-----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, GoUaeq1xm2H9LGNxYUAPKMR6xmdKL4jfha3cnyyqSncddENF3xWw6/Fb3GlrCR13 T9WRtfuPiobeopHSHPEoEA== 0001047469-99-013469.txt : 19990405 0001047469-99-013469.hdr.sgml : 19990405 ACCESSION NUMBER: 0001047469-99-013469 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990402 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MICHAEL PETROLEUM CORP CENTRAL INDEX KEY: 0001061299 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760510239 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 333-52263 FILM NUMBER: 99586764 BUSINESS ADDRESS: STREET 1: 13101 NORTHWEST FREEWAY STREET 2: SUITE 320 CITY: HOUSTON STATE: TX ZIP: 77040 BUSINESS PHONE: 7138950909 MAIL ADDRESS: STREET 1: 13101 NORTHWEST FREEWAY STREET 2: SUITE 320 CITY: HOUSTON STATE: TX ZIP: 77040 10-K405 1 10-K405 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 OR / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO ---------- ---------- COMMISSION FILE NUMBER: 333-52263* MICHAEL PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) TEXAS (State or Other Jurisdiction of Incorporation or Organization) 76-0510239 (I.R.S. Employer Identification No.) 13101 NORTHWEST FREEWAY, SUITE 320, HOUSTON, TEXAS 77040 (Address of principal executive offices including zip code) (713) 895-0909 (Registrant's telephone number including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: X No: --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K: X --- As of March 29, 1999, there were 10,000 shares of Michael Petroleum Corporation Common Stock, $0.10 par value, issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE None * The Commission File Number refers to a Form S-4 Registration Statement filed by the Registrant under the Securities Act of 1933 which was declared effective on July 22, 1998. TABLE OF CONTENTS
PAGE ---- Item 1. Business The Company...................................................... 3 Developments in 1998............................................. 3 Market Factors................................................... 6 Competition...................................................... 6 Governmental Regulation.......................................... 7 Abandonment Costs................................................ 10 Operating Hazards and Insurance.................................. 10 Employees........................................................ 10 Item 2. Properties......................................................... 10 Oil and Natural Gas Reserves..................................... 10 Item 3. Legal Proceedings.................................................. 15 Item 4. Submission of Matters to a Vote of Security Holders................ 15 Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.............................................. 15 Item 6. Selected Consolidated Financial Data............................... 15 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition.......................................... 16 General........................................................ 16 Results of Operations.......................................... 16 Liquidity and Capital Resources................................ 18 Item 7A Quantitative and Qualitative Disclosures About Market Risk......... 29 Item 8. Financial Statements............................................... 30 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................................... 50 Item 10. Directors and Executive Officers of the Registrant................. 50 Item 11. Executive Compensation............................................. 51 Item 12. Security Ownership of Certain Beneficial Owners and Management..... 53 Item 13. Certain Relationships and Related Transactions..................... 53 Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.... 54
PRELIMINARY NOTE: The statements regarding future financial performance and results and oil and natural gas prices and the other statements which are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "predict" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices of natural gas and oil, results for future drilling and marketing activity, the need for and availability of capital, future production and costs and other factors detailed herein and in the Company's other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. See Item 7. "Management's Discussion and Analysis of Results of Operations--Cautionary Statements Regarding Forward-Looking Information." PART I ITEM 1. BUSINESS THE COMPANY Michael Petroleum Corporation (the "Company" or "Michael") is engaged in the acquisition, exploitation and development of oil and natural gas properties, principally in the Lobo Trend of South Texas (the "Lobo Trend"). The Company has significantly expanded its production and reserve base in recent years through development drilling and exploitation activities and by acquiring producing and undeveloped properties. On March 31, 1998 and April 2, 1998, the Company closed separate acquisitions of Lobo Trend properties with Enron Oil and Gas Company ("Enron") (the "Enron Acquisition") and Conoco Inc. ("Conoco") (the "Conoco Acquisition") (collectively, the "Transactions"), pursuant to which the Company acquired interests in 170 gross (98 net) wells covering approximately 46,900 gross acres. In April 1998, the Company acquired leasehold interests in undeveloped acreage (the "Lobo Lease") from Mobil Producing Texas and New Mexico Inc. ("Mobil"), covering approximately 39,636 gross acres in the Lobo Trend. The interests in properties acquired included acreage that was geographically close and geologically similar to the Company's other properties. The Company applied approximately $78.3 million in net proceeds from the sale of its 11 1/2% Senior Notes due 2005, Series A in connection with the closing of the Transactions and the Lobo Lease. See "--Developments in 1998" below and Item 7. "Management's Discussion and Analysis of Results of Operations and Financial Condition". The Lobo Trend, which is located in Webb and Zapata counties in South Texas, covers in excess of one million gross acres and contains multi-pay reservoirs of oil and natural gas. Since 1991, Webb and Zapata counties collectively have constituted one of the largest onshore natural gas producing regions in the United States. Although over 3,500 wells have been drilled and cumulative production from the Lobo Trend since its discovery in 1973 exceeds 6.3 trillion cubic feet of natural gas equivalents, the Lobo Trend is believed to be only partially exploited, with existing wells producing from only approximately 125,000 acres. The primary geologic target in the Lobo Trend is the Lobo sand series of the lower Wilcox formation, which contains three primary objectives. Two secondary objectives also exist, one above the three Lobo sands and one below. The Company believes that the existence of these multi-pay reservoirs reduces drilling risk and enhances the profitability of invested capital. The Company began its operations in 1983 and focused on developing prospects in South Texas. Since the early 1990s, the Company has become an increasingly active participant in development drilling in the Lobo Trend. In 1996, the Company acquired interests in approximately 21,000 developed and undeveloped gross acres in the Lobo Trend (the "1996 Acquisition"). The Company uses 3-D seismic imaging and other advanced technologies in the development and exploitation of its properties. As of December 31, 1998, 3-D seismic data had been obtained over approximately 90% of the Company's properties. See generally, Item 2. "Properties--Glossary of Certain Industry Terms." DEVELOPMENTS IN 1998 SALE AND EXCHANGE OF SENIOR NOTES On April 2, 1998, the Company completed a debt offering in a private placement exempt from registration under the Securities Act of 1933, of $135 million of 11 1/2% Senior Notes, due 2005, Series A (the "Series A Notes"). A portion of the net proceeds from the sale were used to repay outstanding borrowings under a previous credit agreement (the "T.E.P. Financing") of approximately $28 million. Under the T.E.P. Financing, a 30% net profits interest in all of the Company's oil and natural gas properties had been granted to the lender, along with a warrant to purchase up to 5% of the Company's common stock. On April 2, 1998, the T.E.P. Financing Agreement was terminated, and the unamortized balance of the notes payable discount, the deferred debt issuance costs and certain fees incurred at closing were written off and reflected in the income statement as an extraordinary loss, net of taxes. On July 22, 1998, the Securities and Exchange Commission ("SEC") declared the Company's Registration Statement on Form S-4 effective pursuant to Section 8(a) of the Securities Act. The Registration Statement had been filed to cover offers of exchange of the Company's 11 1/2% Senior Notes Due 2005, Series B (the "Series B Notes") for the Series A Notes. As of September 4, 1998, all of the $135 million original principal amount of the Series A Notes had been exchanged for Series B Notes, the terms of which are substantially identical to the terms of the Series A Notes. The effective interest rate under the Series B Notes for the year ended December 31, 1998 was 12.04%. CREDIT FACILITY In May 1998, the Company entered into a four-year credit facility (the "Credit Facility") with Christiania Bank og KreditKasse ("Christiania") which provides maximum loan amounts totaling $50.0 million, subject to borrowing base limitations. The borrowing base will be redetermined semiannually by Christiania based on the Company's proved oil and natural gas reserves beginning at March 31, 1999. Although the initial borrowing base was $30 million, and effective November 9, 1998, the borrowing base was increased by $5 million, the new borrowing base, effective April 1, 1999, was reduced to $23 million. The maturity date of all indebtedness under the Credit Facility is May 28, 2002. The effective interest rate under the Credit Facility for the year ended December 31, 1998 was 6.8%. At December 31, 1998, the Company was in default of certain financial covenants under the Credit Facility but has obtained waivers of such defaults from Christiania and amended the Credit Facility. See Item 7. "Management's Discussion and Analysis of Results of Operation and Financial Condition--Financing Arrangements" and "--Cautionary Statements Regarding Forward-Looking Information-Future Need For and Availability of Capital," "--Restrictions Imposed by Lenders" and "--Incurrence of Substantial Indebtedness." ENRON ACQUISITION The Enron Acquisition was consummated on March 31, 1998. Pursuant to a Purchase and Sale Agreement, Enron conveyed to the Company (i) interests in certain oil and natural gas leases covering approximately 7,500 gross acres in Hidalgo County and Zapata County, Texas, (ii) certain interests in leases covering approximately 37,500 gross acres located in Webb County, Texas (the "Ranch Lands") covering the interval between the surface and 100 feet below the stratigraphic equivalent of the base of the Lobo 6 Sand, (iii) all of Enron's interests in and to a 2.67% non-participating term royalty interest in and to the Ranch Lands limited in depth to the interval covered by the lease granted on the Ranch Lands and terminating simultaneously therewith and (iv) all seismic data owned by Enron covering these properties described in (i) and (ii) above. The purchase price for the Enron Acquisition was $45.8 million, net of closing and post-closing adjustments, and the conveyance by the Company to Enron of certain oil and natural gas properties in Webb County, Texas. The dollar portion of the purchase price was paid in the form of a promissory note issued by the Company in the original principal amount of $45.8 million which was repaid on April 2, 1998, the closing date of the sale of the Series A Notes and the Conoco Acquisition. In addition, the Company granted to Enron a non-exclusive license to use the seismic data it conveyed to the Company. Under the Enron Purchase and Sale Agreement, the Company acquired the properties on an "as is" basis. The Purchase and Sale Agreement also provided for limited environmental indemnities. The Company must indemnify Enron for certain environmental liabilities incurred by Enron, including claims arising in whole or in part from the sole or concurrent negligence or gross negligence of Enron. 4 CONOCO ACQUISITION The Conoco Acquisition was consummated on April 2, 1998, with Conoco conveying to the Company a leasehold interest in all of Conoco's interests in approximately 39,000 gross acres located in Webb County, Texas, covering the same interval covered by the Enron leases. The Company paid $22.5 million, which reflected certain closing adjustments. The Company used a portion of the net proceeds from the sale of the Series A Notes to pay the purchase price of the Conoco Acquisition. Under the Conoco Purchase and Sale Agreement, the Company acquired the properties on an "as is" basis. The Purchase and Sale Agreement also provided for limited environmental indemnities. The Company must indemnify Conoco for certain environmental liabilities incurred by Conoco, including claims arising in whole or in part from the sole or concurrent negligence, gross negligence or strict liability of Conoco. LOBO LEASE TRANSACTION By agreement dated April 20, 1998, the Company acquired from Mobil certain leasehold interests in undeveloped acreage in the Lobo Trend in Webb County, Texas. Under this agreement, Mobil assigned to the Company its interests in two existing leases and granted by lease interests in additional undeveloped acreage under an oil and gas lease having a primary term of seven years. The lease, which has an effective date of January 1, 1998, covers 39,636 gross acres and covers the same interval covered by the Enron and Conoco leases. Excluded from the lease grant were existing productive wells and certain drilling units on the subject properties. The lease contains provisions obligating the Company to indemnify Mobil for certain liabilities incurred by Mobil as a result of the Company's operations on the Lobo Lease properties, including liabilities for violations of environmental laws. The Company and Mobil also agreed that effective May 1, 1998, Michael would be appointed operator with respect to the properties covered by the Lobo Lease pursuant to a joint operating agreement between them. As part of the consideration for the Lobo Lease and related matters, the Company agreed to make future deliveries to Mobil of 4.0 Bcf of natural gas. On April 23, 1998, the Company entered into a contract to secure delivery of this volume of natural gas from a third party for $9.98 million. OTHER ACQUISITIONS On July 31, 1998, the Company acquired all of the common stock of two companies owning non-operating working interests in 132 wells on approximately 17,000 gross (500 net) acres, primarily in the Lobo Trend located in Webb and Zapata Counties in Texas for $2.6 million. The working interest percentages range from 0.5% to 15%, with an average working interest of approximately 2.5% and an average net revenue interest of approximately 2.0%. In December 1998, the Company loaned $1.5 million to a joint venture between a Mexican construction company and a Texas limited liability company to participate in the drilling of 38 natural gas wells for Petroleos Mexicanos ("Pemex") in the Burgos Basin of Northern Mexico. The Mexican construction company has a 51% ownership interest in the joint venture and the Texas limited liability company has a 49% ownership interest. The note is due December 1999 and bears interest at 12% per annum. The Company has an option to convert the note receivable to a 50% equity interest in the Texas limited liability company holding the 49% interest in the venture. 5 MARKET FACTORS The revenues generated by the Company's operations are highly dependent upon the prices of and demand for oil and natural gas. The price received by the Company for its oil and natural gas production depends on numerous factors beyond the Company's control. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, the actions of the Organization of Petroleum Exporting Countries, the foreign supply of oil and natural gas and overall economic conditions. It is impossible to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices may adversely affect the Company's financial condition, liquidity and results of operations. Crude oil prices are generally determined by global supply and demand. After sinking to a five-year low at the end of 1993, oil prices reached their highest levels since the 1990 Persian Gulf War during fourth quarter 1996 and January 1997. Posted crude oil prices ranged from $17 to $20 during most of 1997, then declined to a $16 average in December 1997. Crude oil prices continued to decline throughout 1998, dropping to a West Texas Intermediate price of $8.00 per barrel in December 1998, the lowest level since 1978. This decline has been caused by low demand, as well as the failure of OPEC, at its November 1998 meeting, to further reduce production quotas. Low demand has been caused by warmer than normal winter temperatures and a slow recovery in Asian economies. Natural gas prices are influenced by national and regional supply and demand, which is often dependent upon weather conditions. Natural gas competes with alternative energy sources as a fuel for heating and the generation of electricity. Generally because of colder weather, storage concerns and U.S. economic growth, prices remained relatively high during most of 1996 and 1997. Gas prices declined, however, in December 1997 and have remained lower throughout 1998, primarily because the winters of 1997-1998 and 1998-1999 were abnormally mild in the central and eastern U.S. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." The Company currently markets all of its natural gas through Upstream Energy Services, L.L.C. ("Upstream") pursuant to the terms of an agreement dated effective as of November 1, 1998 (the "Sales Agreement"). The Company and the predecessor to Upstream had similar marketing arrangements in effect from 1991 to October 1998. Under the Sales Agreement, the Company has agreed to sell, and Upstream has agreed to market all of the natural gas produced from properties owned or operated by the Company at the price realized by Upstream from the sale of such natural gas production less (i) the costs incurred by Upstream in the transportation, treating and handling of the gas prior to resale and (ii) marketing compensation ranging from $0.03 to $0.01 per Mmbtu sold, as measured at the point of delivery. The marketing compensation is calculated as follows:
VOLUMETRIC TIER (MMBTU/DAY) MARKETING FEE --------------------------- ------------- First 20,000 $0.03/MMbtu 20,001 to 40,000 $0.02/MMbtu All volumes over 40,000 $0.01/MMbtu
The Sales Agreement is effective for a one-year period and is renewable quarterly thereafter, subject to either party giving 60 days written notice of termination. Until August 1997, the Company's Chief Executive Officer owned an aggregate of approximately 20% of the capital stock of Upstream. See Item 13. "Certain Relationships and Related Transactions." In conjunction with the 1996 Acquisition, Conoco (as the successor in interest to the seller) and the Company entered into a Gas Exchange Agreement whereby such parties agreed that the Company would deliver to Conoco all of the natural gas produced from the leases acquired in the 1996 Acquisition at the point(s) at which such gas enters the transmission pipelines owned by Lobo Pipeline Company ("Lobo Pipeline") (the "delivery point") in exchange for natural gas in the same quantity and quality delivered by Conoco at the Agua Dulce hub near Corpus Christi, Texas. The parties' obligations under the Gas Exchange Agreement are subject to the natural gas delivered and the pipeline meeting certain specifications. The title to the Company's gas vests in Conoco at the delivery point, except to the extent such amount exceeds the amount of redelivered gas at the redelivery point, in which case the Company retains title and ownership of such excess, which is then transported by Lobo Pipeline pursuant to an Interruptible Gas Transportation Agreement. The consideration received by Lobo Pipeline is $0.17 per Mcf for compression, transportation and dehydration. COMPETITION The oil and natural gas industry is highly competitive, and the Company encounters competition from other oil and natural gas companies in all areas of its operations, including the acquisition of seismic, lease options, exploratory prospects and proven properties. The Company's competitors in the Lobo Trend area include major integrated oil and natural gas companies, including Chevron Corporation, Conoco, Enron Corp. and Sonat Exploration Company, and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of the Company's competitors, including those with whom it competes in the Lobo Trend, are large, well-established companies with substantially larger operating staffs and significantly greater capital resources than those of the Company and which, in many instances, have been engaged in the oil and natural gas business for a much longer time than the Company. Such companies may be able to pay more for exploratory 6 prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than could the Company, given its limited financial and human resources. In addition, such companies may be able to expend greater resources on the existing and changing technologies that the Company believes are and will be increasingly important to the current and future success of oil and natural gas companies. The Company's ability to acquire additional properties in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in this highly competitive market. The Company believes that the technological expertise and experience of its management in exploiting the Lobo Trend, as well as the Company's relationships with landowners in the area, generally enable it to compete effectively in the Lobo Trend. However, the business of developing or acquiring reserves is capital intensive, especially in the Lobo Trend area where the land blocks typically range between 5,000 and 50,000 acres. The Company will require additional financing or participation of industry partners to effect future acquisitions in this area. Such additional financing may take the form of equity securities, debt securities or some combination thereof, and there can be no assurance that such financing will be available on terms that are acceptable to the Company, if at all. Failure to secure such financing or to locate industry partners would adversely affect the Company's ability to compete with these other companies for lease acreage as it may become available. See Item 7. "Management's Discussion and Analysis of Results of Operations and Financial Condition." In addition, to the extent that the Company engages in oil and natural gas exploration and production activities on properties in geographic areas other than the Lobo Trend area, the Company may be subject to additional competitive disadvantages due to its lack of experience in and familiarity with prospect characteristics of those areas. GOVERNMENTAL REGULATION Various aspects of the Company's oil and natural gas operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the oil and natural gas industry and its individual members. 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 natural gas could be sold. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. 