-----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, EHlSSqW2POWT7JqJpxDRDOt+Yk2/NvsZi5J7K6HqCJgWzTIuQkzAiyqph2aSTQBa c53fDXMjE970vUfXYcKdyA== 0000950129-96-001585.txt : 19960729 0000950129-96-001585.hdr.sgml : 19960729 ACCESSION NUMBER: 0000950129-96-001585 CONFORMED SUBMISSION TYPE: 424B4 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19960726 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: HARCOR ENERGY INC CENTRAL INDEX KEY: 0000315272 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 330234380 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: 1933 Act SEC FILE NUMBER: 333-04987 FILM NUMBER: 96599387 BUSINESS ADDRESS: STREET 1: FIVE POST OAK PARK STREET 2: STE 2220 CITY: HOUSTON STATE: TX ZIP: 77027-3413 BUSINESS PHONE: 7139611804 FORMER COMPANY: FORMER CONFORMED NAME: PANGEA PETROLEUM CO DATE OF NAME CHANGE: 19880120 FORMER COMPANY: FORMER CONFORMED NAME: POLLOCK PETROLEUM INC DATE OF NAME CHANGE: 19840807 424B4 1 HARCOR ENERGY, INC. 1 Filed Pursuant to Rule 424(b)(4) Registration No. 333-04987 6,400,000 SHARES [HARCOR ENERGY, HARCOR ENERGY, INC. INC. LOGO] COMMON STOCK Of the 6,400,000 shares (the "Shares") of Common Stock, $.10 par value per share (the "Common Stock"), of HarCor Energy, Inc., a Delaware corporation ("HarCor" or the "Company"), offered hereby (the "Offering"), 5,059,059 are being sold by the Company and 1,340,941 are being sold directly by the Selling Stockholders. See "Principal and Selling Stockholders." The Company will not receive any proceeds from the sale of shares of Common Stock by the Selling Stockholders. The Common Stock is traded on the Nasdaq National Market under the symbol "HARC." On July 25, 1996, the closing price of the Common Stock on the Nasdaq National Market was $5.00 per share. See "Price Range of Common Stock." SEE "RISK FACTORS" BEGINNING ON PAGE 12 FOR A DISCUSSION OF CERTAIN RISK FACTORS THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS. --------------------- 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 PROCEEDS TO PRICE DISCOUNTS AND PROCEEDS TO THE THE SELLING TO PUBLIC COMMISSIONS(1) COMPANY(2) STOCKHOLDERS(2) - ------------------------------------------------------------------------------------------------ Per Share............. $4.50 $0.29 $4.21 $4.21 - ------------------------------------------------------------------------------------------------ Total(3).............. $28,800,000 $1,872,000 $21,285,991 $5,642,009 ================================================================================================
(1) See "Underwriting" for information concerning indemnification of the Underwriters. (2) Before deducting expenses of the Offering, estimated at $250,000, payable by the Company. (3) The Company has granted to the Underwriters a 30-day option to purchase up to 960,000 additional shares of Common Stock solely to cover over-allotments, if any. If such option is exercised in full, the total Price to Public, Underwriting Discounts and Commissions, Proceeds to the Company and Proceeds to the Selling Stockholders will be $33,120,000, $2,152,800, $25,325,191 and $5,642,009, respectively. See "Underwriting." --------------------- The shares of Common Stock are offered by the several Underwriters named herein subject to prior sale, when, as and if delivered to and accepted by the Underwriters, subject to the right to reject any order in whole or in part, and subject to certain other conditions. It is expected that delivery of the shares of Common Stock will be made at the offices of Rauscher Pierce Refsnes, Inc., Dallas, Texas, on or about July 31, 1996. RAUSCHER PIERCE REFSNES, INC. PETRIE PARKMAN & CO. SOUTHCOAST CAPITAL CORPORATION The date of this Prospectus is July 25, 1996. 2 AVAILABLE INFORMATION The Company is subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance therewith, files reports and other information with the Securities and Exchange commission (the "Commission"). Reports, proxy statements and other information filed by the Company are available at the web site that the Commission maintains at http: (w)ww.sec.gov. and can be inspected and copied at the public reference facilities maintained by the Commission at 450 Fifth Street, N.W., Washington, D.C. 20549, and the Commission's Regional Offices at Seven World Trade Center, 13th Floor, New York, New York, 10048 and CitiCorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511. Copies of such material can be obtained by mail from the Public Reference Branch of the Commission at 450 West Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates. The Company has filed with the Commission a Registration Statement on Form S-1 (herein, together with all amendments and exhibits, referred to as the "Regulation Statement") under the Securities Act of 1933, as amended (the "Securities Act"). This prospectus does not contain all of the information set forth in the Registration Statement, certain parts of which were omitted in accordance with the rules and regulations of the Commission. For further information, reference is hereby made to the Registration Statement. Any statements contained herein concerning the provisions of any document filed as an exhibit to the Registration Statement or otherwise filed with the Commission are not necessarily complete, and in each instance reference is made to the copy of such document so filed. Each such statement is qualified in its entirety by such reference. --------------------- IN CONNECTION WITH THE OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NASDAQ NATIONAL MARKET, IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. 2 3 PROSPECTUS SUMMARY This summary is qualified in its entirety by the more detailed information and the consolidated financial statements and notes thereto appearing elsewhere in this Prospectus. Unless otherwise indicated all information in this Prospectus assumes that the Underwriters' over-allotment option will not be exercised. Certain terms relating to the oil and gas industry are defined in the Glossary of Oil and Gas Terms included elsewhere in this Prospectus. Investors should carefully consider the information set forth in "Risk Factors." THE COMPANY GENERAL HarCor Energy, Inc. is an independent energy company engaged in the acquisition, exploitation and exploration of onshore crude oil and natural gas properties in the United States. Since 1987 when the present management group acquired control of the Company, HarCor has grown through selective acquisitions and development drilling, with estimated proved reserves increasing from 1.35 MMBOE as of January 1, 1990 to 29.9 MMBOE as of January 1, 1996, at an average replacement cost of $2.62 per BOE. The Company's operations are currently focused in the San Joaquin Basin of California, South Texas and the Permian Basin of West Texas. As of January 1, 1996, the Company's proved reserves, as estimated by the Company's independent petroleum engineers, consisted of 15.3 MMBbls of crude oil and NGLs and 87.6 Bcf of natural gas with a Pre-tax SEC 10 Value of $124.5 million, approximately 84% of which was attributable to net proved reserves located in the Lost Hills Field in the San Joaquin Basin. The Company conducts its exploration, development and production activities through strategic alliances with industry partners that are experienced and knowledgeable in the particular geologic basins of activity and that own a significant interest in the jointly owned properties. The industry partner is generally designated as the operator of the jointly owned properties, thereby allowing the Company to avoid the cost of maintaining the personnel and other resources necessary to be an operator. The Company believes, however, that its ownership of meaningful working interests in its properties, its contractual rights to approve drilling budgets or propose wells and its experienced team of oil and gas professionals allow the Company to control or significantly influence the operators' decisions affecting the magnitude and timing of exploration, development and production activities on its properties. Through geographic concentration and tight control over oil and gas operating and general and administrative expenses, the Company has maintained a relatively low cost structure. For the year ended December 31, 1995, the Company had an average production cost of $3.99 per BOE and general and administrative expenses of $1.80 per BOE. BUSINESS STRATEGY The Company's business objective is to increase its hydrocarbon reserves as economically as possible by: - Continuing to develop its San Joaquin Basin, South Texas and Permian Basin properties through additional drilling and secondary recovery activities; - Using the cash flow from its existing properties and the proceeds from the Offering to engage in exploration activities with experienced and technologically knowledgeable industry partners, initially onshore Texas and Louisiana; - Acquiring onshore oil and gas properties with significant development potential; and - Continuing to maintain relatively low production costs through geographic concentration and tight control over operating and general and administrative expenses. 3 4 DEVELOPMENT ACTIVITIES San Joaquin Basin. Approximately 20.8 MMBOE, or 69.4%, of the Company's total proved reserves as of January 1, 1996 were classified as proved undeveloped by Ryder Scott Company ("Ryder Scott"). Substantially all of the Company's undeveloped reserves are located in the Lost Hills Field in the San Joaquin Basin. Bakersfield Energy Resources, Inc. ("Bakersfield Energy"), a company with extensive experience in the San Joaquin Basin, is the operator of substantially all of HarCor's oil and gas properties in the San Joaquin Basin. As of March 31, 1996, the Company had identified 173 new gross wells which it intends to drill during the next five years to fully develop the proved reserves on the properties, of which 48 are expected to be drilled in 1996. The Company also plans to commence a secondary recovery waterflood project in the fourth quarter of 1996 with respect to a portion of its properties in the Lost Hills Field. In addition, the Company has completed a horizontal well in the Lost Hills Field to test a possible extension of the current proved area of the field and to evaluate the use of horizontal wells to eliminate the need to drill certain infill vertical wells. The Company has identified 60 potential locations for future development of probable and possible reserves located on the San Joaquin Basin properties. The San Joaquin Basin properties produce a light (approximately 40() gravity), low sulfur crude oil that commands a substantial price premium to the heavier crude oils typically produced in California. The associated natural gas produced with the crude oil has a high Btu content (approximately 1,240 Btu) which yields in excess of 2 gallons of NGLs per Mcf of natural gas when processed in the Company's gas processing plant located in the San Joaquin Basin. Since acquiring the properties in June 1994, the Company has drilled 76 gross development wells on the San Joaquin Basin properties, through March 31, 1996. As a result of such drilling activity, the Company's average daily production has increased from 546 Bbls of oil and 7,195 Mcf of gas for the month ended June 30, 1994 to 1,336 Bbls of oil and 13,895 Mcf of gas based on the quarter ended March 31, 1996. Since acquiring the San Joaquin Basin properties, the Company's net proved reserves attributable to such properties have increased from 14.1 MMBOE as of June 30, 1994, to 22.7 MMBOE as of January 1, 1996, at an average replacement cost of $1.65 per BOE. The Pre-tax SEC 10 Value of the Company's San Joaquin Basin properties as of January 1, 1996 was $105.2 million as estimated by Ryder Scott. In addition to the extensive development drilling program in the Lost Hills Field, the Company also plans to undertake a secondary oil recovery program to further increase reserves and production from the field. Using primary production techniques, it is estimated by Ryder Scott, as of January 1, 1996, that the Ellis Lease located in the Lost Hills Field has proved reserves net to the Company of approximately 9.0 MMBbls of crude oil. In addition to primary development, the Company intends to increase recovery rates by implementing a secondary recovery waterflood project in the Diatomite Zone on the Ellis Lease, which is similar to waterflood projects currently used by other oil and gas companies operating in the Lost Hills Field. The first phase of the Ellis Lease waterflood project is planned to be initiated in the fourth quarter of 1996, with expansion planned in 1997 and 1998 to cover the entire area currently estimated to cover proved reserves. Ryder Scott estimates that the Company's Ellis Lease will yield an additional 3.7 MMBbls of proved undeveloped secondary recovery crude oil reserves utilizing the waterflood recovery method. In addition, the Company will commence a feasibility study for waterflooding the Reef Ridge Shale and Antelope Shale formations on its San Joaquin Basin properties. During 1995, the Company and Bakersfield Energy completed a three-dimensional ("3-D") reservoir model of the Diatomite Zone on the Ellis Lease, the results of which are being used to examine various means of further optimizing its planned Ellis Lease waterflood, including the use of horizontal drilling on the property, as well as to assist the Company with additional computer simulation modeling of hot water, steam and CO(2) recovery techniques. In the fourth quarter of 1995, the Company undertook studies to evaluate the use of horizontal drilling technology on its San Joaquin Basin properties. As a result of these studies, the first of two horizontal wells planned for 1996 has been drilled and completed on the Ellis Lease in the Diatomite Zone at a vertical depth of approximately 3,450 feet with an approximate 2,000 foot lateral drilled outside of the Diatomite Zone's previous development to test a possible extension of the current proved area of the field and to evaluate the use of horizontal wells to eliminate the drilling of certain infill vertical wells on the Ellis Lease. During the five days of production tests, the well flowed at an average rate of 418 BOE per day. The second horizontal 4 5 well is planned to evaluate its applicability to producing the deeper MacDonald Shale formation at a depth of approximately 5,200 feet on the Ellis Lease. If these wells are successful, potential additional horizontal locations may be identified for future drilling on the Ellis Lease as well as in areas currently outside the proved areas of the Company's Truman and Tisdale Leases. The Company acquired its San Joaquin Basin properties from Bakersfield Energy in June 1994. Bakersfield Energy, which originally acquired these properties in 1990, retained a 25% working interest in these properties and has continued to serve as the operator. In addition, the Company entered into a joint acquisition agreement with Bakersfield Energy which gives each party the right through June 1997 to participate equally in any acquisition of oil and gas interests located within the state of California by the other party. Gas Plant. As part of the acquisition of the San Joaquin Basin properties, the Company purchased a modern, refrigeration liquid extraction facility with a rated inlet capacity of 23 MMcf of gas per day and a rated liquid fractionation capacity of 100,000 gallons of NGLs per day. Currently, the plant processes all of the gas produced from the Company's San Joaquin Basin properties as well as gas produced by third parties. The plant can deliver dry, residue gas into multiple pipeline systems allowing the Company to enter into contract and marketing arrangements that are not tied to the sometimes unfavorable and volatile California spot market. South Texas. In October 1992, the Company acquired an interest in nine gas fields located in South Texas for a total purchase price of approximately $5.3 million. Subsequent development activities have resulted in average daily production on the South Texas properties of 36 Bbls of crude oil and 4,068 Mcf of natural gas for the quarter ended March 31, 1996 and net proved reserves as estimated by Ryder Scott of 1.7 MMBOE at January 1, 1996. Approximately 51% of the Company's reserves in the South Texas properties is attributable to its interests in the Hostetter Field. The Company owns interests in 17 gross (four net) wells and owns approximately 2,525 gross (956 net) acres in the Hostetter Field. These wells are operated by Texaco Exploration and Production Company ("Texaco") and Cabot Oil and Gas Corporation ("Cabot"). The Company currently believes that there are opportunities for additional development and recompletion work in this field. Permian Basin (West Texas/New Mexico). Since 1989, the Company, in conjunction with Penroc Oil Corporation, has jointly identified and acquired interests in oil and gas properties located in the Permian Basin with total acquisition costs net to the Company of $3.4 million. Subsequent remedial work, development drilling activity and secondary recovery procedures have resulted in average daily production of 269 Bbls of crude oil and 416 Mcf of natural gas based on production in the quarter ended March 31, 1996. Ryder Scott's estimate of the Company's net proved reserves in the Permian Basin as of January 1, 1996 was 2.1 MMBOE. EXPLORATION ACTIVITIES Consistent with its core objective of increasing its reserves as economically as possible, the Company has commenced a program of identifying and developing exploratory prospects in areas where the Company or its partners have expertise. HarCor intends to manage its exploration and economic risks by (i) generating prospects with the assistance of strategic industry partners that are experienced in 3-D seismic and computer assisted exploration ("CAEX") technology, (ii) identifying and pursuing prospects with multiple potential productive zones, (iii) funding its exploration activities with proceeds from the Offering and internally generated cash flow and (iv) limiting its cash exposure to approximately $500,000 for each well. In addition, the Company intends to further manage the drilling risks associated with the exploration projects in South Texas and South Louisiana by drilling multipay prospects that combine shallower lower risk zones that have previously proven productive in the area with deeper potential target zones. In furtherance of this strategy, the Company has recently entered into an agreement with South Coast Exploration Company and its affiliated company Interactive Exploration Solutions, Inc. (collectively, "South Coast Exploration"), which have extensive experience utilizing 3-D seismic and CAEX techniques, to jointly pursue exploration projects on developed and undeveloped properties in South Texas, the Permian Basin of West Texas and South Louisiana. 5 6 The Company and South Coast Exploration have jointly formed an experienced geologic team (the "GeoTeam") to work exclusively to pursue these joint projects. The following table sets forth certain information as of May 30, 1996 relating to the exploration prospects that the Company currently plans to pursue over the 18-month period ending December 31, 1997, including the estimated cost to the Company for 3-D seismic surveys, leasehold acquisitions and drilling of exploratory and development wells relating to such prospects through such date.
GROSS ACREAGE OWNED OR PROSPECTIVE PROSPECTIVE ESTIMATED COST TO COMPANY(3) UNDER SQUARE MILES OF GROSS ------------------------------------- PROSPECT AREA OPTION(1) 3-D SEISMIC DATA WELLS(2) SEISMIC LAND DRILLING TOTAL ------------- ------------- ---------------- ----------- ------- ------ -------- ------- (IN THOUSANDS) South Texas (Upper Wilcox Trend)........ 23,000 83 18 $ 720 $ 640 $ 8,900 $10,260 West Texas (Permian Basin).............. 80,320 210 4 330 480 900 1,710 South Louisiana (Terrebonne Parish)..... 5,529 46 4 235 240 1,300 1,775 -- ------- --- ------ ------ ------- ------- Total........................... 108,849 339 26 $1,285 $1,360 $11,100 $13,745 ======= === == ====== ====== ======= =======
- --------------- (1) Includes acreage in which the Company currently has leases, options to acquire leases, contingent lease rights or fee interests. (2) Includes 10 exploratory wells and 16 development wells. (3) The estimated cost to the Company is based on (i) preliminary estimates of seismic survey costs, leasehold acquisition costs and drilling and completion costs and (ii) assumed levels of participation by the Company in the costs thereof. Actual costs and participation levels may vary from such estimates. The following sets forth a brief summary of each exploration prospect that the Company has in progress. This discussion only includes prospects on which the Company has acquired substantial leasehold interests, options to acquire leasehold interests or other contingent lease rights and has performed or is in the process of arranging related 3-D seismic surveys. See "Risk Factors -- Risk of Exploratory Drilling Activities" for a discussion of the risks associated with these exploration prospects. South Texas (Upper Wilcox Trend). HarCor has entered into an agreement with Cabot to participate in an 83 square mile 3-D seismic survey in southeast McMullen and northwest Duval Counties, Texas. The expanded and over-pressured Upper Wilcox Trend in the survey area has significant potential for the application of 3-D seismic technology due to complex faulting in the area and stacking of multiple pay zones in both the shallow normal-pressured zones such as the Cole Sand at 1,600 feet and the over-pressured zones such as the House Sand at approximately 12,000 feet. The 3-D seismic survey in the Upper Wilcox Trend commenced in April 1996 and is expected to be completed in July 1996. The survey is designed to evaluate prospects already identified and generate new drilling prospects with both development and exploration potential in the area of the Hostetter Field and the nearby Bonne Terre Field. The survey will evaluate approximately 40 geologic formations at depths ranging between 8,500 feet and 13,000 feet for the expanded over-pressured Upper Wilcox formation and as shallow as 1,500 feet for other intervals. HarCor has joined with Cabot to acquire, or to acquire options for, leasehold interests in 23,000 gross acres inside the 3-D survey area as of May 30, 1996. Production to date in the survey area, including production from the Hostetter Field and the Bonne Terre Field, is estimated to be approximately 450 Bcf of natural gas equivalent. On May 29, 1996, HarCor assigned to South Coast Exploration and one of its affiliates 40% of its rights in its agreement with Cabot in exchange for the interest it received in the South Louisiana project described below. West Texas (Permian Basin). In May 1996, the Company entered into an agreement to participate in a 210 square mile 3-D seismic survey in Reeves County, Texas with Penwell Energy, Inc. ("Penwell") which, along with its investment partner MCN Energy, has extensive recent experience in the Permian Basin. Penwell initially derived its rights to about half of the area in the Penwell survey (74,880 fee mineral acres held by Texaco) from an agreement dated September 1995 among Texaco, Penwell and Meridian Oil Inc. Production in the field within or adjoining gross acreage in which Penwell presently owns or has contingent lease rights is estimated to be 455 Bcf of natural gas equivalents, most of which has been produced from the 6 7 Silurian/Devonian Fusselman formation at depths between 10,000 feet and 17,000 feet, where the Company intends to focus. South Louisiana (Terrebonne Parish). South Coast Exploration and its affiliate have acquired an interest in a 46 square mile 3-D seismic survey to be conducted in south Terrebonne Parish, Louisiana. To date, the Lapeyrouse Field, which is located in the survey area, has produced approximately 350 Bcf of natural gas equivalents. Based upon 2-D seismic surveys and reports from independent engineers, South Coast Exploration's joint venture preliminarily has identified potential exploration sites in the area to drill an estimated four test wells in the next 18 months. Two of these potential exploration sites have been identified in the Bourg Sands between 14,500 feet and 15,500 feet and the remaining two potential exploration sites have been identified in traps associated with faulting in a series of Upper Middle Miocene Sands between 15,000 feet and 17,000 feet. South Coast Exploration and its affiliate have each assigned to HarCor a portion of their interest in this survey. SELECTIVE OPPORTUNISTIC ACQUISITIONS The Company also intends to pursue selective strategic acquisitions of attractively priced, underexploited onshore oil and gas properties in the United States. As a consequence of its working relationship with South Coast Exploration, the Company will also pursue property acquisitions where it can utilize 3-D seismic and CAEX technology to identify additional potential reserves. Management intends to continue to be active in developing acquisition opportunities rather than pursuing opportunities in the auction market. Management believes that this strategy has resulted in lower acquisition prices for its oil and gas properties. 7 8 THE OFFERING Shares of Common Stock Offered: By the Company(1)........................... 5,059,059 shares By the Selling Stockholders................. 1,340,941 shares Total............................... 6,400,000 shares Shares of Common Stock Outstanding(1)(2): Before the Offering......................... 8,696,207 shares After the Offering.......................... 13,755,266 shares Use of Proceeds............................... To redeem approximately $9.5 million of principal amount of, together with accrued interest and prepayment premium on, the Company's 14 7/8% Senior Notes due 2002; and to fund 3-D seismic and leasehold acquisitions, 3-D seismic and CAEX processing and interpretation, exploratory and development drilling expenditures and other general corporate purposes. Nasdaq National Market Symbol................. "HARC"
- --------------- (1) Does not include up to 960,000 shares of Common Stock which may be sold by the Company pursuant to the Underwriters' over-allotment option. (2) Does not include (i) options to purchase 898,500 shares of Common Stock which have been granted under the Company's stock option plans and (ii) 1,697,772 shares of Common Stock issuable upon conversion of the Company's outstanding Series A, B, C and E Preferred Stock. Also does not include 2,289,791 shares of Common Stock issuable upon exercise of outstanding warrants of the Company. See "Description of Capital Stock and Other Securities." 8 9 SUMMARY FINANCIAL DATA The following table presents summary historical consolidated financial data of the Company for the five years ended December 31, 1995, which have been derived from the Company's consolidated financial statements. The consolidated financial data of the Company for the three months ended March 31, 1995 and 1996 have been derived from the Company's interim consolidated financial statements which, in the opinion of management of the Company, have been prepared on the same basis as the annual consolidated financial statements and include all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of the financial data for such periods. The information in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and the notes thereto included elsewhere herein.
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ---------------------------------------------------- ------------------ 1991 1992 1993 1994 1995 1995 1996 ------- ------- ------- ------- ------- ------- ------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA(1): Revenues: Oil and gas revenues........................ $ 5,776 $ 6,162 $ 6,507 $10,982 $16,030 $ 3,683 $ 5,956 Gas plant revenues.......................... -- -- -- 1,978 6,362 1,786 1,624 Interest income and other................... 258 504 218 253 203 15 17 ------- ------- ------- ------- ------- ------- ------- Total revenues........................ 6,034 6,666 6,725 13,213 22,595 5,484 7,597 ------- ------- ------- ------- ------- ------- ------- Costs and expenses: Production costs............................ 2,670 2,676 2,249 3,610 5,263 1,263 1,437 Gas plant costs............................. -- -- -- 1,708 3,704 1,410 956 Dry hole, impairment and abandonment costs..................................... 1,287 402 41 75 4 -- -- Engineering and geological costs............ 770 536 188 254 307 89 101 Depletion, depreciation and amortization.... 2,222 2,142 2,641 3,897 5,973 1,346 1,707 General and administrative expenses......... 2,372 2,085 2,105 2,014 2,744 666 721 Interest expense(2)......................... 872 1,048 542 2,269 6,847 1,130 2,642 Other....................................... -- -- -- 203 483 -- 261 ------- ------- ------- ------- ------- ------- ------- Total costs and expenses.............. 10,193 8,889 7,766 14,030 25,325 5,904 7,825 ------- ------- ------- ------- ------- ------- ------- Loss before minority interests................ (4,159) (2,223) (1,041) (817) (2,730) (421) (228) Loss attributable to minority interests....... 2,698 809 -- -- -- -- -- Loss attributable to early extinguishment of debt........................................ -- -- -- (122) (1,888) -- -- ------- ------- ------- ------- ------- ------- ------- Net loss...................................... (1,461) (1,414) (1,041) (939) (4,618) (421) (228) Dividends on preferred stock.................. (40) (32) (246) (795) (1,000) (335) (132) Accretion on redeemable preferred stock....... -- -- -- (156) (2,147) (81) -- ------- ------- ------- ------- ------- ------- ------- Net loss applicable to common stock........... $(1,501) $(1,446) $(1,287) $(1,890) $(7,765) $ (837) $ (360) ======= ======= ======= ======= ======= ======= ======= Net loss applicable to common stock per common and common equivalent share................. $ (0.50) $ (0.41) $ (0.23) $ (0.29) $ (0.98) $ (0.12) $ (0.04) Weighted average number of common and common equivalent shares.................... 2,973 3,512 5,492 6,447 7,904 7,226 8,685 OTHER DATA: EBITDAX(3).................................... $ 992 $ 1,906 $ 2,371 $ 5,881 $10,884 $ 2,145 $ 4,483 Capital expenditures.......................... 2,593 4,237 4,283 45,608(4) 8,953 18 9,635(5)
MARCH 31, 1996 -------------------------- ACTUAL AS ADJUSTED(6) ------- -------------- (IN THOUSANDS) BALANCE SHEET DATA: Cash and cash equivalents.............................................................. $ 3,977 $ 14,319 Total assets........................................................................... 86,770 96,522 Total debt............................................................................. 71,276 61,993 Stockholders' equity................................................................... 9,564 28,774
9 10 (1) Includes results of operations in 1991 and 1992 from HCO Energy, Ltd. ("HCO"), the Company's former Canadian affiliate. In December 1992, the Company deconsolidated HCO, and in January 1993 the Company sold all of its remaining shares of HCO common stock. (2) Interest expense includes $29,000, $42,000, $64,000, $220,000 and $709,000 in 1991, 1992, 1993, 1994 and 1995, respectively, and $117,000 and $240,000 in the three months ended March 31, 1995 and 1996, respectively, related to amortization of deferred financing costs. (3) EBITDAX represents income (loss) before provision for income tax and extraordinary items and before depletion, depreciation, amortization, interest expense, minority interests, non-recurring charges and exploration expenses. EBITDAX is presented because it is a widely accepted financial indicator of a company's ability to service and/or incur indebtedness. However, EBITDAX should not be considered as an alternative to net income as a measure of operating results or to cash flows as a measure of liquidity. (4) Includes $42 million of cash acquisition costs incurred in connection with the acquisition of the San Joaquin Basin properties. (5) Includes $8.2 million relating to drilling costs which were accrued but unpaid at December 31, 1995 resulting from the Company's 1995 drilling program. (6) As adjusted to (i) reflect the public offering price of $4.50 per share and (ii) an extraordinary charge estimated at $1,826,000 relating to early extinguishment of debt. Does not include (i) options to purchase 898,500 shares of Common Stock which have been granted under the Company's stock option plans; (ii) 1,697,772 shares of Common Stock issuable upon conversion of the Company's outstanding Series A, B, C and E Preferred Stock; and (iii) 2,289,791 shares of Common Stock issuable upon exercise of outstanding warrants of the Company. See "Description of Capital Stock and Other Securities." The Company repaid $2 million of the outstanding balance under the Credit Facility subsequent to March 31, 1996 from cash flow generated by operations. Pending the use of proceeds from the Offering to fund certain exploration expenditures, the Company will use approximately $5.5 million to repay amounts outstanding under the Credit Facility. The Company will reborrow under the Credit Facility to fund capital expenditures and operations as necessary. See "Use of Proceeds." SUMMARY OIL AND GAS RESERVE DATA The following table sets forth summary information with respect to the Company's estimated proved oil and gas reserves. The estimates of the Company's proved reserves and future net revenues were primarily derived from reports prepared by Ryder Scott. As of December 31, 1993, 1994 and 1995, the average sales prices used for estimating the proved reserves and future net revenues were $11.65, $15.86 and $17.10 per Bbl of crude oil and $2.16, $2.11 and $2.35 per Mcf of natural gas, respectively (which prices with respect to natural gas reflect the effects of the Company's hedging activities). See "Risk Factors -- Reliance on Estimates of Proved Reserves," "-- Certain Business Risks" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." A summary report of Ryder Scott is included as Annex A hereto.
TOTAL PROVED RESERVES AS OF DECEMBER 31, -------------------------------- 1993 1994 1995 ------- ------- -------- (DOLLARS IN THOUSANDS) Estimated Proved Reserves: Liquids (MBbl)............................ -- 2,908 2,979 Crude oil (MBbl).......................... 1,724 10,581 12,358 Natural gas (MMcf)........................ 17,169 69,802 87,637 Crude oil equivalents (MBOE).............. 4,586 25,123 29,943 Pre-tax SEC 10 Value........................ $20,780 $86,680 $124,498 Percent Proved Undeveloped Reserves (BOE)... 39.8% 67.4% 69.4%
10 11 SUMMARY OPERATING DATA The following table sets forth summary information with respect to the Company's operations for the periods indicated.
