was $97.3 million compared to $54.1 million for the year ended December 31, 1996. The Company's cash position was increased during the year ended December 31, 1997 by borrowings of $79.0 million under the Company's Credit Facility. Funds used in investing and financing activities consisted of $145.1 million for investments in property and equipment and principal payments of $31.0 million on long-term borrowing under the Credit Facility. As a result of these activities, cash and cash equivalents increased $1.9 million from $2.8 million at December 31, 1996 to $4.7 million at December 31, 1997.
Over the past three years, the Company has spent $390 million (including $96.9 million expended on the TransTexas and the Soxco acquisitions) to add 294 Bcfe of net proved reserves, representing a finding and development cost of $1.33 per Mcfe. The Company's primary sources of funds for each of the past three years are reflected in the following table:
The Company's natural gas and oil capital expenditures for each of the past three years are reflected in the following table:
The Company's capital expenditure budget for 1998 of $100 million includes $68 million and $32 million, respectively, for exploration and development. These amounts include development costs associated with recently acquired properties and amounts that are contingent upon drilling success. The Company will continue to evaluate its capital spending plans through the year. No significant abandonment or dismantlement costs are anticipated through 1998. Actual levels of capital expenditures may vary significantly due to a variety of factors, including drilling results,
natural gas prices, industry conditions and outlook and future acquisitions of properties. The Company believes cash flows from operations and borrowings under its Credit Facility will be sufficient to fund these expenditures. The Company will continue to selectively seek acquisition opportunities for proved reserves with substantial exploration and development potential both offshore and onshore. The size and timing of capital requirements for acquisitions is inherently unpredictable. The Company expects to fund exploration and development through a combination of cash flow from operations, borrowings under its Credit Facility, or the issuance of equity or debt securities.
The Company has entered into the Credit Facility (the "Credit Facility") with a syndicate of lenders led by Chase Bank of Texas, National Association ("Chase") which provides a maximum loan amount of $150 million, subject to borrowing base limitations, on a revolving basis. The Credit Facility has a current borrowing base of $130 million. At December 31, 1997, $113 million was borrowed and $1.6 million was committed under outstanding letter of credit obligations. The Credit Facility matures on July 1, 2000. Advances under the Credit Facility bear interest, at the Company's election at (i) a fluctuating rate ("Base Rate") equal to the higher of the Federal Funds Rate plus 0.5% or Chase's prime rate or (ii) a fixed rate ("Fixed Rate") equal to a quoted LIBOR rate plus a margin between 0.375% and 1.125% depending on the amount outstanding under the Credit Facility. Interest is due at calendar quarters for Base Rate loans and at the earlier of maturity or three months from the date of the loan for Fixed Rate loans. The Credit Facility contains covenants of the Company, including certain restrictions on liens and financial covenants which require the Company to, among other things, maintain (i) an interest coverage ratio of 2.5 to 1.0 of earnings before interest, taxes and depreciation to cash interest ("EBIDTA") and (ii) a total debt to capitalization ratio of less than 60%. The Credit Facility also restricts the Company's ability to purchase or redeem its capital stock or to pledge its oil and gas properties or other assets. As of December 31, 1997 the Company was in compliance with all Credit Facility covenants. The borrowing base under the Credit Facility is determined by Chase in its discretion in accordance with Chase's then current standards and practices for similar oil and gas loans taking into account such factors as Chase deems appropriate.
Pursuant to the Credit Facility, the Company may declare and pay cash dividends to its stockholders provided that (i) no defaults exist and the Company will not be in default with respect to any financial covenants as a result of such dividend payment and (ii) the Company continues to have a ratio of consolidated total debt to consolidated total capitalization of less than 55%. Accordingly, the Company's ability to pay dividends will depend upon such restrictions and the Company's results of operations, financial condition, capital requirements and other factors deemed relevant by the Board of Directors. See "Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters -- Dividends."
The Company intends to seek additional long-term debt financing during 1998 to supplement the Credit Facility. The Company intends to use the proceeds from such additional debt financing, if successfully completed, to repay outstanding indebtedness under the Credit Facility and to fund capital expenditures, including payment of a portion of the purchase price of the Pending Acquisition, if completed. No assurances can be made that the Company will be able to successfully complete any such additional debt financing.
The Company utilizes derivative commodity instruments to hedge future sales prices on a portion of its natural gas production to achieve a more predictable cash flow, as well as to reduce its exposure to adverse price fluctuations of natural gas. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Hedging instruments used are swaps, collars and options, and are generally placed with major financial institutions that the Company believes are minimal credit risks. The Company accounts for these transactions as hedging activities and, accordingly, gains or losses are included in natural gas and oil revenues in the period the hedged production occurs. Unrealized gains and losses on these contracts, if any, are deferred and offset in the balance sheet against the related settlement amounts.
As of December 31, 1997, the Company had entered into commodity price hedging contracts with respect to its gas production as listed below. Natural gas production during the month of December 1997 was 5,533 MMcfe (5,570 MMMBtu).
As of February 5, 1998, the Company had no commodity hedging contracts extending beyond March 1998. The Company has entered into basis swaps with respect to more than 50% of the indicated NYMEX hedged volume.
These hedging transactions are settled based upon the average of the reported settlement prices on the New York Mercantile Exchange (the "NYMEX") for the last three trading days of a particular contract month (the "settlement price"). With respect to any particular swap transaction, the counterparty is required to make a payment to the Company in the event that the settlement price for any settlement period is less than the swap price for such transaction, and the Company is 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 such transaction. For any particular collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such transaction. For any particular floor transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with a floor transaction. For option contracts, the Company has 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.