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 (the "Decontrol Act"). The Decontrol Act removed all remaining NGA and NGPA price and nonprice controls affecting wellhead sales of natural gas effective January 1, 1993. The Company's operations currently are located primarily in Texas. Thus, the Company's business is subject to environmental regulation on the state level primarily by the Railroad Commission of Texas and the Texas Natural Resource Conservation Commission. The Railroad Commission of Texas regulations may require the Company to obtain permits and drilling bonds for the drilling of wells. Additionally, the Railroad Commission of Texas regulates the spacing of wells, plugging and abandonment of such wells and the remediation of contamination caused by most types of exploration and production wastes. The Railroad Commission requirements for remediation of contamination are, for the most part, administered on a case-by-case basis. The Company expects that such regulations will be formalized in the future and will in all likelihood become more stringent. REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited nonpipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the results of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. While the United States Court of Appeals upheld most of Order 7 No. 636 in 1997, certain related FERC orders, including the individual pipeline restructuring proceedings, are still subject to judicial review and may be reversed or remanded in whole or in part. While the outcome of these proceedings cannot be predicted with certainty, the Company does not believe that it will be affected materially differently than its competitors. The FERC has also announced several important transportation-related policy statements and proposed rule changes, including a statement of policy and a request for comments concerning alternatives to its traditional cost-of-service ratemaking methodology to establish the rates interstate pipelines may charge for their services. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. Both the policy statement and individual pipeline negotiated rate authorizations are currently subject to appeal before the U.S. Court of Appeals for the D.C. Circuit. In February 1997, the FERC announced a broad inquiry into issues facing the natural gas industry to assist the FERC in establishing regulatory goals and priorities in the post-Order No. 636 environment. In October 1997, the United States Court of Appeals for the Fifth Circuit vacated a FERC decision and remanded it to the agency with directions to reconsider the criteria FERC used to distinguish nonjurisdictional gathering from jurisdictional transportation on offshore pipeline systems. The final outcome of these and other issues being considered by the FERC, and their effect on the Company and its competitors cannot be predicted with certainty. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. OIL PRICE CONTROLS AND TRANSPORTATION RATES Sales of crude oil, condensate and natural gas liquids by the Company are not currently regulated and are made at market prices. The price the Company receives from the sale of these products may be affected by the cost of transporting the products to market. ENVIRONMENTAL Extensive federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to the protection of the environment affect the Company's oil and natural gas operations. 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 civil and even criminal 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 or entity liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person or entity. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and consequently affects the Company's profitability. 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's operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon the capital expenditures or competitive position of the Company. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") imposes liability, without regard to fault or the legality of the original act, on certain classes of persons that are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances at the disposal site. Under CERCLA such persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Comparable state statutes also impose liability on the owner or operator of a property for remediation of environmental contamination existing on such property. In addition, companies that incur liability frequently confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site. 8 The Company currently owns or leases, and has in the past owned or leased, numerous properties that have been used for the exploration and production of oil and natural gas and for other uses associated with the oil and gas industry. Although the Company has followed operating and disposal practices that it considered appropriate under applicable laws and regulations, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where such wastes were taken for disposal. In addition, the Company owns or leases properties that have been operated by third parties in the past. The Company could incur liability under CERCLA or comparable state statutes for contamination caused by wastes it generated or for contamination existing on properties it owns or leases, even if the contamination was caused by the waste disposal practices of the prior owners or operators of the properties. The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as "hazardous waste." A similar exemption is contained in many of the state counterparts to RCRA. Disposal of such nonhazardous oil and natural gas exploration, development and production wastes usually is regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the oil and gas industry in the future. From time to time legislation has been proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of "hazardous wastes" thereby potentially subjecting such wastes to more stringent handling and disposal requirements. If such legislation were enacted, or if changes to applicable state regulations required the wastes to be managed as hazardous wastes, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. The Company's operations are also subject to the Clean Air Act (the "CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from operations of the Company. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. However, the Company believes its operations will not be materially adversely affected by any such requirements, and the requirements are not expected to be any more burdensome to the Company than to other similarly situated companies involved in oil and natural gas exploration and production activities. The Federal Water Pollution Control Act of 1972 (the "FWPCA") imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into navigable waters. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA provides for civil, criminal and administrative penalties for unauthorized discharges of oil and other hazardous substances and imposes substantial potential liability for the costs of removal or remediation. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the Environmental Protection Agency has promulgated regulations that require many oil and natural gas production sites, as well as other facilities, to obtain permits to discharge storm water runoff. The Company believes that compliance with existing requirements under the FWPCA and comparable state statutes will not have a material adverse effect on the Company's financial condition, results of operations or cash flows of the Company. The Company maintains insurance against "sudden and accidental" occurrences which may cover some, but not all, of the environmental risks described above. Most significantly, the insurance maintained by the Company may not cover the risks described above that are not attributable to a single, abrupt event. Further, there can be no assurance that such insurance will continue to be available to cover all such costs 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, results of operations or cash flows. REGULATION OF OIL AND NATURAL GAS EXPLORATION AND PRODUCTION 9 Exploration and production operations of the Company are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells, and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which oil and gas can be produced from the Company's properties. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." ABANDONMENT COSTS The Company is responsible for payment of plugging and abandonment costs on oil and natural gas properties pro rata to its working interest. Historically, the ultimate aggregate salvage value of lease and well equipment located on the Company's properties has not exceeded the costs of abandoning such properties. There can be no assurance, however, that this historical trend will continue or that the Company will be successful in avoiding additional expenses in connection with the abandonment of any of its properties. In addition, abandonment costs and their timing may vary due to many factors including actual production results, inflation rates and changes in environmental laws and regulations. OPERATING HAZARDS AND INSURANCE The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosion, blowout, pipe failure, casing collapse, unusual or unexpected formation pressures and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, 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, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of the operating risks described above. The Company's insurance does not cover business interruption or protect against loss of revenues. There can be no assurance that any insurance obtained by the Company will be adequate to cover any losses or liabilities. The Company cannot predict the continued availability of insurance or the availability of insurance at economic rates. The occurrence of a significant event against which it is not fully insured or indemnified could have a material adverse effect on the Company's financial condition, results of operations or cash flows. EMPLOYEES At December 31, 1998, the Company employed 27 full-time employees, and numerous independent contractors. The Company believes that its relationships with its employees are satisfactory. None of the Company's employees are covered by a collective bargaining agreement. From time to time, the Company utilizes the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well site surveillance, permitting and environmental assessment. ITEM 2. PROPERTIES LOBO TREND The Company owns interests in developed and undeveloped properties in South Texas, primarily in the Lobo Trend and undeveloped acreage in South Texas. The Company's Lobo Trend properties represented substantially all of its reserves and PV-10 Value, as of December 31, 1998. The Company is the operator of over 65% of the wells in which it has an interest. The Lobo Trend in Webb and Zapata Counties in South Texas is one of the largest onshore natural gas producing regions in the United States. The primary geologic target in the Lobo Trend is the Lobo sand series of the Lower Wilcox formation, which contains multiple pay sands. The primary objectives in the Lobo Trend are the Lobo 1 and Lobo 6 sands. Other pay sands exist at shallower and deeper horizons in certain areas of the trend. Extensive faulting has trapped hydrocarbons in the Lobo Trend producing horizons and has created a complex geological environment. Until recently, 2-D seismic and subsurface well control were the primary means for developing the field. The introduction of 3-D seismic to the area in the early 1990s has improved drilling success rates, and the Company has similarly experienced an overall increase in its drilling success rates in the Lobo Trend as technology has evolved. The Company's Lobo Trend production is from reservoirs at depths between 6,000 to 14,000 feet. Most of the production horizons are of low permeability and must be fracture stimulated to improve rates of production. As a result, a typical well has a high initial production rate which declines rapidly and is followed by a long period of production at a lower rate with a gradual decline. OIL AND NATURAL GAS RESERVES The following table sets forth estimated net proved natural gas and oil and condensate reserves of the Company and the present value of estimated future net cash flows related to such reserves as of December 31, 1996, 1997 and 1998. The reserve data and present values presented have been estimated by Huddleston & Co., Inc. For further information concerning the present value of future net revenue from these proved reserves, see Note 11 of Notes to Consolidated Financial Statements of the Company. See also "Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition".
AS OF DECEMBER 31, ------------------------------------------- 1996 1997 1998 ---- ---- ---- Estimated proved reserves: Oil and condensate (MBbls) 239 265 4,923 Natural gas (Mmcf) 49,246 51,165 189,753 10 Natural gas equivalents (Mmcfe) 50,678 52,754 219,291 Proved developed reserves as a percentage of proved reserves 34% 45% 27.2% PV-10 Value (dollars in thousands)(1) $60,727 $51,487 $132,638
(1) PV-10 Value represents the present value of estimated future net revenues before income tax discounted at 10% using prices in effect at the end of the respective periods presented and including the effects of hedging activities. In accordance with applicable requirements of the SEC, estimates of the Company's proved reserves and future net revenues are made using oil and natural gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). The average prices used in calculating historical PV-10 Value as of December 31, 1998 were $9.17 per Bbl of oil and $1.85 per Mcf of natural gas, compared to $15.91 per Bbl of oil and $2.42 per Mcf of natural gas as of December 31, 1997, and $23.86 per Bbl of oil and $2.76 per Mcf of natural gas as of December 31, 1996. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein represents estimates only. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Furthermore, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including future prices, production levels and costs, that may not prove correct. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency. PRODUCTION, PRICES AND EXPENSES The following table presents certain information with respect to oil and natural gas production, prices and expenses attributable to oil and natural gas property interests owned by the Company for the years ended December 31, 1996, 1997, and 1998.
YEAR ENDED DECEMBER 31, ----------------------------------------- 1996 1997 1998 ---- ---- ---- Production volumes: Oil and condensate (MBbls) 37 21 79 Natural gas (Mmcf) 1,324 3,685 10,510 Total (Mmcfe) 1,546 3,811 10,984 Average realized prices: Oil, condensate and natural gas liquids (per Bbl) $20.05 $18.95 $11.19 Natural gas (per Mcf) 2.15 2.33 2.07 Natural gas equivalents (per Mcfe) (1) 2.32 2.35 2.06 Expenses (per MCFE): Production costs 1.25 0.49 0.37 Depreciation, depletion and amortization 0.66 0.96 1.14 Impairment of oil and gas properties 0.10 0.06 0.49 General and administrative, net 0.27 0.26 0.16
(1) Includes effects of hedging transactions. PRODUCTIVE WELLS The following table sets forth the number of productive wells in which the Company owned an interest as of December 31, 1997 and 1998:
1997 1998 -------------- ------------- GROSS NET GROSS NET Oil -- -- 7 -- Natural gas 78 43 438 184 ---- ---- ---- ---- 11 Total 78 43 445 184 ==== ==== ==== ====
Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connection. Wells that are completed in more than one producing horizon are counted as one well. ACREAGE The following table sets forth the Company's developed and undeveloped gross and net leasehold acreage as of December 31, 1997 and 1998.
1997 ------------------------------------------------------------ DEVELOPED UNDEVELOPED TOTAL ------------------ --------------- ---------------- GROSS NET GROSS NET GROSS NET Lobo Trend 20,676 11,554 8,206 5,516 28,882 17,070 Other 640 640 -- -- 640 640 ------ ------ ----- ----- ------ ------ Total 21,316 12,194 8,206 5,516 29,522 17,710 ====== ====== ===== ===== ====== ====== 1998 ------------------------------------------------------------ DEVELOPED UNDEVELOPED TOTAL ------------------ --------------- ---------------- GROSS NET GROSS NET GROSS NET Lobo Trend 30,360 18,467 60,413 44,184 90,773 62,651 Other 2,585 394 -- -- 2,585 394 ------ ------ ------ ------ ------ ------ Total 32,945 18,861 60,413 44,184 93,358 63,045 ====== ====== ====== ====== ====== ======
Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether or not such acreage contains proved reserves. A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres expressed as whole numbers and fractions thereof. DRILLING ACTIVITIES The table below sets forth the drilling activities of the Company on its properties for the years ended December 31, 1996, 1997 and 1998.
YEAR ENDED DECEMBER 31, ----------------------------------------------------------- 1996 1997 1998 ------------- ------------- ------------- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- Development wells Productive Natural Gas 2 1.2 15 9.2 26 17.6 Productive Oil 0 0.0 0 0.0 0 0.0 Dry 0 0.0 4 2.5 6 4.7 Exploratory Wells Productive Natural Gas 0 0.0 0 0.0 0 0.0 Productive Oil 0 0.0 0 0.0 0 0.0 Dry 0 0.0 0 0.0 0 0.0 --- --- --- ---- --- ---- Total 2 1.2 19 11.7 32 22.3 === === === ==== === ==== Wells in progress at end of period 1 0.5 1 0.7 6 3.8
The information contained in the foregoing table should not be considered indicative of future performance, nor should it be assumed that there is any correlation between the number of productive wells drilled and the oil and natural gas reserves generated therefrom. PRESENT ACTIVITIES From January 1, 1999 to March 15, 1999, the Company participated in drilling activities on a total of 7 gross (6 net) wells, 2 of which have been completed as productive wells, 3 of which were not completed and 2 of which were dry holes. A dry well (hole) is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well. A productive well is an exploratory or development well that is not a dry hole. TITLE TO PROPERTIES The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally accepted in the oil and natural gas industry. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens that the Company believes 12 do not materially interfere with the use of or affect the value of such properties. Many of the Company's oil and natural gas properties are held in the form of mineral leases. The indebtedness under the Credit Facility is secured by substantially all of the Company's oil and natural gas properties. See Item 7 - "Management's Discussion and Analysis of Results of Operation and Financial Condition - Liquidity and Capital Resources" and "Financing Arrangements." As is customary in the oil and natural gas industry, a preliminary investigation of title is made at the time of acquisition of undeveloped properties. Title investigations, including a title opinion of local counsel, are generally completed, however, before commencement of drilling operations or the acquisition of producing properties. The Company believes that its methods of investigating title to, and acquiring, its oil and natural gas properties are consistent with practices customary in the industry and that it has generally satisfactory title to the leases covering its proved reserves. GLOSSARY OF CERTAIN INDUSTRY TERMS The definitions set forth below shall apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple. BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. BBLS/D. Stock tank barrels per day. BCF. Billion cubic feet. BCFE. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. BTU. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. CAPITAL ASSET. Under Section 1221 of the Internal Revenue Code of 1986, as amended, a capital asset is defined as any type of property held by a taxpayer, but does not include, among other things; (1) stock in trade, property includible in inventory or property held primarily for sale to customers in the ordinary course of business; or (2) depreciable property used in a trade or business. DEVELOPED ACREAGE. The number of acres which are allocated or assignable to producing wells or wells capable of production. DEVELOPMENT WELL. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. EXPLORATORY WELL. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be, in which a working interest is owned. MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons. MBBLS/D. One thousand barrels of crude oil or other liquid hydrocarbons per day. MCF. One thousand cubic feet. MCFE. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. MMBTU. One million Btus. 13 MMCF. One million cubic feet. MMCF/D. One million cubic feet per day. MMCFE. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, which approximates the relative energy content of crude oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher for crude oil than natural gas on an energy equivalent basis. NET ACRES OR NET WELLS. The sum of the fractional working interests owned in gross acres or gross wells. PRESENT VALUE. When used with respect to oil and natural gas reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to nonproperty-related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. PROVED RESERVES. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. PROVED UNDEVELOPED LOCATION. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves. PROVED UNDEVELOPED RESERVES. 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; proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. PV-10 VALUE. When used with respect to oil and natural gas reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to nonproperty-related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. RECOMPLETION. The completion for production of an existing well bore in another formation from that in which the well has been previously completed. RESERVOIR. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. ROYALTY INTEREST. An interest in an oil and natural gas property entitling the owner to a share of oil or natural gas production free of costs of production. 3-D SEISMIC. Advanced technology method of detecting geological structures susceptible to accumulations of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface. 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 natural gas regardless of whether such acreage contains proved reserves. WORKING INTEREST. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. 14 WORKOVER. Operations on a producing well to restore or increase production. ITEM 3. LEGAL PROCEEDINGS. From time to time the Company is a party to various legal proceedings arising in the ordinary course of business, but is not currently a party to litigation that it believes would have a material adverse effect on the consolidated financial condition, results of operations or cash flows of the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. There were no matters submitted to a vote of security holders during the fourth quarter of 1998. ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Michael Petroleum Corporation is a wholly owned subsidiary of Michael Holdings, Inc. ("MHI"). As of March 15, 1999, substantially all of common stock of MHI is owned by management, directors and employees of Michael Petroleum Corporation and thus no organized trading market exists for either the Company's or MHI's common stock. No dividends have been declared by the Company in the years ended December 31, 1997 and 1998. It is not anticipated by management of the Company that dividends will be declared in subsequent years. See "Item 12. Security Ownership of Certain Beneficial Owners and Management." The terms of the Indenture governing the Series B Notes and the Credit Facility restrict the Company's ability to declare and pay cash dividends. ITEM 6. SELECTED FINANCIAL DATA The following tables set forth selected consolidated financial data as of the end of each of the years in the five-year period ended December 31, 1998. The financial data for each of the years ended, and as of, December 31, 1994, 1995, 1996, 1997 and 1998 have been derived from the audited consolidated financial statements of the Company. This information should be read in conjunction with the Company's consolidated financial statements and Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." The Company's results of operations and financial condition have been affected by acquisitions of oil and natural gas properties during certain of the periods presented below. See Note 2 of Notes to Consolidated Financial Statements.
