-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, JSRAVPnpIEALMFf4Pp4KCXt6jN2I6ffvGX8dnm+zIqqf59SMq1WjriwCsm5Hztr6 /arA15/nmkgX/mZ3MS7VgA== 0000890566-97-001432.txt : 19970626 0000890566-97-001432.hdr.sgml : 19970626 ACCESSION NUMBER: 0000890566-97-001432 CONFORMED SUBMISSION TYPE: 424B4 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19970625 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: DOMAIN ENERGY CORP CENTRAL INDEX KEY: 0001037192 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760526147 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: 1933 Act SEC FILE NUMBER: 333-24641 FILM NUMBER: 97629302 BUSINESS ADDRESS: STREET 1: 1100 LOUISIANA SUITE 1500 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7137575662 MAIL ADDRESS: STREET 1: P O BOX 2511 CITY: HOUSTON STATE: TX ZIP: 77252 424B4 1 [LOGO] DOMAIN ENERGY CORPORATION 6,000,000 Shares Common Stock ($.01 par value) ------------------ All of the shares of Common Stock, $.01 par value (the "Common Stock"), of Domain Energy Corporation (the "Company") offered hereby are being sold by the Company (the "Offering"). Concurrently with consummation of the Offering, the Company will sell 643,037 shares of Common Stock, at a price per share equal to the Price to Public set forth below, to First Reserve Fund VII, Limited Partnership ("Fund VII") for an aggregate purchase price of $8,681,000. Prior to the Offering, there has been no public market for the Common Stock of the Company. For information relating to the factors considered in determining the initial public offering price, see "Underwriting." The Common Stock has been approved for listing on the New York Stock Exchange, subject to notice of issuance, under the symbol "DXD." FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE COMMON STOCK, SEE "RISK FACTORS" BEGINNING ON PAGE 11 HEREIN. THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. UNDERWRITING DISCOUNTS PRICE TO AND PROCEEDS TO PUBLIC COMMISSIONS COMPANY(1) --------------------------------------- Per Share.............................. $13.50 $0.945 $12.555 Total(2)............................... $81,000,000 $5,670,000 $75,330,000 (1) Before deduction of expenses payable by the Company estimated at $1,000,000. (2) The Company has granted the Underwriters an option, exercisable for 30 days from the date of this Prospectus, to purchase a maximum of 900,000 additional shares to cover over-allotments of shares. If the option is exercised in full, the total Price to Public will be $93,150,000, Underwriting Discounts and Commissions will be $6,520,500, and Proceeds to Company will be $86,629,500. See "Underwriting." The shares of Common Stock are offered by the several Underwriters when, as and if issued by the Company, delivered to and accepted by the Underwriters and subject to their right to reject orders in whole or in part. It is expected that the shares of Common Stock offered hereby will be ready for delivery on or about June 27, 1997, against payment in immediately available funds. CREDIT SUISSE FIRST BOSTON PAINEWEBBER INCORPORATED PRUDENTIAL SECURITIES INCORPORATED MORGAN KEEGAN & COMPANY, INC. Prospectus dated June 23, 1997 [The paper version of this Prospectus contains a map of the Gulf of Mexico and the Gulf Coast of Texas, Louisiana and Mississippi, which indicates the locations of the Company's oil and gas properties in such region.] CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANS- ACTIONS THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK, INCLUDING OVER-ALLOTMENT OF COMMON STOCK, PURCHASES OF THE COMMON STOCK TO STABILIZE ITS MARKET PRICE, PURCHASES OF THE COMMON STOCK TO COVER SOME OR ALL OF A SHORT POSITION IN THE COMMON STOCK MAINTAINED BY THE UNDERWRITERS AND THE IMPOSITION OF PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING." PROSPECTUS SUMMARY THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY THE DETAILED INFORMATION AND FINANCIAL STATEMENTS AND THE NOTES THERETO APPEARING ELSEWHERE IN THIS PROSPECTUS. CERTAIN TERMS RELATING TO THE OIL AND GAS BUSINESS ARE DEFINED IN THE "GLOSSARY" SECTION OF THIS PROSPECTUS. UNLESS THE CONTEXT INDICATES OTHERWISE, REFERENCES IN THIS PROSPECTUS TO "DOMAIN" OR THE "COMPANY" ARE TO DOMAIN ENERGY CORPORATION, A DELAWARE CORPORATION, AND ITS SUBSIDIARIES, WHICH SUBSIDIARIES COMPRISE THE COMPANY'S PREDECESSOR BUSINESS UNIT. UNLESS THE CONTEXT INDICATES OTHERWISE, THE DISCUSSION IN THIS PROSPECTUS REFLECTS A 754-FOR-ONE STOCK SPLIT EFFECTED IMMEDIATELY PRIOR TO CONSUMMATION OF THE OFFERING AND ASSUMES THAT THE UNDERWRITERS' OVER-ALLOTMENT OPTION WITH RESPECT TO THE OFFERING IS NOT EXERCISED. UNLESS OTHERWISE INDICATED, THE PRO FORMA INFORMATION PRESENTED IN THIS PROSPECTUS GIVES EFFECT TO THE ACQUISITION, THE FUNDS ACQUISITION AND THE MICHIGAN DISPOSITION (AS SUCH TERMS ARE DEFINED BELOW), THE PURCHASE OF COMMON STOCK BY THE COMPANY'S EMPLOYEES IN 1997, THE GRANT OF OPTIONS TO PURCHASE COMMON STOCK TO THE COMPANY'S EMPLOYEES IN 1997, THE PURCHASE OF COMMON STOCK BY FIRST RESERVE FUND VII, LIMITED PARTNERSHIP CONCURRENTLY WITH CONSUMMATION OF THE OFFERING AND THE APPLICATION OF THE NET PROCEEDS OF THE OFFERING AS DESCRIBED IN "USE OF PROCEEDS." THE ESTIMATES OF THE COMPANY'S PROVED RESERVES AS OF DECEMBER 31, 1996 SET FORTH IN THIS PROSPECTUS ARE BASED ON THE REPORTS OF DEGOLYER AND MACNAUGHTON AND, IN THE CASE OF THE COMPANY'S WEST DELTA 30 FIELD AND FORMER MICHIGAN PROPERTIES, OTHER THIRD-PARTY PETROLEUM ENGINEERS. UNLESS OTHERWISE INDICATED, THE OPERATING AND RESERVE DATA SET FORTH HEREIN DOES NOT INCLUDE THE RESERVES OR RESERVE VALUE ATTRIBUTABLE TO THE COMPANY'S INDEPENDENT PRODUCER FINANCE PROGRAM. THE COMPANY Domain is an independent oil and gas company engaged in the exploration, development, production and acquisition of domestic oil and natural gas properties, principally in the Gulf Coast region. The Company complements these activities with its Independent Producer Finance Program (the "IPF Program") pursuant to which it invests in oil and natural gas reserves through the acquisition of term overriding royalty interests. During 1996, approximately 92% of the Company's revenue was generated by oil and natural gas sales and approximately 8% of the Company's revenue was generated by the IPF Program. The Company's future growth will be driven by development, exploitation and exploration drilling on its existing properties, by the continuation of an opportunistic acquisition strategy in the Gulf Coast region and by further expansion of the IPF Program. The Company was formed in December 1996 by the management of Tenneco Ventures Corporation and an affiliate of First Reserve Corporation to acquire (the "Acquisition") Tenneco Ventures Corporation and certain of its affiliates (collectively, "Tenneco Ventures"). Senior management of the Company established Tenneco Ventures in 1992 as a separate business unit of its former parent, Tenneco Inc. ("Tenneco"), to engage in exploration and production, oil and gas program management, producer financing and related activities. All of the Company's executive officers are veterans of the Tenneco organization, and 11 of the Company's 19 technical personnel have Tenneco Oil Company backgrounds. Approximately 85% of the Company's employees, including all of its management, have purchased shares of Common Stock in the Company. During the last four years, the Company has grown primarily through the opportunistic acquisition of Gulf of Mexico properties and the subsequent development, exploitation and exploration of these properties, resulting in substantial increases in its reserves and production. The Company believes that its acquisition costs, lease operating costs and net general and administrative costs on a per Mcfe basis are low relative to other companies operating principally in the Gulf Coast region. From 1994 through 1996, the Company completed 11 acquisitions aggregating $106.9 million, with an average cost of proved reserves estimated at the time of acquisition of $0.48 per Mcfe. Eight of the 11 acquisitions were Gulf Coast region properties. In 1996 the Company achieved a lease operating expense of $0.42 per Mcfe of production and a net general and administrative expense (excluding Tenneco overhead allocations) of $0.12 per Mcfe of production. 3 The Company's pro forma estimated net proved reserves as of December 31, 1996 were 153.8 Bcfe, and its pro forma average daily production during 1996 was 85.6 MMcfe, each of which represents a twelvefold increase from levels in 1993. Approximately 54% of these reserves were natural gas, and approximately 67% of proved reserves were classified as proved developed producing. On a pro forma basis as of December 31, 1996, the Company had a PV-10 Reserve Value of $213.0 million, which does not include reserve value attributable to the IPF Program. Through the IPF Program, the Company complements its exploration and production activities by providing capital to independent producers in return for term overriding royalty interests in oil and gas properties owned by such producers. From its inception in 1993 through December 31, 1996, the IPF Program has generated an average return on net assets of approximately 19%. In addition, the Company believes that the IPF Program offers a lower level of reserve, production and price risk than that associated with working interest ownership. From inception through December 31, 1996, the Company completed 40 transactions under its IPF Program. At December 31, 1996, based on Company estimates and assuming prices of $2.10 per Mcf of natural gas and $21.00 per Bbl of oil, the net present value attributable to IPF Program assets was $25.4 million. The Company reported net income of $7.0 million, $0.5 million and $0.4 million in 1996, 1995 and 1994, respectively. The Company reported unaudited net loss of $0.3 million and unaudited net income of $2.8 million for the three-month periods ended March 31, 1997 and 1996, respectively. Based on unaudited financial information available to the Company for the period from April 1, 1997 to the date of this Prospectus, the Company estimates that it will report net income (loss) on approximately a "break-even" basis for the three-month period ended June 30, 1997. Pro forma net income for the year ended December 31, 1996 was $11.8 million. See "-- Summary Historical and Pro Forma Combined and Consolidated Financial Data." The Company generated earnings before stock compensation expense, interest, income taxes, depreciation, depletion and amortization ("EBITDA") plus IPF Program return of capital of $41.1 million in 1996, $26.2 million in 1995 and $7.7 million in 1994. IPF Program return of capital was $4.6 million in 1996, $2.6 million in 1995 and $3.5 million in 1994. The Company's 1996 pro forma EBITDA plus IPF Program return of capital was $55.5 million. The Company's Board of Directors has authorized a capital budget of $125.0 million for 1997. These planned expenditures consist of $29.0 million for development and exploration expenditures, $36.0 million for IPF Program investments and $60.0 million for acquisitions in the Company's core operating area, $30.0 million of which is pending. See " -- Certain Transactions -- The Funds Acquisition." BUSINESS STRATEGY The Company's objective is to maximize shareholder value by growing reserves, production, cash flow and earnings through the opportunistic acquisition of Gulf Coast region properties with underexploited value. The Company applies 3-D seismic and other advanced technologies to development, exploitation and exploration. These activities are complemented by the continued expansion of the IPF Program. Fundamental to the execution of the Company's strategy is its foundation of experienced technical talent strengthened by a high level of financial, transactional and risk-management expertise resulting, in part, from the former association of the Company and its employees with Tenneco. Following the Offering, the Company will be in a strong financial position to pursue acquisitions and other growth opportunities. GEOGRAPHIC FOCUS. The Company concentrates its primary oil and gas activities in the Gulf Coast region, specifically in state and federal waters off the coast of Texas and Louisiana. The Company believes this region remains attractive for future development, exploration and acquisition activities. This is due to the availability of seismic data, significant reserve potential and a well developed infrastructure of gathering systems, pipelines and platforms with ready access to drilling services and equipment in the region. In addition, the Company's relationships with major oil companies and independent producers operating in the 4 region allow continued access to new opportunities. This geographic focus has enabled the Company to build and utilize a base of region-specific geological, geophysical, engineering and production expertise. The Company's geographic focus allows it to manage a large asset base with relatively few employees, thus permitting the Company to control expenses and add Gulf of Mexico production at a relatively low incremental cost. The Company engages in IPF Program activities throughout the onshore regions of the United States, with a principal geographic focus in the Gulf Coast region. ACQUISITION OF PROPERTIES WITH UNDEREXPLOITED VALUE. The Company employs an acquisition strategy targeted primarily at purchases of Gulf Coast region producing properties from major oil companies and large independents. These properties provide opportunities to increase reserves, production and cash flow through development and exploitation drilling and lease operating expense reduction. The Company manages its acquired properties by working proactively with its joint interest partners to accelerate development, identify exploitation opportunities and implement cost controls on these properties. DEVELOPMENT, EXPLOITATION AND EXPLORATION. The Company integrates its reservoir and production engineering expertise with its geologic and seismic interpretation abilities to enhance the results of its exploration and production business. The Company applies workovers, recompletions, secondary recovery operations and other production enhancement techniques on its existing properties to increase recoverable reserves, production and cash flow. Additionally, the Company uses advanced technology in both its development and exploration activities to reduce drilling risks and finding costs and to prioritize its drilling prospects based on return potential. The Company utilizes 3-D seismic data to develop the majority of its drilling opportunities. Eighty-five percent of the wells in which the Company participated in 1996 were developed using 3-D seismic data. The Company's ability to integrate geophysics with detailed geology, reservoir engineering and production engineering allows it to identify multiple development and exploratory prospects in mature producing fields that were not identified through earlier technologies. The Company currently employs six geoscientists with an average experience level of more than 16 years and operates two geophysical workstations interpreting 3-D seismic data over twelve fields and six exploratory programs. The Company intends to expand its geoscience team in 1997. The Company has assembled a multiyear inventory of development, exploitation and exploratory drilling opportunities in the Gulf Coast region and has identified more than 70 drilling and recompletion opportunities for 1997. Most of the properties comprising this inventory are located in fields that have well-established production histories. The Company believes these properties may yield significant additional recoverable reserves through the application of advanced exploration and development technologies. The Company participated in the drilling of nine development wells and 33 exploratory wells in 1996, of which 78% and 61%, respectively, were successful. CONTINUED EXPANSION OF THE IPF PROGRAM. The Company has leveraged its expertise in oil and gas reserve appraisal and evaluation to develop and grow the IPF Program. The Company believes this program offers an attractive risk/reward balance and stable earnings. The oil and gas companies that establish a relationship with the Company through the IPF Program often come to view the Company as a prospective working interest partner for their drilling or acquisition projects. Management believes that the investment opportunities, market information and business relationships generated as a result of the IPF Program provide the Company with a strategic advantage over other independent oil and gas companies that are not engaged in this business. As a result of the Company's efficiency in originating and closing IPF Program transactions in the $0.5 to $5.0 million range, the Company currently encounters only limited competition from alternate sources of capital for investment in quality properties and projects of independent oil and gas companies. The Company has budgeted $36.0 million for investment in IPF Program transactions in 1997. The Company closed six IPF Program transactions in the first quarter of 1997 for an aggregate of $9.2 million. In addition, the Company is currently evaluating over 30 transactions, all of which satisfy the Company's initial screening criteria. 5 CERTAIN TRANSACTIONS ACQUISITION OF COMMON STOCK BY FUND VII. Concurrently with consummation of the Offering, First Reserve Fund VII, Limited Partnership, the Company's principal stockholder ("Fund VII"), has agreed to purchase 643,037 shares of Common Stock, at a price per share equal to the Price to Public set forth on the cover of this Prospectus, for an aggregate purchase price of $8,681,000 (the "Concurrent Sale"). See "Transactions with Management and First Reserve -- Acquisition of Common Stock by Fund VII." THE FUNDS ACQUISITION. The Company previously sponsored and managed two oil and gas investment programs (collectively, the "Funds") for institutional investors. The Company has entered into a definitive agreement with the investors in the Funds to acquire certain property interests from such investors upon consummation of the Offering (the "Funds Acquisition"). These property interests are primarily located in the Gulf Coast region and have combined proved reserves of 33.0 Bcfe. Furthermore, these interests include 18,209 net undeveloped leasehold acres with 3-D seismic-based exploration potential. The Company will acquire these property interests at an aggregate cost of $30.0 million, effective January 1, 1997, for a unit cost of $0.65 per Mcfe of net proved reserves. The Funds Acquisition will provide the Company with a larger interest in certain of its existing properties, including the West Delta 30 Field in the Gulf of Mexico. THE MICHIGAN DISPOSITION. The Company recently sold its interests in a natural gas development project located in northwestern Michigan (the "Michigan Development Project"). The Company views this transaction (the "Michigan Disposition") as a disposition of non-core assets and a further enhancement of its focus on the Gulf Coast region. As a result of the Michigan Disposition, the Company sold 28.8 Bcfe of proved reserves as of December 31, 1996 (of which 3.3 Bcfe were proved developed producing as of December 31, 1996) and interests in a pipeline company and a processing company. See "Unaudited Condensed Pro Forma Financial Statements" and the related notes thereto. DEVELOPMENT, EXPLOITATION AND EXPLORATION PROJECTS RABBIT ISLAND FIELD. In 1993 the Company purchased a 25% interest in the Rabbit Island Field located in Louisiana state waters. The field has produced in excess of 1.2 Tcf of gas and 46 MMBbls of oil. A 105 square-mile 3-D survey was interpreted in 1993, and six of seven wells drilled since that time have been successful, discovering 34.3 Bcfe of gross proved reserves (7.2 Bcfe net to the Company's interest). The Company, Texaco Exploration and Production Inc. ("Texaco") and Shell Offshore Inc. ("Shell") are conducting a joint field study to delineate additional exploitation opportunities in this field. This study is expected to be completed in the third quarter of 1997. The preliminary results of the study indicate at least 25 potential exploitation opportunities. WEST DELTA 30. In 1995 the Company purchased a 70% working interest in the West Delta 30 Field in the Gulf of Mexico from Shell and initiated an integrated geological, geophysical and 3-D seismic study in the first half of 1996. As a result of this study, the Company identified eight additional development drilling locations and three deeper pool prospects that the Company believes have significant exploratory potential. Based on the Company's proposal, Exxon Company, U.S.A. ("Exxon"), the operator, is drilling a well to test this field's deeper exploratory potential and is scheduled to drill a development well by year-end 1997. MATAGORDA ISLAND 519. In late 1994 the Company purchased 13 producing fields in the Gulf of Mexico from Pennzoil Company ("Pennzoil") for $51.3 million (the "Pennzoil Acquisition"), including the Matagorda Island 519 Field. The Company owns working interests of 15.8% and 25% in this field, which is operated by Amoco Production Company ("Amoco"). Workover operations on two wells in this field were completed in the first quarter of 1997, increasing gross production by 10 MMcf per day. Workover operations to recomplete a third well are in progress. The Company believes that significant development and exploratory potential remains in the field. Amoco has purchased a 3-D seismic survey to delineate these opportunities, in which the Company owns a 25% working interest. 6 HIGH ISLAND 110/111. The Company purchased its initial interest in this Texaco-operated field as part of the Pennzoil Acquisition and currently holds a 17% working interest. The Company has identified several recompletion zones and two proved undeveloped drilling locations in the field using 3-D seismic data to reinterpret an internal field study. These wells are scheduled to be drilled in 1997. WASSON FIELD. In June 1996 the Company acquired a 34.7% working interest in the Cornell Unit in the Wasson Field in West Texas. Approximately 1.5 billion Bbls of oil have been produced from the San Andres reservoir from which the Cornell Unit produces. The field was initially waterflooded in 1965, and a CO2 flood was initiated in 1985 utilizing the water alternating-gas injection method of enhanced oil recovery. Because the field has been restored to its original pressure as the result of tertiary recovery activities, at year-end 1996 the Company recommended the cessation of CO2 purchases for the next four to five years. This recommendation was adopted by the unit working interest owners. As a result, the Company expects to increase its annual cash flow from the field by $1.9 million. The Company, working with unit operator Exxon, has identified up to 30 infill drilling locations. Furthermore, pressure tests performed recently in an adjoining unit indicate that the upper gas-bearing sands may be produced separately from the oil reservoir. Exxon and the Company plan to test the feasibility of producing these gas-bearing sands in 1997. THE OFFERING Common Stock offered by the Company pursuant to the Offering.............. 6,000,000 shares Common Stock to be sold concurrently with the Offering to Fund VII......... 643,037(1) Common Stock to be outstanding after the Offering and the Concurrent Sale.................................. 14,306,721 shares(2) Use of proceeds......................... The net proceeds to the Company of the Offering and the Concurrent Sale are estimated to be approximately $83.0 million ($94.3 million if the Underwriters' over-allotment option is exercised in full) and will be used (i) to pay the purchase price of the Funds Acquisition and (ii) to repay $52.2 million of indebtedness outstanding under the Company's existing credit facilities, with the balance to be used for general working capital purposes. See "Use of Proceeds." New York Stock Exchange Symbol.......... DXD - ------------ (1) See "Transactions With Management and First Reserve -- Acquisition of Common Stock by Fund VII." (2) Does not include 849,694 shares of Common Stock reserved for issuance pursuant to outstanding options under the Amended and Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain Energy Corporation and Affiliates (the "Stock Purchase and Option Plan"). See "Management -- Stock Purchase and Option Plan" and " -- Stock Option Agreements." 7 SUMMARY HISTORICAL AND PRO FORMA COMBINED AND CONSOLIDATED FINANCIAL DATA The following summary historical financial data are derived from the financial statements of the Company as of and for the periods presented. The summary historical financial data for the three-month periods ended March 31, 1996 and 1997 are derived from financial statements that are unaudited but include all adjustments, consisting of normal recurring adjustments, that the Company considers necessary for a fair presentation of its financial position and results of operations for these periods. The results for the three months ended March 31, 1997 are not necessarily indicative of the results for the full year. The summary unaudited pro forma data are derived from the Unaudited Condensed Pro Forma Financial Statements of the Company included elsewhere in this Prospectus. The unaudited pro forma income statement data and other financial data for the year ended December 31, 1996 and the three months ended March 31, 1997 give effect to (i) the Acquisition, (ii) the Michigan Disposition, (iii) the completion of the Offering, (iv) the completion of the Concurrent Sale and (v) the completion of the Funds Acquisition, as if all such transactions occurred on January 1, 1996. The unaudited pro forma balance sheet data as of March 31, 1997 give effect to (i) the purchase of Common Stock by the Company's employees in April 1997, (ii) the Michigan Disposition, (iii) the completion of the Offering, (iv) the completion of the Concurrent Sale and (v) the completion of the Funds Acquisition as if all such transactions occurred on March 31, 1997. The pro forma financial data are not necessarily indicative of actual results of operations or financial position that would have occurred if these transactions were completed on the indicated dates or of future results of operations. The summary historical and pro forma financial data below should be read in conjunction with "Capitalization," "Unaudited Condensed Pro Forma Financial Statements," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and the Combined and Consolidated Financial Statements of the Company and the related notes thereto included elsewhere in this Prospectus.
YEAR ENDED DECEMBER 31, THREE MONTHS ENDED ------------------------------------------- MARCH 31, PREDECESSOR ------------------------------------- ------------------------------- PRO FORMA PREDECESSOR SUCCESSOR PRO FORMA 1994 1995 1996 1996 1996 1997 1997 --------- --------- --------- --------- ----------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) INCOME STATEMENT DATA: Revenues: Oil and natural gas sales(1)........ $ 5,340 $ 34,877 $ 52,274 $70,746 $15,688 $12,782 $16,538 IPF Activities(2)................... 1,417 2,356 4,369 4,369 340 732 732 Other............................... 283 414 (413) 198 115 (292) 185 --------- --------- --------- --------- ----------- --------- --------- Total revenues................. 7,040 37,647 56,230 75,313 16,143 13,222 17,455 --------- --------- --------- --------- ----------- --------- --------- Expenses: Lease operating..................... 1,790 7,980 10,207 14,438 2,127 3,060 4,078 Production and severance taxes...... 18 710 1,340 1,492 279 413 469 Depreciation, depletion and amortization...................... 3,101 22,692 24,920 22,866 7,613 3,282 4,046 General and administrative, net..... 52 2,780 3,361 3,653 1,089 792 828 Corporate overhead allocation....... 944 2,627 4,827 4,827 939 -- -- Stock compensation.................. -- -- -- -- -- 3,150 3,150 --------- --------- --------- --------- ----------- --------- --------- Total operating expenses....... 5,905 36,789 44,655 47,276 12,047 10,697 12,571 --------- --------- --------- --------- ----------- --------- --------- Income from operations.................. 1,135 858 11,575 28,037 4,096 2,525 4,884 Interest expense, net................... -- -- 150 8,865 -- 1,109 (6) --------- --------- --------- --------- ----------- --------- --------- Income before income taxes.............. 1,135 858 11,425 19,172 4,096 1,416 4,890 Income tax provision.................... 735 351 4,394 7,338 1,342 1,735 3,054 --------- --------- --------- --------- ----------- --------- --------- Net income (loss)....................... $ 400 $ 507 $ 7,031 $11,834 $ 2,754 $ (319) $ 1,836 ========= ========= ========= ========= =========== ========= ========= Net income (loss) per share(3).......... $ 0.78 $ (0.03) $ 0.12 Common stock and common stock equivalents outstanding............... 15,156 9,156 15,156
(TABLE CONTINUED ON FOLLOWING PAGE) 8
YEAR ENDED DECEMBER 31, THREE MONTHS ENDED ------------------------------------------- MARCH 31, PREDECESSOR ------------------------------------- ------------------------------- PRO FORMA PREDECESSOR SUCCESSOR PRO FORMA 1994 1995 1996 1996 1996 1997 1997 --------- --------- --------- --------- ----------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) OTHER FINANCIAL DATA: Operating income.................... $ 1,135 $ 858 $ 11,575 $28,037 $ 4,096 $ 2,525 $ 4,884 Net cash provided by operating activities........................ 11,487 19,933 34,553 -- 5,715 8,112 -- Net cash used in investing activities........................ (86,669) (39,728) (47,329) -- (10,634) (7,577) -- Net cash provided by financing activities........................ 85,014 8,328 12,776 -- 5,285 5,511 -- Capital expenditures(4)............. 85,205 49,904 28,145 58,145 4,848 2,276 32,276 OTHER NON-GAAP FINANCIAL DATA: EBITDA(5)........................... 4,236 23,550 36,495 50,903 11,709 8,957 12,080 IPF Program return of capital(6).... 3,507 2,638 4,618 4,618 517 3,426 3,426 EBITDA plus IPF Program return of capital........................... 7,743 26,188 41,113 55,521 12,226 12,383 15,506
AS OF MARCH 31, 1997 ---------------------------- HISTORICAL PRO FORMA ----------- ---------- (IN THOUSANDS) BALANCE SHEET DATA: Cash and cash equivalents........... $ 6,082 $ 8,711 Property, plant and equipment, net................................ 63,636 93,636 IPF Program notes receivable........ 27,530 27,530 Total assets........................ 125,664 148,064 Long-term debt (including current maturities)........................ 83,838 24,508 Stockholders' equity................ 32,493 114,904 - ------------ (1) Oil and natural gas sales increased from $5.3 million in 1994 to $52.3 million in 1996 primarily as a result of the Company's acquisition of producing properties in 1994 and 1995, results of drilling activities in 1994, 1995 and 1996, and an increase in the net realized price of gas in 1996 relative to 1994 and 1995. (2) IPF Activities includes income from the Company's IPF Program and the Company's "GasFund" partnership with a financial investor. See "Business and Properties -- Producer Investment Activities." (3) Net income per share on a pro forma basis has been computed based on the net income shown above and assuming that the 7,177,681 shares of Common Stock purchased in connection with the Acquisition, the 486,003 shares of Common Stock purchased by the Company's employees in 1997, the 849,694 shares of Common Stock reserved for issuance pursuant to outstanding options under the Stock Purchase and Option Plan, the 6,000,000 shares of Common Stock to be issued pursuant to the Offering and the 643,037 shares of Common Stock to be issued to Fund VII concurrently with consummation of the Offering have been outstanding since January 1, 1996. (4) Pro forma capital expenditures data excludes the Acquisition. (5) EBITDA represents earnings before stock compensation expense, interest, income taxes, depreciation, depletion and amortization. The Company believes that EBITDA may provide additional information about the Company's ability to meet its future requirements for debt service, capital expenditures and working capital. EBITDA is a financial measure commonly used in the oil and gas industry and should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income and may vary among companies, the EBITDA calculation presented above may not be comparable to similarly titled measures of other companies. (6) To more accurately reflect the actual cash flow generated by the Company, IPF Program return of capital is identified separately to allow such cash receipts to be combined with EBITDA. ======================== Based on unaudited financial information available to the Company for the period from April 1, 1997 to the date of this Prospectus, the Company estimates that it will report net income (loss) on approximately a "break-even" basis for the three-month period ended June 30, 1997. 9 SUMMARY OIL AND NATURAL GAS RESERVE DATA The following table summarizes the estimates of the Company's historical and pro forma net proved oil and natural gas reserves as of the dates indicated and the present value attributable to the reserves at such dates. The reserve and present value data as of December 31, 1994, 1995 and 1996 have been prepared by DeGolyer and MacNaughton and other third-party petroleum engineers. See "Business and Properties -- Oil and Natural Gas Reserves." Summaries of the December 31, 1996 reserve reports and the letters of the third-party petroleum engineers with respect thereto are included as Appendix A to this Prospectus. The operating and reserve data set forth below does not include the Company's term overriding royalty interests and associated reserves acquired through the IPF Program. AS OF DECEMBER 31, ------------------------------------------- PRO FORMA 1994 1995 1996(1) 1996(2) ------- -------- -------- -------- PROVED RESERVES: Natural gas (MMcf) .......... 73,399 82,682 81,338 83,418 Oil and condensate (MBbls) .. 4,109 2,197 11,380 11,736 Total (MMcfe) ............... 98,056 95,865 149,616 153,834 PV-10 Reserve Value (in thousands) ................ $61,812 $103,931 $184,816 $213,030 Percent of proved developed producing reserves ........ 53.4% 55.0% 61.3% 66.5% Reserve Life Index (in years)(3) ................. -- 4.7x 6.0x 4.9x RESERVE REPLACEMENT DATA: Finding costs (per Mcfe) .... $ 0.91 $ 1.13 $ 0.51 $ 0.66 Production replacement ratio(4) .................. 3,117.9% 222.8% 217.9% 276.8% - ------------ (1) Includes the Company's proportionate share of reserves attributable to the Michigan Development Project. (2) Gives effect to the Michigan Disposition and the Funds Acquisition as if such transactions were consummated as of January 1, 1996. (3) Calculated by dividing year-end proved reserves by annual actual or pro forma production (as applicable) for the most recent year. The Company's Reserve Life Index for 1994 was 34.6 and is excluded from the above table because it reflects the Company's completion of a large acquisition in late 1994 and does not reflect production attributable to that acquisition for a full-year period. (4) Equals current period reserve additions through acquisitions of reserves, extensions and discoveries, and revisions to prior estimates divided by the production for such period. SUMMARY OPERATING DATA
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------------------ ------------------------------------ PRO FORMA PREDECESSOR SUCCESSOR PRO FORMA 1994 1995 1996 1996(1) 1996 1997 1997(1) --------- --------- --------- --------- ----------- --------- --------- PRODUCTION VOLUMES: Natural gas (MMcf)............... 2,334 18,065 21,192 25,714 5,828 3,668 4,586 Oil and condensate (MBbls)....... 83 424 564 920 116 141 199 Total (MMcfe).................... 2,832 20,609 24,575 31,234 6,524 4,516 5,780 AVERAGE REALIZED PRICES:(2) Natural gas (per Mcf)............ $ 1.76 $ 1.54 $ 1.97 $ 2.06 $ 2.36 $ 2.75 $ 2.74 Oil and condensate (per Bbl)..... 14.93 16.76 18.63 19.43 16.52 19.06 20.07 EXPENSES (PER MCFE): Lease operating.................. $ 0.63 $ 0.39 $ 0.42 $ 0.46 $ 0.33 $ 0.68 $ 0.71 Production taxes................. 0.01 0.03 0.05 0.05 0.04 0.09 0.08 Depreciation, depletion and amortization................... 1.03 1.08 1.01 0.71 1.19 0.69 0.70 General and administrative, net(3)......................... 0.26 0.16 0.12 0.12 0.14 0.14 0.14
- ------------ (1) Gives effect to the Michigan Disposition and the Funds Acquisition as if such transactions were consummated as of January 1, 1996. (2) Reflects the actual realized prices received by the Company, including the results of the Company's hedging activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Matters -- Hedging Activities." (3) Includes production attributable to properties managed for the Funds for the periods indicated and excludes fees received from investors and overhead allocations from Tenneco. Including Tenneco allocations, average net general and administrative expenses per Mcfe for the years ended December 31, 1994, 1995 and 1996 would be $0.26, $0.20 and $0.28, respectively. 10 RISK FACTORS THIS PROSPECTUS CONTAINS FORWARD-LOOKING STATEMENTS. THE WORDS "ANTICIPATE," "BELIEVE," "EXPECT," "PLAN," "INTEND," "SEEK," "ESTIMATE," "PROJECT," "WILL," "COULD," "MAY" AND SIMILAR EXPRESSIONS ARE INTENDED TO IDENTIFY FORWARD-LOOKING STATEMENTS. THESE STATEMENTS INCLUDE INFORMATION REGARDING OIL AND GAS RESERVES, FUTURE ACQUISITIONS, FUTURE DRILLING AND OPERATIONS, FUTURE CAPITAL EXPENDITURES, FUTURE PRODUCTION OF OIL AND GAS AND FUTURE NET CASH FLOW. SUCH STATEMENTS REFLECT THE COMPANY'S CURRENT VIEWS WITH RESPECT TO FUTURE EVENTS AND FINANCIAL PERFORMANCE AND INVOLVE RISKS AND UNCERTAINTIES, INCLUDING WITHOUT LIMITATION, THE RISKS DESCRIBED UNDER THIS CAPTION "RISK FACTORS." SHOULD ONE OR MORE OF THESE RISKS OR UNCERTAINTIES OCCUR, OR SHOULD UNDERLYING ASSUMPTIONS PROVE INCORRECT, ACTUAL RESULTS MAY VARY MATERIALLY AND ADVERSELY FROM THOSE ANTICIPATED, BELIEVED, ESTIMATED OR OTHERWISE INDICATED. CONSEQUENTLY, ALL OF THE FORWARD-LOOKING STATEMENTS MADE IN THIS PROSPECTUS ARE QUALIFIED BY THESE CAUTIONARY STATEMENTS AND THERE CAN BE NO ASSURANCE THAT THE ACTUAL RESULTS OR DEVELOPMENTS ANTICIPATED BY THE COMPANY WILL BE REALIZED OR, EVEN IF SUBSTANTIALLY REALIZED, THAT THEY WILL HAVE THE EXPECTED CONSEQUENCES TO OR EFFECTS ON THE COMPANY OR ITS BUSINESS OR OPERATIONS. THE FOLLOWING RISK FACTORS SHOULD BE CONSIDERED CAREFULLY IN ADDITION TO THE OTHER INFORMATION CONTAINED IN THIS PROSPECTUS BEFORE PURCHASING THE SHARES OF COMMON STOCK OFFERED HEREBY. VOLATILITY OF OIL AND NATURAL GAS PRICES; MARKETABILITY OF PRODUCTION The Company's financial condition, profitability, future rate of growth and ability to borrow funds or obtain additional capital, as well as the carrying value of its oil and natural gas properties, are substantially dependent upon prevailing prices of, and demand for, oil and natural gas. The energy markets have historically been, and are likely to continue to be, volatile, and prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, the actions of the Organization of Petroleum Exporting Countries, domestic and foreign governmental regulations, political stability in the Middle East and other petroleum producing areas, the foreign and domestic supply of oil and natural gas, the price of foreign imports, the price and availability of alternative fuels and overall economic conditions. A substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company's financial position, results of operations, quantities of oil and natural gas reserves that may be economically produced, carrying value of its proved reserves, borrowing capacity and access to capital. In addition, the marketability of the Company's production depends upon a number of factors beyond the Company's control, including the availability and capacity of transportation and processing facilities, the effect of federal and state regulation of oil and natural gas production and transportation, changes in supply due to drilling by other producers and changes in demand. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." RISK OF HEDGING ACTIVITIES The Company's use of energy swap arrangements to reduce its sensitivity to oil and natural gas price volatility is subject to a number of risks. If the Company's reserves are not produced at the rates estimated by the Company due to inaccuracies in the reserve estimation process, operational difficulties or regulatory limitations, or otherwise, the Company would be required to satisfy its obligations under potentially unfavorable terms. If the Company enters into financial instrument contracts for the purpose of hedging prices and the estimated production volumes are less than the amount covered by these contracts, the Company would be required to mark-to-market these contracts and recognize any and all losses within the determination period. Further, under financial instrument contracts the Company may be at risk for basis differential, which is the difference in the quoted financial price for contract settlement and the actual physical point of delivery price. The Company will from time to time attempt to mitigate basis differential risk by entering into basis swap contracts. Substantial variations between the assumptions and estimates used by the Company in its hedging activities and actual results experienced could materially adversely affect the Company's anticipated profit margins and its ability to manage risk associated with fluctuations in 11 oil and natural gas prices. Furthermore, the fixed price sales and hedging contracts limit the benefits the Company will realize if actual prices rise above the contract prices. As of March 31, 1997, on a pro forma basis, approximately 34.6% of the Company's projected 1997 oil production and approximately 45.3% of its projected 1997 natural gas production were committed to hedging contracts. In addition, the Company has hedges in place covering a portion of its projected oil production through the year 2000. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Matters -- Hedging Activities." RESERVE REPLACEMENT RISKS The Company's future performance is dependent upon its ability to identify, acquire and develop additional oil and natural gas reserves that are economically recoverable. Without successful drilling or acquisition activities, the Company's reserves and revenues will decline. No assurances can be given that the Company will be able to identify, acquire or develop additional reserves at an acceptable cost. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors beyond the Company's control. This assessment is necessarily inexact and its accuracy is inherently uncertain. In connection with such an assessment, the Company typically performs, or retains a third party to perform, a review of the subject properties, which review the Company believes is generally consistent with industry practices. This review, however, will not reveal all existing or potential problems, nor will it permit the Company to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. The Company generally assumes preclosing liabilities, including environmental liabilities, in connection with property acquisitions and generally acquires interests in the properties on an "as is" basis. With respect to its acquisitions to date, the Company has no material commitments for capital expenditures to comply with existing environmental requirements. There can be no assurance that any properties acquired by the Company will be successfully developed or produced, and any such properties that are not successfully developed or produced could have a material adverse effect on the Company. Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that any new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. In addition, the Company's use of 3-D seismic requires greater pre-drilling expenditures than traditional drilling strategies. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including economic conditions, mechanical problems, title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. There can be no assurances that any of the Company's future drilling activities will be successful, and unsuccessful drilling activities by the Company may have a material adverse effect on the Company. See "Business and Properties -- Operating Hazards and Drilling Risks." NON-OPERATOR STATUS With the exception of the Mustang Island 846/847 Field and the Company's interests in Michigan, all of the Company's oil and gas properties are operated by others. As a result, the Company has a limited ability to exercise control over operations or the associated costs of such operations. The success of the Company's investment in a drilling or acquisition activity is therefore dependent upon a number of factors that are outside of the Company's control, including the competence and financial resources of the operator. Such factors include the availability of future capital resources of the other participants for the drilling of wells and the approval of other participants of the drilling of wells on the properties in which the Company has an interest. The Company's reliance on the operator and other working interest owners and its limited 12 ability to control certain costs could have a material adverse effect on the realization of expected rates of return on the Company's investment in drilling or acquisition activities. OPERATING RISKS The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. Any of these occurrences could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Moreover, offshore operations are subject to a variety of operating risks peculiar to the marine environment, including hurricanes or other adverse weather conditions, more extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage) and interruption or termination of operations by governmental authorities based on environmental or other considerations. The presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause a drilling or production operation to be unsuccessful, resulting in a total loss of the Company's investment in such operation. Although the Company maintains insurance coverage it believes is customary in the industry for companies of similar size, it is not fully insured against certain of these risks, either because such insurance is not available or because of the high premium costs. The Company does not carry business interruption insurance. There can be no assurance that any insurance obtained by the Company will be adequate to cover any losses or liabilities, or that such insurance will continue to be available or available on terms that are acceptable to the Company. See "Business and Properties -- Operating Hazards and Drilling Risks." RELIANCE ON ESTIMATES OF OIL AND NATURAL GAS RESERVES The reserve data set forth in this Prospectus represent only estimates of DeGolyer and MacNaughton ("DeGolyer"), Netherland, Sewell & Associates, Inc. ("Netherland, Sewell"), and other third-party petroleum engineers. The estimation of reserve data is a subjective process of estimating the recovery of underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of the available data, the assumptions made, and engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows therefrom necessarily depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. Any such estimates are therefore inherently imprecise, and estimates by other engineers, or by the same engineers at a different time, might differ materially from those included herein. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in the estimates, and it is likely that such variances will be significant. Any significant variance from the assumptions could result in the actual quantity of the Company's reserves and future net cash flows therefrom being materially different from the estimates set forth in this Prospectus. In addition, the Company's estimated reserves may be subject to downward or upward revision, based upon production history, results of future exploration and development, prevailing oil and natural gas prices, operating and development costs and other factors. The Company's properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. See "Business and Properties -- Oil and Natural Gas Reserves." The present value of future net cash flows set forth in this Prospectus should not be construed as the current market value or the value at any prior date of the estimated oil and natural gas reserves attributable to the Company's properties. In accordance with applicable requirements of the Securities and Exchange Commission (the "Commission"), the estimated discounted future net cash flows from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are 13 contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. In addition, the 10% discount factor used to calculate the present value of future net cash flows is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general. CERTAIN RISKS AFFECTING THE COMPANY'S IPF PROGRAM The Company's IPF Program involves an up-front cash payment for the purchase of a term overriding royalty interest pursuant to which the Company receives an agreed upon share of revenues from identified properties. The producer's obligation to deliver such revenues is nonrecourse to the producer insofar as the producer generally is not liable to the Company for any failure to meet its payment obligation except for such failures attributable to the producer's failure to operate prudently, title failure or certain other causes within the control of the producer. Consequently, the Company's ability to realize successful investments through its producer finance business is subject to the Company's ability to estimate accurately the volumes of recoverable reserves from which the applicable production payment is to be discharged and the operator's ability to recover these reserves. The Company's interest is believed to constitute a property interest and, therefore, in the event of the producer's bankruptcy or similar event, outside of the reach of the producer's creditors; however, such creditor (or the producer as debtor-in-possession or a trustee for the producer in a bankruptcy proceeding) may argue that the transaction should be characterized as a loan, in which case the Company may have only a creditor's claim for repayment of the amounts advanced. As non-operating interests, the Company's ownership of these production payments should not expose the Company to liability attendant to the ownership of direct working interests, such as environmental liabilities and liabilities for personal injury or death or damage to the property of others, although no assurances can be made in this regard. Finally, as the producer's obligation is only to deliver a specified share of revenues, subject to the ability of the burdened reserves to produce such revenues, the Company bears the risk that future revenues delivered will be insufficient to amortize the purchase price paid by the Company for the interest or to provide any investment return thereon. The Company operates the IPF Program through its indirect wholly-owned subsidiary, Domain Energy Finance Corporation ("IPF Company"). IPF Company has a $100.0 million revolving credit facility with a bank (the "IPF Company Credit Facility") pursuant to which it finances a portion of the IPF Program. The borrowing base under the facility as of May 7, 1997 was $23.0 million. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- IPF Company Credit Facility." EFFECTS OF LEVERAGE On a pro forma basis as of March 31, 1997, the Company would have had total consolidated indebtedness for money borrowed of approximately $24.5 million (consisting of approximately $12.2 million outstanding under the Company's revolving credit facility with a group of banks (the "Revolving Credit Facility") and approximately $12.3 million outstanding under the IPF Company Credit Facility) and stockholders' equity of approximately $114.9 million. The Company intends to incur additional indebtedness for money borrowed in the future, including in connection with the exploration for, and development, production and acquisition of, oil and natural gas properties. These activities could cause the Company's leverage to increase, which could have important consequences to its stockholders, including the following: (i) the Company's ability to obtain additional financing for working capital, capital expenditures, acquisitions or general corporate purposes could be impaired in the future; (ii) a substantial portion of the Company's cash flow from operations could be required for the payment of principal and interest on its indebtedness for money borrowed, thereby reducing the funds available to the Company for its operations and other purposes; (iii) the Company may be substantially more leveraged than certain of its competitors, which could place the Company at a competitive disadvantage; and (iv) the Company's substantial degree 14 of leverage could hinder its ability to adjust rapidly to changing market conditions and could make it more vulnerable in the event of a downturn in general economic conditions or its business. In addition, the Company's borrowings are and are expected to continue to be at variable rates, which exposes the Company to the risk of increased interest rates. See " -- Substantial Capital Requirements" and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources - -- Revolving Credit Facility." The Company's ability to make scheduled payments of principal of and to pay interest on, or to refinance, its indebtedness for money borrowed depends upon its future performance and successful strategy implementation, which is subject not only to its own actions but also to general economic, financial, competitive, legislative, regulatory and other factors beyond its control, as well as to the prevailing market prices for oil and natural gas. There can be no assurance that the Company's business will generate sufficient cash flow from operations or that future credit will be available in an amount sufficient to enable the Company to service its indebtedness for money borrowed, or make necessary capital expenditures. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." RESTRICTIVE DEBT COVENANTS The Revolving Credit Facility contains covenants that, among other things, restrict the ability of the Company to dispose of assets, incur additional indebtedness or grant liens on its properties, repay other indebtedness, pay dividends, enter into certain investments or acquisitions, repurchase or redeem capital stock, engage in mergers or consolidations, or engage in certain transactions with subsidiaries and affiliates and that will otherwise restrict corporate activities. There can be no assurance that such restrictions will not adversely affect the Company's ability to finance its future operations or capital needs or engage in other business activities that may be in the interests of the Company. In addition, the Revolving Credit Facility requires the Company to maintain a specified minimum tangible net worth and to comply with certain prescribed financial ratios. The ability of the Company to maintain such tangible net worth or to comply with such ratios may be affected by events beyond the Company's control. A breach of any of these covenants or the inability of the Company to maintain such tangible net worth or to comply with the required financial ratios could result in a default under the Revolving Credit Facility. The Company believes that the Company is currently in compliance with the terms of the Revolving Credit Facility. However, in the event of any such default, the lenders thereunder (the "Lenders") could elect to terminate the Company's ability to borrow thereunder, to declare all borrowings outstanding thereunder, together with accrued interest and other fees, to be immediately due and payable, and to exercise foreclosure or other remedies against the Company and its assets. The Revolving Credit Facility is secured by approximately 80% of the aggregate value of the Company's oil and natural gas properties and substantially all of the Company's other property (other than the IPF Program properties), including the capital stock of the Company's operating subsidiaries. Although the remaining approximately 20% of the aggregate value of the Company's oil and natural gas properties is not mortgaged to the Lenders under the Revolving Credit Facility, such properties are nevertheless subject to the restrictions set forth therein, including a prohibition on granting any security interests therein. If the indebtedness under the Revolving Credit Facility were to be accelerated, there can be no assurance that the assets of the Company would be sufficient to repay such indebtedness in full. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Revolving Credit Facility." The IPF Company Credit Facility restricts the ability of the IPF Company to dividend cash to its parent, Domain Energy Ventures Corporation, or otherwise advance cash to the Company. Consequently, cash generated by the IPF Company may not be available to the Company, whether for repayment of the Revolving Credit Facility or for other purposes. The IPF Company Credit Facility is secured by substantially all of IPF Company's oil and gas interests, including the notes receivable generated therefrom. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources - -- IPF Company Credit Facility." 15 SUBSTANTIAL CAPITAL REQUIREMENTS Historically, the Company has financed its activities primarily with internally generated funds and advances from Tenneco. The Company currently has plans for substantial capital expenditures to continue its exploration, development, production and acquisition activities. In 1997, excluding acquisitions, the Company's budget for capital expenditures and IPF Program investments is $65.0 million. The Company's business plan is dependent upon the Company's ability to obtain financing beyond its internally generated cash flow, for exploring for, developing, producing and acquiring oil and natural gas properties. Management believes that the Company will have sufficient cash provided by operating activities and borrowings under the Revolving Credit Facility to fund planned capital expenditures in 1997. The Revolving Credit Facility limits the amounts the Company may borrow thereunder to amounts determined by the Lenders in their sole discretion, based upon the Lenders' projection of the Company's discounted future net revenues from oil and natural gas properties and other considerations, and restricts the amounts the Company may borrow under other credit facilities. The Lenders may periodically adjust the borrowing base under the Revolving Credit Facility and may require that outstanding borrowings in excess of the borrowing base be repaid within 30 days of the date such excess occurs. All amounts owed under the Revolving Credit Facility are due and payable on December 31, 1999. In addition, the borrowing base under the Revolving Credit Facility is scheduled to be redetermined as of December 31, 1997 and may be reduced substantially from its March 31, 1997 level of $63.3 million. All amounts outstanding in excess of such reduced borrowing base must be paid in full at such date. If revenues or the Company's borrowing base decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or otherwise, the Company's ability to expend the capital necessary to undertake or complete future activities may be significantly limited. No assurances can be given that the Company will have adequate funds available to it under the Revolving Credit Facility to carry out its strategy or that the Company will be able to make any mandatory principal payments required by the Lenders. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and " -- Revolving Credit Facility." CONTROL BY EXISTING STOCKHOLDERS AND POTENTIAL CONFLICTS OF INTEREST Upon completion of the Offering and the Concurrent Sale, the Company's existing stockholders will own approximately 58.1% of the outstanding shares of Common Stock (approximately 54.6% if the Underwriter's over-allotment option is exercised in full). First Reserve Fund VII, Limited Partnership, a Delaware limited partnership ("Fund VII"), the managing general partner of which is First Reserve Corporation, a Delaware corporation ("First Reserve"), individually will own approximately 54.7% of the outstanding shares of Common Stock (approximately 51.4% if the Underwriter's over-allotment option is exercised in full). As a result of such stock ownership, the Company's existing stockholders, as a group, and Fund VII, individually, will be able to elect all members of the Company's board of directors (the "Board of Directors") and to control the vote on matters submitted to the Board of Directors or stockholders, including, without limitation, matters relating to the Company's exploration, development, capital, operating and acquisition expenditure plans, as well as mergers and other business combinations, asset sales, financings, issuances of securities and other significant transactions. Such concentration of ownership of Common Stock may have an adverse effect on the market price of the Common Stock. Conflicts of interest may arise in the future between the Company and First Reserve and its affiliates with respect to, among other things, potential competitive business activities or business opportunities, issuances of additional shares of voting securities, the election of directors or the payment of dividends, if any, by the Company or the exercise by First Reserve, as managing general partner of Fund VII, of its ability to control the management and affairs of the Company. There are no contractual or other restrictions on the ability of First Reserve or its affiliates to engage in oil and gas exploration and production or to pursue other investment opportunities in the energy industry. Circumstances could arise in the future in which the Company and First Reserve or its affiliates engage in activities in competition with one another. 16 DEPENDENCE ON KEY PERSONNEL The Company's operations are dependent upon a relatively small group of management and technical personnel. The loss of one or more of these individuals could have a material adverse effect on the Company. The Company in particular is substantially dependent on the efforts of Michael V. Ronca, its President and Chief Executive Officer. If Mr. Ronca becomes unable or unwilling to continue in his present role, the Company's business, operations and prospects would be adversely affected. In connection with the consummation of the acquisition by the Company of the capital stock of its operating subsidiaries, Mr. Ronca entered into an Employment Agreement with the Company (the "Ronca Employment Agreement"). Under the terms of the Ronca Employment Agreement, Mr. Ronca would be entitled to terminate his employment (i) upon a "Change of Control," which is defined therein as the acquisition by any person or entity, or group thereof, excluding Fund VII and other affiliates of First Reserve, of more than 50% of the outstanding voting stock of the Company, or (ii) otherwise for "Good Reason," which is defined therein to include, among other things, material reductions in Mr. Ronca's duties, responsibilities or base salary. See "Management -- Ronca Employment Agreement." The Company does not maintain key person life insurance for Mr. Ronca or any of its other personnel. COMPETITION The Company encounters competition from other companies in all areas of its operations, including the acquisition of producing properties and its IPF Program. The Company's competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs and, in the case of its IPF Program, affiliates of investment, commercial and merchant banking firms and affiliates of large interstate pipeline companies. Many of its competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than the Company and which, in many instances, have been engaged in the oil and gas business for a much longer time than the Company. Such companies may be able to pay more for producing oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future, as well as its ability to grow its IPF Program, will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. GOVERNMENTAL REGULATION AND ENVIRONMENTAL MATTERS Oil and natural gas operations are subject to various federal, state and local governmental laws and regulations that may be changed from time to time in response to economic, political or other conditions. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of such resources. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. These laws and regulations have imposed increasingly strict requirements for water and air pollution control and solid waste management. To date, the Company's expenditures related to compliance with these laws and regulations have not been significant, although no assurances can be given that such expenditures will not be significant in the future. The Company believes that the trend of more expansive and stricter environmental legislation and regulations, including regulations that may be promulgated under the Oil Pollution Act of 1990, will continue, and that such legislation and regulations may result in additional costs to the Company in the future. Amendments to the Resource Conservation and Recovery Act to regulate further the handling, transportation, storage and disposal of oil and natural gas exploration and production wastes have been 17 considered by Congress and may be adopted. Such legislation, if enacted, could have a material adverse impact on the Company's operating costs. See "Business and Properties -- Regulation." NO PRIOR PUBLIC MARKET; POSSIBLE VOLATILITY OF STOCK PRICE; DILUTION Prior to the Offering, there has been no public market for the Common Stock. The initial public offering price will be determined by negotiations among the Company, First Reserve and the Underwriters and may not be indicative of the future market price for the Common Stock. See "Underwriting" for a discussion of the factors to be considered in determining the initial public offering price. The Common Stock has been approved for listing on the New York Stock Exchange, subject to notice of issuance. However, no assurance can be made that an active trading market for the Common Stock will develop or, if developed, that it will be sustained. The market price of the Common Stock could also be subject to significant fluctuation in response to variations in results of operations and other factors. In addition, Fund VII and certain employees of the Company acquired their shares of Common Stock (other than the Common Stock to be purchased by Fund VII pursuant to the Concurrent Sale) at a per share price that is substantially less than the initial public offering price. Investors in the Common Stock offered hereby will experience immediate and substantial dilution in the net tangible book value of their shares of Common Stock. At an initial public offering price of $13.50 per share, the dilution to new investors will be $5.47 per share. These investors will also experience additional dilution upon the exercise of outstanding options for the Common Stock. See "Dilution." SHARES ELIGIBLE FOR FUTURE SALE The Company, each of the Company's directors and executive officers and Fund VII have agreed not to dispose of any shares of Common Stock without the prior consent of Credit Suisse First Boston Corporation for a period of 180 days from the date of this Prospectus other than pursuant to the Offering or in connection with the Company's employee benefit plans. The shares of Common Stock held by the Company's officers and by Fund VII are deemed "restricted securities" within the meaning of Rule 144 under the Securities Act of 1933, as amended (the "Securities Act"), and may be resold after the 180-day period only upon registration under the Securities Act or pursuant to an exemption from registration, including exemptions contained in Rule 144. Pursuant to the terms of the Securityholders Agreement, dated as of December 31, 1996, among the Company, Fund VII and the Company's officers who have subscribed for Common Stock, upon the consummation of the Offering and after expiration of the 180-day period referred to above, Fund VII will have the right to demand registration of its shares of Common Stock. See "Transactions With Management and First Reserve - -- Securityholders Agreement." Fund VII has informed the Company that it has no immediate plans to sell or otherwise dispose of shares of the Common Stock. As of the date hereof, options exercisable for 849,694 shares of Common Stock are outstanding under the Amended and Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain Energy Corporation and Affiliates (the "Stock Purchase and Option Plan"). Generally, all shares issued upon the exercise of such options will be freely tradeable under the Securities Act. Sales of substantial amounts of Common Stock in the public market, or the perception of the availability of shares for sale, following the Offering could adversely affect the prevailing market price of the Common Stock. The Company is unable to make any prediction as to the effect, if any, that the future sales of Common Stock or the availability of Common Stock for sale will have on the market price of the Common Stock prevailing from time to time. See "Shares Eligible for Future Sale." BLANK CHECK PREFERRED STOCK The Company's Amended and Restated Certificate of Incorporation (the "Certificate of Incorporation") authorizes "blank check" preferred stock, which may have the effect of discouraging unsolicited acquisition proposals. See "Description of Capital Stock -- Preferred Stock." 18 USE OF PROCEEDS The net proceeds to the Company of the Offering and the Concurrent Sale are estimated to be approximately $83.0 million ($94.3 million if the Underwriters' over-allotment option is exercised in full), after deducting underwriting discounts and commissions and estimated Offering expenses. The Company will use approximately $30.0 million of the net proceeds to consummate the Funds Acquisition. The Company will use $52.2 million of the proceeds to the Company of the Offering and the Concurrent Sale to repay $47.2 million of indebtedness outstanding under the Revolving Credit Facility and $5.0 million of indebtedness outstanding under the IPF Company Credit Facility. The remainder of the net proceeds will be used for general working capital purposes of the Company. Pending application of the net proceeds of the Offering, such net proceeds will be invested in short-term, interest bearing instruments. In December 1996, the Company entered into the Revolving Credit Facility under which the borrowing base was $63.3 million as of March 31, 1997. At such date, borrowings outstanding under the Revolving Credit Facility totalled $59.5 million. The initial borrowings under the Revolving Credit Facility were used to finance a portion of the costs of the Acquisition. The Revolving Credit Facility is a three-year revolving credit facility with the entire outstanding principal amount maturing on December 31, 1999. In addition, the borrowing base under the Revolving Credit Facility may be redetermined by the Lenders at any time and is scheduled to be redetermined as of December 31, 1997. Following any such redetermination, the borrowing base may be reduced substantially from its then current level. All amounts outstanding in excess of such reduced borrowing base must be paid in full at such date. Absent a default or an event of default (as defined therein), outstanding borrowings under the Revolving Credit Facility accrue interest at LIBOR plus a margin of 1.50% to 2.50% per annum depending on the total amount drawn or, at the option of the Company, at the greater of (i) the prime rate and (ii) the federal funds effective rate plus one-half of 1%, plus a margin of 0.50% to 1.50% depending on the total amount drawn. As of March 31, 1997, the weighted average interest rate applicable to outstanding borrowings under the Revolving Credit Facility was 8.05% per annum. For a description of the Revolving Credit Facility, including certain mandatory prepayment terms, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Revolving Credit Facility." IPF Company is a party to the IPF Company Credit Facility, which provides for a maximum $100.0 million revolving line of credit. Borrowings under this facility are used to finance IPF Company's investment activities under the IPF Program. The IPF Company Credit Facility matures June 1, 1999 at which time all amounts owed thereunder are due and payable. The borrowing base under the facility as of March 31, 1997 was $18.0 million and is subject to a scheduled redetermination by the lender every six months and such other redeterminations as the lender may elect to perform each year. Effective as of May 7, 1997, the borrowing base under the facility was increased to $23.0 million. As of March 31, 1997, approximately $17.3 million was outstanding under the IPF Company Credit Facility and the weighted average interest rate applicable to such outstanding amount was 7.857% per annum. So long as no default or event of default (as defined therein) is outstanding, borrowings under the IPF Company Credit Facility accrue interest at LIBOR plus a margin of 2.25% or, at the option of IPF Company, the prime rate published in THE WALL STREET JOURNAL. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- IPF Company Credit Facility." DIVIDEND POLICY The Company intends to retain its earnings to provide funds for reinvestment in the Company's businesses, including exploration, development and production activities, and, therefore, does not anticipate declaring or paying cash dividends in the foreseeable future. The Company is a holding company that conducts substantially all of its operations through its subsidiaries. As a result, the Company's ability to pay dividends on the Common Stock would be dependent on the cash flows of its subsidiaries. Payment of dividends is also subject to then existing business conditions and the business results, cash requirements and financial condition of the Company, and will be at the discretion of the Board of Directors. In addition, the terms of the Revolving Credit Facility currently prohibit the payment of dividends by the Company. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." 19 CAPITALIZATION The following table sets forth (i) the capitalization of the Company as of March 31, 1997 and (ii) the pro forma capitalization of the Company as of March 31, 1997 after giving effect to the purchase of Common Stock by the Company's employees in April 1997, the Michigan Disposition, the issuance of 6,000,000 shares of Common Stock in this Offering and the application of the estimated net proceeds therefrom as described under "Use of Proceeds" and the purchase by Fund VII of 643,037 shares of Common Stock concurrently with consummation of the Offering. This table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Combined and Consolidated Financial Statements of the Company and the related notes thereto included elsewhere in this Prospectus. MARCH 31, 1997 ------------------------- HISTORICAL PRO FORMA ---------- ----------- (IN THOUSANDS) Current maturities of long-term debt.... 23,500 -- Long-term debt.......................... $ 60,338 $ 24,508 Stockholders' equity: Preferred stock, $.01 par value, no shares authorized and outstanding; 5,000,000 shares authorized and none outstanding pro forma........ -- -- Common stock, $.01 par value, 15,080,000 shares authorized; 7,567,988 shares issued and outstanding; 25,000,000 shares authorized and 14,306,721 shares issued and outstanding pro forma......................... 76 143 Additional paid-in capital......... 33,282 116,375 Notes receivable -- stockholders... (546) (546) Retained earnings.................. (319) (1,068) ---------- ----------- Total stockholders' equity.............. 32,493 114,904 ---------- ----------- Total capitalization.................... $ 116,331 $ 139,412 ========== =========== 20 DILUTION "Dilution" means the difference between the initial public offering price per share of Common Stock and the pro forma net tangible book value per share of Common Stock after giving effect to the Offering. "Net tangible book value per share" represents the amount of total tangible assets less total liabilities divided by the total number of shares of Common Stock outstanding. At March 31, 1997, after giving effect to the purchase of Common Stock by the Company's employees in April 1997, the Company's pro forma net tangible book value was $32.9 million, or approximately $4.29 per share of Common Stock. Assuming the sale of 6,000,000 shares pursuant to the Offering, the use of the net proceeds thereof as specified in "Use of Proceeds" and the sale of 643,037 shares of Common Stock at a price of $13.50 per share to Fund VII concurrently with consummation of the Offering and the use of the proceeds thereof to repay outstanding indebtedness under the Revolving Credit Facility, the pro forma net tangible book value of the Company at March 31, 1997 would have been $8.03 per share, representing an immediate increase in pro forma net tangible book value of $3.74 per share to the Company's existing stockholders and an immediate dilution in pro forma net tangible book value of $5.47 per share to new investors purchasing shares of Common Stock in the Offering. The following table illustrates such pro forma per share dilution at March 31, 1997: Initial public offering price per share ........ $ 13.50 Pro forma net tangible book value per share at March 31, 1997 .............. $ 4.29 Increase per share attributable to new investors (including Fund VII) ....... 3.74 --------- Pro forma net tangible book value per share after the Offering and the Concurrent Sale ...................... 8.03 --------- Dilution per share to new investors ............ $ 5.47 ========= The following table sets forth the number of shares of Common Stock purchased from the Company, the total consideration paid, and the average price per share paid by existing stockholders and to be paid by Fund VII pursuant to the Concurrent Sale and by purchasers of shares of Common Stock offered hereby (before deducting underwriting discounts and commissions and estimated offering expenses):
SHARES PURCHASED TOTAL CONSIDERATION AVERAGE ---------------------- ------------------------- PRICE NUMBER PERCENT AMOUNT PERCENT PER SHARE ------------ ------- --------------- ------- --------- Existing stockholders.... 7,663,684 53.6% $32,031,354 26.3% $ 4.18 New investors (including Fund VII).............. 6,643,037 46.4% 89,681,000 73.7% 13.50 ------------ ------- --------------- ------- Total............... 14,306,721 100.0% $121,712,354 100.0% ============ ======= =============== =======
The foregoing computations do not include 424,847 shares of Common Stock issuable upon exercise of outstanding employee stock options at an exercise price of $4.18 and 424,847 shares of Common Stock issuable upon exercise of outstanding employee stock options at an exercise price of $.01 per share. See "Management -- Stock Option Agreements." 21 UNAUDITED CONDENSED PRO FORMA FINANCIAL STATEMENTS On December 31, 1996, the Company completed the Acquisition pursuant to which it acquired all of the outstanding capital stock of its operating subsidiaries from El Paso Natural Gas Company for an aggregate purchase price of approximately $96.2 million and the assumption of liabilities of approximately $16.8 million. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General." In April 1997 the Company completed the Michigan Disposition pursuant to which it sold its interests in a natural gas development project located in northwestern Michigan to Energy Acquisition Corp., a Colorado corporation. See "Business and Properties -- Certain Transactions -- The Michigan Disposition." Concurrently with the consummation of the Offering, the Company expects to complete the Concurrent Sale pursuant to which Fund VII will purchase 643,037 shares of Common Stock for an aggregate purchase price of $8,681,000. See "Transactions with Management and First Reserve -- Acquisition of Common Stock by Fund VII." Upon consummation of the Offering, the Company expects to complete the Funds Acquisition pursuant to which it will acquire certain net profits overriding royalty interests owned by three institutional investors. The Company will acquire these interests for an aggregate cost of $30.0 million. See "Business and Properties -- Certain Transactions -- The Funds Acquisition." The unaudited pro forma consolidated balance sheet as of March 31, 1997 gives effect to (i) the sale of 95,696 shares of Common Stock to the Company's employees in April 1997 for an aggregate purchase price of $400,000, (ii) the Michigan Disposition, (iii) the completion of the Offering, (iv) the completion of the Concurrent Sale and (v) the completion of the Funds Acquisition, as if all such transactions had occurred on March 31, 1997. The unaudited pro forma consolidated income statements for the year ended December 31, 1996 and for the three months ended March 31, 1997 give effect to (i) the Acquisition, (ii) the Michigan Disposition, (iii) the completion of the Offering, (iv) the completion of the Concurrent Sale and (v) the completion of the Funds Acquisition, as if all such transactions (the "Transactions") had occurred on January 1, 1996. The unaudited condensed pro forma balance sheet is based on the unaudited Consolidated Balance Sheet of the Company included elsewhere in this Prospectus. The unaudited condensed pro forma income statements are based on the historical Combined Statements of Income of the Company and unaudited financial information related to the Funds Acquisition. The pro forma adjustments are based upon available information and certain assumptions that management of the Company believes are reasonable. Management of the Company does not believe that any possible deviations will be material to the pro forma financial statements. The pro forma financial information does not purport to represent what the Company's financial position or results of operations would actually have been had the Transactions in fact occurred on such dates. In addition, the pro forma financial statements are not necessarily indicative of the results of future operations of the Company and should be read in conjunction with "Capitalization," "Management's Discussion and Analysis of Financial Condition and Results of Operations," and the Combined and Consolidated Financial Statements of the Company and the related notes thereto included elsewhere in this Prospectus. 22 DOMAIN ENERGY CORPORATION UNAUDITED CONDENSED PRO FORMA BALANCE SHEET MARCH 31, 1997
ADJUSTMENTS FOR ADJUSTMENTS SUBTOTAL ADJUSTMENTS EMPLOYEE FOR FOR ADJUSTMENTS FOR ADJUSTMENTS FOR OFFERING IN MICHIGAN COMPLETED FOR CONCURRENT PENDING FUNDS HISTORICAL APRIL 1997 DISPOSITION TRANSACTIONS OFFERING SALE ACQUISITION ---------- ----------- ----------- ------------ ----------- ----------- --------------- (IN THOUSANDS, EXCEPT SHARE DATA) ASSETS Cash and cash equivalents............ $ 6,082 $ 400(a) $ 2,229 (b) $ 8,711 $ 30,000 (c) $-- $(30,000)(e) Restricted certificate of deposit................ 8,000 -- -- 8,000 -- (8,000)(d) -- Accounts receivable...... 13,989 -- (5,400)(b) 8,589 -- -- -- Notes receivable, current portion................ 8,512 -- 5,400 (b) 13,912 -- -- -- Prepaids and other current assets......... 1,468 -- -- 1,468 -- -- -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- Total current assets............. 38,051 400 2,229 $ 40,680 30,000 (8,000) (30,000) ---------- ----------- ----------- ------------ ----------- ----------- --------------- Notes receivable......... 19,018 -- -- 19,018 -- -- -- Property, plant and equipment, net (full cost method)........... 63,636 -- -- 63,636 -- -- 30,000 (e) Investments, equity...... 2,229 -- (2,229)(b) -- -- -- -- Other assets............. 2,730 -- -- 2,730 -- -- -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- Total assets......... $125,664 $ 400 $ -- 126,064 $ 30,000 $(8,000) $ -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- LIABILITIES AND STOCKHOLDERS' EQUITY Accounts payable......... $ 4,491 $ -- $ -- $ 4,491 $ -- $-- $ -- Accrued expenses......... 2,880 -- -- 2,880 -- (681)(d) -- Current maturities of long-term debt......... 23,500 -- -- 23,500 (16,500)(c) (7,000)(d) -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- Total current liabilities........ 30,871 -- -- 30,871 (16,500) (7,681) -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- Long-term debt........... 60,338 -- -- 60,338 (27,830)(c) (8,000)(d) -- Deferred taxes........... 1,550 -- -- 1,550 -- -- -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- Total liabilities.... 92,759 -- -- 92,759 (44,330) (15,681) -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- Minority interest........ 412 -- -- 412 -- -- -- Common stock 7,567,988 shares issued and outstanding historical; 14,306,721 shares issued and outstanding pro forma.................. 76 1(a) -- 77 60 (c) 6 (d) -- Additional paid-in capital................ 33,282 1,148(a) -- 34,430 74,270 (c) 7,675 (d) -- Notes receivable -- shareholders........... (546) -- -- (546) -- -- -- Retained earnings........ (319) (749)(a) -- (1,068) -- -- -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- Total stockholders' equity............. 32,493 400 -- 32,893 74,330 7,681 -- ---------- ----------- ----------- ------------ ----------- ----------- --------------- Total liabilities and stockholders' equity............. $125,664 $ 400 $ -- $126,064 $ 30,000 $(8,000) $ -- ========== =========== =========== ============ =========== =========== ===============
PRO FORMA --------- ASSETS Cash and cash equivalents............ $ 8,711 Restricted certificate of deposit................ -- Accounts receivable...... 8,589 Notes receivable, current portion................ 13,912 Prepaids and other current assets......... 1,468 --------- Total current assets............. 32,680 --------- Notes receivable......... 19,018 Property, plant and equipment, net (full cost method)........... 93,636 Investments, equity...... -- Other assets............. 2,730 --------- Total assets......... $ 148,064 --------- LIABILITIES AND STOCKHOLDERS' EQUITY Accounts payable......... $ 4,491 Accrued expenses......... 2,199 Current maturities of long-term debt......... -- --------- Total current liabilities........ 6,690 --------- Long-term debt........... 24,508 Deferred taxes........... 1,550 --------- Total liabilities.... 32,748 --------- Minority interest........ 412 Common stock 7,567,988 shares issued and outstanding historical; 14,306,721 shares issued and outstanding pro forma.................. 143 Additional paid-in capital................ 116,375 Notes receivable -- shareholders........... (546) Retained earnings........ (1,068) --------- Total stockholders' equity............. 114,904 --------- Total liabilities and stockholders' equity............. $ 148,064 ========= The accompanying notes are an integral part of the pro forma financial statements. 23 DOMAIN ENERGY CORPORATION UNAUDITED CONDENSED PRO FORMA INCOME STATEMENT YEAR ENDED DECEMBER 31, 1996
ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS FOR SUBTOTAL FOR ADJUSTMENTS FOR FOR THE MICHIGAN COMPLETED FOR CONCURRENT HISTORICAL ACQUISITION DISPOSITION TRANSACTIONS OFFERING SALE ---------- ----------- ----------- ------------- ----------- ----------- (IN THOUSANDS, EXCEPT PER SHARE DATA) REVENUES Oil and natural gas sales............... $ 52,274 $ -- $-- (j) $52,274 $-- $-- IPF Activities.......................... 4,369 -- -- 4,369 -- -- Other................................... (413) -- 605 (j) 192 -- -- ---------- ----------- ----------- ------------- ----------- ----------- Total revenues..................... 56,230 -- 605 56,835 -- -- ---------- ----------- ----------- ------------- ----------- ----------- EXPENSES Lease operating......................... 10,207 -- -- 10,207 -- -- Production and severance taxes.......... 1,340 -- -- 1,340 -- -- Depreciation, depletion and amortization.......................... 24,920 (8,520)(f) -- 16,400 -- -- General and administrative.............. 3,361 -- -- 3,361 -- -- Corporate overhead allocation........... 4,827 -- -- 4,827 -- -- ---------- ----------- ----------- ------------- ----------- ----------- Total operating expenses........... 44,655 (8,520) -- 36,135 -- -- ---------- ----------- ----------- ------------- ----------- ----------- Operating income........................ 11,575 (8,520) 605 20,700 -- -- ---------- ----------- ----------- ------------- ----------- ----------- Interest expense, net................... 150 14,131 (g) -- 14,281 (3,765)(g) (976)(g) Interest income......................... -- (368)(h) (675)(h) (1,043) -- 368 (k) ---------- ----------- ----------- ------------- ----------- ----------- Net income before income taxes.......... 11,425 (5,243) 1,280 7,462 3,765 608 Income tax expense...................... 4,394 (1,992)(i) 486 (i) 2,888 1,431 (i) 231 (i) ---------- ----------- ----------- ------------- ----------- ----------- Net income.............................. $ 7,031 $ (3,251) $ 794 $ 4,574 $ 2,334 $ 377 ========== =========== =========== ============= =========== =========== Net income per share.................... Common stock and common stock equivalents outstanding...............
ADJUSTMENTS FOR PENDING FUNDS ACQUISITION PRO FORMA ----------- --------- REVENUES Oil and natural gas sales............... $18,472(l) $70,746 IPF Activities.......................... -- 4,369 Other................................... 6(l) 198 ----------- --------- Total revenues..................... 18,478 75,313 ----------- --------- EXPENSES Lease operating......................... 4,231(l) 14,438 Production and severance taxes.......... 152(l) 1,492 Depreciation, depletion and amortization.......................... 6,466(l) 22,866 General and administrative.............. 292(l) 3,653 Corporate overhead allocation........... -- 4,827 ----------- --------- Total operating expenses........... 11,141 47,276 ----------- --------- Operating income........................ 7,337 28,037 ----------- --------- Interest expense, net................... -- 9,540 Interest income......................... -- (675) ----------- --------- Net income before income taxes.......... 7,337 19,172 Income tax expense...................... 2,788(i) 7,338 ----------- --------- Net income.............................. $ 4,549 $11,834 =========== ========= Net income per share.................... $ 0.78 ========= Common stock and common stock equivalents outstanding............... 15,156(m) ========= The accompanying notes are an integral part of the pro forma financial statements. 24 DOMAIN ENERGY CORPORATION UNAUDITED CONDENSED PRO FORMA INCOME STATEMENT THREE MONTHS ENDED MARCH 31, 1997
ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS FOR SUBTOTAL FOR ADJUSTMENTS FOR FOR THE MICHIGAN COMPLETED FOR CONCURRENT HISTORICAL ACQUISITION DISPOSITION TRANSACTIONS OFFERING SALE ---------- ----------- ------------ ------------- ----------- ----------- (IN THOUSANDS, EXCEPT PER SHARE DATA) REVENUES Oil and natural gas..................... $ 12,782 $-- $-- $12,782 $ -- $ -- IPF Activities.......................... 732 -- -- 732 -- -- Other................................... (292) -- 477 (j) 185 -- -- ---------- ----------- ------------ ------------- ----------- ----------- Total revenues..................... 13,222 -- 477 13,699 -- -- ---------- ----------- ------------ ------------- ----------- ----------- EXPENSES Lease operating......................... 3,060 -- -- 3,060 -- -- Production and severance taxes.......... 413 -- -- 413 -- -- Depreciation, depletion and amortization.......................... 3,282 (534)(f) -- 2,748 -- -- General and administrative.............. 792 -- -- 792 -- -- Stock compensation...................... 3,150 -- -- 3,150 -- -- ---------- ----------- ------------ ------------- ----------- ----------- Total operating expenses........... 10,697 (534) -- 10,163 -- -- ---------- ----------- ------------ ------------- ----------- ----------- Operating income........................ 2,525 534 477 3,536 -- -- ---------- ----------- ------------ ------------- ----------- ----------- Interest expense, net................... 1,206 -- -- 1,206 (954)(g) (118)(g) Interest income, net.................... (97) -- (135)(j) (232) -- 92 (k) ---------- ----------- ------------ ------------- ----------- ----------- Net income before income taxes.......... 1,416 534 612 2,562 (954) 26 Income tax expense...................... 1,735 203 (i) 232 (i) 2,170 362 (i) 10 (i) ---------- ----------- ------------ ------------- ----------- ----------- Net income (loss)....................... $ (319) $ 331 $ 380 $ 392 $ 592 $ 16 ========== =========== ============ ============= =========== =========== Net income (loss) per share............. $ (0.03) ========== Common stock and common stock equivalents outstanding............... 9,156
ADJUSTMENTS FOR PENDING FUNDS ACQUISITION PRO FORMA ------------ ---------- REVENUES Oil and natural gas..................... $3,756(l) $ 16,538 IPF Activities.......................... -- 732 Other................................... -- 185 ------------ ---------- Total revenues..................... 3,756 17,455 ------------ ---------- EXPENSES Lease operating......................... 1,018(l) 4,078 Production and severance taxes.......... 56(l) 469 Depreciation, depletion and amortization.......................... 1,298(l) 4,046 General and administrative.............. 36(l) 828 Stock compensation...................... -- 3,150 ------------ ---------- Total operating expenses........... 2,408 12,571 ------------ ---------- Operating income........................ 1,348 4,884 ------------ ---------- Interest expense, net................... -- 134 Interest income, net.................... -- (140) ------------ ---------- Net income before income taxes.......... 1,348 4,890 Income tax expense...................... 512(i) 3,054 ------------ ---------- Net income (loss)....................... $ 836 $ 1,836 ============ ========== Net income (loss) per share............. $ 0.12 ========== Common stock and common stock equivalents outstanding............... 15,156(m) ========== The accompanying notes are an integral part of the pro forma financial statements. 25 DOMAIN ENERGY CORPORATION NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS (UNAUDITED) BASIS OF PRESENTATION The following pro forma adjustments have been prepared as if the Transactions had taken place on March 31, 1997 in the case of the pro forma balance sheet or as of January 1, 1996 in the case of the pro forma statements of income. The adjustments are based upon currently available information and certain estimates and assumptions, and therefore the actual adjustments made to effect the Transactions may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the Transactions as contemplated and that the pro forma adjustments give appropriate effect to these assumptions and are properly applied in the pro forma financial information. PRO FORMA ADJUSTMENTS TO THE BALANCE SHEET a. Reflects the issuance in April 1997 of 95,696 shares of Common Stock at $4.18 per share pursuant to a private offering made to the employees of the Company prior to the Offering. For the sale of such shares the Company received $400,000 in cash and in April 1997 recorded compensation expense of $0.8 million. b. Reflects the sale on April 9, 1997 of the Company's ownership interest in Michigan Production Company, L.L.C. and Michigan Energy Company, L.L.C. (the "Michigan Development Project") pursuant to the Michigan Disposition. The Company's interest in both entities was accounted for using the equity method of accounting. The Company received total consideration of approximately $7.6 million, consisting of approximately $2.2 million in cash and a note receivable of $5.4 million bearing interest at a rate of 10% for the initial six months and 15% thereafter to maturity. c. Reflects (i) the proceeds from the issuance of 6,000,000 shares of Common Stock at $13.50 per share pursuant to the Offering and (ii) use of the proceeds as summarized below (in millions): Proceeds from the Offering.............. $ 81.0 Offering expenses....................... (6.7) --------- Net proceeds.................. $ 74.3 ========= Use of proceeds: Cash for Funds Acquisition......... $ 30.0 Repayment of long-term debt........ 44.3 --------- Net proceeds.................. $ 74.3 ========= d. Reflects proceeds of $8.7 million from the issuance of 643,037 shares of Common Stock at $13.50 per share pursuant to a sale to Fund VII to be completed concurrently with consummation of the Offering and proceeds of $8.0 million from the sale of the restricted certificate of deposit, which was purchased with the proceeds of a loan from Fund VII and used as security for certain obligations related to the Michigan Development Project. As a result of the sale of the Michigan Development Project discussed in Note b, the certificate of deposit is no longer restricted and the Company will use the proceeds from the sale thereof to reduce outstanding borrowings. Accordingly, the adjustment also reflects the use of $16.7 million for repayment of indebtedness to Fund VII, payment of accrued expenses and repayment of debt under the Revolving Credit Facility. e. Reflects the pending acquisition of the oil and gas properties of the Funds for $30.0 million. The properties to be acquired consist of net profits overriding royalty interests owned by three institutional investors that are not affiliated with the Company. See "Business and Properties -- Certain Transactions -- The Funds Acquisition." 26 DOMAIN ENERGY CORPORATION NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED) (UNAUDITED) PRO FORMA ADJUSTMENTS TO THE INCOME STATEMENTS f. Reflects the reduction in the depreciation, depletion, and amortization rate as a result of the allocation of the Acquisition purchase price in accordance with the purchase method of accounting. The Company completed the Acquisition for a total cash purchase price of approximately $96.2 million and the assumption of liabilities of approximately $16.8 million. The assets and liabilities acquired have been recorded by the Company at their estimated fair market values, summarized as follows (in thousands): Assets: Accounts receivable -- trade....... $ 19,456 IPF Program notes receivable....... 21,710 Oil and gas properties............. 66,176 Other assets....................... 5,658 ---------- $ 113,000 ========== Liabilities: Accounts payable................... $ (10,624) Long-term debt..................... (6,212) ---------- $ (16,836) ========== 27 DOMAIN ENERGY CORPORATION NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED) (UNAUDITED) g. Reflects the adjustments to interest expense computed as follows (in thousands): 1. Year Ended December 31, 1996 (a) Historical
BEFORE AFTER PAYMENT PAYMENT RATE INTEREST ------- -------- --------- -------- IPF Company Credit Facility....... $ 6,212 $ 6,212 8.00% $ 150(i) -------- $ 150 --------
(b) The Company was capitalized on December 31, 1996 with the issuance of 7,177,681 shares of Common Stock for $30.0 million and borrowings of $61.2 million and $5.0 million under its Revolving Credit Facility and IPF Company Credit Facility, respectively. As discussed in Note f, the Company assumed $6.2 million of long-term debt in connection with the Acquisition.