The Company periodically enters into basis swaps (either as part of a particular hedging transaction or separately) tied to a particular NYMEX-based transaction to eliminate basis risk. Because substantially all of the Company's natural gas production is sold under spot contracts, that have historically correlated with the swap price, the Company believes that it has no material basis risk with respect to gas swaps that are not coupled with basis swaps.
For a description of certain bonding requirements related to offshore production proposed by the Minerals Management Service, see "Items 1 and 2. Business and Properties -- Environmental Matters."
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS
The financial statements required by this Item are incorporated under Item 14 in Part IV of this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III.
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item as to the directors and executive officers of the Company is hereby incorporated by reference from the information appearing under the captions "Election of Directors" and "Executive Officers" in the Company's definitive proxy statement which involves the election of directors and is to be filed with the Securities and Exchange Commission ("Commission") pursuant to the Securities Exchange Act of 1934 within 120 days of the end of the Company's fiscal year on December 31, 1997.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item as to the management of the Company is hereby incorporated by reference from the information appearing under the captions "Executive Compensation" and "Election of Directors - Director's Meetings and Compensation" in the Company's definitive proxy statement which involves the election of directors and is to be filed with the Commission pursuant to the Securities Exchange Act of 1934 within 120 days of the end of the Company's fiscal year on December 31, 1997. Notwithstanding the foregoing, in accordance with the instructions to Item 402 of Regulation S-K, the information contained in the Company's proxy statement under the sub-heading "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 Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item as to the ownership by management and others of securities of the Company is hereby incorporated by reference from the information appearing under the caption "Security Ownership of Certain Beneficial Owners and Management" to the Company's definitive proxy statement which involves the election of directors and is to be filed with the Commission pursuant to the Securities Exchange Act of 1934 within 120 days of the end of the Company's fiscal year on December 31, 1997.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item as to certain business relationships and transactions with management and other related parties of the Company is hereby incorporated by reference to such information appearing under the captions "Certain Transactions" and "Executive Compensation--Compensation Committee Interlocks and Insider Participation" in the Company's definitive proxy statement which involves the election of directors and is to be filed with the Commission pursuant to the Securities Exchange Act of 1934 within 120 days of the end of the Company's fiscal year on December 31, 1997.
PART IV.
ITEM 14.
ITEM 14. 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 notes thereto.
2. EXHIBITS:
Exhibits to the Form 10-K have been included only with the copies of the Form 10-K filed with the Commission and the New York Stock Exchange. Upon request to the Company and payment of a reasonable fee, copies of the individual exhibits will be furnished.
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* Filed herewith. ** Management contract or compensation plan.
(b) Reports on Form 8-K:
None
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.
THE HOUSTON EXPLORATION COMPANY
By: /s/ James G. Floyd ----------------------------------------- James G. Floyd Date: February 6, 1997 President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.
GLOSSARY OF OIL AND GAS TERMS
The definitions set forth below shall apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to herein 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 herein 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 which are 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 such 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 whereunder the owner of a working interest in an natural gas and oil lease assigns the working interest or a portion thereof 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 and/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.
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.
G-1 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.
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 such production exceed production expenses and taxes.
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 developed nonproducing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.
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.
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.
G-2 Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/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 oil or gas production free of costs of production.
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 such 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.
G-3
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited the accompanying combined balance sheets of The Houston Exploration Company (a Delaware corporation and an indirect 65%-owned subsidiary of KeySpan Energy Corporation) as of December 31, 1996 and 1997, and the related combined statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of The Houston Exploration Company, as of December 31, 1996 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York January 27, 1998
THE HOUSTON EXPLORATION COMPANY
COMBINED BALANCE SHEETS
The accompanying notes are an integral part of these combined financial statements.
THE HOUSTON EXPLORATION COMPANY
COMBINED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these combined financial statements.
THE HOUSTON EXPLORATION COMPANY
COMBINED STATEMENT OF STOCKHOLDERS' EQUITY
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(1) Includes $7.8 million related to the $12.0 million nonrecurring charge, net of the tax benefit of $4.2 million.
(2) See Note 3 -- Stockholders' Equity.
(3) Non-cash charge relating to the February 1996 Reorganization.
(4) See Note 4 -- Incentive Stock Option Plan.
The accompanying notes are an integral part of these combined financial statements.
THE HOUSTON EXPLORATION COMPANY
COMBINED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these combined financial statements.
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 1 -- SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
The Houston Exploration Company ("Houston Exploration" or the "Company"), a Delaware corporation, was incorporated in December 1985 and began operations in January 1986 for the purpose of conducting certain natural gas and oil exploration and development activities for The Brooklyn Union Gas Company ("Brooklyn Union"). Effective September 29, 1997, Brooklyn Union became a wholly-owned subsidiary of KeySpan Energy Corporation, ("KeySpan"). Prior to the Company's initial public offering in September 1996 (the "IPO"), the Company was an indirect wholly-owned subsidiary of Brooklyn Union. Subsequent to the IPO, Brooklyn Union holds 65% of the Company's outstanding common stock. The Company's operations focus on the exploration, development and acquisition of domestic natural gas and oil properties offshore in the Gulf of Mexico and onshore in South Texas, the Arkoma Basin, East Texas and West Virginia.