YEAR ENDED DECEMBER 31, ------------------------------------------------------- 1994 1995 1996 1997 1998 ------- ------- ------- ------- ------- (IN THOUSANDS) Income Statement Data: Operating revenues $ 3,592 $ 2,937 $ 3,776 $ 9,139 $22,718 Operating expenses 4,275 4,113 3,581 7,072 24,049 ------- ------- ------- ------- ------- Operating income (loss) (683) (1,176) 195 2,067 (1,331) Loss from continuing operations (853) (2,114) (2,479) (7) (8,710) Discontinued operations (719) 2,087 - - - Extraordinary item - - - - (531) Net loss $(1,572) $ (27) $(2,479) $ (7) $(9,241)
15
AS OF DECEMBER 31, ------------------------------------------------------- 1994 1995 1996 1997 1998 ------- ------- ------- ------- ------- (DOLLARS IN THOUSANDS) Balance Sheet Data: Current assets $ 1,611 $1,241 $ 4,375 $ 5,255 $ 8,951 Oil and gas properties, net 9,176 7,890 16,208 28,011 130,878 Total assets 11,461 9,145 21,001 33,617 147,282 Long-term debt 6,694 6,372 11,784 19,885 144,842 Shareholder's equity (deficit) 1,111 423 (1,908) (1,915) (11,156)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION The following discussion is intended to assist in an understanding of the Company's consolidated financial position and results of operations for each year during the three-year period ended December 31, 1998. The Company's consolidated financial statements and the notes thereto that follow contain detailed information that should be referred to in conjunction with the following discussion. GENERAL The Company is an independent energy company engaged in the acquisition, exploitation and development of oil and natural gas properties, principally in the Lobo Trend of South Texas. The Company began operations in 1983. In August 1996, the Company acquired interests in approximately 21,000 developed and undeveloped gross acres in the Lobo Trend for approximately $15.3 million. In 1998, the Company acquired interests in approximately 46,900 developed and undeveloped gross acres in the Lobo Trend for approximately $78.3 million. In 1998, the Company participated in the drilling of 32 gross and 22.3 net natural gas wells, completing 26 gross and 17.6 net wells capable of commercial production, respectively. Through the periods presented, the Company's results of operations reflect two tax structures (S corporation and C corporation) which have influenced, among other things, the historical levels of its owners' compensation. Effective July 1, 1996, the Company changed its tax filing status from an S corporation to a C corporation. Due to this change, the Company recognized a one-time charge of approximately $2.0 million to reflect deferred income taxes payable as of June 30, 1996. The Company utilizes the "successful efforts" method of accounting for its oil and natural gas activities as described in Note 1 of Notes to Consolidated Financial Statements. From time to time, the Company has utilized hedging transactions with respect to a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce its exposure to price fluctuations. See "Liquidity and Capital Resources." RESULTS OF OPERATIONS The following table summarizes production volumes, average sales prices and operating revenues for the Company's oil and natural gas operations for the years ended December 31, 1996, 1997 and 1998:
YEAR ENDED DECEMBER 31 ----------------------------- 1996 1997 1998 ------ ------ ------- (DOLLARS IN THOUSANDS, EXCEPT PER UNIT DATA) Production volumes: Oil and condensate (MBbls) 37 21 79 Natural gas (Mmcf) 1,324 3,685 10,510 Average sales prices: Oil and condensate (per Bbl) $20.05 $18.95 $11.19 Natural gas (per Mcf) 2.15 2.33 2.07 Operating revenues: Oil and condensate $742 $565 $888 Natural gas(1) 2,852 8,574 21,780 ------ ------ ------- Total $3,594 $9,139 $22,668 ====== ====== =======
(1) Net of hedging gains or losses. COMPARISON OF YEARS ENDED DECEMBER 31, 1998 AND 1997 16 Oil and natural gas revenues for the year ended December 31, 1998 increased 149% to $22.7 million from $9.1 million for the year ended December 31, 1997. Production volumes for natural gas for the year ended December 31, 1998 increased 185% to 10,510 Mmcf from 3,685 Mmcf for the year ended 1997. Average natural gas prices (including the effect of hedging transactions) decreased 12% to $2.07 per Mcf for 1998 from $2.33 per Mcf for 1997. The increase in natural gas production in 1998 was due to the Company's 1998 acquisitions and the new wells placed on line resulting from the Company's drilling activities. Oil and natural gas production costs for the year ended December 31, 1998 increased 116% to $4.1 million from $1.9 million for the year ended December 31, 1997, primarily due to the increase in production. However, actual production costs per equivalent unit decreased to $.37 per Mcfe for the year ended December 31, 1998 from $.57 per Mcfe for the year ended December 31, 1997. The decrease on an equivalent basis was due primarily to increased production volumes during 1998. Depletion, depreciation, and amortization ("DD&A") expense for the year ended December 31, 1998 increased 240% to $12.6 million from $3.7 million for the same period in 1997. The increase in DD&A expense was due to higher production volumes and an increase in the depletion rate per Mcfe from $.96 for 1997 to $1.14 for 1998. The increase in rate was primarily due to acquisitions completed in 1998 and a reduction in estimated proved reserves. In addition, total impairment charges increased to $5.4 million for the year ended December 31, 1998 compared to $238,000 for the year ended December 31, 1997. The impairment charges in 1998 were primarily due to lower oil and natural gas prices and development dry holes drilled on certain oil and gas leases that resulted in a reduction in the estimated proved reserves. General and administrative expense increased 83% to $1.80 million in 1998 from $980,000 for the same period in 1997 due to the addition of several new employees and their related benefits, plus increases in office expenses and legal and professional fees in connection with the Series A and Series B Notes offerings. Interest expense and loan amortization costs, net of capitalized interest, for the year ended December 31, 1998 increased 486% to $12.3 million compared to $2.1 million for 1997. The increase was due to the higher levels of outstanding debt during 1998, primarily as a result of the Series A and Series B Notes offerings, as compared to 1997. The income tax benefit was $4.95 million for the year ended December 31, 1998 compared to an income tax expense of $11,000 for the same period in 1997. The Company has a net operating loss carryforward of $19.5 million at December 31, 1998 which was generated beginning in fiscal year 1997. The net operating loss will begin to expire in 2017. Thus, future taxable income of at least $19.5 million will need to be generated by 2017 in order for the Company to realize the net operating loss at December 31, 1998. Based on estimates of future taxable income, management believes it is more likely than not that the net operating loss will be fully utilized prior to expiration. In order to achieve sufficient taxable income, certain tax planning strategies (primarily the capitalization of intangible drilling costs for tax purposes) were implemented in fiscal year 1998. Specific differences between pre-tax loss and taxable income pertain to developmental dry holes, intangible drilling costs, capitalized interest and depletion and depreciation of oil and gas and other properties. Differences in these items begin reversing in fiscal year 1999 and thereafter. Estimates of future taxable income are significantly affected by changes in oil and natural gas prices, estimates of future production, and estimated operating and capital costs. The deferred tax asset could be reduced in the near term if management's estimates of taxable income during the carryforward period are significantly reduced or if alternative tax strategies are no longer viable. If the Company is not able to generate sufficient taxable income in the future through operating results, a valuation allowance will be recorded through a charge to expense. The extraordinary loss of $531,000 (net of income tax benefit of $285,000) for the year ended December 31, 1998 was due to the writeoff of the remaining loan costs relating to the Company's credit agreement under the T.E.P. Financing, which terminated on April 2, 1998. No extraordinary charges or similar items occurred in 1997. The net loss for the year ended December 31, 1998 was $9.2 million compared to a loss of $7,000 for the year ended December 31, 1997, primarily as a result of the factors discussed above. COMPARISON OF YEARS ENDED DECEMBER 31, 1997 AND 1996 Oil and natural gas revenues for the year ended December 31, 1997 increased 153% to $9.1 million compared to $3.6 million for 1996. Production volumes for natural gas during the year ended December 31, 1997 increased 178% to 3,685 Mmcf from 1,324 Mmcf for 1996. Average gas prices increased 8.3% to $2.33 per Mcf for 1997 from $2.15 per Mcf for 1996. The increase in natural gas production was due to the 1996 acquisitions and the Company's workover and drilling program with respect to the properties acquired and existing properties. Oil and natural gas production costs for the year ended December 31, 1997 decreased 3% to $1.87 million from $1.93 million for 1996 primarily due to the sale of the Company's Hull Field oil properties in August 1996 that historically had incurred much higher lease operating costs than the Company's average Lobo Trend natural gas wells. Accordingly, production costs per equivalent unit decreased to $0.49 per Mcfe for 1997 from $1.25 per Mcfe for 1996. The per unit cost decreased as a result of increased production of natural gas, which has lower per unit operating costs, and the Company's disposition in August 1996 of oil producing properties having higher operating costs. 17 DD&A expense for the year ended December 31, 1997 increased 208% to $3.7 million from $1.2 million for the same period in 1996. This increase was due to the increased production during 1997. Exploration expense increased from $46,000 in 1996 to $333,000 in 1997, due primarily to the expiration of the terms of certain leases that had not been developed. General and administrative expense for the year ended December 31, 1997 increased 131% to $980,000 from $424,000 for 1996, primarily as a result of increases in the number of employees and related benefits, plus increased legal and professional fees. Interest expense, net of capitalized interest, for the year ended December 31, 1997 increased 127% to $2.1 million, compared to $924,000 for 1996. This increase in interest expense was due to increased debt levels in the second half of 1996 and in 1997 resulting from funds borrowed to acquire and develop the Lobo Trend properties. The net loss for the year ended December 31, 1997 decreased to $7,000, compared to a net loss of $2.5 million for 1996, as a result of the factors described above and the $2.0 million income tax charge related to the Company's conversion from an S corporation to a C corporation in 1996. LIQUIDITY AND CAPITAL RESOURCES Cash flows provided by operating activities from the Company's operations were $848,000, $3.5 million and $5.3 million for the years ended December 31, 1996, 1997 and 1998, respectively. The increases in 1997 and 1998 were primarily attributable to increased production resulting from the acquisitions and the new wells placed on line as a result of the Company's drilling activities. Cash and working capital in 1999 is expected to be provided through internally generated cash flows and borrowings. See "--Financing Arrangements" below. Cash flows used in investing activities by the Company were $14.8 million, $15.0 million and $116.3 million in 1996, 1997 and 1998, respectively. Property additions through acquisition, exploration and development activities were the primary reasons for the use of funds in investing activities. Cash flows used in investing activities by the Company for 1996, 1997 and 1998 resulted primarily from the acquisition and development of the Lobo Trend properties. Cash flows provided by the Company's financing activities were $14.8 million, $11.1 million and $110.7 in 1996, 1997 and 1998, respectively. In 1996 and 1997, the cash flows from financing activities resulted from borrowings under the T.E.P. Financing. In 1998, the financing cash flows were primarily from proceeds from the Series A Notes and borrowings from the Credit Facility. The Company's primary sources of liquidity have historically been provided from funds generated by operations and from borrowings. The Company completed the sale of its $135.0 million Series A Notes in April 1998. Approximately $28.0 million of the net proceeds from the sale of the Series A Notes was used to repay the indebtedness outstanding under the T.E.P. Financing. Approximately $89.3 million of the net proceeds were used to fund acquisitions and the remaining balance for working capital and general corporate purposes. During May 1998, the Company entered into the Credit Facility, as described below under "--Financing Arrangements." The Company's revenues, profitability, future growth and ability to borrow funds and obtain additional capital, and the carrying value of its properties, are substantially dependent on prevailing prices of oil and natural gas. It is impossible to predict future oil and natural gas price movements with certainty. Declines in prices received for oil and natural gas would have an adverse effect on the Company's financial condition, liquidity, ability to finance capital expenditures and results of operations. Lower prices would also impact the amount of reserves that can be produced economically by the Company. During 1998, the Company recorded an impairment provision on producing properties of $5.4 million before income tax. This impairment provision was determined based on an assessment of recoverability of net property costs from estimated future net cash flows from those properties. Estimated future net cash flows are based on management's best estimate of projected oil and gas reserves and prices. If oil and gas prices remain at lower levels or decline further, the Company may be required to record further impairment provisions in the future, which may be material. The Company has experienced and expects to continue to experience substantial working capital requirements primarily due to the Company's development program. Capital expenditures for 1999 are currently estimated to be approximately $27.0 million. Substantially all of the capital expenditures will be used to fund drilling activities, property acquisitions and 3-D seismic surveys in the Company's project areas. The Company's plan anticipates drilling 32 gross (28 net) wells in 1999. However, the Company's borrowing base under its Credit Facility was reduced, effective April 1, 1999, from $35 million to $23 million. The remaining amount of borrowing capacity under the Credit Facility was drawn as of April 1, 1999 to make the required interest payments on the Series B Notes. See "--Financing Arrangements" below. While the current estimates of capital expenditures for fiscal 1999 set forth above do not take into account this lower borrowing base, the Company believes that alternate sources of funding to finance the incremental capital expenditures that would otherwise be funded by the Credit Facility should be available to the Company. However, no assurances can be given that any such financing alternatives will be available, and if so, on terms considered advantageous to the Company. If suitable alternative financing or other alternative capital resources are not available to the Company, its currently planned capital expenditures would be reduced and could be significantly reduced. See "--Cautionary Statements Regarding Forward-Looking Information-Future Need For and Availability of Capital," "--Restrictions Imposed by Lenders" and "--Incurrence of Substantial Indebtedness." Assuming additional debt financing was available to fund the Company's 1999 estimated capital expenditures level, the Company believes that additional financing, preferably public or private equity financing, will be necessary in the future in order for the Company to continue to increase its reserve base and make additional acquisitions in accordance with its long-range development plan. Should recent prevailing equity market conditions for oil and natural gas independent exploration and development companies continue, the Company does not foresee an infusion of funds from public sales of its equity for the foreseeable future. An inability to obtain sufficient capital to achieve these purposes could cause the Company to curtail its planned property acquisition and development activities, which could adversely affect its future financial condition, cash flows and results of operations. 18 FINANCING ARRANGEMENTS In August 1996, the Company entered into the T.E.P. Financing, which provided for an aggregate term loan amount of $42.2 million, available for oil and natural gas property acquisitions and development drilling, subject in each case to borrowing base limitations. The Company used approximately $28.0 million of the net proceeds from the sale of the Series A Notes to repay all of the outstanding indebtedness under the T.E.P. Financing in April 1998. In August 1996, the Company also granted Cambrian Capital Partners, L.P., an affiliate of the T.E.P. Financing lender ("Cambrian"), a 30% Net Profits Interest (as defined in the Net Profits Interest Conveyance dated August 12, 1996), net to the Company's interest, in all of the Company's properties, including those acquired in the 1996 Acquisition. As part of the T.E.P. Financing, the Company also granted to Cambrian a warrant to purchase up to 5% of the Company's common stock until August 12, 2001. The value assigned to the Net Profits Interest and warrant was recorded as a discount to the loan proceeds. The Company used approximately $11.0 million of the net proceeds from the sale of the Series A Notes to acquire the Net Profits Interest. In addition, the warrant to purchase the Company's common stock was cancelled, and MHI issued to Cambrian a warrant to acquire 38,671 shares of its Common Stock at an exercise price of $8.00 per share. In May 1998, the Company entered into its Credit Facility with Christiania as lender and administrative agent, pursuant to the terms of the Credit Facility. The Credit Facility provided for loans in an outstanding principal amount not to exceed $50.0 million at any one time, subject to a borrowing base to be determined semi-annually (each April and October) by the administrative agent (the initial borrowing base was $30.0 million), and the issuance of letters of credit in an outstanding face amount not to exceed $6.0 million at any one time with the face amount of all outstanding letters of credit reducing, dollar-for-dollar, the availability of loans under the Credit Facility. Although the initial borrowing base was $30 million, and effective November 9, 1998, the borrowing base was increased by $5 million to a total of $35 million, the new borrowing base effective April 1, 1999, was reduced to $23 million. See "--Liquidity and Capital Resources" above. Under the Credit Facility, the principal balance outstanding is due and payable on May 28, 2002, and each letter of credit shall be reimbursable by the Company when drawn, or if not then otherwise reimbursed, paid pursuant to a loan under the Credit Facility. Commencing on October 31, 1999, and continuing until its stated maturity, the maximum amount available for borrowings and letters of credit under the Credit Facility will not only be adjusted (increased or decreased, as applicable) by the semi-annual borrowing base determination, but also (i) decreased by monthly mandatory reductions in the borrowing base of $1.5 million per month and (ii) adjusted for sales of collateral having an aggregate value exceeding the lesser of $4.0 million per year or 5% of the Company's total proved reserve values. At March 31, 1999, the Company had drawn all of the $23 million then available under Credit Facility. Both the Company and Christiania may also initiate two unscheduled redeterminations of the borrowing base during any consecutive twelve-month period. If the sum of the outstanding principal balance and amount of outstanding letters of credit (both drawn and undrawn) exceeds the borrowing base, the Company shall, within 30 days, either repay such excess in full or provide additional collateral acceptable to Christiania. The Credit Agreement contains certain covenants by the Company, including (i) limitations on additional indebtedness and on guaranties by the Company except as permitted under the Credit Agreement, (ii) limitations on additional investments except those permitted under the Credit Agreement and (iii) restrictions on dividends or distributions