The Acquisition Financing: Revolving Credit Facility........ $ -- $ 61,200 8.00% $ 4,896 IPF Company Credit Facility...... 6,212 11,212 8.00% 400 Indebtedness to Fund VII......... -- 8,000 4.60% 368 Average historical indebtedness to Predecessor Parent(ii)..... -- 118,500 8.00% 9,480 Less: amounts capitalized on $12.6 million of properties not subject to amortization... -- -- 8.00% (1,013) -------- $ 14,131 -------- (c) Repayment of debt using Offering proceeds: Revolving Credit Facility......... $61,200 $ 21,870 7.00%(iii)$ (3,365) IPF Company Credit Facility....... 11,212 6,212 8.00% (400) -------- $ (3,765) -------- (d) Repayment of debt using proceeds from Concurrent Sale: Revolving Credit Facility........ $21,870 $ 13,870 7.00%(iii)$ (608) Indebtedness to Fund VII......... 8,000 -- 4.60% (368) -------- $ (976) -------- Total pro forma interest expense adjusted...................... $ 9,540 ========
A 1/8% increase in the variable interest rates on the above debt instruments would decrease net income by $98,000. 28 DOMAIN ENERGY CORPORATION NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED) (UNAUDITED) 2. Three Months Ended March 31, 1997
BALANCE BEGINNING BALANCE OF END OF PERIOD PERIOD RATE INTEREST ------- -------- --------- -------- (a) Historical: Revolving Credit Facility................. $61,200 $ 59,500 8.00% $ 1,228 IPF Company Credit Facility................. 11,212 17,338 8.00% 222(i) Indebtedness to Fund VII... 8,000 8,000 4.60% 92 Less: Amount capitalized on $12.6 million of properties not subject to amortization............. -- -- 8.00% (336) -------- $ 1,206 -------- (b) Repayment of debt using Offering Proceeds: Revolving Credit Facility................. $59,500 $ 20,170 7.00%(iii) $ (856) IPF Company Credit Facility................. 17,338 12,338 8.00% (98) -------- $ (954) ======== (c) Repayment of debt using proceeds of Concurrent Sale: Revolving Credit Facility................. $20,170 $ 12,170 7.00% ($ 152) Indebtedness to Fund VII... 8,000 -- 4.60% (92) Adjustment to amounts capitalized for reduction in interest rate(iii).... -- -- 7.00% 126 -------- $ (118) -------- Total pro forma interest expense adjusted.............................. $ 134 ========
A 1/8% increase in the variable interests rates on the above debt instruments would decrease net income by $3,100. In connection with the Acquisition on December 31, 1996, the Company did not assume the liabilities of the Predecessor to the Predecessor Parent. Accordingly, for the three months ended March 31, 1997, there is no interest expense related to advances from the Predecessor Parent as is reflected in pro forma interest expense for the year ended December 31, 1996. ------------ (i) Reflects actual historical interest expense incurred on IPF Company Credit Facility debt outstanding prior to the Acquisition based on amounts outstanding from time to time. (ii) The Predecessor Parent did not charge the Company interest on the funds it advanced to the Company. This adjustment reflects interest expense that would have accrued on the average amount of advances from the Predecessor Parent outstanding during 1996 if the Predecessor Parent had charged the Company interest on such advances. (iii) Once the total amount of debt outstanding is below the threshold amount as defined by the Revolving Credit Facility, the interest rate is lowered by 1.0%. See "Notes to Combined and Consolidated Financial Statements -- Long-term Debt -- Revolving Credit Facility." h. Reflects the interest income on a certificate of deposit used as collateral for the Michigan Development Project. i. The effective rate of 38.0% is computed using statutory rates, including state taxes, less the federal income tax benefit derived from state taxes. j. As discussed in Note b, on April 9, 1997, the Company sold its ownership interest in two entities accounted for using the equity method of accounting. This adjustment reflects the effects of the exclusion of the Company's equity share of the results of operations of these two entities and the interest income on the note receivable from the sale. 29 DOMAIN ENERGY CORPORATION NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED) (UNAUDITED) k. Reflects reduction in interest income on a certificate of deposit used as collateral for the Michigan Development Project as a result of the sale of the certificate of deposit. l. Reflects the changes in income items from the Funds Acquisition. Revenues and production expenses were obtained from unaudited historical information for the Funds. Other pro forma items are calculated on a consolidated basis. For example, the DD&A adjustment is calculated based on the impact of the Acquisition on the Company's consolidated DD&A expense rate. m. Common stock and common stock equivalents outstanding has been calculated assuming that the 7,177,681 shares of Common Stock purchased in connection with the Acquisition, the 486,003 shares of Common Stock purchased by the Company's employees in 1997, the 849,694 shares of Common Stock reserved for issuance pursuant to outstanding options under the Stock Purchase and Option Plan, the 6,000,000 shares of Common Stock to be issued pursuant to the Offering and the 643,037 shares of Common Stock to be issued to Fund VII pursuant to the Concurrent Sale have been outstanding since January 1, 1996. 30 SELECTED HISTORICAL COMBINED AND CONSOLIDATED FINANCIAL DATA The following table sets forth selected historical combined and consolidated information of the Company for the five years ended and as of December 31, 1996 and for the three months ended March 31, 1996 and 1997 and as of March 31, 1997. The results for the three months ended March 31, 1997 are not necessarily indicative of the results for the full year. The selected combined and consolidated financial data should be read in conjunction with "Capitalization," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Combined and Consolidated Financial Statements of the Company and the related notes thereto included elsewhere in this Prospectus.
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, -------------------------------------------------------- ----------------------- PREDECESSOR PREDECESSOR SUCCESSOR -------------------------------------------------------- ----------- --------- 1992 1993 1994 1995 1996 1996 1997 --------- --------- ---------- ---------- ---------- ----------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) INCOME STATEMENT DATA: Revenues: Oil and natural gas sales(1)....... $ 2 $ 1,922 $ 5,340 $ 34,877 $ 52,274 $15,688 $ 12,782 IPF Activities(2).................. -- 200 1,417 2,356 4,369 340 732 Other.............................. -- -- 283 414 (413) 115 (292) --------- --------- ---------- ---------- ---------- ----------- --------- Total revenues................ 2 2,122 7,040 37,647 56,230 16,143 13,222 --------- --------- ---------- ---------- ---------- ----------- --------- Expenses: Lease operating.................... -- 218 1,790 7,980 10,207 2,127 3,060 Production and severance taxes..... -- 2 18 710 1,340 279 413 Depreciation, depletion and amortization..................... -- 987 3,101 22,692 24,920 7,613 3,282 General and administrative, net.... 332 681 52 2,780 3,361 1,089 792 Corporate overhead allocation...... -- 257 944 2,627 4,827 939 -- Stock compensation................. -- -- -- -- -- -- 3,150 --------- --------- ---------- ---------- ---------- ----------- --------- Total operating expenses...... 332 2,145 5,905 36,789 44,655 12,047 10,697 --------- --------- ---------- ---------- ---------- ----------- --------- Income (loss) from operations........... (330) (23) 1,135 858 11,575 4,096 2,525 Interest expense, net................... 20 -- -- -- 150 -- 1,109 --------- --------- ---------- ---------- ---------- ----------- --------- Income (loss) before income taxes....... (350) (23) 1,135 858 11,425 4,096 1,416 Income tax provision (benefit).......... (119) 2 735 351 4,394 1,342 1,735 --------- --------- ---------- ---------- ---------- ----------- --------- Net income (loss)....................... $ (231) $ (25) $ 400 $ 507 $ 7,031 $ 2,754 $ (319) ========= ========= ========== ========== ========== =========== ========= Net income (loss) per share............. $ (0.03) ========= Common stock and common stock equivalents outstanding............... 9,156
AS OF DECEMBER 31, -------------------------------------------------------- PREDECESSOR SUCCESSOR -------------------------------------------- SUCCESSOR AS OF MARCH 31, 1992 1993 1994 1995 1996 1997 --------- --------- ---------- ---------- ---------- --------------- BALANCE SHEET DATA: Cash and cash equivalents.......... $ 2 $ 1,635 $ 11,467 $ -- $ 36 $ 6,082 Property, plant and equipment, net.............................. 131 11,544 93,823 111,724 66,176 63,636 IPF Program notes receivable....... -- 4,215 4,023 7,991 21,710 27,530 Total assets....................... 1,403 23,493 117,755 137,096 122,429 125,664 Long-term debt (including current maturities)...................... -- -- -- -- 79,412 83,838 Parent advances.................... 1,684 19,491 104,504 112,832 -- -- Stockholders' equity............... (309) (335) 65 572 28,577 32,493
- ------------ (1) Oil and natural gas sales increased from $5.3 million in 1994 to $52.3 million in 1996 primarily as a result of the Company's acquisition of producing properties in 1994 and 1995, results of drilling activities in 1994, 1995 and 1996, and an increase in the net realized price of gas in 1996 relative to 1994 and 1995. (2) IPF Activities includes income from the Company's IPF Program and the Company's "GasFund" partnership with a financial investor. See "Business and Properties -- Producer Investment Activities." 31 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist in understanding the Company's historical financial position and results of operations as of December 31, 1995 and 1996 and for each year of the three-year period ended December 31, 1996 and as of March 31, 1997, and for the three months ended March 31, 1996 and 1997. The Company's historical financial statements and notes thereto included elsewhere in this Prospectus contain detailed information that should be referred to in conjunction with this discussion. GENERAL On December 31, 1996, the Company acquired all of the outstanding capital stock of its operating subsidiaries, Domain Energy Ventures Corporation ("Ventures Corporation") and Domain Energy Production Corporation ("Production Corporation" and, together with Ventures Corporation, the "Predecessor"). The Company has accounted for the acquisition (the "Acquisition") using the purchase method of accounting, under which the purchase price has been allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition date. The Company is an independent oil and gas company engaged in the exploration, development, production and acquisition of domestic oil and natural gas properties, principally in the Gulf Coast region. The Company complements these activities with its IPF Program pursuant to which it invests in oil and natural gas reserves through the acquisition of term overriding royalty interests accounted for as notes receivable. As of December 31, 1996, the Company had estimated net proved reserves of 149.6 Bcfe. Approximately 54% of the Company's net proved reserves at such date were natural gas and approximately 61% of proved reserves were classified as proved developed producing. As of December 31, 1996, the Company had a PV-10 Reserve Value of $184.8 million, which does not include reserve value attributable to the IPF Program but includes the Company's proportionate share of reserve value attributable to the Michigan Development Project. The Company's selected historical combined and consolidated financial data included elsewhere in this Prospectus have been derived from the audited Combined and Consolidated Financial Statements of the Company. The selected balance sheet data at December 31, 1996 reflects the Acquisition that occurred on that date. The selected balance sheet and income statement data at other dates and for other periods reflects the combined financial position and results of operations of Ventures Corporation and Production Corporation with intercompany transactions and account balances eliminated. Prior to the Acquisition, these companies and their subsidiaries were included in the consolidated federal income tax return of Tenneco, as a result of which Tenneco will receive all benefit for such entities' historical tax losses. In connection with the Acquisition, the Company agreed to file an election under Sections 338(g) and 338(h)(10) of the Internal Revenue Code of 1986, as amended, pursuant to which the Company will allocate the purchase price paid by the Company among the assets of these companies to determine the basis of assets acquired in accordance with the principles of Treasury Regulation 1.338(h)(10)-1(f)(1)(ii). 32 The sources and uses of funds related to financing the Acquisition as of the closing date were as follows: (IN MILLIONS) SOURCES OF FUNDS: Revolving Credit Facility............. $61.2 Common Stock purchased by Fund VII.................................. 30.0 IPF Company Credit Facility........... 5.0 ------------- $96.2 ============= USE OF FUNDS: Acquisition purchase price(1)......... $96.2 ------------- $96.2 ============= - ------------ (1) In February 1997 the Company paid an additional $500,000 as a post-closing adjustment to the Acquisition purchase price. The Company's objective is to maximize shareholder value by growing reserves, production, cash flow and earnings through the opportunistic acquisition of Gulf Coast region properties with underexploited value. The Company applies 3-D seismic and other advanced technologies to development, exploitation and exploration. These activities are complemented by the continued expansion of the IPF Program. Fundamental to the execution of the Company's strategy is its foundation of experienced technical talent strengthened by a high level of financial, transactional and risk-management expertise, resulting in part, from the former association of the Company and its employees with Tenneco. The Company's revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and natural gas, 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 oil or natural gas prices could have a material adverse effect on the Company's financial position, results of operations, quantities of oil and natural gas reserves that may be economically produced, and access to capital. The Company uses the full cost method of accounting for its investments in oil and natural gas properties. Under such methodology, all costs of exploration, development and acquisition of oil and natural gas 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 a ratio of current production to total proved oil and natural gas 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 oil and natural gas reserves and the lower of cost or fair value of unproved properties, such excess costs are charged to operations. If a write-down were required, it would result in a non-cash charge to earnings but would not have an impact on cash flows. ACCOUNTING FOR IPF PROGRAM ACTIVITY Through its IPF Program, the Company acquires term overriding royalty interests in oil and gas properties owned by independent producers. Because the capital advanced to a producer for these interests is repaid from an agreed upon share of cash revenues from the sale of production until the capital advanced plus a contractual return is paid in full, the Company accounts for the term overriding royalty interests as notes receivable. Under this accounting method, the Company recognizes only the interest income portion of payments received from a producer as revenues on its income statement. The remaining cash receipts are recorded as a reduction in notes receivable on the Company's balance sheet and as IPF Program return of capital on the Company's statement of cash flows. If instead of acquiring dollar-denominated term overriding royalty interests, the Company were purchasing term overriding royalty interests requiring delivery of a specified quantity of oil and gas, IPF 33 Program results would be accounted for differently. Specifically, in 1996, Company EBITDA would increase by $4.3 million and IPF Program return of capital in the Combined Statement of Cash Flows would decrease by the same amount. To more accurately reflect the actual cash flows generated by the Company, IPF Program return of capital is identified separately to allow such cash receipts to be combined with EBITDA. Although, to date, the Company has not incurred any losses on notes outstanding under the IPF Program, as of December 31, 1996, the Company established a non-cash reserve for potential future losses of $437,000, which reserve is netted against IPF Program notes receivable in the Company's balance sheet. 34 RESULTS OF OPERATIONS The Company has experienced significant growth in reserves, production, cash flow and earnings over the past three years. The following table summarizes certain operating and financial data, production volumes, average realized prices and average expenses for the Company's oil and natural gas operations for the years ended December 31, 1994, 1995 and 1996 and the three months ended March 31, 1996 and 1997:
YEAR ENDED DECEMBER 31, THREE MONTHS ENDED -------------------------------- MARCH 31, PREDECESSOR ------------------------ -------------------------------- PREDECESSOR SUCCESSOR 1994 1995 1996 1996 1997 ---------- --------- --------- ----------- --------- FINANCIAL DATA (IN THOUSANDS): Revenues Natural gas................... $ 4,101 $ 27,772 $ 41,767 $13,772 $ 10,094 Oil and condensate............ 1,239 7,105 10,507 1,916 2,688 IPF Activities(1)............. 1,417 2,356 4,369 340 732 Total revenues..................... 7,040 37,647 56,230 16,143 13,222 Total operating expenses........... 5,905 36,789 44,655 12,047 10,697 ---------- --------- --------- ----------- --------- Operating income................... $ 1,135 $ 858 $ 11,575 $ 4,096 $ 2,525 ========== ========= ========= =========== ========= Net income (loss).................. $ 400 $ 507 $ 7,031 $ 2,754 $ (319) Net cash provided by operating activities....................... 11,487 19,933 34,553 5,715 8,112 Net cash used in investing activities....................... (86,669) (39,728) (47,329) (10,634) (7,577) Net cash provided by financing activities....................... 85,014 8,328 12,776 5,285 5,511 NON-GAAP FINANCIAL DATA (IN THOUSANDS): EBITDA(2).......................... $ 4,236 $ 23,550 $ 36,495 $11,709 $ 8,957 IPF Program return of capital(3)... 3,507 2,638 4,618 517 3,426 EBITDA plus IPF Program return of capital.......................... 7,743 26,188 41,113 12,226 12,383 PRODUCTION VOLUMES: Natural gas (MMcf)................. 2,334 18,065 21,192 5,828 3,668 Oil and condensate (MBbls)......... 83 424 564 116 141 Total (MMcfe)...................... 2,832 20,609 24,575 6,524 4,516 AVERAGE REALIZED PRICES:(4) Natural gas (per Mcf).............. $ 1.76 $ 1.54 $ 1.97 $ 2.36 $ 2.75 Oil and condensate (per Bbl)....... 14.93 16.76 18.63 16.52 19.06 EXPENSES (PER MCFE): Lease operating.................... $ 0.63 $ 0.39 $ 0.42 $ 0.33 $ 0.68 Production taxes................... 0.01 0.03 0.05 0.04 0.09 Depreciation, depletion and amortization..................... 1.03 1.08 1.01 1.19 0.69 General and administrative, net(5)........................... 0.26 0.16 0.12 0.14 0.14
- ------------ (1) IPF Activities includes income from the Company's IPF Program and the Company's "GasFund" partnership with a financial investor. See "Business and Properties -- Producer Investment Activities." (FOOTNOTES CONTINUED ON FOLLOWING PAGE) 35 (2) EBITDA represents earnings before stock compensation expense, interest, income taxes, depreciation, depletion and amortization. The Company believes that EBITDA may provide additional information about the Company's ability to meet its future requirements for debt service, capital expenditures and working capital. EBITDA is a financial measure commonly used in the oil and gas industry and should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. Because EBITDA excludes some, but not all, items that affect net income and may vary among companies, the EBITDA calculation presented above may not be comparable to similarly titled measures of other companies. (3) To more accurately reflect the actual cash flows generated by the Company, IPF Program return of capital is identified separately to allow such cash receipts to be combined with EBITDA. (4) Reflects the actual realized prices received by the Company, including the results of the Company's hedging activities. See " -- Other Matters -- Hedging Activities." (5) Includes production attributable to properties managed for the Funds for the periods indicated and excludes fees received from investors and overhead allocations from Tenneco. Including Tenneco allocations, average net general and administrative expenses per Mcfe for the years ended December 31, 1994, 1995 and 1996 would be $0.26, $0.20 and $0.28, respectively. THREE MONTHS ENDED MARCH 31, 1997 COMPARED TO THREE MONTHS ENDED MARCH 31, 1996 Oil and natural gas revenues decreased from $15.7 million in the first quarter of 1996 to $12.8 million in the first quarter of 1997, a decrease of $2.9 million, or 18.5%. Production volumes for oil and condensate increased from 116 MBbls in the first quarter of 1996 to 141 MBbls in the first quarter of 1997, an increase of 25 MBbls, or 21.6%. Production volumes for natural gas decreased from 5.8 Bcf in the first quarter of 1996 to 3.7 Bcf in the first quarter of 1997, a decrease of 2.2 Bcf, or 37.1%. The decrease in natural gas production was primarily due to the sale of the ATP Partnership and Cage Ranch properties as well as natural declines in production from the Mustang Island 847 Field, the West Cameron 601 Field, the Eugene Island Field and the Rabbit Island Field. The decrease in total net production decreased revenues by $4.7 million. This was partially offset by a 15.4% increase in oil and condensate prices and a 16.5% increase in natural gas prices. Increases in average oil and natural gas prices were attributable to improved market conditions for oil and natural gas and improved results from natural gas hedging activities. As a result of hedging activities, the Company realized an average oil price of $19.06 per Bbl and an average gas price of $2.75 per Mcf for the first quarter of 1997, compared to average prices of $21.45 per Bbl and $2.73 per Mcf, respectively, that otherwise would have been received. For the first quarter of 1996, as a result of hedging activities the Company realized an average oil price of $16.52 per Bbl and an average gas price of $2.36 per Mcf, compared to average prices of $17.80 per Bbl and $2.57 per Mcf, respectively, that otherwise would have been received. Revenues from IPF Activities increased from $0.3 million in the first quarter of 1996 to $0.7 million in the first quarter of 1997, an increase of $0.4 million, or 115.3%. This was the result of increased activities in the IPF Program. See "Business and Properties -- Producer Investment Activities." Lease operating expenses increased from $2.1 million in the first quarter of 1996 to $3.1 million in the first quarter of 1997, an increase of $1.0 million or 43.9%. On an Mcfe basis, lease operating expenses increased from $0.33 in the first quarter of 1996 to $0.68 in the first quarter of 1997, an increase of $0.35, or 106.1%. Lease operating expenses were higher in the first quarter of 1997 as compared to the first quarter of 1996 as a result of the Wasson Field acquisition completed by the Company after the first quarter of 1996. The Wasson Field, which is in tertiary recovery, had a relatively low purchase price based on reserves, which is offset by relatively high lease operating expenses. Depreciation, depletion and amortization ("DD&A") expense declined from $7.6 million in the first quarter of 1996 to $3.3 million in the first quarter of 1997, a decrease of $4.3 million, or 56.9%. This was the result of lower oil and gas production volumes and a 42.0% decrease in the DD&A rate. The reduced DD&A rate was the result of reduced cost basis attributable to the Company's oil and gas properties purchased in the Acquisition. See "Business and Properties -- The Company." General and administrative expense decreased from $1.1 million in the first quarter of 1996 to $0.8 million in the first quarter of 1997, a decrease of $0.3 million, or 27.3%. This decrease was primarily due to a reduction in the number of employees. 36 The corporate overhead allocation decreased from $0.9 million in the first quarter of 1996 to zero in the first quarter of 1997 due to the Acquisition and the elimination of Tenneco's allocated overhead. Stock compensation increased from zero in the first quarter of 1996 to $3.2 million in the first quarter of 1997 due to the implementation of the Stock Purchase and Option Plan. Income tax expense increased from $1.3 million in the first quarter of 1996 to $1.7 million in the first quarter of 1997, an increase of $0.4 million or 29.3%. This increase was primarily due to an increase in the effective tax rate from 32.8% in the first quarter of 1996 to 122.5% in the first quarter of 1997 due to the exclusion of stock compensation expense in the 1997 tax calculation. This increase in income tax expense was partially offset by a decrease in the income before taxes from $4.1 million in the first quarter of 1996 to $1.4 million in the first quarter of 1997. Net income was $2.8 million in the first quarter of 1996 compared to a net loss of $0.3 million in the first quarter of 1997 as a result of the factors described above. YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995 Oil and natural gas revenues increased from $34.9 million in 1995 to $52.3 million in 1996, an increase of $17.4 million, or 49.9%. Production volumes for oil and condensate increased from 424 MBbls in 1995 to 564 MBbls in 1996, an increase of 140 MBbls, or 33.0%. Production volumes for natural gas increased from 18.1 Bcf in 1995 to 21.2 Bcf in 1996, an increase of 3.1 Bcf, or 17.3%. The increase in oil and natural gas production was due to new wells being successfully drilled and completed during 1996, as well as acquisitions of producing properties. The increase in total net production increased revenues by $7.2 million. In addition, the Company experienced a 11.2% increase in average oil and condensate prices and a 27.9% increase in average natural gas prices. Increases in average oil and natural gas prices were directly attributable to general improved market conditions. As a result of hedging activities, the Company realized an average oil price of $18.63 per Bbl and an average gas price of $1.97 per Mcf for the year ended December 31, 1996, compared to average prices of $20.88 per Bbl and $2.41 per Mcf, respectively, that otherwise would have been received. These hedging activities decreased oil and natural gas revenues by approximately $10.5 million. This loss of revenue was the result of hedges made at the direction of Tenneco in late 1995. Revenues from IPF Activities increased from $2.4 million in 1995 to $4.4 million in 1996, an increase of $2.0 million, or 85.4%. This increase was the result of a $1.0 million increase in IPF Program revenues and a $1.0 million increase in GasFund revenues. See "Business and Properties -- Producer Investment Activities." IPF Program revenues increased as the result of an increase in IPF Program investments attributable to a 100% increase in IPF Program customers at year-end 1996 compared to year-end 1995. Lease operating expenses increased from $8.0 million in 1995 to $10.2 million in 1996, an increase of $2.2 million, or 27.9%. On an Mcfe basis, lease operating expenses increased from $0.39 in 1995 to $0.42 in 1996, an increase of $0.03, or 7.7%. The increase in lease operating expenses was primarily attributable to increased production volumes. On a per unit basis, the increase was primarily attributable to the acquisition in June 1996 of an interest in the Wasson Field, which is undergoing tertiary enhanced recovery and the expenses associated therewith. Depreciation, depletion and amortization ("DD&A") expense increased from $22.7 million in 1995 to $24.9 million, an increase of $2.2 million. This was the result of higher oil and gas production volumes partially offset by a 6.5% decrease in the DD&A rate. The reduced DD&A rate was attributable to the acquisition of low cost reserves in the Wasson Field. General and administrative expense increased from $2.8 million in 1995 to $3.4 million in 1996, an increase of $0.6 million, or 20.9%. This increase reflects a decrease in the reimbursement of overhead paid to the Company by the investors in the Funds from $1.1 million in 1995 to zero in 1996 partially offset by an increase in the capitalization of general and administrative expense in 1996 by $0.5 million as compared to 1995. 37 The corporate overhead allocation increased from $2.6 million in 1995 to $4.8 million in 1996, an increase of $2.2 million, or 83.7%. The increase was primarily due to approximately $2.0 million in costs related to severance payments, retention bonuses and other costs associated with the merger of Tenneco with an affiliate of El Paso Natural Gas Company. Income tax expense increased from $0.4 million in 1995 to $4.4 million in 1996, an increase of $4.0 million, or 1152%. This was due to an increase in income before taxes from $0.9 million in 1995 to $11.4 million in 1996 and an increase in the effective tax rate from 40.9% in 1995 to 38.5% in 1996. Net income was $0.5 million in 1995 compared to $7.0 million in 1996, as a result of the factors described above. YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994 Oil and natural gas revenues increased from $5.3 million in 1994 to $34.9 million in 1995, an increase of $29.5 million, or 553%. Production volumes for oil and condensate increased from 83 MBbls in 1994 to 424 MBbls in 1995, an increase of 341 MBbls, or 411%. Production volumes for natural gas increased from 2.3 Bcf in 1994 to 18.1 Bcf in 1995, an increase of 15.7 Bcf, or 674%. The increase in oil and natural gas production was due to increased drilling activities, as well as the Pennzoil Acquisition and other acquisitions of producing properties. The increase in total net production increased revenues by $32.8 million. In addition, the Company experienced a 12.3% increase in average oil and condensate prices, and a 12.5% decrease in average natural gas prices. As a result of hedging activities, the Company realized an average oil price of $16.76 per Bbl for the year ended December 31, 1995, compared to an average price of $16.31 per Bbl that otherwise would have been received. These hedging activities increased oil revenues by approximately $0.2 million. Revenues from IPF Activities increased from $1.4 million in 1994 to $2.4 million in 1995, an increase of $0.9 million, or 66.3%. This increase was primarily attributable to GasFund loan activity. See "Business and Properties -- Producer Investment Activities." Lease operating expenses increased from $1.8 million in 1994 to $8.0 million in 1995, an increase of $6.2 million, or 346%. However, on an Mcfe basis, lease operating expenses decreased from $0.63 in 1994 to $0.39 in 1995, a decrease of $0.24, or 38%. The decrease in lease operating cost per Mcfe was primarily attributable to significant increases in production volumes, following several substantial asset acquisitions. DD&A expense increased from $3.1 million in 1994 to $22.7 million in 1995, an increase of $19.6 million, or 632%. This increase was due to the increase in oil and gas production volumes and an increase in the DD&A rate per Mcfe from $1.03 in 1994 to $1.08 in 1995, a 5.0% increase. The 1994 DD&A rate was adversely affected by a downward revision in the prior year's estimate of oil and gas reserves. The downward revision was primarily caused by negative drilling results by the Company in an offshore field. The increase in DD&A rate per Mcfe in 1995 is the result of higher finding costs relative to 1994 ($1.13 in 1995 compared to $0.91 in 1994). General and administrative expense increased from $0.1 million in 1994 to $2.8 million in 1995, an increase of $2.7 million. Net general and administrative expense in 1994 was nominal because direct expenses of $3.5 million were offset by $1.8 million of overhead reimbursement paid to the Company by investors in the Funds and $1.6 million of capitalized general and administrative expense. The increase in 1995 was primarily attributable to salary, benefits, rent and related costs of the additional 24 employees hired during 1995 due to acquisitions and increased business activity. The corporate overhead allocation increased from $0.9 in 1994 to $2.6 million in 1995, an increase of $1.7 million. The increase was based on the Company's increased business activities resulting from acquisitions. Income tax expense decreased from $0.7 million in 1994 to $0.4 million in 1995, a decrease of $0.4 million, or 52.2%. This was primarily due to a decrease in the effective tax rate from 64.8% in 1994 to 40.9% in 1995. 38 Net income was $0.4 million in 1994 compared to $0.5 million in 1995, as a result of the factors described above. LIQUIDITY AND CAPITAL RESOURCES Cash flows provided by operating activities from the Predecessor's operations were $11.5 million, $19.9 million and $34.6 million for each of the three years in the periods ended December 31, 1994, 1995 and 1996, respectively. Significant increases in production resulting from oil and gas property acquisitions over this three year period increased net income. Cash flows from the Predecessor's operations for the three months ended March 31, 1996 were $5.7 million and for the Company's operations for the three months ended March 31, 1997 were $8.1 million. This increase was primarily attributable to changes in operating assets and liabilities in 1997 partially offset by production declines due to the sale of certain properties as well as natural declines in production from certain fields. Cash flows used in investing activities by the Predecessor were $86.7 million, $39.7 million and $47.3 million for each of the three years in the periods ended December 31, 1994, 1995 and 1996, respectively. Property additions through acquisition, exploration and development activities and increasing IPF Program activity levels were the primary reasons for the use of funds in investing activities. Partially offsetting these uses of funds were proceeds from sales of non-core oil and gas properties of $8.3 million and $1.5 million in 1995 and 1996, respectively. Cash flows used in investing activities by the Predecessor for the three months ended March 31, 1996 were $10.6 million and by the Company for the three months ended March 31, 1997 were $7.6 million. In both first quarter periods, the uses resulted from expanding acquisition, exploration, development and IPF Program activities partially offset by the sale of non-core oil and gas properties. Cash flows provided by the Predecessor's financing activities were $85.0 million, $8.3 million and $12.8 million for each of the three years in the periods ended December 31, 1994, 1995 and 1996, respectively. In 1994 and 1995 the cash flows were provided by parent advances. In 1996, $6.2 million was generated from the IPF Company Credit Facility and $6.6 million was provided by parent advances. Cash flows provided by the Predecessor's financing activities for the three months ended March 31, 1996 were $5.3 million, which were provided by parent advances. Cash flows provided by financing activities for the Company's operations for the three months ended March 31, 1997 were $5.5 million, consisting of additional net borrowings of $4.4 million and proceeds from the sale of Common Stock to management of the Company of $1.1 million. Funding for the Company's exploration and development activities, acquisitions and IPF Program investments has historically been provided by operating cash flows, revolving credit borrowings, asset sales and advances from Tenneco. The Company's Board of Directors has authorized a capital budget of $125.0 million for 1997 to be spent on exploratory and development drilling, IPF Program investments and acquisitions of oil and gas properties. The Company intends to finance these expenditures with a portion of the net proceeds from this Offering, cash flow from operations and borrowings under its revolving credit facilities. As a result of borrowings under the Revolving Credit Facility and the IPF Company Credit Facility in order to finance a portion of the costs of the Acquisition, the Company has incurred substantial indebtedness and has minimal borrowing availability under either of such facilities. As of March 31, 1997, the Company had total consolidated indebtedness for money borrowed of approximately $83.8 million. On a pro forma basis as of March 31, 1997, the Company would have had total consolidated indebtedness for money borrowed of approximately $24.5 million, resulting in availability for additional borrowings of $51.1 million and $5.7 million under the Revolving Credit Facility and the IPF Company Credit Facility, respectively (assuming a borrowing base of $63.3 million and $18.0 million, respectively). The borrowing base under the Revolving Credit Facility may be redetermined by the Lenders at any time and is scheduled to be redetermined based on the Company's January 1 and June 30 reserve reports. Depending on the price outlook for oil and natural gas and the levels of the Company's cash flows and capital expenditures, the borrowing base may be re-set below the amounts outstanding under the Revolving 39 Credit Facility, and in such case the Company may need to refinance a portion of the principal amount of such indebtedness prior to its maturity. The Company believes that cash flow from operations, proceeds from the Offering and revolving credit borrowings will be adequate to meet future liquidity needs, including satisfying the Company's financial obligations and funding its capital investment program. At December 31, 1996, the Company had a working capital deficit of approximately $2.1 million, primarily due to current maturities of long-term debt. At March 31, 1997, on a pro forma basis after giving effect to the disposition of the Michigan properties and the sale of 95,696 shares of Common Stock to the Company's employees in April 1997, the Company had working capital of approximately $9.8 million. After consummation of the other contemplated transactions described in this Prospectus -- the Offering, the concurrent sale of stock to Fund VII and the Funds Acquisition -- the Company will have a significant amount of working capital. REVOLVING CREDIT FACILITY. In connection with the Acquisition, the Company entered into the $65.0 million Revolving Credit Facility maturing on December 31, 1999 with a group of banks led by The Chase Manhattan Bank (the "Lenders"). As of March 31, 1997, borrowings outstanding under the Revolving Credit Facility totalled $59.5 million. The Revolving Credit Facility is secured by approximately 80% of the aggregate value of the Company's oil and gas properties and substantially all of the Company's other property (other than IPF Program properties), including the capital stock of Ventures Corporation and Production Corporation. Although the remaining approximately 20% of the aggregate value of the Company's oil and natural gas properties is not mortgaged to the Lenders thereunder, such properties are nevertheless subject to the restrictions set forth therein, including a prohibition on granting any security interests therein. The borrowing base under the facility was $63.3 million as of March 31, 1997, and is subject to a scheduled redetermination every six months (and such other redeterminations as the Lenders may elect to perform each year) by the Lenders at the Lenders' sole discretion and in accordance with their customary practices and standards in effect from time to time for reserve-based loans to borrowers similar to the Company. Determination of the borrowing base may be affected by, among other things, estimates and projections of reserves and production rates with respect to the Company's oil and natural gas properties and changes in oil and natural gas prices. The Company's obligations under the Revolving Credit Facility are guaranteed by its wholly-owned subsidiaries, Ventures Corporation and Production Corporation. If the Company's borrowing base is reduced, the amount available to the Company under the Revolving Credit Facility will be reduced and, to the extent that the borrowing base is less than the amount then outstanding thereunder, the Company will be obligated to provide additional collateral or prepay such excess amount within 30 days following the date on which the excess amount first occurred. The borrowing base under the Revolving Credit Facility is scheduled to be redetermined as of December 31, 1997 and may be reduced substantially from its current level. All amounts outstanding in excess of such reduced borrowing base must be paid in full at such date. In addition, if at the end of any fiscal quarter of the Company during 1997 the amount then outstanding thereunder exceeds $43.3 million (as such amount may be adjusted from time to time pursuant to the Revolving Credit Facility), the Company will be obligated to prepay the outstanding indebtedness thereunder in an amount equal to 100% of the Company's "excess cash flow" (as defined therein) for such fiscal quarter. Excess cash flow is defined to include a portion of the net proceeds to the Company of the Offering. Absent a default or an event of default (as defined therein), borrowings under the Revolving Credit Facility accrue interest at LIBOR plus a margin of 1.50% to 2.50% per annum depending on the total amount outstanding or, at the option of the Company, at the greater of (i) the prime rate and (ii) the federal funds effective rate plus 0.50%, plus a margin of 0.50% to 1.50% depending on the total amount outstanding. The Company incurs a quarterly commitment fee ranging from 0.375% to 0.50% per annum on the average unused portion of the Lenders' aggregate commitment, depending on the total amount outstanding. The Revolving Credit Facility contains a number of covenants that, among other things, restrict the ability of the Company to dispose of assets, incur additional indebtedness or grant liens on its properties, repay other indebtedness, pay dividends, enter into certain investments or acquisitions, repurchase or 40 redeem capital stock, engage in mergers or consolidations, or engage in certain transactions with subsidiaries and affiliates and that will otherwise restrict corporate activities. In addition, such facility requires the Company to maintain a specified minimum tangible net worth and to comply with certain prescribed financial ratios. Further, under such facility, an event of default is deemed to occur if any person, other than the Company's officers, Fund VII or any other investment fund, the managing general partner of which is First Reserve, becomes the beneficial owner, directly or indirectly, of more than 40% of the outstanding shares of Common Stock. IPF COMPANY CREDIT FACILITY. IPF Company, an indirect wholly-owned subsidiary of the Company, has a $100.0 million revolving credit facility with Compass Bank-Houston pursuant to which it finances a portion of the IPF Program. The IPF Company Credit Facility matures June 1, 1999 at which time all amounts owed thereunder are due and payable. The IPF Company Credit Facility is secured by substantially all of IPF Company's oil and gas interests, including the notes receivable generated therefrom. IPF Company's obligations under such facility are nonrecourse to the Company. The borrowing base under the facility as of March 31, 1997 was $18.0 million and is subject to a scheduled redetermination by the lender every six months and such other redeterminations as the lender may elect to perform each year. Effective as of May 7, 1997, the borrowing base under the facility was increased to $23.0 million. As of March 31, 1997, approximately $17.3 million was outstanding under the IPF Company Credit Facility. So long as no default or event of default (as defined therein) is outstanding, borrowings under the IPF Company Credit Facility accrue interest at LIBOR plus a margin of 2.25% or, at the option of IPF Company, the prime rate published in THE WALL STREET JOURNAL. IPF Company incurs a quarterly commitment fee based on the difference between amounts outstanding under the facility and the borrowing base. The IPF Company Credit Facility contains a number of covenants that, among other things, restrict the ability of IPF Company to incur additional indebtedness or grant liens on its properties, guarantee indebtedness of any other person, dispose of assets, make loans in excess of $100,000 other than in the ordinary course of its business, issue additional shares of capital stock, engage in certain transactions with affiliates, enter into any new line of business or amend certain of its material contracts. In addition, such facility requires IPF Company to maintain a specified minimum tangible net worth. The IPF Company Credit Facility restricts the ability of IPF Company to dividend cash to its parent, Ventures Corporation, or otherwise advance cash to the Company. As of March 31, 1997, IPF Company net assets of approximately $10.0 million were restricted under the IPF Company Credit Facility. CAPITAL EXPENDITURES AND FUTURE OUTLOOK The following table sets forth the Company's capital expenditures and IPF Program investments for each of the past three years. YEAR ENDED DECEMBER 31, ------------------------------- PREDECESSOR ------------------------------- 1994 1995 1996 --------- --------- --------- (IN THOUSANDS) Acquisition of oil and gas properties... $ 65,201 $ 18,393 $ 8,513 Development and exploitation............ 4,883 7,834 7,506 Exploration............................. 15,121 23,677 12,126 IPF Program investments................. 3,315 6,606 18,608 --------- --------- --------- Total.............................. $ 88,520 $ 56,510 $ 46,753 ========= ========= ========= The Company's Board of Directors has authorized a capital budget of $125.0 million for 1997. The Company expects that $29.0 million of such capital expenditures will be spent on completion, development and exploitation activities on 10 Gulf of Mexico lease-blocks and drilling in connection with six exploratory programs. In addition, the Company expects to invest $36.0 million in new IPF Program assets. The balance of projected capital expenditures is attributable to $60.0 million in acquisitions in the Company's core operating area, $30.0 million of which will be used to finance the Funds Acquisition. The Company expects to finance these expenditures with proceeds from the Offering, cash flow from operations and borrowings under the Company's revolving credit facilities. 41 Although certain of the Company's costs and expenses may be affected by inflation, inflationary costs have not had a significant effect on the Company's results of operations. OTHER MATTERS HEDGING ACTIVITIES. In an effort to achieve more predictable cash flows and earnings and reduce the effects of the volatility of the price of oil and natural gas on the Company's operations, the Company has in the past and may in the future hedge oil and natural gas prices through the use of commodity futures, options and swap agreements and other hedge devices. While the use of these hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. The Company accounts for these transactions as hedging activities and, accordingly, gains and losses are included in oil and natural gas revenues in the period in which the related production occurs. The Company does not engage in speculative hedges. The Revolving Credit Facility imposes certain limitations on the Company's ability to enter into hedging transactions, but such limitations are not expected to constrain the Company's hedging activities in any material respect. The annual average oil and natural gas prices received by the Company have fluctuated significantly over the past three years. The Company's weighted average natural gas price received per Mcf (including the effects of hedging transactions) was $1.76, $1.54 and $1.97 during the years ended December 31, 1994, 1995, and 1996, respectively. Hedging transactions resulted in a $0.44 reduction in the Company's weighted average natural gas price received per Mcf in 1996. The Company's weighted average oil price received per Bbl during the years ended December 31, 1994, 1995 and 1996 was $14.93, $16.76 and $18.63, respectively. Hedging transactions resulted in a $2.25 reduction in the Company's weighted average oil price received per Bbl in 1996. The following table sets forth the Company's open hedging contracts for oil and natural gas and the corresponding weighted average prices to be received under various swap agreements as of March 31, 1997 and, assuming a market price based on the NYMEX twelve-month strip as of March 31, 1997, the Company's projected results from hedging activities from April 1997 to 2000.