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ------------------------ ---------------- 1993 1994 1995 1995 1996 ----- ----- ------ ------ ------ Average Net Daily Production: Crude oil and plant NGLs (Bbls)................. 505 1,128 1,834 1,657 2,450 Natural gas (Mcf)............................... 5,514 9,239 14,074 12,860 19,240 Crude oil equivalents (BOE)..................... 1,424 2,668 4,180 3,800 5,657 Average Sales Price(1): Crude oil (per Bbl)............................. $16.46 $15.79 $16.49 $16.15 $17.33 Natural gas (per Mcf)........................... $ 1.77 $ 1.82 $ 1.64 $ 1.62 $ 1.86 Cost Data (per BOE)(2): Average production costs(3)..................... $ 4.41 $ 4.13 $ 3.99 $ 4.14 $ 3.22 Depletion, depreciation and amortization........ $ 5.13 $ 4.14 $ 3.60(4) $ 4.26 $ 3.60 General and administrative expense.............. $ 4.13 $ 2.32 $ 1.80 $ 2.19 $ 1.61 Total Proved Reserves to Production Ratio......... 8.8 25.8 19.6 -- -- Crude Oil and NGLs as a Percentage of Total Proved Reserve Volumes................................. 37.6% 53.7% 51.2% -- -- Producing Wells (at end of period): Gross wells..................................... 334 379 424 379 431 Net wells....................................... 104 150 183 150 187
- --------------- (1) Calculation of average selling price per barrel of crude oil and condensate excludes certain revenues attributable to hydrocarbon liquids and plant product sales. All average price data reflect the effects of the Company's fixed-price sales and hedging contracts. See Note 10 of Notes to the Consolidated Financial Statements. (2) Excludes operating costs related to the gas plant. (3) Includes production and ad valorem taxes. (4) Excludes the effect of the impairment write-down pursuant to implementation of SFAS 121 ("Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"). See "Management's Discussion and Analysis of Financial Condition and Results of Operations." 11 12 RISK FACTORS Prospective investors should carefully consider the following factors regarding an investment in the Common Stock. LEVERAGE AND DEBT SERVICE As of March 31, 1996, after giving effect to the Offering and the application of a portion of the net proceeds thereof, the Company's total long-term debt and stockholders' equity would have been approximately $61 million and $31 million, respectively. As a result of the Company's indebtedness: (i) the Company incurs significant interest expense and principal repayment obligations in connection with its outstanding indebtedness; (ii) the Company's ability to obtain additional financing in the future, as needed, may be limited; (iii) the Company's leveraged position and the covenants contained in certain of its debt agreements could limit the Company's ability to expand and compete; and (iv) the Company's substantial leverage may make it more vulnerable to economic downturns, limit its ability to withstand competitive pressures and reduce its flexibility in responding to changing business and economic conditions. The Company's ability to pay interest and principal on its outstanding indebtedness and to satisfy its other debt obligations depends upon its future operating performance, which will be affected by prevailing economic conditions and financial, business and other factors, certain of which are beyond its control. The Company anticipates that its operating cash flow, together with borrowings available under its $15 million credit facility (the "Credit Facility") with ING Capital Corporation ("ING Capital"), will be sufficient to meet its operating needs and to service its debt requirements as they become due. However, if the Company is unable to service its indebtedness, it will be forced to pursue one or more alternative strategies such as selling assets, curtailing its development drilling activities, restructuring or refinancing its indebtedness or seeking additional equity capital. There can be no assurance that any of these strategies could be effected on satisfactory terms, if at all. See "Management's Discussion and Analysis of Results of Operations and Financial Condition -- Liquidity and Capital Resources." CAPITAL EXPENDITURES FOR UNDEVELOPED PROPERTIES As of December 31, 1995, approximately 69.4% of the Company's total proved reserves on a BOE basis were classified as proved undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Based on the Company's estimates, aggregate capital expenditures by the Company of approximately $58.7 million, including $55 million on the San Joaquin Basin properties, will be required to develop such undeveloped reserves, of which $12.1 million and $12 million are expected to be incurred during the remainder of 1996 and in 1997, respectively. The Company intends to finance the development of its properties out of the proceeds from the Offering and cash from operations and, to the extent necessary, borrowings under the Credit Facility. There can be no assurance that the Company's estimates of capital expenditures will prove accurate, that such sources of financing will be sufficient to fully fund the Company's planned development activities or that the development activities will be either successful or completed in accordance with the Company's development schedule. Additionally, any decrease in oil and gas prices or any increase in the costs of development of the Company's properties could result in a significant reduction in the number of wells expected to be drilled. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." RISK OF EXPLORATORY DRILLING ACTIVITIES The ability of the Company to add reserves in a cost-effective manner will be in part dependent upon the success of its exploratory drilling program, which will be funded in part with the proceeds from this Offering. Although the Company has significant experience in the development and production of oil and natural gas, the Company has a limited history of conducting exploratory drilling. In that regard, the ability of the Company to pursue its exploratory drilling program is dependent on a number of factors, including (i) favorable results of 3-D seismic surveys, (ii) the availability of leases on favorable terms and permitting for 12 13 the prospects, (iii) the availability of future capital resources by the Company and the other participants for the purchasing of leases and the drilling of prospects, (iv) the approval of other participants to the purchasing of leases and the drilling of wells on the prospects and (v) the economic conditions at the time of drilling, including the prevailing and anticipated prices for natural gas. Additionally, although the Company's prospects are located within geographic areas in which significant quantities of natural gas equivalents have been produced, the proximity to other successful exploratory or development wells provides no assurance that any particular well will be successful due to the complex faulting and fracturing of oil and gas formations and the inherent risks and uncertainties of exploratory drilling. Exploratory drilling is subject to numerous risks, including the risk that no commercially productive oil and natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected formation and drilling conditions, pressure or other irregularities in formations, equipment failures or accidents, as well as weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. In addition, the Company's strategy of focusing on exploratory drilling for larger reserves using 3-D seismic and CAEX technology requires greater pre-drilling expenditures than alternative forms of traditional drilling strategies. Although the Company believes that its use of 3-D seismic and CAEX technology 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 and there can be no assurance as to the future success of the Company's drilling program, especially in light of the Company's limited exploratory drilling experience. See "Business and Properties." HISTORY OF LOSSES For its fiscal years ended December 31, 1991, 1992, 1993, 1994 and 1995 and the three months ended March 31, 1996, the Company incurred operating losses (before dividends and accretion on preferred stock) of $1,461,000, $1,414,000, $1,041,000, $939,000, $4,618,000 and $228,000, respectively. There can be no assurance that the Company will be profitable in the future. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and Notes thereto. VOLATILITY OF OIL AND GAS PRICES AND MARKETS The Company's revenues and earnings are dependent upon prevailing prices for oil and gas. The prices for oil and gas historically have been volatile and are subject to wide fluctuations in response to changes in the supply of and demand for oil and gas, market uncertainties and a variety of additional factors beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulation, political conditions in the Middle East, the foreign supply of oil and gas, the price and availability of alternative fuels and overall oil and gas market conditions. It is impossible to predict future oil and gas price movements with any certainty. Although the Company hedges a substantial portion of its production which provides some protection from price declines, any substantial or extended decline in the price of oil and gas would have a material adverse effect on the Company's financial condition and results of operations, as well as reduce the amount of the Company's oil and gas that could be produced economically. The posted price for West Texas Intermediate crude oil (the "WTI price") varied during 1995 from a high of $19.00 per Bbl in April 1995, to a low of $15.00 per Bbl in July 1995. The price for 40() gravity crude oil in the Lost Hills Field (the location of most of the Company's San Joaquin Basin properties) as stated in the Chevron U.S.A. Products Company Crude Oil Price Bulletin varied during 1995 from a high of $18.10 per Bbl in April 1995 to a low of $15.85 per Bbl in October 1995. Market prices received for crude oil sold in California have in the recent past been generally lower than WTI prices for similar quality oil as a result of certain market and regulatory conditions particular to the California market, including (i) a foreign export ban on Alaskan oil which results in the supply of most of such oil to the California market, (ii) the lack of pipelines to transport large quantities of oil produced in California to other states which limits the ability of producers to respond to price imbalances between California and other domestic markets and (iii) fewer independent refiners in California than in other oil producing states which results in less competition among 13 14 crude oil purchasers in California than in other domestic markets. The posted price for gas at Henry Hub, Louisiana ("Henry Hub price") varied during 1995 from a high of $2.28 per MMBtu in December 1995 to a low of $1.38 per MMBtu in August 1995. The Southern California border monthly average price for natural gas as stated in the Natural Gas Intelligence Gas Price Index varied during 1995 from a high of $1.63 per MMBtu in January 1995 to a low of $1.25 per MMBtu in July 1995. Market prices received for gas sold in the California market during 1996 have been generally similar to Henry Hub prices. Due to fairly stable demand as a result of stable weather conditions in California, gas prices in California do not generally experience fluctuations during the winter and summer months as large as those experienced by Henry Hub prices. Declines in oil and gas prices, if sustained, could require a writedown of the book value of the Company's oil and gas properties unless the Company has sufficient net additions in reserves and/or production to offset the decline in oil and gas prices. Such declines, if sustained, could also result in a reduction in the Company's borrowing base under its Credit Facility, requiring the Company to repay the amount by which outstanding advances exceed the redetermined borrowing base. RISKS OF FIXED PRICE SALES AND HEDGING CONTRACTS The Company manages the risk associated with fluctuations in the price of gas, and to a lesser extent oil, primarily through certain fixed price sales and hedging contracts. The Company's price risk management strategy reduces the Company's sensitivity to changes in market prices of oil and gas, but is subject to a number of other 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, the Company would be required to satisfy its obligations under fixed price sales and hedging contracts on potentially unfavorable terms without the ability to hedge such risk through sales of comparable quantities of its own production. Further, the terms under which the Company enters into fixed price sale and hedging contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation costs to delivery points. Substantial variations between the assumptions and estimates used by the Company and actual results experienced could materially adversely affect the Company's anticipated profit margins and its ability to manage in the future the risk associated with fluctuations in oil and gas prices. Additionally, the fixed price sales and hedging contracts limit the benefits the Company will realize if actual prices rise above the contract prices. In addition, fixed price sales and hedging contracts are subject to the risk that the counterparty may prove unable or unwilling to perform its obligations under such contracts. Currently, an affiliate of ING Capital is the counterparty for a significant portion of the Company's hedging contracts. Although the Company has not experienced and does not anticipate significant nonperformance by counterparties, such significant nonperformance could have a material adverse financial effect on the Company. As of March 31, 1996, the Company had approximately 45% of its oil production and approximately 42% of its gas production committed to sales and hedging contracts based on first quarter 1996 production. RELIANCE ON ESTIMATES OF PROVED RESERVES There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the control of the Company. Certain events, including changes in oil and gas prices, production, acquisitions and future drilling and development, could result in increases or decreases in estimated proved quantities of oil and gas reserves. In addition, estimates of the Company's quantities of proved oil and gas reserves, future net revenues from proved reserves and the present value thereof are based on certain assumptions regarding future oil and gas prices, production levels and operating and development costs that may not prove to be correct. In particular, estimates of proved oil and gas reserves, future net revenues from proved reserves and the present value thereof for the Company's oil and gas properties as of December 31, 1995 included in this Prospectus are based on the assumption that future oil and gas prices remain the same as oil and gas prices at December 31, 1995. As of December 31, 1995, the average sales prices used for purposes of such estimates were $17.21 per Bbl of oil and $2.35 per Mcf of gas with respect to the San Joaquin Basin properties and $17.69 per Bbl of oil and $1.91 per Mcf of gas with respect to the 14 15 Company's other properties in the aggregate. Average oil prices with respect to the San Joaquin Basin properties and the Company's other properties were, for the year ended December 31, 1995, lower than oil prices at December 31, 1995, with average oil prices realized by the Company of $16.85 per Bbl and $15.78 per Bbl, respectively. Average gas prices for the San Joaquin Basin properties and the Company's other properties were, for the year ended December 31, 1995, lower than those received at year-end 1995, with average gas prices realized by the Company of $1.74 per Mcf and $1.46 per Mcf, respectively. Also assumed is the Company's planned expenditures of approximately $60.7 million in future capital expenditures, including $55 million on the San Joaquin Basin properties, necessary to develop and realize the value of its proved undeveloped reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth herein. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." DEPENDENCE ON LOCAL OPERATORS None of the Company's oil and gas properties are operated by the Company. As a result, the Company has limited control over the manner in which operations are conducted on such properties, including the safety and environmental standards used in connection therewith. Pursuant to the operating agreements governing operations on the properties in which the Company has an interest, the Company maintains significant influence or control over the nature and timing of exploration and development activities on the majority of its properties. Such agreements do not, however, allow the Company such influence or control with respect to a portion of its properties; in such cases, the operators of such properties generally have control with respect to the nature and timing of exploration or development activities. In such instances, the operators of such properties could undertake exploration or development projects at a time when the Company does not have the funds required to finance its share of the costs of such projects. In such event, pursuant to the operating agreements relating to properties in which the Company has an interest, the other parties to such agreements who fund their shares of the cost of such a project are generally entitled to receive all cash flow from such project, subject to rights of third party royalty or other interest owners, until they have recovered a multiple of the costs of such project (usually 300% to 400%) prior to the Company's receipt of any production or revenues from such project or, in the event drilling is necessary to maintain certain leasehold interests, the Company may be required to forfeit its interests in such projects. Conversely, the operators of such properties could refuse to initiate exploration or development projects, in which case the Company would be required to propose such activities and may be required to proceed with such activities at much higher levels of participation than expected and without receiving any funding from the other interest owners or the operators may initiate exploration or development projects on a slower schedule than that preferred by the Company. Any of these events could have a significant effect on the Company's anticipated exploration and development activities and financing thereof. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." OPERATING HAZARDS AND UNINSURED RISKS The Company's operations are subject to risks inherent in the oil and gas industry, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. These risks could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. In accordance with customary industry practice, the Company is not fully insured against all risks incident to its business. Because of the nature of industry hazards, it is possible that liabilities for pollution and other damages arising from a major occurrence could exceed insurance coverage or policy limits. Any such liabilities could have a materially adverse effect on the Company. CERTAIN BUSINESS RISKS The Company intends to continue acquiring oil and gas properties. Although the Company performs a review of the properties to be acquired that it believes is consistent with industry practices, such reviews are inherently incomplete. Generally, it is not feasible to review in-depth every individual property involved in 15 16 each acquisition. Ordinarily, the Company will focus its review efforts on the higher-valued properties and will sample the remainder. However, even an in-depth review of all properties and records may not necessarily reveal existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Furthermore, the Company must rely on information, including financial, operating and geological information, provided by the seller of the properties without being able to verify fully all such information and without the benefit of knowing the history of operations of all such properties. In addition, a high degree of risk of loss of invested capital exists in almost all exploration and development activities which the Company undertakes. No assurance can be given that oil or gas will be discovered to replace reserves currently being developed, produced and sold, or that if oil or gas reserves are found, they will be of a sufficient quantity to enable the Company to recover the substantial sums of money incurred in their acquisition, discovery and development. Drilling activities are subject to numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain. The Company's operations may be curtailed, delayed or cancelled as a result of numerous factors including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. The availability of a ready market for the Company's gas production depends on a number of factors, including, without limitation, the demand for and supply of natural gas, the proximity of gas reserves to pipelines, the capacity of such pipelines and government regulations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and "Business and Properties." DEPENDENCE ON KEY PERSONNEL The success of the Company will depend almost entirely upon the ability of a small group of key executives to manage the business of the Company. Should one or more of these executives leave the Company or become unable to perform his duties, no assurance can be given that the Company will be able to attract competent new management. The Company maintains a $10 million key man life insurance policy on Mark G. Harrington, the proceeds of which are payable to the Company. COMPETITION The acquisition, exploration and development of oil and gas properties is a highly competitive business. Many companies and individuals are engaged in the business of acquiring interests in and developing onshore oil and gas properties in the United States. The industry is not dominated by any single competitor or a small number of competitors. The Company competes with major and independent oil and gas companies for the acquisition of desirable oil and gas properties, as well as for the equipment and labor required to operate and develop such properties. Many of these competitors have financial and other resources substantially in excess of those available to the Company. Such competitive disadvantages could adversely affect the Company's ability to acquire desirable properties or to develop existing properties. GOVERNMENTAL REGULATION The Company's business is subject to certain federal, state and local laws and regulations relating to the exploration for and development and production of oil and gas, as well as environmental and safety matters. Such laws and regulations have generally become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Because the requirements imposed by such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance with such requirements and their effect on the Company. See "Business and Properties -- Regulation." 16 17 USE OF PROCEEDS The net proceeds to the Company from the sale of the shares of Common Stock offered hereby, after deducting underwriters' discounts and commissions and estimated expenses of the Offering, are estimated to be approximately $21 million ($25 million if the Underwriters' over-allotment option is exercised in full). The purpose of the Offering is to further strengthen the Company's financial position and to provide it with the financial flexibility necessary to implement its business strategy. The Company is obligated and intends to use 50% of the net proceeds (estimated to be approximately $10.6 million to redeem $9.5 million in principal amount of its outstanding $65 million of senior notes due 2002 (the "Senior Notes") at a price equal to 110% of the principal amount of such Senior Notes plus accrued and unpaid interest thereon (estimated to be approximately $400,000). The Senior Notes mature on July 15, 2002 and bear interest at the rate of 14 7/8% per annum. The resulting reduction in interest costs should permit the Company to devote an increased portion of its cash flow to efforts to expand its reserve base. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Financing Activities." The balance of the proceeds from the Offering (estimated to be approximately $10.4 million), the Company's cash flow from operations and borrowings from available capacity under the Credit Facility will be used to finance the Company's anticipated capital expenditures to implement its exploration and development program in South Texas, West Texas and South Louisiana, utilizing advanced 3-D seismic and CAEX technology, for the remainder of 1996 and in 1997. Based on current plans, the Company expects to make capital expenditures with respect to its exploratory prospects of approximately $14.3 million during the next 18 months, of which approximately $3.2 million is expected to be spent during the second half of 1996, and approximately $11.1 million is expected to be spent during 1997. See "Business and Properties" and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Prior to funding its exploration program, the Company will use approximately $5.5 million to repay amounts outstanding under the Credit Facility. Such repayment will not affect the borrowing availability of the Company under the Credit Facility. The Company anticipates that it will reborrow under the Credit Facility to finance a portion of its exploration and development program. Amounts outstanding under the Credit Facility bear interest at an adjusted Eurodollar rate plus 2.5%. The effective interest rate under the Credit Facility at March 31, 1996 was 8.125%. Unless otherwise renewed by mutual agreement, amounts outstanding under the Credit Facility will convert to a term loan on September 30, 1997, with a set amortization schedule of a percentage of the outstanding principal continuing through December 31, 2000. The Company currently estimates that the net proceeds to the Company from the Offering will be at least $20.8 million. Pursuant to the terms of the Series E Preferred Stock, if the holder of the Series E Preferred Stock does not otherwise convert all of the 30,000 shares of Series E Preferred Stock outstanding at $3.50 per share into 857,143 shares of Common Stock, the Series E Preferred Stock is required to be redeemed by the Company in cash, at a price of $110 per share plus accrued and unpaid dividends. The aggregate amount necessary to redeem all of the 30,000 shares of Series E Preferred Stock outstanding is $3.3 million. Any amount used to redeem the Series E Preferred Stock will reduce (i) the amount of the net proceeds available from the Offering to finance the Company's anticipated capital expenditures to implement its exploration and development program described above and (ii) the amount that will be used to temporarily repay amounts outstanding under the Credit Facility. The Company has not been advised by the holder of the Series E Preferred Stock whether or not it intends to convert all of its shares of the Series E Preferred Stock at $3.50 per share into 857,143 shares of Common Stock prior to the mandatory redemption of the Series E Preferred Stock. See "Description of Capital Stock and Other Securities." 17 18 CAPITALIZATION The following table sets forth the total consolidated capitalization of the Company at March 31, 1996, and as adjusted (i) to give effect to the consummation of the Offering (including the issuance and sale of 5,059,059 shares of Common Stock by the Company at the offering price of $4.50 per share and (ii) the application of the estimated net proceeds to the Company therefrom, as described under "Use of Proceeds." This table should be read in conjunction with the consolidated financial statements of the Company and the related notes and other financial information included elsewhere in this Prospectus.
MARCH 31, 1996 ------------------------ ACTUAL AS ADJUSTED -------- ----------- (IN THOUSANDS) Cash and cash equivalents..................................... $ 3,977 $ 14,319 ======== ========= Total debt, including current maturities: Credit Facility(1).......................................... 7,500 7,500 14 7/8% Senior Secured Notes due 2002....................... 63,180 53,897 Other....................................................... 596 596 -------- ----------- Total debt.......................................... 71,276 61,993 -------- ----------- Stockholders' equity: Preferred stock, $.01 par value -- 1,500,000 shares authorized; 65,000 shares outstanding (35,000 shares outstanding as adjusted)............................................. 1 1 Common Stock, $.10 par value -- 25,000,000 shares authorized; 8,696,207 shares outstanding(2); 13,755,266 shares outstanding as adjusted(2).................................. 870 1,376 Additional paid-in capital.................................... 28,734 49,264 Accumulated deficit(3)........................................ (20,041) (21,866) -------- ----------- Total stockholders' equity.......................... 9,564 28,774 -------- ----------- Total capitalization................................ $ 80,840 $ 90,770 ======== =========
- --------------- (1) The Company repaid $2 million of the outstanding balance under the Credit Facility subsequent to March 31, 1996 from cash flow generated by operations. Pending the use of proceeds from the Offering, to fund certain exploration expenditures the Company will use approximately $5.5 million to repay amounts outstanding under the Credit Facility. The Company will reborrow under the Credit Facility to fund capital expenditures and operations as necessary. See "Use of Proceeds." (2) Does not include (i) options to purchase 898,500 shares of Common Stock which have been granted under the Company's stock option plans; (ii) 1,697,772 shares of Common Stock issuable upon conversion of the Company's outstanding Series A, B, C and E Preferred Stock; and (iii) 2,289,791 shares of Common Stock issuable upon exercise of outstanding warrants of the Company. See "Description of Capital Stock and Other Securities." (3) As adjusted includes an extraordinary charge estimated at $1,826,000 relating to early extinguishment of debt. 18 19 PRICE RANGE OF COMMON STOCK The Common Stock trades on the Nasdaq National Market ("NASDAQ") under the symbol "HARC." Quotations of the sales volume and the closing sales prices of the Common Stock are listed daily in NASDAQ's national market listings. The following table sets forth the range of high and low sale prices of the Common Stock as quoted by NASDAQ's monthly statistical report for the periods indicated.
HIGH LOW ----- ----- 1996 Third Quarter (through July 25, 1996).............................. $6.25 $4.38 Second Quarter..................................................... $5.13 $4.06 First Quarter...................................................... $5.38 $2.31 1995 Fourth Quarter..................................................... $3.38 $1.88 Third Quarter...................................................... $3.50 $2.50 Second Quarter..................................................... $4.38 $2.75 First Quarter...................................................... $4.38 $2.88 1994 Fourth Quarter..................................................... $4.25 $2.75 Third Quarter...................................................... $4.25 $3.00 Second Quarter..................................................... $4.13 $3.25 First Quarter...................................................... $4.13 $3.13
On July 25, 1996, the closing sale price for the Common Stock as reported by NASDAQ was $5.00 per share. As of April 23, 1996, the Company had approximately 1,746 stockholders of record. None of the Company's warrants or preferred stock trade on any public trading market. DIVIDEND POLICY The Company has never paid and does not currently intend to pay dividends on its Common Stock, and pursuant to the terms of the Company's Credit Facility and the Senior Notes, it is currently restricted from the payment of dividends on its Common Stock (except dividends paid in shares of Common Stock). Additionally, pursuant to the terms of the Company's outstanding preferred stock, the Company is restricted from the payment of dividends on its Common Stock (except dividends paid in shares of Common Stock) unless the Company is current in its payment of dividends on such preferred stock. 19 20 DILUTION The net tangible book value of the Common Stock at March 31, 1996 was $9.564 million or $1.10 per share. The net tangible book value per share represents the amount of the Company's total tangible assets less the Company's total liabilities (excluding deferred tax liabilities) divided by the number of shares of Common Stock outstanding. After giving effect to the sale of the shares of Common Stock offered by the Company (at the public offering price of $4.50 per share and after deducting estimated underwriters' discounts and offering expenses of approximately $1.73 million), at March 31, 1996 the pro forma net tangible book value of the Common Stock would have been $28.8 million or $2.09 per share, representing an immediate decrease in net tangible book value of $2.41 per share to new stockholders. Dilution in net tangible book value represents the difference between the price per share to be paid by purchasers of the shares of Common Stock offered in this Offering and the pro forma net tangible book value as of March 31, 1996, as illustrated by the following per share amounts. Assumed public offering price...................................... $ 4.50 Net tangible book value at March 31, 1996........................ 1.10 Increase attributable to new stockholders........................ .99 Adjusted net tangible book value after Offering, before debt repayment........................................................ 2.09 Dilution to new stockholders....................................... 2.41
The foregoing information excludes (i) 898,500 shares of Common Stock issuable pursuant to stock options that have been granted under the Company's stock option plans; (ii) an additional 656,500 shares of Common Stock, which may be granted in the future under such plans; (iii) 1,697,772 shares of Common Stock issuable upon conversion of outstanding preferred stock; (iv) 2,289,791 shares of Common Stock issuable upon exercise of outstanding warrants of the Company; and (v) the use of proceeds from the Offering. See "Shares Eligible for Future Sale." 20 21 SELECTED FINANCIAL DATA The historical financial data presented below for the five years ended December 31, 1995 are derived from the Company's audited financial statements. Such audited financial statements were examined by Arthur Andersen LLP, with the exception of the 1991 and 1992 financial data with respect to HCO Energy, Ltd., the Company's former Canadian affiliate, which were examined by Peat Marwick Thorne. The historical data for the three-month periods ended March 31, 1995 and 1996 are derived from the unaudited financial statements of the Company. In the opinion of management, such unaudited financial statements include all adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation of the financial data for such periods. The information in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and the notes thereto included elsewhere herein.
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ---------------------------------------------------- ------------------ 1991 1992 1993 1994 1995 1995 1996 ------- ------- ------- ------- ------- ------- ------- (IN THOUSANDS, EXCEPT PER SHARE DATA) STATEMENT OF OPERATIONS DATA(1): Revenues: Oil and gas revenues............................... $ 5,776 $ 6,162 $ 6,507 $10,982 $16,030 $ 3,683 $ 5,956 Gas plant revenues................................. -- -- -- 1,978 6,362 1,786 1,624 Interest income and other.......................... 258 504 218 253 203 15 17 ------- ------- ------- ------- ------- ------- ------- Total revenues............................... 6,034 6,666 6,725 13,213 22,595 5,484 7,597 ------- ------- ------- ------- ------- ------- ------- Costs and expenses: Production costs................................... 2,670 2,676 2,249 3,610 5,263 1,263 1,437 Gas plant costs.................................... -- -- -- 1,708 3,704 1,410 956 Dry hole, impairment and abandonment costs......... 1,287 402 41 75 4 -- -- Engineering and geological costs................... 770 536 188 254 307 89 101 Depletion, depreciation and amortization........... 2,222 2,142 2,641 3,897 5,973 1,346 1,707 General and administrative expenses................ 2,372 2,085 2,105 2,014 2,744 666 721 Interest expense(2)................................ 872 1,048 542 2,269 6,847 1,130 2,642 Other.............................................. -- -- -- 203 483 -- 261 ------- ------- ------- ------- ------- ------- ------- Total costs and expenses..................... 10,193 8,889 7,766 14,030 25,325 5,904 7,825 ------- ------- ------- ------- ------- ------- ------- Loss before minority interests....................... (4,159) (2,223) (1,041) (817) (2,730) (421) (228) Loss attributable to minority interests.............. 2,698 809 -- -- -- -- -- Loss attributable to early extinguishment of debt.... -- -- -- (122) (1,888) -- -- ------- ------- ------- ------- ------- ------- ------- Net loss............................................. (1,461) (1,414) (1,041) (939) (4,618) (421) (228) Dividends on preferred stock......................... (40) (32) (246) (795) (1,000) (335) (132) Accretion on redeemable preferred stock.............. -- -- -- (156) (2,147) (81) -- ------- ------- ------- ------- ------- ------- ------- Net loss applicable to common stock.................. $(1,501) $(1,446) $(1,287) $(1,890) $(7,765) $ (837) $ (360) ======= ======= ======= ======= ======= ======= ======= Net loss applicable to common stock per common and common equivalent share............................ $ (0.50) $ (0.41) $ (0.23) $ (0.29) $ (0.98) $ (0.12) $ (0.04) Weighted average number of common and common equivalent shares........................... 2,973 3,512 5,492 6,447 7,904 7,226 8,685 OTHER DATA: EBITDAX(3)........................................... $ 992 $ 1,906 $ 2,371 $ 5,881 $10,884 $ 2,145 $ 4,483 Capital expenditures................................. 2,593 4,237 4,283 45,608(4) 8,953 18 9,635(5) BALANCE SHEET DATA (END OF PERIOD): Cash and cash equivalents.......................... $ 389 $ 929 $ 2,162 $ 899 $12,204 $ 1,653 $ 3,977 Total assets....................................... 15,586 12,580 17,937 68,573 94,231 67,150 86,770 Total debt......................................... 10,427 7,100 8,541 39,400 69,087 39,400 71,276 Stockholders' equity............................... 1,798 4,645 7,536 15,353 10,215 14,748 9,564
- --------------- (1) Includes results of operations in 1991 and 1992 from the Company's Canadian operations. In December 1992, the Company deconsolidated HCO, and in January 1993, the Company sold all of its remaining shares of HCO common stock. (2) Interest expense includes $29,000, $42,000, $64,000, $220,000 and $709,000 in 1991, 1992, 1993, 1994 and 1995, respectively, and $117,000 and $240,000 in the three months ended March 31, 1995 and 1996, respectively, related to amortization of deferred financing costs. (3) EBITDAX represents income (loss) before provision for income tax and extraordinary items and before depletion, depreciation, amortization, interest expense, minority interests, non-recurring charges and exploration expenses. EBITDAX is presented because it is a widely accepted financial indicator of a company's ability to service and/or incur indebtedness. However, EBITDAX should not be considered as an alternative to net income as a measure of operating results or to cash flows as a measure of liquidity. (4) Includes $42 million of cash acquisition costs incurred in connection with the acquisition of the San Joaquin Basin properties. (5) Includes $8.2 million relating to drilling costs which were accrued but unpaid at December 31, 1995 resulting from the Company's 1995 drilling program. 21 22 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Since acquiring control of HarCor in 1987, management has grown the Company significantly, increasing its reserve base from 1.35 MMBOE at January 1, 1990 to 29.9 MMBOE at January 1, 1996, primarily through selective acquisitions of oil and gas properties. Historically, the Company has financed its growth predominantly with debt and preferred stock, which generally require regular principal and interest payments or dividend payments, as the case may be. As a result of the cash requirements of the debt and preferred stock, the Company's early acquisition strategy focused on proved producing properties which would provide relatively stable cash flow, while at the same time providing exploitation potential beyond the estimated proved reserves. In June 1994, the Company acquired 75% of Bakersfield Energy's interests in the Lost Hills Field and a 23 MMcf per day gas processing plant in the San Joaquin Basin of California for approximately $46 million, consisting of $42 million in cash and a combination of preferred stock, common stock and warrants. To finance the cash portion of the purchase price, the Company increased its borrowings under its existing credit facility and issued a combination of preferred stock, common stock and warrants. To further improve its liquidity and ability to develop its San Joaquin Basin properties, in July 1995 the Company consummated the sale of 65,000 units consisting of $65 million aggregate principal amount of its 14 7/8% Senior Notes due in the year 2002 and warrants to purchase 1,430,000 shares of common stock. The Company used the net proceeds of approximately $61 million to repay an aggregate of $39.3 million outstanding under its credit agreement and bridge loan with ING Capital; redeem $10.9 million in outstanding shares of Series D Preferred Stock which were issued in connection with the acquisition of the San Joaquin Basin properties and acquire interests in additional producing wells in the San Joaquin Basin properties for $2.3 million. The Company used the balance of the proceeds to finance a portion of the development of the San Joaquin Basin properties over the remainder of 1995. In order to protect against the effects of declines in oil and gas prices and maintain predictable cash flow to service its outstanding debt, the Company generally enters into either fixed-price sales or hedging contracts covering significant portions of the Company's estimated future production. The Company believes that its hedging strategy has allowed it to grow more rapidly by providing more predictable cash flows with which to finance its acquisitions and development drilling activities. As of March 31, 1996, the Company was a party to various gas contracts covering volumes of approximately 1.8 Bcf and 1.2 Bcf for 1996 and 1997, respectively, at prices ranging from $1.68/MMBtu to $2.07/MMBtu; a gas contract covering 2.2 Bcf for 1996 and 2.2 Bcf for 1997 which fixes volumes to be sold at $0.3675 less than the NYMEX gas future price for each month; and oil hedges covering notional volumes of approximately 243 MBOE and 98 MBOE for 1996 and 1997, respectively, at prices ranging from $15.80/Bbl to $18.75/Bbl. As of March 31, 1996 the Company had approximately 45% of its oil production and approximately 42% of its gas production committed to sales and hedging contracts based on first quarter 1996 production. COMPARISON OF RESULTS FOR THE THREE MONTHS ENDED MARCH 31, 1996 AND 1995 Revenues. The Company's total revenues increased $2,113,000 (39%) from $5,484,000 in the first quarter of 1995 to $7,597,000 in the first quarter of 1996. The Company's oil and gas revenues increased $2,273,000 (62%) from $3,683,000 in the first three months of 1995 to $5,956,000 in the same period in 1996. Oil revenues increased $940,000 (52%) from $1,801,000 in the first quarter of 1995 to $2,741,000 in the same period in 1996 due to higher oil production and slightly higher prices. Oil production increased 46,700 barrels (42%) from 111,500 barrels in the first three months of 1995 to 158,200 barrels in the same period in 1996. The increased production was primarily a result of the continued drilling and development of the San Joaquin Basin properties, which contributed an incremental 48,600 barrels during the first quarter of 1996 as compared to the first quarter of 1995. Oil production from the Company's Permian and other properties declined slightly (1,900 barrels) in the 22 23 aggregate due to normal production declines. The average price received for oil was $17.33 per barrel during the first quarter of 1996 compared to $16.15 per barrel for the same period in 1995. The Company's gas revenues increased $1,332,000 (71%) from $1,883,000 in the first three months of 1995 to $3,215,000 in the same period in 1996 also due to increased production and higher prices. Gas production increased 574,000 Mcf (50%) from 1,157,000 Mcf in the first quarter of 1995 to 1,731,000 Mcf in the first quarter of 1996 primarily due to the continued drilling and development of the San Joaquin Basin properties, which contributed an incremental 523,000 Mcf during the first quarter of 1996 as compared to the first quarter of 1995. Gas production from the Company's South Texas properties increased 50,000 Mcf during the first quarter of 1996 primarily due to the drilling of an additional development well, while gas production from the Company's Permian and other properties remained flat from period to period. Average prices received for gas were $1.86 per Mcf in the first quarter of 1996 as compared to $1.62 per Mcf in the first three months of 1995. During the first quarter of 1996, the Company realized revenues of $1,624,000 from its natural gas processing plant. These revenues consisted of $1,131,000 from the sale of 2,615,000 gallons of processed natural gas liquids (NGLs), $468,000 from the resale of natural gas purchased from third parties, and $25,000 in gas processing fees. During the first quarter of 1995, the Company realized revenues of $1,785,000 from the natural gas plant, consisting of $1,139,000 in the resale of natural gas purchased from third parties, $622,000 from the sale of 1,561,000 gallons of NGLs, and $24,000 in gas processing fees. Although total gas plant revenues decreased slightly in the first quarter of 1996, the plant's net operating margin increased $293,000 (78%) due to an increase in NGLs sales as a result of higher lease production. The Company realized total interest and other income of approximately $17,000 in the first quarter of 1996 as compared to $15,000 during the first three months of 1995. Costs and Expenses. Total costs and expenses increased $1,920,000 (32%) from $5,904,000 in the first quarter of 1995 to $7,824,000 in the first quarter of 1996. The Company's production costs increased $174,000 (14%) from $1,263,000 in the first three months of 1995 to $1,437,000 in the first quarter of 1996. This was primarily due to the continuing development of the San Joaquin Basin properties and resulting increase in number of producing wells in that area. Production costs on the Company's South Texas and Permian properties decreased slightly in the first quarter of 1996. Average production cost decreased to $3.22 per BOE in the first quarter of 1996 as compared to $4.14 per BOE in the first quarter of 1995. During the first quarter of 1996, the Company incurred costs of $956,000 resulting from the operations of its natural gas processing plant. These costs included $359,000 from the purchase of natural gas for processing and resale and $597,000 of direct operating expenses. During the first quarter of 1995, the Company incurred costs of $1,410,000 in the operations of its natural gas processing plant, consisting of $958,000 from the purchase of natural gas for processing and resale and $452,000 of direct operating expenses. This represents a decrease of $454,000 (32%) in plant costs during the first quarter of 1996. The Company incurred engineering and geological expenses of $101,000 and $89,000 during the three months ended March 31, 1996 and 1995, respectively. The Company's depletion, depreciation, amortization and impairment expense ("DD&A") increased $360,000 (27%) from $1,346,000 in the first quarter of 1995 to $1,706,000 in the first quarter of 1996 as a result of increases in depreciable oil and gas assets due to costs incurred in the continued development of the San Joaquin Basin properties. The DD&A rate per BOE for oil and gas reserves was $3.60 per BOE in the first quarter of 1996 as compared to $4.14 during the first quarter of 1995. The Company's general and administrative expenses increased slightly in the first quarter of 1996 ($55,000 or 8%) due to the Company's continued growth and expansion. The Company's interest expense increased $1,513,000 from $1,130,000 in the first quarter of 1995 to $2,643,000 in the first quarter of 1996. This was due to the refinancing of the Company's bank debt and the Series D Preferred Stock with $65,000,000 in 14 7/8% Senior Secured Notes in July 1995. Also affecting interest 23 24 expense in the first quarter of 1996 was an increase in amortization of deferred financing costs resulting from the Senior Note and related warrant offering. Total dividends on preferred stock were $132,500 in the first three months of 1996, as compared to $335,000 in the first quarter of 1995. First quarter 1996 dividends consisted of cash, while first quarter 1995 dividends consisted of $70,000 in cash, $235,000 in Series D Preferred Stock and $30,000 in Common Stock of the Company. The Company also incurred a non-cash charge of $81,000 attributable to accretion on its Series D Preferred Stock in 1995. The Series D Preferred Stock was redeemed in July 1995. Non-Recurring Charge. During the first quarter of 1996 the Company incurred a non-cash write-off of $261,000, representing the remaining portion of a long-term investment made in a gas marketing company which recently declared bankruptcy. Net Loss. The Company's net operating loss for the first quarter of 1996 was $228,000 while net loss attributable to common stockholders was $360,000 ($.04 per share) after preferred dividends. In the first quarter of 1995, the Company had a net operating loss of $421,000 and net loss to common shareholders of $837,000 ($.12 per share) after preferred dividends and accretion. COMPARISON OF RESULTS OF 1995 TO 1994 Acquisition of San Joaquin Basin Properties. Included in results of operations for 1995 are twelve months of operations from the San Joaquin Basin properties, as compared to six months of operations in the comparable period of 1994. The San Joaquin Basin properties were acquired on June 30, 1994. (See Note 4 of Notes to Consolidated Financial Statements included elsewhere is this Prospectus.) Revenues. The Company's total revenues increased $9,382,000 (71%) from $13,213,000 in 1994 to $22,595,000 in 1995. The Company's total oil and gas revenues increased $5,048,000 (46%) from $10,982,000 in 1994 to $16,030,000 in 1995. Oil revenues increased $2,688,000 (54%) due primarily to an increase in oil production volumes of 151,000 barrels (48%), from 312,000 barrels in 1994 to 463,000 barrels in 1995. The increased production was a result of the acquisition of the San Joaquin Basin properties, which produced 304,200 barrels of oil in 1995 as compared to 131,400 barrels in 1994 (six months). Oil production from the Company's other properties decreased 30,000 barrels (16%) in the aggregate due to normal production declines. The average price received for oil was $16.49 per barrel during 1995 compared to $15.79 per barrel in 1994. The Company's gas revenues increased $2,360,000 (39%) in 1995 in spite of lower gas prices due to increased production. Gas production increased 1,811,000 Mcf (54%) from 3,326,000 Mcf in 1994 to 5,137,000 Mcf in 1995. The San Joaquin Basin properties contributed 3,217,000 Mcf of production in 1995 as compared to 1,315,000 Mcf in 1994 (six months). Gas production from the Company's other properties decreased 90,000 Mcf (5%) in the aggregate during 1995 due to normal production declines. The average price received for gas was $1.64 per Mcf in 1995 as compared to $1.82 per Mcf in 1994. During 1995, the company realized revenues of $6,362,000 from its share of the operations of the natural gas processing plant acquired with the San Joaquin Basin properties. These revenues consisted of $2,320,000 in the resale of natural gas purchased from third parties, $3,321,000 in the sale of processed natural gas liquids, $111,000 in gas processing fees and $610,000 from the monetization of certain index-based gas contracts. In 1994, the Company realized gas plant revenues of $1,978,000 (six months), which consisted of $718,000 in the resale of purchased natural gas, $1,199,000 from the sale of processed natural gas liquids and $61,000 in gas processing fees. The Company realized interest and other income of $164,000 and $39,000, respectively, in 1995. This compares to interest and other income of $16,000 and $237,000, respectively, in 1994. The increase in 1995 interest income is due to significantly larger cash balances resulting from the Senior Note offering in July 1995. Other income in 1994 was primarily a gain on sale of miscellaneous oil and gas properties. Costs and Expenses. Total costs and expenses increased $11,295,000 (81%) from $14,030,000 in 1994 to $25,325,000 in 1995. 