or on repurchases or redemptions of capital stock by the Company except for those involving repurchases of MHI capital stock which may not exceed $500,000 in any fiscal year. In addition, the Credit Agreement requires the Company to maintain and comply with certain financial covenants and ratios, including a minimum interest coverage ratio, a minimum current ratio and a covenant requiring that the Company's general and administrative expenses may not exceed 12.5% of the Company's gross revenues in any calendar year. As of December 31, 1998, the Company was in violation of certain administrative covenants and a financial covenant under the Credit Facility. The Company has obtained a waiver with respect to these violations from Christiania, which agreed not to assert any default based upon such violations. The Company and the lender have entered into a First Amendment to the Credit Facility to amend those covenants and the interest rate under the Credit Facility. As amended, the interest rate for each borrowing under the Credit Facility will be calculated at either (i) the ABR rate (as described below), or (ii) the Eurodollar Rate (as described below) plus 2.25%, at the election of the Company. Interest on the borrowings under the Credit Facility will be due (i) with respect to loans bearing interest at the ABR rate, quarterly in arrears and at maturity, and (ii) with respect to loans bearing interest at the Eurodollar Rate, on the last day of each relevant interest period and, in the case of any interest period longer than three months, on a quarterly basis. The Company's obligations under the Credit Facility are secured by substantially all of the oil and natural gas assets of the Company, including accounts receivable and material contracts, equipment and gathering systems. The proceeds of the Credit Facility may be used to finance working capital needs and for general corporate purposes of the Company in the ordinary course of its business. Under the Credit Facility, "ABR" means the highest of (i) the interest rate announced publicly by Christiania as its prime rate plus 0.5% in effect in its principal office in New York, (ii) the secondary market rate for three-month certificates of deposit (adjusted for statutory reserve requirements) plus 1.5% and (iii) the federal funds effective rate from time to time plus 1.0%. "Eurodollar Rate" means the rate (adjusted for statutory reserve requirements of eurocurrency 19 liabilities) at which eurodollar deposits for one, two, three or six (or, if available and acceptable to the Credit Facility lenders, nine or twelve) months (as selected by the Company) are offered to Christiania in the Interbank eurodollar market. See "--Cautionary Statements Regarding Forward-Looking Information- Future Need For and Availability of Capital," "--Restrictions Imposed by Lenders" and "--Incurrence of Substantial Indebtedness." TERMS AND FINANCIAL COVENANTS OF 11 1/2% SENIOR NOTES DUE 2005 The indenture governing the Series B Notes (the "Indenture") contains certain covenants that, among other things, limit the ability of the Company to incur additional indebtedness, pay dividends, repurchase equity interests or make other Restricted Payments (as defined in the Indenture), create liens, enter into transactions with affiliates, sell assets or enter into certain mergers and consolidations. The Company is allowed to incur additional indebtedness if it meets an EBITDA/Interest ratio and an ACNTA/Debt ratio computed based on the last four quarters immediately proceeding the incurrence of the indebtedness on a pro forma basis. In the event of certain asset dispositions, the Company is required under certain circumstances to use the excess proceeds from such a disposition to offer to repurchase the Series B Notes (and other Senior Indebtedness for which an offer to repurchase is required to be concurrently made) having an aggregate principal amount equal to the excess proceeds at a purchase price equal to 100% of the principal amount of the Series B Notes, together with accrued and unpaid interest and Liquidated Damages (as defined in the Indenture), if any, to the date of repurchase (a "Net Proceeds Offer"). CAPITAL EXPENDITURES AND OUTLOOK The following table sets forth the Company's capital expenditures for the three years ended December 31, 1998 (in thousands):
YEAR ENDED DECEMBER 31 ----------------------------------- 1996 1997 1998 -------- -------- -------- Property acquisition: Unproved $ 2,929 $ 355 $ 15,183 Proved 9,554 2,425 78,458 Development 2,757 12,074 25,295 Interest capitalized 217 574 1,440 -------- -------- -------- Total costs incurred $ 15,457 $ 15,428 $120,376 ======== ======== ========
The Company currently has budgeted capital expenditures of approximately $27.0 million for 1999. See "--Liquidity and Capital Resources" above. Substantially all of the capital expenditures will be used to fund drilling activities, property acquisitions and 3-D seismic surveys in the Company's project areas. The Company intends to drill approximately 32 gross (28 net) wells in 1999. The Company will require capital from sources in addition to that funded under the Credit Facility in order for the Company to fully implement its development drilling strategy in 1999 and for the foreseeable future. In the event that additional capital is not available to the Company, capital expenditures are expected to be reduced and could be significantly reduced. NATURAL GAS BALANCING The Company incurs certain natural gas production volume imbalances in the ordinary course of business and utilizes the sales method to account for such imbalances. Under this method, income is recorded based on the Company's net revenue interest in production taken for delivery. Management does not believe that the Company had any material imbalances as of December 31, 1996, 1997, or 1998. EFFECTS OF INFLATION AND CHANGES IN PRICE 20 The Company's results of operations and cash flows are affected by changes in oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that the Company is required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had only a minimal effect on the Company. YEAR 2000 Many computer systems have been designed using software that processes transactions using two digits to represent the year. This type of software will generally require modifications to function properly with dates after December 31, 1999. The same issue applies to microprocessors embedded in machinery and equipment, such as gas compressors and pipeline meters. The impact of failing to identify and correct this problem could be significant to the Company's ability to operate and report results, as well as potentially exposing the Company to third party liability. The Company has begun making necessary modifications to its internal information computer systems in preparation for the Year 2000. The Company currently estimates that its Year 2000 project will be completed by June 1999, and believes that the total related costs will be approximately $30,000, funded by cash from operations or short term borrowings. Actual costs to date have been less than $10,000. The Company began reviewing the Year 2000 compliance status of field equipment, including compressor stations, gas control systems and data logging equipment, during the fourth quarter of 1998 and expects to complete this review by June 1999. The Company has identified significant third parties whose Year 2000 compliance could affect the Company and is in the process of formally inquiring about their Year 2000 status. The Company has received responses to less than 10% of its inquiries. Despite its efforts to assure that such third parties are Year 2000 compliant, the Company cannot provide assurance that all significant third parties will achieve compliance in a timely manner. A third party's failure to achieve Year 2000 compliance could have a material adverse effect on the Company's operations and cash flow. The potential effect of Year 2000 non-compliance by third parties is currently unknown. Project costs and the timetable for Year 2000 compliance are based on management's best estimates. In developing these estimates, assumptions were made regarding future events including, among other things, the availability of certain resources and the continued cooperation of the Company's customers and suppliers. Actual costs and timing may differ from management's estimates due to unexpected difficulties in obtaining trained personnel, locating and correcting relevant computer code and other factors. Management does not expect the costs of the Company's Year 2000 project to have a material adverse effect on the Company's financial position, results of operations or cash flows. Presently, based on information available, the Company cannot conclude that any failure of the Company or third parties to achieve Year 2000 compliance will not adversely effect the Company. The Company has designated personnel responsible to not only identify and respond to these issues, but also to develop a contingency plan in the event that a problem arises after the turn of the century.The Company is currently identifying appropriate contingency plans in the event of potential problems resulting from failure of the Company's or significant third party computer systems on January 1, 2000. The Company has not completed any contingency plans to date. Specific contingency plans will be developed in response to the results of testing scheduled to be complete by October 1999, as well as the assessed probability and risk of system or equipment failure. These contingency plans may include installing backup computer systems or equipment, temporarily replacing systems or equipment with manual processes, and identifying alternative suppliers, service companies and purchasers. The Company expects these plans to be complete by December 1999. CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION Certain information contained in this Annual Report on Form 10-K (as well as certain other written or oral statements made by or on behalf of the Company) may be deemed to be forward-looking statements which can be identified by the use of forward-looking terminology such as "believes," "expects," "may," "will," "should" or "anticipates" or the negative thereof or comparable terminology, or by discussions of strategy that involve risks and uncertainties. In addition, all statements other than statements of historical facts included in this Annual Report on Form 10-K, including, without limitation, statements regarding the the levels of capital expenditures for 1999 and succeeding periods, the availability of sources of capital to fund these capital expenditures and the Company's other working capital and operational requirements, the Company's business strategy, worldwide prices for crude oil and natural gas, the Company's ability to raise additional long-term capital, the Company's success in dealing with its lenders, future governmental regulation, future oil and natural gas reserves, future drilling and development opportunities and operations, future acquisitions, future production of oil and natural gas (and the prices thereof and costs therefor), anticipated results of hedging activities, future capital expenditures and future net cash flows, are forward-looking statements and may contain information concerning financial results, economic conditions, trends and known uncertainties. Such statements reflect the Company's current views with respect to future events and financial performance, and involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements as a result of these various risks and uncertainties, including, without limitation, (i) factors discussed below such as natural gas price fluctuations and markets, uncertainties of estimates of reserves and future net revenues, the success of the Company's drilling programs, competition in the oil and natural gas industry, operating risks, risks associated with acquisitions, future need for and availability of capital, and regulatory and environmental risks, (ii) adverse changes to the properties acquired in the Transactions and the interests subject to the Lobo Lease or the failure of the Company to achieve the anticipated benefits of the Transactions and the interests subject to the Lobo Lease, (iii) adverse changes in the market for the Company's oil and natural gas production and (iv) those additional factors discussed immediately below and under Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations," Item 1. "Business" and Item 2. "Properties" and elsewhere in this Annual Report on Form 10-K. INCURRENCE OF SUBSTANTIAL INDEBTEDNESS As of December 31, 1998, the Company had $147.1 million ($144.8 million, net of unamortized discount) of indebtedness outstanding (including current maturities of long-term indebtedness) as compared to a shareholder's deficit of $11.2 million. The indenture limits the amounts of borrowings under bank facilities, including borrowings under the Credit Facility. In addition, as of March 31, 1999, due to borrowing base reductions, the Company has no borrowing capacity remaining under the Credit Facility. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources" and "--Financing Arrangements". This level of indebtedness may pose substantial risks to the Company, including, but not limited to, the following: (i) the Company's ability to obtain additional financing in the future, whether for working capital, capital expenditures, acquisitions or other purposes, may be impaired; (ii) a portion of the Company's cash flow from operations is required to be dedicated to the payment of interest on its debt, thereby reducing funds available to the Company for other purposes; (iii) the Company may not generate sufficient cash flow to pay the principal of and interest on the Series B Notes; (iv) the Company's flexibility in planning for or reacting to changes in market conditions may be limited; and (v) the Company may be more vulnerable given current prevailing industry conditions. In addition, the Company's earnings have been insufficient to meet its fixed charges. The ability of the Company to meet its debt service obligations, including with respect to the Series B Notes, will depend on the future operating performance and financial results of the Company, which will be subject in part to factors beyond the control of the Company. Further, if the Company is unsuccessful in increasing its proved reserves, the future net revenues from existing proved reserves may not be sufficient to pay the principal of and interest on the 21 Series B Notes in accordance with their terms. There can be no assurance that the Company will continue to generate earnings in the future sufficient to cover its fixed charges. If the Company is unable to generate earnings in the future sufficient to cover its fixed charges and is unable to borrow sufficient funds to cover such charges, it may be required to refinance all or a portion of its debt or to sell all or a portion of its assets. There can be no assurance that a refinancing would be possible, nor can there be any assurance as to the timing of any asset sales or the proceeds that the Company could realize therefrom. In addition, the Credit Agreement contains certain covenants by the Company, including (i) limitations on additional indebtedness and on guaranties by the Company except as permitted under the Credit Agreement, (ii) limitations on additional investments except those permitted under the Credit Agreement and (iii) restrictions on dividends or distributions on or repurchases or redemptions of capital stock by the Company, except for those involving repurchases of MHI capital stock which may not exceed $500,000 in any fiscal year. Also, the Credit Agreement requires the Company to maintain and comply with certain financial covenants and ratios, including a minimum interest coverage ratio, a minimum current ratio and a covenant requiring that the Company's general and administrative expenses may not exceed 12.5% of the Company's gross revenues in any calendar year. See "--Restrictions Imposed by Lenders," "--Future Need for and Availability of Capital" and Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations--Financing Arrangements." EFFECTIVE SUBORDINATION OF THE SERIES B NOTES The Series B Notes are senior unsecured obligations of the Company and rank in parity with all existing and future Senior Indebtedness of the Company, including any indebtedness incurred under the Credit Facility, and senior in right of payment to all future Subordinated Indebtedness of the Company. Holders of secured Indebtedness of the Company, including under the Credit Facility, will have claims with respect to assets constituting collateral for such Indebtedness that are prior to the claims of the Holders of the Series B Notes. In the event of a default on the Series B Notes, or a bankruptcy, liquidation or reorganization of the Company, such assets will be available to satisfy obligations with respect to the indebtedness secured thereby before any payment therefrom could be made on the Series B Notes. Accordingly, the Series B Notes will be effectively subordinated to claims of secured creditors of the Company to the extent of such pledged collateral. As of March 31, 1999, the Company had $23.0 million of secured indebtedness. RESTRICTIONS IMPOSED BY LENDERS The Indenture and the Credit Agreement governing the terms of the Credit Facility impose significant operating and financial restrictions on the Company. Such restrictions will affect, and in many respects significantly limit or prohibit, among other things, the ability of the Company to incur additional indebtedness, make certain capital expenditures, pay dividends, repay or repurchase indebtedness prior to its stated maturity or engage in mergers or acquisitions. These restrictions could also limit the ability of the Company to effect future financings, make needed capital expenditures, withstand a future downturn in the Company's business or the economy in general, or otherwise conduct necessary corporate activities. Any failure by the Company to comply with these restrictions could lead to a default under the terms of such indebtedness and the Series B Notes. In the event of default, the holders of such indebtedness could elect to declare all of the funds borrowed pursuant thereto to be due and payable together with accrued and unpaid interest. In such event, there can be no assurance that the Company would be able to make such payments or borrow sufficient funds from alternative sources to make any such payment. Even if additional financing could be obtained, there can be no assurance that it would be on terms that are favorable or acceptable to the Company. In addition, the Company's indebtedness under the Credit Facility is secured by a substantial oprtion of the assets and properties of the Company. The pledge of such collateral to the Company's secured lenders could impair the Company's ability to obtain additional financing on favorable terms. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources" and "--Financing Arrangements." FUTURE NEED FOR AND AVAILABILITY OF CAPITAL The Company anticipates that it will require additional financing to effect both future property acquisitions and continue its development programs. The Company or MHI may seek funds through the sale of debt or equity securities, which could significantly dilute the ownership of the Company's or MHI's existing shareholders. In addition, if necessary (and permitted under the terms of the indenture), the Company or MHI may seek funds from project financing, strategic alliances or other sources, all of which may dilute the interest of the Company in the specific project financed. The Company's ability to access additional capital is dependent upon the Company's outstanding commitments and financial condition, and the financial strength of the capital markets at such time. There can be no assurance that such additional financing can be obtained 22 or, if so, obtained on terms acceptable to the Company. Future cash flows and the availability of credit are subject to a number of variables, such as the level of production from existing wells, prices of oil and natural gas and the Company's success in locating and producing new reserves. If revenues were to decrease as a result of lower oil and natural gas prices, decreased production or otherwise, the Company could have limited ability to replace its reserves or to maintain production at current levels, resulting in a decrease in production and revenues over time. The Company has budgeted approximately $27.0 million for capital expenditures in 1999, exclusive of acquisitions. The Company expects to use cash flow from operations and from borrowings or other capital sources to fund these expenditures. However, the Company's borrowing base under the Credit Facility has been reduced from $35 million to $23 million, substantially all of which is currently drawn. If the Company's cash flow from operations and availability of funds from other capital sources are not sufficient to satisfy its capital expenditure requirements capital expenditures may be reduced. There can be no assurance that additional debt or equity financing will be available. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." VOLATILITY OF NATURAL GAS AND OIL PRICES The revenues generated by the Company's operations are highly dependent upon the prices of, and demand for, natural gas and, to a lesser extent, the price of oil. Historically, the prices of oil and natural gas have been volatile and are likely to continue to be volatile in the future and are dependent upon numerous factors such as weather, domestic and foreign political and economic conditions, the overall level of international and domestic demand for oil and natural gas, domestic and international regulatory developments, domestic and international severance and excise taxes, competition from other sources of energy and the availability of pipeline capacity. The Company is affected more by fluctuations in natural gas prices than oil prices, because the majority of its production is natural gas. The volatile nature of the energy markets and the unpredictability of actions of OPEC members make it impossible to predict future prices of natural gas and oil with any certainty. Prices of natural gas and oil are subject to wide fluctuations in response to relatively minor changes in circumstances, and there can be no assurance that future prolonged decreases in such prices will not occur. All of these factors are beyond the control of the Company. Any significant decline in natural gas and oil prices would have a material adverse effect on the Company's results of operations and financial condition, its ability to fund operations and capital expenditures, the book value of its natural gas and oil properties and its ability to meet its debt service requirements. Although the Company may enter into hedging arrangements from time to time to reduce its exposure to price risks in the sale of its natural gas and oil, substantially all of the Company's production will remain subject to natural gas and oil price fluctuations. DEPENDENCE ON DISTRIBUTION AND PROCESSING SYSTEMS The marketability of the Company's natural gas and oil production depends upon the availability and capacity of natural gas gathering systems, pipelines and processing facilities which are not owned by the Company. The unavailability or lack of capacity thereof could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Moreover, substantially all of the Company's properties rely on the same gathering systems, transportation lines and processing plants. In addition, federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand could adversely affect the Company's ability to produce and market its natural gas and oil on a profitable basis. Any significant change in the Company's ability to market its production could have a material adverse effect on the Company's financial condition and results of operations. CONCENTRATION OF PRODUCING PROPERTIES The Company's production of natural gas and oil is concentrated within an approximate 120 square mile area in the Lobo Trend. Any impairment or material reduction in the expected size of the reserves attributable to the Company's wells, any material harm to the producing reservoirs from which these wells produce or any significant governmental regulation with respect to any of these wells, including curtailment of production or interruption of transportation of production, could have a material adverse effect on the Company's financial condition and results of operations. DRILLING RISKS The Company's revenues, operating results and future rate of growth will be dependent upon the success of its drilling program. Oil and natural gas drilling involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The timing and cost of drilling, completing and operating wells is often uncertain, and drilling 23 operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs and the delivery of equipment. Oil and natural gas drilling remains a speculative activity notwithstanding the Company's use of 3-D seismic data. Even when fully utilized and properly interpreted, 3-D seismic data and other advanced technologies only assist geoscientists in identifying subsurface structures and do not enable the interpreter to know whether hydrocarbons are in fact present in such structures. In addition, the use of 3-D seismic data and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies and the Company could incur losses as a result of such expenditures. Furthermore, completion of a well does not assure a profit on the investment or a recovery of any portion of drilling, completion or operating costs. Unsuccessful drilling activities could have a material adverse effect on the Company's results of operations and financial condition. There can be no assurance that the Company's overall drilling success rate or its drilling success rate within a particular project area will not decline. The Company may choose not to acquire option and lease rights prior to acquiring seismic data and, in many cases, the Company may identify a prospect or drilling location before seeking option or lease rights in the prospect or location. Although the Company has identified or budgeted for numerous drilling prospects, there can be no assurance that such prospects will ever be leased or drilled (or drilled within the scheduled or budgeted time frame) or that oil or natural gas will be produced from any such prospects or any other prospects. In addition, prospects may initially be identified through a number of methods, some of which do not include interpretation of 3-D or other seismic data. Actual drilling and results are likely to vary from such statistical results and such variance may be material. Similarly, the Company's drilling schedule may vary from its capital budget because of future uncertainties, including those described above. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations." ABILITY AND NEED TO REPLACE RESERVES The Company's future success depends upon its ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless the Company successfully replaces the reserves that it produces through successful development, exploration or acquisition, the Company's proved reserves will decline. Further, substantially all of the Company's estimated proved reserves at December 31, 1998 were located in the Lobo Trend, where wells are characterized by high initial production followed by rapid initial decline rates and a relative flattening of production thereafter. Additionally, approximately 61.3% of the PV-10 Value of the Company's total estimated proved undeveloped reserves as of December 31, 1998 was attributable to undeveloped reserves. Recovery of such reserves will require significant capital expenditures and successful drilling operations, and there can be no certainty regarding the results of developing these reserves. The Company's business strategy is to add reserves by pursuing an active development drilling program on its properties (including the properties acquired in the Transactions) and on additional properties that it may acquire in the future. There can be no assurance that the Company will drill the number of wells currently projected or that the production from these new wells will be sufficient to replace production from existing wells during such period. To the extent the Company is unsuccessful in replacing or expanding its estimated proved reserves, the Company may be unable to pay the principal of and interest on the Series B Notes in accordance with their terms, or otherwise to satisfy certain of its covenants contained in the Indenture. UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES The proved developed and undeveloped oil and natural gas reserve data presented in this Report are estimates based on reserve reports prepared by independent petroleum engineers, as well as internally generated reports by the Company. The estimation of reserves requires substantial judgment on the part of the petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Estimates of economically recoverable oil and natural gas reserves and of future net revenues necessarily depend upon a number of variable factors and assumptions, such as assumed production, which is based in part on an assessment of historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. Estimates of reserves and of future net revenues prepared by different petroleum engineers may vary substantially, depending, in part, on the assumptions made (including assumptions required by the SEC), as to oil and natural gas prices, drilling, workover, remedial and operating expenses, capital expenditures, severance and ad valorem taxes and availability of funds, and may be subject to material adjustment. Estimates of proved undeveloped reserve quantities, which comprise 73% of the Company's total proved reserves as of December 31, 1998, are, by their nature, 24 much less certain than proved developed reserves. The accuracy of any reserve estimate depends on the quality of available data as well as engineering and geological interpretation and judgment. Results of drilling, testing and production or price changes subsequent to the date of the estimate may result in changes to such estimates. Any significant variance in the assumptions could materially affect estimates of economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenues expected therefrom. The estimates of future net revenues contained herein reflect oil and natural gas prices and production costs as of the date of estimation, without escalation, except where changes in prices were fixed under existing contracts. There can be no assurance that such prices will be realized, estimated production volumes will be produced or proved undeveloped reserves will be developed during the period specified in such reports. Either inaccuracies in estimates of proved undeveloped reserves or the inability to fund development could result in substantially reduced reserves. In addition, the timing of receipt of estimated future net revenues from proved undeveloped reserves will be dependent upon the timing and implementation of drilling and development activities estimated by the Company for purposes of the reserve report. See "Item 2. Properties--Oil and Natural Gas Reserves." The estimated reserves and future net revenues may be subject to material downward or upward revision based upon production history, results of future development, prevailing oil and natural gas prices and other factors. A material decrease in estimated reserves or future net revenues could have a material adverse effect on the Company's financial condition and results of operations. In addition, the PV-10 Value of the Company's proved oil and natural gas reserves does not necessarily represent the current or fair market value of such proved reserves, and the 10% discount rate required by the SEC may not reflect current interest rates, the Company's cost of capital or any risks associated with the development and production of the Company's proved oil and natural gas reserves. In accordance with applicable SEC requirements, proved reserves and the future net revenues from which PV-10 Value is derived are estimated using prices and costs at the date of the estimate held constant throughout the life of the properties (except to the extent a contract specifically provides otherwise). The Company emphasizes with respect to such estimates that the discounted future net cash flows should not be construed as representative of the fair market value of the proved oil and natural gas properties belonging to the Company, because discounted future net cash flows are based upon projected cash flows that do not provide for changes in oil and natural gas prices or for escalation of expenses and capital costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results may differ materially from the results estimated. The estimated future net revenues attributable to the Company's proved oil and natural gas reserves are based on prices in effect at December 31, 1998 ($1.85 per Mcf of natural gas and $9.17 per Bbl of oil), which may be materially different than actual future prices. See "Item 2. Properties--Oil and Natural Gas Reserves." RISKS ASSOCIATED WITH ACQUISITIONS The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and natural gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact. In connection with its assessment of a potential acquisition, the Company performs a review of the subject properties that it believes to be generally consistent with industry practices, including examination of contingencies associated with the properties. Such a review, however, will not reveal all existing or potential problems nor will it permit a buyer to become sufficiently familiar with the properties to fully assess the deficiencies and capabilities of such properties. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. There can be no assurance that the Company will be able to identify attractive acquisition opportunities, obtain financing for acquisitions on satisfactory terms or successfully acquire identified targets. Furthermore, there can be no assurance that competition for acquisition opportunities in these industries will not escalate, thereby increasing the cost to the Company of making further acquisitions or causing the Company to refrain from making further acquisitions. In addition, there can be no assurance that any acquisition of property interests by the Company will be successful and, if unsuccessful, that such failure will not have a material adverse effect on the Company's future results of operations and financial condition. The Company's current inability to borrow to fund its capital expenditures will, for so long as it continues, adverse affect its ability to fund its acquisition strategy. 25 OPERATIONAL HAZARDS AND UNINSURED RISKS Oil and natural gas drilling activities are subject to numerous risks, many of which are beyond the Company's control, including the risk that no commercially productive oil or 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 drilling conditions, pressure irregularities information, equipment failures or accidents, adverse weather conditions, title problems and shortages or delays in the delivery of equipment. The Company's future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on future results of operations and financial condition. In addition, oil and natural gas operations involve hazards such as fire, explosion, blowout, pipe failure, casing collapse, unusual or unexpected formation pressures and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, the occurrence of any one 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, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. Although the Company maintains insurance against certain risks that it believes are customarily insured against by companies in the industry of comparable size and scope of operations, such insurance does not cover all of the risks and hazards involved in oil and natural gas exploration, drilling and production because insurance is unavailable at economic rates, there are limitations in the Company's insurance policies or for other reasons. Even if coverage does exist, it may not be sufficient to pay the full amount of liabilities incurred, and there can be no assurance that such insurance will continue to be available on terms acceptable to the Company. Any uninsured loss could have a material adverse effect on the Company's financial condition and results of operations. COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY The Company encounters competition from other oil and natural gas companies in all areas of its operations, including the acquisition of exploratory prospects and proven properties. Properties within the Lobo Trend are characterized by large tracts (typically 5,000 to 50,000 acres) that have been owned by the same families for generations. Securing leases or necessary permits and approvals for 3-D seismic shoots depends heavily on developing and maintaining favorable relationships with the surface owners. The Company's competitors, particularly in the Lobo Trend, include major integrated oil and natural gas companies and independent oil and natural gas companies, individuals and drilling and income programs. Most of its competitors are large, well-established companies with substantially larger operating staffs and significantly greater capital resources than those of the Company and which, in many instances, have been engaged in the oil and natural gas business for a much longer time than the Company. Such companies may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than could the Company, given its limited financial and human resources. There can be no assurance that the Company will be able to secure the necessary financing or industry partners or evaluate and select suitable properties and consummate transactions in this highly competitive environment. See "Item 1. Business-- Competition." PROPERTY IMPAIRMENT CHARGES Effective January 1, 1996, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which requires that long-lived assets held and used by an entity be reviewed for impairment whenever events or changes indicate that the net book value of an asset may not be recoverable. The net book value of an asset is reduced to fair value if the sum of expected undiscounted future net cash flows from the use of the asset is less than the net book value of the asset. Under SFAS No. 121 the Company evaluates impairment of oil and natural gas properties on a field basis. Applying SFAS No. 121, the Company recognized non-cash property impairment charges of $5.4 million, $238,000 and $156,000 as of December 31, 1998, 1997 and 1996, respectively. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Results of Operations." Significant declines in oil or natural gas prices or downward revisions of reserve estimates could adversely impact the Company's estimates of future net revenues from its proved reserves and consequently could result in future non-cash impairment charges against the Company's results of operations. DEPENDENCE OF KEY PERSONNEL The Company is dependent upon the efforts and skills of key executives of the Company, including Glenn D. Hart, Chairman of the Board and Chief Executive Officer, Michael G. Farmar, President and Chief Operating Officer, 26 and Jerry F. Holditch, Vice President-Exploration. The loss of any of these officers or other key personnel could have a material adverse effect on the Company. Further, as the Company grows its asset base and scope of operations as a result of the Transactions and other future acquisitions, its future profitability will depend upon the Company's ability to attract and retain additional qualified personnel. CONTROL BY CERTAIN SHAREHOLDERS The Company is a wholly-owned subsidiary of MHI, which in turn is principally owned by the management of the Company and MHI. Four of the Company's directors, three of whom are also executive officers of the Company, beneficially owned 701,550 shares of common stock of MHI (the "Common Stock") representing, in the aggregate, approximately 91% of the outstanding Common Stock. Such owners, should they act together, would have sufficient voting power to (i) elect the entire Boards of Directors of the Company and MHI, (ii) exercise control over the business, policies and affairs of the Company and MHI and (iii) in general, determine the outcome of any corporate transaction or other matters submitted to the stockholders for approval such as (a) any amendment to the Company's Articles of Incorporation, (b) the authorization of additional shares of capital stock and (c) any merger, consolidation or sale of all or substantially all of the assets of the Company which could prevent or cause a change of control of the Company. REGULATORY AND ENVIRONMENTAL RISKS Oil and natural gas operations are subject to various federal, state and local governmental regulations which may be changed from time to time in response to economic or political conditions. From time to time, regulatory agencies have imposed price controls and limitations on production in order to conserve supplies of oil and natural gas. In addition, the production, handling, storage, transportation and disposal of oil and natural gas, byproducts thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations. The Company's operations currently are located primarily in Texas. Thus, the Company's business is subject to environmental regulation on the state level primarily by the Railroad Commission of Texas and the Texas Natural Resource Conservation Commission. The Railroad Commission of Texas regulations may require on the Company to obtain permits and drilling bonds for the drilling of wells. Additionally, the Railroad Commission of Texas regulates the spacing of wells, plugging and abandonment of such wells and the remediation of contamination caused by most types of exploration and production wastes. The Railroad Commission requirements for remediation of contamination are, for the most part, administered on a case-by-case basis. The Company expects that such regulations will be formalized in the future and will in all likelihood become more stringent. Currently, federal regulations provide that drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas are exempt from regulation as "hazardous waste." To the extent that the Company's operations produce wastes that do not fall within this exemption, the storage, handling and disposal of those wastes are regulated on the state level by the Texas Natural Resource Conservation Commission. From time to time, legislation has been proposed to eliminate or modify this exemption. Should the exemption be modified or eliminated, wastes associated with oil and natural gas exploration and production would be subject to more stringent regulation. On the federal level, the Company's operations may be subject to various federal statutes, including the Natural Gas Act, the Comprehensive Environmental Response, Compensation the Liability Act, the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, the Clean Air Act, the Federal Water Pollution Control Act and the Oil Pollution Act, as well as by regulations promulgated pursuant to these actions. These regulations subject the Company to increased operating costs and potential liability associated with the use and disposal of hazardous materials. Although these laws and regulations have not had a material adverse effect on the Company's financial condition or results of operations, there can be no assurance that the Company will not be required to make material expenditures in the future. Moreover, the Company anticipates that such laws and regulations will become increasingly stringent in the future, which could lead to material costs for environmental compliance and remediation by the Company. Any failure by the Company to obtain required permits for, control the use of, or adequately restrict the discharge of hazardous substances under present or future regulations could subject the Company to substantial 27 liability or could cause its operations to be suspended. Such liability or suspension of operations could have a material adverse effect on the Company's business, financial condition and results of operations. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In June 1998, the FASB issued SFAS No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES, which is effective for fiscal years beginning after June 15, 1999. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It also requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those items at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. As discussed in Note 5 to the Financial Statements, the Company has historically hedged a portion of its future gas production using gas swap contracts. These contracts are a hedge of the Company's exposure to the variability of future cash flows due to potential decreases in gas prices. For a derivative designated as hedging the exposure to variable cash flows of a forecasted transaction (referred to as a cash flow hedge), the effective portion of the derivative gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. The extent of the impact of adopting SFAS No. 133 on the Company's consolidated financial position, results of operations, or cash flows will be a function of the open derivative contracts at the date of adoption. As of December 31, 1998, the Company can not estimate the impact of SFAS 133 on the consolidated financial position, results of operations or cash flows. 28 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK HEDGING ACTIVITIES From time to time, the Company has utilized hedging transactions including swaps, put options and costless collars, with respect to a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure to price fluctuations. While the use of these hedging arrangements limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of hedging transactions also involves risk that the counterparties will be unable to meet the financial terms of such transactions. All of the Company's hedging transactions to date were carried out in the over-the-counter market and the obligations of the counterparties have been guaranteed by entities with at lest an investment grade rating or secured by letters of credit. The Company accounts for these transactions as hedging activities and, accordingly, gains or losses are included in oil and gas revenues when the hedged production is delivered. Neither the hedging contracts nor the unrealized gains or losses on these contracts are recognized in the financial statements. In addition, if the Company's reserves are not produced at the rates estimated by the Company due to inaccuracies in the reserve estimation process, operational difficulties or regulatory limitations, or otherwise, the Company would be required to satisfy its obligations under potentially unfavorable terms. The Company may be at a risk for basis differential, which is the difference in the quoted financial price for contract settlement and the actual physical point of delivery price. Substantial variations between the assumptions and estimates used by the Company in its hedging activities and actual results experienced could materially adversely affect the Company's financial condition and its ability to manage risk associated with fluctuations in oil and natural gas prices. The annual average oil and natural gas prices received by the Company have fluctuated significantly over the past three years. Approximately 54%, 72% and 48% of the Company's production was hedged during the years ended December 31, 1996, 1997 and 1998, respectively. The Company's weighted average natural gas price received per Mcf (including the effects of hedging transactions) was $2.15, $2.33 and $2.07 during the years ended December 31, 1996, 1997 and 1998, respectively. Hedging transactions resulted in a ($0.24), ($0.32) and $0.01 (reduction) increase in the Company's weighted average natural gas price received per Mcf in 1996, 1997 and 1998, respectively. The fair value of these hedging contracts was $(1.1 million), $(1.1 million) and $2.1 million as of December 31, 1996, 1997, and 1998, respectively. As of December 31, 1998, the Company had entered into commodity price hedging contracts with respect to its gas production for 1999 and 2000 as follows:
PRICE PER MMbtu ------------------------------------------------ COLLAR VOLUME IN ------------------------------- PERIOD MMbtu FLOOR CEILING STRIKE PRICE - ------------------------- --------- ------------- ------------- ------------ Jan 1999 - Dec 1999 Put option 600,000 $2.25 Costless collar 1,800,000 $2.25 $2.99 Costless collar 1,800,000 $2.00 $2.22 Costless collar 2,400,000 $2.15 $2.38 Costless collar 1,800,000 $1.98 $2.22 Costless collar 1,200,000 $2.15 $2.36 Jan 2000 - April 2000 Costless collar 600,000 $2.00 $2.22 Costless collar 1,200,000 $2.15 $2.38 Costless collar 600,000 $1.98 $2.22 Costless collar 600,000 $2.15 $2.36
These hedging transactions are settled based on settlement prices relative to a Houston Ship Channel Index. With respect to any particular costless collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such transaction. For put options, the counterparty is required to make payment to the Company if the settlement price for any settlement period is below the strike price for such transaction. The Company is not required to make any payment in connection with the settlement of put options. The premium paid by the Company for the put option was approximately $229,500. As of December 31, 1998, approximately $76,500 remains unamortized. The borrowings under the Credit Facility and the value of the $135 million Series B Notes are subject to market fluctuations as influenced by certain economic factors and events. The interest rate for borrowings under the Credit Facility are determined at one of two floating interest rates (ABR rate or Eurodollar rate) plus 0.5% to 2.25% at the election of the Company. Thus, the fair value of the Credit Facility approximates its market value. The fair value of the $135 million Series B Notes was approximately $120 million at December 31, 1998 and the effective interest rate was 12.04%. 29 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ---- Report of Independent Accountants.......................................... 31 Consolidated Balance Sheets................................................ 32 Consolidated Statement of Operations....................................... 33 Consolidated Statement of Stockholder's Deficit............................ 34 Consolidated Statement of Cash Flows....................................... 35 Notes to Consolidated Financial Statements................................. 36
30 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Michael Petroleum Corporation: In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholder's deficit, and cash flows present fairly, in all material respects, the financial position of Michael Petroleum Corporation at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Houston, Texas March 31, 1999 31 MICHAEL PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands of dollars, except share data)
DECEMBER 31, ---------------------- 1997 1998 ------- -------- ASSETS Current assets: Cash and cash equivalents $ 782 $ 430 Receivables: Accrued oil and gas sales 3,991 5,362 Joint interest and other 481 1,004 Note receivable -- 1,500 Prepaid expenses and other 1 655 ------- -------- Total current assets 5,255 8,951 Oil and gas properties (successful efforts method), at cost 34,977 155,867 Less: accumulated depletion, depreciation and amortization (6,966) (24,989) ------- -------- 28,011 130,878 Deferred income taxes 1,876 Other assets 351 5,577 ------- -------- Total assets $33,617 $147,282 ======= ======== LIABILITIES AND STOCKHOLDER'S DEFICIT Current liabilities: Accounts payable: Trade $ 3,746 $ 7,202 Revenue distribution 1,756 1,723 Accrued interest 263 4,076 Accrued liabilities 35 554 Current portion of long-term debt 8,056 41 ------- -------- Total current liabilities 13,856 13,596 Long-term debt 19,885 144,842 Deferred income taxes 1,791 -- ------- -------- Total liabilities 35,532 158,438 Commitments and contingencies (Note 10) Stockholder's deficit: Preferred stock ($.10 par value, 50,000,000 shares authorized, no shares issued) Common stock ($.10 par value, 100,000,000 shares authorized, 10,000 shares issued and outstanding) 1 1 Additional paid-in capital 610 610 Accumulated deficit (2,526) (11,767) ------- -------- Total stockholder's deficit (1,915) (11,156) ------- -------- Total liabilities and stockholder's deficit $33,617 $147,282 ======= ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 32 MICHAEL PETROLEUM CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS (In thousands of dollars)
YEAR ENDED DECEMBER 31, ---------------------------------- 1996 1997 1998 ------- ------- -------- Revenues: Oil and natural gas sales $ 3,594 $ 9,139 $ 22,668 Gain on sale of oil and natural gas properties 182 - 50 ------- ------- -------- 3,776 9,139 22,718 ------- ------- -------- Operating expenses: Production costs 1,931 1,870 4,118 Depletion, depreciation and amortization 1,024 3,651 12,620 Impairment of oil and natural gas properties 156 238 5,424 Exploration 46 333 85 General and administrative 424 980 1,802 ------- ------- -------- 3,581 7,072 24,049 ------- ------- -------- Operating income (loss) 195 2,067 (1,331) ------- ------- -------- Other income (expense): Interest income and other 30 46 235 Interest expense and other (924) (2,109) (12,281) ------- ------- -------- (894) (2,063) (12,046) (Loss) income before income taxes and extraordinary item (699) 4 (13,377) Provision (benefit) for income taxes 1,780 11 (4,667) ------- ------- -------- Loss before extraordinary item (2,479) (7) (8,710) Extraordinary item - extinguishment of T.E.P. Financing, net of tax of $285 - - (531) ------- ------- -------- Net loss $(2,479) $ (7) $ (9,241) ======= ======= ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 33 MICHAEL PETROLEUM CORPORATION CONSOLIDATED STATEMENT OF STOCKHOLDER'S DEFICIT For the years ended December 31, 1996, 1997 and 1998 (In thousands of dollars, except per share data)
COMMON STOCK ----------------- ADDITIONAL PAID-IN ACCUMULATED SHARES AMOUNT CAPITAL DEFICIT TOTAL ------ ------ ---------- ----------- -------- Balance, December 31, 1995 10 $1 $455 $ (31) $ 425 Dividend to MHI (9) (9) Issuance of warrants in conjunction with T.E.P. Financing 155 155 Net loss (2,479) (2,479) ---- --- ---- -------- -------- Balance, December 31, 1996 10 $1 610 (2,519) (1,908) Net loss (7) (7) ---- --- ---- -------- -------- Balance, December 31, 1997 10 $1 610 (2,526) (1,915) Net loss (9,241) (9,241) ---- --- ---- -------- -------- Balance December 31, 1998 10 $1 $610 $(11,767) $(11,156) ==== === ==== ======== ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 34 MICHAEL PETROLEUM CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (In thousands of dollars)
YEAR ENDED DECEMBER 31, ------------------------------------ 1996 1997 1998 -------- -------- --------- Cash flows from operating activities: Net loss $ (2,479) $ (7) $ (9,241) Adjustments to reconcile net loss to net cash provided by operating activities: Depletion, depreciation and amortization 1,024 3,651 12,620 Impairment of oil and natural gas properties 156 238 5,424 Deferred income taxes 1,780 11 (4,952) Extraordinary item - extinguishment of T.E.P. Financing, net of taxes -- -- 470 Gain on sale of oil and gas properties (182) -- (50) Abandonment of oil and gas properties -- 249 35 Amortization of debt and bond issuance costs -- -- 619 Amortization of deferred loss on early termination of commodity swap agreement -- -- 712 Amortization of discount on debt 43 131 205 Changes in assets and liabilities: Accounts receivable - accrued oil and gas sales (1,189) (2,333) (1,370) Accounts receivable - joint interest and other (682) 562 (514) Prepaid expenses and other 2 72 (1,236) Accounts payable - trade 1,350 710 (1,769) Accounts payable - revenue distribution 846 296 (32) Accrued interest 73 (121) 3,813 Accrued liabilities 106 7 518 -------- -------- --------- Net cash provided by operating activities 848 3,466 5,252 -------- -------- --------- Cash flows from investing activities: Additions to oil and gas properties (14,981) (14,963) (114,978) Proceeds from sale of oil and gas properties 228 -- 150 Issuance of note receivable -- -- (1,500) -------- -------- --------- Net cash used in investing activities (14,753) (14,963) (116,328) -------- -------- --------- Cash flows from financing activities: Proceeds from long-term debt 17,329 14,238 145,603 Payments on long-term debt (2,130) (3,114) (29,314) Dividend to MHI (9) -- -- Additions to deferred loan costs (440) (26) (5,565) -------- -------- --------- Net cash provided by financing activities 14,750 11,098 110,724 Net increase (decrease) in cash and cash equivalents 845 (399) (352) Cash and cash equivalents, beginning of period 336 1,181 782 -------- -------- --------- Cash and cash equivalents, end of period $ 1,181 $ 782 $ 430 ======== ======== =========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS. 35 MICHAEL PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: NATURE OF OPERATIONS AND BASIS OF PRESENTATION Michael Petroleum Corporation and Subsidiaries (the "Company" or "MPC") is engaged in the acquisition, exploration and development of oil and natural gas properties principally located in the Lobo Trend of South Texas. The Company was incorporated in June 1982. The Company, which was owned by the stockholders of Michael Holdings, Inc. ("MHI"), became a wholly-owned subsidiary of MHI on July 1, 1996 in a transaction accounted for at historical cost as a reorganization of entities under common control. On March 25, 1998, the Company was merged with and into Michael Gas Production Company ("MGPC"), which was also a wholly-owned subsidiary of MHI. Following the merger, MGPC changed its name to MPC. This transaction was accounted for at historical cost as a reorganization of entities under common control. The consolidated financial statements reflect the financial position, results of operations and cash flows of the combined companies for all periods presented as if the merger had occurred on December 31, 1995. The consolidated financial statements contain the accounts of the Company after elimination of all significant intercompany balances and transactions. As an independent oil and gas producer, the Company's revenue, profitability and future rate of growth are substantially dependent upon prevailing prices for natural gas, oil and condensate, which are dependent upon numerous factors beyond the Company's control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been very volatile, as evidenced by the recent volatility of oil and gas prices, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. A substantial or extended decline in oil and gas prices could have a material adverse effect on the Company's consolidated financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and access to capital. Natural gas approximates 87% and 97% of the Company's proved reserves at December 31, 1998 and 1997, respectively. CASH AND CASH EQUIVALENTS Cash equivalents consist of short-term highly liquid investments that have an original maturity of three months or less. The Company maintains its cash with two financial institutions. The Company periodically assesses the financial condition of the institutions and believes that any possible credit risk is minimal. OIL AND GAS PROPERTIES The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment allowance is provided to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered to be not realizable. Depletion, depreciation and amortization ("DD&A") of development costs and acquisition costs of proved oil and gas properties is provided using the units-of-production method based on proved developed reserves and proved reserves, respectively. The computation of DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds from equipment salvage. The estimated restoration, dismantlement and abandonment costs are expected to be offset by the estimated residual value of lease and well equipment. Gains and losses are recognized on sales of entire interests in proved and unproved properties. Sales of partial interests are generally treated as recoveries of costs. 36 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS IMPAIRMENT OF OIL AND GAS PROPERTIES The net book value of an asset is reduced to fair value if the sum of expected undiscounted future net cash flows from the use of the asset is less than the net book value of the asset. The Company evaluates impairment of its oil and gas properties on a field basis. The Company makes a determination of any market changes or performs a periodic review of all fields each year. NATURAL GAS BALANCING The Company incurs natural gas production volume imbalances in the ordinary course of business on jointly owned properties. The Company follows the sales method to account for such imbalances. Under this method, revenue is recorded based on the Company's net revenue interest in production taken for delivery. The Company records a liability if its sales of gas volumes in excess of its entitlements from a jointly owned reservoir exceed its interest in the remaining estimated natural gas reserves of such reservoir. Volumetric production is monitored to minimize imbalances, and such imbalances were not significant at December 31, 1997 and 1998. OTHER ASSETS Other assets include loan origination costs which are amortized on a straight-line basis over the term of the related obligation. INCOME TAXES Through June 30, 1996, the Company was taxed under the provisions of "Subchapter S" of the Internal Revenue Code, which provides that the individual shareholders are liable for federal income taxes on the Company's taxable income. Accordingly, no provision for federal income taxes is reflected in the consolidated statement of operations for periods ending prior to June 30, 1996. Effective July 1, 1996, the Company began filing a consolidated federal income tax return with MHI. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax bases of assets and liabilities. Tax credits are accounted for under the flow-through method, which reduces the provision for income taxes in the year the tax credits are earned. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company calculates current and deferred taxes on an individual company basis. STOCK-BASED COMPENSATION Statement of Financial Accounting Standards No. 123, ACCOUNTING FOR STOCK-BASED COMPENSATION, encourages, but does not require companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to continue to apply Accounting Principles Board Opinion No. 25, ACCOUNTING FOR STOCK ISSUED TO EMPLOYEES, and related interpretations to account for stock-based compensation. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock. PRICE RISK MANAGEMENT ACTIVITIES The Company periodically uses swaps, put options and costless collars to hedge or otherwise reduce the impact of natural gas price fluctuations. Gains and losses resulting from changes in the market value of the financial instruments utilized as hedges are deferred and recognized in the statement of operations, together with the gain or loss on the hedged transaction, as the physical production is sold under the relevant contracts. Cash flows resulting from the Company's risk management activities are classified in the accompanying statement of cash flows in the same category as the item being hedged. These instruments are measured for effectiveness on an enterprise basis both at the inception of the contract and on an ongoing basis. If these instruments are terminated prior to maturity, resulting gains or losses continue to be deferred until the hedged item is recognized in income. In connection with these hedging transactions, the Company may be exposed to nonperformance by other parties to such agreements, thereby subjecting the Company to current natural gas prices. However, the Company only enters into hedging contracts with large financial institutions and does not anticipate nonperformance. 37 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS CONCENTRATION OF CREDIT RISK Substantially all of the Company's receivables are within the oil and gas industry, primarily from purchasers of oil and gas and joint venture participants. Collectibility is dependent upon the general economic conditions of the purchasers and the oil and gas industry. The receivables are not collateralized and to date, the Company has had minimal bad debts. FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying amounts reported in the balance sheet for cash and cash equivalents, receivables, and accounts payable approximate their fair value. The fair value of the Company's long-term debt and derivative financial instruments are estimated using current market quotes. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company's most significant estimates relate to the assessment of impairment of proved and unproved oil and gas properties, depreciation, depletion, and amortization expense, proved oil and gas reserves and utilization of deferred tax assets. Actual results could differ from these estimates. 2. OIL AND GAS PROPERTY TRANSACTIONS: In August 1996, the Company acquired certain oil and natural gas properties in Webb County and Zapata County, Texas (the "1996 Acquisition") for approximately $11.8 million. As a result, unaudited pro forma revenues and income from continuing operations for the year ended December 31, 1996 were $8,730,000 (unaudited) and $2,497,000 (unaudited), respectively. In March 1998, the Company completed the acquisition of interests in certain oil and natural gas properties in Webb County, Hildago County and Zapata County, Texas, and certain related seismic data from Enron Oil & Gas Company (the "Enron Acquisition") for $45.8 million. In April 1998, the Company completed the acquisition of certain oil and natural gas leases in Webb County, Texas, from Conoco Inc. (the "Conoco Acquisition") for $22.5 million. In April 1998, the Company entered into a lease with Mobil effective as of January 1, 1998 in the Lobo Trend (the "Lobo Lease"). Consideration for the Lobo Lease is in the form of future deliveries of 4 Bcf of gas, which commenced May 1, 1998 and terminated December 31, 1998. On April 23, 1998, the Company entered into a contract to secure delivery of this volume of gas for consideration of $9.98 million. The following pro forma data presents the results of the Company for the years ended December 31, 1997 and 1998, as if the acquisitions of the Lobo Lease, the Conoco Acquisition and the Enron Acquisition had occurred on January 1, 1997. The pro forma results of operations are presented for comparative purposes only and are not necessarily indicative of results which would have been obtained had the acquisitions been consummated as presented. The following data reflect pro forma adjustments for oil and natural gas revenues, production costs, depreciation, and depletion related to the properties acquired, interest on borrowed funds, and related income tax effects (in thousands):
YEAR ENDED DECEMBER 31, ------------------------- 1997 1998 ------- ------- (UNAUDITED) Pro forma: Revenues $31,209 $26,563 Loss from continuing operations (1,465) (9,375)
38 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. LONG-TERM DEBT: Long-term debt consisted of the following (in thousands):
DECEMBER 31, --------------------------- 1997 1998 -------- -------- 11 1/2% Senior Notes due 2005 - $135,000 Credit Facility - 12,000 Notes payable under the comprehensive credit agreement $ 28,266 - Installment notes to financial institutions, payable monthly, interest at rates ranging from 3.9% to 11.26%, due April 1996 to September 2001, collateralized by vehicles and office equipment 139 65 Note payable to an individual, payable monthly, interest at 8%, due February 2000, unsecured 17 9 -------- -------- 28,422 147,074 -------- -------- Unamortized original issue discount on Senior Notes (2,191) Unamortized discount on note payable under comprehensive credit agreement (481) - -------- -------- Total long-term debt 27,941 144,883 -------- -------- Less: current portion (8,056) (41) -------- -------- Long-term debt $19,885 $144,842 ======== ========
Estimated annual principal payments at December 31, 1998 are as follows (in thousands): 1999 $ 41 2000 25 2001 8 2002 12,000 2003 - Thereafter 135,000 -------- $147,074 ========
SENIOR NOTES On April 2, 1998, the Company issued $135 million of Senior Notes at a discount of 1.751%. The Senior Notes mature in April 2005 and bear interest at a rate of approximately 11.5% per annum, payable semi-annually in April and October of each year, commencing October 1998. The effective interest rate under the Senior Notes for the year ended December 31, 1998 was 12.04%. Bond discount costs are amortized on the interest method over the term of the Senior Notes. The Senior Notes are redeemable at the option of the Company, in whole or in part, at any time after April 2003, at specified redemption prices plus accrued and unpaid interest and liquidated damages, as defined. In the event of certain asset dispositions, the Company is required under certain circumstances to use the excess proceeds from such a disposition to offer to repurchase the Senior Notes (and other Senior Indebtedness for which an offer to repurchase is required to be concurrently made). The Company is required to comply with certain covenants, which limit, among other things, the ability of the Company to incur additional indebtedness, pay dividends, repurchase equity interests, sell assets or enter into mergers and consolidations. The fair value of the Senior Notes was $120 million at December 31, 1998. 39 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS T.E.P. FINANCING On August 13, 1996, the Company entered into a comprehensive credit agreement (the "T.E.P. Financing") with a limited partnership. Under the T.E.P. Financing, total available credit amounted to approximately $42.2 million, of which $16.3 million was available for oil and gas property acquisitions and $25.9 million for development costs. The Company utilized loan proceeds of approximately $14.9 million to acquire proved oil and gas properties located in South Texas the 1996 Acquisition. Through 1997, loan proceeds of approximately $11.8 million had been used to develop those properties. In conjunction with entering into the T.E.P. Financing, the Company conveyed to an affiliate of the lender a net profits interest in all of the Company's oil and gas properties, including the acquired properties ("Net Profits Interest"). The Net Profits Interest granted the affiliate 30% of the net profits, as defined, beginning the earlier of August 12, 2001, or the date of repayment of all amounts due and owing pursuant to the T.E.P. Financing. The Net Profits Interest decreased to 15% of the net profits, as defined, after payment of $10 million. As part of the T.E.P. Financing, the Company also granted to the lender a warrant to purchase up to five percent of MHI's common stock at an exercise price of $8 per share until August 12, 2001. The value assigned to the Net Profits Interest and warrant was recorded as a discount to the loan proceeds. Under the terms of the T.E.P. Financing, principal was payable as a percentage of net revenue, as defined. As of December 31, 1997, the Company had repaid approximately $2.9 million of principal under the T.E.P. Financing. Interest was payable monthly and accrued at a combination of LIBOR plus 4.5% and New York prime plus certain basis points based on the specific borrowing. At December 31, 1997, the blended effective interest rate accruing on the loans was 15% per annum. The loan was collateralized by the oil and gas properties and the stock of the Company. The T.E.P. Financing contained financial covenants, the most restrictive of which pertained to the payment of dividends, distributions to shareholders and the Company's working capital ratio. The T.E.P. Financing also contained administrative covenants. Except for violations of certain administrative covenants during the year ended December 31, 1997, the Company was in compliance with the covenants of the T.E.P. Financing. Regarding the violations of such administrative covenants, the Company obtained a waiver from the lender of the T.E.P. Financing which agreed not to assert any default based upon such violations unless they existed after April 15, 1998. On April 2, 1998, a portion of the proceeds from the sale of the Senior Notes was used to pay outstanding borrowings under the T.E.P. Financing amounting to approximately $28 million and repurchase the Net Profits Interest for $11 million. On April 2, 1998, the T.E.P. Financing was extinguished, and the unamortized balance of the notes payable discount, the deferred debt issuance costs and certain fees incurred at closing were written off and reflected in the income statement as an extraordinary loss, net of taxes. The effective interest rate accruing on the loans through the date of extinguishment in 1998 was 12.8%. CREDIT FACILITY In May 1998, the Company entered into a four-year credit facility with Christiania Bank og KreditKasse ("Christiania") as lender and administrative agent, pursuant to the terms of that certain Credit Agreement dated effective as of May 15, 1998 (the "Credit Facility"). The Credit Facility provides for loans in an outstanding principal amount not to exceed $50.0 million at any one time, subject to a borrowing base to be determined semi-annually by the administrative agent (the initial borrowing base was $30.0 million), and the issuance of letters of credit in an outstanding face amount not to exceed $6.0 million at any one time with the face amount of all outstanding letters of credit reducing, dollar-for-dollar, the availability of loans under the Credit Facility. The initial borrowing base was increased by $5 million to a total of $35 million. However, effective April 1, 1999, the borrowing base was reduced to $23 million. Under the Credit Facility, the principal balance outstanding is due and payable on May 28, 2002, and each letter of credit shall be reimbursable by the Company when drawn, or if not then otherwise reimbursed, paid pursuant to a loan under the Credit Facility. Commencing on October 31, 1999, and continuing until its stated maturity, the maximum amount available for borrowings and letters of credit under the Credit Facility will not only be adjusted (increased or decreased, as applicable) by the semi-annual borrowing base determination, but also (i) decreased by monthly mandatory reductions in the borrowing base of $1.5 40 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS million per month and (ii) adjusted for sales of collateral having an aggregate value exceeding the lesser of $4.0 million per year or 5% of the Company's total proved reserve values. Both the Company and Christiania may initiate two unscheduled redeterminations of the borrowing base during any consecutive twelve-month period. No assurance can be given that the bank will not elect to redetermine the borrowing base in the future. If the sum of the outstanding principal and letters of credit (both drawn and undrawn) exceeds the borrowing base, the Company shall, within 30 days, either repay such excess in full or provide additional collateral acceptable to Christiania. At March 31, 1999, the Company had $23 million of outstanding indebtedness under the Credit Facility. The interest rate for borrowings under the Credit Facility are determined at either (i) the ABR rate, or (ii) the Eurodollar Rate plus 2.25%, at the election of the Company. The "ABR" rate is the higher of (i) Christiania Bank's prime rate then in effect plus 0.5%, (ii) the secondary market rate for three-month certificates of deposit plus 1.5% or (iii) the federal funds rate then in effect plus 1.0%. The effective interest rate under the Credit Facility for the year ended December 31, 1998 was 6.8%. Interest is due on a quarterly basis. The Credit Facility is collateralized by substantially all of the oil and natural gas assets of the Company, including accounts receivable, equipment and gathering systems. The proceeds of the Credit Facility may be used to finance working capital needs and for general corporate purposes of the Company in the ordinary course of its business. The Credit Facility contains certain covenants by the Company, including (i) limitations on additional indebtedness and on guaranties by the Company except as permitted under the Credit Facility, (ii) limitations on additional investments except those permitted under the Credit Facility and (iii) restrictions on dividends or distributions or on repurchases or redemptions of capital stock by the Company except for those involving repurchases of MHI capital stock which may not exceed $500,000 in any fiscal year. The Credit Facility requires the Company to maintain and comply with certain financial covenants and ratios, including a minimum interest coverage ratio, a minimum current ratio and a covenant requiring that the Company's general and administrative expenses may not exceed 12.5% of the Company's gross revenues in a calendar year. The Company was in violation of certain administrative and one financial covenant of the Credit Facility as of December 31, 1998. The Company has obtained a waiver with respect to those violations, from the lender of the Credit Facility, which agreed not to assert any default based upon such violations. The Company and the lender have entered into a First Amendment to the Credit Facility to amend certain financial covenants and the effective interest rate under the Credit Facility. 4. FEDERAL INCOME TAXES: The components of the net deferred taxes are as follows (in thousands):
DECEMBER 31, ------------------- 1997 1998 ------- -------- Deferred tax assets: Net operating loss carryforward $ 3,242 $ 6,613 Other 30 46 ------- -------- Total deferred tax asset 3,272 6,659 ------- -------- Deferred tax liabilities: Oil and gas properties (5,063) (4,774) Other (9) ------- -------- Total deferred tax liability (5,063) (4,783) ------- -------- Net deferred taxes $(1,791) $ 1,876 ======= ========
At December 31, 1998, the Company had a net operating loss carryforward of approximately $19.5 million, which begins expiring in 2017. Utilization of the net operating loss carryforward is subject to annual limitations due to certain stock ownership changes that have occurred or may occur. Realization of deferred tax assets associated with the net operating loss carryforward is dependent upon generating sufficient taxable income prior to their expiration. Management believes it is more likely than not that future taxable income generated will be sufficient to recover the net operating loss prior to expiration. Estimates of taxable income are significantly effected by changes in oil and gas prices, estimates of future production, and estimates of operating and capital costs. The net deferred tax assets could be reduced in the near term if management's estimates of taxable income during the carryforward period are significantly reduced. 41 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Income tax expense (benefit) differs from the amount that would be provided by applying the statutory U.S. federal income tax rate to (loss) income before income taxes for the following reasons (in thousands):
YEAR ENDED DECEMBER 31, ---------------------------- 1996 1997 1998 ------ ---- ------- Computed statutory tax (benefit) expense at 34% $ (304) $ 1 $(4,826) Changes in taxes resulting from: Section 29 credits (13) Conversion to C corporation status 2,032 Permanent differences 10 (11) Other 65 (115) ------ ---- ------- Total income tax expense (benefit) $1,780 $11 $(4,952) ====== ==== =======
5. HEDGING ACTIVITIES: In an effort to achieve more predictable cash flows and earnings and reduce the effects of volatility of the price of oil and natural gas on the Company's operations, the Company has hedged in the past, and in the future expects to hedge oil and natural gas prices through the use of swaps, put options and costless collars. While the use of these hedging arrangements limits the downside-risk of adverse price movements, it also limits future gains from favorable movements. The annual average oil and natural gas prices received by the Company have fluctuated significantly over the past three years. Approximately 54%, 72% and 48% of the Company's production was hedged during the years ended December 31, 1996, 1997 and 1998, respectively. The Company's weighted average natural gas price received per Mcf (including the effects of hedging transactions) was $2.15, $2.33 and $2.07 during the years ended December 31, 1996, 1997 and 1998, respectively. Hedging transactions resulted in a ($0.24), ($0.32) and $0.01 increase (reduction) in the Company's weighted average natural gas price received per Mcf in 1996, 1997 and 1998, respectively. The unrealized (loss) gain related the hedging contracts was ($1.1 million), ($1.1 million) and $2.1 million as of December 31, 1996, 1997, and 1998, respectively. As of December 31, 1998, the Company had entered into commodity price hedging contracts with respect to its gas production for 1999 and 2000 as follows:
PRICE PER MMbtu ------------------------------------------------ COLLAR VOLUME IN ------------------------------- PERIOD MMbtu FLOOR CEILING STRIKE PRICE - ------------------------- --------- ------------- ------------- ------------ Jan 1999 - Dec 1999 Put option 600,000 $2.25 Costless collar 1,800,000 $2.25 $2.99 Costless collar 1,800,000 $2.00 $2.22 Costless collar 2,400,000 $2.15 $2.38 Costless collar 1,800,000 $1.98 $2.22 Costless collar 1,200,000 $2.15 $2.36 Jan 2000 - April 2000 Costless collar 600,000 $2.00 $2.22 Costless collar 1,200,000 $2.15 $2.38 Costless collar 600,000 $1.98 $2.22 Costless collar 600,000 $2.15 $2.36
These hedging transactions are settled based on settlement prices relative to a Houston Ship Channel Index. With respect to any particular costless collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such transaction. For put options, the counterparty is required to make payment to the Company if the settlement price for any settlement period is below the strike price for such transaction. The Company is not required to make any payment in connection with the settlement of put options. The premium paid by the Company for the option was approximately $229,500. As of December 31, 1998, approximately $76,500 remains unamortized. 42 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. EMPLOYEE BENEFIT PLANS: STOCK OPTIONS On July 1, 1998, the shareholders of MHI approved the Michael Holdings, Inc. 1998 Stock Option Plan ("1998 Plan"). The 1998 Plan is available for grants to substantially all employees and directors of MHI and the Company. The 1998 Plan is administered by the Compensation Committee of the Board of Directors of MHI and the Company. A maximum of 194,000 shares of MHI common stock is available for grant under the 1998 Plan. As of December 31, 1998, MHI granted, at exercise prices in excess of the fair market value per share, options covering a total of 73,350 shares to 22 employees and directors of the Company. Options that have been granted and are outstanding generally expire 10 years from the date of grant and become exercisable at the rate of 33.33% per year. The following is a summary of all stock options activity for 1998. The Company did not have a stock option plan in 1996 and 1997.