Effective February 29, 1996 Brooklyn Union implemented a reorganization of its exploration and production assets and liabilities by transferring to Houston Exploration certain onshore producing properties and acreage formerly owned by Fuel Resources Inc. ("FRI"), another subsidiary of Brooklyn Union. These combined financial statements have been prepared giving effect to the transfer of these assets and liabilities from the time of the acquisition of such assets and liabilities by Brooklyn Union. The transfer of assets and liabilities has been accounted for at historical cost as a reorganization of companies under common control in a manner similar to a pooling-of-interests and the 1995 financial statements reflect the combined historical results of Houston Exploration and the assets and liabilities transferred by Brooklyn Union.
Net Income (Loss) Per Share
In February 1997, the Financial Accounting Standards Board (the "FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings Per Share." The statement specifies the computation, presentation, and disclosure requirements for earnings per share ("EPS") and is designed to improve the EPS information provided in the financial statements by simplifying the existing computation. Primary EPS has been replaced with Basic EPS which is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the year. No dilution for any potentially dilutive securities is included. Fully diluted EPS is now called Diluted EPS and assumes the conversion of all potentially dilutive securities. The Company adopted SFAS No. 128 in its December 31, 1997 financial statements and has presented Diluted EPS for the years 1996 and 1995 which were previously not required as the dilutive effect of options and contingent shares was less than 3%. As of December 31, 1997, the Company had 2,333,276 options authorized, of which 1,640,098 were outstanding, and had an estimated 521,509 contingent shares of common stock payable to Soxco pursuant to the accrued minimum purchase price of $8.8 million (see Note 12 -- Acquisitions).
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Under the requirements of SFAS No. 128, the Company's EPS are as follows:
Reclassifications and Use of Estimates
The preparation of the combined financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The Company's most significant financial estimates are based on remaining proved natural gas and oil reserves. See Note 14 -- Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities. Because there are numerous uncertainties inherent in the estimation process, actual results could differ from the estimates. Certain reclassifications for prior years have been made to conform with current year presentation.
Natural Gas and Oil Properties
Natural gas and oil properties are accounted for using the full cost method of accounting. Under this method of accounting, all costs identified with acquisition, exploration and development of natural gas and oil properties, including leasehold acquisition costs, geological and geophysical costs, dry hole costs, tangible and intangible drilling costs, interest and the general and administrative overhead directly associated with these activities are capitalized as incurred. The Company computes the provision for depreciation, depletion and amortization of natural gas and oil properties on a quarterly basis using the unit-of-production method. The quarterly provision is calculated by multiplying the natural gas and oil production each quarter by a depletion rate determined by dividing the total unamortized cost of natural gas and oil properties (including estimates of the costs of future development and property abandonment and excluding the cost of significant investments in unproved and unevaluated properties) by net equivalent proved reserves at the beginning of the quarter. Natural gas and oil reserve quantities represent estimates only. Actual future production may be materially different from estimated reserve quantities and such differences could materially affect future amortization of natural gas and oil properties. The Company believes that unevaluated properties at December 31, 1997 will be fully evaluated within five years.
Proceeds from the dispositions of natural gas and oil properties are recorded as reductions of capitalized costs, with no gain or loss recognized, unless such adjustments significantly alter the relationship of unamortized capitalized costs and total proved reserves.
The Company limits the capitalized costs of natural gas and oil properties, net of accumulated depreciation, depletion and amortization and related deferred taxes to the estimated future net cash flows from proved natural gas and oil reserves discounted at ten percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the "full cost ceiling"). A current period charge to operating income is required to the extent that capitalized costs plus certain estimated costs for future property
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
development, plugging, abandonment and site restorations, net of related accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the full cost ceiling.
Other Property and Equipment
Other property and equipment include the costs of West Virginia gathering facilities which 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 equipment which are recorded at cost and depreciated using the straight-line method over estimated useful lives ranging between two to five years.
Income Taxes
Deferred taxes are determined 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. These differences relate primarily to (i) 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 (ii) provisions for depreciation and amortization for financial reporting purposes that differ from those used for income tax reporting purposes.
Prior to September 30, 1996, the Company was included in the consolidated federal income tax return of Brooklyn Union. Under the Company's tax sharing agreement with Brooklyn Union, the Company received or paid to Brooklyn Union an amount equal to the reduction or increase in the currently payable federal income taxes for Brooklyn Union resulting from the inclusion of the Company's taxable income or loss in the consolidated Brooklyn Union return, whether or not such amounts could be utilized on a separate return basis. For periods subsequent to September 1996, the Company is no longer included in the consolidated federal income tax return of Brooklyn Union and therefore calculates taxes on a separate return basis.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Inventories
Inventories consist primarily of tubular goods used in the Company's operations and are stated at the lower of cost or market value.
General and Administrative Costs and Expenses
The Company receives reimbursement for administrative and overhead expenses incurred on behalf of other working interest owners of properties operated by the Company. These reimbursements totaling $1.2 million, $1.0 million and $0.9 million for the years ended December 31, 1995, 1996 and 1997, respectively, were allocated as reductions to general and administrative expenses. The capitalized general and administrative costs directly related to the Company's acquisition, exploration and development activities, during 1995, 1996 and 1997, aggregated $4.1 million, $5.3 million and $7.2 million, respectively.
Capitalization of Interest
The Company capitalizes interest related to its unevaluated natural gas and oil properties and certain properties under development which are not currently being amortized. For the years ended December 31, 1995, 1996 and 1997 interest costs of $2.9 million, $3.5 million and $5.9 million, respectively, were capitalized.