24 25 The Company's production costs increased $1,653,000 (46%) from $3,610,000 in 1994 to $5,263,000 in 1995. This was primarily due to the acquisition of the San Joaquin Basin properties, which accounted for $3,050,000 of production costs incurred in 1995 as compared to $1,373,000 in 1994 (six months). Production costs on the Company's other properties decreased $33,000 in the aggregate during 1995. Average production costs decreased to $3.99 per BOE in 1995 as compared to $4.13 per BOE in 1994. During 1995, the Company incurred costs of $3,704,000 resulting from its share of the operations of the natural gas processing plant acquired with the San Joaquin Basin properties. These costs included $1,998,000 for the purchase of natural gas for processing and resale and $1,706,000 of direct operating expenses. During 1994, the Company incurred gas plant costs of $1,708,000 (six months) consisting of $876,000 of natural gas purchased for resale and $832,000 of direct operating expenses. The Company incurred incidental abandonment costs of $4,000 in 1995 as compared to $75,000 during 1994. Engineering and geological expenses increased $53,000 (21%) from $254,000 in 1994 to $307,000 in 1995 due to an increase in the number of oil and gas properties owned by the Company and activities related to their evaluation and management. The Company adopted in 1995 the provisions of Statement of Financial Accounting Standards No. 121 ("SFAS 121") which resulted in a non-cash impairment charge of $876,000 which is included in DD&A. Excluding the impairment charge, the Company's DD&A increased $1,200,000 (31%) from $3,897,000 in 1994 to $5,097,000 in 1995. This was a result of the substantial increase in acquisition and development costs related to the San Joaquin Basin property acquisition. The DD&A rate, excluding the effects of SFAS 121, was $3.60 per BOE in 1995 as compared to $4.14 during 1994 as a result of an increase in oil and gas reserves attributable to the San Joaquin Basin properties during 1995. Further affecting the increase in overall DD&A expense was $314,000 in depreciation expense in the current period relating to the natural gas processing plant acquired with the San Joaquin Basin properties as compared to $145,000 in 1994 (six months). The Company's general and administrative expenses increased $730,000 (36%) from $2,014,000 in 1994 to $2,744,000 in 1995. Increases in G&A were a result of the Company's increased development and financing activities and general expansion. The Company's interest expense increased $4,578,000 from $2,268,000 in 1994 to $6,846,000 in 1995. This was due to the increased bank debt resulting from the original financing of the San Joaquin Basin properties in June 1994 and subsequent refinancing of that bank debt and Series D Preferred Stock with $65,000,000 in 14 7/8% Senior Secured Notes in July 1995. Also increasing interest expense in 1995 was increased amortization of deferred financing costs resulting from these financings. Other expense of $483,000 in 1995 resulted from the write-down of a long-term investment of $261,000, bad debt expense of $90,000 and a $132,000 loss on the disposition of miscellaneous oil and gas properties. In 1994, the Company recorded a charge of $203,000 from a write-off of a portion of its interests in the South Texas Properties, a portion of which was conveyed to a third party pursuant to the terms of the dissolution of the South Texas Limited Partnership, a partnership in which the Company was a partner. Extraordinary Item. In connection with the refinancing of its long-term debt, the Company incurred in 1995 a non-cash extraordinary charge of $1,888,000 resulting from the early extinguishment of debt. This was primarily the write-off of all deferred financing costs associated with the Company's bank debt and Series D Preferred Stock which were repaid in July 1995. During 1994, the Company incurred an extraordinary non-operating charge of $122,000 resulting from the early extinguishment of debt in the refinancing of the South Texas properties in connection with the dissolution of the South Texas Limited Partnership. Accretion. During 1995, the company incurred a non-cash accretion charge of $2,147,000 on its Series D Preferred Stock. This accretion charge was primarily the result of the early redemption of the Series D Preferred Stock in connection with the refinancing of the Company's long-term debt. Preferred Dividends. Dividends on preferred stock were $1,000,000 for 1995 as compared to $795,000 in 1994. Increased dividends in 1995 were a result of the Series D and Series E Preferred Stocks being outstanding for a longer portion of the year during 1995 as compared to 1994 and an increase in the Series E 25 26 coupon rate from 4% to 9% effective July 1995. Dividends in 1995 consisted of $464,000 in cash, $476,000 in shares of Series D Preferred Stock and $60,000 in Common Stock of the Company. Dividends for 1994 consisted of $280,000 in cash, $455,000 in shares of Series D Preferred Stock and $60,000 in Common Stock of the Company. Net Loss. The Company's net loss from continuing operations for 1995 was $2,730,000 ($0.35 per share), while net loss attributable to common stockholders after extraordinary item, preferred dividends and accretion was $7,765,000 ($0.98 per share). In 1994, the Company had a net loss from continuing operations of $816,000 and net loss to common shareholders of $1,890,000 ($0.29 per share) after extraordinary item, preferred dividends and accretion. COMPARISON OF RESULTS OF 1994 TO 1993 Acquisition. Included in results of operations for 1994 are six months of operations from the San Joaquin Basin properties, which were acquired on June 30, 1994. Revenues. The Company's total revenues increased $6,488,000 (96%) from $6,725,000 in 1993 to $13,213,000 in 1994. The Company's oil and gas revenues increased $4,475,000 (69%) from $6,507,000 in 1993 to $10,982,000 in 1994. Oil revenues increased $1,975,000 (67%) from $2,950,000 in 1993 to $4,925,000 in 1994 due to higher oil production. The Company's oil production increased approximately 133,000 barrels (74%) from 179,000 barrels in 1993 to 312,000 barrels in 2994. The increased production was primarily a result of the acquisition of the San Joaquin Basin properties, which contributed 131,400 barrels during the last six months of 1994. The Company's Permian Basin properties experienced an increase of 5,400 barrels in 1994 due to the Company's acquisition of additional oil and gas interests in that area in late 1994. Additionally, oil production from the South Texas properties increased by 2,100 barrels due to the additional 12.625% interest in those properties acquired by the Company in May 1993 and the drilling of four development wells in late 1993 and early 1994. Oil production from the Company's Gulf Coast and other properties declined approximately 6,200 barrels in the aggregate due to normal production declines. The average price received for oil was $15.79 per barrel during 1994 compared to $16.46 per barrel in 1993. The Company's gas revenues increased $2,527,000 (72%) from $3,518,000 in 1993 to $6,045,000 in 1994 also due to increased production. Gas production increased 1,341,000 Mcf (68%) from 1,985,000 Mcf in 1993 to 3,326,000 Mcf in 1994. The acquisition of the San Joaquin Basin properties contributed 1,315,000 Mcf of the increase while production from the South Texas properties increased 174,000 Mcf due to the additional 12.625% interest acquired by the Company and the drilling of four development wells. Gas production from the Royalty Interests decreased 76,000 Mcf in 1994 as compared to 1993 as a result of mechanical problems with a gas purchaser's compression facilities which serve a significant gas lease. These facility problems were corrected in the fourth quarter of 1994. Gas production from the Company's other properties deceased 72,000 Mcf in the aggregate in 1994 due to normal production declines. Average prices received for gas were $1.82 per Mcf in 1994 as compared to $1.77 per Mcf in 1993. Excluding natural gas liquids attributable to the Bakersfield gas plant, the Company also realized $12,000 in natural gas liquids sales in 1994 as compared to $39,000 in 1993. During 1994, the Company realized revenues of $1,978,000 from its share of the operations of the natural gas processing plant acquired as part of the San Joaquin Basin properties. These revenues consisted of $718,000 in the resale of natural gas purchased from third parties, $1,199,000 in the sale of processed natural gas liquids, including the sale of natural gas liquids extracted from the natural gas purchased from third parties and $61,000 in gas processing fees. The Company realized other income of $237,000 in 1994 resulting primarily from a gain on the sale of securities. During 1993, the company had other income of $197,000 resulting primarily from the sale of its interests in several minor oil and gas properties. Costs and Expenses. Total costs and expenses increased $6,264,000 (81%) from $7,766,000 in 1993 to $14,030,000 in 1994. 26 27 The Company's production costs increased $1,361,000 (61%) from $2,249,000 in 1993 to $3,610,000 in 1994. This was primarily due to the acquisition of the San Joaquin Basin properties, which accounted for $1,373,000 in production costs during the last six months of 1994. Production costs on the South Texas properties increased $143,000 in the current year due to developmental drilling activities while production costs from the Company's other oil and gas properties decreased $155,000 in the aggregate as a result of lower workover costs. During 1994, the Company incurred operating costs of $1,708,000 associated with the natural gas processing plan acquired as part of the San Joaquin Basin properties. These costs included $876,000 from the purchase of natural gas for processing and resale of $832,000 of directing operating expenses. The Company incurred incidental abandonment costs on older non-productive leases of $75,000 in 1994 as compared to $41,000 in 1993. Engineering and geological expenses increased $66,000 (35%) from $188,000 in 1993 to $254,000 in 1994 due to the Company's increased activities. The Company's depletion, depreciation and amortization expense increased $1,256,000 (48%) from $2,641,000 in 1993 to $3,897,000 in 1994 as a result of increases in depreciable oil and gas assets due to acquisitions and development costs. The DD&A rate per BOE for oil and gas reserves decreased from $5.13 per BOE in 1993 to $4.14 per BOE in 1994 due to lower acquisition costs per BOE for oil and gas reserves acquired during 1994 and positive reserve revisions during 1994. Further affecting the increase in overall DD&A expense was depreciation expense relating to the natural gas processing plant acquired as part of the San Joaquin Basin properties in 1994. The Company's general and administrative expenses decreased slightly from $2,105,000 in 1993 to $2,014,000 in 1994 (4%). The Company experienced $142,000 in nonrecurring costs resulting from its relocation from California to Texas during 1993. The Company's interest expense increased $1,727,000 from $542,000 in 1993 to $2,269,000 in 1994 primarily as a result of the bank debt used to finance the acquisition of the San Joaquin Basin properties in June 1994. The Company's bank debt increased from $8,541,000 at December 31, 1993 to $39,400,000 at December 31, 1994, resulting in a significantly higher average debt balance during the current year. The Company recorded a charge of $203,000 in 1994 from a write-off of a portion of its interests in the South Texas Properties, which portion was conveyed to a third party pursuant to the terms of the dissolution of the South Texas Limited Partnership. Also in connection with the dissolution of the South Texas Limited Partnership, the Company incurred an extraordinary non-operating charge of $122,000 in 1994 resulting from the early extinguishment of debt in the refinancing of the South Texas properties. Dividends on preferred stock were $795,000 in 1994, as compared to $246,000 in 1993. The increase in dividends was a result of the issuance of additional preferred stock as part of the financing for the acquisition of the San Joaquin Basin properties. Dividends in 1994 consisted of $280,000 in cash, $455,000 in Series D Preferred Stock and detachable warrants and $60,000 in common stock of the Company. All 1993 dividends were paid in cash. The Company also incurred a non-cash charge of $156,000 attributable to accretion on its Series D Preferred Stock in 1994. Net Loss. The Company's net loss before the extraordinary item in 1994 was $816,000, and $939,000 after the extraordinary item. Net loss attributable to common stockholders was $1,890,000 ($.29 per share) after preferred dividends, accretion on preferred stock and the extraordinary item. In 1993, the Company had a net loss of $1,041,000 and a loss of $1,287,000 ($.23 per share) attributable to common shareholders after preferred dividends. LIQUIDITY AND CAPITAL RESOURCES Summary. The Company's sources of working capital have primarily been cash flows from operations and a combination of debt and equity financings as needs for capital have arisen. During the three months ended March 31, 1996, the Company used net cash from operations of $88,000 as compared to $944,000 cash flows generated from operations during the same period in 1995. The Company realized net proceeds of $1,597,000 27 28 from financing activities during the first quarter of 1996, which consisted primarily of a draw-down on its credit facility net of dividends and miscellaneous financing costs. During the first quarter of 1995, the Company had nominal financing activities. The Company utilized a net of $9,736,000 for investing activities in the first quarter of 1996 as compared to $107,000 during the first quarter of 1995. Included in investing activities in the first quarter of 1996 were payments of $8,188,000 relating to drilling costs incurred but unpaid at the end of 1995. Working Capital. The Company had net working capital of $1,789,000 with a current ratio of 1.3:1 at March 31, 1996 as compared to net working capital of $1,325,000 and a current ratio of 1.1:1 at December 31, 1995. Operating Activities. Discretionary cash flow is a measure of performance which is useful for evaluating exploration and production companies. It is derived by adjusting net income or loss to eliminate the non-cash effects of exploration expenses, depletion, depreciation, amortization and non-recurring charges, if applicable. The effects of non-cash working capital changes are also excluded. This measure reflects an amount that is available for capital expenditures, debt service and repayment and dividend payments. During the three months ended March 31, 1996, the Company generated discretionary cash flow of $2,080,000. This compares to $1,132,000 during the same period in 1995. The improvement in 1996, in spite of significantly increased debt service, was primarily due to increased oil and gas production resulting from the continued drilling and development of the San Joaquin Basin properties. The Company had a total of 144 producing wells in this area at March 31, 1996, as compared to 96 producing wells at March 31, 1995. As a consequence of these drilling activities and the acquisition of certain additional interests in these properties in July 1995, HarCor's share of sales production from the San Joaquin Basin properties averaged 1,336 Bbls per day and 13,895 Mcf per day during the first quarter of 1996, showing increases of 68% and 72%, respectively, over first quarter 1995 average rates of 796 Bbls per day and 8,085 Mcf per day. Additionally, first quarter 1996 production rates on the San Joaquin Basin properties demonstrated a continuing increase over fourth quarter average production rates of 1,174 Bbls per day and 11,734 Mcf per day. The Company also realized a net operating margin of $668,000 on its gas plant operations in the first quarter of 1996 as compared to $375,000 in the first quarter of 1995. This was primarily due to increased gas production volumes from the San Joaquin Basin properties processed through the plant, resulting in increased NGLs sales in the first quarter of 1996. Early in the first quarter of 1996, the Company deferred drilling vertical wells in the San Joaquin Basin pending the results of its first horizontal well in this area. The Company anticipates resuming drilling certain vertical wells required for implementation of the waterflood program towards the end of the second quarter of 1996. Results of the Company's first horizontal well on the Ellis Lease, which was completed in June 1996 and is currently being tested, will determine if additional horizontal wells will be drilled to eliminate certain planned vertical wells. See "Capital Expenditures and Future Outlook" below. Financing Activities: Credit Facility. Availability under the Company's Credit Facility with ING Capital is limited to a "borrowing base" amount. The borrowing base is determined semi-annually by ING Capital, at its sole discretion, and may be established at an amount up to $15 million. The borrowing base is currently $15 million. The Credit Facility will terminate on June 30, 1997 unless renewed by mutual agreement. If not so renewed, amounts outstanding will convert to a term loan on September 30, 1997, with a set amortization schedule of a percentage of the outstanding principal balance continuing through December 31, 2000. The Company drew down $1.9 million on this facility during the first quarter of 1996 and there was $7.5 million outstanding at March 31, 1996. The effective interest rate on the balance outstanding was 8.125% at that date. Amounts advanced under this facility bear interest at an adjusted Eurodollar rate plus 2.50%. The Company repaid $2 million of the outstanding balance under the Credit Facility subsequent to March 31, 1996 from cash flows generated by operations. The Credit Facility contains restrictive covenants which impose limitations on the Company and its subsidiaries with respect to, among other things, certain financial ratios or limitations, incurrence of indebtedness, the sale of the Company's oil and gas properties and other assets, hedging transactions, payment 28 29 of dividends, mergers or consolidations and investments outside the ordinary course of business. The Credit Facility also contains customary default provisions. All indebtedness of the Company under the Credit Facility is secured by a first lien upon substantially all of the Company's oil and gas properties as well as by the accounts receivable, inventory, general intangibles, machinery and equipment and other assets of the Company. All assets not subject to a lien in favor of the lender are subject to a negative pledge, with certain exceptions. See Notes 6 and 7 of Notes to Consolidated Financial Statements included herein for a complete description of the Senior Notes and the Credit Facility. Senior Notes. In July 1995, the Company consummated the sale of 65,000 units consisting of $65 million aggregate principal amount of its 14 7/8% Senior Notes due in the year 2002 and warrants to purchase 1,430,000 shares of Common Stock. Each unit consisted of a $1,000 principal amount note and 22 warrants to purchase an equal number of shares of Common Stock. The Senior Notes and the warrants became separately transferrable immediately after July 24, 1995. The Company used the net proceeds of approximately $61 million to repay an aggregate of $39.3 million outstanding under its Credit Facility and bridge loan with ING Capital; redeem $10.9 million in outstanding shares of Series D Preferred Stock which were issued in connection with the acquisition of the San Joaquin Basin properties; and acquire additional interests in additional producing wells in the San Joaquin Basin properties for $2.3 million. The Company used the balance of the proceeds from the Senior Notes to finance a portion of the development of its San Joaquin Basin properties over the remainder of 1995. This refinancing of the Company's debt and capital structure resulted in an extraordinary loss on early extinguishment of debt of $1.9 million and accretion on Series D Preferred Stock of $2.1 million in the current year. The Company's Senior Notes bear interest at the rate of 14 7/8% per annum. Interest accrues from the date of issue and will be payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 1996. The Senior Notes are redeemable, in whole or in part, at the option of the Company at any time on or after July 15, 1999, at the following redemption prices (expressed as percentages of the principal amount) if redeemed during the 12-month period commencing on July 15 of the year set forth below plus, in each case, accrued interest thereon to the date of redemption:
YEAR PERCENTAGE -------------------------------------------------------------- 1999................................................ 110% 2000................................................ 107% 2001 and thereafter................................. 100%
In the event that the Company has excess cash flow (defined as the amount by which the sum of consolidated net income and certain other consolidated non-cash charges exceeds the sum of capital expenditures and payments required to be made pursuant to the scheduled maturities of certain indebtedness) in excess of $2 million in any fiscal year, beginning with the fiscal year ending December 31, 1996, the Company will be required to make an offer to purchase notes from all holders thereof in an amount equal to 50% of all such excess cash flow for such fiscal year (not just the amount in excess of $2 million) at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest thereon. The Company does not expect to have any excess cash flow in the foreseeable future due to its planned capital expenditures. In the event that the Company consummates on or prior to July 15, 1997 an offering of qualified capital stock, which includes Common Stock, of the Company for cash having proceeds in excess of $5 million, then following the offering the Company is obligated to make an offer to purchase Senior Notes from all of the holders of the Senior Notes on a date within 90 days after the consummation of the offering at a purchase price equal to 110% of the aggregate principal amount of the Senior Notes that the Company is required to offer to repurchase, plus accrued and unpaid interest thereon, if any. The aggregate principal amount of the Senior Notes to be repurchased will be an amount equal to the lesser of (i) 40% of the aggregate principal amount of the Senior Notes originally issued and (ii) the maximum amount of the Senior Notes which could be purchased with 50% of the amount of net proceeds received or receivable by the Company from the offering of qualified capital stock. The Company also has the option to redeem a portion of the Senior Notes at a 29 30 redemption price of 110% of the principal amount of the Senior Notes to be redeemed, plus accrued and unpaid interest to the date of redemption, utilizing net proceeds from such an offering to the extent that such proceeds could have otherwise been utilized to purchase Senior Notes as described above. The Company intends to use 50% of the net proceeds of the Offering to redeem a portion of the Senior Notes as described above. The Company estimates that it will incur an extraordinary charge of approximately $2,081,000 relating to the early extinguishment of debt. All of the obligations of the Company under the Senior Notes and related indenture are secured by a second priority lien on substantially all of the assets of the Company, which assets also collateralize the Company's obligations under the Credit Facility. The Company also used an aggregate of $303,000 for the payment of dividends and miscellaneous financing costs during the current period. Hedging Activities. The Company's hedging activities during the three years ended December 31, 1995 and the three months ended March 31, 1996 have not had any material effect on the Company's liquidity or results of operations. In the fourth quarter of 1995, the Company received $610,000 in revenues from the privatization of certain index-based gas contracts. The following table presents all hedge contracts that the Company was a party to at March 31, 1996 including the type of contract, volumes contracted, period of contract and unit contract price.
TYPE OF CONTRACT CONTRACTED VOLUMES PERIOD UNIT CONTRACT PRICE - ---------------- ------------------ ------------------------- ---------------------- Hedge 8,000 Bbls/month Feb. 1994 to Aug. 1996 $18.75/$15.80 Bbl(A) Hedge 300 Bbls/day May 1995 to April 1996 $18.50/Bbl Hedge 250 Bbls/day May 1996 to April 1997 $18.50/Bbl Hedge 6,750 Bbls/month Jan. 1996 to Dec. 1996 $17.25/Bbl(B) Hedge 5,625 Bbls/month Jan. 1997 to Dec. 1997 $17.25/Bbl(B) Hedge 4,875 Bbls/month Jan. 1998 to Dec. 1998 $17.25/Bbl(B) Physical 3,000 MMBtu/day Oct. 1995 to Sept. 1996 $2.03/MMBtu Physical 2,000 MMBtu/day Oct. 1995 to Sept. 1997 $1.68/MMBtu Physical 2,500 MMBtu/day Oct. 1996 to Sept. 1997 $2.07/MMBtu Physical 6,000 MMBtu/day Jan. 1996 to Dec. 1997 NYMEX-indexed(C)
- --------------- (A) Pursuant to such hedge contract, if the NYMEX price of light, sweet crude oil ("NYMEX price") is lower than $15.80, then the Company is paid the difference between the NYMEX price and $15.80 for each barrel hedged; and, if the NYMEX price is higher than $18.75, then the Company pays the difference between the NYMEX price and $18.75 for each barrel hedged. (B) Pursuant to such hedge contract, the Company pays half of the difference between $17.25 and the NYMEX price if the index price is higher than $17.25; and the Company receives the difference between $17.25 and the index price if the index price is lower than $17.25, as determined on a monthly basis. (C) Firm gas sales contract which fixes volumes to be sold at $0.3675 less than the NYMEX gas future price for each applicable month. As of March 31, 1996 the Company had approximately 45% of its oil production and approximately 42% of its gas production committed to the above sales and hedging contracts based on first quarter 1996 production. Capital Expenditures and Future Outlook. Subsequent to the refinancing of its debt in July 1995, the Company spent $2.3 million on the acquisition of interests in additional producing wells on the San Joaquin Basin properties and spent approximately $15 million on developmental and drilling activities on these properties through March 31, 1996. The Company also spent an aggregate of $848,000 on the development of its Permian and South Texas properties during 1995. See "Operating Activities" for current production rates. The Company intends to spend an additional estimated $56.6 million for capital expenditures to develop the proved reserves of the San Joaquin Basin properties during the period from 1996 through the year 2000, of 30 31 which $16 million is planned to be spent during 1996, $12 million in 1997, $13 million in 1998 and $15.6 million thereafter. The Company currently anticipates that total additional development of the San Joaquin Basin properties will result in approximately 173 new gross wells, including 145 development wells and a secondary recovery waterflood project in the Diatomite Zone of the Ellis Lease. The first phase of the waterflood project is planned to be initiated in the fourth quarter of 1996, with expansion of the project planned in 1997 and 1998 to cover the entire area of proved reserves. The Company plans to fund 1996 and future capital expenditures from operating cash flows and borrowings under the Credit Facility. The Company also plans to spend approximately $1.5 million to drill two horizontal wells on these properties during 1996. The first of these wells has been drilled and completed on the Ellis Lease in the Diatomite formation to test a possible extension of the current proved area of the field and to evaluate the use of horizontal wells to eliminate the drilling of certain planned infill vertical wells on the Ellis Lease. A second horizontal well is planned to evaluate its applicability to producing the deeper MacDonald formation on the Ellis Lease. If successful, additional horizontal locations may be identified for future drilling on the Ellis Lease as well as the Company's Truman and Tisdale Leases in areas currently outside the proven areas of these fields. No assurances can be given, however, that any of such wells will be drilled, or that if such wells are drilled, they will be either successful or completed in accordance with the Company's development schedule. The Company is also involved in two small waterflood projects on its Permian Basin properties and has approximately $2.4 million in capital expenditures planned in this area during the next two years. In the second half of 1995, the Company participated in a leasing program which was undertaken in South Texas around the Company's existing Hostetter Field for a planned 3-D seismic program. The 3-D seismic survey is currently being conducted and processing of data from this seismic program commenced in May 1996 and drilling could begin in the fourth quarter of 1996. In furtherance of this effort and as part of the Company's strategy of aligning itself with partners that have technological expertise, the Company has entered into an agreement with South Coast Exploration to jointly explore the Hostetter Field. South Coast Exploration in turn has provided the Company with a similar opportunity to jointly explore a prospect area in Terrebonne Parish, Louisiana. The Company and South Coast Exploration have also agreed to jointly participate in a 3-D seismic/exploration project in Reeves County, Texas, the first phase of which is currently being conducted. The Reeves County project area of mutual interest covers approximately 160,000 acres and will entail shooting 3-D seismic data over approximately 200 square miles with the first exploratory test well planned for the first quarter of 1997. The Company and South Coast Exploration have also jointly formed the GeoTeam to assist them in the evaluation of these 3-D projects. Based on current plans, the Company expects to make capital expenditures with respect to its exploratory prospects of approximately $14.3 million during the next 18 months, of which approximately $3.2 million is expected to be spent during the second half of 1996, and approximately $11.1 million is expected to be spent during 1997. Of the estimated capital expenditures in 1996, approximately $1.3 million is expected to be made for seismic surveys, of which $720,000 will be made in South Texas, $330,000 will be made in West Texas and $235,000 will be made in South Louisiana; approximately $1.4 million is expected to be made for leasehold acquisitions, of which $640,000 will be made in South Texas, $480,000 will be made in West Texas and $240,000 will be made in South Louisiana; and approximately $570,000 is expected to be made for exploration drilling in South Texas. Of the estimated capital expenditures in 1997, approximately $8.9 million is expected to be made to drill approximately 18 exploration and development wells in South Texas; approximately $900,000 is expected to be made to drill four exploration and development wells in West Texas and approximately $1.3 million is expected to be made to drill four exploration and development wells in South Louisiana. While the Company has had losses in each of the past five years and the first quarter of 1996, the Company has taken steps to address its continuing losses. The most notable of which include increasing the development of its undeveloped properties, including the Bakersfield Properties, to increase production of oil and gas and cash flow from operations and using a portion of the proceeds from the Offering to redeem part of its outstanding Senior Notes and reduce the Company's interest expense. The reduced interest expense should permit further development of the Company's properties and expansion of its reserve base. In addition, the 31 32 Company has continued to maintain relatively low general and administrative expenses by continuing to operate through a management team that is few in number. Despite its lack of profits, the Company expects that its available cash, expected cash flows from operating activities, credit availability under its Credit Facility and the proceeds from the Offering will be sufficient to meet its financial obligations and fund its planned developmental drilling and exploration activities through the end of 1997, provided, that (i) there are no significant decreases in oil and gas prices beyond current levels or anticipated seasonal lows, (ii) there are no significant declines in oil and gas production from existing properties other than declines in production currently anticipated based on engineering estimates of the decline curves associated with such properties, (iii) drilling costs for development wells with respect to the San Joaquin Basin properties do not increase significantly from the drilling costs recently experienced by the operator in such areas with respect to similar wells and (iv) the operator continues its development program with respect to the San Joaquin Basin properties on the schedule currently contemplated. In the event the cash flows from the Company's operating activities, credit available under its Credit Facility and the proceeds from the Offering are not sufficient to fund development costs, or results from developmental drilling are not as successful as anticipated, then the Company will either (i) curtail its developmental drilling and/or exploration activities or (ii) seek additional financing to assist in its developmental drilling activities. The Company intends to continue efforts to acquire additional interests in selected producing oil and gas properties if and when these opportunities become available. Any such acquisitions could require borrowings under the Credit Facility or additional debt or equity financing. UNCERTAINTIES INVOLVING FORWARD-LOOKING DISCLOSURE Certain of the statements set forth above under "Liquidity and Capital Resources -- Capital Expenditures and Future Outlook" and elsewhere in this Prospectus, such as the statements regarding planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled in 1996 and thereafter and the planned 3-D seismic program, are forward-looking and are based upon the Company's current belief as to the outcome and timing of such future events. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimate and such revisions, if significant, would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered. Furthermore, the estimated numbers of wells to be drilled in 1996 and 1997 are based upon product prices and costs as of December 31, 1995 (except for gas sold under contract, in which case the contract prices were used), which will probably be different from the actual prices recognized and costs incurred in 1996 and 1997. Additional factors which could materially affect the Company's oil and gas production and development drilling program in the future are general economic conditions; the impact of the activities of OPEC and other competitors; the impact of possible geopolitical occurrences world-wide; the results of financing efforts, risks under contract and swap agreements; changes in laws and regulations; capacity, deliverability and supply constraints or difficulties, unforeseen engineering and mechanical or technological difficulties in drilling or working over wells; and other risks set forth in "Risk Factors," appearing elsewhere in this Prospectus. Because of the foregoing matters, the Company's actual results for 1996 and beyond could differ materially from those expressed in the forward-looking statements. 32 33 EFFECTS OF INFLATION AND CHANGES IN PRICE The Company's results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and gas increases, there could be a corresponding increase in the cost to the Company for drilling and related services, as well as an increase in revenues. Inflation has had a minimal effect on the Company. OTHER In September 1995, the Company adopted the provisions of SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS 121 requires the Company to review its oil and gas properties whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable, and recognize a loss if such recoverable amounts are less than the carrying amount. The adoption of SFAS 121 resulted in an impairment loss of $876,000 which was included in depletion, depreciation, amortization and impairment in 1995. The Company uses the successful efforts method of accounting for its oil and gas properties. See Note 1 of Notes to Consolidated Financial Statements included herein for a summary of significant accounting policies. 33 34 BUSINESS AND PROPERTIES THE COMPANY HarCor Energy, Inc. is an independent energy company engaged in the acquisition, exploitation and exploration of onshore crude oil and natural gas properties in the United States. Since 1987 when the present management group acquired control of the Company, HarCor has grown through selective acquisitions and development drilling, with estimated proved reserves increasing from 1.35 MMBOE as of January 1, 1990 to 29.9 MMBOE as of January 1, 1996, at an average replacement cost of $2.62 per BOE. The Company's operations are currently focused in the San Joaquin Basin of California, South Texas and the Permian Basin of West Texas. As of January 1, 1996, the Company's proved reserves, as estimated by the Company's independent petroleum engineers, consisted of 15.3 MMBbls of crude oil and NGLs and 87.6 Bcf of natural gas with a Pre-tax SEC 10 Value of $124.5 million, approximately 84% of which was attributable to net proved reserves located in the Lost Hills Field in the San Joaquin Basin. The Company conducts its exploration, development and production activities through strategic alliances with industry partners that are experienced and knowledgeable in the particular geologic basins of activity and that own a significant interest in the jointly owned properties. The industry partner is generally designated as the operator of the jointly owned properties, thereby allowing the Company to avoid the cost of maintaining the personnel and other resources necessary to be an operator. The Company believes, however, that its ownership of meaningful working interests in its properties, its contractual rights to approve drilling budgets or propose wells and its experienced team of oil and gas professionals allow the Company to control or significantly influence the operators' decisions affecting the magnitude and timing of exploration, development and production activities on its properties. Through geographic concentration and tight control over oil and gas operating and general and administrative expenses, the Company has maintained a relatively low cost structure. For the year ended December 31, 1995, the Company had an average production cost of $3.99 per BOE and general and administrative expenses of $1.80 per BOE. BUSINESS STRATEGY The Company's business objective is to increase its hydrocarbon reserves as economically as possible by: - Continuing to develop its San Joaquin Basin, South Texas and Permian Basin properties through additional drilling and secondary recovery activities; - Using the cash flow from its existing properties and the proceeds from the Offering to engage in exploration activities with experienced and technologically knowledgeable industry partners, initially onshore Texas and Louisiana; - Acquiring onshore oil and gas properties with significant development potential; and - Continuing to maintain relatively low production costs through geographic concentration and tight control over operating and general and administrative expenses. DEVELOPMENT ACTIVITIES San Joaquin Basin. Approximately 20.8 MMBOE, or 69.4%, of the Company's total proved reserves as of January 1, 1996 were classified as proved undeveloped by Ryder Scott. Substantially all of the Company's undeveloped reserves are located in the Lost Hills Field in the San Joaquin Basin. Bakersfield Energy, a company with extensive experience in the San Joaquin Basin, is the operator of substantially all of HarCor's oil and gas properties in the San Joaquin Basin. As of March 31, 1996, the Company had identified 173 new gross wells which it intends to drill during the next five years to fully develop the proved reserves on the properties, of which 48 are expected to be drilled in 1996. The Company also plans to commence a secondary recovery waterflood project in the fourth quarter of 1996 with respect to a portion of its properties in the Lost Hills Field. In addition, the Company has completed a horizontal well in the Lost Hills Field to test a possible extension of the current proved area of the field and to evaluate the use of horizontal wells to eliminate the 34 35 need to drill certain infill vertical wells. The Company has identified 60 potential locations for future development of probable and possible reserves located on the San Joaquin Basin properties. The San Joaquin Basin properties produce a light (approximately 40() gravity), low sulfur crude oil that commands a substantial price premium to the heavier crude oils typically produced in California. The associated natural gas produced with the crude oil has a high Btu content (approximately 1,240 Btu) which yields in excess of 2 gallons of NGLs per Mcf of natural gas when processed in the Company's gas processing plant located in the San Joaquin Basin. Since acquiring the properties in June 1994, the Company has drilled 76 gross development wells on the San Joaquin Basin properties through March 31, 1996. As a result of such drilling activity, the Company's average daily production has increased from 546 Bbls of oil and 7,195 Mcf of gas for the month ended June 30, 1994 to 1,336 Bbls of oil and 13,895 Mcf of gas for the quarter ended March 31, 1996. Since acquiring the San Joaquin Basin properties, the net proved reserves attributable to such properties have increased from 14.1 MMBOE as of June 30, 1994, to 22.7 MMBOE as of January 1, 1996, at an average replacement cost of $1.65 per BOE. The Pre-tax SEC 10 Value of the Company's San Joaquin Basin properties as of January 1, 1996 was $105.2 million as estimated by Ryder Scott. In addition to the extensive development drilling program in the Lost Hills Field, the Company also plans to undertake a secondary oil recovery program to further increase reserves and production from the field. Using primary production techniques, it is estimated by Ryder Scott, as of January 1, 1996, that the Ellis Lease located in the Lost Hills Field has proved reserves net to the Company of approximately 9.0 MMBbls of crude oil. In addition to primary development, the Company intends to increase recovery rates by implementing a secondary recovery waterflood project in the Diatomite Zone on the Ellis Lease, which is similar to waterflood projects currently used by other oil and gas companies operating in the Lost Hills Field. The first phase of the Ellis Lease waterflood project is planned to be initiated in the fourth quarter of 1996, with expansion planned in 1997 and 1998 to cover the entire area currently estimated to cover proved reserves. Ryder Scott estimates that the Company's Ellis Lease will yield an additional 3.7 MMBbls of proved undeveloped secondary recovery crude oil reserves utilizing the waterflood recovery method. In addition, the Company will commence a feasibility study for waterflooding the Reef Ridge Shale and Antelope Shale formations on its San Joaquin Basin properties. During 1995, the Company and Bakersfield Energy completed a 3-D reservoir model of the Diatomite Zone on the Ellis Lease, the results of which are being used to examine various means of further optimizing its planned Ellis Lease waterflood, including the use of horizontal drilling on the property, as well as to assist the Company with additional computer simulation modeling of hot water, steam and CO(2) recovery techniques. In the fourth quarter of 1995, the Company undertook studies to evaluate the use of horizontal drilling technology on its San Joaquin Basin properties. As a result of these studies, the first of two horizontal wells planned for 1996 has been drilled and completed on the Ellis Lease in the Diatomite Zone at a vertical depth of approximately 3,450 feet with an approximate 2,000 foot lateral drilled outside of the Diatomite Zone's previous development to test a possible extension of the current proved area of the field and to evaluate the use of horizontal wells to eliminate the drilling of certain infill vertical wells on the Ellis Lease. During the five days of production tests, the well flowed at an average rate of 418 BOE per day. The second horizontal well is planned to evaluate its applicability to producing the deeper MacDonald Shale formation at a depth of approximately 5,200 feet on the Ellis Lease. If these wells are successful, potential additional horizontal locations may be identified for future drilling on the Ellis Lease as well as in areas currently outside the proved areas of the Company's Truman and Tisdale Leases. The Company acquired its San Joaquin Basin properties from Bakersfield Energy in June 1994. Bakersfield Energy, which originally acquired these properties in 1990, retained a 25% working interest in these properties and has continued to serve as the operator. In addition, the Company entered into a joint acquisition agreement with Bakersfield Energy which gives each party the right through June 1997 to participate equally in any acquisition of oil and gas interests located within the state of California by the other party. Gas Plant. The South Belridge Gas Plant is a modern refrigerated liquids extraction facility located in the South Belridge Field in Kern County, California, approximately 10 miles southwest of the Lost Hills Field. The gas plant was originally acquired from Exxon Corporation and has a rated inlet capacity of 23 MMcf of 35 36 gas per day and a rated liquid fractionation capacity of 100,000 gallons of NGLs per day at a rate of two gallons of NGLs per every Mcf of natural gas throughput. The plant is located on a 12-acre site and has NGL storage capacity of 407,000 gallons. The plant removes the NGLs from the wet gas inlet stream then delivers the residue natural gas directly into the pipeline system of Southern California Gas Company ("SoCal") or directly to their customers. The NGLs extracted at the plant are propane, iso-butane, normal butane and natural gasoline and are sold on the spot market. The plant produced 62,266 barrels of NGLs during the quarter ended March 31, 1996 as compared to 37,613 during the first quarter that the plant was acquired by the Company. In addition to its capacity to strip high volumes of liquids from the Lost Hills property's wet gas stream, the gas plant is integral in the Company's ability to market the residue dry gas produced from that property. The plant's gathering lines transport wet gas from the Exxon Corporation and San Joaquin Basin properties gathering systems and can deliver dry, residue gas into the SoCal, Chevron U.S.A., Inc., Mobil Oil Corporation and Texaco Inc. pipeline systems. It is these pipeline connections that allow the Company to market the dry gas to various customers and realize favorable pricing. More importantly, it has allowed the Company to enter into contract and marketing arrangements that are not tied to the sometimes unfavorable and volatile California spot market. During the fourth quarter of 1995, the Company realized a gain of $610,000 from the monetization of certain index-based gas contracts that the Company had been able to enter into as a result of the gas plant's pipeline connections. Additionally, in the first quarter of 1996 the Company entered into a contract for 6,000 mcf/day fixing the price for those volumes at $0.3675 less than the NYMEX gas future price for two years. South Texas. In October 1992, the Company acquired an interest in nine gas fields located in South Texas for a total purchase price of approximately $5.3 million. Subsequent development activities have resulted in average daily production on the South Texas properties of 36 Bbls of crude oil and 4,068 Mcf of natural gas for the quarter ended March 31, 1996 and net proved reserves as estimated by Ryder Scott of 1.7 MMBOE at January 1, 1996. Approximately 51% of the Company's reserves in the South Texas properties is attributable to its interests in the Hostetter Field. The Company owns interests in 17 gross (four net) wells and owns approximately 2,525 gross (956 net) acres in the Hostetter Field. These wells are operated by Texaco and Cabot. The Company currently believes that there are opportunities for additional development and recompletion work in this field. Permian Basin (West Texas/New Mexico). Since 1989, the Company, in conjunction with Penroc Oil Corporation, has jointly identified and acquired interests in oil and gas properties located in the Permian Basin with total acquisition costs net to the Company of $3.4 million. Subsequent remedial work, development drilling activity and secondary recovery procedures have resulted in average daily production of 269 Bbls of crude oil and 416 Mcf of natural gas based on production in the quarter ended March 31, 1996. Ryder Scott's estimate of the Company's net proved reserves in the Permian Basin as of January 1, 1996 was 2.1 MMBOE. EXPLORATION ACTIVITIES Consistent with its core objective of increasing its reserves as economically as possible, the Company has commenced a program of identifying and developing exploratory prospects in areas where the Company or its partners have expertise. HarCor intends to manage its exploration and economic risks by (i) generating prospects with the assistance of strategic industry partners that are experienced in 3-D seismic and CAEX technology, (ii) identifying and pursuing prospects with multiple potential productive zones, (iii) funding its exploration activities with proceeds from the Offering and internally generated cash flow and (iv) limiting its cash exposure to approximately $500,000 for each well. In addition, the Company intends to further manage the drilling risks associated with the exploration projects in South Texas and South Louisiana by drilling multipay prospects that combine shallower lower risk zones that have previously proven productive in the area with deeper potential target zones. In furtherance of this strategy, the Company has recently entered into an agreement with South Coast Exploration, a company that has extensive experience utilizing 3-D seismic and CAEX techniques, to jointly pursue exploration projects on developed and undeveloped properties in South 36 37 Texas, the Permian Basin of West Texas and South Louisiana. The Company and South Coast Exploration have jointly formed the GeoTeam to work exclusively to pursue these joint projects. The Company believes the use of 3-D seismic and CAEX technology is particularly beneficial to developing prospects with multiple pay zones such as those found in the geographic areas encompassing the Company's prospects. Specifically, the Company and its partners plan to use the detailed 3-D seismic data acquired in the prospect areas to select well locations that are positioned to provide that well bores drilled to test the deeper high potential plays will also penetrate the shallow lower risk reservoirs at geologically favorable locations and provide shallow zone completion potential in the event the deeper zones are not productive. The Company believes that the potential reserves from the prospects currently targeted by this program should be comprised largely of natural gas, which should complement the Company's current mix of estimated proved reserves, which as of January 1, 1996 consisted of 51% of crude oil and NGLs and 49% of natural gas. The following table sets forth certain information as of May 30, 1996 relating to the exploration prospects that the Company currently plans to pursue over the 18-month period ending December 31, 1997, including the estimated cost to the Company for 3-D seismic surveys, leasehold acquisitions and drilling of exploratory and development wells relating to such prospects through such date.