OIL NATURAL GAS --------------------- ------------------ WEIGHTED WEIGHTED AVERAGE AVERAGE BBLS PRICE MMBTU PRICE --------- -------- ----- -------- April 1997 through December 1997........ 184,240 $17.43 7,640 $2.07 January 1998 through December 2000...... 442,550 $18.37 -- -- Projected Results: April 1997 through December 2000 (in thousands)............................ $ (1,411) $ 698
The following table sets forth the increase (decrease) in the Company's oil and natural gas revenues as a result of hedging transactions and the effects of hedging transactions on price per Mcf and price per Bbl during the periods indicated. The Company's hedging transactions in 1995 and 1996 were made at the direction of the management of Tenneco.
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------- ----------------------- PREDECESSOR PREDECESSOR SUCCESSOR ------------------------------- ----------- --------- 1994 1995 1996 1996 1997 --------- --------- --------- ----------- --------- Increase (decrease) in natural gas sales (in thousands)........................ $ -- $ -- $ (9,241) $(1,239) $ 71 Increase (decrease) in oil sales (in thousands)............................ -- 189 (1,269) (149) (337) Effect of hedging transactions on average gas sales price (per Mcf)..... -- -- (0.44) (0.21) 0.02 Effect of hedging transactions on average oil sales price (per Bbl)..... -- 0.45 (2.25) (1.28) (2.39)
42 NATURAL GAS BALANCING. The Company incurs certain gas production volume imbalances in the ordinary course of business and utilizes the sales method to account for such imbalances. Under this method, income is recorded based on the Company's net revenue interest in production taken for delivery. Management does not believe that the Company had any material gas imbalances as of December 31, 1995 or 1996. ACCOUNTING PRONOUNCEMENTS. On October 23, 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), which establishes a fair value method for accounting for stock-based compensation plans either through recognition or disclosure. SFAS 123 encourages, but does not require, companies to adopt the fair value method of accounting in place of the existing intrinsic value method of accounting for stock-based compensation. The Company currently utilizes the intrinsic value method of accounting and will continue to use this method. When applicable, the Company will disclose the pro forma adjustments to net income and earnings per share as required by SFAS 123 in the notes to the Combined and Consolidated Financial Statements of the Company included elsewhere in this Prospectus. BUSINESS AND PROPERTIES THE COMPANY Domain is an independent oil and gas company engaged in the exploration, development, production and acquisition of domestic oil and natural gas properties, principally in the Gulf Coast region. The Company complements these activities with its Independent Producer Finance Program (the "IPF Program") pursuant to which it invests in oil and natural gas reserves through the acquisition of term overriding royalty interests. During 1996, approximately 92% of the Company's revenue was generated by oil and natural gas sales and approximately 8% of the Company's revenue was generated by the IPF Program. The Company's future growth will be driven by development, exploitation and exploration drilling on its existing properties, by the continuation of an opportunistic acquisition strategy in the Gulf Coast region and by further expansion of the IPF Program. The Company was formed in December 1996 by the management of Tenneco Ventures Corporation and an affiliate of First Reserve Corporation to acquire (the "Acquisition") Tenneco Ventures Corporation and certain of its affiliates (collectively, "Tenneco Ventures"). Senior management of the Company established Tenneco Ventures in 1992 as a separate business unit of its former parent, Tenneco Inc. ("Tenneco"), to engage in exploration and production, oil and gas program management, producer financing and related activities. All of the Company's executive officers are veterans of the Tenneco organization, and 11 of the Company's 19 technical personnel have Tenneco Oil Company backgrounds. Approximately 85% of the Company's employees, including all of its management, have purchased shares of Common Stock in the Company. During the last four years, the Company has grown primarily through the opportunistic acquisition of Gulf of Mexico properties and the subsequent development, exploitation and exploration of these properties, resulting in substantial increases in its reserves and production. The Company believes that its acquisition costs, lease operating costs and net general and administrative costs on a per Mcfe basis are low relative to other companies operating principally in the Gulf Coast region. From 1994 through 1996, the Company completed 11 acquisitions aggregating $106.9 million, with an average cost of proved reserves estimated at the time of acquisition of $0.48 per Mcfe. Eight of the 11 acquisitions were Gulf Coast region properties. In 1996 the Company achieved a lease operating expense of $0.42 per Mcfe of production and a net general and administrative expense (excluding Tenneco overhead allocations) of $0.12 per Mcfe of production. The Company's pro forma estimated net proved reserves as of December 31, 1996 were 153.8 Bcfe, and its pro forma average daily production during 1996 was 85.6 MMcfe, each of which represents a twelvefold increase from levels in 1993. Approximately 54% of these reserves were natural gas, and approximately 67% of proved reserves were classified as proved developed producing. On a pro forma basis as of December 31, 1996, the Company had a PV-10 Reserve Value of $213.0 million, which does not include reserve value attributable to the IPF Program. 43 Through the IPF Program, the Company complements its exploration and production activities by providing capital to independent producers in return for term overriding royalty interests in oil and gas properties owned by such producers. From its inception in 1993 through December 31, 1996, the IPF Program has generated an average return on net assets of approximately 19%. In addition, the Company believes that the IPF Program offers a lower level of reserve, production and price risk than that associated with working interest ownership. From inception through December 31, 1996, the Company completed 40 transactions under its IPF Program. At December 31, 1996, based on Company estimates and assuming prices of $2.10 per Mcf of natural gas and $21.00 per Bbl of oil, the net present value attributable to IPF Program assets was $25.4 million. The Company reported net income of $7.0 million, $0.5 million and $0.4 million in 1996, 1995 and 1994, respectively. The Company reported unaudited net loss of $0.3 million and unaudited net income of $2.8 million for the three-month periods ended March 31, 1997 and 1996, respectively. Based on unaudited financial information available to the Company for the period from April 1, 1997 to the date of this Prospectus, the Company estimates that it will report net income (loss) on approximately a "break-even" basis for the three-month period ended June 30, 1997. Pro forma net income for the year ended December 31, 1996 was $11.8 million. See "Prospectus Summary -- Summary Historical and Pro Forma Combined and Consolidated Financial Data." The Company generated earnings before stock compensation expense, interest, income taxes, depreciation, depletion and amortization ("EBITDA") plus IPF Program return of capital of $41.1 million in 1996, $26.2 million in 1995 and $7.7 million in 1994. IPF Program return of capital was $4.6 million in 1996, $2.6 million in 1995 and $3.5 million in 1994. The Company's 1996 pro forma EBITDA plus IPF Program return of capital was $55.5 million. The Company's Board of Directors has authorized a capital budget of $125.0 million for 1997. These planned expenditures consist of $29.0 million for development and exploration expenditures, $36.0 million for IPF Program investments and $60.0 million for acquisitions in the Company's core operating area, $30.0 million of which is pending. See " -- Certain Transactions -- The Funds Acquisition." The Company's principal executive offices are located at 1100 Louisiana, Suite 1500, Houston, Texas 77002 and its telephone number is (713) 757-5662. The mailing address of the Company's principal executive offices is P.O. Box 2229, Houston, Texas 77252-2229. BUSINESS STRATEGY The Company's objective is to maximize shareholder value by growing reserves, production, cash flow and earnings through the opportunistic acquisition of Gulf Coast region properties with underexploited value. The Company applies 3-D seismic and other advanced technologies to development, exploitation and exploration. These activities are complemented by the continued expansion of the IPF Program. Fundamental to the execution of the Company's strategy is its foundation of experienced technical talent strengthened by a high level of financial, transactional and risk-management expertise resulting, in part, from the former association of the Company and its employees with Tenneco. Following the Offering, the Company will be in a strong financial position to pursue acquisitions and other growth opportunities. GEOGRAPHIC FOCUS. The Company concentrates its primary oil and gas activities in the Gulf Coast region, specifically in state and federal waters off the coast of Texas and Louisiana. The Company believes this region remains attractive for future development, exploration and acquisition activities. This is due to the availability of seismic data, significant reserve potential and a well developed infrastructure of gathering systems, pipelines and platforms with ready access to drilling services and equipment in the region. In addition, the Company's relationships with major oil companies and independent producers operating in the region allow continued access to new opportunities. This geographic focus has enabled the Company to build and utilize a base of region-specific geological, geophysical, engineering and production expertise. The Company's geographic focus allows it to manage a large asset base with relatively few employees, thus permitting the Company to control expenses and add Gulf of Mexico production at a relatively low 44 incremental cost. The Company engages in IPF Program activities throughout the onshore regions of the United States, with a principal geographic focus in the Gulf Coast region. ACQUISITION OF PROPERTIES WITH UNDEREXPLOITED VALUE. The Company employs an acquisition strategy targeted primarily at purchases of Gulf Coast region producing properties from major oil companies and large independents. These properties provide opportunities to increase reserves, production and cash flow through development and exploitation drilling and lease operating expense reduction. The Company manages its acquired properties by working proactively with its joint interest partners to accelerate development, identify exploitation opportunities and implement cost controls on these properties. DEVELOPMENT, EXPLOITATION AND EXPLORATION. The Company integrates its reservoir and production engineering expertise with its geologic and seismic interpretation abilities to enhance the results of its exploration and production business. The Company applies workovers, recompletions, secondary recovery operations and other production enhancement techniques on its existing properties to increase recoverable reserves, production and cash flow. Additionally, the Company uses advanced technology in both its development and exploration activities to reduce drilling risks and finding costs and to prioritize its drilling prospects based on return potential. The Company utilizes 3-D seismic data to develop the majority of its drilling opportunities. Eighty-five percent of the wells in which the Company participated in 1996 were developed using 3-D seismic data. The Company's ability to integrate geophysics with detailed geology, reservoir engineering and production engineering allows it to identify multiple development and exploratory prospects in mature producing fields that were not identified through earlier technologies. The Company currently employs six geoscientists with an average experience level of more than 16 years and operates two geophysical workstations interpreting 3-D seismic data over twelve fields and six exploratory programs. The Company intends to expand its geoscience team in 1997. The Company has assembled a multiyear inventory of development, exploitation and exploratory drilling opportunities in the Gulf Coast region and has identified more than 70 drilling and recompletion opportunities for 1997. Most of the properties comprising this inventory are located in fields that have well-established production histories. The Company believes these properties may yield significant additional recoverable reserves through the application of advanced exploration and development technologies. The Company participated in the drilling of nine development wells and 33 exploratory wells in 1996, of which 78% and 61%, respectively, were successful. CONTINUED EXPANSION OF THE IPF PROGRAM. The Company has leveraged its expertise in oil and gas reserve appraisal and evaluation to develop and grow the IPF Program. The Company believes this program offers an attractive risk/reward balance and stable earnings. The oil and gas companies that establish a relationship with the Company through the IPF Program often come to view the Company as a prospective working interest partner for their drilling or acquisition projects. Management believes that the investment opportunities, market information and business relationships generated as a result of the IPF Program provide the Company with a strategic advantage over other independent oil and gas companies that are not engaged in this business. As a result of the Company's efficiency in originating and closing IPF Program transactions in the $0.5 to $5.0 million range, the Company currently encounters only limited competition from alternate sources of capital for investment in quality properties and projects of independent oil and gas companies. The Company has budgeted $36.0 million for investment in IPF Program transactions in 1997. The Company closed six IPF Program transactions in the first quarter of 1997 for an aggregate of $9.2 million. In addition, the Company is currently evaluating over 30 transactions, all of which satisfy the Company's initial screening criteria. CERTAIN TRANSACTIONS ACQUISITION OF COMMON STOCK BY FUND VII. Concurrently with consummation of the Offering, Fund VII, the Company's principal stockholder, has agreed to purchase 643,037 shares of Common Stock, at a price per share equal to the Price to Public set forth on the cover page of this Prospectus, for an aggregate 45 purchase price of $8,681,000 (the "Concurrent Sale"). See "Transactions with Management and First Reserve --Acquisition of Common Stock by Fund VII." THE FUNDS ACQUISITION. The Company previously sponsored and managed two oil and gas investment programs (collectively, the "Funds") for institutional investors. The Company has entered into a definitive agreement with the investors in the Funds to acquire certain property interests from such investors upon consummation of the Offering (the "Funds Acquisition"). These property interests are primarily located in the Gulf Coast region and have combined proved reserves of 33.0 Bcfe. Furthermore, these interests include 18,209 net undeveloped leasehold acres with 3-D seismic based exploration potential. The Company will acquire these reserves at an aggregate cost of $30.0 million, effective January 1, 1997, for a unit cost of $0.65 per Mcfe of net proved reserves. The Funds Acquisition will provide the Company with a larger interest in certain of its existing properties, including the West Delta 30 Field in the Gulf of Mexico. THE MICHIGAN DISPOSITION. The Company recently sold its interests in a natural gas development project located in northwestern Michigan (the "Michigan Development Project"). The Company views this transaction (the "Michigan Disposition") as a disposition of non-core assets and a further enhancement of its focus on the Gulf Coast region. As a result of the Michigan Disposition, the Company sold 28.8 Bcfe of proved reserves as of December 31, 1996 (of which 3.3 Bcfe were proved developed producing as of December 31, 1996) and interests in a pipeline company and a processing company. See "Unaudited Condensed Pro Forma Financial Statements" and the related notes thereto. The Company retained its interests in Oceana Exploration Company, L.C., a Michigan exploration company. See "Business and Properties -- Exploration Programs -- Michigan." DEVELOPMENT, EXPLOITATION AND EXPLORATION PROJECTS Set forth below is a description of the development and exploitation projects that the Company's management expects to pursue during calendar year 1997. While the Company presently intends to complete these projects, the number, type and timing thereof are subject to change as a result of many factors, including the availability of capital to fund such projects, initial test results, results of drilling by third parties on adjacent blocks, weather, oil and gas prices and other general economic conditions that are beyond the control of the Company. In addition, because the Company does not operate most of its properties, it can influence but does not have the ability to control the initiation and timing of many capital projects. The Company currently anticipates spending approximately $29.0 million during calendar year 1997 on development and exploration projects, including those described below. There can be no assurance that any of these projects can be successfully developed within budget, or that, once developed, such projects will be commercially productive. See "Risk Factors -- Volatility of Oil and Natural Gas Prices; Marketability of Production," "-- Reserve Replacement Risks," "-- Reliance on Estimates of Oil and Natural Gas Reserves" and "-- Substantial Capital Requirements." RABBIT ISLAND FIELD. In 1993 the Company purchased a 25% interest in the Rabbit Island Field located in Louisiana state waters. The field has produced in excess of 1.2 Tcf of gas and 46 MMBbls of oil. A 105 square-mile 3-D survey was interpreted in 1993, and six of seven wells drilled since that time have been successful, discovering 34.3 Bcfe of gross proved reserves (7.2 Bcfe net to the Company's interest). The Company, Texaco Exploration and Production Inc. ("Texaco") and Shell Offshore Inc. ("Shell") are conducting a joint field study to delineate additional exploitation opportunities in this field. This study is expected to be completed in the third quarter of 1997. The preliminary results of the study indicate at least 25 potential exploitation opportunities. WEST DELTA 30. In 1995 the Company purchased a 70% working interest in the West Delta 30 Field in the Gulf of Mexico from Shell and initiated an integrated geological, geophysical and 3-D seismic study in the first half of 1996. As a result of this study, the Company identified eight additional development drilling locations and three deeper pool prospects that the Company believes have significant exploratory potential. Based on the Company's proposal, Exxon Company, U.S.A. ("Exxon"), the operator, is drilling a well to test this field's deeper exploratory potential and is scheduled to drill a development well by year-end 1997. 46 MATAGORDA ISLAND 519. In late 1994 the Company purchased 13 producing fields in the Gulf of Mexico from Pennzoil Company ("Pennzoil") for $51.3 million (the "Pennzoil Acquisition"), including the Matagorda Island 519 Field. The Company owns working interests of 15.8% and 25% in this field, which is operated by Amoco Production Company ("Amoco"). Workover operations on two wells in this field were completed in the first quarter of 1997, increasing gross production by 10 MMcf per day. Workover operations to recomplete a third well are in progress. The Company believes that significant development and exploratory potential remains in the field. Amoco has purchased a 3-D seismic survey to delineate these opportunities, in which the Company owns a 25% working interest. HIGH ISLAND 110/111. The Company purchased its initial interest in this Texaco-operated field as part of the Pennzoil Acquisition and currently holds a 17% working interest. The Company has identified several recompletion zones and two proved undeveloped drilling locations in the field using 3-D seismic data to reinterpret an internal field study. These wells are scheduled to be drilled in 1997. WASSON FIELD. In June 1996 the Company acquired a 34.7% working interest in the Cornell Unit in the Wasson Field in West Texas. Approximately 1.5 billion Bbls of oil have been produced from the San Andres reservoir from which the Cornell Unit produces. The field was initially waterflooded in 1965, and a CO2 flood was initiated in 1985 utilizing the water alternating-gas injection method of enhanced oil recovery. Because the field has been restored to its original pressure as the result of tertiary recovery activities, at year-end 1996 the Company recommended the cessation of CO2 purchases for the next four to five years. This recommendation was adopted by the unit working interest owners. As a result, the Company expects to increase its annual cash flow from the field by $1.9 million. The Company, working with unit operator Exxon, has identified up to 30 infill drilling locations. Furthermore, pressure tests performed recently in an adjoining unit indicate that the upper gas-bearing sands may be produced separately from the oil reservoir. Exxon and the Company plan to test the feasibility of producing these gas-bearing sands in 1997. PRODUCER INVESTMENT ACTIVITIES IPF PROGRAM. The Company complements its exploration and production activities with its IPF Program pursuant to which it invests in oil and natural gas reserves through the acquisition of term overriding royalty interests. From inception through December 31, 1996, the IPF Program has generated an average return on assets employed of approximately 19%. The IPF Program was established in 1993 and is funded by a combination of equity provided by the Company and third-party debt. The IPF Program enables independent producers to obtain nonrecourse financing, while maintaining ownership of their properties, through the sale to the Company of term overriding royalty interests. Transaction sizes for the program generally have ranged from $0.5 million to $5.0 million. A strong customer focus has resulted in a large majority of IPF Program customers having returned for additional funding requests and approximately a 100% average annual growth in year-end customers over the last two years. From inception through December 31, 1996, the Company completed 40 transactions under the IPF Program. At December 31, 1996, based on Company estimates and assuming prices of $2.10 per Mcf of natural gas and $21.00 per Bbl of oil, the net present value attributable to IPF Program assets was $25.4 million. The Company believes that the IPF Program offers a lower level of reserve, production and price risk than that associated with working interest ownership. Such risks are mitigated through strict adherence to the Company's IPF Program underwriting guidelines and the Company structuring its investment to receive an agreed upon share of revenues from identified properties until a contractual return is attained. The Company's underwriting guidelines include the requirement of sufficient reserve value, or collateral coverage, in excess of the IPF Program investment and the requirement that the IPF Program investments be structured so as not to bear production expenses. Additionally, because the Company originates dollar-denominated IPF Program assets, the effect of commodity price declines on the expected return on these assets is reduced as compared to working interest ownership. This reduction in price risk occurs because the Company structures its IPF Program term overriding royalty interests to result in a contractual return before the overriding royalty interest is discharged. As a result, IPF Program customers must deliver proceeds from 47 the sale of oil and gas production until such return is achieved by the Company on its investment, regardless of the commodity price realized by the customer over the term of the transaction. On June 7, 1996, the Company's indirect wholly-owned subsidiary, IPF Company, entered into the IPF Company Credit Facility pursuant to which it finances the purchase of term overriding royalty interests under the IPF Program. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- IPF Company Credit Facility." THE GASFUND. In May 1993, Ventures Corporation and EnCap Ventures 1993 Limited Partnership ("EnCap") finalized a partnership arrangement named the GasFund ("GasFund"). The GasFund was a financing vehicle that utilized bank debt supported by limited Company and EnCap credit enhancements, which provided production-based financing to independent producers for oil and gas projects generally exceeding $10.0 million. Currently, there are no existing obligations and no outstanding transactions associated with the GasFund. As a result of the Company's assessment that the market to provide financing in amounts greater than $10.0 million is competitive to the point of unattractive returns, and the reduced credit enhancement capabilities of the Company as a result of the Acquisition, the Company does not anticipate participating in any future GasFund transactions. EXPLORATION PROGRAMS During 1996 the Company participated in 33 exploration wells with 20 completions, for a 60.6% success rate. In addition to the exploration that the Company may conduct on its existing properties, the Company intends to continue participation in exploration activities through various joint venture programs, including those summarized below. SOUTH TEXAS -- COX & PERKINS DRILLING PROGRAM. The Cox & Perkins drilling program is an exploration effort in the expanded Yegua gas trend within Jackson and Wharton Counties, Texas. The Company holds a 10% working interest in this program, which utilizes 3-D seismic data to delineate potential structural and stratigraphic traps within the trend. The program sponsor and operator is Cox & Perkins Exploration, Inc., a privately-held, independent exploration and production company. Thirty-one wells have been drilled to date, of which 21 are productive. Current gross daily production from the wells is approximately 41 MMcf of natural gas and 1,181 Bbls of condensate. One additional development well is scheduled to be drilled in 1997. SOUTH TEXAS -- KENEDY RANCH. The Kenedy Ranch program is an exploration effort to delineate expanded Frio reservoir traps on this large ranch in Kenedy County along the southern Texas Gulf Coast. Output Exploration Company, Inc., Hunt Petroleum Company and the Company have shot a 180 square mile 3-D seismic survey and acquired 49,000 acres in defining potential drill sites. The program operator is Hunt Petroleum Company. Interpretation of the seismic data has identified five primary prospect areas. The first well drilled was a dry hole and a second well is currently being drilled. The Company holds a 12.5% working interest in this project. SOUTH LOUISIANA SALT DOMES. The Company and an affiliate of Shell, together with the operator, Texaco, are engaged in an effort to delineate the exploitation and exploration potential of three salt domes in southern Louisiana, including the Rabbit Island Field. The group is utilizing 3-D seismic to identify remaining potential. Ten out of 12 wells drilled to date have been successful, discovering approximately 63.2 Bcfe of gross proved reserves (12.0 Bcfe net to the Company's interest). The Company's net working interest in these program wells ranges from 7.6% to 25%. ANADARKO BASIN. The Anadarko Basin seismic program is an exploration effort within the Morrow Sand trend. The Company and the operator, Brigham Exploration Company, are utilizing 3-D seismic technology to delineate potential gas reservoirs in the channel-controlled Upper Morrow Sand. Additional objectives are present both above and below the main objective. The program participants hold 35,750 gross acres under lease. Six 3-D seismic surveys have been shot and the evaluation thereof is in progress. Eight wells have been drilled to date, of which two are producing and two are nearing completion. The Company 48 holds a 70% working interest in two of the 3-D areas, a 37.5% working interest in three of the 3-D areas and a 35% working interest in the remainder. Three additional wells are currently being drilled or are scheduled to be drilled in the first half of 1997. PERMIAN BASIN. The Permian Basin drilling program is an exploration effort targeting the Wolfcamp and Strawn Formations. The Company and the operator, Rand Paulson Oil Company, Inc., a privately-held, independent exploration and production company, combine 3-D seismic technology with detailed, biostratigraphic zonation work to delineate potential traps. Numerous secondary objectives exist above the primary targets. The program participants hold 32,400 gross acres under lease. To date, the Company has participated in 15 wells, of which five were productive and three are currently being drilled. Eleven additional leads and prospects are being evaluated for future drilling opportunities. The Company holds a 50% working interest in the program. MICHIGAN. Oceana Exploration Company, L.C., a Texas limited liability company and 80% owned subsidiary of Ventures Corporation, is obligated to drill, or cause to be drilled, four exploratory wells in Oceana County, Michigan by the end of 1997. Two such wells have been drilled and are awaiting completion. Through this program, the Company is targeting the Niagaran reef trend, which the Company believes has significant exploratory potential. SIGNIFICANT PROPERTIES The following table sets forth the net proved reserves and the PV-10 Reserve Value attributable to the Company's significant properties as of December 31, 1996 and on a pro forma basis as of December 31, 1996 after giving effect to the Funds Acquisition and the Michigan Disposition. The reserve data set forth below does not include reserves or reserve value attributable to the IPF Program. At December 31, 1996, the Company estimates that the net present value attributable to IPF Program assets was $25.4 million.
PRO FORMA AS OF DECEMBER 31, 1996 AS OF DECEMBER 31, 1996 ------------------------------------- ------------------------------------- NET % OF TOTAL PV-10 NET % OF TOTAL PV-10 PROVED NET RESERVE PROVED NET RESERVE RESERVES PROVED VALUE RESERVES PROVED VALUE (BCFE) RESERVES (IN MILLIONS) (BCFE) RESERVES (IN MILLIONS) -------- ---------- ------------- -------- ---------- ------------- GULF COAST FIELDS Matagorda Island 519............... 14.2 9.5% $ 33.6 14.2 9.2% $ 33.6 West Delta 30...................... 11.5 7.7% 18.4 28.8 18.7% 46.1 High Island 110/111................ 5.6 3.7% 8.4 5.6 3.6% 8.4 Eugene Island 372.................. 3.0 2.0% 4.7 3.0 2.0% 4.7 Rabbit Island...................... 3.0 2.0% 10.3 3.0 2.0% 10.3 Main Pass 74....................... 2.5 1.7% 4.7 2.5 1.6% 4.7 Other Gulf Coast................... 30.7 20.6% 61.8 46.4 30.2% 99.8 -------- ---------- ------------- -------- ---------- ------------- 70.5 47.2% $ 141.9 103.5 67.3% $ 207.6 OTHER FIELDS Wasson Field....................... 50.3 33.6% $ 12.6 50.3 32.7% $ 12.6 Michigan Development Project....... 28.8 19.2% $ 36.9 -- -- -- -------- ---------- ------------- -------- ---------- ------------- Total......................... 149.6 100% $ 191.4(1) 153.8 100% $ 220.2(1) ======== ========== ============= ======== ========== =============
- ------------ (1) Does not reflect losses calculated to be incurred from future hedging activities. As a result of such losses, PV-10 Reserve Value and pro forma PV-10 Reserve Value as of December 31, 1996 were $184.8 million and $213.0 million, respectively. MATAGORDA ISLAND 519 FIELD. The Matagorda Island Block 519 Field is located offshore Texas, approximately 12 miles southeast of Matagorda County, in approximately 69 feet of water. Amoco discovered the field in 1983 and is the current operator. Four wells produce gas from lower Miocene Sands at a depth of approximately 14,800 feet to 17,000 feet. This field is currently producing 59.1 MMcf of gas 49 per day and 157 Bbls of oil per day (7.7 MMcf and 7.4 Bbls net to the Company's interest). The Company acquired an average 20% working interest in the field effective October 1, 1994 pursuant to the Pennzoil Acquisition. WEST DELTA 30 FIELD. The West Delta 30 Field is located offshore Louisiana, approximately 65 miles south-southeast of New Orleans, in approximately 50 feet of water. The field was discovered in 1954 and has had over 200 wells drilled, the last of which was drilled in the early 1990s. Effective January 1, 1995, the Company acquired 70% of Shell's working interests in this field, which ranged from 50% to 100%. Cumulative production to date is approximately 300 Bcf of gas and 200 MMBbls of oil and the field currently produces 5.9 MMcf of gas per day and 1,551 Bbls of oil per day (1.65 MMcf and 434 Bbls net to the Company's interest). Seneca Resources Corporation and Exxon are the operators of the field. The West Delta 30 Field produces from Pliocene and Miocene Sands at a depth of approximately 6,500 feet to 11,000 feet that are trapped against a salt dome feature. HIGH ISLAND 110/111 FIELD. High Island Blocks 110 and 111 are located offshore Texas, approximately 20 miles offshore of Jefferson County, in approximately 30 feet of water. The field was discovered in 1973 and is currently operated by Texaco. The 17.7% average working interest owned by the Company was acquired from Pennzoil in 1994 and Sonat Exploration Company in 1996. Cumulative production to date from this field has been approximately 309 Bcf of gas and 2.6 MMBbls of oil and the field currently produces 9.5 MMcf of gas per day and 173 Bbls of oil per day (1.4 MMcf and 24.6 Bbls net to the Company's interest). The High Island 110/111 Field produces from Miocene Sands at a depth of approximately 7,500 feet to 12,500 feet that are trapped in a faulted anticline, downthrown to a major listric fault. EUGENE ISLAND 372 FIELD. Eugene Island Block 372 is located offshore Louisiana, approximately 168 miles southwest of New Orleans, in approximately 400 feet of water. This field was discovered in 1978 and has produced approximately 44 Bcf of gas and 1.5 MMBbls of oil from nine wells. Currently, there are five active wells in this field. The Company acquired its 37.5% working interest in this field as a result of the Pennzoil Acquisition. The Eugene Island 372 Field produces from Pleistocene Sands at a depth of approximately 5,100 feet to 9,900 feet. The reservoir trap is characterized by complex faulting and highly stratigraphic sands. Unocal Corporation ("Unocal"), the current operator, is in the process of interpreting a new 3-D seismic survey covering the block and has identified several untested seismic amplitudes. Work is in progress to evaluate the size and economic viability of these leads. RABBIT ISLAND. The Rabbit Island Field is located in Louisiana state waters, approximately 95 miles southwest of New Orleans in approximately ten feet of water. This field was discovered in 1939 and has produced in excess of 1.2 Tcf of gas and 46 MMBbls of oil. The field is currently producing 27.4 MMcf of gas per day and 48 Bbls of oil per day (5.4 MMcf and 9.0 Bbls net to the Company's interest). Benton Oil & Gas Company of Louisiana ("Benton") earned a 50% working interest in this field from Texaco by acquiring and interpreting a 105 square mile 3-D seismic survey across the field. In 1993, the Company bought a 25% working interest from Benton. In early 1996, Shell acquired Benton, leaving Texaco, Shell, and the Company as working interest owners. The productive interval is Miocene Sands at a depth of approximately 1,600 feet to 12,000 feet. The field is a piercement salt dome with associated radial faulting. MAIN PASS 74. Main Pass Block 74 is located in Louisiana state waters, approximately 85 miles southeast of New Orleans in approximately 75 feet of water. This field was discovered in 1981 and is currently operated by Exxon. Cumulative production from this field has been approximately 20 MMBbls of oil and 41 Bcf of gas. The Company acquired an average working interest of 14.4% in this field as a result of the Pennzoil Acquisition. All production from the Main Pass 74 Field has come from Miocene Puma Sand at a depth of approximately 10,000 feet to 10,500 feet. The reservoir trap is a westerly-dipping, stratigraphic trap. The Company has identified one additional drilling location within the field, and Exxon has expressed an interest in drilling a horizontal well into the reservoir. WASSON FIELD. The Wasson Field is located in Gaines and Yoakum Counties, Texas, approximately 80 miles northwest of Midland, Texas. In June 1996 the Company acquired from Kerr-McGee Corporation 34.7% and .17% working interests in the Cornell and Denver Units at this field, respectively. These two 50 units are currently producing 41,469 Bbls of oil per day (539 Bbls net to the Company's interest). The Wasson Field was discovered in 1937. The Cornell and Denver Units are currently operated by Exxon and Altura Energy, Inc. (a joint venture between Shell and Amoco), respectively. Approximately 1.5 billion barrels of oil have been produced from the San Andres reservoir. The San Andres produces in both the Cornell and Denver Units at depths of approximately 5,500 feet to 6,000 feet. This field was initially waterflooded in 1965, and a CO2 flood was initiated in 1985 utilizing the water-alternating-gas injection method of enhanced oil recovery. OIL AND NATURAL GAS RESERVES The following table summarizes the estimates of the Company's historical net proved reserves as of December 31, 1994, 1995 and 1996 and pro forma net proved reserves as of December 31, 1996, and the present values attributable to these reserves at such dates. The reserve data and present values as of December 31, 1994 have been estimated by DeGolyer and other third-party petroleum engineers. The reserve data and present values as of December 31, 1995 have been estimated by DeGolyer and Netherland, Sewell. The reserve data and present values as of December 31, 1996 have been estimated by (i) Netherland, Sewell, with respect to the West Delta 30 Field, (ii) by other third-party petroleum engineers with respect to the Michigan Development Project and (iii) by DeGolyer with respect to all of the Company's other oil and natural gas properties. See "Significant Properties." The pro forma December 31, 1996 reserve data and present values give effect to the Funds Acquisition and the Michigan Disposition. Summaries of the December 31, 1996 reserve reports and the letters of DeGolyer and Netherland, Sewell with respect thereto are included as Appendix A to this Prospectus. The reserve data set forth below does not include reserves or reserve value attributable to the IPF Program. At December 31, 1996, the Company estimates that the net present value attributable to IPF Program assets was $25.4 million. AS OF DECEMBER 31, -------------------------------------------- PRO FORMA 1994 1995 1996(1)(2) 1996(1) --------- ---------- ---------- --------- PROVED RESERVES: Natural Gas (MMcf)............... 73,399 82,682 81,338 83,418 Oil and condensate (MBbls)....... 4,109 2,197 11,380 11,736 Total (MMcfe).................... 98,056 95,865 149,616 153,834 PROVED DEVELOPED PRODUCING RESERVES : Natural Gas (MMcf)............... 46,544 45,386 36,293 44,292 Oil and condensate (MBbls)....... 967 1,219 9,248 9,673 Total (MMcfe).................... 52,346 52,700 91,781 102,330 PV-10 Reserve Value (in thousands).................. $61,812 $ 103,931 $ 184,816 $ 213,030 Standardized measure of discounted future net cash flows (in thousands)...................... $68,492 $ 98,999 $ 154,424 -- - ------------ (1) The present values as of December 31, 1996 were prepared using a weighted average sales price of $22.50 per Bbl of oil and $3.38 per Mcf of natural gas. The pro forma present values as of December 31, 1996 were prepared using a weighted average sales price of $23.63 per Bbl of oil and $3.59 per Mcf of natural gas. By comparison, the present values as of December 31, 1995 were prepared using a weighted average sales price of $18.76 per Bbl of oil and $3.30 per Mcf of natural gas. (2) Includes the Company's proportionate share of reserves attributable to the Michigan Development Project. The estimation of reserve data is a subjective process of estimating the recovery of underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of the available data, the assumptions made, and engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows therefrom necessarily depend upon a number of variable factors and 51 assumptions, including historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. Any such estimates are therefore inherently imprecise, and estimates by other engineers, or by the same engineers at a different time, might differ materially from those included herein. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in the estimates and it is likely that such variances will be significant. Any significant variance from the assumptions could result in the actual quantity of the Company's reserves and future net cash flow therefrom being materially different from the estimates set forth in this Prospectus. In addition, the Company's estimated reserves may be subject to downward or upward revision, based upon production history, results of future exploration and development, prevailing oil and natural gas prices, operating and development costs and other factors. Estimates with respect to proved undeveloped reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. The present value of future net cash flows shown above should not be construed as the current market value, or the market value as of December 31, 1996, or any prior date, of the estimated oil and natural gas reserves attributable to the Company's properties. In accordance with applicable requirements of the Commission, the estimated discounted future net cash flows from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. The Company's PV-10 Reserve Value as of December 31, 1996 was prepared using a weighted average sales price of $22.50 per Bbl of oil and $3.38 per Mcf of natural gas. These prices were substantially higher than prices used by the Company to calculate PV-10 Reserve Value in recent years. The Company estimates that a substantial decline in prices relative to year-end 1996 would cause a substantial decline in the Company's PV-10 Reserve Value. For example, compared to the pro forma data set forth in the above table as of December 31, 1996, a $0.10 per Mcf decline in natural gas prices, holding all other variables constant, would decrease the Company's pro forma December 31, 1996 PV-10 Reserve Value by approximately $6.4 million, or 2.8%, and a $1.00 per Bbl decline in oil and condensate prices would decrease the Company's PV-10 Reserve Value by approximately $4.0 million, or 1.8%. While the foregoing calculations should assist the reader in understanding the effect of a decline in oil or natural gas prices on the Company's PV-10 Reserve Value, such calculations assume that quantities of recoverable reserves are constant and therefore would not be accurate if prices decreased to a level at which reserves would no longer be economically recoverable. In accordance with methodology approved by the Commission, specific assumptions were applied in the estimates of future net cash flows. Under this methodology, estimated future net cash flows are determined by reducing estimated future gross cash flows to the Company for oil and natural gas sales by the estimated costs to develop and produce the underlying reserves, including future capital expenditures, operating costs, transportation costs, royalty and overriding royalty burdens. Estimated future production costs were based on actual annual production costs incurred during the reported period. A portion of the Company's proved reserves are undeveloped, and future development costs thereon were calculated based on a continuation of present economic conditions. Future net cash flows were discounted at 10% per annum to arrive at discounted future net cash flows. The 10% discount factor used to calculate present value is required by the Commission, but such rate is not 52 necessarily the most appropriate discount rate. Present value of future net cash flows, irrespective of the discount rate used, is materially affected by assumptions as to timing of future natural gas and oil prices and production, which may prove to be inaccurate. In addition, the calculations of estimated net revenues do not take into account the effect of certain cash outlays, including among other things, general and administrative costs, interest expense and dividends. The Company's estimated proved reserves have not been filed with or included in reports to any federal authority or agency. PRODUCTION, PRICES AND OPERATING EXPENSES
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------------- ------------------------ PREDECESSOR PREDECESSOR SUCCESSOR ------------------------------- ----------- --------- 1994 1995 1996 1996 1997 --------- --------- --------- ----------- --------- PRODUCTION VOLUMES: Natural gas (MMcf)................. 2,334 18,065 21,192 5,828 3,668 Oil and liquids (MBbls)............ 83 424 564 116 141 Total (MMcfe)...................... 2,832 20,609 24,575 6,524 4,516 AVERAGE REALIZED PRICES:(1) Natural gas (per Mcf).............. $ 1.76 $ 1.54 $ 1.97 $ 2.36 $ 2.75 Oil and liquids (per Bbl).......... 14.93 16.76 18.63 16.52 19.06 EXPENSES (PER MCFE): Lease operating expense............ $ 0.63 $ 0.39 $ 0.42 $ 0.33 $ 0.68 Production taxes................... 0.01 0.03 0.05 0.04 0.09 Depreciation, depletion and amortization..................... 1.03 1.08 1.01 1.19 0.69 General and administrative, net(2)........................... 0.26 0.16 0.12 0.14 0.14
- ------------ (1) Reflects the actual realized prices received by the Company, including the results of the Company's hedging activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Matters -- Hedging Activities." (2) Includes production attributable to properties managed for the Funds for the periods indicated and excludes fees received from investors and overhead allocations from Tenneco. Including Tenneco allocations, average net general and administrative expenses per Mcfe for the years ended December 31, 1994, 1995, and 1996 would be $0.26, $0.20 and $0.28, respectively. 53 PRODUCTIVE WELLS The following table sets forth the number of productive oil and natural gas wells in which the Company owned an interest as of March 31, 1997. TOTAL PRODUCTIVE WELLS -------------------- GROSS NET --------- --------- OFFSHORE Natural gas............................. 67.0 18.9 Oil..................................... 35.0 7.4 --------- --------- Total.............................. 102.0 26.3 ONSHORE Natural gas............................. 43.0 10.0 Oil..................................... 838.0(1) 25.6(1) --------- --------- Total.............................. 881.0 35.6 TOTAL OFFSHORE AND ONSHORE Natural gas............................. 110.0 28.9 Oil..................................... 873.0(1) 33.0(1) --------- --------- Total.............................. 983.0 61.9 ========= ========= - ------------ (1) Includes 756 gross wells in the Wasson Field (Denver Unit) in which the Company holds a 0.17% working interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. In wells with multiple completions mechanically isolated zones are counted as individual wells. 54 ACREAGE DATA The following table sets forth the approximate developed and undeveloped acreage in which the Company held a leasehold mineral or other interest as of March 31, 1997. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether or not such acreage contains proved reserves. TOTAL ACREAGE DEVELOPED UNDEVELOPED -------------------- ACREAGE ACREAGE AREA (GROSS) (NET) (NET) (NET) - ------------------------------ --------- --------- --------- ----------- Onshore: Alabama.................. 18,571 2,889 2,889 -- Louisiana................ 9,630 3,843 1,058 2,785 Michigan................. 10,419 9,058 1,512 7,546 Mississippi.............. 4,292 953 626 327 New Mexico............... 32,203 12,750 168 12,582 Texas.................... 102,837 16,464 2,493 13,971 --------- --------- --------- ----------- Total Onshore................. 177,952 45,957 8,746 37,211 --------- --------- --------- ----------- Offshore: Louisiana................ 158,776 42,283 29,333 12,950 Texas.................... 74,795 23,512 20,392 3,120 --------- --------- --------- ----------- Total Offshore................ 233,571 65,795 49,725 16,070 --------- --------- --------- ----------- Total......................... 411,523 111,752 58,471 53,281 ========= ========= ========= =========== The Company will acquire an aggregate of 15,062 developed and 18,209 undeveloped net leasehold acres pursuant to the Funds Acquisition and has disposed of 1,892 of the gross leasehold acres and 1,512 of the net developed leasehold acres set forth above in Michigan pursuant to the Michigan Disposition. 55 DRILLING ACTIVITIES The following table sets forth the drilling activity of the Company on its properties for the years ended December 31, 1994, 1995 and 1996 and the three months ended March 31, 1997.