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Gas Imbalances
The Company utilizes the entitlements method to account for its gas imbalances. Under this method, income is recorded based on the Company's net revenue interest in production or nominated deliveries. Net deliveries in excess of these amounts are recorded as liabilities, while net under deliveries are reflected as assets. Production imbalances are valued using current market prices. Production imbalances were not material as of December 31, 1996 and 1997.
Hedging
The Company utilizes derivative commodity instruments to hedge future sales prices on a portion of its natural gas production in order to achieve a more predictable cash flow and to reduce its exposure to adverse price fluctuations. These instruments include swaps, costless collars and options, and are usually placed with major financial institutions that the Company believes are minimal credit risks. The Company's hedging strategies meet the criteria for hedge accounting treatment under Statement of Financial Accounting Standards No. 80, "Accounting for Futures Contracts" ("SFAS 80"). Accordingly, gains and losses are recognized when the underlying transaction is completed, at which time these gains and losses are included in earnings as a component of natural gas revenues in accordance with a hedged transaction. Natural gas revenues were increased by $5.6 million in 1995, and were reduced by $11.1 million and $9.9 million during 1996 and 1997, relative to these contracts. See Note 8 -- Financial Instruments.
The Company regularly assesses the relationship between natural gas commodity prices in the "cash" and futures markets. The correlation between prices in these markets has been well within a range generally deemed to be acceptable. If correlation ceases to exist for more than a temporary period of time, the Company accounts for its financial instrument positions as trading activities and marks-to-market its open positions.
The Company also uses interest rate swaps to manage the interest rate exposure arising from certain borrowings. Swaps used to hedge debt are designated as hedges and are matched to the debt as to notional amount and maturity. The periodic receipts or payments from each swap are recognized ratably over the term of the swap as an adjustment to interest expense. Gains and losses resulting from the termination of hedge contracts prior to their stated maturity are recognized ratably over the remaining life of the instrument being hedged.
Concentration of Credit Risk
Substantially all of the Company's 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 the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically the Company has not experienced credit losses on such receivables.
New Accounting Pronouncements
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation," which is effective for years beginning after December 15, 1995. This statement encourages, but does not require companies to record compensation expense for stockbased compensation at fair value. The Company has chosen to continue to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees," and related Interpretations. Under APB No. 25, compensation expense is measured as the excess, if any, of the fair market value of the Company's stock at the date of grant over the price at which the option was granted. Compensation expense for phantom stock rights is recorded annually based on the quoted market price of the Company's stock at the end of the period. See Note 4 -- Incentive Stock Option Plans.
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
In February 1997, the FASB issued SFAS No. 129, "Disclosure of Information About Capital Structure," which consolidates the existing requirements to disclose certain information about an entity's capital structure, for both public and nonpublic entities. In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive Income," which establishes standards for reporting and display of comprehensive income and its components. Also issued in June of 1997 was SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information," which specifies and revises guidelines for determining an entity's operating and geographic segments and the type and level of financial information about those segments to be disclosed. The Company has adopted the provisions of SFAS Nos. 129, 130 and 131 in its 1997 financial statements. The adoption of SFAS Nos. 129, 130 and 131 did not have an effect on results of operations or the calculation of net income.
NOTE 2 -- LONG-TERM DEBT
Credit Facility. On July 2, 1996, the Company entered into a revolving credit facility ("Credit Facility") with a syndicate of lenders led by Chase Bank of Texas, National Association ("Chase"), which provides an aggregate commitment of $150 million, subject to borrowing base limitations, of which $130 million was the available borrowing base at December 31, 1997. In addition, up to $5 million of the Credit Facility is available for the issuance of letters of credit to support performance guarantees. The Credit Facility matures on July 1, 2000 and is unsecured. At December 31, 1997, $113 million was outstanding under the Credit Facility and $1.6 million was outstanding in letter of credit obligations.
Interest is payable on borrowings under the Credit Facility, at the Company's option, at an alternate base rate of the greater of the Federal Funds rate plus 0.5% or Chase's prime rate or at a margin of 0.375% to 1.125% above a quoted LIBOR rate. Interest is payable at calendar quarters on base rate loans and at maturity on LIBOR loans. In addition, a commitment fee of: (i) between 0.20% and 0.375% per annum on the unused portion of the Designated Borrowing Base, and (ii) 33% of the fee in (i) above on the difference between the lower of the Facility Amount or the Borrowing Base and the Designated Borrowing Base. The weighted average interest rate was 6.9%, 6.25% and 6.9%, respectively, for the years ended December 31, 1995, 1996 and 1997.
The Credit Facility, as amended, contains covenants of the Company, including certain restrictions on liens and financial covenants which require the Company to, among other things, maintain (i) an interest coverage ratio of 2.5 to 1.0 of earnings before interest, taxes and depreciation ("EBITDA") to cash interest and (ii) a total debt to capitalization ratio of less than 60%. In addition to maintenance of certain financial ratios, cash dividends and/or purchase or redemption of the Company's stock is restricted as well as the encumbering of the Company's gas and oil assets or the pledging of the assets as collateral. As of December 31, 1997, the Company was in compliance with all such covenants.