GROSS ACREAGE PROSPECTIVE OWNED OR SQUARE MILES PROSPECTIVE ESTIMATED COST TO COMPANY(3) UNDER OF 3-D GROSS ------------------------------------- PROSPECT AREA OPTION(1) SEISMIC DATA WELLS(2) SEISMIC LAND DRILLING TOTAL - -------------------------------------------------------- ------------- ----------- ------- ------ -------- ------- (IN THOUSANDS) South Texas (Upper Wilcox Trend)........... 23,000 83 18 $ 720 $ 640 $ 8,900 $10,260 West Texas (Permian Basin)................. 80,320 210 4 330 480 900 1,710 South Louisiana (Terrebonne Parish)........ 5,529 46 4 235 240 1,300 1,775 -- ------- --- ------ ------ ------- ------- Total.............................. 108,849 339 26 $1,285 $1,360 $11,100 $13,745 ======= === == ====== ====== ======= =======
- --------------- (1) Includes acreage in which the Company currently has leases, options to acquire leases, contingent lease rights or fee interests. (2) Includes 10 exploratory wells and 16 development wells. (3) The estimated cost to the Company is based on (i) preliminary estimates of seismic survey costs, leasehold acquisition costs and drilling and completion costs and (ii) assumed levels of participation by the Company in the costs thereof. Actual costs and participation levels may vary from such estimates. The following sets forth a brief summary of each exploration prospect that the Company has in progress. This discussion only includes prospects on which the Company has acquired substantial leasehold interests, options to acquire leasehold interest or other contingent lease rights and has performed or is in the process of arranging related 3-D seismic surveys. See "Risk Factors -- Risk of Exploratory Drilling Activities" for a discussion of the risks associated with these exploration prospects. South Texas (Upper Wilcox Trend). HarCor has entered into an agreement with Cabot to participate in an 83 square mile 3-D seismic survey in southeast McMullen and northwest Duval Counties, Texas. The expanded and over-pressured Upper Wilcox Trend in the survey area has significant potential for the application of 3-D seismic technology due to complex faulting in the area and stacking of multiple pay zones in both the shallow normal-pressured zones such as the Cole Sand at 1,600 feet and the over-pressured zones such as the House Sand at approximately 12,000 feet. The 3-D seismic survey in the Upper Wilcox Trend commenced in April 1996 and is expected to be completed in July 1996. The survey is designed to evaluate prospects already identified and generate new drilling prospects with both development and exploration potential in the area of the Hostetter Field and the nearby Bonne Terre Field. The survey will evaluate approximately 40 geologic formations at depths ranging between 8,500 feet and 13,000 feet for the expanded over-pressured Upper Wilcox formation and as shallow as 1,500 feet for other intervals. HarCor has joined with Cabot to acquire, or to acquire options for, leasehold interests in 23,000 gross acres inside the 3-D survey area as of May 30, 1996. Production to date in the survey area, including production from the Hostetter Field 37 38 and the Bonne Terre Field, is estimated to be approximately 450 Bcf of natural gas equivalent. On May 29, 1996, HarCor assigned to South Coast Exploration and one of its affiliates 40% of its rights in its agreement with Cabot in exchange for the interest it received in the South Louisiana prospect described below. West Texas (Permian Basin). In May 1996, the Company entered into an agreement to participate in a 210 square mile 3-D seismic survey in Reeves County, Texas with Penwell which, along with its investment partner MCN Energy, has extensive recent experience in the Permian Basin. Penwell Energy initially derived its rights to about half of the area in the Penwell survey (74,880 fee mineral acres held by Texaco) from an agreement dated September 1995 among Texaco, Penwell and Meridian Oil Inc. Production in the field within or adjoining gross acreage in which Penwell presently owns or has contingent lease rights is estimated to be 455 Bcf of natural gas equivalents, most of which has been produced from the Silurian/Devonian Fusselman formation at depths between 10,000 feet and 17,000 feet, where the Company intends to focus. South Louisiana (Terrebonne Parish). South Coast Exploration and its affiliates have acquired an interest in a 46 square mile 3-D seismic survey to be conducted in south Terrebonne Parish, Louisiana. To date, the Lapeyrouse Field, which is located in the survey area, has produced approximately 350 Bcf of natural gas equivalents. Based upon 2-D seismic surveys and reports from independent engineers, South Coast Exploration's joint venture preliminarily has identified potential exploration sites in the area to drill an estimated four test wells in the next 18 months. Two of these potential exploration sites have been identified in the Bourg Sands between 14,500 feet and 15,500 feet and the remaining two potential exploration sites have been identified in traps associated with faulting in a series of Upper Middle Miocene Sands between 15,000 feet and 17,000 feet. South Coast Exploration and its affiliate have each assigned to HarCor a portion of their interest in this survey. The effectiveness of the assignment is subject to receipt by HarCor of the other party's consents to HarCor's participation in the survey. SOUTH COAST EXCHANGE AGREEMENT In May 1996, the Company and South Coast Exploration entered into an exchange agreement (the "South Coast Exchange Agreement") under which the Company and South Coast Exploration have agreed to use good faith efforts on a non-exclusive basis to identify and mutually agree upon the exchange of a portion of their interests in comparable 3-D seismic surveys and related joint operating agreements and other agreements on or before December 31, 1996. The interests to be exchanged must be comparable in terms of capital exposure and reserve potential. Once one set of such interests are identified, the Company and South Coast Exploration may, but are not obligated to, mutually identify and agree upon the exchange of additional comparable interests. Pursuant to the South Coast Exchange Agreement, HarCor assigned to South Coast Exploration and its affiliate 40% of its rights in its agreement with Cabot in South Texas in exchange for a 12% interest in the South Louisiana prospect described below. SOUTH TEXAS AGREEMENTS In January 1996, the Company entered into a participation agreement with Cabot (the "Cabot Agreement") providing for the shooting of a 3-D seismic survey over an area covering approximately 83 square miles in the Hostetter Field in McMullen and Duval Counties in South Texas. Pursuant to the Cabot Agreement, the Company is participating with an initial undivided 37.875% ownership interest in all leases, options, and seismic lease options previously acquired by either Cabot or the Company, and the Company is obligated to pay 37.875% of the total 3-D survey costs in the prospect area, subject to certain limitations. The Cabot Agreement also establishes an area of mutual interest (the "Cabot AMI") to be established over the prospect area which gives the Company the right to initially acquire 37.875% of any leasehold interest, option or other property right subsequently acquired by Cabot within the Cabot AMI through January 1, 1999. Conversely, Cabot has the right to acquire its proportionate share of any leasehold interest, option or other property right subsequently acquired by the Company within the Cabot AMI. As of April 1, 1996, Cabot entered into an Exploration Agreement with Texaco under which Texaco committed 7,800 net acres located within the Cabot AMI (the "Texaco Agreement") to Cabot's survey and exploration program. Under the Texaco Agreement, Cabot, among other things, grants to Texaco a non- 38 39 transferable license to the 3-D survey over a portion of area included in the Cabot survey. In return, Cabot has the right to propose to Texaco drilling prospects on the Texaco lands. If Texaco elects to participate in a drilling prospect on Texaco lands, Cabot will receive a 50% working interest in the Texaco lands included in a drilling prospect. If Texaco elects not to participate, Texaco would retain an overriding royalty interest in the Texaco lands convertible to a working interest at well payout. On May 2, 1996, Cabot entered into an agreement with Vastar Resources, Inc. ("Vastar") whereby Vastar agreed to contribute 50% of the cost of the 3-D survey over approximately one-quarter of the acreage of the Cabot AMI which is expected to reduce the total cost of the 3-D survey. On May 29, 1996, the Company entered into an agreement with South Coast Exploration pursuant to which the Company assigned 40% of its rights and interests under the Cabot Agreement to South Coast Exploration and its affiliate, which reduced the Company's interest in the rights created under the Cabot agreements to 22.73%. The effectiveness of the assignments to South Coast Exploration and its affiliate, however, are contingent on the Company receiving Cabot's consent to such assignments. WEST TEXAS AGREEMENTS In May 1996, the Company entered into an agreement with Penwell (the "Penwell Agreement") to participate in a multiphase 3-D geophysical survey and oil and gas exploration program pertaining to an area of mutual interest covering approximately 210 square miles in Reeves County, Texas (the "Penwell AMI"). Penwell, as operator of the prospect, has commenced an initial survey which covers 145 square miles and plans to perform a second survey covering an additional approximately 65 square miles beginning on or about July 1, 1996. South Coast Exploration also has entered into an agreement with Penwell with substantially the same terms as the Penwell Agreement. Under the Penwell Agreement, the Company paid $372,380 to purchase a 7.5% participation interest in the 3-D seismic survey and exploration program to be conducted by Penwell. Additionally, HarCor paid Penwell $231,000 for its estimated share of phase one survey costs and $99,750 to be applied against projected phase two survey costs. HarCor also agreed to pay its proportionate share of all lease acquisition costs. Penwell derives its oil and gas exploration rights with respect to a substantial portion of the Penwell AMI from an agreement (the "TMP Exploration Agreement") executed on September 15, 1995, between Texaco, Meridian Oil Inc. ("Meridian") and Penwell. Under the TMP Exploration Agreement, Texaco contributed its mineral rights underlying all or part of 117 square miles in Reeves County, Texas. In addition, Penwell has obtained control of approximately 5,529 acres to date through either leasehold or seismic options within the Penwell AMI. Under the TMP Exploration Agreement, Texaco and Meridian granted Penwell the exclusive right for three years to conduct a 3-D survey and exploration program within the area of mutual interest established by the TMP Exploration Agreement (the "Texaco AMI"). Under the TMP Exploration Agreement, Penwell is obliged to conduct a 3-D survey over a 50 square mile block in the first year and over one additional 50 square mile block during the subsequent two years of the Agreement term. By conducting a 3-D survey over Texaco's mineral fee lands, Penwell earns the right to receive an oil and gas lease covering 100% of the working interest in all depths above approximately 7,500 feet under all lands surveyed by Penwell. After identifying prospects at depths below 7,500 feet within the Texaco AMI, Penwell has the right to drill exploratory wells to such depths. If an exploratory well is successful, Penwell earns 100% of the working interest to all depths below approximately 7,500 feet in the proration unit for such well until well payout and a 65% working interest in such well after payout and in the surrounding lands. At well payout, Texaco and Meridian have the right to reacquire a 35% working interest in the proration unit for such exploratory well. Penwell holds a 65% working interest in any development wells drilled on the Texaco mineral fee lands as a result of a successful exploratory well. 39 40 SOUTH LOUISIANA AGREEMENTS In February 1996, South Coast Exploration and its affiliate entered into an exploration agreement dated February 19, 1996 (the "Louisiana Exploration Agreement") with Polaris Exploration Corporation ("Polaris"), Frontier Natural Gas Corporation ("Frontier"), Matagorda Production Company ("Matagorda"). The Louisiana Exploration Agreement established an area of mutual interest (the "Louisiana AMI") covering approximately 46 square miles in Terrebonne Parish, Louisiana for the purpose of conducting 3-D seismic surveys, securing additional leases and initiating drilling activities on oil and gas prospects. Pursuant to the Louisiana Exploration Agreement, South Coast Exploration and its affiliate have a 40% participation interest in oil and gas leases and seismic option support agreements initially covering approximately 5,529 acres. From its interest in the Louisiana Exploration Agreement, South Coast Exploration and its affiliate assigned to the Company a 12% interest in the Louisiana Exploration Agreement. This assignment, however, is subject to the approval of Polaris, Frontier and Matagorda and the waiver of certain preferential purchase rights. If the assignment is approved and all preferential purchase rights are waived, the Company will be entitled to a 12% participation in all leasehold interests acquired, all earning agreements entered into, and all geological and geophysical information generated by, Polaris and Frontier (as designated prospect generators) pursuant to the Louisiana Exploration Agreement. The Company will be obligated to pay 12% of all costs and liabilities related to such operations. The Louisiana Exploration Agreement terminates three years from the date when the last of the 3-D data taken from the prospect area has been processed and delivered to the parties to the agreement. SELECTIVE OPPORTUNISTIC ACQUISITIONS The Company also intends to pursue selective strategic acquisitions of attractively priced, underexploited onshore oil and gas properties in the United States. As a consequence of its working relationship with South Coast Exploration, the Company will also pursue property acquisitions where it can utilize 3-D seismic and CAEX technology to identify additional potential reserves. Management intends to continue to be active in developing acquisition opportunities rather than pursuing opportunities in the auction market. Management believes that this strategy has resulted in lower acquisition prices for its oil and gas properties. PRODUCTION BY GEOGRAPHIC REGION The following table shows, for the periods indicated, the net production, measured in Bbls of oil, Mcf of gas and BOEs, attributable to the Company's oil and gas interests by geographic region:
1993 1994 1995 ------------------------------- ------------------------------- --------------------------------- BBLS MCF BOE BBLS MCF BOE BBLS MCF BOE ------- --------- ------- ------- --------- ------- ------- --------- --------- San Joaquin Basin(1)..... -- -- -- 131,368 1,315,321 350,588 304,193 3,216,841 840,333 Permian Basin............ 86,006 204,907 120,157 91,404 161,187 118,269 95,966 152,386 121,364 South Texas.............. 26,481 1,272,867 238,626 28,630 1,446,404 269,697 14,098 1,411,708 249,382 Other.................... 66,748 507,029 151,253 60,429 402,729 127,551 48,276 356,144 107,633 ------- --------- ------- ------- --------- ------- ------- --------- --------- Total............ 179,235 1,984,803 510,036 311,831 3,325,641 866,105 462,533 5,137,079 1,318,712 ======= ========= ======= ======= ========= ======= ======= ========= =========
FIRST QUARTER 1995 FIRST QUARTER 1996 ----------------------------------- ----------------------------------- BBLS MCF BOE BBLS MCF BOE ------- --------- ------- ------- --------- ------- San Joaquin Basin(1)........................ 71,653 727,665 192,930 120,239 1,250,535 328,661 Permian Basin............................... 24,411 35,423 30,315 24,170 37,450 30,411 South Texas................................. 2,854 315,878 55,500 3,229 366,114 64,248 Other....................................... 12,601 78,435 25,674 10,554 77,517 23,474 ------- --------- ------- ------- --------- ------- Total..................................... 111,519 1,157,401 304,419 158,192 1,731,616 446,794 ======= ========= ======= ======= ========= =======
- --------------- (1) Excludes NGLs. 40 41 The following table summarizes the Company's producing and shut-in wells and producing acreage as of March 31, 1996:
GROSS UNDEVELOPED WELLS(1) NET WELLS(2) PRODUCING ACREAGE ACREAGE - ------------- ------------- ------------------ ------------------ OIL GAS OIL GAS GROSS NET GROSS NET - --- --- --- --- ------ ----- ------ ----- 352 79 168 19 30,852 7,626 19,618 7,217 === == === === ====== ===== ====== =====
- --------------- (1) The number of gross wells and acreage shown equals the total number of wells or acres in which a working interest is owned. (2) The number of net wells or acres shown equals the sum of the fractional working interests owned in gross wells or acres, expressed as whole numbers. PRODUCTION, REVENUES AND LIFTING COSTS The following table shows, for the periods indicated, the average net daily production, measured in Bbls of oil and Mcf of gas, attributable to the Company's oil and gas interests, the annual revenues derived by the Company from the sale of such production, the weighted average selling price per unit and the weighted average cost to the Company per unit produced:
THREE MONTHS ENDED YEAR ENDED DECEMBER 31, MARCH 31, ---------------------------- ------------------ 1993 1994 1995 1995 1996 ------ ------- ------- ------- ------- (DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER UNIT DATA) Average Net Daily Production: Crude oil and condensate (Bbls)............. 505 867 1,267 1,239 1,758 Natural gas (Mcf)........................... 5,514 9,239 14,074 12,860 19,240 Plant NGLS.................................. -- 261 567 412 692 Revenues: Crude oil and condensate.................... $2,951 $ 4,925 $ 7,625 $ 1,801 $ 2,741 Natural gas................................. 3,518 6,045 8,405 1,883 3,215 Gas plant................................... -- 1,978 6,362 1,785 1,624 Other....................................... 38 12 -- 15 17 ------ ------- ------- ------- ------- Total revenues................................ $6,507 $12,960 $22,392 $ 5,484 $ 7,597 ====== ======= ======= ======= ======= Costs: Production costs............................ $2,249 $ 3,610 $ 5,263 $ 1,263 $ 1,437 Gas plant operating expenses................ -- 1,708 3,704 1,410 956 ------ ------- ------- ------- ------- Total costs................................... $2,249 $ 5,318 $ 8,967 $ 2,673 $ 2,393 ====== ======= ======= ======= ======= Weighted average selling price: Crude oil and condensate (per Bbl).......... $16.46 $ 15.79 $ 16.49 $ 16.15 $ 17.33 Natural gas liquids (per Bbl)............... $ -- $ 13.95 $ 16.06 $ 16.73 $ 18.16 Natural gas (per Mcf)....................... $ 1.77 $ 1.82 $ 1.64 $ 1.62 $ 1.86 Production costs per BOE (1).................. $ 4.41 $ 4.13 $ 3.99 $ 4.14 $ 3.22
- --------------- (1) Includes severance and ad valorem taxes and excludes gas plant costs. Calculation of average selling price per barrel of crude oil and condensate excludes certain revenues attributable to hydrocarbon liquids and product sales in 1993 and 1994. All average price data consider the effects of the Company's fixed-price sales and hedging contracts. See Note 10 of Notes to Consolidated Financial Statements. 41 42 DRILLING ACTIVITIES The following table shows the gross and net number of exploratory and development wells drilled in the years indicated and the Company's interests therein:
1993 1994 1995 -------------- --------------- --------------- GROSS NET GROSS NET GROSS NET ----- ---- ----- ----- ----- ----- Exploratory: Oil................................. -- -- -- -- -- -- Gas................................. -- -- -- -- -- -- Dry................................. -- -- -- -- -- -- Development: Oil................................. 10 0.74 14 10.50 44 33.00 Gas................................. 4 1.37 2 .60 1 .28 Dry................................. -- -- -- -- -- -- ----- ---- ----- ----- ----- ----- Total....................... 14 2.11 16 11.10 45 33.28 ==== ==== ==== ===== ==== =====
RESERVES The Company's net proved reserves and the standardized measure of discounted future net cash flows from such proved reserve quantities are shown in the table below.
TOTAL PROVED RESERVES AS OF DECEMBER 31, -------------------------------- 1993 1994 1995 ------- ------- -------- (DOLLARS IN THOUSANDS) Estimated proved reserves: Liquids (MBbl)..................................... -- 2,908 2,979 Crude oil (MBbl)................................... 1,724 10,581 12,358 Natural gas (MMcf)................................. 17,169 69,802 87,637 Crude oil equivalents (MBOE)....................... 4,586 25,123 29,943 Pre-tax SEC 10 Value................................. $20,780 $86,680 $124,498 Percent Proved Undeveloped Reserves (BOE)............ 39.8% 67.4% 69.4%
The majority of the Company's oil and gas interests is held through mineral leases which are maintained in effect by current production and will continue to remain in effect so long as there is production of oil and gas in commercial quantities from such interests. PRINCIPAL CUSTOMERS The following purchasers accounted for more than 10% of the Company's oil and gas revenues in at least one of the years as indicated:
CUSTOMER 1993 1994 1995 ---------------------------------------------------------------- ---- ---- ---- Cabot Oil and Gas Marketing..................................... 36% 21% -- Kern Oil and Refining........................................... -- 17% 10% Mock Resources, Inc............................................. -- -- 24% Valero Gas Marketing, L.P....................................... -- -- 10%
The Company considers its relationships with the other principal purchasers to be satisfactory. The Company believes that the loss of any present customer would not have a material adverse effect on the Company's consolidated business. 42 43 SALES, MARKETS AND MARKET CONDITIONS With the exception of the gas produced from the San Joaquin Basin properties, all of HarCor's production is generally sold at the wellhead or from on-site storage facilities to oil and gas purchasing companies in the areas where it is produced. Crude oil and condensate are typically sold at prices which are based upon posted field prices. The natural gas produced from the San Joaquin Basin properties is processed at the gas processing plant in which the Company has a 75% interest. The NGLs which are extracted are sold in the spot market. Including the natural gas remaining after extraction of the NGLs, approximately 76% of HarCor's 1995 natural gas production was subject to fixed-price contracts. The remainder of the Company's natural gas was sold at spot market prices. The term "spot market" as used herein refers to contracts with a term of six months or less or contracts which call for a redetermination of sales prices every six months or earlier. For much of the past decade, the markets for oil and natural gas have been volatile. The Company anticipates that such markets will continue to be volatile over the next year. As an independent oil and gas company, the Company's revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and gas, which are in turn dependent upon numerous factors beyond the Company's control, such as economic, political and regulatory developments and competition from other sources of energy. A substantial or extended decline in oil and gas prices could have a material adverse effect on the Company's financial position, results of operations, quantities of oil and gas reserves that may be economically produced and access to capital. Price fluctuations in the oil market have a significant impact on the Company's business because all of the Company's oil production is sold at prices based upon posted field prices which vary monthly. In order to minimize the price volatility to which the Company is subject, the Company entered into hedging contracts with third parties covering significant portions of its oil production in 1995. Additionally, price fluctuations in the gas market also have a significant impact on the Company's business because approximately 24% of the Company's 1995 natural gas production was sold at spot market prices and the Company currently anticipates that approximately 36% of HarCor's estimated natural gas production for 1996 will be sold at spot market prices based on contracted volumes at December 31, 1995. The remainder of the Company's gas production is subject to certain fixed-price contracts. For further information concerning the Company's fixed-price sales and hedging contracts, see Note 9 of Notes to Consolidated Financial Statements. The Company's business is typically seasonal in nature. The demand for the Company's oil and gas production generally increases during the winter months. Gas prices in particular have been sensitive to weather patterns in recent years. Weather conditions at certain times of the year can also affect the operations of the Company's oil and gas properties and its ability to produce hydrocarbons in commercially marketable quantities. COMPETITION The acquisition, exploration and development of oil and gas properties is a highly competitive business. Many companies and individuals are engaged in the business of acquiring interests in and developing onshore oil and gas properties in the United States. The industry is not dominated by any single competitor or a small number of competitors. Many entities with which the Company competes have significantly greater financial resources, staff and experience. The Company competes with major and independent oil and gas companies for the acquisition of desirable oil and gas properties, as well as for the equipment and labor required to operate and develop such properties. Many of these competitors have financial and other resources substantially in excess of those available to the Company. Such competitive disadvantages could adversely affect the Company's ability to acquire desirable prospects or develop existing prospects. REGULATION General. The Company's business is affected by governmental laws and regulations, including price control, energy, environmental, conservation, tax and other laws and regulations relating to the petroleum industry. For example, state and federal agencies have issued rules and regulations that require permits for the 43 44 drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and crude oil reserves through proration, and regulate environmental and safety matters including restrictions on the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limits or prohibitions on drilling activities on certain lands lying within wetlands and other protected areas, and remedial measures to prevent pollution from current and former operations. Changes in any of these laws, rules and regulations could have a material adverse effect on the Company's business. In view of the many uncertainties with respect to current laws and regulations, including their applicability to the Company, the Company cannot predict the overall effect of such laws and regulations on future operations. The Company believes that its operations comply in all material respects with all applicable laws and regulations and that the existence of such laws and regulations have no more restrictive effect on the Company's method of operations than on other similar companies in the industry. The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by reference thereto. Regulation of the Sale and Transportation of Oil and Natural Gas. Various aspects of the Company's oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted and by certain agencies of the federal government for operations on federal leases. The Federal Energy Regulatory Commission (the "FERC") regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). In the past, the federal government has regulated the prices at which oil and gas could be sold. Currently, sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids can be made at uncontrolled market prices, but Congress could reenact price controls at any time. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act which removed all NGA and NGPA price and nonprice controls affecting wellhead sales of natural gas effective January 1, 1993. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, and 636-B ("Order No. 636"), which require interstate pipelines to provide open-access transportation on a basis that is equal for all gas shippers. Although Order No. 636 does not directly regulate the Company's activities, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Company's activities. Although, Order No. 636, assuming it is upheld in its entirety, could provide the Company with additional market access and more fairly applied transportation service rates, Order No. 636 could also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of those tolerances. The FERC has issued final orders in virtually all Order No. 636 pipeline restructuring proceedings. Appeals of Order No. 636, as well as orders in the individual pipeline restructuring proceedings, are currently pending and the Company cannot predict the ultimate outcome of court review. This review may result in the reversal, in whole or in part, of Order No. 636. The FERC has clarified that it does not have jurisdiction over natural gas gathering facilities and services and that such facilities and services are properly regulated by state authorities. As a result, natural gas gathering may receive greater regulatory scrutiny by state agencies. The Company's gathering operations could be adversely affected should they be subject in the future to state regulation of rates and services, although the Company does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. In addition, the FERC has approved several transfers by interstate pipelines of gathering facilities to unregulated gathering companies, including pipeline affiliates. This could allow such companies to compete more effectively with independent gatherers, such as the Company. The Company's natural gas gathering operations are generally subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of facilities. Pipeline safety issues have recently become the subject of increasing focus in various political and administrative arenas at both the state and federal levels. For example, federal legislation addressing pipeline safety issues has recently been introduced before Congress. Among other things, the legislation includes a 44 45 requirement that states adopt "one-call" notification systems. The Company cannot predict what effect, if any, the adoption of such legislation might have on its operations. The FERC has announced its intention to reexamine certain of its transportation-related policies, including the manner in which interstate pipeline shippers may release interstate pipeline capacity under Order No. 636 for resale in the secondary market. While any resulting FERC action would affect the Company only indirectly, the FERC's current rules and policies may have the effect of enhancing competition in natural gas markets by, among other things, encouraging non-producer natural gas marketers to engage in certain purchase and sale transactions. The Company cannot predict what action the FERC will take on these matters, nor can it accurately predict whether the FERC's actions will achieve the goal of increasing competition in markets in which the Company's natural gas is sold. However, the Company does not believe that it will be affected by any action taken materially differently than other natural gas producers and marketers with which it competes. The FERC has issued a policy statement on how interstate natural 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. 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 would generally index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting crude oil, liquids and condensates by pipeline. These regulations are subject to pending petitions for judicial review. The Company is not able to predict with certainty what effect, if any, these regulations will have on it, but other factors being equal, the regulations may tend to increase transportation costs or reduce wellhead prices for such conditions. Additional proposals and proceedings that might affect the oil and gas industry are pending before Congress, the FERC and the courts. The Company cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry historically has been very heavily regulated. There is no assurance that the current regulatory approach pursued by the FERC will continue indefinitely into the future. Notwithstanding the foregoing, it is not anticipated that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of the Company. Taxation. The operations of the Company, as is the case in the petroleum industry generally, are significantly affected by federal tax laws, including the Tax Reform Act of 1986. Certain transactions which were entered into in connection with the Company's 1987 recapitalization have, under the Tax Reform Act of 1986, significantly limited the Company's ability to utilize its net operating losses arising prior to the recapitalization. In addition, certain 1992 equity transactions resulted in additional restrictions on the utilization of net operating losses arising since 1987. For further information on the limitations of the Company's net operating loss carryforwards, see Note 10 of Notes to Consolidated Financial Statements contained herein. In addition to the foregoing, federal, as well as state tax laws have many provisions applicable to corporations in general which could affect the potential tax liability of the Company. Operating Hazards and Environmental Matters. The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases or naturally occurring radioactive materials, the occurrence of any of which 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 45 46 penalties and suspension of operations. Such hazards may hinder or delay drilling, development and on-line production operations. Extensive federal, state and local laws and regulations govern oil and natural gas operations regulating the discharge of materials into the environment, restoration of surface locations, plugging and abandonment of wells or otherwise relating to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose "strict liability" for environmental contamination, rendering a person liable for environmental damages and response costs without regard to negligence or fault on the part of such person. For example, the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, also known as the "Superfund" law, imposes strict liability of an owner and operator of a facility or site where a release of hazardous substances into the environment has occurred and companies that disposed or arranged for the disposal of the hazardous substances released at the facility or site. Other 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 natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect the operations and costs of the Company. While compliance with environmental requirements generally could have a material adverse effect upon the capital expenditures, earnings or competitive position of the Company, the Company believes that other independent energy companies in the oil and gas industry likely would be similarly affected. The Company believes that it 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. Although the Company maintains insurance against some, but not all, of the risks described above, including insuring the costs of clean-up operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future or that such insurance will be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on the Company's financial condition and operations. EMPLOYEES At March 31, 1996, the Company had 11 full-time employees. The Company believes its relationship with its employees is satisfactory. The Company also employs technical consultants from time to time. HarCor is not materially dependent on any of such consultants. LEGAL PROCEEDINGS No material lawsuits are pending or, to the best of the Company's knowledge, have been threatened against it. Due to the nature of its business, however, the Company, from time to time, may be a party to certain legal or administrative proceedings arising in the ordinary course of its business. OFFICE FACILITIES The Company's corporate headquarters are located at Five Post Oak Park, Suite 2220, Houston, Texas in rented office space. 46 47 MANAGEMENT DIRECTORS AND EXECUTIVE OFFICERS The names and ages of the Company's executive officers and directors, the principal occupation or employment of each of them during the past five years and at present, the name and principal business of the corporation or other organization, if any, in which such occupation or employment is or was carried on, directorships of other public companies or investment companies held by them, and the period during which the directors have served in that capacity with the Company are set forth below.