YEAR ENDED DECEMBER 31, ------------------------------------------------- THREE MONTHS ENDED 1994 1995 1996 MARCH 31, 1997 ------------- ------------- ------------- -------------- GROSS NET GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- ----- --- OFFSHORE DRILLING ACTIVITY: Development: Productive...................... 3.0 0.8 2.0 0.5 5.0 1.5 -- -- Non-productive.................. -- -- -- -- -- -- -- -- ----- --- ----- --- ----- --- Total...................... 3.0 0.8 2.0 0.5 5.0 1.5 -- -- Exploratory: Productive...................... 2.0 0.9 4.0 1.3 2.0 0.6 -- -- Non-productive.................. 4.0 0.5 4.0 0.9 1.0 0.2 -- -- ----- --- ----- --- ----- --- Total...................... 6.0 1.4 8.0 2.2 3.0 0.8 -- -- ONSHORE DRILLING ACTIVITY: Development: Productive...................... -- -- 4.0 0.7 2.0 0.3 -- -- Non-productive.................. -- -- 1.0 0.1 2.0 0.6 -- -- ----- --- ----- --- ----- --- Total...................... -- -- 5.0 0.8 4.0 0.9 -- -- Exploratory: Productive...................... 12.0 1.7 15.0 1.8 18.0 2.0 4.0 1.0 Non-productive.................. 14.0 2.7 25.0 4.6 12.0 1.7 5.0 1.3 ----- --- ----- --- ----- --- ----- --- Total...................... 26.0 4.4 40.0 6.4 30.0 3.7 9.0 2.3
The information contained in the foregoing table should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and the oil and natural gas reserves generated therefrom. From January 1, 1997 through May 15, 1997, the Company participated in drilling activities on 23 gross wells. Of the 23 (7.6 net) wells, 10 (3.4 net) are being completed, or have been completed, as commercial producers, 6 (1.6 net) were dry holes, and 7 (2.6 net) are currently being drilled. OIL AND GAS MARKETING The Company's production is priced based on short-term spot prices and is marketed to third parties consistent with industry practices. The Company is aided by the presence of multiple delivery points near its production in the Gulf Coast region. From time to time, the Company has hedged a portion of its oil and gas production to achieve more predictable cash flows and to reduce its exposure to fluctuations in oil and gas prices. Despite the measures taken by the Company to attempt to control price risk, the revenues generated by the Company's operations are highly dependent upon the prices of, and demand for, oil and natural gas. The price received by the Company for its oil and natural gas production depends on numerous factors beyond the Company's control, including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other natural gas-producing and oil-producing countries, the actions of OPEC and domestic government regulation, legislation and policies. Decreases in the prices of oil and natural gas could have a material adverse effect on the carrying value of the Company's proved reserves and the Company's revenues, profitability and cash flow. Although the Company is not currently experiencing any significant involuntary curtailment of its oil or natural gas production, market, transportation, economic and regulatory factors may in the future materially adversely affect the Company's ability to sell its oil or natural gas production. See "Risk Factors -- Volatility of Oil 56 and Natural Gas Prices; Marketability of Production" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." COMPETITION The Company encounters competition from other companies in all areas of its operations, including the acquisition of producing properties and its IPF Program. The Company's competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs and, in the case of its IPF Program, affiliates of investment, commercial and merchant banking firms and affiliates of large interstate pipeline companies. Many of its competitors are large, well-established companies with substantially larger operating staffs and greater capital resources than the Company's and which, in many instances, have been engaged in the oil and gas business for a much longer time than the Company. Such companies may be able to pay more for productive natural gas and oil properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future, and to grow its IPF Program, will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. REGULATION The availability of a ready market for oil and natural gas production depends upon numerous factors beyond the Company's control. These factors include regulation of oil and natural gas production, federal, state and local laws and regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the supply of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an oversupply of natural gas or the lack of an available natural gas pipeline in the areas in which the Company conducts its operations. Federal, state and local laws and regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. REGULATION OF OIL AND NATURAL GAS EXPLORATION AND PRODUCTION. The Company's exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilling and the plugging and abandonment of wells. The Company's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells that may be drilled and unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas the Company's operator or the Company can produce from its wells, and to limit the number of wells the Company can drill or the locations thereof. In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and, consequently, affects its profitability. Inasmuch as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. 57 NATURAL GAS MARKETING AND TRANSPORTATION. Federal legislation and regulatory controls in the United States have historically affected the price of the natural gas produced by the Company and the manner in which such production is marketed. The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the Federal Energy Regulatory Commission (the "FERC"). Although maximum selling prices of natural gas were regulated in the past, on July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol Act") was enacted, which amended the NGPA to remove completely by January 1, 1993 price and nonprice controls for all "first sales" of domestic natural gas, which include all sales by the Company of its production; consequently, sales of the Company's natural gas production currently may be made at market prices, subject to applicable contract provisions. The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. The FERC also regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such natural gas. Since the latter part of 1985, the FERC has endeavored to make interstate natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. The FERC's efforts have significantly altered the marketing and pricing of natural gas. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C (collectively, "Order No. 636"), which, among other things, require interstate pipelines to "restructure" to provide transportation separate or "unbundled" from the pipelines' sales of natural gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all natural gas supplies. Order No. 636 has been implemented through negotiated settlements in individual pipeline service restructuring proceedings. In many instances, the result of the Order No. 636 and related initiatives has been to reduce substantially or bring to an end the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The FERC has issued final orders in virtually all pipeline restructuring proceedings, and has now commenced a series of one year reviews to determine whether refinements are required regarding individual pipeline implementations of Order No. 636. In May 1995, the FERC issued a policy statement on how interstate gas pipelines can recover the costs of new pipeline facilities. While this policy statement affects the Company only indirectly, in its present form the new policy should enhance competition in natural gas markets and facilitate construction of gas supply laterals. However, requests for rehearing of this policy statement are currently pending. The Company cannot predict what action the FERC will take on these requests. Commencing in May 1994, the FERC issued a series of orders in individual cases that delineate a new gathering policy in light of the interstate pipeline industry's restructuring under Order No. 636. As a general matter, gathering is exempt from the FERC's jurisdiction; however, the courts have held that where the gathering is performed by the interstate pipelines in association with the pipeline's jurisdictional transportation activities, the FERC retains regulatory control over the associated gathering services to prevent abuses. Among other matters, the FERC slightly narrowed its statutory tests for establishing gathering status and reaffirmed that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate the FERC's transportation policies, the FERC does not generally have jurisdiction over natural gas gathering facilities and services. In the FERC's opinion, such facilities and services are more properly regulated by state authorities. In addition, the FERC has approved several transfers proposed by interstate pipelines of gathering facilities to unregulated independent or affiliated gathering companies. Certain of the FERC's orders delineating its new gathering policy recently were the subject of an opinion issued by the United States Court of Appeals for the District of Columbia Circuit. That opinion generally upheld the FERC's policy of approving the interstate pipeline's proposed "spindown" of its gathering facilities to an unregulated affiliate company, but remanded to the FERC that portion of the FERC's orders imposing so-called "default contracts" by which the unregulated affiliate was obligated to continue existing gathering services to customers under "default contracts" for up to two years after spindown. It remains unclear whether the FERC will attempt to reimpose such conditions or will otherwise act in response to producer requests for additional protection against perceived monopolistic action by pipeline-related gatherers. In 58 addition, in February 1996, the FERC issued a policy statement that, among other matters, reaffirmed, with some clarifications, its long-standing test for determining whether particular pipeline facilities perform a jurisdictional transmission function or nonjurisdictional gathering function. While changes to the FERC's gathering policy affect the Company only indirectly, such changes could affect the price and availability of capacity on certain gathering facilities, and thus access to certain interstate pipelines, which, in turn, could affect the price of gas at the wellhead and in markets in which the Company competes. However, the Company does not believe that it will be affected by these changes to the FERC's gathering policy materially differently than other natural gas producers with which it competes. Proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective, or their effect, if any, on the Company's operations. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. FEDERAL OFFSHORE LEASING. Certain of the Company's operations are conducted on federal oil and gas leases administered by the Minerals Management Service ("MMS"). The MMS issues such leases through competitive bidding. These leases contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf ("OCS") to meet stringent engineering and construction specifications. The MMS also has issued regulations restricting the flaring or venting of natural gas and prohibiting the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other security can be substantial and there is no assurance that the Company can obtain bonds or other security in all cases. See " -- Environmental Matters." The OCSLA requires that all pipelines operating on or across the OCS provide open-access, non-discriminatory service. Although the FERC has opted not to impose the regulations of Order No. 509, which implements these requirements of the OCSLA, on gatherers and other non-jurisdictional entities, the FERC has retained the authority to exercise jurisdiction over those entities if necessary to permit non-discriminatory access to services on the OCS. If the FERC were to apply Order No. 509 to gatherers in the OCS, eliminate the exemption of gathering lines, and redefine its jurisdiction over gathering lines, the result would be a reduction in available pipeline space for existing shippers in the Gulf of Mexico and elsewhere. OIL SALES AND TRANSPORTATION RATES. Sales of crude oil, condensate and gas liquids by the Company are not regulated and are made at market prices. The price the Company receives from the sale of these products is affected by the cost of transporting the products to market. Effective as of January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, subject to certain conditions and limitations, would generally index such rates to inflation. The Company is not able to predict with certainty what effect, if any, these regulations will have on it, but other factors being equal, under certain conditions the regulations may cause increased transportation costs and may reduce wellhead prices for such commodities. ENVIRONMENTAL MATTERS The Company's operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, 59 quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, require remedial measures to prevent pollution from former operations, such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from the Company's operations. In addition, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects its profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment (including pre-remedial investigations and post-remedial monitoring), for damages to natural resources. In some instances, neighboring landowners and other third parties file claims based on common law theories of tort liability for personal injury and property damage allegedly caused by the release of hazardous substances at a CERCLA site. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in "waters of the United States." A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The term "waters of the United States" has been broadly defined to include not only the waters of the Gulf of Mexico but also inland waterbodies, including wetlands, playa lakes and intermittent streams. A 1996 amendment to the OPA also requires owners and operators of "offshore facilities" (including those located in coastal inland waters, such as bays or estuaries) to establish $35.0 million in financial responsibility to cover environmental cleanup and restoration costs likely to be incurred in connection with an oil spill. Offshore facilities are facilities used for exploring for, drilling for or producing oil or transporting oil from facilities engaged in oil exploration, drilling or production. If it is determined that an increase in the amount of financial responsibility required is warranted, the President has the authority to raise such to an amount not exceeding $150.0 million. In any event, the impact of any adjustment to the annual required financial responsibility is not expected to be any more burdensome to the Company than it will be to other similarly situated companies involved in oil and gas exploration and production. OPA imposes a variety of additional requirements on responsible parties for vessels or oil and gas facilities related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. OPA establishes a liability limit for offshore facilities of all removal costs plus $75.0 million. A party cannot take advantage of liability limits if the spill is caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If a party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability for oil spills imposed by OPA. OPA also imposes other requirements on facility operators, such as the preparation of an oil spill contingency plan. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions. As of the date hereof, the Company is not the subject of any civil or criminal enforcement actions under the OPA and is in substantial compliance with the requirements of the OPA. 60 In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating in the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution. As of the date hereof, the Company is not the subject of any civil or criminal enforcement actions under the OCSLA and is in substantial compliance with the requirements under the OCSLA. The Clean Water Act ("CWA") imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The CWA provides for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and, along with the OPA, imposes substantial potential liability for the costs of removal, remediation and damages. State laws for the control of water pollution also provide civil, criminal and administrative penalties and liabilities in the case of a discharge of petroleum or its derivatives into state waters. The U.S. Environmental Protection Agency ("EPA") issued general permits prohibiting the discharge of produced water and produced sand derived from oil and gas point source facilities into coastal waters in Louisiana and Texas, which became effective as of January 1, 1997. Although the costs of compliance with zero discharge mandates under federal or state law may be significant, the entire industry will experience similar costs and the Company believes that these costs will not have a material adverse impact on the Company's financial condition and operations. Certain oil and gas exploration and production facilities are required to obtain permits for their storm water discharges and costs may be associated with treatment of wastewater, or developing storm water pollution prevention plans. In addition, the Coastal Zone Management Act authorizes state implementation and development of management measures for nonpoint source pollution designed to restore and protect coastal waters. OPERATING HAZARDS AND DRILLING RISKS The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. Any of these occurrences could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Moreover, offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions, to more extensive governmental regulation, including regulations that may, in certain circumstances, impose strict liability for pollution damage, and to interruption or termination of operations by governmental authorities based on environmental or other considerations. The presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause such activity to be unsuccessful, resulting in a total loss of the Company's investment in such activity. Although the Company maintains insurance coverage considered to be customary in the industry, it is not fully insured against certain of these risks, either because such insurance is not available or because of the high premium costs. The Company does not carry business interruption insurance. There can be no assurance that any insurance obtained by the Company will be adequate to cover any losses or liabilities, or that such insurance will continue to be available or available on terms which are acceptable to the Company. See "Risk Factors -- Operating Risks." Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be 61 curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, mechanical problems, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. The Company's future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on the Company's future results of operations and financial condition. In addition, the Company's use of 3-D seismic requires greater pre-drilling expenditures than traditional drilling strategies. Although the Company believes that its use of 3-D seismic will increase the probability of success of its exploratory wells and should reduce average finding costs through the elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic data and other traditional methods, unsuccessful wells are likely to occur. There can be no assurance that the Company's participation in drilling programs will be successful or that unsuccessful drilling efforts will not have a material adverse effect on the Company. ABANDONMENT COSTS The Company is responsible for the payment of abandonment costs on its oil and natural gas properties pro rata to its working interest. The Company accrues for its expected future abandonment liabilities as a component of depletion, depreciation and amortization as the properties are produced. As of December 31, 1996, total pro forma undiscounted abandonment costs estimated to be incurred through the year 2006 were approximately $16.6 million for properties in federal and state waters. The Company does not consider abandonment costs estimated to be incurred on its onshore properties to be significant at this time. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates, and changes in environmental laws and regulations. The MMS requires lessees of OCS properties to post bonds in connection with the plugging and abandonment of wells located offshore on the federal OCS and the removal of all production facilities. Operators in the OCS waters of the Gulf of Mexico are currently required to post an area-wide bond of $3.0 million or $500,000 per producing lease, which the Company has provided. Under certain circumstances, the MMS has the authority to suspend or terminate operations on federal leases for failure to comply with the applicable bonding requirements or other regulations applicable to plugging and abandonment. Any such suspensions or terminations of the Company's operations could have a material adverse effect on the Company's financial condition and results of operations. TITLE TO PROPERTIES The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, the Company obtains title opinions on the most significant leases. However, as is customary in the oil and gas industry, the Company makes only a cursory review of title to farmout acreage and to undeveloped oil and natural gas properties upon execution of the contracts pursuant to which the Company acquires rights thereto. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or other investigations reflect title defects affecting farmout acreage or undeveloped properties, the Company, rather than the seller of the undeveloped property, is typically responsible for curing any such title defects at its expense. If the Company were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, the Company could suffer a loss of its entire investment in the property. The Company has obtained title opinions on substantially all of its producing properties and believes that it has satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The Company's oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. Approximately 80% of the aggregate value of the Company's oil and natural gas properties (other than the IPF Program properties) are and will continue to be mortgaged to secure borrowings under the Revolving Credit Facility. Although the remaining approximately 20% of the 62 aggregate value of the Company's oil and natural gas properties are not mortgaged to the Lenders under the Revolving Credit Facility, such properties are nevertheless subject to the restrictions set forth therein, including a prohibition on granting any security interests therein. EMPLOYEES On March 31, 1997, the Company employed 39 full-time persons and five full-time contractors. The Company believes that its relationships with its employees are good. None of the Company's employees are covered by a collective bargaining agreement. OFFICES The Company currently leases approximately 31,000 square feet of office space in Houston, Texas, where its principal offices are located. LEGAL PROCEEDINGS Various claims have been filed naming joint working interest owners of the Company in the ordinary course of business, particularly claims alleging personal injuries, for which the Company would be responsible for its pro rata share of any uninsured damages or settlement costs. In addition, MarkWest Michigan, Inc. ("MarkWest"), the Company's former partner in the Michigan Development Project, has notified the Company that it believes that it had a preferential purchase right with respect to a portion of the interest in the project that the Company sold to a third party pursuant to the Michigan Disposition. On April 29, 1997, MarkWest filed a demand for arbitration with the American Arbitration Association seeking to enforce its alleged preferential purchase right and claiming that the sale by the Company to the third party should be declared void. The Company believes that MarkWest's claim has no merit. On May 13, 1997, the Company filed an action in the District Court of Harris County, Texas (234th Judicial District) against MarkWest seeking to stay the arbitration proceedings initiated by MarkWest on the basis that the Company was never a party to the agreement under which MarkWest alleges it has the right to arbitrate its dispute with the Company. No pending or threatened claims, actions or proceedings against the Company are expected to have a material adverse effect on the Company's financial condition or results of operations. 63 MANAGEMENT DIRECTORS AND EXECUTIVE OFFICERS The Company's Board of Directors currently has four members. Following the Offering, the Company intends to increase the size of its Board of Directors to six persons. The two individuals to be nominated for appointment to the Board of Directors following the Offering are William P. Nicoletti and Gary K. Wright, neither of whom are employees of or otherwise affiliated with the Company, Fund VII or First Reserve. The new directors will be elected by the current directors. All directors are elected annually to serve until the next annual meeting of stockholders or until their successors are duly elected and qualified. The officers of the Company are elected by, and serve until their successors are elected by, the Board of Directors. The following table sets forth certain information concerning the directors and executive officers of the Company as of April 30, 1997. NAME AGE POSITION - ------------------------------------- --- ------------------------------------- Michael V. Ronca..................... 43 President and Chief Executive Officer and Director Herbert A. Newhouse.................. 52 Executive Vice President Catherine L. Sliva................... 38 Executive Vice President and Secretary Rick G. Lester....................... 45 Vice President, Chief Financial Officer and Treasurer Jonathan S. Linker................... 48 Director and Chairman of the Board William E. Macaulay.................. 51 Director Steven H. Pruett..................... 35 Director William P. Nicoletti*................ 51 Director Gary K. Wright*...................... 52 Director - ------------ * To be nominated for appointment to the Board of Directors following the Offering. Michael V. Ronca has been the President and Chief Executive Officer of the Company and has served as a Director of the Company since its inception in 1996. Mr. Ronca has been the President of Ventures Corporation since 1993. Prior to starting Ventures Corporation, Mr. Ronca served as Executive Director, Investor Relations for Tenneco where he was responsible for the development, implementation and management of a global investor relations program. Mr. Ronca, who was an employee of Tenneco for over 20 years, moved to Houston in 1984 to assume the position of administrative assistant to the chairman and chief executive officer of Tenneco Inc. In this capacity he focused on acquisition and disposition analysis, strategic planning and operational issues. Mr. Ronca graduated from Villanova University in 1975 with a bachelor of science degree in Finance and Marketing and later earned a master of business administration degree from Drexel University. Herbert A. Newhouse has been Executive Vice President of the Company since its inception in 1996. Mr. Newhouse is responsible for exploration, production and evaluation activities for the Company, including geological, geophysical and engineering technical evaluations. Mr. Newhouse joined Ventures Corporation in 1995 as Vice President. He has more than 28 years operational and managerial experience in oil and gas exploration and production, most recently having served as Vice President of Production for North Central Oil Corporation for the six years prior to 1995. Before joining North Central, Mr. Newhouse spent 17 years with the exploration and production division of Tenneco Oil Company ("Tenneco Oil"), rising to the position of Division Production Manager responsible for drilling, production, development geology and reservoir engineering. He graduated from Ohio State University in 1968, with a bachelor of science degree in Chemical Engineering. Catherine L. Sliva has been the Executive Vice President and Secretary of the Company since its inception in 1996 and is principally responsible for the IPF Program, strategic planning and analysis, and investor relations. Ms. Sliva has been with Tenneco Ventures since 1992. Ms. Sliva has 17 years experience in offshore and onshore petroleum engineering and economics and is experienced in production finance, 64 acquisition evaluations, reservoir management, field development, economic analysis, coordination of budgets and formulation of corporate goals and strategies. A registered professional petroleum engineer, Ms. Sliva is a graduate of Texas A&M University, where she received a bachelor of science degree in Petroleum Engineering in 1980. Ms. Sliva joined Tenneco Oil in the Gulf Coast division in 1980. She remained in the Gulf Coast division for five years, advancing to Senior Petroleum Engineer. In 1985, Ms. Sliva became a member of the Economic Planning and Analysis Group at Tenneco Oil. She evaluated Tenneco Oil's exploration results, conducted an analysis of Tenneco Oil's competitors and evaluated each division's profitability, including operating results, manpower efficiencies, capital investment levels and results. Rick G. Lester has been Vice President, Chief Financial Officer, Treasurer and Assistant Secretary of the Company since its inception in 1996 with overall responsibility for its accounting, financial analysis, financing and banking activities. Mr. Lester joined Tenneco Ventures in 1992. Mr. Lester has 22 years experience in the financial area, including accounting, tax, corporate finance, and planning and analysis. He received his bachelor of business administration degree in Accounting from the University of Oklahoma in 1974 and his Texas CPA certificate in 1977, and is a member of the AICPA and the Texas Society of CPAs. Mr. Lester joined Tenneco Oil in 1981 and was responsible at various times for managing several operational accounting groups and the tax planning group. In 1988, Mr. Lester became Manager, Corporate Finance with Tenneco where he was responsible for developing financing plans and negotiating credit agreements for its U.S. and Canadian finance companies and for other special projects including the review of its world-wide finance and stock repurchase programs. Jonathan S. Linker has served as a Director of the Company since its inception in 1996. Mr. Linker has been a Managing Director of First Reserve since 1996, the President and a director of IDC Energy Corporation since 1987, and a Vice President and director of Sunset Production Corporation since 1991. First Reserve Corporation is an investment management firm specializing in making private equity investments in energy companies. IDC Energy Corporation and Sunset Production Corporation are small, privately-held oil and gas companies. Mr. Linker also serves as a director of Hugoton Energy Corporation, an independent oil and gas exploration and production company. Mr. Linker earned a bachelor of arts degree in Geology from Amherst College, a master of arts degree in Geology from Harvard University and a master of business administration degree from the Harvard Business School. William E. Macaulay has served as a Director of the Company since March 1997. Mr. Macaulay has been the President and Chief Executive Officer of First Reserve since 1983. Mr. Macaulay serves as a director of Weatherford Enterra, Inc., an oilfield service company, Maverick Tube Corporation, a manufacturer of steel pipe and casing, TransMontaigne Oil Company, an oil products distribution and refining company, National-Oilwell, Inc., a manufacturer and distributor of equipment and products used in oil and gas drilling and production, and Hugoton Energy Corporation. Mr. Macaulay earned a bachelor of arts degree in Economics from City University of New York and a master of business administration degree in Finance from the Wharton School at the University of Pennsylvania. Steven H. Pruett has served as a Director of the Company since March 1997. Mr. Pruett has been a Vice President of First Reserve since 1995. Mr. Pruett has been the President and Chief Executive Officer of First Reserve Oil & Gas Co. since 1996. First Reserve Oil & Gas Co. is a privately-held company engaged in the acquisition and development of oil and gas properties in the Midcontinent Region and the Permian Basin. Prior to joining First Reserve, Mr. Pruett worked for Credit Suisse First Boston as an investment banker in the Natural Resources Group in New York and Houston from 1994 to 1995. Mr. Pruett worked for Amoco Production Company in Planning and Economics from 1991 to 1994, following his graduation from the Harvard Business School with a master of business administration degree in 1991. After earning a bachelor of science degree in Petroleum Engineering from the University of Texas at Austin in 1984, Mr. Pruett was a Petroleum Engineer for ARCO Oil and Gas Company from 1984 to 1989. William P. Nicoletti will be nominated for appointment to the Board of Directors following the Offering. Mr. Nicoletti has been Managing Director of Nicoletti & Company Inc., a New York based private investment banking firm, since 1991. Prior to founding Nicoletti & Company Inc., Mr. Nicoletti was 65 a Managing Director and Head of the Energy and Natural Resources Group of PaineWebber Incorporated. Mr. Nicoletti serves as Chairman of the Board of Directors of Amerac Energy Corporation, an independent oil and gas company, and is a director of Star Gas Corporation, a propane distribution company, and StatesRail, Inc., a short line railroad holding company. Mr. Nicoletti earned a bachelor of science degree in Mathematics from Seton Hall University and a master of business administration degree in Finance from the Columbia University Graduate School of Business. Gary K. Wright will be nominated for appointment to the Board of Directors following the Offering. Mr. Wright joined Texas Commerce Bank -- Houston in 1973 and is currently Manager of its Corporate Banking Department, with responsibility for relationships with the bank's Energy and National Brands Group. Mr. Wright is also Managing Director of the Global Oil and Gas Group for The Chase Manhattan Bank and is the senior banker for the group in the Southwest. Mr. Wright earned a bachelor of science degree in Petroleum Engineering from Louisiana State University and a law degree from Loyola University Law School. COMMITTEES OF THE BOARD OF DIRECTORS Following the Offering the Company will have an Audit Committee and a Compensation Committee. AUDIT COMMITTEE. The Board of Directors intends to name directors to an Audit Committee after consummation of the Offering. The Audit Committee will have responsibility for, among other things, (i) recommending the selection of the Company's independent accountants, (ii) reviewing and approving the scope of the independent accountants' audit activity and extent of non-audit services, (iii) reviewing with management and the independent accountants the adequacy of the Company's basic accounting systems, (iv) reviewing with management and the independent accountants the Company's financial statements and exercising general oversight of the Company's financial reporting process and (v) reviewing the Company's litigation and other legal matters that may affect the Company's financial condition and monitoring compliance with the Company's business ethics and other policies. COMPENSATION COMMITTEE. The Compensation Committee consists of Messrs. Ronca, Linker and Pruett, and following the Offering, one of the independent directors to be appointed to the Board of Directors will become a member of the Compensation Committee. This committee has general supervisory power over, and the power to grant options under, the Stock Purchase and Option Plan. The Compensation Committee additionally has responsibility for, among other things, (i) reviewing the recommendations of the Chief Executive Officer as to appropriate compensation of the Company's principal executive officers and certain other key personnel and establishing the compensation of such key personnel and the Chief Executive Officer, (ii) examining periodically the general compensation structure of the Company and (iii) supervising the employee benefit plans and compensation plans of the Company. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION During the Company's fiscal year ended December 31, 1996, the Company had no compensation committee or other committee of the Board of Directors performing similar functions. Decisions concerning compensation of Mr. Ronca were made during such fiscal year by the Compensation Committee of the board of directors of Tenneco, the former indirect parent of the Company's operating subsidiaries. Decisions concerning compensation of the other executive officers of the Company were made during fiscal year 1996 by the compensation committee of Tennessee Gas Pipeline Company, the former parent of the Company's operating subsidiaries. Mr. Ronca served as a member of the compensation committee of Tennessee Gas Pipeline Company during fiscal year 1996. RONCA EMPLOYMENT AGREEMENT In connection with the Acquisition, the Company entered into a three-year employment agreement with Mr. Ronca on December 31, 1996 pursuant to which Mr. Ronca serves as the Company's President and Chief Executive Officer. Under the Ronca Employment Agreement, Mr. Ronca receives an annual base salary of $180,000 and is entitled to receive an annual cash bonus based on the satisfaction of performance criteria determined by the Board of Directors, in target and maximum amounts equal to 50% and 90%, 66 respectively, of such base salary. The Ronca Employment Agreement also provides that Mr. Ronca will receive $20,000 annually to be used, at his discretion, for perquisites and other fringe benefits associated with his position as President and Chief Executive Officer of the Company. Mr. Ronca is additionally entitled to participate in all other employee compensation and welfare benefit plans and programs available to the Company's other senior executive officers, including health, dental, group life, disability and retirement plans, and expense reimbursement. In the event Mr. Ronca's employment is terminated prior to December 31, 1999 and under certain circumstances, including an election by Mr. Ronca to terminate his employment following a Change of Control (as therein defined) or for Good Reason (as therein defined), he would be entitled under such employment agreement to receive up to the full amount of the base salary he would have received thereunder for the remaining term thereof had his employment not been so terminated. Under the Ronca Employment Agreement, a "Change of Control" is defined as the acquisition by any person or entity, or group thereof, excluding Fund VII and other affiliates of First Reserve of more than 50% of the outstanding voting stock of the Company, and "Good Reason" is defined to include, among other things, material reductions in Mr. Ronca's duties, responsibilities or base salary. COMPENSATION OF DIRECTORS Prior to the Offering, directors of the Company have not received compensation for their services in such capacity. The Company anticipates that, after consummation of the Offering, directors who are employees of the Company or its subsidiaries will not be paid any fees or additional compensation for service as members of the Board of Directors or any committee thereof and that the Company will enter into customary arrangements respecting fees and other compensation (including expense reimbursement) for other directors of the Company. Members of the Board of Directors who are not employees of the Company or its subsidiaries will be eligible to receive options to purchase Common Stock as described below under " -- Stock Option Plan for Nonemployee Directors." STOCK OPTION PLAN FOR NONEMPLOYEE DIRECTORS Effective upon consummation of the Offering, the Company plans to adopt the Domain Energy Corporation 1997 Stock Option Plan for Nonemployee Directors (the "Nonemployee Director Plan"). The objective of the Nonemployee Director Plan is to enable the Company to attract and retain the services of outstanding nonemployee directors by affording them an opportunity to acquire a proprietary interest in the Company through automatic, non-discretionary awards of options exercisable to purchase shares of Common Stock. Each member of the Board of Directors who is not an employee of the Company or its subsidiaries is eligible to receive options under the Nonemployee Director Plan. On the effective date of the Nonemployee Director Plan, each such eligible director will automatically be granted an option to purchase such number of shares of Common Stock as will be determined by the Board of Directors prior to consummation of the Offering. Future eligible directors will also be granted an option to purchase an identical number of shares of Common Stock upon their initial appointment or election to the Board of Directors. The exercise price of the options will be equal to the fair market value of the Common Stock on the date of grant. The options may be exercised for a period of ten years commencing on the date of grant as follows: (i) up to one-third of the total number of shares of Common Stock subject to an option may be purchased as of the date of grant; (ii) up to an additional one-third of the total number of shares of Common Stock subject to an option may be purchased as of the date of the annual meeting of stockholders of the Company in the year following the year in which the option was granted ("Second Vesting Date"), provided that the holder of the option is an eligible director immediately following such meeting; and (iii) the balance of the total number of shares of Common Stock subject to an option may be purchased as of the date of the annual meeting of stockholders next following the Second Vesting Date ("Final Vesting Date"), provided that the holder of the option is an eligible director immediately following such meeting. On the date of the annual meeting of stockholders of the Company that takes place during the calendar year in which the first anniversary of the Final Vesting Date of an option occurs, the holder of such option shall automatically be granted an option to purchase such number of shares of Common Stock as will be determined by the Board of Directors prior to 67 consummation of the Offering, provided that the holder of the option is an eligible director immediately following such meeting. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE The following table sets forth certain information with respect to the compensation of the Company's chief executive officer and for each of its other executive officers (the "named executive officers") during fiscal year 1996. ANNUAL COMPENSATION(1) NAME AND --------------------- ALL OTHER PRINCIPAL POSITION SALARY BONUS COMPENSATION(2) - ------------------------------------- -------- -------- ---------------- Michael V. Ronca..................... $185,120 $160,000 $9,500 President and Chief Executive Officer Herbert A. Newhouse.................. 150,800 70,000 9,500 Executive Vice President Catherine L. Sliva................... 98,040 38,400 7,843 Executive Vice President and Secretary Rick G. Lester....................... 114,060 39,200 9,125 Vice President, Chief Financial Officer and Treasurer - ------------ (1) Does not include the value of perquisites and other personal benefits, securities or property because the aggregate amount of such compensation, if any, does not exceed the lesser of $50,000 or 10 percent of the total amount of annual salary and bonus for the named executive officers. (2) Represents contributions of Tenneco under its 401(k) plan. Does not include options to acquire shares of common stock of Tenneco granted to Mr. Ronca, Mr. Newhouse, Ms. Sliva and Mr. Lester or restricted stock awards made to Mr. Ronca and Mr. Newhouse, all of which were granted or awarded in January 1996 as compensation for performance in 1995. STOCK PURCHASE AND OPTION PLAN The Company recently adopted the Amended and Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain Energy Corporation and Affiliates (the "Stock Purchase and Option Plan"). The objectives of the Stock Purchase and Option Plan are (i) to attract and retain management personnel with the training, experience and ability to enable them to make a substantial contribution to the success of the Company's business, (ii) to motivate management personnel by means of growth-related incentives to achieve long range goals and (iii) to further the alignment of interests of participants with those of the Company's stockholders through opportunities for increased stock or stock-based ownership in the Company. The Stock Purchase and Option Plan authorizes the issuance of options to acquire up to 867,091 shares of Common Stock, and the Company has reserved 867,091 shares of Common Stock for issuance in connection therewith. The Stock Purchase and Option Plan will be administered by the Compensation Committee of the Board of Directors. Pursuant to the Stock Purchase and Option Plan, the Company may grant to employees, directors or other persons having a unique relationship with the Company or its affiliates, singly or in combination, Incentive Stock Options, Other Stock Options, Stock Appreciation Rights, Restricted Stock, Purchase Stock, Dividend Equivalent Rights, Performance Units, Performance Shares or Other Stock-Based Grants, in each case as such terms are defined therein. See " -- Stock Option Agreements." The terms of any such grant will be determined by the Compensation Committee and set forth in a separate grant agreement. The exercise price will be at least equal to 100% of fair market value of the Common Stock on the date of grant in the case of Incentive Stock Options and the exercise price of Other Stock Options will be at least equal to 50% of fair market value of the Common Stock on the date of grant, provided that options to purchase up to 433,546 shares of Common Stock may be granted with an exercise price equal to $.01 per share, which is the par value of the Common Stock. Non-Qualified Stock Options and Other Stock Options may be exercisable for up to ten years. The Compensation Committee 68 may provide that an optionee may pay for shares upon exercise of an option: (i) in cash; (ii) in already-owned shares of Common Stock; (iii) by payment through a cash or margin arrangement with a broker; (iv) in shares otherwise issuable upon exercise of the option; or (v) by any combination of (i) through (iv) as authorized by the Compensation Committee. In the event of certain extraordinary transactions, including a merger, consolidation, a sale or transfer of all or substantially all assets or an acquisition of all or substantially all the Common Stock, vesting of such options will generally be accelerated. The Stock Purchase and Option Plan will terminate on December 31, 2006. STOCK OPTION AGREEMENTS On February 21, 1997 (the "Grant Date"), the Company granted to the following persons the following options under the Stock Purchase and Option Plan, pursuant to separate Non-Qualified Stock Option Agreements between the Company and each of such persons (collectively, as amended, the "Stock Option Agreements"): (i) an option to purchase up to 339,300 shares of Common Stock to Michael V. Ronca, the President and Chief Executive Officer of the Company, (ii) an option to purchase up to 113,100 shares of Common Stock to Herbert A. Newhouse, an Executive Vice President of the Company, (iii) an option to purchase up to 113,100 shares of Common Stock to Catherine L. Sliva, an Executive Vice President and the Secretary of the Company, (iv) an option to purchase up to 50,266 shares of Common Stock to Rick G. Lester, a Vice President, the Chief Financial Officer and the Treasurer of the Company, (v) an option to purchase up to 50,266 shares of Common Stock to Douglas H. Woodul, the Vice President -- Production of the Company, (vi) an option to purchase up to 50,266 shares of Common Stock to Steven M. Curran, the Vice President -- Exploration of the Company, (vii) an option to purchase up to 18,850 shares of Common Stock to Dean R. Bouillion, the Vice President -- Land of the Company, and (viii) an option to purchase up to 18,850 shares of Common Stock to Lucynda S. Herrin, an Assistant Controller of the Company. In addition, the Company has granted options to purchase an aggregate of 95,696 shares of Common Stock to other employees of the Company. Under the terms of the Stock Option Agreements, 50% of the options granted to each such person are designated as time options (collectively, the "Time Options"), with an exercise price equal to $4.18 per share, and 50% are designated as performance options (collectively, the "Performance Options"), with an exercise price equal to $.01 per share. The Time Options become exercisable as to 20% of the shares of Common Stock subject thereto on the first anniversary of the Grant Date and are thereafter exercisable as to an additional 20% of such shares upon each anniversary thereafter. The Performance Options become exercisable at any time following the second anniversary of the Grant Date, when the Investment Return Hurdle (as such term is defined below) is met; provided that the Performance Options become exercisable as to 100% of the shares of Common Stock subject thereto on the ninth anniversary of the Grant Date. The following terms have the following meanings under the Stock Option Agreements: "EQUITY VALUE" means the sum of: (i) all amounts actually received by the FRC Entities from time to time on a cumulative basis through the date of determination of (A) cash (x) through any cash dividend or other distribution on account of the Investor Stock or (y) in connection with either (1) any disposition (whether by way of redemption, repurchase, repayment, merger or otherwise) of all or any part of the Investor Stock or of securities or other non-cash property previously received by way of a dividend or other distribution on account of the Investor Stock, but only to the extent Investor Stock or other securities or non-cash property is so disposed and excluding any disposition to one or more other FRC Entities, (2) a disposition of any or all of the assets of the Company or any of its subsidiaries, or (3) a recapitalization of the Company or its subsidiaries, or (B) securities or any other non-cash property (valued at their fair market value) in connection with either (x) any disposition (whether by sale, merger or otherwise) of all or any part of the Investor Stock to a third party, but only to the extent Investor Stock is so disposed and excluding any disposition to one or more other FRC Entities, or (y) any disposition of any or all of the assets of the Company or any of its subsidiaries (it being understood that for purposes of this clause (i), the terms "disposition," "dispose," and "disposed" shall not include the creation of a pledge, lien or 69 other similar encumbrance unless and until foreclosed upon); PROVIDED, that when determining the amount actually received by the FRC Entities after delivery of a notice that the options will be terminated upon the merger of the Company, the exchange of all or substantially all of its assets for the securities of another Company, a Change of Control, or the recapitalization, reclassification, liquidation or dissolution of the Company, the amount actually received will be deemed to include any amounts to be received by the FRC Entities pursuant to the transaction giving rise to the termination of the options (to the extent such amounts would otherwise qualify as amounts received pursuant to clauses (A) and (B) above); plus, if applicable, (ii) to the extent the Equity Value is being determined prior to the fifth anniversary of the Grant Date, an amount with respect to each unsold share of Common Stock then owned by the FRC Entities equal to the Trading Value (as therein defined) thereof as of such date. "FRC ENTITIES" means investment funds or other entities for which First Reserve acts as a general and/or managing partner or in respect of which First Reserve provides investment advice, either directly or through entities controlled by it. "INVESTMENT" means $30.0 million invested by the FRC Entities in Investor Stock on the closing date of the Acquisition, plus the amount of any additional cash invested by the FRC Entities in Investor Stock after such closing date. Expressly excluded from such term is the $8.0 million loan made by Fund VII to Domain Energy Guarantor Corporation and evidenced by the Subordinated Promissory Note dated December 31, 1996. See "Transactions With Management and First Reserve -- Indebtedness to Fund VII." "INVESTMENT RETURN HURDLE" will be satisfied when the Equity Value with respect to the Investor Stock is equal to or greater than, as of the date of determination, the amount determined by increasing the Investment at a compounded annual rate of 25% commencing on the date of any cash investment by the FRC Entities (as to that portion of the Investment made on such date) through and including such date of determination. "INVESTOR STOCK" means issued and outstanding shares of capital stock of any class or series of the Company, so long as such shares were originally acquired by the FRC Entities from the Company. 401(K) PLAN The Company has offered its employees an employee 401(k) savings plan (the "401(k) Plan"), which became effective upon inception of the Company. The 401(k) Plan covers all employees and entitles each to contribute up to 15% of his or her annual compensation subject to maximum limitations imposed by the Internal Revenue Code. The 401(k) Plan allows for employer matching of up to 8% of the employee's contributions based on years of participation in the plan, including years of participation in the 401(k) plan previously offered by Tenneco. LIMITATION OF DIRECTORS' LIABILITY; INDEMNIFICATION OF DIRECTORS AND OFFICERS The Company's Certificate of Incorporation provides that no director of the Company shall be liable to the Company or its stockholders for monetary damages for breach of fiduciary duty or the duty of care as a director, except for liability for breach of the director's duty of loyalty, acts not in good faith, intentional misconduct or knowing violations of law, unlawful payment of dividends or stock purchases or redemptions, or transactions in which the director derived an improper personal benefit. The Certificate of Incorporation also provides for the indemnification of officers and directors to the fullest extent permitted by Delaware law. The Company also maintains directors' and officers' liability insurance coverage. Generally, Section 145 of the Delaware General Corporation Law, as amended (the "DGCL"), provides that a corporation may indemnify any person who is or was a party or is threatened to be made a party to any threatened, pending or completed action, including any action by or in the right of the corporation (unless such person was adjudged liable to the corporation, in which event indemnification is permitted if, but only to the extent that, the court in which such action was brought determined such indemnification is fair and reasonable) by reason of the fact that such person is or was a director, officer, employee or agent of the corporation, or is or was serving in such capacity for another corporation or entity 70 at the request of the corporation, if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. Such indemnification may include all expenses (including attorneys' fees) and, in the case of any action other than an action by or in the right of the corporation, all judgments, fines and amounts paid in settlement, to the extent such expenses, judgments, fines and amounts were actually paid and reasonably incurred by the indemnified party in connection with such action. TRANSACTIONS WITH MANAGEMENT AND FIRST RESERVE SECURITYHOLDERS AGREEMENT The Company, Fund VII and the Company's officers who have purchased Common Stock (the "Management Investors") are parties to Securityholders Agreement dated as of December 31, 1996 (the "Securityholders Agreement"). The Securityholders Agreement contains provisions governing the management of the Company, voting of shares, election of directors and restrictions on transfer of shares, all of which terminate automatically upon the completion of the Offering. In addition, the Securityholders Agreement provides Fund VII, after the Offering, the right on four occasions to require the Company to register all or part of Fund VII's registrable shares of Common Stock under the Securities Act, and the Company is required to use its reasonable best efforts to effect such registration, subject to certain conditions and limitations. Upon the Company's receipt of a demand from Fund VII to register all or part of its registrable shares, the Company is required to notify the other parties to the Securityholders Agreement of the demand, and such parties shall, subject to certain conditions and limitations, have the right to include the registrable shares held by them in such registration. The Securityholders Agreement also provides all the parties thereto with piggyback registration rights on any offering by the Company of any of its securities to the public except a registration on Forms S-4 or S-8 under the Securities Act; provided, however, that until two years after the date of the Offering, the Management Investors will not have piggyback registration rights with respect to any registration in which Fund VII or any of its permitted transferees are not participating. The Company will bear the expenses of all registrations under the Securityholders Agreement. Fund VII has waived its registration rights with respect to a Registration Statement filed by the Company with respect to the Offering. MANAGEMENT INVESTOR SUBSCRIPTION AGREEMENTS AND RELATED TRANSACTIONS Shortly before the Offering, each of the Management Investors entered into a Management Investor Subscription Agreement with the Company pursuant to which the Management Investors purchased an aggregate of 390,307 shares of Common Stock. To facilitate such purchases, the Company loaned the Management Investors the following amounts: (i) Mr. Ronca ($249,200), (ii) Mr. Newhouse ($87,000), (iii) Ms. Sliva ($35,445), (iv) Mr. Lester ($50,011), (v) Mr. Woodul ($49,763), (vi) Mr. Curran ($50,376) and (vii) Ms. Herrin ($24,231). All such indebtedness of such persons accrues interest at the rate of 8% per annum, payable semiannually; provided that each Management Investor may elect to satisfy his or her semiannual interest payment obligation by increasing the principal amount of the indebtedness owed to the Company by the amount of interest otherwise payable. As security for such loans made by the Company, each Management Investor pledged to the Company, and granted a first priority security interest in, the shares of Common Stock purchased by such Management Investor pursuant to its respective Management Investor Subscription Agreement and is required to pledge, and grant a first priority security interest in, all other shares of Common Stock that each such person may subsequently acquire, including, without limitation, upon exercise of options to purchase shares of Common Stock. As of April 30, 1997, the outstanding indebtedness of each Management Investor to the Company was equal to the original principal amount loaned to such Management Investor as indicated above plus interest accrued thereon. FIRST RESERVE TRANSACTION FEE For financial advisory services rendered in connection with the Acquisition, the Company agreed to pay First Reserve a fee of $500,000. 71 INDEBTEDNESS TO FUND VII Prior to the Acquisition, Tennessee Gas Pipeline Company ("TGPL"), the former wholly-owning parent of Ventures Corporation, was a guarantor with respect to certain indebtedness (the "Michigan Senior Debt") of a partnership formed to participate in the Michigan Development Project in which Ventures Corporation was at the time a general partner. In connection with the Acquisition, the Company formed Domain Energy Guarantor Corporation, a Delaware corporation ("Guarantor Corporation"), for the sole purpose of assuming the obligations of TGPL under such guaranty. As security for its obligations under the guaranty, Guarantor Corporation purchased an $8.0 million certificate of deposit issued by the lender in respect of the Michigan Senior Debt and assigned and pledged such certificate to the lender. To enable Guarantor Corporation to purchase the $8.0 million certificate pledged as collateral for its guaranty of the Michigan Senior Debt, Fund VII loaned Guarantor Corporation $8.0 million evidenced by a Subordinated Promissory Note dated December 31, 1996 (the "Note"). The full principal amount of the Note matures on December 31, 1999. Interest accrues on the Note at a rate per annum equal to the interest rate per annum earned by Guarantor Corporation on the $8.0 million certificate and is payable quarterly. The obligations of Guarantor Corporation under the Note are expressly made subordinate and subject in right of payment to the prior payment in full of the Michigan Senior Debt. Upon consummation of the Michigan Disposition, the Michigan Senior Debt was repaid in full and the pledge of the $8.0 million certificate was released. ACQUISITION OF COMMON STOCK BY FUND VII Pursuant to the Subscription Agreement dated December 31, 1996 (the "First Reserve Subscription Agreement"), between the Company and Fund VII, the Company granted to Fund VII an option (the "First Reserve Option") to acquire 1,914,048 shares of Common Stock for an aggregate purchase price of $8.0 million plus any cash interest payment on the Note actually received by Fund VII (the "Option Price"). The Option Price could be paid by Fund VII (i) prior to the date on which the Note has been paid in full, by delivery to the Company of the Note together with the payment in cash of any principal or interest payments on the Note previously received by Fund VII and (ii) after the date on which the Note has been paid in full, by payment of the Option Price in cash. In connection with the Offering, the Company and Fund VII have agreed to restructure the terms of the First Reserve Option as set forth below. The Company and Fund VII have agreed that concurrently with consummation of the Offering, Fund VII will purchase 643,037 shares of Common Stock, at a price per share equal to the Price to Public set forth on the cover page of this Prospectus, for an aggregate purchase price of $8,681,000. The amount of $8,681,000 represents the sum of (i) the outstanding principal balance of the Note plus estimated accrued interest thereon through June 15, 1997 and (ii) $500,000 to be paid in cash by Fund VII. See "-- Indebtedness to Fund VII." 72 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth certain information as of the date of this Prospectus concerning the persons known by the Company to be beneficial owners of more than five percent of the Company's outstanding Common Stock, the members of the Board of Directors of the Company, the named executive officers listed in the Summary Compensation Table above and all directors and executive officers of the Company as a group.