NOTE 3 -- STOCKHOLDERS' EQUITY
On September 19, 1996, the Company entered into an underwriting agreement with respect to the Company's IPO of its common stock at a price of $15.50 per share. The initial closing of the IPO, in which the Company issued 6,200,000 shares of common stock, was completed on September 25, 1996. The underwriters delivered notice of the exercise of their over-allotment option on September 30, 1996. The closing of the over-allotment, in which the Company issued an additional 930,000 shares of common stock, was completed on October 3, 1996. The Company received net proceeds of approximately $101.0 million from the total of 7,130,000 shares sold in the IPO.
Concurrently with the completion of the IPO, the Company's President exchanged certain of his after program-payout working interests valued at $2.3 million for 145,161 shares of common stock. In addition, concurrently with the completion of the IPO, the Company issued 762,387 shares of common stock valued at $11.8 million to Soxco in connection with the Soxco Acquisition. See Note 12 -- Acquisitions.
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- INCENTIVE STOCK OPTION PLANS
1994 Incentive Plan
On July 1, 1994, the Company adopted the Long-Term Stock Incentive Plan (the "1994 Incentive Plan"), and granted options to purchase 247,000 shares of common stock at $11.22 per share to certain officers and directors of Brooklyn Union. Options under the 1994 Incentive Plan were nonqualified and had tandem phantom option shares that gave the option holder the right to receive a cash payment five years from the grant date provided the Company was a privately held entity. At completion of the Company's IPO on September 20, 1996, all options under the 1994 Incentive Plan were canceled in exchange for a cash payment by the Company of $840,000. The Company recorded the $840,000 charge as compensation expense.
1996 Incentive Plan
At the completion of the IPO, the Company adopted the 1996 Stock Option Plan (the "1996 Incentive Plan"), which allows the Company to grant options not to exceed 10% of the shares of the Company's common stock outstanding from time to time. On September 20, 1996, the Company authorized 2,333,276 options and subsequently granted 1,697,238 options. The options granted under the 1996 Incentive Plan expire 10 years from the grant date and vest in one-fifth increments on each of the first five anniversaries of the grant date. During 1997, employees of the Company exercised 28,140 options at a weighted average price of $15.50. As of December 31, 1997, 266,188 options were vested and exercisable. No options were exercisable at December 31, 1996.
During 1997, the 1996 Incentive Plan was amended to allow option grants to non-employee directors of the Company. Options granted to non-employee directors vest on the date of grant. During 1997 the Company granted 49,000 options to non-employee directors at a grant price of $20.813.
Under the 1996 Incentive Plan, 1,048,770 of the options granted are incentive stock options ("ISOs") and the balance, 648,468 are nonqualified stock options ("NQSOs"). Common stock issued through the exercise of nonqualified options will result in a tax deduction for the Company equivalent to the taxable gain recognized by the optionee. Generally, the Company will not receive an income tax deduction for ISOs.
The following is a summary of option activity during the years ended December 31, 1995, 1996 and 1997:
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* Weighted average exercise price for the year.
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Phantom Stock Rights
On December 16, 1996, the Company granted key employees of Houston Exploration 176,470 phantom stock rights ("PSRs") that give the holder the right to receive a cash payment determined by reference to the fair market value of one share of the Company's common stock. Twenty percent (20%) of the PSRs are payable on December 16th of each of the years 1997 through 2001. On each date on which a PSR is payable, the holder will receive a cash payment equal to (i) the average of the closing prices per share of the Company's common stock for the five trading days immediately preceding such payment date multiplied by (ii) the number of PSRs payable on such date. During 1997, the Company made payments of $0.8 million for the vested portion of PSRs.
Effective October 1, 1997, the Company adopted an incentive compensation plan for non-employee, non-affiliated directors under which they 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. Phantom stock rights are exchanged for a cash distribution upon retirement.
Fair Value of Employee Stock-Based Compensation
The Company accounts for the Incentive Stock Plans using the intrinsic value method prescribed under APB No. 25 and accordingly no compensation expense has been recognized for stock options granted. Had stock options been accounted for using the fair value method as recommended in SFAS No. 123, compensation expense would have had the following pro forma effect on the Company's net income and earnings per share for the years ended December 31, 1995, 1996 and 1997:
The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts. SFAS No. 123 does not apply to awards prior to 1995. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions used for grants in 1996 and 1997: (i) risk-free interest rate of 6.66% in 1996 and 6.30% in 1997; (ii) expected lives of 5 years; (iii) expected dividends of zero; and (iv) expected volatility of 41%.
NOTE 5 -- INCOME TAXES
The components of the federal income tax provision (benefit) are:
The credit in the current provision for 1997 includes (i) proceeds of $1.2 million received in connection with the sale of Section 29 tax credits to Brooklyn Union during the first quarter of 1997 (see Note 6 --
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Related Party Transactions) and (ii) an adjustment to the 1996 tax return. Amounts received from Brooklyn Union pursuant to the previous tax-sharing agreement were $14.6 million and $13.7 million in 1995 and 1996, respectively. No amounts were received in 1997, as effective September 30, 1996, the Company became a stand alone tax entity and is no longer consolidated with Brooklyn Union.
The following is a reconciliation of statutory federal income tax expense (benefit) to the Company's income tax provision:
Deferred Income Taxes
The components of deferred tax assets and liabilities pursuant to SFAS No. 109 for the years ended December 31, 1996 and 1997 primarily represent temporary differences related to natural gas and oil properties.