PRESENT POSITION DIRECTOR TERM AS DIRECTOR NAME AGE WITH THE COMPANY SINCE EXPIRES - ------------------------------ --- ---------------------------------- -------- ---------------- Mark G. Harrington............ 43 Chairman of the Board and Chief 1987 1998 Executive Officer Francis H. Roth............... 58 President, Chief Operating Officer 1989 1998 and Director Gary S. Peck.................. 43 Vice President -- Finance, Chief -- -- Financial Officer and Secretary Albert J. McMullin............ 39 Vice President -- Land, Contracts -- -- and Acquisitions Robert J. Cresci.............. 52 Director 1994 1999 Vinod K. Dar.................. 45 Director 1992 1997 David E. K. Frischkorn, Jr.... 45 Director 1992 1997 Ambrose K. Monell............. 41 Director 1987 1999 Herbert L. Oakes.............. 49 Director 1992 1998 Robert A. Shore............... 49 Director 1994 1997
Mr. Harrington has been Chairman of the Board of Directors and Chief Executive Officer of the Company since May 1987. He also is President and controlling shareholder of Harrington and Company International Incorporated ("Harrington and Company"), an investment company which he founded in 1986. Harrington and Company is the general partner, managing partner or limited partner of several limited partnerships which in the aggregate own approximately 7.9% of the outstanding Common Stock. In 1977, he joined Carl H. Pforzheimer and Co., an investment banking firm, where he became a partner in 1980 and remained as a partner until December 1985. During his eight years with Carl H. Pforzheimer and Co., he worked in the firm's research and corporate finance departments. In 1984, Mr. Harrington helped organize Chipco Energy Corporation, the holding company for the firm's oil and gas assets. He is a director of HCO Energy Ltd. and Jefferson Gas Systems, Inc. Mr. Harrington holds a Bachelor of Business Administration degree and a Master of Business Administration degree, both in finance, from the University of Texas. Mr. Roth has been President and Chief Operating Officer of the Company since March 1989. Prior to that time, he served as Vice President -- Production of the Company since July 1988. He has been employed in various engineering positions with both Amoco and Chevron in several geographic locations. Prior to joining the Company, he had been employed for 16 years by MCO Resources, Inc., an oil and gas company, in various positions, including General Manager of Operations and Engineering. He also served as Vice President of Drilling and Production and Engineering for MCOR Oil and Gas Corporation, a subsidiary of MCO Resources, Inc. Mr. Roth holds a Bachelor of Science degree in petroleum engineering from the University of Kansas, a Master of Science degree in petroleum engineering from the University of Oklahoma and a Master of Business Administration degree from the University of California. Mr. Peck joined the Company as Vice President -- Finance and Chief Financial Officer in October 1989 and became Secretary in November 1989. Prior to joining the Company, Mr. Peck acted as a financial consultant to the Company. Mr. Peck was Director of Finance for Herbert L. Farkas Company (a multi-location furniture and business equipment concern) from 1987 to 1989 and was Vice President -- Finance and 47 48 Chief Financial Officer of RAWA, Inc. (a franchising and car rental company) from 1985 to 1987. Prior to that, Mr. Peck had approximately seven years' experience in oil and gas accounting management with Minoco Southern Corporation and MCO Resources, Inc. He graduated from California State University at Long Beach in 1977 with a Bachelor of Science degree in accounting and finance. Mr. McMullin joined the Company as Vice President -- Land, Contracts and Acquisitions in August 1992. Prior to joining the Company, Mr. McMullin was a gas supply manager for Mitchel Marketing Company since 1991 and for Delhi Gas Pipeline Corporation during 1990. Mr. McMullin also worked as an Accounts Manager for United Gas Pipeline from 1987 to 1989. From 1980 to 1985, Mr. McMullin worked for Atlantic Richfield Company as a landman. He holds a Bachelor of Arts degree in petroleum land management from the University of Texas and earned a Masters in Business Administration from the University of St. Thomas. Mr. Cresci has served as a Managing Director of Pecks Management Partners Ltd., an investment management firm, since September 1990. From 1985 to 1990 Mr. Cresci was Vice President of Alliance Capital Management L.P. Mr. Cresci currently serves as a director of Serv-Tech, Inc., EIS International, Inc., Sepracor, Inc., Vestro Natural Foods, Inc., Olympic Financial, Ltd., GeoWaste, Inc., Hitox, Inc., Natures Elements, Inc., Garnet Resources Corporation, Meris Laboratories, Inc. and several private companies. Mr. Dar has been President and Chairman of Jefferson Gas Systems, Inc. (a natural gas and electric power co-investment concern) since May 1991, and the Managing Director of Dar & Company (a consulting firm to energy companies and financial institutions) since August 1990. Currently, he is Senior Advisor of RCG/Hagler, Bailly & Company, an international management consulting firm he helped found in 1980. He was also the Chairman of Sunrise Energy Services, Inc. between 1992 and 1994. Since 1980, Mr. Dar has held a variety of executive positions in the natural gas industry and with management consulting firms. He has been the Senior Vice President of American Exploration Company, an oil and gas firm, and Executive Vice President and Director of Hadson Corporation, a diversified public company. He was the founder and Chief Executive Officer of four major Hadson subsidiaries, Hadson Gas Systems, Hadson New Mexico, Hadson Liquid Fuels and Hadson Electric. He has a Bachelor of Science degree in engineering and a Master's degree in management and finance from MIT, where he also received his doctoral training in economics. See "Transactions with Related Parties." Mr. Frischkorn is a financial consultant to the oil and gas industry. From January 1993 through March 1996, he was Senior Vice President and Managing Director of the Energy Corporate Finance Department of Rauscher Pierce Refsnes, Inc., an investment banking firm. From 1988 to 1992, he was President of Frischkorn & Co., a Houston, Texas-based merchant banking firm specializing in oil and gas corporate finance services. Prior to that he served as Vice President, Energy Group of Kidder, Peabody & Co. in Houston, Texas and Senior Vice President, Corporate Finance of Rotan Mosle, Inc. in Houston. He holds a Bachelor of Arts degree in economics and German from Tufts University and a Masters of Business Administration from Columbia. Mr. Monell has been Vice President and a director of Harrington and Company since 1986. He has been active in the oil and gas industry since 1976. In 1976, he co-founded Alexander & Ambrose Oil Corporation, a privately-held Denver-based exploration company. He graduated from the University of Virginia in 1976 with a Bachelor of Science degree in foreign affairs. Mr. Oakes is Managing Director and a principal of Oakes, Fitzwilliams & Co. Limited, a member of the London Stock Exchange, which he founded in 1987. In 1973, he joined Dillon, Read & Co. Inc., an investment banking firm, in London. In 1982, he formed H. L. Oakes & Co. Limited specializing in arranging venture and development capital for U.S. and U.K. corporations. He is a director of Shared Technologies, Inc., The New World Power Corporation and a number of private corporations in the U.S. and the U.K. 48 49 Mr. Shore was founder and has been Chief Executive Officer of Bakersfield Energy Resources, Inc. since 1990. He is responsible for evaluating and negotiating acquisitions, and planning the development of oil and gas properties for Bakersfield Energy Resources, Inc. For 20 years prior to founding Bakersfield Energy Resources, Inc., Mr. Shore held various engineering, supervisory and management positions with Mission Resources, Texaco Inc. and Getty Oil Company in California. Mr. Shore holds a Bachelor of Science degree in petroleum engineering from Stanford University. He is a member of the American Petroleum Institute, the Society of Petroleum Engineers and the California Independent Petroleum Association. Mr. Shore also serves as a Director of the Stanford University Petroleum Investment Fund. COMMITTEES AND MEETINGS OF THE BOARD OF DIRECTORS The Board of Directors has established an Audit Committee and a Stock Option and Compensation Committee. An Executive Committee was terminated subsequent to the 1995 Annual Meeting. The Company does not have a nominating committee. The current members of the Audit Committee are David E. K. Frischkorn, Jr. and Herbert L. Oakes, Jr. The responsibilities of the Audit Committee include reviewing the scope and results of audits by the Company's independent auditors, the Company's compliance with all accounting and financial reporting requirements, the Company's internal accounting controls, the scope of other services performed by independent auditors, and the cost of all accounting and financial services, and to make recommendations to the Board of Directors as to the appointment of the Company's independent auditors. The Audit Committee held one meeting during 1995. The current members of the Stock Option and Compensation Committee are Vinod K. Dar and Herbert L. Oakes. The functions of the Stock Option and Compensation Committee are to monitor the Company's executive compensation plans, practices and policies, including all salaries, bonus and stock option awards and fringe benefits, and to make recommendations to the Board of Directors as to changes in existing executive compensation plans and the formulation and adoption of new executive compensation plans. The Stock Option and Compensation Committee held two meetings during 1995. During the year ended December 31, 1995, the Board of Directors held five meetings. In 1995, each incumbent director attended at least 75% of the aggregate of the total number of meetings of the Board of Directors and the total number of meetings held by all committees on which he served (in each case held during the periods that he served). COMPENSATION OF DIRECTORS During 1995, nonemployee members of the Board of Directors received annual compensation of $10,000 plus $1,000 for each meeting of the Board of Directors attended in person ($250 per telephonic meeting) and reimbursement for their reasonable expenses incurred in connection with their duties and functions as directors. Directors of the Company who are also employees do not receive any compensation for their services as directors. On October 14, 1992, the Board of Directors adopted the Company's 1992 Nonemployee Directors' Stock Option Plan (the "Directors' Option Plan"). Under the Directors' Option Plan, upon the later of the effective date of the Directors' Option Plan or the date of their initial election or appointment to the Board of Directors, directors who are not employees of the Company were granted options to purchase 20,000 shares of Common Stock at an exercise price equal to the fair market value of the Common Stock on the date of grant. Thereafter, and so long as the Directors' Option Plan is in effect, upon the completion of each full year of service on the Board of Directors, each nonemployee director continuing to serve as a director will automatically be granted an additional option to purchase 5,000 shares of Common Stock at an exercise price equal to 110% of the fair market value of the Common Stock on the date of grant. All options granted under the Directors' Option Plan vest in equal parts over two years. Upon the first anniversary of their election to the Board of Directors effective (July 6, 1995), Messrs. Cresci and Shore were each automatically granted options to purchase 5,000 shares of common stock 49 50 at an exercise price of $3.7125 per share which was equal to 110% of the fair market value of the common stock on such date. Upon completion of each of their third full year of service after the effective date of the Directors' Option Plan (October 14, 1995), Messrs. Dar, Frischkorn and Monell were each automatically granted options to purchase 5,000 shares of Common Stock at an exercise price equal to $3.1625 per share, 110% of the fair market value of the Common Stock on such date. Upon the third anniversary of his initial election to the Board of Directors (November 17, 1995), Mr. Oakes was automatically granted options to purchase 5,000 shares of Common Stock at an exercise price equal to $2.6125 per share, 110% of the fair market value of the Common Stock on such date. EXECUTIVE COMPENSATION The following table sets forth certain information regarding compensation earned during 1995 by the Company's Chief Executive Officer and each of the Company's two other most highly compensated executive officers (collectively, the "Named Executive Officers") based on salary and bonus earned in 1995: SUMMARY COMPENSATION TABLE
LONG-TERM AWARDS ANNUAL COMPENSATION ---------- -------------------------------------- SECURITIES ALL OTHER NAME AND OTHER ANNUAL UNDERLYING COMPENSATION PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION(1) OPTIONS(2) (3) - --------------------------- ---- -------- ------- --------------- ---------- ------------ Mark G. Harrington......... 1995 $190,000 $70,417 $ -- 50,000 $3,699 Chairman of the Board 1994 190,000 62,500 -- 148,750 3,699 and Chief Executive 1993 190,000 17,917 -- 40,000 3,455 Officer Francis H. Roth............ 1995 125,000 70,208 -- 18,000 5,113 President and Chief 1994 125,000 -- -- 75,625 5,113 Operating Officer 1993 125,000 30,209 -- 25,000 4,779 Gary S. Peck............... 1995 100,000 39,167 -- 16,000 2,306 VicePresident -- Finance, 1994 100,000 -- -- 42,500 2,306 Chief Financial Officer 1993 100,000 24,167 -- 17,500 2,156 and Secretary Albert J. McMullin......... 1995 73,770 8,026 -- 10,000 -- Vice President -- Land, 1994 67,000 5,025 -- 33,500 -- Contracts and Acquisitions
- --------------- (1) Does not include perquisites and other personal benefits because the value of these items did not exceed the lesser of $50,000 or 10% of reported salary and bonus of any of the Named Executive Officers. (2) No stock appreciation rights ("SARs") were granted to any of the Named Executive Officers during any of the years presented. (3) Such amounts were premiums paid by the Company for annual disability insurance for each such officer. 50 51 STOCK OPTION GRANTS DURING 1995 The following table provides details regarding stock options granted to the Named Executive Officers in 1995. The Company does not have any outstanding SARs. OPTION GRANTS IN 1995
% OF POTENTIAL TOTAL REALIZABLE VALUE AT NUMBER OPTIONS ASSUMED ANNUAL OF GRANTED EXERCISE RATES OF STOCK SECURITIES TO OR PRICE APPRECIATION UNDERLYING EMPLOYEES BASE FOR OPTION TERM OPTIONS IN PRICE ------------------- NAME GRANTED(#)(1) 1995 ($/SH)(2) EXPIRATION DATE 5%($) 10%($) - ---------------------- ------ ----- ----- ------------------ ------- ------- Mark G. Harrington.... 50,000 41.7% $2.89 September 26, 2000 $23,820 $67,215 Francis H. Roth....... 18,000 15.0% $2.63 September 26, 2000 $13,255 $28,877 Gary S. Peck.......... 16,000 13.3% $2.63 September 26, 2000 $11,782 $25,669 Albert J. McMullin.... 10,000 8.3% $2.63 September 26, 2000 $ 7,364 $16,043
- --------------- (1) Fifty percent of the options become exercisable on September 26, 1996 (the first anniversary of the date of grant), and the remaining 50% become exercisable on September 26, 1997. If the Company recapitalizes or otherwise changes its capital structure, thereafter upon any exercise of an option the optionee will be entitled to purchase, in lieu of the number and class of shares of Common Stock then covered by such option, the number and class of shares of stock and securities to which the optionee would have been entitled pursuant to the terms of the recapitalization if, immediately prior to such recapitalization, the optionee had been the holder of record of the number of shares of Common Stock then covered by such option. If there is a Corporate Change, as defined in the 1994 Stock Option Plan, then the Stock Option and Compensation Committee, acting in its sole discretion, has the following alternatives, which may vary among individual optionees: (1) accelerate the time at which options then outstanding may be exercised, (2) require the surrender to the Company by selected optionees of some or all of the outstanding options held by such optionees, in which event the Committee will thereupon cancel such options and pay to each optionee a certain amount of cash or (3) make such adjustments to the options then outstanding as the Committee deems appropriate to reflect such Corporate Change. Any adjustment provided for pursuant to this paragraph will be subject to any required stockholder action. (2) The exercise price per share with respect to the stock options granted to Messrs. Roth and Peck in 1995 is equal to the closing bid price of the Common Stock on the date of grant thereof, as quoted by the National Association of Securities Dealers, Inc. Automated Quotation System ("NASDAQ"). Pursuant to the terms of the 1994 Stock Option Plan, because Mr. Harrington is deemed to own more than 10% of the Common Stock, the exercise price per share of all options granted to him in 1995 was 110% of the closing bid price of the Common Stock on the date of grant thereof, as quoted by NASDAQ. 51 52 1995 OPTION EXERCISES AND OUTSTANDING STOCK OPTION VALUES AS OF DECEMBER 31, 1995 The following table shows the number of shares acquired by the Named Executive Officers upon their exercise of stock options during 1995, the value realized by such Named Executive Officers upon such exercises, the number of shares of Common Stock covered by both exercisable and non-exercisable stock options as of December 31, 1995 and their values at such date.
NUMBER OF SECURITIES UNDERLYING UNEXERCISED VALUE OF UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS AT SHARES DECEMBER 31, 1995 (#) DECEMBER 31, 1995 ($)(1) ACQUIRED ON VALUE --------------------------- --------------------------- EXERCISE (#) REALIZED ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE ------------ ------------ ----------- ------------- ----------- ------------- Mark G. Harrington........... -- -- 204,500 112,500 12,750 -- Francis H. Roth.............. -- -- 102,500 48,000 12,750 -- Gary S. Peck................. -- -- 101,500 31,000 23,375 -- Albert J. McMullin........... -- -- 22,500 17,500 -- --
- --------------- (1) The closing bid price of the Common Stock as quoted by NASDAQ on December 31, 1995, the date of exercise of such options, was $2.625. The value realized is calculated on the basis of the difference between the exercise price of such options and $2.625, multiplied by the number of shares of Common Stock issued upon exercise. The option price for exercisable options granted to Mr. Harrington, Mr. Roth and Mr. Peck covering 30,000, 30,000 and 55,000 shares, respectively, is $2.20 per share. The option prices for the remaining exercisable options and all of the unexercisable options are higher than $2.625 and therefore no value is ascribed to such options in the above table. RESTRICTED SHARE VALUES AS OF DECEMBER 31, 1995 The following table shows the value of restricted shares of common stock granted to the Named Executive Officers as of December 31, 1995:
NUMBER AND VALUE OF RESTRICTED SHARES AT DECEMBER 31, 1995 ---------------------------- NAME SHARES(#)(1) VALUE($)(2) ----------------------------------------------------------- ------------ ----------- Mark G. Harrington......................................... 23,750 62,344 Francis H. Roth............................................ 15,625 41,016 Gary S. Peck............................................... 12,500 32,816 Albert J. McMullin......................................... 8,500 22,312
- --------------- (1) The Restricted Shares may not be sold, tendered, assigned, transferred, pledged or otherwise encumbered prior to the earliest of April 28, 1997 (lapse date), the date of a grantee's death or disability, or the date of a "Change of Control" of the Company, as defined in the Restricted Stock Agreement. In the event that a grantee terminates employment with the Company prior to the lapse date, the Restricted Shares shall revert back to the Company; provided, however, in the event a grantee is involuntarily terminated for any reason other than cause, the Compensation Committee of the Board of Directors of the Company administering this Agreement may, at its sole discretion, determine to release a prorated number of Restricted Shares, based on the number of months of active employment service during the restriction period, as a percentage of the total months of the restriction period. (2) The value of Restricted Shares at December 31, 1995 is calculated by multiplying the number of Restricted Shares by the December 31, 1995 closing bid price of the common stock as quoted by NASDAQ, which was $2.625 per share. DIRECTOR AND OFFICER LIABILITY; INDEMNIFICATION The Company's Certificate of Incorporation (the "Certificate") states that directors of the Company shall not be personally liable to the Company or its stockholders for monetary damages for breach of fiduciary 52 53 duty as a director, provided, however, that the Certificate does not eliminate or limit the liability of a director (i) for any breach of his duty of loyalty to the Company or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of the law, (iii) under Section 174 of the General Corporation Law of the State of Delaware ("Delaware GCL"), or (iv) for any transaction from which the director derived an improper personal benefit. In addition, these provisions do not eliminate the liability of a director for violations of federal securities laws, nor do they limit the rights of the Company or its stockholders, in appropriate circumstances, to seek equitable remedies such as injunctive or other forms of non-monetary relief. Such remedies may not be available in all cases. The Company's By-laws (the "By-laws") further provide that each person who was or is made a party or is threatened to be made a party to or is involved in a proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he, or a person of whom he is the legal representative, is or was a director or officer of the Company or is or was serving at the request of the Company as a director or officer of another corporation, or of a partnership, joint venture, trust or other enterprise, shall be indemnified and held harmless by the Company to the fullest extent authorized by the Delaware GCL; provided, however, that, except as provided below the Company shall indemnify any person seeking indemnity in connection with an action, suit or proceeding (or part thereof) initiated by such person only if such action, suit or proceeding (or part thereof) was authorized by the Board of Directors of the Company. Under the Delaware GCL, directors and officers may be indemnified against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement in connection with specified actions, suits or proceedings, whether civil, criminal, administrative or investigative if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceedings, had no reasonable cause to believe their conduct was unlawful. The Company has entered into indemnification agreements (the "Agreement") with its directors which provide that in the event a director was, is or becomes a party to or witness or other participant in, or is threatened to be made a party to or witness or other participant in, any threatened, pending or completed action, suit or proceeding, or any inquiry or investigation, whether instituted by or in the name of the Company or any other party, that such director in good faith believes might lead to the institution of any such action, suit or proceeding, whether civil, criminal, administrative, investigative or other (a "Claim") by reason of (or arising in part out of) any event or occurrence related to the fact that such director is or was a director or, officer of the Company, or is or was serving at the request of the Company as a director or officer, of another corporation, partnership, joint venture, employee benefit plan, trust or other enterprise, or occurring by reason of anything done or not done by such director in any such capacity (an "Indemnifiable Event"), the Company will indemnify such director to the full extent authorized or permitted by law as soon as practicable against any and all expenses (including, without limitation, attorneys' fees and all other costs, expenses and obligations reasonably paid or incurred in connection with investigating, defending, being a witness in or participating in (including on appeal), or preparing to defend, be a witness in or participate in any Claim relating to any Indemnifiable Event) ("Expenses"), judgments, fines, penalties, taxes and any and all amounts paid in settlement (including all interest, assessments and other charges paid or payable in connection with or in respect of such Expenses, judgments, fines, penalties, taxes or amounts paid in settlement) of such Claim. The Company also has a Directors and Officers Insurance and Company Reimbursement Policy which protects directors and officers of the Company. Notwithstanding the other provision of the Agreements, to the extent that any director has served as a witness on behalf of the Company or has been successful, on the merits or otherwise, in defense of any or all Claims relating in whole or in part to any Indemnifiable Event, or in defense of any issue or matter therein, including, without limitation, dismissal without prejudice, such director will be indemnified against Expenses reasonably paid or incurred by him or on his behalf in connection therewith. 53 54 PRINCIPAL AND SELLING STOCKHOLDERS The following table sets forth information as to the number and percentage of shares of Common Stock owned beneficially as of March 26, 1996 and as adjusted to reflect the sale of Common Stock offered hereby by (i) each person known to the Company to be the beneficial owner of more than 5% of the Common Stock, (ii) each director and each executive officer, (iii) each of the Selling Stockholders (including warrantholders selling warrants to the Underwriters in connection with this Offering) and (iv) all directors and officers of the Company as a group. Unless otherwise indicated in the footnotes following the table, the named beneficial owner had sole voting and investment power over the shares of Common Stock shown as beneficially owned by them.
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP PRIOR TO OFFERING AFTER OFFERING --------------------- --------------------- NUMBER OF NUMBER OF SHARES NUMBER OF SHARES PERCENT BEING OFFERED SHARES PERCENT --------- ------- ---------------- --------- ------- Harrington and Company International Incorporated(3).................... 690,768 7.9 -- 690,768 5.0 Robert J. Cresci(4)(5)............... 1,110,000 12.7 1,100,000 10,000 * Vinod K. Dar(4)...................... 32,500 * -- 32,500 * David E. K. Frischkorn, Jr.(4)....... 27,500 * -- 27,500 * Mark G. Harrington(4)(6)............. 919,018 10.2 -- 919,018 6.5 Ambrose K. Monell(4)................. 31,421 * -- 31,421 * Herbert L. Oakes(4).................. 32,500 * -- 32,500 * Gary S. Peck(4)...................... 131,500 1.5 -- 131,500 * Francis H. Roth(4)................... 160,625 1.8 -- 160,625 1.2 Robert A. Shore(4) (7)............... 1,111,084 11.6 240,941 867,143 5.9 FMR Corp.(8)......................... 550,000 5.9 -- 550,000 3.8 Bakersfield Energy Resources, Inc.(7)(9)......................... 1,098,084 11.5 240,941 857,143 5.9 Granite Capital L.P.(10)............. 612,092 6.8 -- 612,092 4.4 Pecks Management Partners Ltd.(11)... 1,100,000 12.6 1,100,000 -- -- Trust Company of the West(12)........ 1,730,710 19.3 -- 1,730,710 12.4 Wellington Management Company(13).... 666,700 7.7 -- 666,700 4.8 All Directors and Officers as a group (10 persons)(5)(6)(7)(14).......... 3,584,148 35.2 1,340,941 2,243,207 14.7
- --------------- * Less than 1% (1) Information with respect to beneficial ownership is based on information publicly available or furnished to the Company by each person included in this table. (2) Includes, in each case, shares deemed beneficially owned by such persons or entities pursuant to Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended, because such persons or entities have the right to acquire such shares within 60 days upon the exercise of stock options or similar rights or because such persons or entities have or share investment or voting power with respect to such shares. (3) The business address of Harrington and Company International Incorporated is 4400 Post Oak Parkway, Suite 2220, Houston, Texas 77027. Such amount includes (i) 372,305 shares held by Harrington and Company EV Fund I, Ltd., and (ii) 309,868 shares held by Harrington and Company EV Fund II, Ltd. (71,429 shares of which are issuable within 60 days upon conversion of Series A Preferred Stock held by Harrington and Company EV Fund II, Ltd.), of which limited partnerships Harrington and Company International Incorporated is the general or managing partner. The shares held by each such limited partnership are also deemed to be beneficially owned by such limited partnership. Harrington and Company International Incorporated disclaims beneficial ownership of such shares. 54 55 (4) Includes 10,000, 27,500, 27,500, 204,500, 27,500, 27,500, 101,500, 27,500, 102,500 and 10,000 shares for Messrs. Cresci, Dar, Frischkorn, Harrington, Monell, Oakes, Peck, Roth and Shore, respectively, purchasable within 60 days upon the exercise of stock options. (5) Includes 1,100,000 shares deemed to be beneficially owned by Pecks Management Partners Ltd., of which Mr. Cresci is a managing director (See footnote 12). As a result, Mr. Cresci may be deemed to share voting and investment power with respect to such shares. Mr. Cresci disclaims beneficial ownership of such shares. (6) Mr. Harrington is the Chief Executive Officer and Chairman of the Board of Directors of the Company. The number of shares indicated includes 690,768 shares deemed to be beneficially owned by Harrington and Company International Incorporated (see footnote 3 above) of which Mr. Harrington is the majority stockholder, the President and a director. As a result, voting and investment power over such shares may be deemed to be shared between Mr. Harrington and Harrington and Company International Incorporated. Mr. Harrington disclaims beneficial ownership of such shares. (7) Includes 1,098,084 shares deemed to be beneficially owned by Bakersfield Energy Resources, Inc., of which Mr. Shore is the Chief Executive Officer and a director (see footnote 10). As a result, Mr. Shore may be deemed to share voting and investment power with respect to such shares. Mr. Shore disclaims beneficial ownership of such shares. Also includes 3,000 shares purchased for the benefit of Mr. Shore's daughter. Mr. Shore disclaims beneficial ownership of such shares. (8) The principal business address for FMR Corp. is 82 Devonshire Street, Boston, Massachusetts 02109. Consists of 550,000 shares issuable upon exercise of a warrant granted to Fidelity Management & Research Company ("Fidelity"), a wholly-owned subsidiary of FMR Corp., as a result of Fidelity's acting as investment advisor to various investment companies registered under the Investment Company Act of 1940. FMR Corp. disclaims sole power to vote or direct the voting of the shares owned directly by the Fidelity Funds, which power resides with the Funds' Boards of Trustees. Fidelity carries out the voting of the shares under written guidelines established by the Funds' Boards of Trustees. FMR Corp., through its control of Fidelity, and the Funds each has sole power to dispose of the 550,000 shares owned by the Funds. (9) The principal business address for Bakersfield Energy Resources, Inc. is 2131 Mars Court, Bakersfield, California 93308. Includes 857,143 shares of common stock issuable to Bakersfield Gas, L.P. upon its conversion of 30,000 shares of Series E Preferred Stock, of which limited partnership Bakersfield Energy Resources, Inc. is the general or managing partner. The shares held by such limited partnership are also deemed to be beneficially owned by such limited partnership. (10) The principal business address for Granite Capital L.P. is 126 East 56th Street, New York, New York 10022. Includes 256,400 shares of common stock issuable within 60 days upon conversion of 10,000 shares of the Series C Preferred Stock. Also includes 45,000 shares beneficially owned by an affiliate of Granite Capital L.P. and 3,000 shares beneficially owned by certain managed accounts for which Granite Capital is the investment manager and shares voting and investment power. Granite Capital L.P. disclaims beneficial ownership of such 3,000 shares. Messrs. Walter F. Harrison III and Lewis Eisenberg may be deemed to share voting and investment power with respect to the shares owned by Granite Capital L.P. Messrs. Harrison III and Eisenberg disclaim beneficial ownership of such shares. (11) The principal business address for Pecks Management Partners Ltd. is One Rockefeller Plaza, New York, New York 10020. All such shares are beneficially owned by three investment advisory clients of Pecks Management Partners Ltd. As investment manager for such clients, Pecks Management Partners Ltd. may be deemed to share voting and investment power with respect to such shares. (12) The business address of Trust Company of the West ("TCW") is 865 South Figueroa, Suite 1800, Los Angeles, CA 90017. Includes 1,474,359 shares beneficially owned by a General Mills pension fund, which shares TCW controls voting and investment power as Investment Manager and Custodian. TCW disclaims beneficial ownership of the 1,474,359 shares. Mr. Arthur R. Carlson may be deemed to have voting and investment power with respect to the shares owned by TCW. Mr. Carlson disclaims beneficial ownership of such shares. 55 56 (13) The principal business address for Wellington Management Company is 75 State Street, Boston, Massachusetts 02109. Such shares are also deemed beneficially owned by Wellington Trust Co., N.A., a subsidiary of Wellington Management Company. Mr. Binkley Shorts may be deemed to have voting and investment power with respect to such shares. Mr. Shorts disclaims beneficial ownership of such shares. (14) Includes 1,514,572 shares purchasable within 60 days upon the exercise of stock options or warrants held or deemed to be owned by all officers and directors. Holders of the Company's Series B, C and E Preferred Stock have certain voting rights, including the right to vote together with the holders of the common stock on all matters voted upon by the holders of the common stock. In all such matters, holders of the Series B, C and E Preferred Stock have the number of votes per share of such preferred stock equal to the whole number of shares of common stock into which each share of such preferred stock is convertible. The outstanding shares of Series B Preferred Stock are held by (i) Citibank, N.A., as Trustee for the United Technologies Corporation Master Retirement Trust, United Technologies Building, Hartford, Connecticut 06101 (25%), (ii) Bankers Trust Company, as Trustee of the Hughes Aircraft Company Retirement Plan, 7200 Hughes Terrace, Los Angeles, California 90045-0066 (25%), and (iii) Bankers Trust Company, as Trustee of the GTE Service Corporation Plan for Employees' Pensions, One Stamford Place, Stamford, Connecticut 06904 (50%). All of the outstanding shares of the Series C Preferred Stock are held by Granite Capital Partners, L.P., 666 Fifth Avenue, 33rd Floor, New York, New York 10103. All outstanding shares of the Series E Preferred Stock are held by Bakersfield Gas, L.P., 2131 Mars Court, Bakersfield, California 93308. TRANSACTIONS WITH RELATED PARTIES The Company completed an agreement with Bakersfield Gas, L.P. in June 1995 for the exchange of a warrant to purchase 1,000,000 shares of Common Stock for 182,500 shares of Common Stock of the Company. This warrant had an exercise price of $5.00 per share and would have expired on June 30, 2001. Robert A. Shore, one of the Company's directors, is the Chief Executive Officer of Bakersfield Energy Resources, Inc., the general partner of Bakersfield Gas, L.P. The Company completed an agreement in June 1995 with the former holders of its Series D Preferred Stock, concurrently with the completion of the sale of the Senior Notes, for the exchange of warrants to purchase 3,424,666 shares of Common Stock for 1,100,000 shares of Common Stock of the Company. These warrants had an exercise price of $3.67 per share and would have expired two years following the date of redemption of the Series D Preferred Stock. Robert J. Cresci, one of the Company's directors, is a managing director of Pecks Management Partners Ltd., the investment advisor to the former holders of its Series D Preferred Stock. Vinod K. Dar, one of the Company's directors, was the Chairman of the Board of Directors and Chief Executive Officer of Sunrise Energy Services, Inc. ("Sunrise Energy") from October 1992 to October 1994. As part of the Company's acquisition of the San Joaquin Basin properties, the Company was assigned an interest in a previously existing gas marketing contract with Sunrise Energy Marketing Company ("Sunrise Marketing"), a subsidiary of Sunrise Energy, whereby Sunrise Marketing agreed to pay $1.97 per one million British thermal units ("MMBtu") for the delivery of 2,250 MMBtu of gas per day from the San Joaquin Basin properties during June, July and August of 1994. As of December 20, 1994, Sunrise Marketing owed the Company approximately $92,000 for gas delivered by the Company during the term of such contract. On November 15, 1994, Sunrise Marketing filed a voluntary petition for protection under Chapter 11, Title 11 of the United States Bankruptcy Code. The $92,000 amount owed to the Company by Sunrise Marketing is an unsecured claim and, as such, the Company is unable to determine whether such amount will be paid and if such amount is paid in full or in part, when such amount will be paid. 56 57 DESCRIPTION OF CAPITAL STOCK AND OTHER SECURITIES COMMON STOCK The Company's total authorized capital stock consists of 25,000,000 shares of $.10 par value Common Stock and 1,500,000 shares of $.01 par value preferred stock. All of the outstanding Common Stock is fully paid and nonassessable. Each share of Common Stock is entitled to one vote at stockholders' meetings and will be equal to each other share of Common Stock with respect to voting rights, liquidation rights and dividend rights. A majority of the outstanding capital stock eligible to vote at a meeting constitutes a quorum for voting purposes. Stockholders do not have preemptive rights to purchase additional shares of Common Stock. The Common Stock has no subscription, conversion or redemption rights. Each holder of Common Stock on liquidation is entitled to receive a pro-rata share of the Company's assets available for distribution to such stockholders after the required liquidation payment is made on any outstanding shares of preferred stock. As of May 30, 1996, there were 8,696,207 shares of Common Stock outstanding and held of record by approximately 1,746 persons and 7,124,231 shares reserved for issuance upon exercise of outstanding warrants, options and convertible securities. The Company has never paid dividends on its Common Stock and, pursuant to the terms of the Senior Notes and the Credit Facility, the Company is restricted from the payment of dividends on its Common Stock. Additionally, pursuant to the terms of the Company's preferred stock, the Company is restricted from the payment of dividends on the Common Stock (except dividends paid in shares of capital stock) unless the Company is current in its payment of dividends on such preferred stock. Management intends to retain any future earnings for future acquisitions and the operations of the Company and does not anticipate paying any cash dividends in the foreseeable future. The Company currently has outstanding options to purchase 898,500 shares of Common Stock. Such options have an aggregate average exercise price of $3.34 and expire between December 31, 1995 and November 17, 2000. The Company also currently has outstanding warrants to purchase 2,289,791 shares of Common Stock. Such warrants have an aggregate average exercise price of $3.83 and expire between November 23, 1996 and July 25, 2000. In addition, the Company currently intends to grant incentive compensation in the form of warrants to purchase up to 60,000 shares of Common Stock to certain key geologists of the GeoTeam and to South Coast Exploration. The purpose of these grants is to align the interests of the GeoTeam and South Coast Exploration with those of the shareholders of the Company. Accordingly, the vesting of these warrants will depend upon the aggregate replacement and finding costs to the Company of replacing its current reserves in the South Texas, West Texas and Terrebonne Parish projects. PREFERRED STOCK As of May 30, 1996, 5,000 shares of Series A 8% Cumulative Convertible Preferred Stock (the "Series A Preferred Stock") were outstanding. The Series A Preferred Stock (i) is convertible into Common Stock at a conversion price of $3.50 per share of Common Stock, subject to certain anti-dilution provisions; (ii) is redeemable at the Company's option under certain circumstances; (iii) receives a cumulative annual dividend of 8% payable quarterly; and (iv) has a liquidation preference equal to the initial purchase price of $50 per share plus accrued but unpaid dividends thereon. The Series A Preferred Stock does not have voting rights except to the extent otherwise provided by Delaware law. The complete terms of the Series A Preferred Stock are set forth in the Certificate of Designations, Powers, Preferences and Rights of the Series A Preferred Stock. As of May 30, 1996, 20,000 and 10,000 shares of Series B Convertible Preferred Stock (the "Series B Preferred Stock") and Series C Convertible Preferred Stock (the "Series C Preferred Stock"), respectively, were outstanding. The Company's Series B and C Preferred Stock is convertible at the option of the holder into Common Stock at a conversion price of $3.90 per share of Common Stock, subject to certain anti-dilution adjustments, and will be automatically converted at the same conversion price (i) on the first date after December 31, 1996 until December 31, 1998 that the closing price per share of Common Stock has been at 57 58 least $5.85 for 20 of 30 consecutive trading days; or (ii) on December 31, 1998. If the Company merges with or consolidates into another entity (after which the stockholders of the Company own less than 50% of the voting power in the election of directors of the other corporation or entity) or is acquired or sells or otherwise conveys substantially all of its assets, or if a person or entity (other than Mark G. Harrington or an affiliate or associate thereof) acquires beneficial ownership of more than 50% of the outstanding Common Stock, the conversion price shall be adjusted to the current market price of the Common Stock if the current market price is less than the conversion price. The Company may at its option elect to redeem the Series B and C Preferred Stock at $150 per share at any time after December 31, 1994, if the market price for the Common Stock exceeds $5.85 for 20 of 30 consecutive trading days. The holders of the Series B and C Preferred Stock are entitled to receive cumulative cash dividends at the rate of $8 per share per annum. In addition, each share of Series B and C Preferred Stock entitles the holder thereof to such number of votes per share as equals the whole number of shares of Common Stock into which each share of Series B and C Preferred Stock is then convertible, and holders of Series B and C Preferred Stock are entitled to vote on all matters as to which holders of Common Stock are to vote, in the same manner and with the same effect as such holders of Common Stock, voting together with such holders of Common Stock as one class, except for certain matters in which the Series B and C have class voting rights. If at any time the Company fails to declare and pay in cash the full amount of dividends payable on any two dividend payment dates, the holders of the Series B Preferred Stock, voting separately as a class, shall be entitled to elect two directors until such time as the dividends in default have been paid in full. Furthermore, at any time while a minimum of 50% of the shares of Series B or C Preferred Stock remain outstanding, the Company may not take any action to alter or repeal its Certificate of Incorporation or Bylaws which would adversely affect the rights, privileges or powers of the Series B or C Preferred Stock (other than the issuance of additional series of stock or increases in the authorized amount of existing series of stock) without the consent or approval of, with respect to the Series B Preferred Stock, at least a majority of the voting power of the Series B Preferred Stock or, with respect to the Series C Preferred Stock, at least a majority of the voting power of the Series C Preferred Stock. The complete terms of the Series B and C Preferred Stock are set forth in the Certificates of Designations, Powers, Preferences and Rights for the Series B Preferred Stock and the Series C Preferred Stock. On June 30, 1994, the Company issued 30,000 shares of Series E Junior Convertible Preferred Stock (the "Series E Preferred Stock") to Bakersfield Gas, L.P. The purchase price of the Series E Preferred Stock was $100 per share. The Series E Preferred Stock is convertible at the option of the holder into Common Stock at a conversion price of $3.50 per share, subject to adjustment for certain stock dividends, subdivisions, reclassification or combinations with respect to the Common Stock and for certain other distributions or events of consolidation, merger or sale, lease or conveyance of all or substantially all of the assets of the Company. Bakersfield Gas, L.P. has agreed not to exercise its option to convert the shares of Series E Preferred Stock prior to the closing of the Company's first underwritten public offering of equity securities after the issuance of the Series E Preferred Stock. The Series E Preferred Stock receives a cash dividend, cumulative from the date of issuance of the Series E Preferred Stock and payable quarterly in arrears commencing on September 30, 1994, at the rate of $4 per share per annum until June 30, 1995, and thereafter at the rate of $9 per share per annum. The Company has the option of paying dividends on the Series E Preferred Stock either in cash or in shares of Common Stock. The Series E Preferred Stock is redeemable in cash at any time, in whole or in part, at the option of the Company, at a price of $110 per share, plus accrued and unpaid dividends. The Company must redeem all of the Series E Preferred Stock in cash, at a price of $110 per share plus accrued and unpaid dividends, upon completion by the Company of its first underwritten public offering of securities following the issuance of the Series E Preferred Stock in which the net proceeds received by the Company equal or exceed $20.8 million. If the proceeds from the Company's first underwritten public offering of securities following the issuance of the Series E Preferred Stock is between $17.5 million and $20.5 million, the Company must use all proceeds in excess of $17.5 million to redeem shares of the Series E Preferred