BENEFICIAL OWNERSHIP ------------------------------------------------- PRIOR TO OFFERING SUBSEQUENT TO OFFERING ----------------------- ----------------------- NAME OF BENEFICIAL OWNER SHARES PERCENT SHARES PERCENT - ---------------------------------------- ----------- ------- ----------- ------- First Reserve Corporation(1)............ 7,177,681 93.7% 7,820,718(4) 54.7% 475 Steamboat Road Greenwich, Connecticut 06830 William E. Macaulay(2).................. 7,177,681(3) 93.7 7,820,718(4) 54.7 475 Steamboat Road Greenwich, Connecticut 06830 John A. Hill(2)......................... 7,177,681(3) 93.7 7,820,718(4) 54.7 475 Steamboat Road Greenwich, Connecticut 06830 Michael V. Ronca........................ 179,442 2.3 179,442 1.3 Herbert A. Newhouse..................... 59,813 * 59,813 * Catherine L. Sliva...................... 39,955 * 39,955 * Rick G. Lester.......................... 29,913 * 29,913 * Jonathan S. Linker...................... -- -- -- -- Steven H. Pruett........................ -- -- -- -- William P. Nicoletti.................... -- -- -- -- Gary K. Wright.......................... -- -- -- -- All directors and executive officers as a group (9 persons)................... 7,486,804(3) 97.7 8,129,841(4) 56.8
- ------------ * Less than 1%. (1) Shares of Common Stock shown as owned by First Reserve Corporation are owned of record by Fund VII, of which First Reserve Corporation is the sole general partner and as to which it possesses sole voting and investment power. (2) Messrs. Macaulay and Hill may be deemed to share beneficial ownership of the shares shown as beneficially owned by First Reserve Corporation as a result of Messrs. Macaulay and Hill's ownership of common stock of First Reserve Corporation. Messrs. Macaulay and Hill disclaim beneficial ownership of such shares. (3) Includes 7,177,681 shares beneficially owned by First Reserve Corporation. (4) Includes 7,177,681 shares beneficially owned by First Reserve Corporation and 643,037 shares to be purchased by Fund VII concurrently with consummation of the Offering. 73 DESCRIPTION OF CAPITAL STOCK THE FOLLOWING SUMMARY DESCRIPTION OF THE COMPANY'S CAPITAL STOCK IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO THE COMPANY'S CERTIFICATE OF INCORPORATION, A COPY OF WHICH HAS BEEN INCLUDED AS AN EXHIBIT TO THE REGISTRATION STATEMENT OF WHICH THIS PROSPECTUS IS A PART. ALL CAPITALIZED TERMS USED AND NOT DEFINED BELOW HAVE THE RESPECTIVE MEANINGS ASSIGNED TO THEM IN THE CERTIFICATE OF INCORPORATION. COMMON STOCK The Company is authorized to issue up to 25,000,000 shares of Common Stock, $.01 par value per share. As of the date of this Prospectus, there were 7,663,684 shares of Common Stock issued and outstanding. Immediately after completion of the Offering, 14,306,721 shares of Common Stock will be issued and outstanding. Holders of Common Stock are entitled to one vote for each share held, are not entitled to cumulative voting for the purpose of electing directors and have no preemptive or similar right to subscribe for, or to purchase, any shares of Common Stock or other securities to be issued by the Company in the future. Accordingly, the holders of more than 50% in voting power of the shares of Common Stock voting generally for the election of directors will be able to elect all of the Company's directors. Immediately after completion of the Offering and the concurrent sale to Fund VII, Fund VII will own 54.7% of the outstanding shares of Common Stock of the Company (or 51.4% if the over-allotment option is exercised in full) and will be in a position to control actions that require the consent of stockholders, including the election of directors, payment of dividends, amendment of the Certificate of Incorporation and mergers or a sale of substantially all of the assets of the Company. Holders of shares of Common Stock have no exchange, conversion or preemptive rights and such shares are not subject to redemption. All outstanding shares of Common Stock are, and upon issuance the shares of Common Stock offered hereby will be, duly authorized, validly issued, fully paid and nonassessable. Subject to the prior rights, if any, of holders of any outstanding class or series of capital stock having a preference in relation to the Common Stock as to distributions upon the dissolution, liquidation and winding-up of the Company and as to dividends, holders of Common Stock are entitled to share ratably in all assets of the Company which remain after payment in full of all debts and liabilities of the Company, and to receive ratably such dividends, if any, as may be declared by the Company's Board of Directors from time to time out of funds and other assets legally available therefor. See "Dividend Policy" and "Capitalization." PREFERRED STOCK The Board of Directors is authorized, without action by the holders of Common Stock, to issue up to 5,000,000 shares of preferred stock, $.01 par value (the "Preferred Stock"), in one or more series, to establish the number of shares to be included in each such series and to fix the designations, preferences, relative, participating, optional and other special rights of the shares of each such series and the qualifications, limitations and restrictions thereof. Such matters may include, among others, voting rights, conversion and exchange privileges, dividend rates, redemption rights, sinking fund provisions and liquidation rights that could be superior and prior to the Common Stock. The issuance of one or more series of the Preferred Stock could, under certain circumstances, adversely affect the voting power of the holders of the Common Stock and could have the effect of discouraging or making more difficult any attempt by a person or group to effect a change in control of the Company. DELAWARE BUSINESS COMBINATION STATUTE The Company is a Delaware corporation and is subject to Section 203 of the DGCL ("Section 203"). In general, Section 203 prevents an "interested stockholder" (defined generally as a person owning 15% or more of a corporation's outstanding voting stock) from engaging in a "business combination" (as therein defined) with a Delaware corporation for three years following the time that such person became an interested stockholder, unless (i) before such person became an interested stockholder, the board of 74 directors of the corporation approved the business combination in question or the transaction which resulted in such person becoming an interested stockholder, (ii) upon consummation of the transaction that resulted in the interested stockholder's becoming such, the interested stockholder owns at least 85% of the voting stock of the corporation outstanding at the time such transaction commenced (excluding stock held by directors who are also officers of the corporation and by employee stock plans that do not provide employees with rights to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer), or (iii) at or following the transaction in which such person became an interested stockholder, the business combination is approved by the board of directors of the corporation and authorized at a meeting of stockholders by the affirmative vote of the holders of not less than 66 2/3% of the outstanding voting stock of the corporation not owned by the interested stockholder. Under Section 203, the restrictions described above do not apply to certain business combinations proposed by an interested stockholder following the announcement (or notification) of one of certain extraordinary transactions involving the corporation and a person who had not been an interested stockholder during the preceding three years or who became an interested stockholder with the approval of the corporation's directors or at a time when the restrictions imposed by Section 203 did not apply in accordance with the terms thereof, and which transactions are approved or not opposed by a majority of the members of the board of directors then in office who were directors prior to any person becoming an interested stockholder during the previous three years or were recommended for election or elected to succeed such directors by a majority of such directors. Fund VII is not subject to the restrictions contained in Section 203 because the transaction that resulted in Fund VII becoming an interested stockholder (i.e., the sale of shares of Common Stock to Fund VII to finance the Acquisition pursuant to the First Reserve Subscription Agreement) was approved by the Board of Directors. TRANSFER AGENT AND REGISTRAR The transfer agent and registrar for the Common Stock is ChaseMellon Shareholder Services, L.L.C. SHARES ELIGIBLE FOR FUTURE SALE Upon completion of the Offering and the Concurrent Sale, the Company will have outstanding an aggregate of 14,306,721 shares of Common Stock. All of the 6,000,000 shares sold in the Offering (6,900,000 shares if the over-allotment option granted to the Underwriters is exercised in full) will be freely tradeable without restriction or further registration under the Securities Act, except for any shares purchased by "affiliates" of the Company, as that term is defined in Rule 144 under the Securities Act (whose sales would be subject to certain limitations and restrictions described below). The 7,663,684 shares of Common Stock held by the Company's existing stockholders were, and the 643,037 shares of Common Stock to be purchased by Fund VII concurrently with consummation of the Offering will be, issued and sold by the Company in reliance on an exemption from the registration requirements of the Securities Act. Substantially all of the outstanding shares of Common Stock held by the Company's existing stockholders after the Offering will be subject to the "lock-up" agreement described below. After expiration of such lock-up agreement 180 days after the date of this Prospectus, the Common Stock then owned by such stockholders may be resold only upon registration under the Securities Act or pursuant to an exemption from such registration requirements, including exemptions contained in Rule 144. The Securityholders Agreement provides Fund VII, after the Offering, the right on four occasions to require the Company to register all or part of Fund VII's registrable shares of Common Stock (which includes the Common Stock to be purchased in the Concurrent Sale) under the Securities Act, and the Company is required to use its reasonable best efforts to effect such registration, subject to certain conditions and limitations. Upon the Company's receipt of a demand from Fund VII to register all or part of its registrable shares, the Company is required to notify the other parties to the Securityholders Agreement of the demand and such parties shall, subject to certain conditions and limitations, have the right to include the registrable shares held by them in such registration. The Securityholders Agreement also provides all the parties thereto with piggyback registration rights on any offering by the Company of any of its securities to the public except a registration on Forms S-4 or S-8 under the Securities Act; provided, however, that until two years 75 after the date of the Offering, the Management Investors will not have piggyback registration rights with respect to any registration in which Fund VII or any of its permitted transferees are not participating. Fund VII has waived its registration rights with respect to a Registration Statement filed by the Company with respect to the Offering and has informed the Company that it has no immediate plans to sell or otherwise dispose of shares of the Common Stock. In general, under Rule 144 as currently in effect, a person (or persons whose shares are aggregated) who has beneficially owned shares of a public company for at least one year (including the holding period of any prior owner except an affiliate) that were not acquired in a public offering is entitled to sell in "broker's transactions" or to market makers, within any three-month period, a number of shares that does not exceed the greater of (i) 1% of the number of shares of Common Stock then outstanding (approximately 143,067 shares immediately after the Offering) or (ii) generally, the average weekly trading volume in the Common Stock during the four calendar weeks preceding the required filing of a Form 144 with respect to such sale. Sales under Rule 144 are generally subject to the availability of current public information about the Company. Under Rule 144(k), a person who is not deemed to have been an affiliate of the Company at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, is entitled to sell such shares without having to comply with the manner of sale, public information, volume limitation or notice filing provisions of Rule 144. As soon as practicable following the Offering, the Company intends to file a registration statement on Form S-8 under the Securities Act covering 867,091 shares of Common Stock reserved for issuance pursuant to its Stock Purchase and Option Plan and such number of shares of Common Stock as will be reserved for issuance pursuant to its Nonemployee Director Plan. Shares of Common Stock issued upon exercise of the stock options granted under the Stock Purchase and Option Plan after the effective date of such registration statement will be freely tradeable, except for any such shares acquired by an "affiliate" of the Company, as that term is defined in Rule 144 under the Securities Act. The Company, each of the Company's directors and executive officers and Fund VII have agreed not to sell, offer to sell, contract to sell, grant any option for the sale of or otherwise dispose of, directly or indirectly, any shares of Common Stock or any securities convertible into or exercisable or exchangeable for any Common Stock owned by any of them prior to the expiration of 180 days from the date of this Prospectus, except (i) for shares of Common Stock offered hereby, (ii) with the prior written consent of Credit Suisse First Boston Corporation, and (iii) for the issuance of shares pursuant to employee benefit plans of the Company, provided that the Company has agreed not to grant options to purchase shares of Common Stock at a price less than the Offering price. Prior to the Offering, there has been no public market for the Common Stock, and no prediction can be made as to the effect, if any, that future sales of shares or the availability of shares for sale will have on the market price for Common Stock prevailing from time to time. Sales of substantial amounts of Common Stock in the public market, or the perception of the availability of shares for sale, could adversely affect the prevailing market price of the Common Stock and could impair the Company's ability to raise capital through the sale of its equity securities. 76 UNDERWRITING Under the terms and subject to the conditions contained in an Underwriting Agreement dated June 23, 1997 (the "Underwriting Agreement"), the underwriters named below (the "Underwriters"), for whom Credit Suisse First Boston Corporation, PaineWebber Incorporated, Prudential Securities Incorporated and Morgan Keegan & Company, Inc. are acting as representatives (the "Representatives"), have severally but not jointly agreed to purchase from the Company the following respective numbers of Shares: NUMBER UNDERWRITER OF SHARES - ---------------------------------------- --------- Credit Suisse First Boston Corporation ................................................ 1,152,000 PaineWebber Incorporated ..................................... 1,152,000 Prudential Securities Incorporated ........................... 1,152,000 Morgan Keegan & Company, Inc. ................................ 384,000 Arneson, Kercheville & Associates, Inc ........................................................ 60,000 Bear, Stearns & Co. Inc. ..................................... 120,000 Donaldson, Lufkin & Jenrette Securities Corporation ................................................ 120,000 Gaines, Berland Inc. ......................................... 60,000 Gerard Klauer Mattison & Co., Inc. ........................... 60,000 Goldman, Sachs & Co. ......................................... 120,000 Howard, Weil, Labouisse, Friedrichs Incorporated ............................................... 120,000 Invemed Associates, Inc. ..................................... 120,000 Jefferies & Company, Inc. .................................... 120,000 Johnson Rice & Company L.L.C ................................. 60,000 Merrill Lynch, Pierce, Fenner & Smith Incorporated ............................................... 120,000 Morgan Stanley & Co. Incorporated ............................ 120,000 Nesbitt Burns Securities Inc. ................................ 60,000 Oppenheimer & Co., Inc. ...................................... 120,000 Petrie Parkman & Co. ......................................... 120,000 Principal Financial Securities, Inc. ......................... 60,000 Rauscher Pierce Refsnes, Inc. ................................ 60,000 Raymond James & Associates, Inc. ............................. 60,000 Salomon Brothers Inc. ........................................ 120,000 Sanders Morris Mundy ......................................... 60,000 Southcoast Capital Corporation ............................... 60,000 Starr Securities, Inc. ....................................... 60,000 Stephens Inc. ................................................ 60,000 TD Securities (USA) Inc. ..................................... 120,000 --------- Total ................................................... 6,000,000 ========= The Underwriting Agreement provides that the obligations of the Underwriters are subject to certain conditions precedent and that the Underwriters will be obligated to purchase all of the shares offered hereby (other than those shares covered by the over-allotment option described below) if any are purchased. The Underwriting Agreement provides that, in the event of a default by an Underwriter in certain circumstances, the purchase commitments of non-defaulting Underwriters may be increased or the Underwriting Agreement may be terminated. The Company has granted to the Underwriters an option expiring at the close of business on the 30th day after the date of this Prospectus, to purchase up to 900,000 additional shares of Common Stock (the "Option Shares") at the initial public offering price, less the underwriting discounts and commissions, all as set forth on the cover page of this Prospectus. Such option may be exercised only to cover over-allotments, if any, in the sale of the shares offered hereby. To the extent that this option to purchase is 77 exercised, each Underwriter will become obligated, subject to certain conditions, to purchase approximately the same percentage of Option Shares as the number of shares set forth next to such Underwriter's name in the preceding table bears to the sum of the total number of shares in such table it was obligated to purchase pursuant to the Underwriting Agreement. The Company has been advised by the Representatives that the Underwriters propose to offer the shares offered hereby to the public initially at the public offering price set forth on the cover page of this Prospectus and, through the Representatives, to certain dealers at such price less a concession of $0.555 per share, and the Underwriters and such dealers may allow a discount of $0.10 per share on sales to other dealers. After the initial public offering, the public offering price and concession and discount to dealers may be changed by the Representatives. The Company has agreed to indemnify the Underwriters against certain liabilities, including civil liabilities under the Securities Act, or contribute to payments which the Underwriters may be required to make in respect thereto. The Company, each of the Company's directors and executive officers and Fund VII have agreed not to sell, offer to sell, contract to sell, grant any option for the sale of or otherwise dispose of, directly or indirectly, any shares of Common Stock or any securities convertible into or exercisable or exchangeable for any Common Stock owned by any of them prior to the expiration of 180 days from the date of this Prospectus, except (i) for shares of Common Stock offered hereby, (ii) with the prior written consent of Credit Suisse First Boston Corporation and (iii) for the issuance of shares pursuant to employee benefit plans of the Company, provided that the Company has agreed not to grant options to purchase shares of Common Stock at a price less than the Offering price. In connection with the Acquisition, the Company paid PaineWebber Incorporated a fee of $2.1 million for financial advisory services. The Representatives have informed the Company that they do not expect discretionary sales by the Underwriters to exceed 5% of the number of shares offered hereby. The Common Stock has been approved for listing on the New York Stock Exchange subject to notice of issuance. To satisfy one of the requirements for listing of the Common Stock on the New York Stock Exchange, the Underwriters have undertaken to sell lots of 100 or more shares to a sufficient number of persons to establish a minimum of 2,000 round lot beneficial holders after the Offering. Prior to the Offering, there has been no public market for the Common Stock. The initial public offering price for the shares offered hereby will be determined by negotiations among the Company, First Reserve and the Representatives. In determining such price, consideration will be given to various factors, including market conditions for initial public offerings, the history of and prospects for the Company's business, the Company's past and present operations, its past and present earnings and current financial position, an assessment of the Company's management, the market of securities of companies in businesses similar to those of the Company, the general condition of the securities markets and other relevant factors. There can be no assurance that the initial public offering price will correspond to the price at which the Common Stock will trade in the public market subsequent to the Offering or that an active trading market for the Common Stock will develop and continue after the Offering. The Representatives, on behalf of the Underwriters, may engage in over-allotment, stabilizing transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934 (the "Exchange Act"). Over-allotment involves syndicate sales in excess of the offering size, which creates a syndicate short position. Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. Syndicate covering transactions involve purchases of the Common Stock in the open market after the distribution has been completed in order to cover syndicate short positions. Penalty bids permit the Representatives to reclaim a selling concession from a syndicate member when the Common Stock originally sold by such syndicate member is purchased in a syndicate covering transaction to cover syndicate short positions. Such stabilizing transactions, syndicate covering transactions and penalty bids 78 may cause the price of the Common Stock to be higher than it would otherwise be in the absence of such transactions. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time. NOTICE TO CANADIAN RESIDENTS RESALE RESTRICTIONS The distribution of the Common Stock in Canada is being made only on a private placement basis exempt from the requirement that the Company prepare and file a prospectus with the securities regulatory authorities in each province where trades of Common Stock are effected. Accordingly, any resale of the Common Stock in Canada must be made in accordance with applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made in accordance with available statutory exemptions or pursuant to a discretionary exemption granted by the applicable Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the Common Stock. REPRESENTATIONS OF PURCHASERS Each purchaser of Common Stock in Canada who receives a purchase confirmation will be deemed to represent to the Company and the dealer from whom such purchase confirmation is received that (i) such purchaser is entitled under applicable provincial securities laws to purchase such Common Stock without the benefit of a prospectus qualified under such securities laws, (ii) where required by law, that such purchaser is purchasing as principal and not as agent, and (iii) such purchaser has reviewed the text above under "Resale Restrictions". RIGHTS OF ACTION (ONTARIO PURCHASERS) The securities being offered are those of a foreign issuer and Ontario purchasers will not receive the contractual right of action prescribed by section 32 of the Regulation under the SECURITIES ACT (Ontario). As a result, Ontario purchasers must rely on other remedies that may be available, including common law rights of action for damages or rescission or rights of action under the civil liability provisions of the U.S. federal securities laws. ENFORCEMENT OF LEGAL RIGHTS All of the issuer's directors and officers as well as the experts named herein may be located outside of Canada and, as a result, it may not be possible for Canadian purchasers to effect service of process within Canada upon the issuer or such persons. All or a substantial portion of the assets of the issuer and such persons may be located outside of Canada and, as a result, it may not be possible to satisfy a judgment against the issuer or such persons in Canada or to enforce a judgment obtained in Canadian courts against such issuer or persons outside of Canada. NOTICE TO BRITISH COLUMBIA RESIDENTS A purchaser of Common Stock to whom the SECURITIES ACT (British Columbia) applies is advised that such purchaser is required to file with the British Columbia Securities Commission a report within ten days of the sale of any Common Stock acquired by such purchaser pursuant to this offering. Such report must be in the form attached to British Columbia Securities Commission Blanket Order BOR #95/17, a copy of which may be obtained from the Company. Only one such report must be filed in respect of Common Stock acquired on the same date and under the same prospectus exemption. TAXATION AND ELIGIBILITY FOR INVESTMENT Canadian purchasers of Common Stock should consult their own legal and tax advisors with respect to the tax consequences of an investment in the Common Stock in their particular circumstances and with respect to the eligibility of the Common Stock for investment by the purchaser under relevant Canadian legislation. 79 LEGAL MATTERS The validity of the shares of Common Stock offered hereby will be passed on for the Company by Weil, Gotshal & Manges LLP, Houston, Texas and for the Underwriters by Baker & Botts, L.L.P., Houston, Texas. EXPERTS The consolidated financial statements of the Company as of December 31, 1996 and for the period from December 30, 1996 (date of incorporation) to December 31, 1996, the combined financial statements of the Predecessor as of December 31, 1995 and for each of the years in the three-year-period ended December 31, 1996 and the statement of revenues and direct operating expenses of certain properties acquired by the Predecessor for the eleven month period ended November 30, 1994 have been audited by Deloitte & Touche LLP, independent auditors, as stated in their reports appearing herein, and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing. The reserve reports and estimates of the Company's net proved oil and natural gas reserves included herein have, to the extent described herein, been prepared by DeGolyer and Netherland, Sewell. Summaries of these estimates and the audit letters of DeGolyer and Netherland, Sewell have been included in this Prospectus as Appendix A in reliance upon such firms as experts with respect to such matters. AVAILABLE INFORMATION As a result of the Offering, the Company will be subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and in accordance therewith will file reports and other information with the Commission. The reports and other information filed by the Company with the Commission can be inspected and copies can be obtained at the public reference facilities maintained by the Commission at Judiciary Plaza, Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549, and at the Regional Offices of the Commission at 7 World Trade Center, New York, New York 10048 and Northwestern Atrium Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such material also can be obtained from the Public Reference Section of the Commission, 450 Fifth Street, N.W., Washington, D.C. 20549 at prescribed rates. In addition, the Commission maintains a site on the World Wide Web at http://www.sec.gov that contains reports, proxy and information statements and other information regarding registrants that file electronically with the Commission. The Company has filed with the Commission a Registration Statement on Form S-1 under the Securities Act with respect to the Common Stock offered hereby. This Prospectus does not contain all of the information set forth in the Registration Statement, certain portions of which are omitted as permitted by the rules and regulations of the Commission. Such additional information may be obtained at the locations listed above. Statements made in this Prospectus concerning the contents of any contract, agreement or other document filed as an exhibit to the Registration Statement are summaries of the terms of such contract, agreement or document and are not necessarily complete. Reference is made to each such exhibit for a more complete description of the matters involved. The Company intends to furnish its stockholders with annual reports containing audited financial statements and an opinion expressed by independent auditors and with quarterly reports for the first three quarters of each fiscal year containing unaudited summary financial information. 80 GLOSSARY The following are definitions of certain terms used in this Prospectus. BBL. One barrel of crude oil, condensate or other liquids equal to 42 U.S. gallons. BCF. Billion cubic feet. BCFE. Billion cubic feet of natural gas equivalent. BTU. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees Fahrenheit to 59.5 degrees Fahrenheit under specific conditions. DEVELOPED ACREAGE. The number of acres which are allocated or assignable to producing wells or wells capable of production. DEVELOPMENT 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 in an attempt to recover proved undeveloped reserves. EXPLORATORY WELL. A well drilled to find and produce oil or gas in an unproved area, 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. FARMOUT. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well or the establishment of production on that location. The assignor usually retains an overriding royalty interest or a working interest after payout in the lease. FINDING COSTS. Expressed in terms of dollars per Mcfe, calculated by dividing the amount of total capital expenditures for oil and gas activities by the amount of estimated net proved reserves added during the same period (including the effect on proved reserves of reserve revisions). GROSS ACRES OR GROSS WELLS. The number of acres or wells in which the Company has a working interest. LEASE OPERATING EXPENSE. Costs incurred to operate and maintain wells and related equipment and facilities including applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. MBBL. One thousand barrels. MCF. One thousand cubic feet. MCFE. One thousand cubic feet of natural gas equivalent. MMBBL. One million barrels. MMBTU. One million Btus. MMCF. One million cubic feet. MMCFE. One million cubic feet of natural gas equivalent. NATURAL GAS EQUIVALENT. Cubic feet of natural gas equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. NET ACRES OR NET WELLS. The sum of the fractional working interests owned in gross acres or gross wells. NET PROFITS INTEREST. An interest in an oil and gas property entitling the owner to a share of the gross revenues from oil and gas production less all operating, production, development, transportation, transmission and marketing expenses, production, sales and ad valorem taxes attributable to such production. OVERRIDING ROYALTY INTEREST. A royalty interest which is carved out of a lessee's working interest under an oil and gas lease. PRODUCTION PAYMENT. A share of the oil or natural gas produced from a specified tract of land, free of the costs of production at the surface, terminating when a specified sum from the sale of such oil or natural gas has been realized. 81 PRODUCTIVE WELL. A well that is producing oil and gas or that is capable of production. PROVED DEVELOPED NONPRODUCING RESERVES. Proved developed reserves expected to be recovered from zones behind casing in existing wells. PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market. PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be recovered from completion intervals currently open in existing wells and able to produce to market. PROVED RESERVES. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 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 for recompletion. PV-10 RESERVE VALUE. The pre-tax present value, discounted at 10% per annum, of future net cash flows from estimated proved reserves, calculated holding prices and costs constant at amounts in effect on the date of the estimate (unless such prices or costs are subject to change pursuant to contractual provisions). The difference between the PV-10 Reserve Value and the standardized measure of discounted future net cash flows is the present value of income taxes applicable to such future net cash flows. RECOMPLETION. The completion for production of an existing well bore in another formation from that in which the well has been previously completed. RESERVE LIFE INDEX. Calculated by dividing year-end proved reserves by annual production for the most recent year. ROYALTY INTEREST. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of costs of production. SPUD. To start (or restart) the drilling of a new well. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The present value, discounted at 10% per annum, of future net cash flows from estimated proved reserves, calculated holding prices and costs constant at amounts in effect on the date of the estimate (unless such prices or costs are subject to change pursuant to contractual provisions) and in all instances in accordance with the Commission's rules for inclusion of oil and gas reserve information in financial statements filed with the Commission. TCF. One trillion cubic feet. TERM OVERRIDING ROYALTY INTEREST. An overriding royalty interest with a fixed duration. UNDEVELOPED ACREAGE. Lease acreage on which wells have not been participated in or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves. WATERFLOOD. The injection of water into a reservoir to fill pores vacated by produced fluids, thus maintaining reservoir pressure and assisting production. WORKING INTEREST. A cost bearing interest which gives the owner the right to drill, produce and conduct oil and gas operations on the property, as well as a right to a share of production therefrom. WORKOVER. Operations on a producing well to restore or increase production. 82 INDEX TO FINANCIAL STATEMENTS PAGE ---- Independent Auditors' Report................... F-2 Combined and Consolidated Balance Sheets as of December 31, 1995 and 1996, respectively........................... F-3 Combined Statements of Income for the years ended December 31, 1994, 1995 and 1996..................................... F-4 Combined and Consolidated Statements of Stockholder's Equity for the years ended December 31, 1994, 1995 and 1996 and the period from December 30, 1996 (date of incorporation) to December 31, 1996, respectively........................... F-5 Combined and Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1995 and 1996 and the period from December 30, 1996 (date of incorporation) to December 31, 1996, respectively....................... F-6 Notes to the Combined and Consolidated Financial Statements................................... F-7 Consolidated Balance Sheets as of December 31, 1996 and March 31, 1997 (Unaudited)............................. F-22 Combined and Consolidated Statements of Income for the three months ended March 31, 1996 and 1997, respectively (Unaudited)..................... F-23 Consolidated Statement of Stockholders' Equity for the three months ended March 31, 1997 (Unaudited)................... F-24 Combined and Consolidated Statements of Cash Flows for the three months ended March 31, 1996 and 1997, respectively (Unaudited)..................... F-25 Notes to the Combined and Consolidated Financial Statements (Unaudited).................................. F-26 Independent Auditors' Report................... F-28 Statement of Revenues and Direct Operating Expenses of the Properties Acquired by Tenneco Ventures Corporation from Pennzoil Exploration and Production Corporation and Pennzoil Petroleum Company for the eleven months ended November 30, 1994........................... F-29 Notes to the Statement of Revenues and Direct Operating Expenses............... F-30 F-1 INDEPENDENT AUDITORS' REPORT Board of Directors and Stockholders of Domain Energy Corporation We have audited the accompanying consolidated balance sheet of Domain Energy Corporation and subsidiaries (the "Company"), the Successor, as of December 31, 1996 and the related statement of stockholder's equity and cash flows from December 30, 1996 (date of incorporation) to December 31, 1996. We have also audited the accompanying combined balance sheet of Tenneco Ventures Corporation and Tenneco Gas Production Corporation (the "Tenneco Entities"), the Predecessor, as of December 31, 1995 and the related combined statements of income, stockholder's equity and cash flows for each of the three years in the period ended December 31, 1996. 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, such financial statements present fairly, in all material respects, the consolidated financial position of the Company and its subsidiaries as of December 31, 1996 and the combined financial position of the Tenneco Entities as of December 31, 1995 and the combined results of their operations and their combined cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Houston, Texas April 3, 1997 (June 20, 1997 as to Note 7) F-2 DOMAIN ENERGY CORPORATION COMBINED AND CONSOLIDATED BALANCE SHEETS (NOTE 1) (IN THOUSANDS, EXCEPT SHARE DATA) AS OF DECEMBER 31, --------------------------- PREDECESSOR SUCCESSOR 1995 1996 ------------ ------------- ASSETS Cash and cash equivalents............ $ -- $ 36 Restricted certificate of deposit.... -- 8,000 Accounts receivable.................. 13,219 19,456 IPF Program notes receivable, current portion............................ 2,247 7,874 Prepaid and other current assets..... 1,608 1,525 ------------ ------------- Total current assets............ 17,074 36,891 IPF Program notes receivable......... 5,744 13,836 Oil and natural gas properties, full cost method.......................... 137,975 66,176 Less: Accumulated depreciation, depletion and amortization........... (26,251) -- Investments and other assets......... 2,554 5,526 ------------ ------------- Total assets.................... $137,096 $ 122,429 ============ ============= LIABILITIES Accounts payable..................... $ 11,265 $ 14,018 Accrued expenses..................... 48 42 Current maturities of long-term debt............................... -- 24,900 ------------ ------------- Total current liabilities....... 11,313 38,960 Long-term debt....................... -- 54,512 Deferred income taxes................ 12,379 -- Parent advances...................... 112,832 -- ------------ ------------- Total liabilities............... 136,524 93,472 Minority interest.................... -- 380 Commitments and contingencies STOCKHOLDER'S EQUITY Common stock: Predecessor -- $5.00 par value, 400 shares authorized, issued and outstanding at December 31, 1995. Successor -- $.01 par value, 15,080,000 shares authorized and 7,177,681v issued and outstanding at December 31, 1996........... $ 2 $ 72 Additional paid-in capital........... -- 28,505 Retained earnings.................... 570 -- ------------ ------------- Total stockholder's equity...... 572 28,577 ------------ ------------- Total liabilities and stockholder's equity............ $137,096 $ 122,429 ============ ============= The accompanying notes are an integral part of the combined and consolidated financial statements. F-3 DOMAIN ENERGY CORPORATION COMBINED STATEMENTS OF INCOME (IN THOUSANDS) PREDECESSOR ------------------------------- YEAR ENDED DECEMBER 31, ------------------------------- 1994 1995 1996 --------- --------- --------- REVENUES: Oil and natural gas sales............... $ 5,340 $ 34,877 $ 52,274 IPF Activities.......................... 1,417 2,356 4,369 Other................................... 283 414 (413) --------- --------- --------- Total revenues................ 7,040 37,647 56,230 --------- --------- --------- EXPENSES: Lease operating......................... 1,790 7,980 10,207 Production and severance taxes.......... 18 710 1,340 Depreciation, depletion and amortization.......................... 3,101 22,692 24,920 General and administrative.............. 52 2,780 3,361 Corporate overhead allocation........... 944 2,627 4,827 --------- --------- --------- Total operating expenses...... 5,905 36,789 44,655 Income from operations.................. 1,135 858 11,575 Interest expense........................ -- -- 150 --------- --------- --------- Income before income taxes.............. 1,135 858 11,425 Income tax provision.................... 735 351 4,394 --------- --------- --------- Net income.............................. $ 400 $ 507 $ 7,031 ========= ========= ========= The accompanying notes are an integral part of the combined and consolidated financial statements. F-4 DOMAIN ENERGY CORPORATION COMBINED AND CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY (IN THOUSANDS)
PREDECESSOR -------------------------------------------------------- ADDITIONAL RETAINED TOTAL COMMON PAID IN EARNINGS STOCKHOLDER'S STOCK CAPITAL (DEFICIT) EQUITY ------ ---------- -------- -------------- Balance at January 1, 1994.............. $ 2 $ -- $ (337) $ (335) Net income.............................. -- -- 400 400 ------ ---------- -------- -------------- Balance at December 31, 1994............ 2 -- 63 65 Net income.............................. -- -- 507 507 ------ ---------- -------- -------------- Balance at December 31, 1995............ 2 -- 570 572 Net income.............................. -- -- 7,031 7,031 ------ ---------- -------- -------------- Balance at December 31, 1996 (prior to the Acquisition)............ $ 2 $ -- $ 7,601 $ 7,603 ====== ========== ======== ============== SUCCESSOR -------------------------------------------------------- ADDITIONAL TOTAL COMMON PAID IN RETAINED SHAREHOLDER'S STOCK CAPITAL EARNINGS EQUITY ------ ---------- -------- -------------- Balance at December 30, 1996 (date of incorporation)........................ $-- $ -- $ -- $-- Issuance of Common Stock, net of costs................................. 72 27,505 -- 27,577 Issuance of detachable stock options.... -- 1,000 -- 1,000 ------ ---------- -------- -------------- Balance at December 31, 1996............ $ 72 $ 28,505 $ -- $ 28,577 ====== ========== ======== ==============
The accompanying notes are an integral part of the combined and consolidated financial statements. F-5 DOMAIN ENERGY CORPORATION COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
PREDECESSOR SUCCESSOR ---------------------------------- ------------------------ FOR THE PERIOD FROM YEAR ENDED DECEMBER 31, DECEMBER 30, 1996 ---------------------------------- (DATE OF INCORPORATION) 1994 1995 1996 TO DECEMBER 31, 1996 ---------- ---------- ---------- ------------------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net income.............................. $ 400 $ 507 $ 7,031 $-- Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization..................... 3,101 22,692 24,920 -- Deferred income taxes.............. 9,586 883 6,702 -- Minority interest.................. -- -- 380 -- Allowance for doubtful IPF investments...................... -- -- 437 Changes in operating assets and liabilities: Increase in accounts receivable.... (713) (6,731) (7,584) -- Decrease (increase) in prepaid and other current assets............. (441) (956) 83 -- Increase (decrease) in accounts payable and accrued expenses.................. (446) 3,538 2,584 -- ---------- ---------- ---------- ------------- Net cash provided by operating activities............................ 11,487 19,933 34,553 -- CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of the Tenneco Entities..... -- -- -- (96,164) Purchase of restricted certificate of deposit............................... -- -- -- (8,000) Investment in oil and natural gas properties............................ (85,433) (44,118) (32,023) -- Proceeds from sale of oil and gas properties............................ -- 8,275 1,546 -- IPF Program investments of capital (notes receivable).................... (3,315) (6,606) (19,045) -- IPF Program return of capital (notes receivable)........................... 3,507 2,638 4,618 -- Investment and other assets............. (1,428) 83 (2,425) -- ---------- ---------- ---------- ------------- Net cash used in investing activities... (86,669) (39,728) (47,329) (104,164) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from debt borrowings........... -- -- 6,968 73,200 Repayment of debt borrowings............ -- -- (756) -- Advances from Parent, net............... 85,014 8,328 6,564 -- Issuance of common stock................ -- -- -- 31,000 ---------- ---------- ---------- ------------- Net cash provided by financing activities............................ 85,014 8,328 12,776 104,200 Increase (decrease) in cash and cash equivalents........................... 9,832 (11,467) -- -- Cash and cash equivalents, beginning of period................................ 1,635 11,467 -- -- ---------- ---------- ---------- ------------- Cash and cash equivalents, end of period (Predecessor -- before Acquisition)... $ 11,467 $ -- $ -- $ 36 ========== ========== ========== =============