NOTE 6 -- RELATED PARTY TRANSACTIONS
Sale of Section 29 Tax Credits
Effective January 1, 1997, the Company entered into an agreement to sell to a subsidiary of Brooklyn Union certain interests in onshore producing wells of the Company that produce from formations that qualify for tax credits under Section 29 of the Internal Revenue Code ("Section 29"). 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. Brooklyn Union acquired an economic interest in wells that are qualified for the tax credits and in exchange, the Company (i) retained a volumetric production payment and a net profits interest of 100% in the properties, (ii) received a cash down payment of $1.4 million and (iii) will receive a quarterly payment of $0.75 for every dollar of tax credit utilized. The Company will manage and administer the daily operations of the properties in exchange for an annual management fee of $100,000. At December 31, 1997, the balance sheet effect of this transaction was a $1.4 million reduction to the full cost pool for the down payment. The income statement effect for the year ended December 31, 1997 was a reduction to income tax expense of $1.2 million, representing benefits received from the Section 29 tax credits.
General and Administrative Expense
The Company reimburses Brooklyn Union for certain general and administrative costs. During the years ended December 31, 1995, 1996 and 1997, the Company paid Brooklyn Union $0.7 million, $0.6 million and $0.1 million in general and administrative reimbursements.
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Gas Sales
In 1992, the Company entered into a term supply agreement with BRING Gas Services Corp. ("BRING"), an affiliate of Brooklyn Union, at that time. As of April 1, 1995, this contract was superseded when the Company entered into a term supply agreement with PennUnion Energy Services, L.L.C. ("PennUnion"), successor to BRING, and an affiliate of Brooklyn Union. This contract was terminated in October 1996 with Brooklyn Union's sale of its interest in PennUnion. Under the terms of the agreement, the Company agreed to sell and PennUnion agreed to buy a substantial portion of the Company's production at index-related prices. The agreement contained provisions for both the commitment of gas reserves subsequently developed or acquired by the Company and the release of gas reserves sold, traded or exchanged to third parties.
For the years ended December 31, 1995 and 1996 the Company had natural gas sales of $18.9 million and $26.7 million, respectively, to PennUnion.
Employment Contracts
Prior to the IPO the Company maintained an employment agreement with its President and Chief Executive Officer which provided him with the option to participate in up to a 5% working interest in certain prospects of the Company. During 1995 and 1996, affiliates of the Company's President obtained a 5% working interest in 144 wells (which includes 142 Charco wells) operated by the Company pursuant to such agreement. In addition, during 1995, 1996 and 1997, affiliates of the Company's President paid $0.7 million, $1.4 million and $3.3 million, respectively, in expenses attributable to working interests owned in properties operated by the Company, and received $0.9 million, $1.6 million and $3.9 million, respectively, in distributions attributable to such working interests. See Note 12 -- Acquisitions.
The employment agreement also provided for the assignment to the President of a 2% net profits interest in all prospects of the Company and a 6.75% after program-payout working interest. In addition, the employment agreement provided for the assignment to certain key employees designated by the President of an overriding royalty interest equivalent in the aggregate to a four percent net revenue interest in certain properties acquired by the Company. Assignments were made in two wells during 1995; no assignments were made in 1996 or 1997. Upon completion of the IPO, the President's employment agreement was terminated and replaced with a new employment agreement, which does not provide the President with the option to participate in prospects of the Company or to receive or grant assignments or after program-payout working interests. In addition to the Company's President, certain other key employees of the Company entered into employment agreements upon completion of the IPO.
NOTE 7 -- EMPLOYEE BENEFIT PLANS
401(k) Profit Sharing Plan
The Company maintains a 401(k) Profit Sharing Plan (the "401(k) Plan") for its employees. Under the 401(k) Plan, eligible employees may elect to have the Company contribute on their behalf up to 10% of their base compensation (subject to certain limitations imposed under the Internal Revenue Code of 1986, as amended) on a before tax basis. The Company makes a matching contribution of $0.50 for each $1.00 of employee deferral, not to exceed 5% of an employee's base compensation, subject to limitations imposed by the Internal Revenue Service. The amounts contributed under the 401(k) Plan are held in a trust and invested among various investment funds in accordance with the directions of each participant. An employee's salary deferral contributions under the 401(k) Plan are 100% vested. The Company's matching contributions vest at the rate of 20% per year of service. Participants are entitled to payment of their vested account balances upon termination of employment. For the years ended December 31, 1995, 1996 and 1997, Company contributions to the 401(k) Plan were $157,000, $158,000 and $210,000, respectively.
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Supplemental Executive Plan
Effective immediately prior to the IPO, the Company adopted an unfunded, nonqualified Supplemental Executive Retirement Plan (the "SERP") for the benefit of James G. Floyd, the Company's President and Chief Executive Officer. The SERP provides that, if the executive remains with the Company until age 65, upon his retirement on or after age 65, the executive will be paid $100,000 per year for life. If, after retirement, the executive predeceases his spouse, 50% of the executive's SERP benefit will continue to be paid to the executive's surviving spouse for her life. During 1997 the Company accrued $123,000 related to the SERP and in 1996 no amounts were accrued as required accruals were de minimus.
NOTE 8 -- FINANCIAL INSTRUMENTS
Cash and Cash Equivalents
The carrying amount approximates fair value due to the short maturity of these instruments.
Long-Term Debt
The carrying amount of borrowings outstanding under the Credit Facility approximates fair value as the interest rate is tied to current market rates.