Stock. Each share of Series E Preferred Stock entitles the holder thereof to such number of votes per share as equals the whole number of shares of Common Stock into which each share of Series E Preferred Stock is 58 59 then convertible, and each share of Series E Preferred Stock is entitled to vote on all matters as to which holders of Common Stock are to vote, in the same manner and with the same effect as such holders of Common Stock, voting together with the holders of Common Stock as one class, except for certain matters in which holders of the Series E Preferred Stock have class voting rights. At any time while a minimum of 50% of the shares of Series E Preferred Stock remain outstanding, the Company shall not take any action to alter or repeal its Certificate of Incorporation or Bylaws which would adversely affect the rights, privileges or powers of the Series E Preferred Stock (other than the issuance of additional series of stock or increases in the authorized amount of existing series of stock) without the consent or approval of at least a majority of the voting power of the Series E Preferred Stock. The complete terms of the Series E Preferred Stock are set forth in the Certificates of Designations, Powers, Preferences and Rights for the Series E Preferred Stock. In the event of any voluntary or involuntary liquidation, dissolution or other winding up of the affairs of the Company, before any distribution or payment will be made to the holders of the Common Stock or Series E Preferred Stock, the holders of the Series B and C Preferred Stock are entitled to be paid $100 per share for each share of outstanding Series B and C Preferred Stock, plus any accrued but unpaid dividends. If the net assets of the Company distributable among the holders of all outstanding shares of the Series A, B and C Preferred Stock is insufficient to permit the payment in full to such holders of the preferential amounts to which they are entitled, then the entire net assets of the Company will be distributed among the holders of the Series A, B and C Preferred Stock ratably in proportion to the full amounts to which they would otherwise be respectively entitled. Subject to the prior rights of the holders of Series A, B and C Preferred Stock, the Series E Preferred Stock has a liquidation preference of $100 per share plus accrued and unpaid dividends. The Board of Directors may, without further action by the stockholders (but subject to the rights of holders of the Company's preferred stock), issue additional shares of preferred stock, and, with respect to such additional shares, fix or alter dividend rights, dividend rates, conversion rights, voting rights, rights and terms of redemption (including sinking fund provisions), redemption price or prices and liquidation preferences of a wholly unissued series of preferred stock, with the designation of any such series and the number of shares to constitute any such unissued series. The Board of Directors of the Company has not created any series of preferred stock, which has not been fully redeemed, other than the Series A, B, C, E and F Preferred Stock. ANTI-TAKEOVER PROVISIONS OF THE COMPANY'S CERTIFICATE OF INCORPORATION AND BYLAWS The Company's Certificate of Incorporation and Bylaws contain provisions which could discourage certain transactions which involve an actual or threatened change in control of the Company. Such provisions are summarized below. Article XI of the Company's Certificate of Incorporation ("Article XI") establishes an advance notice procedure for the nomination, other than by or at the direction of the Board of Directors or a committee thereof, of candidates for election of directors. Notice of director nominations must be given in writing to the Secretary of the Company not less than 30 days nor more than 90 days prior to any meeting of the stockholders at which directors are to be elected; provided, however, that if fewer than 31 days notice of the meeting is given to stockholders, notice of director nominations must be given not later than the close of business on the tenth day following the day on which notice of the meeting was mailed to stockholders. Notice to the Company from a stockholder who intends to nominate a person for election as a director at a meeting must contain certain information about the proposed nominee. The director nomination for which notice was properly given may be made only in a meeting of the stockholders called for the election of directors at which the nominating stockholder is present in person or by proxy. If the presiding officer of the meeting determines that stockholder's nomination is not made in accordance with the procedures set forth in the Company's Certificate of Incorporation, such nomination, at the direction of such presiding officer, may be disregarded. Article XI requires the affirmative vote of the holders of at least 66 2/3% of the voting power of the outstanding shares of the Company to alter, amend or adopt any provision inconsistent with the advance notice procedures set forth above. Article XII of the Company's Certificate of Incorporation ("Article XII") requires the affirmative vote of the holders of not less than 66 2/3% of the Company's outstanding voting stock for the approval or 59 60 authorization of any (i) merger or consolidation of the Company with or into any other corporation, or (ii) sale, lease, exchange or other disposition of all or substantially all of the assets of the Company to or with any corporation, person or other entity; provided, however, that such 66 2/3% of the voting requirement is not applicable if (a) a majority of the outstanding shares of all classes of stock entitled to vote generally in the election of directors, considered for such purpose to be one class, of such other corporation, person or entity is owned of record or beneficially by the Company and its subsidiaries or (b) a majority of the Board of Directors of the Company has approved such transaction. Article XII further requires the vote or consent of at least 66 2/3% of the outstanding stock of the Company to amend, alter, change or repeal any of the provisions of such article. The Company's Certificate of Incorporation contains no provision expressly electing not to be governed by Section 203 of the Delaware General Corporation Law. In general, Section 203 prevents an "interested stockholder" (defined generally as any person owning, or who is an affiliate or associate of the corporation and has owned in the preceding three years, 15% or more of a corporation's outstanding voting stock and affiliates and associates of such person) from engaging in a "business combination" (as defined) with a Delaware corporation for three years following the date such person became an interested stockholder unless (i) before such person became an interested stockholder, the board of directors of the corporation approved either the business combination or the transaction in which the interested stockholder became an interested stockholder, (ii) upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the 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 the rights to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer); or (iii) on or subsequent to the date 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 two-thirds of the outstanding voting stock of the corporation not owned by the interested stockholder. Under Section 203, the restrictions described above also 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 previous three years or who became an interested stockholder with the approval of a majority of the corporation's directors. Article III, Section 2 of the Company's Bylaws provides that the Board of Directors shall be divided into three classes as nearly equal in number as possible, with terms of office expiring at different times in annual succession. The Bylaws require the affirmative vote of the holders of 66 2/3% or more of the outstanding shares of the Company's capital stock entitled to vote generally in the election of directors to amend, alter, repeal or change Article III, Section 2 of the Company's Bylaws. Additionally, the Company's Bylaws provide that, unless otherwise provided in the Company's Certificate of Incorporation, special meetings of stockholders can only be called by the President, Secretary or by a majority of the Board of Directors or the Executive Committee thereof, if any. SHARES ELIGIBLE FOR FUTURE SALE As of May 1, 1996 the Company had outstanding 8,696,207 shares of Common Stock and securities (including warrants, options and convertible preferred stock) convertible into 4,886,063 shares of Common Stock. An aggregate of 1,550,000 shares of Common Stock have been reserved for issuance under the Company's 1992 Stock Option Plan, the Company's 1992 Nonemployee Directors' Stock Option Plan and the Company's 1994 Stock Option Plan (the "Plans"), and options to purchase 898,500 of such shares have been granted. Following the consummation of the Offering, the Company will have 5,722,581 shares of Common Stock available for issuance at such times and upon such terms as may be approved by the Company's Board of Directors. No prediction can be made as to the effect, if any, that future sales or the availability of shares for sale will have on the market price of the Common Stock prevailing from time to time. Nevertheless, sales of substantial amounts of Common Stock of the Company in the public market could adversely affect the 60 61 prevailing market price of the Common Stock and could impair the Company's ability to raise capital through sales of its equity securities. After giving effect to the Offering, 2,484,148 shares of Common Stock (including shares issuable upon exercise of outstanding options and warrants and conversion of convertible securities) will be held by executive officers and directors of the Company and affiliates of the Company and may be sold pursuant to an effective registration statement covering such shares or pursuant to Rule 144 of the Securities Act, subject to the contractual restrictions described below. In general, under Rule 144, as currently in effect, a person (or persons whose shares are aggregated), including an affiliate, who has beneficially owned Restricted Shares for at least two years, is entitled to sell within any three-month period, a number of shares that does not exceed the greater of (i) 1% of the then outstanding shares of the Company's Common Stock or (ii) an amount equal to the average weekly reported volume of trading in such shares during the four calendar weeks preceding the date on which notice of such sale is filed with the Securities and Exchange Commission (the "Commission"). Sales under Rule 144 are also subject to certain manner of sale limitations, notice requirements and the availability of current public information about the Company. Restricted Shares properly sold in reliance on Rule 144 are thereafter freely tradeable without restrictions or registration under the Securities Act, unless thereafter held by an affiliate of the Company. In addition, affiliates of the Company must comply with the restrictions and requirements of Rule 144, other than the two-year holding period requirement, in order to sell shares of Common Stock which are not Restricted Shares (such as shares of Common Stock acquired by affiliates of the Company in this Offering). As defined in Rule 144, an "affiliate" of an issuer is a person that directly, or indirectly through one or more intermediaries, controls or is controlled by, or is under common control with, such issuer. If three years have elapsed since the later of the date of any acquisition of Restricted Shares from the Company or from any affiliate of the Company, and the acquiror or subsequent holder thereof is deemed not to have been an affiliate of the Company at any time during the 90 days preceding a sale, such person would be entitled to sell such shares in the public market pursuant to Rule 144(k) without regard to volume limitations, manner of sale restrictions, or public information or notice requirements. TCW has the right to demand three registrations under the Securities Act of up to 1,730,710 shares of the Company's Common Stock, of which 256,351 shares are issuable upon exercise of its warrant. ING Capital has the right to demand two registrations under the Securities Act of up to 30,000 shares of the Company's Common Stock. Bakersfield Energy has the right to demand two registrations under the Securities Act of up to 1,098,084 shares of the Company's Common Stock, of which 857,143 shares are issuable upon conversion of 30,000 shares of Series E Preferred Stock. Also, First Union has the right to demand two registrations under the Securities Act of up to 100,000 shares issuable upon exercise of their warrants dated June 30, 1994. The Series D Holders have the right to demand two registrations under the Securities Act of up to 1,100,000 shares of the Company's Common Stock. The holders of Senior Note Warrants, BT Securities and ING, also have the right to demand two registrations under the Securities Act of up to 1,780,000 shares of the Company's Common Stock. Upon any such demand, the Company, at its expense, must register the applicable shares or a portion thereof for sale. Additionally, in the event the Company registers any shares of its Common Stock (of its own accord or pursuant to the request of one of its stockholders), it must give TCW, ING Capital, Bakersfield Energy, First Union, the Series D Holders and the Senior Note Warrant Holders an opportunity to include in such registration the shares of Common Stock issued to them or issuable to them upon exercise of their warrants or preferred stock, as applicable. The Company has given such notice to each of these parties, and only Bakersfield Energy has elected to participate in the Offering to the extent of 240,941 shares of Common Stock. There can be no assurance that the holders of such rights will not exercise these registration rights in a manner and at a time which may adversely impact the market price of the Common Stock or business plans of the Company or may adversely affect the Company's efforts to seek additional capital. TRANSFER AGENT AND REGISTRAR The Transfer Agent and Registrar for the Common Stock is Chemical/Mellon Shareholders Services. 61 62 UNDERWRITING The Underwriters named below, have severally agreed, subject to the terms and conditions of the Underwriting Agreement, to purchase from the Company and the Selling Stockholders an aggregate of 6,400,000 shares of Common Stock. The number of shares of Common Stock that each Underwriter has agreed to purchase is set forth opposite their respective names below.
NUMBER OF SHARES UNDERWRITERS TO BE PURCHASED ------------ - ---------------- Rauscher Pierce Refsnes, Inc......................... 2,560,000 Petrie Parkman & Co., Inc............................ 2,560,000 Southcoast Capital Corporation....................... 1,280,000 --------- Total...................................... 6,400,000 =========
The Underwriting Agreement provides that the Underwriters' obligation to pay for and accept delivery of the shares of Common Stock offered hereby is subject to certain conditions precedent and that the Underwriters will be obligated to purchase all such shares, excluding shares covered by the over-allotment option, if any are purchased. The Company has been advised by the Underwriters that they propose initially to offer the Common Stock to the public at the public offering price set forth on the cover page of this Prospectus and to certain dealers at such price, less a concession not in excess of $0.18 per share. The Underwriters may allow and such dealers may reallow a concession not in excess of $0.10 per share to certain other brokers and dealers. After the Offering, the public offering price, the concession and reallowances to dealers and other selling terms may be changed by the Underwriters. The Company has granted to the Underwriters an option exercisable for 30 days after the date of this Prospectus to purchase up to an aggregate of 960,000 additional shares of Common Stock to cover over-allotments, if any, at the same price per share to be paid by the Underwriters for the other shares of Common stock offered hereby. If the Underwriters purchase any such additional shares pursuant to the over-allotment option, each Underwriter will be committed, subject to certain conditions, to purchase a number of the additional shares of Common Stock proportionate to such Underwriter's initial commitment. The Company, its directors and executive officers, and certain stockholders who will beneficially own an aggregate of 3,942,917 shares of the Common Stock outstanding after the Offering have agreed with the Underwriters, for a period of 180 days (120 days, in the case of Mr. Cresci and Pecks Management Partners Ltd.) after the date of this Prospectus, not to issue, sell, offer to sell, grant any options for the sale of, or otherwise dispose of any shares of Common Stock or any rights to purchase shares of Common Stock (other than with respect to the Company stock issued or options granted pursuant to the Company's stock incentive plans), without the prior written consent of the Rauscher Pierce Refsnes, Inc. See "Shares Eligible for Future Sale." The Company and the Selling Stockholders have severally agreed to indemnify the Underwriters against certain liabilities that may be incurred in connection with the sale of the Common Stock, including liabilities arising under the Securities Act, and to contribute to payments that the Underwriters may be required to make with respect thereto. 62 63 LEGAL MATTERS The legality of the securities offered hereby will be passed on for the Company by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the sale of such securities will be passed on for the Underwriters by Andrews & Kurth L.L.P., Houston, Texas. ACCOUNTANTS The audited financial statements included in this prospectus and elsewhere in the registration statement have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in giving said report. ENGINEERS Information set forth in this Prospectus relating to the Company's estimated proved oil and gas reserves at December 31, 1995, the related calculations of future net production revenues and the net present value thereof have been derived from independent petroleum engineering reports prepared by Ryder Scott Company and Huddleston & Co., independent petroleum engineers. 63 64 GLOSSARY OF OIL AND GAS TERMS The terms defined in this section are used throughout this Prospectus. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bcf. Billion cubic feet. BOE. Barrels of oil equivalent, determined using the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl of crude oil or condensate. Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. Development location. A location on which a development well can be drilled. 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. Dry hole. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Estimated future net revenues. Revenues from production of oil and gas, net of all production-related taxes, lease operating expenses and capital costs. 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. Gross acres. An acre in which a working interest is owned. Gross well. A well in which a working interest is owned. MBbl. One thousand barrels of crude oil or other liquid hydrocarbons. MBOE. One thousand barrels of oil equivalent. MBtu. One thousand Btus. Mcf. One thousand cubic feet. MMBbl. One million barrels of crude oil or other liquid hydrocarbons. MMBOE. One million barrels of oil equivalent. MMBtu. One million Btus. MMcf. One million cubic feet. Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells. NGLs. Natural gas liquids such as ethane, propane, iso-butane, normal butane and natural gasoline that have been extracted from natural gas. Overriding royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and gas production free of costs of production. PDP. Proved developed producing. Pre-tax SEC 10 Value or Present value of estimated future net revenues or pretax present value at constant prices of estimated future net revenues. Estimated future net revenues discounted by a factor of ten percent per annum, before income taxes and with no price or cost escalation or de-escalation, in accordance with guidelines promulgated by the Securities and Exchange Commission. Production costs. All costs necessary for the production and sale of oil and gas, including production and ad valorem taxes. 64 65 Productive well. A well that is producing oil or gas or that is capable of production. Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped location. A site on which a development well can be drilled consistent with local spacing rules for the purpose of recovering proved reserves. Proved undeveloped reserves. 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. Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed. Reserve life is calculated by dividing year-end reserves by total production in that year. Reserve replacement costs. Total costs incurred for exploration and development, divided by reserves added from all sources, including reserve discoveries, extensions and improved recovery additions, net revisions to reserve estimates and purchases of reserves-in-place. This calculation is often used as a measure of the efficiency of an oil and gas company's exploration and development expenditures. Reserve replacement ratio is calculated by dividing the net total reserves added in a specific year through drilling, acquisitions, and revisions by total production in that year. Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves. Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. 65 66 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ----- Interim Unaudited Consolidated Financial Statements: Consolidated Balance Sheets at March 31, 1996 (unaudited).......................... F-2 Consolidated Statements of Operations for the three months ended March 31, 1996 and 1995 (unaudited)................................................................ F-3 Consolidated Statements of Stockholders' Equity for the three months ended March 31, 1996........................................................................ F-4 Consolidated Statements of Cash Flows for the three months ended March 31, 1996 and 1995 (unaudited)................................................................ F-5 Notes to Condensed Consolidated Financial Statements (unaudited)................... F-7 Audited Consolidated Financial Statements: Report of Independent Public Accountants........................................... F-11 Consolidated Balance Sheets at December 31, 1995 and 1994.......................... F-12 Consolidated Statements of Operations for the years ended December 31, 1995, 1994 and 1993........................................................................ F-13 Consolidated Statements of Stockholders' Equity for the years ended December 31, 1995, 1994 and 1993............................................................. F-14 Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993........................................................................ F-15 Notes to Consolidated Financial Statements......................................... F-18
F-1 67 HARCOR ENERGY, INC. CONSOLIDATED BALANCE SHEETS AS OF MARCH 31, 1996 (UNAUDITED)
MARCH 31, 1996 ----------- ASSETS CURRENT ASSETS: Cash and cash investments..................................................... $ 3,976,750 Accounts receivable........................................................... 3,699,634 Prepaids and other............................................................ 398,385 ----------- Total current assets.................................................. 8,074,769 ----------- PROPERTY AND EQUIPMENT, at cost, successful efforts method: Unproved oil and gas properties............................................... 5,211,556 Proved oil and gas properties: Leasehold costs............................................................ 55,670,301 Plant, lease and well equipment............................................ 18,120,654 Intangible development costs............................................... 19,371,617 Furniture and equipment....................................................... 262,740 ----------- 98,636,868 Less -- accumulated depletion, depreciation and amortization.................. (24,354,217) ----------- Net property, plant and equipment............................................. 74,282,651 ----------- OTHER ASSETS.................................................................... 4,413,029 ----------- $86,770,449 =========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Short-term debt............................................................... $ 595,876 Accounts payable and accrued liabilities...................................... 5,689,828 ----------- Total current liabilities............................................. 6,285,704 ----------- LONG-TERM BANK DEBT............................................................. 7,500,000 ----------- OTHER LIABILITIES............................................................... 240,169 ----------- 14 7/8% SENIOR SECURED NOTES.................................................... 63,180,433 ----------- COMMITMENTS AND CONTINGENCIES STOCKHOLDERS' EQUITY: Preferred stock, $.01 par value -- 1,500,000 shares authorized; 65,000 shares outstanding................................................................ 650 Common stock, $.10 par value -- 25,000,000 shares authorized; 8,696,207 and 8,631,207 shares outstanding at March 31, 1996 and December 31, 1995, respectively............................................................... 869,621 Additional paid-in capital.................................................... 28,734,380 Accumulated deficit........................................................... (20,040,508) ----------- Total stockholders' equity............................................ 9,564,143 ----------- $86,770,449 ===========
The accompanying notes are an integral part of these consolidated financial statements. F-2 68 HARCOR ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 1996 AND 1995 (UNAUDITED)
THREE MONTHS ENDED MARCH 31, ------------------------- 1996 1995 ---------- ---------- REVENUES: Oil and gas revenues.............................................. $5,956,058 $3,683,309 Gas plant operating and marketing revenues........................ 1,623,785 1,785,306 Interest income................................................... 10,310 6,833 Other............................................................. 6,413 8,282 ---------- ---------- 7,596,566 5,483,730 ---------- ---------- COSTS AND EXPENSES: Production costs.................................................. 1,436,729 1,263,087 Gas plant operating and marketing costs........................... 956,190 1,410,349 Engineering and geological costs.................................. 101,007 88,665 Depletion, depreciation and amortization.......................... 1,706,560 1,346,247 General and administrative expenses............................... 720,795 665,900 Interest expense.................................................. 2,642,541 1,129,996 Other............................................................. 260,703 -- ---------- ---------- 7,824,525 5,904,244 ---------- ---------- Loss before provision for income tax.............................. (227,959) (420,514) Provision for income taxes.......................................... -- -- ---------- ---------- Net operating loss................................................ (227,959) (420,514) Dividends on preferred stock........................................ (132,500) (335,242) Accretion on redeemable preferred stock............................. -- (80,986) ---------- ---------- NET LOSS APPLICABLE TO COMMON STOCKHOLDERS.......................... $ (360,459) $ (836,742) ========= ========= NET LOSS PER COMMON SHARE........................................... $ (0.04) $ (0.12) ========= =========
The accompanying notes are an integral part of these consolidated financial statements. F-3 69 HARCOR ENERGY, INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY FOR THE THREE MONTHS ENDED MARCH 31, 1996 (UNAUDITED)
PREFERRED STOCK COMMON STOCK ADDITIONAL --------------- -------------------- PAID-IN ACCUMULATED SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT ------ ------ --------- -------- ----------- ------------ Balance, December 31, 1995..... 65,000 $650 8,631,207 $863,121 $29,163,670 $(19,812,549) Issuance of common stock pursuant to warrant exchange..................... -- -- 65,000 6,500 (6,500) -- Cancellation of warrants....... -- -- -- -- (290,290) -- Preferred stock dividends...... -- -- -- -- (132,500) -- Net loss for the three months ended March 31, 1996......... -- -- -- -- -- (227,959) ------ ------ --------- -------- ----------- ------------ Balance, March 31, 1996........ 65,000 $650 8,696,207 $869,621 $28,734,380 $(20,040,508) ====== ====== ======== ======== ========== ===========
The accompanying notes are an integral part of these consolidated financial statements. F-4 70 HARCOR ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 1996 AND 1995 (UNAUDITED)
THREE MONTHS ENDED MARCH 31, --------------------------- 1996 1995 ------------ ---------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Loss........................................................ $ (227,959) $ (420,514) Adjustments to reconcile net loss to net cash provided by operating activities: Depletion, depreciation and amortization..................... 1,706,560 1,346,247 Amortization of deferred charges............................. 239,574 117,441 Engineering and geological costs................................ 101,007 88,665 Other........................................................... 260,703 -- ------------ ---------- 2,079,885 1,131,839 Changes in working capital, net of effects of non-cash transactions................................................. (2,167,741) (187,421) ------------ ---------- Net cash provided by (used in) operating activities............. (87,856) 944,418 ------------ ---------- CASH FLOWS FROM INVESTING ACTIVITIES: Engineering and geological costs................................ (101,007) (88,665) Additions to property and equipment............................. (9,635,408) (18,341) ------------ ---------- Net cash used in investing activities........................... (9,736,415) (107,006) ------------ ---------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from increase in debt.................................. 1,900,000 -- Dividends on preferred stock.................................... (132,500) (70,000) Other........................................................... (170,939) (13,313) ------------ ---------- Net cash used in financing activities........................... 1,596,561 (83,313) ------------ ---------- Net increase (decrease) in cash................................. (8,227,710) 754,099 Cash at beginning of period..................................... 12,204,460 899,198 ------------ ---------- Cash at end of period........................................... $ 3,976,750 $1,653,297 ============ ==========
The accompanying notes are an integral part of these consolidated financial statements. F-5 71 HARCOR ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 1996 AND 1995 (UNAUDITED) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (ALL DOLLAR AMOUNTS HAVE BEEN ROUNDED TO THE NEAREST THOUSAND) HarCor Energy, Inc. (the "Company") made interest payments of $4,668,000 and $969,000 during the three months ended March 31, 1996 and 1995, respectively. SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING ACTIVITIES -- THREE MONTHS ENDED MARCH 31, 1996 During the current period the Company entered into agreements resulting in the issuance of 65,000 unregistered shares of its common stock in exchange for the cancellation of options and warrants to purchase an aggregate of 376,000 of its common shares. Additionally, a warrant to purchase 350,000 shares of the Company's common stock, which was issued in connection with a prior financing, was returned to the Company and canceled in exchange for the issuance of 99,750 new warrants. These activities are not reflected in financing activities (see Note 5). Included in investing activities in the current period are payments of $8,188,000 relating to drilling costs which were accrued but unpaid at December 31, 1995. At March 31, 1996, the Company had accrued capital costs and a capitalized lease aggregating $1,649,000 which are not reflected in investing activities. SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING ACTIVITIES -- THREE MONTHS ENDED MARCH 31, 1995 During the three months ended March 31, 1995, the Company paid "in-kind" dividends on its Series D Redeemable Preferred Stock consisting of $235,000 in newly-issued Series D Preferred Stock and issued detachable warrants to purchase shares of common stock which were valued at $45,000. The Company also paid dividends on its Convertible Series E Preferred Stock consisting of $30,000 in newly-issued unregistered shares of the Company's common stock. In addition, the Company incurred an accretion charge of $81,000 on its Series D Preferred Stock during the period. Pursuant to the terms of its bridge loan facility, the Company issued to its secured lender 50,000 shares of its common stock which was valued at $156,000 and recorded to deferred financing costs. F-6 72 HARCOR ENERGY, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 1996 (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation The accompanying consolidated financial statements for the three months ended March 31, 1995 include the accounts and results of HarCor Energy, Inc. ("HarCor") and its wholly-owned subsidiaries, Warrior, Inc. ("Warrior") and HTAC Investments, Inc.(collectively, the "Company" or "HarCor" unless the context specifies otherwise). The accompanying consolidated financial statements for the three months ended March 31, 1996 include the accounts and results of HarCor, and Warrior and HTAC until those subsidiaries' merger into HarCor (see below). Principally all of the assets, equity, revenue and earnings of the Company as described herein are within HarCor Energy, Inc. Separate financial statements of Warrior and HTACI, HarCor's only direct or indirect subsidiaries, have not been included herein because they are wholly owned and not material. In March 1996, Warrior and HTACI were merged into HarCor, and all of their assets became the property, and all of their liabilities and guarantees became the obligations, of HarCor. All significant intercompany accounts and transactions have been eliminated in consolidation. The consolidated financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. The Company believes, however, that it has made adequate disclosures so that the information presented herein is not misleading. A summary of the Company's significant accounting policies is included in the consolidated financial statements and notes thereto, contained in its Annual Report on Form 10-K for the year ended December 31, 1995 (the "10-K"). The unaudited consolidated financial data presented herein should be read in conjunction with the 10-K. In the opinion of the Company, the unaudited consolidated financial statements contained herein include all adjustments (consisting of normal recurring accruals and the elimination of intercompany transactions) necessary to present fairly the Company's consolidated results of operations, cash flows and changes in stockholders' equity for the three-month periods ended March 31, 1996 and 1995. The results of operations for an interim period are not necessarily indicative of the results to be expected for a full year. Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at March 31, 1996 and 1995 comprised the following (amounts in thousands):
1996 1995 ------ ------ Accrued development costs.......................................... $1,553 $ 365 Accrued interest payable........................................... 2,124 931 Trade accounts payable and other................................... 2,013 2,969 ------ ------ $5,690 $4,265 ====== ======
F-7 73 HARCOR ENERGY, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Capitalized Interest Costs Interest costs of $172,000 for the three months ended March 31, 1996 have been capitalized as part of the historical costs of unproved oil and gas properties. New Accounting Standard: Impairment of Long-Lived Assets In September 30, 1995, the Company adopted the provisions of Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS 121 requires the Company to review its oil and gas properties whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If the carrying amount of any of the Company's oil and gas properties (determined on a field-by-field basis) is greater than its projected undiscounted future cash flow, an impairment loss is recognized down to the properties' fair values. There were no write-downs pursuant to SFAS 121 in the current period. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve volumes and the related present value of estimated future net revenues therefrom. Net Loss Per Common Share Net loss per common share was calculated by dividing the appropriate net loss, after considering preferred stock dividends, by the weighted average number of common shares outstanding during each period. Outstanding stock options, warrants and convertible preferred shares were not included in the calculations, since their effect was antidilutive. The weighted average number of outstanding common shares utilized in the calculations was 8,685,000 and 7,226,000 for the three-month periods ended March 31, 1996 and 1995, respectively. (2) LONG-TERM DEBT Availability under the Company's credit agreement with ING Capital is limited to a "borrowing base" amount which is determined semi-annually by ING, at its sole discretion, and may be established at an amount up to $15 million. The borrowing base is currently $10 million, and ING Capital has no obligation to increase the borrowing base above this amount. Availability under the credit agreement, which was amended in March 1996, will terminate on June 30, 1997, at which time amounts outstanding will convert to a term loan on September 30, 1997, with a set amortization schedule of a percentage of the outstanding principal balance continuing through December 31, 2000. There was $7.5 million outstanding under this facility at March 31, 1996. The effective interest rate on the balance outstanding was 8.125% at that date. Amounts advanced under this facility bear interest at an adjusted Eurodollar rate plus 2.50%. See Notes to Consolidated Financial Statements included in Item 8. of Part II of the Company's December 31, 1995 Report on Form 10-K for a complete description of the Company's New Credit Agreement. (3) SENIOR SECURED NOTES On July 24, 1995, the Company consummated the sale (the "Note Offering") of 65,000 units (the "Units") consisting of $65 million aggregate principal amount of its 14 7/8% Senior Notes due July 15, 2002 F-8 74 HARCOR ENERGY, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (the "Notes") and warrants to purchase 1,430,000 shares of common stock at $3.85 per share. Each Unit consists of a $1,000 principal amount Note and 22 warrants to purchase an equal number of shares of common stock. The Company used the net proceeds of approximately $61 million from the sale of the Units (after discounts and offering expenses) to retire all outstanding debt, redeem the Series D Preferred Stock outstanding, acquire interests in certain oil and gas wells associated with the Bakersfield Properties, and finance a portion of the development of the Bakersfield Properties during the remainder of 1995. The differing amount between the $65 million face value of the Notes and the balance sheet amount recorded herein is the result of an allocation to paid-in capital of the value ascribed to the warrants at the time of their issuance. This amount will amortize through interest expense over the life of the Notes. The Notes bear interest at the rate of 14 7/8% per annum. Interest accrues from the date of issue and will be payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 1996. The Notes are redeemable, in whole or in part, at the option of the Company at any time on or after July 15, 1999, at the following redemption prices (expressed as percentages of the principal amount) if redeemed during the twelve-month period commencing on July 15 of the year set forth below plus, in each case, accrued interest thereon to the date of redemption:
YEAR PERCENTAGE ---------------------------------------------------------- ---------- 1999...................................................... 110% 2000...................................................... 107% 2001 and thereafter....................................... 100%
The Notes were issued pursuant to an indenture between the Company and Texas Commerce Bank National Association, as Trustee (the "Indenture"). All of the obligations of the Company under the Notes and the Indenture are secured by a second priority lien on substantially all of the assets of the Company and its subsidiaries securing its bank debt. See Notes to Consolidated Financial Statements included in Item 8. of Part II of the Company's December 31, 1995 Report on Form 10-K for a complete description of the Company's Senior Secured Notes. (4) COMMITMENTS AND CONTINGENCIES Risk Management and Hedging Activities The Company utilizes financial instruments as a hedging strategy to protect against the effects of volatility in crude oil and natural gas commodity prices. Upon consummation of an acquisition, the Company will usually enter into commodity derivative contracts (hedges) such as futures, swaps or collars or forward contracts which cover a substantial portion of the existing production of the acquired property. Over time, as production increases, the Company may continue to utilize hedging techniques to ensure that a portion of its production remains appropriately hedged. Gains or losses under the hedging agreements are recognized in oil and gas production revenues in periods in which the hedged production occurs and such agreements are settled on a monthly basis. As of March 31, 1996, the Company was a party to various gas contracts covering volumes of approximately 1.8 Bcf and 1.2 Bcf for 1996 and 1997, respectively, at prices ranging from $1.68/MMBtu to $2.07/MMBtu; a gas contract covering 2.2 Bcf for 1996 and 2.2 Bcf for 1997 which fixes volumes to be sold at $0.3675 less than the NYMEX gas future price for each month; and oil hedges covering notional volumes of approximately 243 MBOE, 98 MBOE and 29 MBOE for 1996, 1997 and 1998, respectively, at prices ranging from $15.80/Bbl to $18.75/Bbl. F-9 75 HARCOR ENERGY, INC. NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (5) STOCKHOLDERS' EQUITY Warrant Exchanges During the current quarter the Company completed exchange agreements whereby certain holders of options and warrants to purchase the Company's common stock exchanged all or a portion of their options and warrants outstanding for unregistered shares of common stock of the Company. Pursuant to these exchange agreements, an option to purchase 150,000 common shares at $4.875 per share, and warrants to purchase an aggregate of 226,000 common shares at prices ranging from $4.75 to $5.50 per share, were exchanged and canceled for 65,000 unregistered shares of common stock of the Company. Additionally, in March 1996, a warrant to purchase 350,000 shares of the Company's common stock at $3.85 per share, which was issued in connection with the Note Offering, was returned to the Company and canceled in exchange for the issuance of 99,750 new warrants with the same exercise price. Preferred Stock Dividends The Company has paid dividends on preferred stocks for the three months ended March 31, 1996 and 1995 as follows:
THREE MONTHS ENDED MARCH 31, --------------------- 1996 1995 -------- -------- 8% Convertible (Series A, B, C)................................ $ 65,000 $ 70,000 9% Redeemable (Series D)....................................... -- 235,242 4%/9% Convertible (Series E)................................... 67,500 30,000 -------- -------- $132,500 $335,242 ======== ========
Dividends on 8% Series A, Series B and Series C Preferred Stock were paid in cash for both periods presented. Dividends on 9% Series D in first quarter 1995 were paid, at the option of the Company, in additional shares of Series D Redeemable Preferred Stock. Dividends on the Series E Preferred Stock for first quarter 1995 were paid, at the option of the Company, in shares of common stock of the Company in lieu of cash. Dividends on the Series E Preferred were paid in cash for the current quarter. The coupon rate on the Series E increased from 4% per annum to 9% per annum effective July 1, 1995. F-10 76 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Stockholders and Board of Directors of HarCor Energy, Inc.: We have audited the accompanying consolidated balance sheets of HarCor Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1995. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of HarCor Energy, Inc. and subsidiaries as of December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. As discussed in Note 1 to the consolidated financial statements, effective September 30, 1995, the Company adopted the Provisions of Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." ARTHUR ANDERSEN LLP Houston, Texas March 22, 1996 F-11 77 HARCOR ENERGY, INC. CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1995 AND 1994 ASSETS
1995 1994 ------------ ------------ CURRENT ASSETS: Cash and cash investments..................................... $ 12,204,460 $ 899,198 Accounts receivable........................................... 3,829,548 3,707,433 Prepaids and other............................................ 282,833 307,241 ------------ ------------ Total current assets.................................. 16,316,841 4,913,872 ------------ ------------ PROPERTY, PLANT AND EQUIPMENT, at cost, successful efforts method: Unproved oil and gas properties............................... 5,039,553 7,414,113 Proved oil and gas properties: Leasehold costs............................................ 54,793,930 52,158,281 Lease and well equipment................................... 16,858,402 12,900,913 Intangible development costs............................... 18,547,293 4,745,579 Furniture and equipment....................................... 256,211 231,354 ------------ ------------ 95,495,389 77,450,240 Less -- accumulated depletion, depreciation, amortization and impairment................................................. (22,647,657) (16,674,540) ------------ ------------ Net property, plant and equipment............................. 72,847,732 60,775,700 ------------ ------------ OTHER ASSETS.................................................... 5,066,904 2,883,277 ------------ ------------ $ 94,231,477 $ 68,572,849 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Short-term debt............................................... $ 378,695 $ -- Current portion of long-term debt............................. -- 2,511,200 Subordinated Bridge Loan...................................... -- 5,000,000 Accounts payable and accrued liabilities...................... 14,612,813 5,345,967 Total current liabilities..................................... 14,991,508 12,857,167 ------------ ------------ LONG-TERM DEBT, net of current portion................ 5,600,000 31,888,800 ------------ ------------ OTHER LIABILITIES............................................... 316,469 71,055 ------------ ------------ 14 7/8% SENIOR SECURED NOTES.................................... 63,108,608 -- ------------ ------------ COMMITMENTS AND CONTINGENCIES (Note 9) REDEEMABLE SERIES D PREFERRED STOCK............................. -- 8,402,430 STOCKHOLDERS' EQUITY: Preferred stock, $.01 par value -- 1,500,000 shares authorized; 65,000 and 67,500 shares outstanding at December 31, 1995 and 1994, respectively................... 650 675 Common stock, $.10 par value -- 25,000,000 shares authorized; 8,631,207 and 7,192,837 shares outstanding at December 31, 1995 and 1994, respectively................................ 863,121 719,284 Additional paid-in capital.................................... 29,163,670 29,827,989 Accumulated deficit........................................... (19,812,549) (15,194,551) ------------ ------------ Total stockholders' equity............................ 10,214,892 15,353,397 ------------ ------------ $ 94,231,477 $ 68,572,849 ============ ============