The accompanying notes are an integral part of the combined and consolidated financial statements. F-6 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION, BASIS OF PRESENTATION AND NATURE OF OPERATIONS For the years ended December 31, 1994 and 1995 and for the period from January 1, 1996 through December 11, 1996, Tenneco Ventures Corporation ("Ventures") and Tenneco Gas Production Corporation ("Production" and, together with Ventures, the "Tenneco Entities") were indirect subsidiaries of Tenneco, Inc. ("Tenneco"). As a result of a merger between Tenneco and a subsidiary of El Paso Natural Gas Company ("El Paso"), Ventures and Production became wholly owned indirect subsidiaries of El Paso for the period from December 12, 1996 to December 31, 1996. On December 31, 1996, Domain Energy Corporation ("Domain") acquired all of the outstanding common stock of Ventures and Production (the "Acquisition"). Domain was incorporated in Delaware in December 1996 to acquire such common stock and had no operations prior to the Acquisition. Unless otherwise indicated, references to the Company are to Domain and its subsidiaries at and subsequent to December 31, 1996 and to the combined activities of the Tenneco Entities prior to December 31, 1996. References to the Parent are to Tenneco or its affiliates prior to December 11, 1996 and to El Paso from December 12, 1996 to December 31, 1996. The Company was capitalized on December 31, 1996 with the issuance of 7,177,681 shares of common stock for $30.0 million and borrowings of $66.2 million under its credit facilities. The Company completed the Acquisition for a total cash purchase price of approximately $96.2 million and the assumption of liabilities of approximately $16.8 million. The Company did not assume the liability of $124.1 million due to the parent of the Tenneco Entities. The Company has accounted for the Acquisition using the purchase method of accounting. The assets and liabilities of the Tenneco Entities have been recorded in the Company's balance sheet at December 31, 1996 at their estimated fair market values, summarized as follows (in thousands): ASSETS: Accounts receivable -- trade.... $ 19,456 IPF Program notes receivable.... 21,710 Oil and gas properties.......... 66,176 Other assets.................... 5,658 ---------- Total assets............... $ 113,000 ========== LIABILITIES: Accounts payable................ (10,624) Long-term debt.................. (6,212) ---------- Total liabilities.......... $ (16,836) ========== The financial statements of the Tenneco Entities at December 31, 1995 and for each of the years ended December 31, 1994, 1995 and 1996 have been combined to reflect their combined historical financial position and historical results of operations. The following unaudited pro forma summary presents the consolidated results of operations of the Company for the years ended December 31, 1995 and 1996 as if the Acquisition had occurred at the beginning of 1995 (in thousands): 1995 1996 --------- --------- Revenues................................ $ 37,647 $ 56,230 Net income.............................. $ 3,024 $ 9,714 The Company is an independent oil and gas company engaged in the exploration, development, production and acquisition of domestic oil and natural gas properties, principally in the Gulf Coast region. The Company complements these activities with its Independent Producer Finance Program (the "IPF F-7 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Program") pursuant to which it invests in oil and natural gas reserves through the acquisition of term overriding royalty interests. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION AND COMBINATION -- The consolidated balance sheet at December 31, 1996 includes the accounts of the Company and its majority-owned subsidiaries. The Company sponsored and managed two oil and gas investment programs for unaffiliated institutional investors (the "Funds"). The Company has a 10% interest in one program and a 30% interest in the other. The Company and the investors each own direct undivided interests in oil and gas properties. The Company accounts for its interests in the Funds using the pro rata method of consolidation. The Company owns 35% of the voting capital stock of Michigan Production Company L.L.C. ("MPC") and accounts for MPC using the equity method of accounting. The Company also owns 28% of the voting capital stock of Michigan Energy Company, L.L.C. ("MEC"), which is accounted for using the equity method of accounting. Both equity investments were acquired in 1996. The following presents combined summary information for MPC and MEC (in thousands): DECEMBER 31, 1996 ------------ Current assets....................... $ 1,654 Non-current assets................... 35,601 Current liabilities.................. 6,640 Non-current liabilities.............. 27,587 YEAR ENDED DECEMBER 31, 1996 ------------ Revenues............................. $ 690 Operating expenses................... 953 Net income........................... (520) The combined financial statements of the Tenneco Entities include their combined accounts and the combined accounts of their majority-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. OIL AND GAS PROPERTIES -- Investments in oil and gas properties are accounted for using the full cost method of accounting. All costs associated with the acquisition, exploration, exploitation and development of oil and gas properties are capitalized. General and administrative costs of $1.6 million, $2.1 million and $2.6 million were included in capitalized costs for the years ended December 31, 1994, 1995 and 1996, respectively. Such capitalized costs include payroll and other related costs attributable to the Company's acquisition and exploration activities. Costs related to production, development, and the IPF program are expensed within the presented year and not capitalized. Oil and gas properties are amortized using the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of the assessment indicate that the properties are impaired, the amount of impairment is added to the proved oil and gas property costs to be amortized. The amortizable base includes future development costs and, where significant, dismantlement, restoration, and abandonments costs, net of estimated salvage values. The depletion rate per Mcfe for the years ended December 31, 1994, 1995 and 1996 was $1.03, $1.08 and $1.01, respectively. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between F-8 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) capitalized costs and proved reserves. Abandonments of properties are accounted for as adjustments of capitalized costs with no loss recognized. In addition, the total capitalized costs of oil and gas properties are subject to a "ceiling test," which limits such costs to the estimated present value, discounted at a 10% interest rate, of future net cash flows from proved reserves, based on current economic and operating conditions, plus the cost of unproved prospects. If capitalized costs exceed this limit, the excess is charged to depreciation, depletion and amortization. INDEPENDENT PRODUCER FINANCE PROGRAM -- Through its IPF Program, the Company acquires term overriding royalty interests in oil and gas properties owned by independent producers. Because the funds advanced to a producer for these interests are repaid from an agreed upon share of cash proceeds from the sale of production until the amount advanced plus interest is paid in full, the Company accounts for the term overriding royalty interests as notes receivable. Under this accounting method, the Company recognizes only the interest income portion of payments received from a producer as revenues on its income statement. The remaining cash receipts are recorded as a reduction in notes receivable on the Company's balance sheet and as IPF Program return of capital on the Company's statement of cash flows. The Company records an impairment for its investments on a case-by-case basis when it determines repayment to be doubtful. PARENT ADVANCES -- Prior to the Acquisition, Parent advances to the Company for net working capital and capital expenditure requirements are recorded as non-current liabilities on the combined balance sheet. The Parent did not charge the Company any interest expense on the funds utilized by the Company. INCOME TAXES -- Through December 31, 1996, the Company's taxable income is included in a consolidated United States income tax return with the Parent. The intercompany tax allocation policy between the Company and the Parent provided that each member of the consolidated group compute a provision for income taxes on a separate return basis. The Company records its income taxes utilizing an asset and liability approach which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. All current amounts due to or from the Parent are included in Parent advances on the combined balance sheet. OIL AND GAS HEDGING ACTIVITIES -- The Company periodically uses derivative financial instruments to manage price risks related to oil and natural gas sales and not for speculative purposes. For book purposes, gains and losses related to the hedging of anticipated transactions are recognized as income when the hedged transaction occurs. The Company primarily utilizes price swap agreements with major energy companies to accomplish its hedging objectives. The price swap agreements generally provide for the Company to receive or make counter-party payments on the differential between a fixed price and a variable indexed price. Total oil and natural gas sales hedged during the years ended December 31, 1996 and 1995 were 258,710 Bbls and 16,025 MMcf and 65,840 Bbls and -0-MMcf, respectively. There were no hedging transactions in 1994. Gains (losses) realized by the Company under such hedging arrangements, and reported as an increase (reduction) of revenues, were ($10.5 million) and $0.2 million for the years ended December 31, 1996 and 1995, respectively. The following table sets forth the Company's open hedging contracts for oil and natural gas under various price swap agreements with major energy companies as of December 31, 1996:
CRUDE OIL NATURAL GAS ------------------------------ ---------------------------- WEIGHTED AVERAGE WEIGHTED AVERAGE BBLS FIXED SALES PRICE MMBTU FIXED SALES PRICE --------- ------------------ ------ ------------------ Jan 1997 -- Dec 1997............ 244,540 $17.37 4,270 $ 2.58 Jan 1998 -- Dec 2000............ 442,550 $18.37 -- --
F-9 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) REVENUE RECOGNITION -- The Company recognizes oil and gas revenue from its interests in producing wells as oil and gas is sold from those wells. Oil and gas sold in production operations is not significantly different from the Company's share of production. The Company recognizes financing revenues from its producer financing activities using the effective interest rate method. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, income is recorded based on the Company's net revenue interest in production taken for delivery. Management does not believe that the Company had any material natural gas imbalances at December 31, 1996 or 1995. FINANCIAL INSTRUMENTS -- The Company's financial instruments consist of cash, accounts and notes receivable, payables, long-term debt and oil and natural gas commodity hedges. The carrying amount of cash, accounts receivable and payables approximates fair value because of the short-term nature of these items. Based on current industry and other conditions, management believes that the carrying value of its IPF Program notes receivable approximates, at a minimum, their fair value. The carrying value of long-term debt approximates fair value because the individual borrowings bear interest at floating market rates. Assuming a market price based on the twelve-month strip as of December 31, 1996, the Company's projected losses from these open hedge contracts were approximately $2.7 million as of December 31, 1996. Considerable judgment is required in developing these estimates and, accordingly, no assurance can be given that the estimated values presented herein are indicative of amounts that would be realized in a full market exchange. USE OF ESTIMATES -- The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from these estimates. Significant estimates include depreciation, depletion and amortization of proved producing oil and natural gas properties; estimates of proved oil and natural gas reserve volumes; and discounted future net cash flows. CONCENTRATION OF RISK -- Substantially all of the Company's accounts and notes receivable result from oil and natural gas sales, joint interest billings and lending activities to third parties in the oil and natural gas industry. This concentration of customers, joint interest owners and borrowers may impact the Company's overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. STATEMENTS OF CASH FLOWS -- The statements of cash flows are presented using the indirect method and consider all highly liquid investments with maturities at the time of purchase of three months or less to be cash equivalents. Supplemental cash flow information may be summarized as follows (in thousands):
PREDECESSOR SUCCESSOR ---------------------------------- --------- 1994 1995 1996 1996 ---------- ---------- ---------- --------- Interest expense paid................ $ -- $ -- $ 307 -- Income taxes paid to Parent.......... -- -- -- -- The Acquisition: Total cash consideration........ $ -- $ -- $ -- $ 96,164 Fair value of assets acquired... -- -- -- 113,000 Liabilities assumed............. -- -- -- 16,836
EMPLOYEE STOCK-BASED COMPENSATION -- In October 1995, Financial Accounting Standards Board Statement No. 123, "Accounting for Stock Based Compensation" ("SFAS 123") was issued. Under SFAS No. 123, the Company is permitted to either record expenses for stock options and other stock-based employee compensation plans based on their fair value at the date of grant or to apply the existing standard, Accounting Principles Board Opinion No. 25 ("APB 25") and recognize compensation expense, if any, based on the intrinsic value of the equity instrument at the measurement date. The Company has elected to F-10 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) continue to follow APB 25. When applicable, the Company will disclose pro forma net income and earnings per share computed as if the Company utilized SFAS 123. 3. NOTES RECEIVABLE -- INDEPENDENT PRODUCER FINANCING At December 31, 1996 and 1995, the Company had total outstanding notes receivable related to its IPF Program of $21.7 million and $8.0 million, respectively. The notes receivable result from the Company's purchase of a production payment in the form of a term overriding royalty interest in exchange for an agreed upon share of revenues from identified properties until the amount invested and a specified rate of return on investment is paid in full. During 1995 and 1996, the Company realized returns from the IPF Program of 20.0% and 17.7%, respectively. The weighted average returns expected by the Company on the notes receivable outstanding at December 31, 1995 and December 31, 1996 were 26.5% and 20.9%, respectively. While the independent producer's obligation to deliver such revenues is nonrecourse to the producer, management believes that the Company's overriding royalty interest constitutes a property interest and therefore, such property interest and the underlying oil and gas reserves effectively serves as security for the notes receivable. Based on reserve data available, the Company has estimated that $7.9 million and $2.2 million of notes receivable at December 31, 1996 and 1995 will be repaid in the next twelve months and has classified such amounts as current assets. In fiscal 1996, the Company established an allowance for doubtful accounts of approximately $0.4 million related to its IPF Program, which is the balance of such account at December 31, 1996. No other allowance activity occurred during the three years ended December 31, 1996. The allowance for doubtful accounts was zero for the years ended December 31, 1994 and 1995. Based on the December 31, 1996 notes receivable balance, expected principal payments in each of the next five years are as follows (in thousands): 1997.................................... $ 7,874 1998.................................... $ 4,689 1999.................................... $ 2,902 2000.................................... $ 1,995 2001.................................... $ 1,527 4. UNEVALUATED PROPERTY Oil and natural gas properties not subject to amortization consist of the cost of undeveloped leaseholds, exploratory and developmental wells in progress, and secondary recovery projects before the assignment of proved reserves. These costs are reviewed periodically by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production, production response to secondary recovery activities and available funds for exploration and development. The following table summarizes the cost of the properties not subject to amortization for the year cost was incurred (in thousands): DECEMBER 31, -------------------- 1995 1996 --------- --------- Year cost incurred: Remainder 1993....................... $ 4,219 $ -- 1994....................... 23,364 -- 1995....................... 10,334 -- 1996....................... -- 12,662 --------- --------- $ 37,917 $ 12,662 ========= ========= F-11 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. LONG-TERM DEBT At December 31, 1995 and 1996, notes payable and long-term debt consisted of the following (in thousands): DECEMBER 31, --------------------- 1995 1996 --------- ---------- Revolving Credit Facility............ $ -- $ 61,200 Indebtedness to Fund VII............. -- 7,000 IPF Company Credit Facility.......... -- 11,212 --------- ---------- Long-term debt....................... $ -- $ 79,412 Less current maturities.............. -- (24,900) --------- ---------- $ -- $ 54,512 ========= ========== REVOLVING CREDIT FACILITY -- In connection with the Acquisition, the Company entered into a $65.0 million revolving credit facility maturing on December 31, 1999 (the "Revolving Credit Facility") with a group of banks led by The Chase Manhattan Bank. The Revolving Credit Facility is secured by approximately 80% of the aggregate value of the Company's oil and gas properties and substantially all of the Company's other property (other than IPF Program related properties), including the capital stock of Ventures and Production and is also guaranteed by Ventures and Production. Amounts available under the Revolving Credit Facility are subject to a borrowing base with scheduled redeterminations every six months (and such other redeterminations as the lender may elect to perform) by the lenders at the lenders' sole discretion and in accordance with their customary practices and standards in effect from time to time for reserve-based loans to borrowers similar to the Company. The borrowing base under the Revolving Credit Facility at December 31, 1996 was $65.0 million. On December 31, 1997, the Company is required to reduce its outstanding indebtedness under the Revolving Credit Facility to $43.3 million. In addition, if at the end of any fiscal quarter of the Company during 1997 the amount then outstanding thereunder exceeds $43.3 million (as such amount may be adjusted from time to time pursuant to the Revolving Credit Facility), the Company will be obligated to prepay the outstanding indebtedness thereunder in an amount equal to 100% of the Company's "excess cash flow" (as defined therein) for such fiscal quarter. Excess cash flow is defined to include a portion of the net proceeds to the Company of the Offering. Absent a default or an event of default, borrowings under the Revolving Credit Facility accrue interest at LIBOR plus a margin of 1.50% to 2.50% per annum depending on the total amount outstanding or, at the option of the Company, at the greater of (i) the prime rate and (ii) the federal funds effective rate plus 0.50%, plus a margin of 0.50% to 1.50% depending on the total amount outstanding. The Company also incurs a quarterly commitment fee ranging from 0.375% to 0.50% per annum on the average unused portion of the lenders' aggregate commitment depending on the total amount outstanding. The interest rate on the amounts outstanding at December 31, 1996 was 9.75%. The Revolving Credit Facility contains a number of covenants that, among other things, restrict the ability of the Company to dispose of assets, incur additional indebtedness, pay dividends, enter into certain investments or acquisitions, repurchase or redeem capital stock, engage in mergers or consolidations, or engage in certain transactions with subsidiaries and affiliates and that will otherwise restrict corporate activities. In addition, such facility requires the Company to maintain a specified minimum tangible net worth and to comply with certain prescribed financial ratios. Further, under such facility, an event of default is deemed to occur if any person, other than the Company's officers, Fund VII or any other investment fund, the managing general partner of which is First Reserve, becomes the beneficial owner, directly or indirectly, of more than 40% of the outstanding shares of Common Stock. IPF COMPANY CREDIT FACILITY -- IPF Company, an indirect wholly-owned subsidiary of the Company, has a $20.0 million revolving credit facility with Compass Bank-Houston (the "IPF Company Credit F-12 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Facility") pursuant to which it finances a portion of the IPF Program. The IPF Company Credit Facility matures June 1, 1998 at which time all amounts owed thereunder are due and payable. The IPF Company Credit Facility is secured by substantially all of IPF Company's oil and gas term overriding royalty interests, including the notes receivable generated therefrom. The borrowing base under the facility as of March 31, 1997 was $18.0 million and is subject to a scheduled redetermination by the lender every six months and such other redeterminations as the lender may elect to perform each year. Absent a default or an event of default (as defined therein), borrowings under the IPF Company Credit Facility accrue interest at LIBOR plus a margin of 2.25% or, at the option of the IPF Company, the prime rate published in THE WALL STREET JOURNAL. The interest rate on the amounts outstanding as of December 31, 1996 was 7.81%. The IPF Company Credit Facility contains a number of covenants that, among other things, restrict the ability of IPF Company to incur additional indebtedness or grant liens on its properties, guarantee indebtedness of any other person, dispose of assets, make loans in excess of $100,000 other than in the ordinary course of its business, issue additional shares of capital stock, engage in certain transactions with affiliates, enter into any new line of business or amend certain of its material contracts. In addition, such facility requires IPF Company to maintain a specified minimum tangible net worth. The IPF Company Credit Facility restricts the ability of IPF Company to dividend cash to its parent, Ventures, or otherwise advance cash to the Company. At December 31, 1996, IPF Company net assets of approximately $10.0 million were restricted. INDEBTEDNESS TO FUND VII -- Prior to the Acquisition, Tennessee Gas Pipeline Company ("TGPL"), the former wholly-owning parent of Ventures, was a guarantor with respect to certain indebtedness (the "Michigan Senior Debt") of a partnership formed to participate in a development project in Michigan in which Ventures was at the time a general partner. In connection with the Acquisition, the Company formed Domain Energy Guarantor Corporation ("Guarantor Corporation"), for the sole purpose of assuming the obligations of TGPL under such guaranty. As security for its obligations under the guaranty, Guarantor Corporation purchased an $8.0 million certificate of deposit issued by the lender in respect of the Michigan Senior Debt and assigned and pledged such certificate to the lender. To enable Guarantor Corporation to purchase the $8.0 million certificate pledged as collateral for its guaranty of the Michigan Senior Debt, First Reserve Fund VII, Limited Partnership ("Fund VII"), the Company's sole stockholder at December 31, 1996, loaned Guarantor Corporation $8.0 million evidenced by a Subordinated Promissory Note dated December 31, 1996 (the "Note"). The full principal amount of the Note matures on December 31, 1999. Interest accrues on the Note at a rate per annum equal to the interest rate per annum earned by Guarantor Corporation on the $8.0 million certificate and is payable quarterly. The obligations of Guarantor Corporation under the Note are expressly made subordinate and subject in right of payment to the prior payment in full of the Michigan Senior Debt. Pursuant to the terms of the Note, First Reserve has the right to convert the Note into Common Stock. In accordance with APB 14, $1.0 million of the Note has been reclassified from notes payable to additional paid-in capital on the Company's financial statements. As a result of the reclassification, the effective interest rate on the Note increases from 4.60% to 5.26%. The remaining $7.0 million of the Note has been classified as current maturities of long-term debt in keeping with First Reserve's intent to exercise its option to acquire Common Stock concurrent with consummation of the Offering. 6. RELATED PARTY TRANSACTIONS CORPORATE OVERHEAD ALLOCATION -- Prior to the Acquisition, the Company paid an affiliate of the Parent for various administrative support services, including treasury, legal, tax, human resources and administration. Allocations were based on the Company's percentage of total assets as compared to the Parent's total assets. Included in the 1996 allocation was approximately $2.0 million of costs that were directly related to severance payments, retention bonuses and other costs associated with the merger of F-13 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Tenneco with an affiliate of El Paso Natural Gas Company. Management of the Company believes that the allocations were reasonable and approximate those costs which would have been incurred from unrelated parties. Prior to the Acquisition, the Parent also advanced various amounts to the Company for working capital and capital expenditure requirements. The Parent did not charge the Company any interest expense on the funds utilized by the Company. The average amounts of advances outstanding from the Parent were approximately $31.6 million, $107.7 million and $118.5 million for the years ended December 31, 1994, 1995 and 1996, respectively. A summary of the activity in the advances from Parent account follows (in thousands): 1994 1995 1996 ---------- ---------- ------------ Beginning balance, January 1,........ $ 19,491 $ 104,504 $ 112,832 Cash advances, net................... 93,937 5,545 1,737 Corporate overhead allocation........ 944 2,627 4,827 Other allocations (accrued taxes).... (9,868) 156 4,734 Liability to Parent at the Acquisition date not assumed by the Company............................ -- -- (124,130) ---------- ---------- ------------ Ending balance, December 31.......... $ 104,504 $ 112,832 $ -- ========== ========== ============ In connection with the Acquisition, the Company agreed to pay First Reserve Corporation ("First Reserve"), the managing partner of Fund VII, a fee of $500,000 for financial advisory services rendered in connection with the Acquisition. 7. STOCKHOLDERS' EQUITY COMMON STOCK -- As of June 20, 1997, the Company was authorized to issue up to 25,000,000 shares of Common Stock, $.01 par value per share. All share amounts in the financial statements have been retroactively restated to present a 754-for-one stock split effected on June 20, 1997. As of December 31, 1996, there were 7,177,681 shares of Common Stock issued and outstanding. Holders of Common Stock are entitled to one vote for each share held and are not entitled to cumulative voting for the purpose of electing directors and have no preemptive or similar right to subscribe for, or to purchase, any shares of Common Stock or other securities to be issued by the Company in the future. Accordingly, the holders of more than 50% in voting power of the shares of Common Stock voting generally for the election of directors will be able to elect all of the Company's directors. PREFERRED STOCK -- As of June 20, 1997, the Board of Directors was authorized, without action by the holders of Common Stock, to issue up to 5,000,000 shares of preferred stock, $.01 par value per share (the "Preferred Stock"), in one or more series, to establish the number of shares to be included in each such series and to fix the designations, preferences, relative, participating, optional and other special rights of the shares of each such series and the qualifications, limitations and restrictions thereof. Such matters may include, among others, voting rights, conversion and exchange privileges, dividend rates, redemption rights, sinking fund provisions and liquidation rights that could be superior and prior to the Common Stock. As of December 31, 1996, no shares of preferred stock were issued and outstanding. STOCK PURCHASE AND OPTION PLAN -- The Company recently adopted the Amended and Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain Energy Corporation and Affiliates (the "Stock Purchase and Option Plan"). The Stock Purchase and Option Plan authorizes the issuance of options to acquire up to 867,091 shares of Common Stock and the Company has reserved 867,091 shares of Common Stock for issuance in connection therewith. The Stock Purchase and Option Plan will be administered by the Compensation Committee of the Board of Directors. Pursuant to the Stock Purchase and Option Plan, the Company may grant to employees, directors or other persons having a unique F-14 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) relationship with the Company or its affiliates, singly or in combination, Incentive Stock Options, Other Stock Options, Stock Appreciation Rights, Restricted Stock, Purchase Stock, Dividend Equivalent Rights, Performance Units, Performance Shares or Other Stock-Based Grants, in each case as such terms are defined therein. The terms of any such grant will be determined by the Compensation Committee and set forth in a separate grant agreement. The exercise price will be at least equal to 100% of fair market value of the Common Stock on the date of grant in the case of Incentive Stock Options and the exercise price of Other Stock Options will be at least equal to 50% of fair market value of the Common Stock on the date of grant, provided that options to purchase up to 433,546 shares of Common Stock may be granted with an exercise price equal to $.01 per share, which is the par value of the Common Stock. Non-Qualified Stock Options and Other Stock Options may be exercisable for up to ten years. On February 21, 1997 (the "Grant Date"), the Company granted to the officers of the Company, pursuant to separate Non-Qualified Stock Option Agreements (collectively, as amended, the "Stock Option Agreements") between the Company and each of such persons, options to purchase a total of 753,998 shares of Common Stock under the Stock Purchase and Option Plan. In addition, the Company has granted options to purchase an aggregate of 95,696 shares of Common Stock to other employees of the Company. Under the terms of the Stock Option Agreements, 50% of the options granted to each such person are designated as time options (collectively, the "Time Options"), with an exercise price equal to $4.18 per share, and 50% are designated as performance options (collectively, the "Performance Options"), with an exercise price equal to $.01 per share. The Time Options become exercisable as to 20% of the shares of Common Stock subject thereto on the first anniversary of the Grant Date and are exercisable as to an additional 20% of such shares upon each anniversary of the Grant Date thereafter. The Performance Options become exercisable at any time following the second anniversary of the Grant Date, when the Investment Return Hurdle (as such term is defined) is met; provided that the Performance Options become exercisable as to 100% of the shares of Common Stock subject thereto on the ninth anniversary of the Grant Date. MANAGEMENT INVESTOR SUBSCRIPTION AGREEMENTS AND RELATED TRANSACTIONS -- On February 21, 1997, each of the Company's officers (the "Management Investors") entered into a Management Investor Subscription Agreement with the Company pursuant to which the Management Investors purchased an aggregate of 390,307 shares of Common Stock at $4.18 per share. To facilitate such purchases, the Company loaned the Management Investors an aggregate of approximately $546,000. All such indebtedness of such persons accrues interest at the rate of 8% per annum, payable semiannually; provided that each Management Investor may elect to satisfy his or her semiannual interest payment obligation by increasing the principal amount of the indebtedness owed to the Company by the amount of interest otherwise payable. As security for such loans made by the Company, each Management Investor pledged to the Company, and granted a first priority security interest in, the shares of Common Stock purchased by such Management Investor pursuant to its respective Management Investor Subscription Agreement and is required to pledge, and grant a first priority security interest in, all other shares of Common Stock that each such person may subsequently acquire, including, without limitation, upon exercise of options to purchase shares of Common Stock. In addition, in April 1997, other employees of the Company purchased 95,696 shares of Common Stock at an average price of $4.18 per share. F-15 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) COMPENSATION EXPENSE -- For purposes of determining compensation expense pursuant to APB 25, the measurement date for the stock options granted to officers of the Company is December 31, 1996 as on that date each officer knew the number of options (both Time Options and Performance Options) that they would be granted, the number of shares that they would be entitled to receive upon exercise of the options and the option exercise price. The measurement date for other options granted and stock sold is the date of the grant or sale. Compensation expense is calculated based on the difference in the proceeds that the Company receives upon issuance of the stock and the estimated fair value of the stock at the measurement date. The Company anticipates recognizing stock compensation expense based on actual stock acquired and in accordance with the vesting schedule of options granted as follows: 1997................................. $ 4,832,000 1998................................. $ 1,188,000 1999................................. $ 238,000 2000................................. $ 40,000 2001................................. $ 20,000 2002................................. $ 4,000 OPTION TO ACQUIRE COMMON STOCK -- Pursuant to the Subscription Agreement, dated December 31, 1996 (the "First Reserve Subscription Agreement"), between the Company and Fund VII, the Company granted to Fund VII an option (the "First Reserve Option") to acquire 1,914,048 shares of Common Stock for an aggregate purchase price of $8.0 million plus any cash interest payment on the Note (see Note 5) actually received by Fund VII (the "Option Price"). The Option Price could be paid by Fund VII (i) prior to the date on which the Note has been paid in full, by delivery to the Company of the Note together with the payment in cash of any principal or interest payments on the Note previously received by Fund VII and (ii) after the date on which the Note has been paid in full, by payment of the Option Price in cash. In connection with the Offering, the Company and Fund VII have agreed to restructure the terms of the First Reserve Option as set forth below. The Company and Fund VII have agreed that concurrently with consummation of the Offering, Fund VII will purchase at a price per share equal to the Price to Public set forth on the cover page of this Prospectus, a number of shares of Common Stock such that the aggregate purchase price paid by Fund VII for such shares equals $8,681,000. The amount of $8,681,000 represents the sum of (i) the outstanding principal balance of the Note plus estimated accrued interest thereon through June 15, 1997 and (ii) $500,000 in cash to be paid by Fund VII. In accordance with APB 14, $1.0 million of the Note, representing the estimated fair value of the First Reserve Option, has been reclassified from notes payable to additional paid-in capital. See Note 5. 8. INCOME TAXES The provision for income taxes consists of the following (in thousands): YEAR ENDED DECEMBER 31, ------------------------------- 1994 1995 1996 --------- --------- --------- Federal: Current......................... $ (7,082) $ (518) $ (2,965) Deferred........................ 7,296 791 6,511 State: Current......................... (1,769) (14) 657 Deferred........................ 2,290 92 191 --------- --------- --------- Income tax expense................... $ 735 $ 351 $ 4,394 ========= ========= ========= F-16 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth a reconciliation of the statutory federal income tax with the Company's effective taxes allocated by the Parent (in thousands): 1994 1995 1996 --------- --------- --------- Income before income taxes........... $ 1,135 $ 858 $ 11,425 --------- --------- --------- Income tax computed at statutory rates.............................. $ 397 $ 300 $ 3,999 State taxes, net of federal benefit............................ 338 54 551 Other................................ -- (3) (156) --------- --------- --------- Income tax expense................... $ 735 $ 351 $ 4,394 ========= ========= ========= Deferred income taxes reflect the tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts calculated for income tax purposes. The Company's deferred tax liability as of December 31, 1995 was $12,379,000. This amount represents the temporary difference in the tax and book basis of the Company's oil and natural gas properties and investments. As of December 31, 1996, the Company had no deferred tax liability. As a result of the Acquisition and the corresponding election made by El Paso and the Company to step-up the tax basis in the assets acquired, there are no temporary differences in the carrying amounts of assets and liabilities for financial reporting and income tax purposes. 9. COMMITMENTS AND CONTINGENCIES From time to time, the Company is a party to certain lawsuits and claims arising in the ordinary course of business. While the outcome of lawsuits and claims cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the Company's financial condition, results of operations or cash flow. 401(K) PLAN -- Effective December 31, 1996, the Company has offered its employees an employee 401(k) savings plan (the "401(k) Plan"). The 401(k) Plan covers all employees and entitles each to contribute up to 15% of his or her annual compensation subject to maximum limitations imposed by the Internal Revenue Code. The 401(k) Plan allows for employer matching of up to 8% of the employee's contributions based on years of participation in the plan, including years of participation in the 401(k) plan previously offered by Tenneco. 10. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER ENDED ------------------------------------------------------ MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, 1995 1995 1995 1995(1) --------- -------- ------------- ------------ (IN THOUSANDS) Revenues............................. $ 6,499 $ 7,546 $ 7,681 $ 15,921 Operating income (loss).............. (454) 418 (547) 1,441 Net income (loss).................... (287) 241 (336) 889 QUARTER ENDED ------------------------------------------------------ MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, 1996 1996 1996 1996(1) --------- -------- ------------- ------------ (IN THOUSANDS) Revenues............................. $16,143 $ 14,686 $13,531 $ 11,870 Operating income (loss).............. 4,096 6,126 2,047 (694) Net income (loss).................... 2,754 3,855 982 (560)
- ------------ (1) The fourth quarter 1996 includes $2.1 million of corporate overhead which is $1.2 million greater than the average of the first three quarters. This amount includes costs related to the merger between Tenneco and an affiliate of El Paso. F-17 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 11. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) This footnote provides unaudited information required by SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." CAPITALIZED COSTS -- Capitalized costs and accumulated depreciation, depletion and amortization relating to the Company's oil and gas producing activities, all of which are conducted within the continental United States, are summarized below (in thousands): YEAR ENDED DECEMBER 31, --------------------- 1995 1996 ---------- --------- Proved producing oil and gas properties......................... $ 100,058 $ 53,514 Unevaluated properties............... 37,917 12,662 ---------- --------- 137,975 66,176 Less: Accumulated depreciation, depletion and amortization......... (26,251) -- ---------- --------- Net capitalized costs................ $ 111,724 $ 66,176 ========== ========= Company's share of equity method investee's net capitalized cost.... $ 17,815 --------- COSTS INCURRED -- Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below (in thousands): YEAR ENDED DECEMBER 31, ------------------------------- 1994 1995 1996 --------- --------- --------- Property acquisition costs: Unproved........................ $ 1,967 $ 3,207 $ 732 Proved.......................... 63,234 15,186 7,781 Exploration costs.................... 15,121 23,677 12,126 Development costs.................... 4,883 7,834 7,506 --------- --------- --------- Total costs incurred................. $ 85,205 $ 49,904 $ 28,145 ========= ========= ========= Company's share of equity method investee's cost incurred........... $ 17,978 --------- RESERVES -- Proved reserves are estimated quantities of oil and natural gas 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 developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities and the related discounted future net cash flows before income taxes for the periods presented are based on estimates prepared by DeGolyer and MacNaughton, Netherland, Sewell & Associates, Inc., and other third-party independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission. F-18 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company's net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below. OIL, CONDENSATE AND NATURAL GAS LIQUIDS (BBLS) --------------------------------------- 1994 1995 1996 ----------- ------------ ------------ Proved developed and undeveloped reserves: Beginning of year............... 419,253 4,109,442 2,197,181 Revisions of previous estimates..................... (130,555) (704,308) 289,216 Purchases of oil and gas properties.................... 3,713,694 1,713,328 8,152,514 Extensions and discoveries...... 190,050 179,224 180,286 Sales of oil and gas properties.................... -- (2,676,505) (127,305) Production...................... (83,000) (424,000) (563,831) ----------- ------------ ------------ End of year..................... 4,109,442 2,197,181 10,128,061 =========== ============ ============ Proved developed reserves at end of year............................... 3,124,873 1,701,656 9,775,753 =========== ============ ============ Equity in proved reserves of equity investee............................. 1,251,592 ------------ NATURAL GAS (MCF) ----------------------------------------- 1994 1995 1996 ------------ -------------- ----------- Proved developed and undeveloped reserves: Beginning of year............... 10,073,576 73,398,877 82,682,380 Revisions of previous estimates..................... (4,525,096) 5,769,806 (2,920,927) Purchases of oil and gas properties.................... 64,489,577 19,898,227 -- Extensions and discoveries...... 5,694,820 13,083,241 4,743,646 Sales of oil and gas properties.................... -- (11,402,771) (3,218,665) Production...................... (2,334,000) (18,065,000) (21,191,895) ------------ ------------ ------------ End of year..................... 73,398,877 82,682,380 60,094,539 ============ ============ ============ Proved developed reserves at end of year............................... 58,005,413 65,178,731 47,495,614 ============ ============ ============ Equity in proved reserves of equity investee............................. 21,243,379 ------------
TOTAL (MCFE) -------------------------------------------- 1994 1995 1996 ------------ -------------- -------------- Proved developed and undeveloped reserves: Beginning of year............... 12,589,094 98,055,529 95,865,466 Revisions of previous estimates..................... (5,308,426) 1,543,958 (1,185,631) Purchases of oil and gas properties.................... 86,771,741 30,178,195 48,915,084 Extensions and discoveries...... 6,835,120 14,158,585 5,825,362 Sales of oil and gas properties.................... -- (27,461,801) (3,982,495) Production...................... (2,832,000) (20,609,000) (24,574,881) ============ ============== ============== End of year..................... 98,055,529 95,865,466 120,862,905 ============ ============== ============== Proved developed reserves at end of year............................... 76,754,651 75,388,667 106,150,132 ============ ============== ============== Equity in proved reserves of equity investee............................. 28,752,931 --------------
F-19 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) STANDARDIZED MEASURE -- The table of the Standardized Measure of Discounted Future Net Cash Flows relating to the Company's ownership interests in proved oil and gas reserves as of year end is shown below (in thousands): AS OF DECEMBER 31, ---------------------------------- 1994 1995 1996 ---------- ---------- ---------- Future cash inflows.................. $ 170,237 $ 210,818 $ 422,377 Future oil and natural gas operating expenses........................... (47,895) (43,204) (204,741) Future development costs............. (40,622) (38,680) (31,208) Future income tax expenses........... (852) (14,422) (37,156) ---------- ---------- ---------- Future net cash flows................ 80,868 114,512 149,272 10% annual discount for estimated timing of cash flows............... (12,376) (15,513) (23,926) ---------- ---------- ---------- Standardized measure of discounted future net cash flows.............. $ 68,492 $ 98,999 $ 125,346 ========== ========== ========== Company's share of equity method investee's standardized measure of discounted future net cash flows... $ 29,078 ---------- Future cash flows are computed by applying year end prices of oil and natural gas to year end quantities of proved oil and natural gas reserves. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on year end statutory rates, adjusted for operating loss carryforwards and tax credits. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company's oil and gas properties. 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 oil and natural gas 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. F-20 DOMAIN ENERGY CORPORATION NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CHANGE IN STANDARDIZED MEASURE -- Changes in standardized measure of future net cash flows relating to proved oil and gas reserves are summarized below (in thousands): 1994 1995 1996 ---------- ---------- ---------- Changes due to current year operations: Sales of oil & gas, net of production costs.............. $ (3,532) $ (26,200) $ (40,727) Sales of reserves in place...... -- (20,027) (4,639) Extensions & discoveries........ 4,977 18,595 7,941 Purchase of reserves in place... 54,134 21,143 12,601 Future development costs incurred...................... 4,883 7,834 7,270 Changes due to revisions in standardized variables Price & production costs........ (8,793) 23,926 52,020 Revisions of previous quantity estimates..................... (10,008) (950) (1,857) Estimated future development costs......................... (4,535) (8,825) (1,187) Income taxes.................... 8,185 (11,613) (17,560) Accretion of discount........... 1,211 6,181 10,393 Production rates (timing) and other......................... 11,363 20,443 2,092 ---------- ---------- ---------- Net increase......................... 57,885 30,507 26,347 Beginning of year.................... 10,607 68,492 98,999 ---------- ---------- ---------- End of year.......................... $ 68,492 $ 98,999 $ 125,346 ========== ========== ========== Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pre-tax results. Sales of oil and gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis. F-21 DOMAIN ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS (NOTE 1) (IN THOUSANDS, EXCEPT SHARE DATA) (UNAUDITED) SUCCESSOR ------------------------- DECEMBER 31, MARCH 31, 1996 1997 ------------ --------- ASSETS Cash and cash equivalents............ $ 36 $ 6,082 Restricted certificate of deposit.... 8,000 8,000 Accounts receivable.................. 19,456 13,989 IPF Program notes receivable, current portion............................ 7,874 8,512 Prepaid and other current assets..... 1,525 1,468 ------------ --------- Total current assets............ 36,891 38,051 IPF Program notes receivable......... 13,836 19,018 Oil and natural gas properties, full cost method........................ 66,176 66,752 Less: Accumulated depreciation, depletion and amortization......... -- (3,116) Investments and other assets......... 5,526 4,959 ------------ --------- Total assets.................... $122,429 $ 125,664 ============ ========= LIABILITIES Accounts payable..................... $ 14,018 $ 4,491 Accrued expenses..................... 42 2,880 Current maturities of long-term debt............................... 24,900 23,500 ------------ --------- Total current liabilities....... 38,960 30,871 Long-term debt....................... 54,512 60,338 Deferred income taxes................ -- 1,550 ------------ --------- Total liabilities............... 93,472 92,759 Minority interest.................... 380 412 STOCKHOLDERS' EQUITY Common stock: $0.01 par value, 15,080,000 shares authorized and 7,177,681 and 7,567,988 issued and outstanding at December 31, 1996 and March 31, 1997, respectively............. 72 76 Additional paid-in capital........... 28,505 33,282 Notes receivable -- stockholders..... -- (546) Retained earnings.................... -- (319) ------------ --------- Total stockholders' equity...... 28,577 32,493 ------------ --------- Total liabilities and stockholders' equity............ $122,429 $ 125,664 ============ ========= The accompanying notes are an integral part of the combined and consolidated financial statements. F-22 DOMAIN ENERGY CORPORATION COMBINED AND CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS) (UNAUDITED) THREE MONTHS ENDED MARCH 31, ------------------------ PREDECESSOR SUCCESSOR 1996 1997 ------------ ---------- REVENUES Oil and natural gas.................. $ 15,688 $ 12,782 IPF Activities....................... 340 732 Other................................ 115 (292) ------------ ---------- Total revenues............. 16,143 13,222 ------------ ---------- EXPENSES Lease operating...................... 2,127 3,060 Production and severance taxes....... 279 413 Depreciation, depletion and amortization....................... 7,613 3,282 General and administrative........... 1,089 792 Corporate overhead allocation........ 939 -- Stock compensation................... -- 3,150 ------------ ---------- Total operating expenses... 12,047 10,697 Income from operations............... 4,096 2,525 Interest expense..................... -- 1,109 ------------ ---------- Income before income taxes........... 4,096 1,416 Income tax provision................. 1,342 1,735 ------------ ---------- Net income (loss).................... $ 2,754 $ (319) ============ ========== Net income (loss) per share.......... $ (0.03) Common Stock and common stock equivalents outstanding............ 9,156 The accompanying notes are an integral part of the combined and consolidated financial statements. F-23 DOMAIN ENERGY CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (IN THOUSANDS) (UNAUDITED)