DERIVATIVE TRANSACTIONS
Interest Rate Swap Agreements
The fair values are obtained from the financial institutions that are counterparties to the transactions. These values represent the estimated amount the Company would pay or receive to terminate the agreements, taking into consideration current interest rates and the current creditworthiness of the counterparties. The Company's interest rate swap agreements are off balance sheet transactions and, accordingly, no respective carrying amounts for these transactions are included in the accompanying combined balance sheets at December 31, 1997. At December 31, 1997, the Company had two interest rate swap agreements to exchange an aggregate notional principal of $80.0 million over various periods from November 1996 through November 1999 at rates between 5.805% and 6.025%.
Commodity Related Transactions
The Company uses derivative financial instruments for non-trading purposes as a hedging strategy to reduce the impact of market volatility and to ensure cash flows. Gains and losses on these hedging transactions are recorded when the related natural gas has been produced or delivered. While derivative financial
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
instruments are intended to reduce the Company's exposure to declines in the market price of natural gas, the derivative financial instruments may limit the Company's gain from increases in the market price.
The derivative instruments used to hedge commodity transactions have historically had high correlation with commodity prices and are expected to continue to do so. The correlation of indices and prices is regularly evaluated to ensure that the instruments continue to be effective hedges. In the event that correlation falls below allowable levels, the gains or losses associated with the hedging instruments are immediately recognized to the extent that correlation was lost. In December of 1995, the Company recognized a pretax loss of $0.7 million due to the loss of correlation of the New York Mercantile Exchange ("NYMEX") futures market for natural gas with the market price for natural gas in certain parts of the country. The Company's hedges in place at December 31, 1996 or 1997 did not experience loss of market correlation.
Commodity Price Swaps
Price swap agreements call for one party to make monthly payments to (or receive from) another party based upon the differential between a fixed and a variable price (fixed-price swap) or two variable prices (basis swap) for a notional volume specified by the contract. The fair value is the estimated amount the Company would receive or pay to terminate swap agreements at year-end, taking into account the difference between NYMEX natural gas prices or index prices at year-end and fixed swap prices. NYMEX natural gas price closed at $3.61 per MMbtu and $2.68 per MMbtu at December 31, 1996 and 1997, respectively. At December 31, 1996 and 1997, the Company had fixed-price swap agreements and basis swap agreements to exchange a total notional volume of 23,278 MMbtu and 5,410 MMbtu, respectively, of natural gas over the period January 1996 through March 1998. The Company has no hedges in place past March 1998.
The Company is exposed to credit risk in the event of nonperformance by counterparties to futures and swaps contracts. The Company believes that the credit risk related to the futures and swap contracts is no greater than that associated with the primary contracts which they hedge, as these contracts are with major investment grade financial institutions, and that elimination of the price risk lowers the Company's overall business risk.
NOTE 9 -- SALES TO MAJOR CUSTOMERS
As is the nature of the exploration, development and production business, production is normally sold to relatively few customers. However, alternate buyers are available to replace the loss of any of the Company's major customers. For year ended December 31, 1995, PennUnion was the only customer for which natural gas sales exceeded 10% of total revenues and during 1995 sales to PennUnion comprised 46% of total revenues. For the year ended December 31, 1996, the Company sold natural gas production representing more than 10% of its total revenues to PennUnion (40%) and H&N Gas Ltd. (27%). For the year ended December 31, 1997, the Company's only customer to whom sales of natural gas production represented more than 10% of its total revenues was H&N Gas Ltd. (38%). The Company believes that prices at which it sold gas to PennUnion were similar to those it would be able to obtain in the open market. The Company also believes that the loss of H&N Gas Ltd. as a purchaser would not have a material adverse effect on the Company's operations. See Note 6 -- Related Party Transactions.
NOTE 10 -- COMMITMENTS AND CONTINGENCIES
Litigation
The Company is involved from time to time in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability thereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
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NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Leases
The Company has entered into certain noncancelable operating lease agreements relative to office space and equipment with various expiration dates through 2002. Minimum rental commitments under the terms of the leases are as follows:
Net rental expense related to these leases was $0.3 million for each of the years ended December 31, 1997, 1996 and 1995.
NOTE 11 -- NONRECURRING CHARGE
In connection with the February 1996 reorganization in which Brooklyn Union transferred certain onshore producing properties and acreage to the Company, certain former employees of FRI, the subsidiary of Brooklyn Union that previously owned the onshore properties, were entitled to remuneration for the increase in the value of the transferred properties prior to the reorganization. The Company incurred a $12 million non-cash charge in the quarter ended December 31, 1995 with respect to the remuneration to which such employees of FRI were entitled.
NOTE 12 -- ACQUISITIONS
TransTexas
On July 2, 1996, the Company acquired certain natural gas and oil properties and associated gathering pipelines and equipment located in Zapata County, Texas (the "TransTexas Acquisition") from TransTexas Gas Corporation and TransTexas Transmission Corporation (together, "TransTexas"). The Company acquired a 100% working interest (95% after the exercise by James G. Floyd, the Company's President and Chief Executive Officer, of his right to purchase a 5% working interest) in the approximately 142 wells on such properties. The purchase price of $62.2 million ($59.1 million after giving effect to the exercise of Mr. Floyd's purchase option) for the TransTexas Acquisition was reduced by $3.1 million for production revenue and expenses related to the assets between the May 1, 1996 effective date of the TransTexas Acquisition and July 2, 1996. The purchase price of the TransTexas Acquisition was paid in cash, financed with borrowings under the Company's Credit Facility.