The accompanying notes are an integral part of these consolidated financial statements. F-12 78 HARCOR ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1995 1994 1993 ----------- ----------- ----------- REVENUES: Oil and gas revenues.............................. $16,030,043 $10,981,651 $ 6,507,468 Gas plant operating and marketing revenues........ 6,361,665 1,978,317 -- Interest income................................... 164,193 16,269 20,593 Other............................................. 39,368 236,814 197,022 ----------- ----------- ----------- 22,595,269 13,213,051 6,725,083 ----------- ----------- ----------- COSTS AND EXPENSES: Production costs.................................. 5,262,887 3,609,831 2,248,877 Gas plant operating and marketing costs........... 3,704,397 1,707,551 -- Dry hole and abandonment costs.................... 4,013 74,797 41,165 Engineering and geological costs.................. 307,102 254,418 187,862 Depletion, depreciation, amortization and impairment..................................... 5,973,117 3,897,133 2,641,079 General and administrative expenses............... 2,744,239 2,014,232 2,104,857 Interest expense.................................. 6,846,471 2,268,558 542,098 Other............................................. 482,608 203,000 -- ----------- ----------- ----------- 25,324,834 14,029,520 7,765,938 ----------- ----------- ----------- Loss before provision for income taxes and extraordinary item............................. (2,729,565) (816,469) (1,040,855) Provision for income taxes........................ -- -- -- ----------- ----------- ----------- Loss before extraordinary item.................... (2,729,565) (816,469) (1,040,855) EXTRAORDINARY ITEM: Loss on early extinguishment of debt.............. (1,888,433) (122,193) -- ----------- ----------- ----------- Net loss.......................................... (4,617,998) (938,662) (1,040,855) Dividends on preferred stock........................ (1,000,161) (795,065) (246,468) Accretion on Redeemable Preferred Stock............. (2,146,812) (156,152) -- ----------- ----------- ----------- NET LOSS APPLICABLE TO COMMON STOCKHOLDERS.......... $(7,764,971) $(1,889,879) $(1,287,323) ========== ========== ========== NET LOSS PER COMMON SHARE BEFORE EXTRAORDINARY ITEM.............................................. $ (.74) $ (.27) $ (.23) EXTRAORDINARY ITEM.................................. (.24) (.02) -- ----------- ----------- ----------- NET LOSS PER COMMON SHARE AFTER EXTRAORDINARY ITEM.............................................. $ (.98) $ (.29) $ (.23) ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. F-13 79 HARCOR ENERGY, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
PREFERRED STOCK COMMON STOCK ADDITIONAL ------------------ ---------------------- PAID-IN ACCUMULATED SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT ------- ------ --------- -------- ----------- ------------ BALANCE, DECEMBER 31, 1992................. 8,000 $ 80 5,399,877 $539,988 $17,320,228 $(13,215,034) Issuance of 8% Series B Convertible Preferred Stock.......................... 30,000 300 -- -- 2,999,700 -- Issuance of 8% Series C Convertible Preferred Stock.......................... 10,000 100 -- -- 930,926 -- Conversion of Convertible Preferred Stock.................................... (10,500) (105) 235,157 23,516 (23,411) -- Issuance of common stock pursuant to exercise of stock options................ -- -- 101,850 10,185 236,745 -- Preferred stock dividends.................. -- -- -- -- (246,468) -- Net loss................................... -- -- -- -- -- (1,040,855) ------- ------ --------- -------- ----------- ------------ BALANCE, DECEMBER 31, 1993................. 37,500 375 5,736,884 573,689 21,217,720 (14,255,889) Issuances in connection with Bakersfield Property acquisition: 4% Series E Convertible Preferred Stock.................................. 30,000 300 -- -- 2,982,443 -- Common stock............................. -- -- 1,363,907 136,391 2,965,148 -- Warrants................................. -- -- -- -- 3,200,842 -- Issuances of common stock pursuant to Restricted Stock grant and exercise of stock options............................ -- -- 75,375 7,537 266,776 -- Issuances of common stock and warrants pursuant to preferred stock dividends.... -- -- 16,671 1,667 146,277 -- Preferred stock dividends.................. -- -- -- -- (795,065) -- Accretion on 9% Redeemable Series D Preferred Stock.......................... -- -- -- -- (156,152) -- Net loss................................... -- -- -- -- -- (938,662) ------- ------ --------- -------- ----------- ------------ BALANCE, DECEMBER 31, 1994................. 67,500 675 7,192,837 719,284 29,827,989 (15,194,551) Conversion of Convertible Preferred Stock.................................... (2,500) (25) 64,100 6,410 (6,385) -- Issuance of common stock................... -- -- 75,000 7,500 226,125 -- Issuance of common stock pursuant to warrant exchange......................... -- -- 1,282,500 128,250 (128,250) -- Issuance of common stock and warrants pursuant to preferred stock dividends.... -- -- 16,770 1,677 153,164 -- Issuance of warrants pursuant to 14 7/8% Senior Secured Notes..................... -- -- -- -- 2,238,000 -- Preferred stock dividends.................. -- -- -- -- (1,000,161) -- Accretion on Series D Preferred Stock...... -- -- -- -- (2,146,812) -- Net loss................................... -- -- -- -- -- (4,617,998) ------- ------ --------- -------- ----------- ------------ BALANCE, DECEMBER 31, 1995................. 65,000 $ 650 8,631,207 $863,121 $29,163,670 $(19,812,549) ======= ====== ======== ======== ========== ===========
The accompanying notes are an integral part of these consolidated financial statements. F-14 80 HARCOR ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1995 1994 1993 ------------ ------------ ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Loss........................................ $ (4,617,998) $ (938,662) $(1,040,855) Adjustments to reconcile net loss to net cash provided by operating activities: Depletion, depreciation, amortization and impairment................................. 5,973,117 3,897,133 2,641,079 Amortization of deferred financing costs..... 708,932 254,372 67,177 Dry hole and abandonment costs............... 4,013 74,797 41,165 Engineering and geological costs............. 307,102 254,418 187,862 (Gain) loss on sale of assets................ 131,702 (230,993) (166,021) Loss on early extinguishment of debt......... 1,888,433 122,193 -- Other........................................ 350,908 203,000 -- ------------ ------------ ----------- 4,746,209 3,636,258 1,730,407 Changes in current assets and liabilities: Decrease (increase) in receivables........... (212,319) (2,520,726) 11,987 Decrease (increase) in other current assets..................................... 24,408 (147,002) 68,786 Increase in accounts payable and accrued liabilities................................ 457,233 1,772,930 560,074 ------------ ------------ ----------- Net cash provided by operating activities....... 5,015,531 2,741,460 2,371,254 ------------ ------------ ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Engineering and geological costs................ (307,102) (254,418) (187,862) Proceeds from sale of assets.................... 13,650 455,754 363,332 Additions to oil and gas properties............. (8,953,427) (45,607,532) (4,283,066) Dry hole and abandonment costs.................. (4,013) (74,797) (41,165) Sale of Canadian securities..................... -- -- 1,287,356 Other........................................... -- -- 58,683 ------------ ------------ ----------- Net cash used in investing activities........... (9,250,892) (45,480,993) (2,802,722) ------------ ------------ ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of debt.................. 5,600,000 34,436,875 2,603,528 Repayment of debt............................... (39,400,000) (3,577,873) (1,949,189) Proceeds from issuance of preferred stock....... -- -- 931,026 Proceeds from issuance of Redeemable Preferred Stock........................................ -- 10,000,000 -- Proceeds from 14 7/8% Senior Secured Notes...... 64,647,700 -- -- Proceeds from issuance of common stock.......... -- 3,053,101 246,930 Redemption of Redeemable Preferred Stock........ (10,931,200) -- -- Dividends on preferred stock.................... (464,161) (356,413) (170,055) Increase in other assets........................ (3,856,119) (1,772,621) (47,655) Other........................................... (55,597) (305,850) 49,888 ------------ ------------ ----------- Net cash provided by financing activities....... 15,540,623 41,477,219 1,664,473 ------------ ------------ ----------- Net increase (decrease) in cash................... 11,305,262 (1,262,314) 1,233,005 Cash and cash investments at beginning of period.......................................... 899,198 2,161,512 928,507 ------------ ------------ ----------- Cash and cash investments at end of period........ $ 12,204,460 $ 899,198 $ 2,161,512 =========== =========== ==========
The accompanying notes are an integral part of these consolidated financial statements. F-15 81 HARCOR ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (ALL DOLLAR AMOUNTS HAVE BEEN ROUNDED TO THE NEAREST THOUSAND) The Company made cash interest payments of $2,329,000, $2,030,000 and $453,000 in 1995, 1994 and 1993, respectively. SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING ACTIVITIES -- YEAR ENDED DECEMBER 31, 1995 The Company had accrued capital expenditure costs of $8,266,000 at December 31, 1995 which are not reflected in investing activities. Pursuant to the terms of its bridge loan facility, the Company issued to its secured lender 75,000 shares of its common stock to which a value of $253,000 was ascribed. These additions to deferred financing costs and equity are not reflected in financing activities. The Company incurred $379,000 in short-term debt and $282,000 in other liabilities in connection with the financing of an annual insurance policy and the financing of equipment which is not reflected in financing activities. In connection with the refinancing of its long-term debt, the Company incurred a non-cash charge of $1,888,000 in writing off all of the deferred financing costs associated with the extinguished debt. Also in connection with this refinancing, the Company issued warrants to which a value of $580,000 was ascribed. These charges to deferred financing costs and equity are not reflected in financing activities. Included in the payment of dividends on its Series D Preferred Stock were "in-kind" dividends consisting of $476,000 in newly-issued Series D Preferred Stock. Included in the payment of dividends on the Convertible Series E Preferred Stock was $60,000 of newly-issued unregistered shares of the Company's common stock. These dividend payments as described are not reflected in financing activities. The Company incurred aggregate non-cash accretion charges of $2,147,000 on its Series D Preferred Stock which are not reflected in financing activities. SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING ACTIVITIES -- YEAR ENDED DECEMBER 31, 1994 In connection with the dissolution of the South Texas Limited Partnership and related property conveyance, the Company wrote off $203,000 of its cost basis of the partnership, and expensed $122,000 reflecting a write-off of deferred financing costs resulting from the early extinguishment of debt. These non-cash charges for the dissolution and debt extinguishment are not reflected in investing and financing activities. At December 31, 1994, the Company had accrued acquisition and developmental drilling costs aggregating $1,823,000 and accrued prepaid and deferred financing costs aggregating $342,000. The additions to property, plant and equipment and financing costs resulting from these and the above described transactions are not reflected in investing and financing activities. In connection with the Company's acquisition of certain oil and gas assets, the Company issued to the sellers, as a portion of the consideration, 30,000 shares of its Series E Preferred Stock with a face value of $3,000,000, 25,000 shares of unregistered common stock with a value of $81,000 and a warrant to purchase 1,000,000 shares of the Company's common stock at $5.00 per share to which the Company ascribed a value of $850,000. The acquisition value of the assets acquired and corresponding additions to equity resulting from these transactions are not reflected in investing and financing activities. F-16 82 In connection with the amendment of the Company's credit agreement, the Company issued warrants to purchase 250,000 shares of the Company's common stock to which the Company ascribed a value of $230,000. The deferred financing cost and addition to equity resulting from this transaction are not reflected in financing activities. During 1994, the Company issued an aggregate of 60,375 restricted shares of common stock to officers which was valued as deferred compensation of $242,000 and was not reflected in financing activities. During 1994, the Company paid "in-kind" dividends on its Series D Redeemable Preferred Stock consisting of $455,000 in newly-issued Series D Preferred Stock and detachable warrants to purchase shares of common stock which were valued at $88,000. The Company also paid dividends on its Convertible Series E Preferred Stock consisting of $60,000 in newly-issued unregistered shares of the Company's common stock. These dividend payments and issuance of common stock and warrants are not reflected in financing activities. SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING ACTIVITIES -- YEAR ENDED DECEMBER 31, 1993 In March 1993, the Company acquired oil and gas royalty and net profit interests in exchange for 30,000 shares of the Company's 8% Series B Convertible Preferred Stock at $100.00 per share for an aggregate of $3,000,000. The acquisition value of the assets acquired and corresponding addition to equity are not reflected in investing or financing activities. In connection with the Company's May 1993 acquisition of assets for $1,095,000, the Company assumed $787,000 of an outstanding production note payable. The additions to properties and production note are not reflected in investing and financing activities. The Company declared dividends totaling $76,000 in the fourth quarter on its Series A, B and C Convertible Preferred Stock, which were accrued and unpaid and not reflected in financing activities at December 31, 1993. The accompanying notes are an integral part of these consolidated financial statements. F-17 83 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1995 (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation The accompanying consolidated financial statements for the year ended December 31, 1993 include the accounts and results of operations of HarCor Energy, Inc. ("HarCor") and its wholly-owned subsidiaries, Warrior, Inc. ("Warrior") and HTAC Investments, Inc. ("HTACI"); HarCor's general partner share of the assets, liabilities, revenues and costs and expenses of South Texas Limited Partnership ("STLP"); and HarCor's share of assets, revenues and costs and expenses of oil and gas interests acquired from the TCW Commingled Debt and Royalty Fund I ("Royalty Interests") for the period of March 1993 through December 1993. The accompanying consolidated financial statements for the years ended December 31, 1994 and 1995 include the accounts and results of HarCor, Warrior and HTACI; HarCor's share of the assets, liabilities, revenues and costs and expenses of STLP or, after STLP's dissolution in March 1994, HarCor's direct working interests in the STLP properties ("South Texas Properties"); HarCor's share of the Royalty Interests; and HarCor's interest in certain oil and gas assets located in Kern County, California acquired on June 30, 1994 (the "Bakersfield Properties"); (collectively, the "Company" or "HarCor" unless the context specifies otherwise). Principally all of the assets, equity, revenue and earnings of the Company as described herein are within HarCor Energy, Inc. Separate financial statements of Warrior and HTACI, HarCor's only direct or indirect subsidiaries, have not been included herein because they are wholly owned and not material. Subsequent to December 31, 1995, Warrior and HTACI were merged into HarCor, and all of their assets became the property, and all of their liabilities and guarantees became the obligations, of HarCor. All significant intercompany accounts and transactions have been eliminated in consolidation. Business and Organization HarCor, a Delaware corporation, was incorporated in 1976 and is engaged in the business of acquiring interests in and developing onshore oil and gas properties in the United States. Cash Flows For purposes of reporting cash flows, cash and cash investments include cash on hand and temporary short-term cash investments, with original maturities of three months or less. Property, Plant and Equipment The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, exploratory costs, except costs of drilling exploratory wells, are charged to expense when incurred; exploratory well costs (including leasehold costs) are initially capitalized, but are charged to expense if the well is determined to be unsuccessful. Upon discovery of reserves on an oil and gas property in commercially producible quantities, all costs of developing that property, including costs of drilling unsuccessful development wells, are capitalized. Capitalized leasehold acquisition costs are depleted on a unit-of-production method, based on proved oil and gas reserves. Exploration, development and equipment costs are depreciated or amortized on a unit-of-production method, based on proved developed oil and gas reserves. The carrying amount of all unproved properties is evaluated periodically and reduced if such properties have been impaired. The gas plant is stated at cost and is depreciated utilizing the straight-line method over 14 years. F-18 84 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Furniture and equipment are stated at cost and are depreciated utilizing the straight-line method over three to five years. Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at December 31, 1995 and 1994 comprised the following (amounts in thousands):
1995 1994 ------- ------ Accrued development costs......................................... $ 8,188 $1,823 Accrued interest payable.......................................... 4,217 814 Trade accounts payable............................................ 1,889 2,434 Other accrued liabilities......................................... 319 275 ------- ------ $14,613 $5,346 ======= ======
Capitalized Interest Costs Certain interest costs of approximately $452,000 have been capitalized as part of the historical costs of unproved oil and gas properties effective with the refinancing and subsequent active development thereof in July 1995 and through December 31, 1995. Net Loss per Common Share Net loss per common share was calculated by dividing the net loss, after consideration of preferred stock dividends paid or accrued and related accretion, by the weighted average number of common shares outstanding during each period. Outstanding stock options, warrants and convertible preferred shares were not included in the calculations, since their effect was antidilutive in all periods. The weighted average number of outstanding common shares utilized in the calculation was 7,904,000 shares in 1995, 6,447,000 shares in 1994 and 5,492,000 shares in 1993. New Accounting Standard: Impairment of Long-Lived Assets In September 30, 1995, the Company adopted the provisions of Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS 121 requires the Company to review its oil and gas properties whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If the carrying amount of any of the Company's oil and gas properties (determined on a field-by-field basis) is greater than its projected undiscounted future cash flow, an impairment loss is recognized down to the properties' fair values. Accordingly, the estimated fair values of its oil and gas properties at December 31, 1995 were evaluated and compared to the carrying values of such assets at that date. The resulting impairment loss of $876,000 was included in depletion, depreciation, amortization and impairment in 1995. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil F-19 85 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) and gas reserve volumes and the related present value of estimated future net revenues therefrom (see Note 16, "Oil and Gas Producing Activities"). Prior Year Reclassifications Certain prior year amounts have been reclassified to conform with the current year presentation. (2) SOUTH TEXAS LIMITED PARTNERSHIP In October 1992, the Company formed STLP, a Texas limited partnership, with two industry partners. The Company became a general partner of STLP with an initial 25.25% interest in the partnership. In May 1993, the Company purchased an additional 12.625% of STLP for $1,095,000 in cash and assumed an incremental 12.625% of STLP's production note with a bank ($787,000 at the acquisition date). In March 1994, the Company and the remaining partner of STLP agreed to dissolve and terminate the partnership. Pursuant to the terms of a dissolution agreement, 37.875% of the assets and liabilities of STLP (reflecting its proportionate interest in STLP) were distributed to the Company. The principal asset distributed to the Company was its 37.875% direct working interest in the South Texas Properties. Concurrent with STLP's dissolution, the Company repaid its respective share of all amounts owed pursuant to STLP's production note outstanding ($3.1 million). The dissolution of STLP resulted in a write-off of $122,000 by the Company of deferred financing costs in connection with the early extinguishment of debt and the write-off of $203,000 in oil and gas properties resulting from a conveyance of 6% of the South Texas Properties pursuant to the dissolution agreement. (3) ROYALTY EXCHANGE AND ISSUANCE OF PREFERRED STOCK In March 1993, the Company entered into a transaction in which six institutional participants in the TCW Commingled Debt and Royalty Fund I ("the Fund") exchanged their proportionate share of the gross royalty and net profit interests in certain oil and gas properties (the "Royalty Interests") for an aggregate of 30,000 shares of the Company's 8% Series B Convertible Preferred Stock priced at $100 per share. Trust Company of the West ("TCW") is the manager and trustee of the Fund. As of December 31, 1995, TCW, acting on behalf of certain pension funds, was a holder of approximately 17% of the outstanding common stock of the Company. The Royalty Interests acquired by the Company consisted of gross overriding royalty interests and net profit interests, which were estimated to have total proved net reserves of 124,000 barrels of oil and 2.64 Bcf of natural gas with an ascribed acquisition cost of $3,073,000. (4) ACQUISITION OF BAKERSFIELD PROPERTIES On June 30, 1994, the Company acquired a 75% interest in substantially all of the oil and gas properties, a 23 MMcf per day natural gas processing plant and gathering lines owned by Bakersfield Energy Resources, Inc. and its affiliates ("BER"). The oil and gas reserves acquired were principally natural gas (1,240 Btu) and light (35-40() gravity), low sulfur, crude oil located in Kern County, California. BER has retained its remaining 25% working interest in these assets and continues to operate all of the properties and facilities acquired by the Company. Additionally, the Company and BER entered into a three-year joint acquisition agreement which gives each the right to participate in acquisitions of oil and gas interests located within the state of California by the other. The purchase price for such interests was approximately $46 million, consisting of $42 million in cash plus 25,000 shares of the Company's common stock, 30,000 shares of the Company's Series E Junior Convertible Preferred Stock at $100 per share and a seven-year callable warrant to purchase 1,000,000 shares of common stock at an exercise price of $5.00 per share to which the Company had ascribed a value of F-20 86 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) $850,000. This warrant was subsequently canceled in May 1995 pursuant to a warrant exchange agreement. (See Note 11.) To finance the acquisition, the Company amended its credit facility with a group of lenders led by Internationale Nederlanden (U.S.) Capital Corporation ("ING Capital") to increase the total commitment under such facility to $34.4 million. The Company financed the cash portion of the purchase price with (i) $25 million of incremental borrowings under a credit agreement; (ii) $5 million of borrowings under a bridge loan facility with ING Capital; (iii) $10 million gross proceeds from the private placement of 100,000 shares of the Company's Series D Preferred Stock and (iv) a portion of the $3.5 million of gross proceeds from the private placement of 1,071,538 shares of common stock. The assets acquired in this transaction were accounted for by the purchase method of accounting. The following table presents the unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 1994, assuming the acquisition of the Bakersfield Properties and the related financings had occurred at January 1, 1994 (amounts are in thousands except per share data): Total revenues............................................................. $19,304 ======= Net loss attributable to common stockholders............................... $(1,587) ======= Net loss per common share.................................................. $ (0.22) =======
Pro forma net loss for the year ended December 31, 1994 includes losses of approximately $600,000 attributable to gas plant operating losses incurred during its start-up phase prior to acquisition by the Company. (5) SUBORDINATED BRIDGE LOAN In connection with the acquisition of the Bakersfield Properties in June 1994, the Company entered into a $5 million bridge loan facility (the "Bridge Loan") with ING Capital. Outstanding advances under the Bridge Loan bore interest at a floating rate of, at the Company's option, prime plus 2% or LIBOR plus 4% per annum until September 30, 1994 and escalating by (i) .75% per annum from October 1, 1994 through January 31, 1995 and (ii) 1.5% per annum at all times after January 31, 1995. In July 1995, the Company refinanced the Bridge Loan with proceeds from a long-term refinancing of its debt. (See Note 6.) (6) LONG-TERM DEBT Effective upon the closing of the acquisition of the Bakersfield Properties in June 1994, the Company amended its facility with ING Capital (the "Amended Credit Agreement") to provide for a total commitment of $34.4 million. Outstanding advances under the Amended Credit Agreement bore interest at a floating rate of, at the Company's option, prime plus 1% or LIBOR plus 3% per annum. The Amended Credit Agreement contained certain covenants and restrictions with respect to dividends, redemption of preferred stock, general and administrative expenses, working capital, fixed charge coverage ratios and hedging activities. The Amended Credit Agreement also made provisions for the mandatory early repayment of portions of the loan amount outstanding under certain specified events. The Company issued to the lending institutions involved with the Amended Credit Agreement and the preceding credit facility warrants to purchase an aggregate of 326,000 shares of its common stock at prices ranging from $4.75 to $5.50 per share, of which 226,000 warrants were canceled pursuant to certain warrant exchange agreements subsequent to December 31, 1995. (See Note 11.) F-21 87 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) In July 1995, the Company repaid $34.3 million of the amount outstanding under the Amended Credit Agreement with proceeds resulting from a long-term refinancing of its debt and entered into a new credit agreement with ING Capital (the "New Credit Agreement"). A write-off of deferred financing costs of approximately $1.9 million was charged to expense as an extraordinary item resulting from this early extinguishment of debt and concurrent early redemption of the Series D Preferred Stock. (See Notes 7 and 8.) The New Credit Agreement provides that the Company initially may borrow up to $10 million on a revolving credit basis. Availability under the New Credit Agreement is limited to a "borrowing base" amount. The borrowing base will be determined semi-annually by ING Capital, at its sole discretion, and may be established at an amount up to $15 million. The initial borrowing base was set at and is currently $10 million, and ING Capital will have no obligation to increase the borrowing base above this amount. Availability under the New Credit Agreement, as amended in March 1996, will terminate on June 30, 1997, at which time amounts outstanding under the New Credit Agreement will convert to a term loan on September 30, 1997, with a set amortization schedule of a percentage of the outstanding principal balance continuing through December 31, 2000. There was $5.6 million outstanding under the New Credit Agreement at December 31, 1995. The effective interest rate on the balance outstanding was approximately 9% at that date. Amounts advanced under the New Credit Agreement will bear interest at an adjusted Eurodollar rate plus 2.50%. The New Credit Agreement contains restrictive covenants which impose limitations on the Company and its subsidiaries with respect to, among other things: (i) the maintenance of current assets equal to at least 100% of current liabilities, (ii) the maintenance of a minimum tangible net worth, (iii) the incurrence of indebtedness (with exceptions for the notes and the New Credit Agreement and certain other limited exceptions), (iv) dividends and similar payments (except dividends on Series A, B and C Preferred Stock of up to $530,000), (v) the creation of additional liens on, or the sale of, the Company's oil and gas properties and other assets, (vi) the Company's ability to enter into hedging transactions, (vii) mergers or consolidations, (viii) investments outside the ordinary course of business and (ix) transactions with affiliates. All indebtedness of the Company under the New Credit Agreement is secured by a first lien upon substantially all of the Company's oil and gas properties as well as by a pledge of all of the capital stock of the Company's subsidiaries and the accounts receivable, inventory, general intangibles, machinery and equipment and other assets of the Company. All assets not subject to a lien in favor of the lender are subject to a negative pledge, with certain exceptions. (7) SENIOR SECURED NOTE OFFERING Sale of Units On July 24, 1995, the Company consummated the sale (the "Note Offering") of 65,000 units (the "Units") consisting of $65 million aggregate principal amount of its 14 7/8% Senior Notes due July 15, 2002 (the "Notes") and warrants to purchase 1,430,000 shares of common stock. Each Unit consists of a $1,000 principal amount Note and 22 warrants to purchase an equal number of shares of common stock. The Notes and warrants became separately transferrable immediately after July 24, 1995. Use of Proceeds The net proceeds to the Company from the offering of Units was approximately $61 million after deducting discounts and offering expenses. The Company immediately used a portion of the net proceeds to (i) repay $34.3 million outstanding under its Amended Credit Agreement with ING Capital and repay $5 million outstanding under the Bridge Loan with ING Capital, (ii) redeem $10.9 million in outstanding shares of Series D Preferred Stock and (iii) acquire interests in certain oil and gas wells associated with the Bakersfield Properties (the "Carried Interests Wells") for $2.3 million. The Company used the balance of the F-22 88 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) proceeds from the Note Offering to finance a portion of the development of the Bakersfield Properties during the remainder of 1995. The Notes The Notes bear interest at the rate of 14 7/8% per annum. Interest accrues from the date of issue and will be payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 1996. The Notes are redeemable, in whole or in part, at the option of the Company at any time on or after July 15, 1999, at the following redemption prices (expressed as percentages of the principal amount) if redeemed during the twelve-month period commencing on July 15 of the year set forth below plus, in each case, accrued interest thereon to the date of redemption:
YEAR PERCENTAGE ---------------------------------------------------------- ---------- 1999...................................................... 110% 2000...................................................... 107% 2001 and thereafter....................................... 100%
The Notes are issued pursuant to an indenture, dated July 24, 1995, between the Company and Texas Commerce Bank National Association, as Trustee (the "Indenture"). All of the obligations of the Company under the Notes and the Indenture are secured by a second priority lien on substantially all of the assets of the Company and its subsidiaries securing its bank debt. The subsidiaries of the Company were merged into HarCor subsequent to December 31, 1995 and all of their assets became the property, and all of their liabilities and guarantees became the obligations, of HarCor. The Warrants Each warrant entitles the holder thereof to purchase one share of common stock at an exercise price of $3.85 per share. The warrants are exercisable at any time on or after July 24, 1996 and expire at the close of business on July 24, 2000. Holders of the warrants have certain demand and piggy-back rights to cause the Company to register the shares of common stock issuable thereunder. Such shares of common stock collectively represent approximately 10% of the common stock of the Company on a fully diluted basis (after taking into account the conversion or exercise of all existing options, warrants and other convertible securities). Placement of Units Subject to the terms of the Purchase Agreement dated July 17, 1995 (the "Purchase Agreement"), the Company sold the Units to BT Securities Corporation and Internationale Nederlanden (U.S.) Securities Corporation (the "Initial Purchasers"). As part of the compensation to the Initial Purchasers in connection with the offering of the Units, the Company issued to the Initial Purchasers (i) additional warrants to purchase 350,000 shares of common stock at an initial exercise price of $3.85 per share and (ii) warrants to purchase 150,000 shares of the Company's Series F Preferred Stock at an initial exercise price of $3.85 per share. Each share of Series F Preferred Stock is convertible into one share of common stock. The additional warrants issued as such compensation have substantially the same terms as the warrants described above. All of the warrants as described herein were ascribed an aggregate value of approximately $2.2 million and are reflected in either other assets or additional paid-in capital to be amortized over the life of the Notes. Equity Proceeds Offer and Redemption In the event the Company completes an offering for the sale of $5 million or more of its equity securities on or prior to July 15, 1997 ("Equity Offering"), then following such Equity Offering, the Company must F-23 89 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) make an offer to purchase from all the holders of the Notes ("Holders") (on a date not later than the 90th day after the date of the consummation of such Equity Offering) at a purchase price equal to 110% of the aggregate principal amount of Notes to be repurchased, plus accrued and unpaid interest thereon, an aggregate principal amount of Notes equal to the lesser of (i) the maximum principal amount of Notes such that 60% of the aggregate principal amount of Notes originally issued remains outstanding after completion of the offer or (ii) the maximum principal amount of the Notes which could be purchased with 50% of the amount of net proceeds received or receivable by the Company from such Equity Offering. Excess Cash Flow Offer In the event that the Company has excess cash flow (as defined) in excess of $2 million in any fiscal year, beginning with the fiscal year ending December 31, 1996, the Company will be required to make an offer to purchase Notes from all Holders in an amount equal to 50% of all such excess cash flow for such fiscal year (not just the amount in excess of $2 million) at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest thereon ("Excess Cash Flow Offer"). The Company may credit the principal amount of Notes acquired in the open market and retired prior to the Excess Cash Flow Offer against such required Excess Cash Flow Offer, provided that each Note may only be so credited once. Excess cash flow for this purpose is generally defined as net cash flow provided by operations less capital expenditures and payments on scheduled indebtedness. Pro Forma Financial Statements The following Unaudited Pro Forma Condensed Consolidated Statements of Operations are derived from the historical financial statements of the Company set forth herein and are adjusted to reflect (i) the issuance of the Units and the application of a portion of the net proceeds to repay all indebtedness outstanding under the Amended Credit Agreement and the Bridge Loan and to redeem the Series D Preferred Stock and (ii) the acquisition of the Carried Interests Wells as if such transactions had occurred on January 1, 1995. This unaudited pro forma financial information should be read in conjunction with the notes thereto. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would actually have occurred if the transactions described had occurred as presented in such statements or which may be obtained in the future. In addition, future results may vary significantly from the results reflected in such statements due to normal crude oil and natural gas production declines, reductions in prices paid for crude oil and natural gas, future acquisitions and other factors. F-24 90 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1995
PRO FORMA ---------------------------------------------------- ADJUSTMENTS ------------------------ CARRIED NOTE HISTORICAL INTERESTS(A) OFFERING ADJUSTED ---------- ------------ -------- -------- Total revenues.................................. $ 22,595 $ 1,281 $ -- $ 23,876 ------- ------ ------- ------- Costs and expenses: Operating and exploration costs............... 9,278 194 -- 9,472 Depletion, depreciation, amortization and impairment................................. 5,973 445 -- 6,418 General and administrative expenses........... 2,744 -- -- 2,744 Interest expense.............................. 6,847 -- 3,826(B) 10,673 Other...................................... 483 -- -- 483 ------- ------ ------- ------- Total costs and expenses................... 25,325 639 3,826 29,790 ------- ------ ------- ------- Loss from continuing operations............... $ (2,730) $ 642 $ (3,826) $ (5,914) ======= ====== ======= ======= Loss applicable to common shareholders........ $ (7,765) $ (8,263) ======= ======= Loss from continuing operations per share applicable to common shareholders............. $ (0.98) $ (1.05)(C) ======= ======= Weighted average shares outstanding............. 7,904 7,904(C) ======= =======
All amounts in the tables above are in thousands except per share data. See accompanying notes to pro forma financial statements. Pro forma adjustments to the Unaudited Pro Forma Condensed Consolidated Statements of Operations included herein are as follows (dollar amounts are in thousands): (A) Revenues and expenses resulting from the acquisition of the Carried Interests Wells and adjustments to depletion, depreciation and amortization for the six months ended June 30, 1995 (the Carried Interests were acquired effective July 1, 1995). (B) Changes in interest expense associated with (i) the inclusion of $6,030 in interest, discount amortization and amortization of deferred financing costs associated with the Notes for the period ended July 24, 1995, the date of the completion of Note Offering, and (ii) the elimination of $2,204 in interest expense and deferred financing costs for that period related to the Amended Credit Agreement and the Bridge Loan. (C) The pro forma earnings per share data reflect dividends on remaining preferred stock which increase loss applicable to common shareholders. The extraordinary write-off of deferred financing costs and the charge to additional paid-in capital resulting from the early extinguishment of debt and early redemption of preferred stock have not been reflected in the earnings per share calculation as their effects are nonrecurring. Outstanding stock options, warrants and Convertible Preferred shares were not included in the calculation as their effect was antidilutive. (8) REDEMPTION OF SERIES D PREFERRED STOCK In connection with the acquisition of the Bakersfield Properties in June 1994, the Company had issued 100,000 shares of Series D Preferred Stock with detachable warrants in a private placement at a price of F-25 91 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) $100.00 per share for an aggregate value of $10 million. The Series D Preferred Stockholders ("Series D Holders") received dividends at rates from 9% to 12% per annum, payable in cash or in shares of the Series D Preferred Stock at the option of the Company. Pursuant to the Company's election to pay a portion of dividends in shares and also as a result of accretion, the number of shares outstanding of the Series D Preferred had increased to 109,312 shares and its face value had increased to $10.9 million at June 30, 1995. Upon issuance of the Series D Preferred Stock, the Company issued to the Series D Holders warrants to purchase 2,305,263 shares of common stock at an initial exercise price of $4.75 per share. The Company had ascribed a value to these warrants of $0.92 per warrant, based on certain warrant valuation models, for an aggregate value of $2.1 million. Pursuant to generally accepted accounting principles, the Company had allocated the $2.1 million ascribed value of the warrants to additional paid-in capital and correspondingly reduced the face amount of the Series D Preferred Stock reflected on its balance sheet to $7.9 million at the original date of issuance. Pursuant to the issuance of share dividends and terms of the Series D Preferred Stock, the number of warrants to purchase common stock issued to the Series D Holders thereof had increased to 3,424,666 at June 30, 1995, and the exercise price had decreased to $3.67 per share. In July 1995, the Company redeemed the total 109,312 shares of Series D Preferred Stock outstanding with proceeds resulting from a long-term refinancing of its debt. (See Note 7.) Resultant from this early redemption was an acceleration of accretion resulting in a non-cash charge of $2.1 million to paid-in capital in 1995. Also in conjunction with the early redemption of the Series D Preferred Stock, the Series D Holders exchanged all of their warrants to purchase shares of common stock for unregistered common stock of the Company. (See Note 11.) (9) COMMITMENTS AND CONTINGENCIES Risk Management and Hedging Activities The Company utilizes financial instruments as a hedging strategy to protect against the effects of volatility in crude oil and natural gas commodity prices. Upon consummation of an acquisition, the Company will usually enter into commodity derivative contracts (hedges) such as futures, swaps or collars or forward contracts which cover a substantial portion of the existing production of the acquired property. Over time, as production increases, the Company will continue to utilize hedging techniques to ensure that a substantial portion of its production remains appropriately hedged. Gains or losses under the hedging agreements are recognized in oil and gas production revenues in periods in which the hedged production occurs and such agreements are settled on a monthly basis. As of December 31, 1995, the Company was a party to various gas contracts covering volumes of approximately 4.0 Bcf and 3.4 Bcf for 1996 and 1997, respectively, at prices ranging from $1.68/MMBtu to $2.07/MMBtu; and oil hedges covering notional volumes of approximately 243 MBOE, 98 MBOE and 29 MBOE for 1996, 1997 and 1998, respectively, at prices ranging from $15.80/Bbl to $18.75/Bbl. The following table summarizes the estimated fair value of financial instruments and related transactions for non-trading activities at December 31, 1995 (amounts are in thousands):
ESTIMATED CARRYING FAIR AMOUNT VALUE(1) -------- --------- Long-Term Debt(2)(4)............................................ $ 5,600 $ 5,600 14 7/8% Senior Secured Notes(3)(4).............................. $ 63,109 $63,109 Financial Instruments........................................... -- $ 710