ADDITIONAL NOTES TOTAL COMMON PAID IN RECEIVABLE -- RETAINED STOCKHOLDERS' STOCK CAPITAL STOCKHOLDERS EARNINGS EQUITY ------- ---------- ------------- -------- ------------- Balance at December 31, 1996......... $ 72 $ 28,505 $-- $-- $28,577 Sale of common stock to employees.... 4 1,627 (546) -- 1,085 Stock compensation................... -- 3,150 -- -- 3,150 Net loss............................. -- -- -- (319) (319) ------- ---------- ------------- -------- ------------- Balance at March 31, 1997............ $ 76 $ 33,282 $ (546) $ (319) $32,493 ======= ========== ============= ======== =============
The accompanying notes are an integral part of the combined and consolidated financial statements. F-24 DOMAIN ENERGY CORPORATION COMBINED AND CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) (UNAUDITED) THREE MONTHS ENDED MARCH 31, ----------------------- PREDECESSOR SUCCESSOR 1996 1997 ----------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss).................... $ 2,754 $ (319) Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization................... 7,613 3,282 Stock option compensation....... -- 3,150 Deferred income taxes........... 320 1,550 Minority interest............... -- 32 Changes in operating assets and liabilities: Decrease (increase) in accounts receivable..................... (6,302) 5,467 Decrease (increase) in prepaid and other current assets....... (117) 57 Increase (decrease) in accounts payable and accrued expenses... 1,447 (5,107) ----------- --------- Net cash provided by operating activities......................... 5,715 8,112 CASH FLOWS FROM INVESTING ACTIVITIES: Investments in oil and natural gas properties......................... (9,306) (3,858) Proceeds from sale of oil and gas properties......................... 412 1,700 IPF Program investments of capital (notes receivable)................. (2,314) (9,246) IPF Program return of capital (notes receivable)........................ 517 3,426 Investment and other assets.......... 57 401 ----------- --------- Net cash used in investing activities......................... (10,634) (7,577) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from debt borrowings........ -- 9,379 Repayments of debt borrowings........ -- (4,953) Advances from Parent, net............ 5,285 -- Sale of common stock................. -- 1,085 ----------- --------- Net cash provided by financing activities......................... 5,285 5,511 Increase in cash and cash equivalents........................ 366 6,046 Cash and cash equivalents, beginning of period.......................... 0 36 ----------- --------- Cash and cash equivalents, end of period............................. $ 366 $ 6,082 =========== ========= The accompanying notes are an integral part of the combined and consolidated financial statements. F-25 DOMAIN ENERGY CORPORATION NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The financial statements included herein have been prepared by Domain Energy Corporation (the "Company"), without audit pursuant to the rules and regulations of the Securities and Exchange Commission, and reflect all adjustments which are, in the opinion of management, necessary to present a fair statement of the results for the interim periods on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. The results of operations for the interim periods are not necessarily indicative of the results to be expected for an entire year. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with the Company's audited annual financial statements included herein at pages F-2 through F-21. 2. STOCKHOLDERS' EQUITY STOCK PURCHASE AND OPTION PLAN -- The Company recently adopted the Amended and Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain Energy Corporation and Affiliates (the "Stock Purchase and Option Plan"). The Stock Purchase and Option Plan authorizes the issuance of options to acquire up to 867,091 shares of Common Stock and the Company has reserved 867,091 shares of Common Stock for issuance in connection therewith. The Stock Purchase and Option Plan will be administered by the Compensation Committee of the Board of Directors. Pursuant to the Stock Purchase and Option Plan, the Company may grant to employees, directors or other persons having a unique relationship with the Company or its affiliates, singly or in combination, Incentive Stock Options, Other Stock Options, Stock Appreciation Rights, Restricted Stock, Purchase Stock, Dividend Equivalent Rights, Performance Units, Performance Shares or Other Stock-Based Grants, in each case as such terms are defined therein. The terms of any such grant will be determined by the Compensation Committee and set forth in a separate grant agreement. The exercise price will be at least equal to 100% of fair market value of the Common Stock on the date of grant in the case of Incentive Stock Options and the exercise price of Other Stock Options will be at least equal to 50% of fair market value of the Common Stock on the date of grant, provided that options to purchase up to 433,546 shares of Common Stock may be granted with an exercise price equal to $.01 per share, which is the par value of the Common Stock. Non-Qualified Stock Options and Other Stock Options may be exercisable for up to ten years. On February 21, 1997 (the "Grant Date"), the Company granted to the officers of the Company, pursuant to separate Non-Qualified Stock Option Agreements (collectively, as amended, the "Stock Option Agreements") between the Company and each of such persons, options to purchase a total of 753,998 shares of Common Stock under the Stock Purchase and Option Plan. In addition, the Company has granted options to purchase an aggregate of 95,696 shares of Common Stock to other employees of the Company. Under the terms of the Stock Option Agreements, 50% of the options granted to each such person are designated as time options (collectively the "Time Options"), with an exercise price equal to $4.18 per share, and 50% are designated as performance options (collectively, the "Performance Options"), with an exercise price equal to $.01 per share. The Time Options become exercisable as to 20% of the shares of Common Stock subject thereto on the first anniversary of the Grant Date and are exercisable as to an additional 20% of such shares upon each anniversary of the Grant Date thereafter. The Performance Options become exercisable at any time following the second anniversary of the Grant Date, when the Investment Return Hurdle (as such term is defined) is met; provided that the Performance Options become exercisable as to 100% of the shares of Common Stock subject thereto on the ninth anniversary of the Grant Date. MANAGEMENT INVESTOR SUBSCRIPTION AGREEMENTS AND RELATED TRANSACTIONS -- On February 21, 1997, each of the Company's officers (the "Management Investors") entered into a Management Investor Subscription Agreement with the Company pursuant to which the Management Investors purchased an F-26 DOMAIN ENERGY CORPORATION NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) aggregate of 390,307 shares of Common Stock at an average price of $4.18 per share. To facilitate such purchases, the Company loaned the Management Investors an aggregate of approximately $546,000. All such indebtedness of such person accrues interest at the rate of 8% per annum, payable semiannually; provided that each Management Investor may elect to satisfy his or her semiannual interest payment obligation by increasing the principal amount of the indebtedness owed to the Company by the amount of interest otherwise payable. As security for such loans made by the Company, each Management Investor pledged to the Company, and granted a first priority security interest in, the shares of Common Stock purchased by such Management Investor pursuant to its respective Management Investor Subscription Agreement and is required to pledge, and grant a first priority security interest in, all other shares of Common Stock that each such person may subsequently acquire, including, without limitation, upon exercise of options to purchase shares of Common Stock. In addition, in April 1997, other employees of the Company purchased 95,696 shares of Common Stock at an average price of $4.18 per share. COMPENSATION EXPENSE -- For purposes of determining compensation expense pursuant to APB 25, the measurement date for the stock options granted to officers of the Company is December 31, 1996 as on that date each officer knew the number of options (both Time Options and Performance Options) that they would be granted, the number of shares that they would be entitled to receive upon exercise of the options and the option exercise price. The measurement date for other options granted and stock sold is the date of the grant or sale. Compensation expense is calculated based on the difference in the proceeds that the Company receives upon issuance of the stock and the estimated fair value of the stock at the measurement date. OPTION TO ACQUIRE COMMON STOCK -- Pursuant to the Subscription Agreement, dated December 31, 1996 (the "First Reserve Subscription Agreement"), between the Company and Fund VII, the Company granted to Fund VII an option (the "First Reserve Option") to acquire 1,914,048 shares of Common Stock for an aggregate purchase price of $8.0 million plus any cash interest payment on the Note actually received by Fund VII (the "Option Price"). The Option Price may be paid by Fund VII (i) prior to the date on which the Note has been paid in full, by delivery to the Company of the Note together with the payment in cash of any principal or interest payments on the Note previously received by Fund VII and (ii) after the date on which the Note has been paid in full, by payment of the Option Price in cash. In connection with the Offering, the Company and Fund VII have agreed to restructure the terms of the First Reserve Option as set forth below. The Company and Fund VII have agreed that concurrently with consummation of the Offering, Fund VII will purchase, at a price per share equal to the Price to Public set forth on the cover page of this Prospectus, a number of shares of Common Stock such that the aggregate purchase price paid by Fund VII for such shares equals $8,681,000. The amount of $8,681,000 represents the sum of (i) the outstanding principal balance of the note plus estimated accrued interest thereon through June 15, 1997 and (ii) $500,000 in cash to be paid by Fund VII. In accordance with APB 14, $1.0 million of the Note, representing the estimated fair value of the First Reserve Option, has been reclassified from notes payable to additional paid-in capital. 3. SALE OF NON-CORE ASSETS On April 9, 1997, the Company sold its interest in a natural gas development project located in northwest Michigan (the "Michigan Development Project"). The Company received $2.1 million in cash and will receive an additional $5.4 million from the payment of an interest-bearing note receivable. The aggregate sale price approximated the Company's carrying value. F-27 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Stockholders of Domain Energy Corporation We have audited the accompanying statement of revenues and direct operating expenses of the properties acquired by Tenneco Ventures Corporation, predecessor to Domain Energy Corporation, (the "Company") from Pennzoil Exploration and Production Corporation and Pennzoil Petroleum Company (collectively "Pennzoil") for the eleven month period ended November 30, 1994. This statement is the responsibility of the Company's management. Our responsibility is to express an opinion on the statement based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statement. We believe that our audit provides a reasonable basis for our opinion. The accompanying statement was prepared for the purpose of complying with certain rules and regulations of the Securities and Exchange Commission (for inclusion in the Registration Statement on Form S-1 of Domain Energy Corporation) and is not intended to be a complete financial presentation of Pennzoil's interests in the properties described above. In our opinion, the statement referred to above presents fairly, in all material respects, the revenues and direct operating expenses of the properties acquired by the Company from Pennzoil for the eleven month period ended November 30, 1994, in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Houston, Texas June 13, 1997 F-28 DOMAIN ENERGY CORPORATION STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTIES ACQUIRED BY TENNECO VENTURES CORPORATION FROM PENNZOIL EXPLORATION AND PRODUCTION CORPORATION AND PENNZOIL PETROLEUM COMPANY FOR THE ELEVEN MONTHS ENDED NOVEMBER 30, 1994 (IN THOUSANDS) -------------- Oil and gas revenues................. $ 23,047 Direct operating expenses............ 6,179 -------------- Revenues in excess of direct operating expenses................. $ 16,868 ============== The accompanying notes are an integral part of this statement. F-29 DOMAIN ENERGY CORPORATION NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTIES ACQUIRED BY TENNECO VENTURES CORPORATION FROM PENNZOIL EXPLORATION AND PRODUCTION CORPORATION AND PENNZOIL PETROLEUM COMPANY FOR THE ELEVEN MONTHS ENDED NOVEMBER 30, 1994 1. OPERATIONS, ORGANIZATION AND BASIS OF PRESENTATION The accompanying statement represents the interests in the natural gas and oil revenues and direct operating expenses of the natural gas and oil producing properties acquired by Tenneco Ventures Corporation, predecessor to Domain Energy Corporation (the "Company") from Pennzoil Exploration and Production Company and Pennzoil Petroleum Company (collectively "Pennzoil") on December 1, 1994 for approximately $51,300,000. The oil and gas producing properties acquired are located primarily in the Gulf of Mexico. These properties are referred to herein as the "Properties." The accompanying statement was derived from the historical accounting records of Pennzoil. Direct operating expenses include payroll, lease and well repairs, maintenance and other direct operating expenses. ACCRUAL BASIS STATEMENTS -- Memorandum adjustments have been made to the financial information in order to present the accompanying statement in accordance with generally accepted accounting principles. REVENUE RECOGNITION AND GAS BALANCING -- The Company recognized oil and gas revenue from its interests in producing wells as oil and gas was sold from those wells. Accordingly, the Company used the sales method to account for gas production volume imbalances. Under the sales method of accounting, revenue is recorded based on the sales of production. Substantially all such gas imbalances were anticipated to be settled with production in future periods. At November 30, 1994, the Company was entitled to additional future production from the Properties of approximately 901,000 mcf. USE OF ESTIMATES -- A number of estimates and assumptions have been made relating to the preparation of this statement in conformity with generally accepted accounting principles. Actual results could differ from those estimates. 2. OMITTED HISTORICAL FINANCIAL INFORMATION Historical financial statements reflecting financial position, results of operations and cash flows required by generally accepted accounting principles are not presented as such information is not readily available on an individual property basis and not meaningful for the properties. Historically no allocation of general and administrative, litigation, interest or federal income tax expense was made to the Properties, and depreciation, depletion and amortization was computed based on Pennzoil's basis in the Properties. Accordingly, the statement is presented in lieu of the financial statements required under Rule 3-05 of Securities and Exchange Commission Regulation S-X. 3. COMMITMENT AND CONTINGENCIES The Company is unaware of any legal, environmental or other contingencies that would be materially important in relation to the statement. 4. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) ESTIMATED NET QUANTITIES OF PROVED AND DEVELOPED OIL AND GAS RESERVES -- Proved reserves are estimated quantities of crude oil and natural gas 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 developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. F-30 DOMAIN ENERGY CORPORATION NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTIES ACQUIRED BY TENNECO VENTURES CORPORATION FROM PENNZOIL EXPLORATION AND PRODUCTION CORPORATION AND PENNZOIL PETROLEUM COMPANY FOR THE ELEVEN MONTHS ENDED NOVEMBER 30, 1994 -- (CONTINUED) The following tables present the estimated net proved and proved developed oil and gas reserves, attributable to the Properties at November 30, 1994, along with a summary of changes in the quantities of net proved reserves during the eleven months ended November 30, 1994. NOVEMBER 30, 1994 ---------------------------------- OIL, CONDENSATE AND NATURAL NATURAL GAS GAS LIQUIDS (MCF) (BBLS) ------------ ---------------- Proved Reserves: Beginning of period............. 59,970,693 1,481,458 Production...................... (10,722,190) (218,649) ------------ ---------------- End of period................... 49,248,503 1,262,809 ============ ================ Proved Developed Reserves -- End of period................... 39,457,176 682,914 ============ ================ STANDARDIZED MEASURE -- The Standardized Measure of Discounted Future Net Cash Flows relating to the Company's ownership interest in proved oil and gas reserves attributable to the Properties as of November 30, 1994 are shown below (in thousands): Future cash inflows.................. $ 96,693 Future oil and natural gas operating expenses........................... (28,451) Future development costs............. (21,245) Future income tax expense............ (17,859) ---------- Future net cash flows................ 29,138 10% annual discount for estimated timing of net cash flows........... (4,839) ---------- Standardized measure of discounted future net cash flows.............. $ 24,299 ========== Future cash flows were computed by applying period end prices of oil and natural gas to period end quantities of proved oil and natural gas reserves. Future operating expenses and development costs were computed primarily by the Company's petroleum engineers by estimating the amount and timing of the expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves attributable to the Properties at the end of the period, based on period end costs and assuming continuation of existing economic conditions. Future income taxes were based on period end statutory rates. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the oil and natural gas reserves attributable to the Properties. 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, a discount factor more representative of the time value of money and the risks inherent in reserve estimates. F-31 DOMAIN ENERGY CORPORATION NOTES TO THE STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTIES ACQUIRED BY TENNECO VENTURES CORPORATION FROM PENNZOIL EXPLORATION AND PRODUCTION CORPORATION AND PENNZOIL PETROLEUM COMPANY FOR THE ELEVEN MONTHS ENDED NOVEMBER 30, 1994 -- (CONTINUED) CHANGES IN THE STANDARDIZED MEASURE -- Changes in the standardized measure of discounted future net cash flows relating to proved reserves attributable to the Properties for the eleven months ended November 30, 1994 are summarized below (in thousands): Standardized measure, beginning of period............................. $ 40,363 Sales, net of production costs....... (16,868) Net change in income taxes........... 6,410 Accretion of discount................ (5,606) ---------- Standardized measure, end of period............................. $ 24,299 ========== F-32 DEGOLYER AND MACNAUGHTON ONE ENERGY SQUARE DALLAS, TEXAS 75206 APPRAISAL REPORT AS OF DECEMBER 31, 1996 ON CERTAIN INTERESTS OWNED BY DOMAIN ENERGY VENTURES CORPORATION AND DOMAIN ENERGY PRODUCTION CORPORATION PROVED RESERVES FOREWARD SCOPE OF INVESTIGATION This report presents an appraisal, as of December 31, 1996, of the extent and value of the proved crude oil, condensate, and natural gas reserves of certain property interests owned by (i) Domain Energy Ventures Corporation (Domain), (ii) the Matrix Limited Partnership owned by Domain, and (iii) Domain Energy Production Corporation through the Investment Fund I (DEPC Fund I) and the Investment Fund II (DEPC Fund II). DEPC Fund I is composed of four investors, one of which is Domain Energy Corporation. Domain Energy Corporation is the managing partner for DEPC Fund I and its ownership interest is 10 percent of the total working interest owned by DEPC Fund I. The other investors participate as net profits interest owners in the remaining 90 percent of the total working interest taken by DEPC Fund I. The interests evaluated herein are the total of Domain Energy Corporation's 10 percent and the 90 percent owned by the other three Participants in DEPC Fund I. DEPC Fund II is composed of four investors, one of which is Domain Energy Corporation. Domain Energy Corporation is the managing partner for DEPC Fund II and its ownership interest is 30 percent of the total working interest owned by DEPC Fund II. The other investors participate as net profits interest owners in the remaining 70 percent of the total working interest taken by DEPC Fund II. The interest evaluated herein are the total of Domain Energy Corporation's 30 percent and the 70 percent owned by the other three participants in DEPC Fund II. Those properties consist of certain productive leasehold interests located in Alabama, Louisiana, Mississippi, and Texas and offshore from Alabama, Louisiana, and Texas. This report estimates values for proved reserves using initial prices and costs based on data provided by Domain with no increases in the future based on inflation. A detailed explanation of the future price and cost assumptions is included in the Valuation of Reserves section of this report. Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 1996. Net reserves are defined as that portion of the gross reserves attributable to the interests of Domain, DEPC Fund I, or DEPC Fund II after deducting royalties and interests owned by others. Values of the net reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue from the production and sale of the estimated production taxes, operating expenditures, and capital costs from the future gross revenue. Operating expenditures include field operating costs, ad valorem taxes, and the estimated expenses of direct supervision but do not include that portion of general administrative costs sometimes allocated to production. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded A-1 DEGOLYER AND MACNAUGHTON monthly over the expected period of realization. This report shows present worth values using a discount rate of 10 percent. Estimates of oil, condensate, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. AUTHORITY This report was prepared at the request of Mr. Douglas H. Woodul, Vice President -- Production, Domain. SOURCE OF INFORMATION Information used in the preparation of this report was obtained from the Domain files, from records on file with the appropriate regulatory agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished by Domain with respect to property interests, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report. A-2 DEGOLYER AND MACNAUGHTON CLASSIFICATION OF RESERVES Petroleum reserves included in this report are classified as proved and are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: PROVED -- Reserves that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data. Commercial productivity has been established by actual production, successful testing, or in certain cases by favorable core analyses and electrical-log interpretation when the producing characteristics of the formation are known from nearby fields. Volumetrically, the structure, areal extent, volume, and characteristics of the reservoir are well defined by a reasonable interpretation of adequate subsurface well control and by known continuity of hydrocarbon-saturated material above known fluid contacts, if any, or above the lowest known structural occurrence of hydrocarbons. DEVELOPED -- Reserves that are recoverable from existing wells with current operating methods and expenses. Developed reserves include both producing and nonproducing reserves. Estimates of producing reserves assume recovery by existing wells producing from present completion intervals with normal operating methods and expenses. Developed nonproducing reserves are in reservoirs behind the casing or at minor depths below the producing zone and are considered proved by production from other wells in the field, by successful drill-stem tests, or by core analyses from the particular zones. Nonproducing reserves require only moderate expense to be brought into production. UNDEVELOPED -- Reserves that are recoverable from additional wells yet to be drilled. Undeveloped reserves are those considered proved for production by reasonable geological interpretation of adequate subsurface control in reservoirs that are producing or proved by other wells but are not recoverable from existing wells. This classification of reserves requires drilling of additional wells, major deepening of existing wells, or installation of enhanced recovery or other facilities. Reserves recovered by enhanced recovery methods, such as injection of external fluids to provide energy not inherent in the reservoirs, may be classified as proved developed or proved undeveloped reserves depending upon the extent to which such enhanced recovery methods are in operation. These reserves are considered to be proved only in cases where a successful fluid injection program is in operation, a pilot program indicates successful fluid injection, or information is available concerning the successful application of such methods in the same reservoir and it is reasonably certain that the program will be implemented. A-3 DEGOLYER AND MACNAUGHTON ESTIMATION OF RESERVES Estimates of reserves were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volumes. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to calculate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP. Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the calculation of reserves. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic conditions. In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available. Future oil and gas producing rates estimated for this report are based on production rates considering the most recent data available or, in certain cases, are based on estimates provided by Domain. The rates used for future production are estimated to be within the capacity of a well or reservoir to produce. Data available from wells drilled on the appraised properties through December 31, 1996, were used in estimating gross ultimate recovery. Gross production estimated to December 31, 1996, when applicable, was deducted from gross ultimate recovery to arrive at estimates of gross reserves. This required that production rates be estimated for up to 5 months since production data were available only through July 1996 in certain fields. Gas reserves are expressed as salable reserves at a temperature of 60 degrees Fahrenheit (F) and at the legal pressure bases of the states or areas in which the reserves are located. Condensate reserves estimated herein are those to be obtained by normal separator recovery. A-4 DEGOLYER AND MACNAUGHTON The proved reserves, as of December 31, 1996, of the properties appraised are estimated as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf):
GROSS RESERVES NET RESERVES ---------------------------- ------------------------- OIL AND OIL AND CONDENSATE GAS CONDENSATE GAS (BBL) (MCF) (BBL) (MCF) ----------- -------------- ---------- ------------ DOMAIN Proved Developed............. 275,866,767 410,903,065 7,740,848 46,979,647 Undeveloped........... 268,052 40,304,512 46,463 9,744,742 ----------- -------------- ---------- ------------ Total Proved............... 276,134,819 451,207,577 7,787,311 56,724,389 MATRIX LIMITED PARTNERSHIP Proved Developed............. 36,473 38,804,681 7,685 3,940,863 Undeveloped........... 3,333 2,564,000 178 137,217 ----------- -------------- ---------- ------------ Total Proved............... 39,806 41,368,681 7,863 4,078,080 DEPC FUND I Proved Developed............. 359,641 86,955,018 49,983 14,317,813 Undeveloped........... 70,875 11,120,000 15,571 2,620,854 ----------- -------------- ---------- ------------ Total Proved............... 430,516 98,075,018 65,554 16,938,667 DEPC FUND II Proved Developed............. 0 888,744 0 149,922 Undeveloped........... 0 0 0 0 ----------- -------------- ---------- ------------ Total Proved............... 0 888,744 0 149,922
A-5 DEGOLYER AND MACNAUGHTON VALUATION OF RESERVES Revenue values in this report were estimated using the initial prices and costs, as of December 31, 1996, provided by Domain. Future prices were estimated using guidelines established by the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB). The initial and future prices and producing rates used in this report have been reviewed by Domain and it has represented that the gas prices and rates used herein are those that Domain could reasonably expect to receive. In this report, values for proved reserves are based on projections of estimated future production and revenue prepared for these properties. The assumptions used for estimating future prices and costs are as follows: DOMAIN OIL AND CONDENSATE PRICES Initial oil and condensate prices furnished by Domain range from $19.23 to $24.71 per barrel and are held constant for the producing lives of the properties. NATURAL GAS PRICES Initial gas prices, also furnished by Domain, range from $1.59 to $4.1403 per thousand cubic feet of gas and are held constant for the producing lives of the properties. MATRIX LIMITED PARTNERSHIP OIL AND CONDENSATE PRICES Initial oil and condensate prices furnished by Domain range from $20.98 to $23.39 per barrel and are held constant for the producing lives of the properties. NATURAL GAS PRICES Initial gas prices, also furnished by Domain, range from $2.50 to $3.9129 per thousand cubic feet of gas and are held constant for the producing lives of the properties. DEPC FUND I OIL AND CONDENSATE PRICES Initial oil and condensate prices furnished by Domain range from $22.85 to $24.71 per barrel and are held constant for the producing lives of the properties. NATURAL GAS PRICES Initial gas prices, also furnished by Domain, range from $1.641 to $4.0122 per thousand cubic feet of gas and are held constant for the producing lives of the properties. DEPC FUND II OIL AND CONDENSATE PRICES No oil or condensate reserves are assigned, therefore no price was furnished. NATURAL GAS PRICES The initial gas price furnished by Domain is $1.641 per thousand cubic feet of gas and are held constant for the producing life of the property. A-6 DEGOLYER AND MACNAUGHTON For all properties, assumptions used for estimating operating and capital costs are as follows: OPERATING AND CAPITAL COSTS Initial estimates of operating costs are based on data furnished by Domain and are used for the lives of the properties with no increases in the future based on inflation. Future capital expenditures are estimated using 1996 values and are not adjusted for inflation. The estimated future revenue to be derived from the production and sale of the net proved reserves of the properties appraised herein under the economic assumptions furnished by Domain is summarized as follows: PROVED PROVED TOTAL DEVELOPED UNDEVELOPED PROVED ($) ($) ($) ----------- ----------- -------------- DOMAIN Future Gross Revenue.............340,203,048 37,704,437 377,907,485 Production Taxes................. 13,483,172 149,489 13,632,661 Operating Costs and Ad Valorem Taxes..........................185,033,938 3,267,082 188,301,020 Capital Costs.................... 11,954,105 8,535,145 20,489,250 Future Net Revenue*..............129,731,833 25,752,721 155,484,554 Present Worth at 10 Percent*.....108,460,234 14,303,791 122,764,025 MATRIX LIMITED PARTNERSHIP Future Gross Revenue............. 12,957,212 541,077 13,498,289 Production Taxes................. 0 0 0 Operating Costs and Ad Valorem Taxes.......................... 1,758,862 93,600 1,852,462 Capital Costs.................... 910,967 97,500 1,008,467 Future Net Revenue*.............. 10,287,383 349,977 10,637,360 Present Worth at 10 Percent*..... 9,327,934 244,630 9,572,564 DEPC FUND I Future Gross Revenue............. 53,972,978 9,809,858 63,782,836 Production Taxes................. 387,065 171,027 558,092 Operating Costs and Ad Valorem Taxes.......................... 3,297,374 517,507 3,814,881 Capital Costs.................... 1,882,791 1,891,348 3,774,139 Future Net Revenue*.............. 48,405,748 7,229,976 55,635,724 Present Worth at 10 Percent*..... 36,128,387 5,484,908 41,613,295 DEPC FUND II Future Gross Revenue............. 246,021 0 246,021 Production Taxes................. 18,452 0 18,452 Operating Costs and Ad Valorem Taxes.......................... 38,940 0 38,940 Capital Costs.................... 0 0 0 Future Net Revenue*.............. 188,629 0 188,629 Present Worth at 10 Percent*..... 173,247 0 173,247 - ------------ * Future income tax expenses were not taken into account in the preparation of these estimates. A-7 DEGOLYER AND MACNAUGHTON In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 10-13, 15 and 30(a)-(b) of Statement of Financial Account Standards No. 69 (November 1982) of the FASB and Rules 4-10(a) (1)-(13) of Regulation S-X and Rule 302(b) of Regulation S-K of the SEC; provided, however, (i) certain estimated data have not been provided with respect to changes in reserves information and (ii) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein. To the extent the above-enumerated rules regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of our report, we are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. A-8 DEGOLYER AND MACNAUGHTON SUMMARY AND CONCLUSIONS Evaluated herein are certain interests owned by Domain, the Matrix Limited Partnership, and Domain Energy Production Corporation through DEPC Fund I and DEPC Fund II. The appraised properties are located in Alabama, Louisiana, Mississippi, and Texas and offshore from Alabama, Louisiana, and Texas. The net proved reserves, as of December 31, 1996, of the property interests owned by Domain are estimated as follows, expressed in barrels (bbl) and thousands of cubic feet (Mcf): OIL AND CONDENSATE GAS (BBL) (MCF) ---------- ------------ Net Proved Reserves.................. 7,787,311 56,724,389 Revenue and costs attributable to the production and sale of Domain's net proved reserves as of December 31, 1996, of the properties evaluated, under the aforementioned assumptions concerning future prices and costs, are estimated as follows: PROVED PROVED TOTAL DEVELOPED UNDEVELOPED PROVED ($) ($) ($) -------------- ----------- -------------- DOMAIN Future Gross Revenue............ 340,203,048 37,704,437 377,907,485 Production Taxes................ 13,483,172 149,489 13,632,661 Operating Costs and Ad Valorem Taxes......................... 185,033,938 3,267,082 188,301,020 Capital Costs................... 11,954,105 8,535,145 20,489,250 Future Net Revenue*............. 129,731,833 25,752,721 155,484,554 Present Worth at 10 Percent*.... 108,460,234 14,303,791 122,764,025 * Future income tax expenses were not taken into account in the preparation of these estimates. The net proved reserves, as of December 31, 1996, of the properties owned by the Matrix Limited Partnership are estimated as follows: OIL AND CONDENSATE GAS (BBL) (MCF) ---------- ----------- Net Proved Reserves.................. 7,863 4,078,080 Revenue and costs attributable to the production and sale of Matrix Limited Partnership's net proved reserves as of December 31, 1996, of the properties evaluated, under the aforementioned assumptions concerning future prices and costs, are estimated as follows: PROVED PROVED TOTAL DEVELOPED UNDEVELOPED PROVED ($) ($) ($) ------------ ----------- ------------ MATRIX LIMITED PARTNERSHIP Future Gross Revenue............. 12,957,212 541,077 13,498,289 Production Taxes................. 0 0 0 Operating Costs and Ad Valorem Taxes.......................... 1,758,862 93,600 1,852,462 Capital Costs.................... 910,967 97,500 1,008,467 Future Net Revenue*.............. 10,287,383 349,977 10,637,360 Present Worth at 10 Percent*..... 9,327,934 244,630 9,572,564 * Future income tax expenses were not taken into account in the preparation of these estimates. A-9 DEGOLYER AND MACNAUGHTON The net proved reserves, as of December 31, 1996, of the properties owned by Domain Energy Production Corporation through DEPC Fund I are estimated as follows: OIL AND CONDENSATE GAS (BBL) (MCF) ---------- ------------ Net Proved Reserves.................. 65,554 16,938,667 Revenue and costs attributable to the production and sale of the net proved reserves, as of December 31, 1996, of the DEPC Fund I properties, under the aforementioned assumptions concerning future prices and costs, are estimated as follows: PROVED PROVED TOTAL DEVELOPED UNDEVELOPED PROVED ($) ($) ($) ------------ ----------- ------------ DEPC FUND I Future Gross Revenue.............. 53,972,978 9,809,858 63,782,836 Production Taxes.................. 387,065 171,027 558,092 Operating Costs and Ad Valorem Taxes........................... 3,297,374 517,507 3,814,881 Capital Costs..................... 1,882,791 1,891,348 3,774,139 Future Net Revenue*............... 48,405,748 7,229,976 55,635,724 Present Worth at 10 Percent*...... 36,128,387 5,484,908 41,613,295 * Future income tax expenses were not taken into account in the preparation of these estimates. The net proved reserves, as of December 31, 1996, of the properties owned by Domain Energy Production Corporation through DEPC Fund II are estimated as follows: OIL AND CONDENSATE GAS (BBL) (MCF) ---------- --------- Net Proved Reserves.................. 0 149,922 Revenue and costs attributable to the production and sale of the net proved reserves, as of December 31, 1996, of the DEPC Fund II properties, under the aforementioned assumptions concerning future prices and costs, are estimated as follows: PROVED PROVED TOTAL DEVELOPED UNDEVELOPED PROVED ($) ($) ($) --------- ----------- --------- DEPC FUND II Future Gross Revenue............... 246,021 0 246,021 Production Taxes................... 18,452 0 18,452 Operating Costs and Ad Valorem Taxes............................ 38,940 0 38,940 Capital Costs...................... 0 0 0 Future Net Revenue*................ 188,629 0 188,629 Present Worth at 10 Percent*....... 173,247 0 173,247 * Future income tax expenses were not taken into account in the preparation of these estimates. A-10 DEGOLYER AND MACNAUGHTON Gas reserves estimated herein are expressed at a temperature base of 60F and at the legal pressure bases of the states or areas in which the reserves are located. Submitted, /s/DEGOLYER AND MACNAUGHTON DeGOLYER and MacNAUGHTON SIGNED: March 26, 1997 /s/JAMES W. HAIL, JR., P.E. James W. Hail, Jr., P.E. Senior Vice President DeGolyer and MacNaughton A-11 March 26, 1997 Mr. Herb A. Newhouse Domain Energy Corporation 1100 Louisiana, Suite 1500 Houston, Texas 77002 Dear Mr. Newhouse: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 1996, to the Domain Energy Ventures Corporation (Domain) interest and the Domain Energy Production Corporation Fund II (DEPC Fund) interest in certain oil and gas properties located in the West Delta 30 Field Area, federal waters offshore Louisiana. This letter summarizes the results of our reports dated February 24, 1997, and February 26, 1997. This report has been prepared using constant prices and costs and conforms to the guidelines of the Securities and Exchange Commission (SEC). We estimate the net reserves and future net revenue to the Domain interest, as of December 31, 1996, to be:
Net Reserves Future Net Revenue ------------------------------ ---------------------------------- Oil Gas Present Worth Category (Barrels) (MCF) Total at 10% - ---------------------- ------------- ------------ --------------- --------------- Proved Developed Producing 92,463 129,699 $ 3,600 $ 103,100 Non-Producing 167,675 892,194 3,778,900 3,179,700 Proved Undeveloped 108,610 876,744 4,408,600 3,315,500 ------------- ------------ --------------- --------------- Total Proved 368,748 1,898,637 $ 8,191,100 $ 6,598,300
We estimate the net reserves and future net revenue to the DEPC Fund interest, as of December 31, 1996, to be:
Net Reserves Future Net Revenue ------------------------------ ---------------------------------- Oil Gas Present Worth Category (Barrels) (MCF) Total at 10% - ---------------------- ------------- ------------ --------------- --------------- Proved Developed Producing 554,797 778,206 $ 6,000 $ 610,400 Non-Producing 1,006,060 5,353,157 22,593,100 19,019,700 Proved Undeveloped 651,665 5,260,459 26,365,500 19,825,300 ------------- ------------ --------------- --------------- Total Proved 2,212,522 11,391,822 $48,964,600 $39,455,400
The oil reserves shown include crude oil and condensate. Oil volumes are expressed in barrels which are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (MCF) at the contract temperature and pressure bases. A-12 The estimated reserves and future revenue shown are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. In accordance with SEC guidelines, our estimates do not include any value for probable or possible reserves which may exist for these properties. Our estimates do not include any value which could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Future gross revenue is Domain and DEPC Fund's share of the gross (8/8ths) revenue from the properties. Future net revenue is after deducting future capital costs, operating expenses, any applicable payments to net profits interests, and abandonment costs, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its "present worth." The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties. For the purposes of this report, a field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs which may be incurred due to such possible liability. Also, our estimates do not include any salvage value for the lease and well equipment, but do include our estimates of the costs to abandon the wells, platforms, and production facilities. Abandonment costs are included with other capital investments. The oil and gas prices used in this report are the actual prices received on December 31, 1996. Oil and gas prices are held constant in accordance with SEC guidelines. Lease and well operating costs are based on operating expense records of Domain Energy Corporation. These costs include the per-well overhead expenses allowed under joint operating agreements along with costs estimated to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Domain Energy Corporation are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, new development wells, and production equipment. We have made no investigation of potential gas volume and value imbalances which may have resulted from overdelivery or underdelivery to the Domain or the DEPC Fund interests. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Domain and the DEPC Fund receiving their net revenue interest share of estimated future gross gas production. A-13 The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. A substantial portion of these reserves are for behind pipe zones and undeveloped locations. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. As such reserve estimates are usually subject to greater revision than those based on substantial production and pressure data, it may be necessary to revise these estimates up or down in the future as additional performance data become available. The sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions included in this report due to governmental policies and uncertainties of supply and demand. Also, estimates of reserves may increase or decrease as a result of future operations. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which legal or accounting, rather than engineering and geological, interpretation may be controlling. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions necessarily represent only informed professional judgments. The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Domain Energy Ventures Corporation, Domain Energy Corporation, other interest owners, various operators of the properties, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. We are independent petroleum engineers, geologists, and geophysicists; we do not own an interest in these properties and are not employed on a contingent basis. Basic geologic and field performance data together with our engineering work sheets are maintained on file in our office. Very truly yours, /s/ CLARENCE NETHERLAND A-14 - ------------------------------------------------------ NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE INFORMATION HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE SUCH DATE. ------------------ TABLE OF CONTENTS PAGE ---- Prospectus Summary...................... 3 Risk Factors............................ 11 Use of Proceeds......................... 19 Dividend Policy......................... 19 Capitalization.......................... 20 Dilution................................ 21 Unaudited Condensed Pro Forma Financial Statements............................ 22 Selected Historical Financial Data...... 31 Management's Discussion and Analysis of Financial Condition and Results of Operations............................ 32 Business and Properties................. 43 Management.............................. 64 Transactions with Management and First Reserve............................... 71 Security Ownership of Certain Beneficial Owners and Management................. 73 Description of Capital Stock............ 74 Shares Eligible for Future Sale......... 75 Underwriting............................ 77 Notice to Canadian Residents............ 79 Legal Matters........................... 80 Experts................................. 80 Available Information................... 80 Glossary................................ 81 Index to Financial Statements........... F-1 Reports of Independent Petroleum Engineers............................. A-1 ------------------ UNTIL JULY 19, 1997, ALL DEALERS EFFECTING TRANSACTIONS IN THE REGISTERED SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS. [LOGO] DOMAIN ENERGY CORPORATION 6,000,000 Shares Common Stock ($.01 par value) PROSPECTUS CREDIT SUISSE FIRST BOSTON PAINEWEBBER INCORPORATED PRUDENTIAL SECURITIES INCORPORATED MORGAN KEEGAN & COMPANY, INC. - ------------------------------------------------------ -----END PRIVACY-ENHANCED MESSAGE-----