The Company loaned Mr. Floyd the $3.1 million purchase price for his purchase of a 5% working interest in the properties purchased by the Company in the TransTexas Acquisition. In addition, the Company has agreed to loan Mr. Floyd, on a revolving basis, the amounts required to fund the expenses attributable to Mr. Floyd's working interest. Mr. Floyd is required to repay amounts owed under the loan in the amount of 65% of all distributions received by Mr. Floyd in respect of such working interest, as distributions are received. Amounts outstanding under such loan bear interest at an interest rate equal to the Company's cost of borrowing under the Credit Facility. Mr. Floyd's obligations under the agreement are secured by a pledge of his working interest in, and the production from, such properties. As of December 31, 1997, the outstanding balance owed by Mr. Floyd under the agreement was $3.7 million and the loan will mature on July 2, 2006.
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NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Soxco
On September 25, 1996, the Company acquired substantially all of the natural gas and oil properties and related assets (the "Soxco Acquisition") of Smith Offshore Exploration Company ("Soxco"). The natural gas and oil properties acquired in the Soxco Acquisition consisted solely of working interests in properties located in the Gulf of Mexico that are operated by the Company or in which the Company also has a working interest. Pursuant to the Soxco Acquisition, the Company paid Soxco cash in the aggregate amount of $20.3 million (net of $3.4 million for certain purchase price adjustments), and issued to Soxco 762,387 shares of common stock with an aggregate value (determined by reference to the IPO price) of $11.8 million. The cash portion of the purchase price was funded with the proceeds of the IPO. In addition to the foregoing, the Company will pay Soxco a deferred purchase price of up to $17.6 million effective January 31, 1998. The amount of the deferred purchase price will be determined by the probable reserves of Soxco as of December 31, 1995 (approximately 17.6 Bcfe) that are produced prior to or classified as proved as of December 31, 1996 and December 31, 1997, respectively, provided that Soxco is entitled to receive a minimum deferred purchase price of approximately $8.8 million. The amounts so determined will be paid in shares of common stock based on the fair market value of such stock at the time of issuance. At December 31, 1997, the Company believes it is probable that only the minimum payment will be required and as a result, $8.8 million has been accrued and reflected in current liabilities.
Pending Acquisition
On January 12, 1998, the Company entered into a non-binding letter of intent with respect to the acquisition of natural gas and oil properties located onshore in South Louisiana, representing 45 Bcfe of net proved reserves (the "South Louisiana Acquisition"). The average net production in December 1997 attributable to such properties was approximately 14 Mmcfe per day, net to the Company's interest. The non-binding letter of intent provides for the Company to pay $60 million for the properties to be acquired. The estimated purchase price of $60 million is less than 10% of the Company's total assets and income generated from these properties for the year ended December 31, 1997 was estimated to be less than 20% of the Company's income from operations.
NOTE 13 -- SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES
The following information concerning the Company's natural gas and oil operations has been provided pursuant to Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities." The Company's 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. The Company's natural gas and oil reserves were estimated by independent reserve engineers.
Capitalized Costs of Natural Gas and Oil Properties
As of December 31, 1995, 1996 and 1997, the Company's capitalized costs of natural gas and oil properties are as follows:
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The following is a summary of the costs (in thousands) which are excluded from the amortization calculation as of December 31, 1997, by year of acquisition. The Company is not able to accurately predict when these costs will be included in the amortization base; however, the Company believes that unevaluated properties at December 31, 1997 will be fully evaluated within five years.
Costs incurred for natural gas and oil exploration, development and acquisition are summarized below. Costs incurred during the years ended December 31, 1995, 1996 and 1997 include interest expense, general and administrative costs related to acquisition, exploration and development of natural gas and oil properties, of $7.0 million, $8.8 million and $13.1 million, respectively.
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(1) These amounts represent costs incurred by the Company and excluded from the amortization base until proved reserves are established or impairment is determined.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas and Oil Reserves (unaudited)
The following summarizes the policies used by the Company 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 such 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 such information in a manner comparable with industry peers.
The information is based on estimates of proved reserves attributable to the Company's interest in natural gas and oil properties as of December 31 of the years presented. These estimates were principally 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.
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NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
2. The estimated future cash flows are compiled by applying year-end prices of natural gas and oil relating to the Company's proved reserves to the year-end quantities of those reserves except for those reserves devoted to future production that is hedged. The estimated future cash flows associated with such reserves are compiled by applying the reference prices of such hedges to the future production that is hedged. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.
3. The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and certain 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 the Company's proved natural gas and oil reserves.
5. Future net cash flows are discounted to present value by applying a discount rate of 10 percent.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company's 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 standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves is as follows:
Future cash inflows include the effect of hedges in place at year end December 31, 1995, 1996 and 1997. At December 31, 1995, 1996, and 1997 the effect of the hedges in place is a reduction to future cash inflows of $4.4 million, $28.7 million and $0.5 million, respectively.
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NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes changes in the standardized measure of discounted future net cash flows:
ESTIMATED NET QUANTITIES OF NATURAL GAS AND OIL RESERVES (UNAUDITED)
The following table sets forth the Company's net proved reserves, including changes therein, and proved developed reserves (all within the United States) at the end of each of the three years in the period ended December 31, 1995, 1996 and 1997.
THE HOUSTON EXPLORATION COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 14 -- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Selected unaudited quarterly data is shown below:
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(1) Quarterly earnings per share are based on the weighted average number of shares outstanding during the quarter. Because of the increase in the number of shares outstanding during the third quarter of 1996, the sum of quarterly earnings per share do not equal earnings per share for the year.
INDEX TO EXHIBITS
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* Filed herewith. ** Management contract or compensation plan.