F-26 92 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) - --------------- (1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. (2) See Note 6, "Long-Term Debt." (3) See Note 7, "Senior Secured Note Offering." (4) The fair value of long-term debt and the Senior Secured Notes are the value the Company would have to pay to retire the debt or the Notes, including any premium or discount to the holder for the differential between the stated interest rate and the year-end market rate. The fair value of the long-term debt and the Notes is based upon interest rates available to the Company at year-end. Lease Obligations Future net minimum rental payments for office and office equipment lease commitments as of December 31, 1995 aggregated approximately $180,000 and $52,000 for 1996 and 1997, respectively. Rental expense in the aggregate under noncancellable long-term operating leases was approximately $165,000, $159,000 and $166,000 for 1995, 1994 and 1993, respectively. (10) INCOME TAXES The Company files a consolidated United States federal income tax return for its United States incorporated entities. The difference between the federal income tax statutory rate of 35% and the effective tax rate of zero for such years reflected in the accompanying consolidated statements of operations relates to the uncertainty of utilizing future benefits from net operating loss carryforwards. The Company did not pay any United States regular or alternative minimum federal income taxes during the three-year period ended December 31, 1995 due to taxable losses in all three years. At December 31, 1995, the Company had accumulated net operating loss ("NOL") carryforwards for United States federal income tax purposes of approximately $21,287,000. Certain Company security transactions occurring since 1986 have triggered changes in the stock ownership of the Company aggregating more than 50% over a three-year period. Accordingly, NOL carryforwards of approximately $5,455,000 arising prior to 1987 are limited to approximately $755,000 of future utilization in the aggregate (expiring in the year 2001), and certain NOLs are subject to limitations on the amounts that may be used to reduce taxable income in any given year. Accordingly, the total net operating loss carryforwards available to reduce federal income taxes in the future are approximately $16,587,000. Such net operating loss carryforwards expire as follows for the years ending December 31 (amounts in thousands): 1998....................................................... $ 550 2001....................................................... 205 2002....................................................... 90 2003....................................................... 1,555 2004....................................................... 755 2006....................................................... 1,045 2007....................................................... 1,150 2008....................................................... 1,449 2009....................................................... 3,316 2010....................................................... 6,472 ------- $16,587 =======
F-27 93 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Under the provisions of SFAS 109, the income tax effects of temporary differences between financial and income tax reporting and carryforwards that give rise to deferred income tax assets and liabilities at December 31, 1995 and 1994 are as follows (amounts in thousands):
DECEMBER 31, ------------------- 1995 1994 ------- ------- Deferred tax assets: Net operating loss carryforwards............................... $ 5,805 $ 3,540 Accounts payable............................................... -- 1,757 Other.......................................................... 115 -- ------- ------- Total deferred tax assets................................... 5,920 5,297 Less valuation allowances................................... (4,145) (2,472) ------- ------- Net deferred tax assets..................................... $ 1,775 $ 2,825 ------- ------- Deferred tax liabilities: Intangible drilling costs...................................... $(1,375) $(1,285) Depreciation of property and equipment......................... (306) (294) Accounts receivable............................................ -- (1,152) Other.......................................................... (94) (94) ------- ------- Total deferred tax liabilities.............................. (1,775) (2,825) ------- ------- Net deferred taxes.......................................... $ -- $ -- ======= =======
(11) STOCKHOLDERS' EQUITY Common Stock During 1993, holders of 3,000 shares of Series A Preferred Stock converted these shares into 42,857 common shares of the Company; and holders of 7,500 shares of Series B Preferred Stock converted these shares into an aggregate of 192,300 common shares of the Company. Also during 1993, the Company issued 101,850 common shares at an average price of $2.42 per share pursuant to the exercise of stock options. In June 1994, the Board of Directors adopted (and the shareholders approved) an amendment to the Company's Certificate of Incorporation increasing the number of authorized shares of the Company's common stock from 15,000,000 shares to 25,000,000 shares. In June 1994, the Company sold 1,071,538 shares of unregistered newly-issued common stock in a private placement at $3.25 per share for gross proceeds of approximately $3,482,000. The Company also issued to an agent 267,369 shares of common stock in connection with the above sale and the private placement sale of the Company's Series D Preferred Stock and Series E Preferred Stock. Additionally, the Company issued to BER 25,000 shares of common stock as part of the consideration for the purchase of the Bakersfield Properties. Pursuant to the terms of the above private placement sale agreement of common stock, the Company filed on December 20, 1994 a registration statement with the Securities and Exchange Commission covering the resale of such shares of common stock by the initial purchasers thereof. Also included in the registration statement were an additional 1,778,869 shares of common stock, which included shares issued in a November 1992 private placement sale, shares issuable upon conversion of the Company's Series B and Series C Preferred Stock and shares issuable upon exercise of certain warrants. The Company has agreed to keep a registration statement continuously effective for at most three years. During 1994, the Company issued 15,000 common shares at a price of $2.19 per share pursuant to the exercise of stock options and issued an aggregate of 60,375 restricted shares of common stock to officers at F-28 94 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) $4.00 per share. Also during 1994, the Company issued 16,671 common shares pursuant to the payment of Series E Preferred Stock dividends. The Company issued to ING Capital an aggregate of 75,000 shares of its common stock during 1995 pursuant to the terms of its Bridge Loan. In April 1995, holders of 2,500 shares of Series B Preferred Stock converted their shares into 64,100 common shares of the Company. The Company issued 16,671 and 16,770 common shares pursuant to the payment of Series E Preferred Stock dividends during 1994 and 1995, respectively. Warrant Exchanges In May 1995, BER exchanged its warrant to purchase 1,000,000 shares of the Company's common stock at $5.00 per share for 182,500 unregistered shares of the Company's common stock. The Company had ascribed a value of $850,000 to the warrant upon its original issuance and has ascribed the same value to the common stock issued in this exchange. In July 1995, in connection with the Senior Secured Note Offering, the Company and the Series D Holders effected an agreement pursuant to which the Series D Holders exchanged their warrants to purchase shares of common stock for unregistered common stock of the Company. The Series D Holders had warrants to purchase 3,424,666 shares of common stock at an exercise price of $3.67 per share at the time of the exchange. Pursuant to the agreement, the Series D Holders exchanged all of their warrants for 1,100,000 unregistered shares of common stock of the Company. This exchange agreement also contained certain conditions including certain appreciation rights to the Series D Holders effective during a two-year period following the exchange in the event of a sale of the Company or its assets and certain registration rights to the Series D Holders. Subsequent to December 31, 1995, the Company completed exchange agreements whereby certain holders of options and warrants to purchase the Company's common stock exchanged all or a portion of their options and warrants outstanding for unregistered shares of common stock of the Company. Pursuant to these exchange agreements, an option to purchase 150,000 common shares at $4.875 per share, and warrants to purchase an aggregate of 226,000 common shares at prices ranging from $4.75 to $5.50 per share, were exchanged and canceled for 65,000 unregistered shares of common stock of the Company. Additionally, in March 1996, a warrant to purchase 350,000 shares of the Company's common stock at $3.85 per share which was issued in connection with the Note Offering was returned to the Company and canceled. Preferred Stock The Series A 8% Convertible Preferred Stock, of which 5,000 shares are outstanding, is convertible into common shares of the Company at $3.50 per share, subject to certain anti-dilution provisions. At the Company's option, the preferred stock may be redeemed. Upon liquidation of the Company, the preferred shares have a preference over the common shares equal to the sum of the aggregate offering price ($50 per share) plus accrued but unpaid dividends thereon. The cumulative dividend of 8% is payable quarterly. The Series B Preferred Stock, of which 20,000 shares are outstanding, is convertible at the option of the respective holders into the Company's common stock at $3.90 per share and will be automatically converted into common stock of the Company at $3.90 per share on December 31, 1998. If the Company merges or consolidates with, or sells all or substantially all of its assets to, any entity which results in the stockholders of the Company owning less than 50% of the voting power in the election of directors of such other entity; or if any person other than Mark Harrington (Chairman of the Board, Chief Executive Officer and director of the Company) acquires more than 50% of the Company's outstanding common stock, then the conversion price F-29 95 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) shall be adjusted to the then-current market price of the Company's common stock, but only if the then-current market price is less than the conversion price. The Company may at its option elect to redeem the Series B Preferred Stock at $150 per share at any time after December 31, 1994, if the then-current market price of the Company's common stock exceeds $5.85 per share for 20 of 30 consecutive trading days. The cumulative dividend of 8% is payable quarterly. The Series C 8% Convertible Preferred Stock, of which 10,000 shares are outstanding at $100.00 per share, has substantially the same designations, preferences and rights as the Series B 8% Convertible Preferred Stock. Pursuant to the agreement with BER for the purchase of the Bakersfield Properties, the Company issued 30,000 shares of Series E Junior Convertible Preferred Stock (the "Series E Preferred Stock") to BER. The purchase price of the Series E Preferred Stock was $100.00 per share for an aggregate face value of $3,000,000. The Series E Preferred Stock is convertible at the option of the holder into common stock at a conversion price of $3.50 per share, subject to adjustment for certain stock dividends, subdivisions, reclassifications or combinations with respect to the common stock and for certain other distributions or events of consolidation, merger or sale, lease or conveyance of all or substantially all of the assets of the Company. The Series E Preferred Stock receives a cash dividend, cumulative from the date of issuance of the Series E Preferred Stock and payable quarterly in arrears commencing on September 30, 1994, at the rate of $4.00 per share per annum until June 30, 1995, and thereafter at the rate of $9.00 per share per annum. The Company has the option of paying dividends on the Series E Preferred Stock either in cash or in shares of common stock. The Series E Preferred Stock is redeemable in cash at any time, in whole or in part, at the option of the Company, at a price of $110.00 per share, plus accrued and unpaid dividends. The Company must redeem the Series E Preferred Stock in cash upon completion of its first underwritten public offering of securities following the issuance of the Series E Preferred Stock in which the net proceeds received by the Company equal or exceed $20,800,000. Each share of Series E Preferred Stock entitles the holder thereof to such number of votes per share as equals the whole number of shares of common stock into which each share of Series E Preferred Stock is then convertible, and each share of Series E Preferred Stock is entitled to vote on all matters as to which holders of common stock are to vote, in the same manner and with the same effect as such holders of common stock, voting together with the holders of common stock as one class, except for certain matters in which holders of the Series E Preferred Stock have class voting rights. At any time while a minimum of 50% of the shares of Series E Preferred Stock remain outstanding, the Company shall not take any action to alter or repeal its Certificate of Incorporation or Bylaws which would adversely affect the rights, privileges or powers of the Series E Preferred Stock (other than the issuance of additional series of stock or increases in the authorized amount of existing series of stock) without the consent or approval of at least a majority of the voting power of the Series E Preferred Stock. The Company may not pay any dividend on its common stock unless all accrued dividends on the Series E Preferred Stock have been paid. Preferred Stock Dividends The Company has paid dividends on preferred stocks for the three years ended December 31, 1995 as follows:
PREFERRED STOCK 1995 1994 1993 ------------------------------------------------ ---------- ---------- -------- 8% Convertible Series A, B, C................... $ 265,000 $ 280,000 $246,468 9% Redeemable Series D.......................... 540,161 455,065 -- 4%-9% Convertible Series E...................... 195,000 60,000 -- ---------- ---------- -------- $1,000,161 $ 795,065 $246,468 ========= ========= ========
F-30 96 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Dividends on 8% Series A, Series B and Series C Preferred Stock were paid in cash for all years presented. Dividends on the 9% Series D Preferred Stock for 1994 and the first two quarters of 1995 were paid, at the option of the Company, in additional shares of Series D Preferred Stock. Remaining accrued dividends on the Series D Preferred Stock were paid in cash at its redemption in July 1995. Dividends on the Series E Preferred Stock for 1994 and the first two quarters of 1995 were paid, at the option of the Company, in shares of common stock of the Company in lieu of cash. Dividends on the Series E Preferred were paid in cash for the remaining two quarters of 1995. The coupon rate on the Series E increased from 4% per annum to 9% per annum effective July 1, 1995. (12) STOCK OPTIONS AND WARRANTS Stock Options In October 1992, the Board of Directors adopted the Company's 1992 Stock Option Plan and the Company's 1992 Nonemployee Directors' Stock Option Plan. In May 1994, the Board of Directors adopted the Company's 1994 Stock Option Plan and amended the 1992 Nonemployee Directors' Stock Option Plan to increase the aggregate number of shares which may be issued under that plan. These plans initially had available an aggregate of 1,525,000 shares of common stock and allow the granting of options to purchase shares to employees, officers and nonemployee directors of the Company at a price, for any incentive stock options, not less than the fair market value of the common stock at the time of grant. In the case of options that do not constitute incentive stock options, the options may not be less than 85% of the fair market value of the shares at the time the option is granted. The options under these plans vest over a two-year period and expire in five years. In addition to the above stock option plans, the Company's Board of Directors and Option Committee has, from time to time, granted options directly to its officers and directors outside of the existing plans. Option transactions for the three years ended December 31, 1995 are summarized as follows:
NUMBER OF OPTIONS -------------------------------------------- AVAILABLE EXERCISE FOR FUTURE OUTSTANDING PRICE GRANT ----------- -------------- ---------- Balance at December 31, 1992................. 693,150 $2.19 -- $3.85 226,500 Expired.................................... (112,800) $3.30 -- Exercised.................................. (101,850) $2.19 -- $2.80 -- Granted.................................... 167,000 $3.88 -- $4.68 (167,000) ----------- ---------- Balance at December 31, 1993................. 645,500 $2.19 -- $4.68 59,500 Exercised.................................. (15,000) $2.19 -- New plans or shares........................ -- -- 1,100,000 Granted.................................... 330,000 $3.38 -- $4.33 (280,000) ----------- ---------- Balance at December 31, 1994................. 960,500 $2.20 -- $4.68 879,500 Expired.................................... (62,000) $3.13 -- $4.68 62,000 Granted.................................... 150,000 $2.61 -- $3.71 (150,000) ----------- ---------- Balance at December 31, 1995................. 1,048,500 $2.20 -- $4.68 791,500 ========= ========
At December 31, 1995, options to purchase 1,048,500 common shares were outstanding under these plans and agreements (744,000 exercisable with prices ranging from $2.20 to $4.68 per share). At December 31, 1995, the aggregate exercise price of these exercisable options was $2,758,000. Subsequent to December 31, F-31 97 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 1995, an option to purchase 150,000 shares of common stock at $4.875 per share was canceled pursuant to an exchange offer. (See Note 11.) Warrants The Company has issued warrants in connection with certain of its financings. Issuances of these warrants are described in other footnotes herein pertaining to those transactions. All warrant transactions for the three years ended December 31, 1995 are summarized as follows:
NUMBER OF WARRANTS EXERCISE OUTSTANDING PRICE ---------- -------------- Balance at December 31, 1992............................ 640,293 $3.20 -- $5.00 1993 Activity......................................... -- -- ---------- Balance at December 31, 1993............................ 640,293 $3.20 -- $5.00 Granted............................................... 3,757,294 $4.65 -- $5.50 ---------- Balance at December 31, 1994............................ 4,397,587 $3.20 -- $5.50 Expired............................................... (291,346) $5.00 Canceled.............................................. (4,424,666) $4.75 -- $5.00 Granted............................................... 3,051,765 $3.85 -- $4.75 ---------- Balance at December 31, 1995............................ 2,733,340 $3.20 -- $5.50 =========
At December 31, 1995, warrants to purchase 2,733,340 common shares were outstanding and exercisable under all current warrant agreements. At December 31, 1995, the aggregate exercise price of these warrants was $11,045,000. Subsequent to December 31, 1995, warrants to purchase an aggregate of 576,000 common shares at prices ranging from $3.85 to $5.50 per share were canceled pursuant to certain exchange agreements. (See Note 11.) In October 1995, the Financial Accounting Standards Board issued SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123 encourages companies to account for stock-based compensation awards based on the fair value of the awards at the date they are granted. The resulting compensation cost would be shown as an expense in the statement of income. Companies can choose not to apply the new accounting method and continue to apply current accounting requirements; however, disclosure will be required as to what net income and earnings per share would have been had the new accounting method been followed. SFAS No. 123 is effective for calendar year 1996, and the Company intends not to apply SFAS No. 123 in its statement of operations in future periods. F-32 98 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) (13) RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES The following table sets forth the Company's results of operations for oil and gas producing activities for the years ended December 31, 1995, 1994 and 1993 (amounts in thousands):
1995 1994 1993 ------- ------- ------ Oil and gas revenues................................... $16,030 $10,982 $6,507 Gas plant and related revenues......................... 6,362 1,978 -- ------- ------- ------ 22,392 12,960 6,507 ------- ------- ------ Production costs....................................... 5,263 3,610 2,249 Gas plant operating costs.............................. 3,704 1,708 -- Exploration expenses................................... 311 329 229 Depreciation -- gas plant.............................. 316 159 -- Depletion, depreciation and impairment................. 5,619 3,694 2,619 ------- ------- ------ 15,213 9,500 5,097 ------- ------- ------ Income before income taxes............................. 7,179 3,460 1,410 Income tax expense..................................... 2,513 1,211 479 ------- ------- ------ Net income............................................. $ 4,666 $ 2,249 $ 931 ======= ======= ======
The results of operations from oil and gas producing activities were determined in accordance with Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" ("SFAS 69") and, therefore, do not include corporate overhead, interest and other general income and expense items. The Company's depletion, depreciation and impairment expense for oil and gas properties per physical unit of production measured in barrel of oil equivalents (with six Mcf of gas equalling one barrel of oil) was $4.26, $4.26 and $5.13 for the years ended December 31, 1995, 1994 and 1993, respectively. The Company's depletion and depreciation expense for 1995 included an impairment write-down of $876,000 relating to the implementation of the provisions of SFAS 121. Excluding such impairment write-down, the Company's depletion and depreciation expense was $3.60 per barrel of oil equivalent for 1995. (14) CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES The aggregate amounts of capitalized costs relating to the Company's oil and gas producing activities and the related accumulated depletion, depreciation, amortization and impairment at December 31, 1995 and 1994 were as follows (amounts are in thousands):
1995 1994 -------- -------- Unproved properties............................................ $ 5,040 $ 7,414 Proved properties.............................................. 90,200 69,805 ------- ------- Total capitalized costs........................................ 95,240 77,219 Less -- accumulated depletion, depreciation and amortization... (22,501) (16,565) ------- ------- $ 72,739 $ 60,654 ======= =======
F-33 99 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The following table sets forth the costs incurred, both capitalized and expensed, in the Company's oil and gas property acquisition, exploration and development activities for the years presented (amounts in thousands):
1995 1994 1993 ------- ------- ------ Property acquisition costs -- Proved................................................. $ 407 $39,094 $5,148 Unproved............................................... -- 7,013 22 Exploration costs........................................ 311 329 229 Development costs........................................ 17,760 4,998 3,047 ------- ------- ------ $18,478 $51,434 $8,446 ======= ======= ======
(15) MAJOR CUSTOMERS AND CREDIT RISK Substantially all the Company's accounts receivable at December 31, 1995 result from oil and gas sales and joint interest billings to other companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. Such receivables are generally not collateralized. Historically, credit losses incurred by the Company on receivables generally have not been material. No known material credit losses were experienced during 1995. The Company grants short-term credit to its customers, primarily major oil and gas companies, and generally receives payment within 30 to 60 days after the month of production. The following table summarizes the customers that accounted for more than 10% of the Company's oil and gas revenues in at least one of the years indicated:
CUSTOMER 1995 1994 1993 ----------------------------------------------------------- ---- ---- ---- Cabot Oil and Gas Marketing Corp. ......................... -- 21% -- Kern Oil and Refining...................................... 10% 17% -- Mock Resources, Inc. ...................................... 24% -- -- Valero Gas Marketing, L.P. ................................ 10% -- -- Washington Energy Marketing, Inc. ......................... -- -- 36%
The Company considers its relationship with its current major customers to be satisfactory. (16) OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) Reserves The process of estimating proved developed and proved undeveloped oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of available geologic, engineering and economic data for each reservoir. The data for a given reservoir may change over time as a result of, among other things, additional development activity, production history and viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur in the future. Although every reasonable effort is made to ensure that reserve estimates are based on the most accurate and complete information possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. F-34 100 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The Company's oil and gas reserves, shown below, all of which are located in the continental United States, consist of proved developed and undeveloped reserves which, based on subjective judgments, are estimated to be recoverable in the future under existing economic and operating conditions. The following table sets forth the changes in the Company's total proved reserves for the years ended December 31, 1995, 1994 and 1993. The reserve estimates for the Royalty Interests were prepared by Huddleston Engineering. All other U.S. reserve estimates for the Company were prepared by Ryder Scott Company. Both firms are independent petroleum engineering firms. During 1993, additional proved undeveloped reserves were assigned to STLP as a result of development activities on these properties. Proved undeveloped reserves were also added in 1993 for a new waterflood project in Lea County, New Mexico. A portion of the proved undeveloped reserves from new waterflood projects was moved to the proved developed reserve category in 1993 as a result of a production response in one of the two projects during 1993. Reserves in certain instances were revised downward as a result of lower oil prices adversely affecting economic limits and also the reduced performance on some projects. During 1994, the acquisition of interests in the San Joaquin Basin properties account for the reserve volumes purchased in 1994. Additional development drilling work performed on the San Joaquin properties during the last six months of 1994 has resulted in an extension of the proved undeveloped reserve area and is reflected in the extension and discoveries. The improved production performance of the properties has also resulted in an upward revision of the proved reserves. Improved performance on certain Permian Basin properties has also resulted in an increase in reserves. The less than expected performance of the South Texas gas properties and reduced gas prices at December 31, 1994 has resulted in downward revisions of the South Texas reserves. Although gas prices were generally lower at December 31, 1994, as compared to December 31, 1993, an increase in oil prices during the same period provided an offset in revenue which prevented significant changes in economic limits for various properties. During 1995, the continued development drilling program on the San Joaquin properties and the successful drilling of a step-out well on the Ellis Lease resulted in a further extension of the proved undeveloped area which is reflected in the extension and discoveries. The favorable gas production rates on the properties also resulted in an upward revision of the proved gas reserves. In 1995, the acquisition of interests in additional wells in the San Joaquin properties and the acquisition of additional properties in the Permian Basin account for the reserve volumes purchased in 1995. F-35 101 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
OIL NGLS GAS PROVED RESERVES (BBLS) (BBLS) (MCF) - ------------------------------------------------------ ---------- --------- ---------- Proved reserves December 31, 1992..................... 1,331,085 -- 6,591,417 Revisions of previous estimates..................... (512,883) -- (272,711) Improved recovery................................... 695,198 -- 688,000 Extensions, discoveries and other additions......... 58,604 -- 7,645,825 Sales in place...................................... (562) -- (249,202) Purchases in place.................................. 334,685 -- 4,750,447 Production.......................................... (181,759) -- (1,984,820) ---------- --------- ---------- December 31, 1993..................................... 1,724,368 -- 17,168,956 Revisions of previous estimates..................... 1,697,742 -- 5,538,878 Improved recovery................................... -- -- -- Extensions, discoveries and other additions......... 950,013 -- 5,356,714 Sales in place...................................... (2,411) -- (280,907) Purchases in place.................................. 6,523,611 2,994,273 45,344,000 Production.......................................... (311,831) (85,940) (3,325,641) ---------- --------- ---------- December 31, 1994..................................... 10,581,492 2,908,333 69,802,000 Revisions of previous estimates..................... (17,124) 102,106 10,118,498 Improved recovery................................... -- -- -- Extensions, discoveries and other additions......... 1,851,381 174,991 12,291,500 Sales in place...................................... -- -- -- Purchases in place.................................. 404,508 -- 561,281 Production.......................................... (462,533) (206,823) (5,137,079) ---------- --------- ---------- December 31, 1995..................................... 12,357,724 2,978,607 87,636,200 ========== ========= ========== Proved developed reserves -- December 31, 1993........ 869,328 -- 11,361,784 ========== ========= ========== December 31, 1994..................................... 2,555,988 1,014,293 27,651,000 ========== ========= ========== December 31, 1995..................................... 2,801,504 939,088 32,474,000 ========== ========= ==========
F-36 102 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Standardized Measures of Discounted Future Net Cash Flows The Company's standardized measure of discounted future net cash flows, and changes therein, related to proved oil and gas reserves are as follows (amounts in thousands):
1995 1994 1993 --------- --------- --------- Future cash inflow............................ $ 478,302 $ 375,585 $ 57,052 Future production, development and abandonment costs....................................... (238,517) (215,163) (22,662) --------- --------- --------- Future cash flows before income taxes......... 239,785 160,422 34,390 Future income taxes........................... (47,082) (27,228) (4,747) --------- --------- --------- Future net cash flows......................... 192,703 133,194 29,643 10% discount factor........................... (81,798) (52,381) (11,835) --------- --------- --------- Standardized measure of discounted future net cash flow................................... $ 110,905 $ 80,813 $ 17,808 ========= ========= ========= Changes in standardized measure of discounted future net cash flows: Sales of oil, gas and natural gas liquids, net of production costs.................. $ (10,857) $ (7,643) $ (4,194) Extensions, discoveries and other additions................................ 13,667 6,381 9,015 Revisions of estimates of reserves proved in prior years: Quantity estimated....................... 7,685 16,144 (3,070) Net changes in price and production costs.................................. 22,261 (6,446) (2,931) Accretion of discount....................... 8,668 2,098 1,693 Purchases of reserves in place.............. 3,252 57,001 6,406 Sales of reserves in place.................. -- (342) (238) Development costs incurred.................. (16,691) (977) 2,854 Changes in future development costs......... 17,167 790 (1,913) Net change in income taxes.................. (7,725) (2,696) (2,442) Changes in production rates (timing) and other.................................... (7,335) (1,305) (1,162) --------- --------- --------- Net change.................................. $ 30,092 $ 63,005 $ 4,018 ========= ========= =========
Estimated future cash inflows are computed by applying year-end prices of oil and gas to year-end quantities of proved reserves. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Estimated future income tax expense is calculated by applying year-end statutory tax rates to estimated future pretax net cash flows related to proved oil and gas reserves, less the tax basis (including net operating loss carryforwards projected to be usable) of the properties involved. These estimates were determined in accordance with SFAS 69. Because of unpredictable variances in expenses and capital forecasts, crude oil and natural gas prices and the fact that the bases for such volume estimates vary significantly, management believes the usefulness of this data is limited. These estimates of future net cash flows do not necessarily represent management's assessment of estimated fair market value, future profitability or future cash flow to the Company. Management's investment and operating decisions are F-37 103 HARCOR ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) based upon reserve estimates that include proved as well as probable reserves and upon different price and cost assumptions from those used herein. The 1993 revisions of previous estimates of oil and gas reserves reflect the significant decrease in oil prices from 1992 to 1993 and downward adjustments due to performance on certain properties. The purchases in place of oil and gas reserves reflect the acquisition of a larger interest in STLP and the acquisition of interests in additional properties in Lea County, New Mexico. Sales in place reflect the sale of two minor properties in STLP. Extensions and discoveries are primarily a result of drilling activity on the STLP properties during 1993. Improved recovery was primarily the result of projected recovery from an additional secondary recovery project in Lea County, New Mexico. The increased production rates in 1993 reflect a full year of production from interests acquired in 1992 and production from additional property interests acquired during 1993. The 1994 revisions of the purchase of reserves in place reflect the acquisition of the property interests in the San Joaquin Basin, California. The extension and discoveries are a result of the extension of the proved undeveloped area of the San Joaquin Leases. The upward revisions are primarily a result of improved performance on the San Joaquin properties which offset the under performance of certain South Texas Properties. The sales of oil and gas are significantly increased reflecting the production from the San Joaquin properties purchased June 30, 1994. The 1995 upward revision in extensions and discoveries reflects the increased proved undeveloped area on the Ellis Lease in the San Joaquin properties which resulted from the development drilling activity and the drilling of a step-out well. Revisions of previous estimates of proved reserves are largely a result of favorable gas production on the San Joaquin properties. The net changes in prices and production costs are primarily a reflection of higher crude oil prices at December 31, 1995, as compared to prior year. Reserve purchases include the acquisition of interests in additional San Joaquin wells and the acquisition of additional properties in the Permian Basin. The future cash flows presented in the "Standardized Measures of Discounted Future Net Cash Flows" are based on contract prices for oil and gas for contracted volumes over the contract period, as applicable, and year-end 1995 oil and gas prices for oil and gas volumes not covered under oil and gas contracts. (See Note 9.) F-38 104 APPENDIX A [RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERHEAD] March 14, 1996 HarCor Energy, Inc. Five Post Oak Park, Suite 2220 Houston, Texas 77027-3413 Gentlemen: The estimated reserve volumes and future income amounts presented in this report are related to hydrocarbon prices. December 1995 hydrocarbon prices were used in the preparation of this report as required by Securities and Exchange Commission (SEC) and Financial Accounting Standards Bulletin No. 69 (FASB 69) guidelines; however, actual future prices may vary significantly from December 1995 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The Company's reserves are located in the states of Alabama, California, Louisiana, Michigan, New Mexico, Oklahoma, Texas and Wyoming. Our estimates of the net proved reserves attributable to the interests of HarCor Energy, Inc. (referred to herein as the Company) as of December 31, 1995 are presented below:
PROVED NET RESERVES AS OF DECEMBER 31, 1995 ----------------------------- LIQUID, BARRELS GAS, MMCF --------------- --------- Developed and Undeveloped......................... 15,283,842 86,569 Developed......................................... 3,687,803 31,406
The "Liquid" reserves shown above are comprised of crude oil, condensate, and natural gas liquids. Natural gas liquids comprise 25.5 percent of the Company's developed liquid reserves and 19.5 percent of the Company's developed and undeveloped liquid reserves. These natural gas liquids are attributable to the Company's ownership in the Lost Hills Gas Plant in Kern County, California. All hydrocarbon liquid reserves are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in MMCF at the pressure and temperature bases of the area where the gas reserves are located. The proved reserves presented in this report comply with the SEC's Regulation S-X Part 210.4-10 Sec. (a) as clarified by subsequent Commission Staff Accounting Bulletins, and are based on the following definitions and criteria: Proved reserves of crude oil, condensate, natural gas, and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions. Reservoirs are considered proved if economic producibility is supported by actual production or formation tests. In certain instances, proved reserves are assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs are analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by fluid contacts, if any, and (2) the adjoining [RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERFOOT] A-1 105 portions not yet drilled that can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Proved reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data become available. Proved natural gas reserves are comprised of non-associated, associated, and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of natural gas liquids, for lease and plant fuel, and the exclusion of non-hydrocarbon gases if they occur in significant quantities and are removed prior to sale. Reserves that can be produced economically through the application of improved recovery techniques are included in the proved classification when these qualifications are met: (1) successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based, and (2) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including (1) pressure maintenance, (2) cycling, and (3) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids. Estimates of proved reserves do not include crude oil, natural gas, or natural gas liquids being held in underground storage. Depending on the status of development, these proved reserves are further subdivided into: (i) "developed reserves" which are those proved reserves reasonably expected to be recovered through existing wells with existing equipment and operating methods, including (a) "developed producing reserves" which are those proved developed reserves reasonably expected to be produced from existing completion intervals now open for production in existing wells, and (b) "developed non-producing reserves" which are those proved developed reserves which exist behind the casing of existing wells which are reasonably expected to be produced through these wells in the predictable future where the cost of making such hydrocarbons available for production should be relatively small compared to the cost of a new well; and (ii) "undeveloped reserves" which are those proved reserves reasonably expected to be recovered from new wells on undrilled acreage, from existing wells where a relatively large expenditure is required, and from acreage for which an application of fluid injection or other improved recovery technique is contemplated where the technique has been proved effective by actual tests in the area in the same reservoir. Reserves from undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled and reserves assigned to the undeveloped portions of secondary projects which we have been assured will definitely be developed. The Company has interests in certain tracts which have substantial additional hydrocarbon quantities which cannot be classified as proved and consequently are not included herein. The Company has active exploratory and development drilling programs which may result in the reclassification of significant additional volumes to the proved category. [RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERFOOT] A-2 106 Our estimates of future cash inflows, future costs, and future net cash inflows before income tax as of December 31, 1995 from this report are presented as follows.
AS OF DECEMBER 31, 1995 ----------------------- Future Cash Inflows........................... $ 476,142,034 Future Costs Production....................... $ 176,878,327 Development................................. 60,698,858 ------------ Total Costs......................... $ 237,577,185 Future Net Cash Inflows Before Income Tax........................... $ 238,564,849 Present Value at 10% Before Income Tax........................... $ 123,534,000
The future cash inflows are gross revenues before any deductions and include $4,037,117 attributable to the Company's ownership in the Lost Hills Gas Plant in Kern County, California, from processing third party gas. The production costs were based on current data and include production taxes and ad valorem taxes in addition to the operating costs directly applicable to the individual leases or wells. The development costs were based on current data. The Company furnished us with gas prices in effect at December 31, 1995 and with its forecasts of future gas prices which take into account SEC guidelines, current market prices, contract prices, and fixed and determinable price escalations where applicable. In accordance with SEC guidelines, the future gas prices used in this report make no allowances for future gas price increases which may occur as a result of inflation nor do they account for seasonal variations in gas prices which may cause future yearly average gas prices to be different than December gas prices. For gas sold under contract, the contract gas price including fixed and determinable escalations exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves. The Company furnished us with liquid prices in effect at December 31, 1995 and these prices were held constant to depletion of the properties. In accordance with SEC guidelines, changes in liquid prices subsequent to December 31, 1995 were not considered in this report. Operating costs for the leases and wells in this report were based on the operating expense reports of the Company and include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. Development costs were furnished to us by the Company and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The current operating and development costs were held constant throughout the life of the properties. At the request of HarCor, their estimate of zero net abandonment costs after salvage value for onshore properties was used in this report. Ryder Scott has not performed a detailed study of the abandonment costs nor the salvage value and makes no warranty for HarCor's estimate. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments. We have included gas imbalances for those properties located in South Texas. No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist in any other areas. The estimates of reserves presented herein are based upon a detailed study of the properties in which the Company owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. The Company has informed us that they have furnished us all of the accounts, records, geological and engineering data and reports, and other data required for this investigation. The ownership interests, prices, and other [RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERFOOT] A-3 107 factual data furnished by the Company were accepted without independent verification. The estimates presented in this report are based on data available through December 1995. The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations. In general, we estimate that future gas production rates will continue to be the same as the average rate for the latest available 12 months of actual production until such time that the well or wells are incapable of producing at this rate. The well or wells were then projected to decline at their decreasing delivery capacity rate. Our general policy on estimates of future gas production rates is adjusted when necessary to reflect actual gas market conditions in specific cases. The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation. Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future cash inflows for the subject properties. Very truly yours, RYDER SCOTT COMPANY PETROLEUM ENGINEERS C. Patrick McInturff, P.E. Petroleum Engineer CPM/sw Approved: Fred W. Ziehe, P.E. Group Vice President [RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERFOOT] A-4 108 ================================================================================ NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR MAKE ANY REPRESENTATIONS IN CONNECTION WITH THE OFFER CONTAINED HEREIN OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITY OTHER THAN THOSE TO WHICH IT RELATES NOR DOES IT CONSTITUTE AN OFFER TO SELL, OR A SOLICITATION OF AN OFFER TO BUY, TO ANY PERSON IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF. --------------------- TABLE OF CONTENTS
PAGE ---- Available Information................ 2 Prospectus Summary................... 3 Risk Factors......................... 12 Use of Proceeds...................... 17 Capitalization....................... 18 Price Range of Common Stock.......... 19 Dividend Policy...................... 19 Dilution............................. 20 Selected Financial Data.............. 21 Management's Discussion and Analysis of Financial Condition and Results of Operations...................... 22 Business and Properties.............. 34 Management........................... 47 Principal and Selling Stockholders... 54 Transactions with Related Parties.... 56 Description of Capital Stock and Other Securities................... 57 Shares Eligible for Future Sale...... 60 Underwriting......................... 62 Legal Matters........................ 63 Accountants.......................... 63 Engineers............................ 63 Glossary of Oil and Gas Terms........ 64 Index to Consolidated Financial Statements......................... F-1 Summary Report of Ryder Scott Company............................ A-1
================================================================================ ================================================================================ 6,400,000 SHARES [HARCOR ENERGY, INC. LOGO] HARCOR ENERGY, INC. COMMON STOCK -------------------- PROSPECTUS -------------------- RAUSCHER PIERCE REFSNES, INC. PETRIE PARKMAN & CO. SOUTHCOAST CAPITAL CORPORATION July 25, 1996 ================================================================================ -----END PRIVACY-ENHANCED MESSAGE-----