NUMBER OF WEIGHTED SHARES AVERAGE UNDERLYING EXERCISE OPTIONS PRICE ---------- -------- Outstanding at December 31, 1997 - - Granted 73,350 $ 78.35 Exercised - - Forfeited - - ------ ------- Outstanding at December 31, 1998 73,350 $ 78.35 ====== ======= Exercisable at December 31, 1998 - - ====== =======
At December 31, 1998, the Company had an additional 120,650 shares available for grants of options under the 1998 Plan. If granted, these additional options will be exercisable at a price not less than the fair market value per share of the Company's Common Stock on the date of grant. The weighted average fair value of options granted during 1998 was $18.12. The fair value of each stock option granted is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions for grants in 1998: no dividend yield; expected volatility of 0.00%; risk-free interest rates of 5.40% and an expected option life of 5 years. The following table summarizes information about stock options outstanding and exercisable at December 31, 1998:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE --------------------------------------------------------------------- ----------------------------------- WEIGHTED AVERAGE EXERCISE REMAINING PRICE OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE $ 78.35 73,350 9.52 $ 78.35 - -
Common Stock issued through the exercise of stock options results in a tax deduction for the Company equivalent to the taxable gain recognized by the optionee. For financial reporting purposes, the tax effect of this deduction is accounted for as a credit to additional paid-in capital rather than as a reduction of income tax expense. There were no exercises of options as of December 31, 1998. 43 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS If the fair value based method of accounting in Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123") had been applied, the Company's net loss for 1998 would have approximated the pro forma amount below (in thousands):
YEAR ENDED DECEMBER 31, 1998 ----------------- Net loss - as reported $ (9,241) Net loss - pro forma $ (9,380)
The effects of applying SFAS 123 in this pro forma disclosure are not indicative of future amounts as the Company anticipates making awards in the future under its stock-based compensation plans. 401(k) PLAN The Company sponsors a 401(k) profit sharing plan (the "401(k) Plan") under Section 401(k) of the Internal Revenue Code, which covers all employees of the Company, subject to eligibility conditions. Effective August 1, 1998, the Company, began to match $0.50 for each $1.00 of employee deferral, with the Company's contribution not to exceed 6% of an employee's salary, subject to limitations imposed by the Internal Revenue Code. The Company's contributions amounted to approximately $18,000 for the year ended December 31, 1998. The Company did not make any contributions to the 401(k) Plan during the years ended December 31, 1996 and 1997. 7. RECENT ACCOUNTING PRONOUNCEMENT: In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", ("SFAS 133") which is effective for fiscal years beginning after June 15, 1999. SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It also requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those items at fair value. If certain conditions are met, a derivative may be specifically designated as (a) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction, or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-dominated forecasted transaction. For a derivative designated as hedging the exposure to variable cash flows of a forecasted transaction (referenced to as a cash flow hedge), the effective portion of the derivative gain or loss is initially reported as a component of other comprehensive income (outside earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is reported in earnings immediately. The extent of the impact of adopting SFAS 133 on the Company's financial position, results of operations, or cash flows will be a function of the open derivative contracts at the date of adoption. As of December 31, 1998, the Company can not estimate the impact of SFAS 133 on its future consolidated financial position, results of operations or cash flows. 8. RELATED PARTY TRANSACTIONS AND SIGNIFICANT CONCENTRATIONS: Beginning in April 1996, the Company entered into an agreement, continuing thereafter on a quarterly basis subject to termination by either party, with Upstream Energy Services ("Upstream") whereby Upstream purchases all of the gas produced by the Company at spot market prices. The chairman of the board and chief executive officer ("CEO") of the Company had an ownership interest in Upstream until August 1997. Upstream executed a promissory note in an aggregate principal amount of $20,000 payable to the Company's chairman of the board and chief executive officer in connection with the purchase of his interest. Interest on the indebtedness accrues at a rate of 8.25% per annum. Effective November 1, 1998, the Company entered into a new agreement with Upstream. Under the terms of the agreement, the Company pays Upstream a marketing fee as follows:
VOLUMETRIC TIER (MMBTU/DAY) MARKETING FEE --------------------------- ------------- 1. First 20,000 $0.03/MMbtu 44 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. 20,001 to 40,000 $0.02/MMbtu 3. All volumes over 40,000 $0.01/MMbtu
The Sales Agreement is effective for a one-year period and is renewable quarterly thereafter, subject to either party giving 60 days written notice of termination. Marketing fees paid to Upstream were approximately $106,000, $220,000 and $253,000 for the years ended December 31, 1996, 1997 and 1998, respectively. During the years ended December 31, 1996, 1997 and 1998, Upstream purchased gas produced by the Company for approximately $3.2 million, $9.7 million and $20.8 million, respectively. At December 31, 1996, 1997 and 1998, receivables from Upstream of approximately $2.1 million, $3.9 million and $5.2 million respectively, were included in accrued oil and gas sales in the balance sheet. The Company believes the revenues received were equivalent to those that would be paid under an arms-length transaction in the normal course of business. In July 1997, the Company executed in writing a verbal agreement which had granted to the vice president of geosciences of the Company a 1.5% of 8/8ths overriding royalty interest in leases acquired either directly or indirectly by the Company or its affiliates in Webb County or Zapata County, Texas. This overriding royalty interest expires upon the death of the vice president or upon his termination, resignation or retirement from the Company. The overriding royalty interest does not apply to any producing properties acquired by the Company except for deepenings or sidetracks of existing wells and/or all new wells drilled on the acquired producing properties. For the year ended December 31, 1996, 1997 and 1998, the Vice President of geosciences received from the Company approximately $33,000, $105,000 and $275,000, respectively, under the overriding royalty interests. On June 10, 1997, the Chairman of the Board and CEO of the Company, entered into an agreement with the Company pursuant to which he granted the Company an option to purchase his undivided two-thirds working interest in a leasehold interest. The Company exercised this option and purchased the lease. The leasehold interest expires on May 30, 2000 and covers approximately 750 acres in Webb County, Texas. The exercise price of the option was $87,500. In addition, pursuant to the agreement, the Chairman of the Board and CEO reserved a 1% overriding royalty interest. In December 1998, the Company loaned $1.5 million to a joint venture between a Mexican construction company and a Texas limited liability company that participates in the drilling of natural gas wells for Petroleos Mexicanos ("Pemex") in the Burgos Basin of Northern Mexico. The Mexican construction company has a 51% ownership interest in the joint venture and the Texas limited liability company has a 49% ownership interest. The note receivable is due December 1999 and bears interest at 12%. The Company has the option to convert the note receivable to a 50% equity interest in the Texas limited liability company. 9. SUPPLEMENTAL CASH FLOW INFORMATION: Cash payments for interest are as follows (in thousands):
YEAR ENDED DECEMBER 31, --------------------------------------- 1996 1997 1998 ---- ---- ---- Interest payments (net of interest capitalized of $217, $574, and $1,440 during 1996, 1997, and 1998, respectively) $833 $1,626 $7,677 Non-cash investing and financing transactions not reflected in the statement of cash flows include the following (in thousands): YEAR ENDED DECEMBER 31, 1996 1997 1998 ---- ---- ---- Changes in accounts payable related to capital expenditures $238 $ 465 $5,225 Increase of oil and gas properties due to recognition of deferred tax liabilities from acquired properties 1,285 Transfer of oil and gas properties as repayment Of note payable to a limited partnership 4,791 Adjustment to purchase price of certain oil and gas properties 420
45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. COMMITMENTS AND CONTINGENCIES: LEASES The Company has entered into a noncancelable operating lease agreement for office space in Houston, Texas. The lease term expires in 2004, with two options to renew the lease for a period of five years each. Future minimum lease payments required as of December 31, 1998 related to noncancelable operating leases are as follows:
YEAR ENDED DECEMBER 31, ----------------------- 1999 $144,583 2000 144,583 2001 157,075 2002 163,321 2003 114,159 2004 56,011 -------- $779,732 ========
Rent expense for the years ended December 31, 1996, 1997 and 1998 was approximately $50,000, $69,000 and $154,000, respectively. LEGAL PROCEEDINGS The Company has been and may in the future be involved as a party in various legal proceedings, which are incidental to the ordinary course of business. Management of the Company regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management and legal counsel, as of December 31, 1998, there were no threatened or pending legal matters which would have a material impact on the Company's consolidated financial position, results of operations or cash flows. OTHER MATTERS In conjunction with the 1996 Acquisition, Conoco (as the successor in interest to the seller) and the Company entered into a Gas Exchange Agreement whereby such parties agreed that the Company would deliver to Conoco all of the natural gas produced from the leases acquired in the 1996 Acquisition at the point(s) at which such gas enters the transmission pipelines owned by Lobo Pipeline Company ("Lobo Pipeline") (the "delivery point") in exchange for natural gas in the same quantity and quality delivered by Conoco at the Agua Dulce hub near Corpus Christi, Texas. The parties' obligations under the Gas Exchange Agreement are subject to the natural gas delivered and the pipeline meeting certain specifications. The title to the Company gas vests in Conoco at the delivery point, except to the extent such amount exceeds the amount of redelivered gas at the redelivery point, in which case the Company retains title and ownership of such excess, which is then transported by Lobo Pipeline pursuant to an Interruptible Gas Transportation Agreement. The consideration received by Lobo Pipeline is $0.17 per Mcf for compression, transportation and dehydration. 11. DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES: CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
DECEMBER 31, ---------------------- 1997 1998 ------- --------- Unproved oil and gas properties $ 1,247 $ 14,496 Proved oil and gas properties 33,447 140,490 Other 283 881 ------- --------- 34,977 155,867 Accumulated depreciation, depletion and amortization (6,966) (24,989) ------- --------- $28,011 $ 130,878 ======= =========
46 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES Costs incurred for oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are as follows (in thousands):
YEAR ENDED DECEMBER 31 ------------------------------ 1996 1997 1998 ------- ------- -------- Property acquisition: Unproved $ 2,929 $ 355 $ 15,183 Proved 9,554 2,425 78,458 Development 2,757 12,074 25,295 Interest capitalized 217 574 1,440 ------- ------- -------- Total costs incurred $15,457 $15,428 $120,376 ======= ======= ========
SALES OF OIL AND GAS Substantially all of the Company's natural gas is sold to one purchaser (see Note 8). Substantially all of the Company's oil and condensate is sold to two customers. OIL AND GAS RESERVE QUANTITIES (UNAUDITED) Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments 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. The reserve information as of December 31, 1996, 1997 and 1998 was prepared by Huddleston & Co., Inc. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing economic and operating methods. No major discovery or other favorable or adverse event subsequent to December 31, 1998 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. 47 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table sets forth the Company's net proved reserves, including the changes therein, and proved developed reserves (all within the United States) at the end of each of the three years in the period ended December 31, 1998:
CRUDE OIL NATURAL (MBBl) GAS (MMcf) --------- ---------- Proved developed and undeveloped reserves: January 1, 1996 2,260 5,909 Revision of previous estimates -- 5,920 Extensions, discoveries and other additions 9 2,299 Production (37) (1,324) Sales of minerals in place (2,182) -- Purchases of reserves in place 189 36,442 ------ ------ December 31, 1996 239 49,246 ------ ------ Revision of previous estimates (38) (6,848) Extensions, discoveries and other additions 70 9,105 Production (21) (3,685) Purchases of reserves in place 15 3,347 ------ ------ December 31, 1997 265 51,165 ------ ------ Revision of previous estimates (144) (15,128) Extensions, discoveries and other additions 411 56,116 Production (79) (10,510) Sales of minerals in place (4) (716) Purchases of reserves in place 4,474 108,826 ------ ------ December 31, 1998 4,923 189,753 ====== ======= CRUDE OIL NATURAL (MBBl) GAS (MMcf) --------- ---------- Proved developed reserves: December 31, 1995 689 2,627 December 31, 1996 79 16,924 December 31, 1997 108 22,937 December 31, 1998 904 54,277
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (UNAUDITED) SFAS No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Estimated future income taxes are computed using current statutory income tax rates, including consideration for estimated future statutory depletion and alternative fuels tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such do not necessarily reflect the Company's expectations of actual revenues to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows (in thousands): 48 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, ----------------------------------------- 1996 1997 1998 -------- -------- -------- Future cash inflows $129,588 $115,766 $396,091 Less related future: Production costs (19,319) (20,226) (74,723) Development costs (16,070) (17,295) (92,504) Income tax expense (28,715) (22,497) (38,182) -------- -------- -------- Future net cash flows 65,484 55,748 190,682 10% annual discount for estimating timing of cash flows (23,135) (19,109) (80,172) -------- -------- -------- Standardized measure of discounted future net cash flows $ 42,349 $ 36,639 $110,510 ======== ======== ========
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and gas reserves is as follows (in thousands):
YEAR ENDED DECEMBER 31, ----------------------------------------- 1996 1997 1998 -------- -------- -------- Beginning of the period $ 12,877 $ 42,349 $ 36,639 -------- -------- -------- Revisions of previous estimates: Changes in prices and costs 17,803 (9,701) (8,241) Changes in quantities 9,108 (12,789) (19,637) Development costs incurred during the period 96 1,836 2,400 Additions to proved reserves resulting from extensions and discoveries, less related costs 2,051 11,172 31,001 Purchases of reserves in place 31,082 3,894 83,040 Sales of reserves in place (11,983) (729) Accretion of discount 1,851 6,073 5,149 Sales of oil and gas, net of production costs (1,663) (7,269) (18,262) Net change in income taxes (12,744) 3,530 (7,280) Production timing and other (6,129) (2,456) 6,430 -------- -------- -------- Net increase (decrease) 29,472 (5,710) 73,871 End of the period $ 42,349 $ 36,639 $110,510 ======== ======== ========
49 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not Applicable PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The following table sets forth the names, ages and positions of the directors and executive officers of the Company. A summary of the background and experience of each of these individuals is set forth following the table.
NAME AGE POSITION WITH COMPANY - ---- --- --------------------- Glenn D. Hart 42 Chairman of the Board and Chief Executive Officer Michael G. Farmar 41 President, Chief Operating Officer and Director Jerry F. Holditch 41 Vice President-Geosciences and Director Douglas R. Fogle 43 Vice President-Engineering Robert L. Swanson 41 Vice President-Finance Scott R. Sampsell 42 Vice President, Controller, Treasurer and Secretary Jim R. Smith 59 Director Jack I. Tompkins 53 Director Bryant H. Patton 41 Director
Glenn D. Hart served as President of the Company from its inception in 1982 until August 1996, when he was elected to his current position as Chairman of the Board and Chief Executive Officer. From 1980 to 1983, Mr. Hart was an engineering manager with Sanchez-O'Brien Oil & Gas Corporation, an independent exploration and production company in South Texas. From 1978 to 1980, he held several engineering positions with Tenneco Oil Company's Gulf Coast District. Mr. Hart has a B.S. in petroleum engineering from Texas A&M University. Michael G. Farmar has served as President and Director of the Company since August 1996 and was elected Chief Operating Officer in January 1997. From January 1995 to August 1996, Mr. Farmar served as a financial advisor to small independent oil companies. In 1988, Mr. Farmar joined Odyssey Petroleum Company, where, as General Manager, he was responsible for operational and financial functions of the company until it was sold in 1994. As an analyst for Maxus Exploration Company from 1986 until 1988, Mr. Farmar worked on mergers, acquisitions and divestitures. From 1984 to 1986, Mr. Farmar served in Diamond Shamrock Exploration Company's strategic planning group. Mr. Farmar began his career with Chevron U.S.A. in 1980 and held drilling and production engineering positions through 1983. Mr. Farmar holds a B.S. in petroleum engineering from the University of Southern California and an MBA from Southern Methodist University. Jerry F. Holditch joined the Company in 1987 and has served as Vice President of Geosciences and as Director since that time. From 1982 until 1987, Mr. Holditch served as a developmental geologist with TransTexas Gas Corporation and its predecessors, where he was involved in numerous drilling activities in the Lobo Trend area. From 1980 until 1982, Mr. Holditch was employed as a Gulf Coast geologist with Gulf Oil Corporation. Mr. Holditch holds a B.S. in geology from Texas A&M University. Douglas R. Fogle has served as Engineering Manager of the Company since 1994 after joining the Company in 1992 as a Production Engineer and was appointed to the additional position of Vice President of Engineering in October 1998. From 1986 to 1991, Mr. Fogle worked as an insurance agent. From 1984 to 1986, Mr. Fogle worked with Langham Energy, an independent exploration and production company, as Senior Petroleum Engineer. Mr. Fogle worked from 1978 through 1984 with Champlin Petroleum (which was subsequently acquired by Union Pacific Resources Company), an independent exploration and production company, first as a Drilling and Completion Engineer and then, starting in 1983, as Staff Production Engineer. Mr. Fogle has a B.S. in petroleum engineering from Texas A&M University. Robert L. Swanson joined the Company in September 1997 and has served as Vice President of Finance since that time. From 1994 until joining the Company, Mr. Swanson served as controller, chief financial officer and 50 treasurer of Southwest Ice Enterprises, L.C., a Texas limited liability company and the owner and operator of a professional hockey team in Houston, Texas. Prior to joining Southwest Ice Enterprises, L.C., Mr. Swanson was employed as a public accountant from 1985 to 1994 with two Houston-area accounting firms and one San Antonio-area accounting firm. Mr. Swanson is a certified public accountant and is a member of the American Institute of Certified Public Accountants and the Texas Society of Certified Public Accountants. Scott R. Sampsell has served as the Company's Controller and Treasurer since 1992 and was appointed to the additional positions of Vice President and Secretary in April 1998. From 1982 to 1992, Mr. Sampsell worked in various accounting supervisory roles with Union Texas Petroleum Corporation, an independent exploration and production company, including Manager of Financial and Operational Accounting for one of its subsidiaries. From 1977 until 1982, Mr. Sampsell worked with Supron Energy Corporation, an independent exploration and production company, where he began as staff accountant and advanced to Assistant Treasurer. Jim R. Smith has served as a Director of the Company since November 1996. Since 1964, Mr. Smith has managed a privately-owned real estate development company headquartered in Houston, Texas, which he founded. Mr. Smith is also a private investor and holds positions with several non-profit organizations, including Chairman of the Board of Directors of Goodwill Industries of Houston. Jack I. Tompkins has served as a Director of the Company since July 1997. Mr. Tompkins is a managing director of Raintree Equity Advisors, L.L.C. and is Chairman of the Board of Automotive Realty Trust of America. From 1988 until October 1996, Mr. Tompkins served as Senior Vice President, Chief Information, Administrative and Accounting Officer at Enron Corporation. He also served as a member of Enron Corporation's Management Committee from 1989 through 1996. Mr. Tompkins began his career with Arthur Young & Co., serving three years before joining Arthur Andersen, L.L.P., where he was elected to the partnership in 1981 and was in charge of the Mergers and Acquisitions Program for the Houston office. Mr. Tompkins also serves as chairman of the board of Boys and Girls Country of Houston, Inc., and formerly served on the board of directors of Bank of America Texas, the Private Sector Council and Junior Achievement of Southeast Texas, Inc. Bryant H. Patton has served as a Director of the Company since July 1997. Since 1991, Mr. Patton has been the Vice President of Associated Energy Managers ("AEM"), an institutional investment management firm specializing in private investments in the energy industry. AEM has invested for its clients over $300 million with 23 different independent oil and gas companies through three investment partnerships. Mr. Patton's industry experience spans 20 years including ten years as an equity owner in a fully integrated, family-owned, oil and gas producing company consisting at one time of seven entities and 350 employees. ITEM 11. EXECUTIVE COMPENSATION The following table sets forth certain summary information regarding compensation paid or accrued by the Company to or on behalf of the Company's executive officers (the "Named Executive Officers") for the fiscal years ended December 31, 1997 and 1998. SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION --------------------- 401K STOCK OPTIONS ALL OTHER PRINCIPAL POSITIONS SALARY BONUS CONTRIBUTIONS GRANTED COMPENSATION - ------------------------------------------------- -------- -------- ------------- ------------- ------------ GLENN D. HART Chairman of the Board and Chief Executive Officer 1998 $238,500 $202,500 $3,038 -0- $ 10,553 (1) 1997 144,000 6,000 - -0- 11,303 (1) MICHAEL G. FARMAR President and Chief Operating Officer 1998 165,000 135,000 $2,160 -0- $ -0- 1997 84,000 3,500 - -0- -0- JERRY F. HOLDITCH Vice President-Geosciences 1998 99,000 75,000 $1,355 -0- $274,690 (2) 1997 60,000 2,500 -0- -0- 104,946 (2) DOUGLAS R. FOGLE Vice President-Engineering 1998 90,900 11,000 $1,262 -0- 1,686 (1) 1997 63,000 2,625 -0- -0- 4,023 (1) SCOTT R. SAMPSELL Vice President, Controller, Treasurer and Secretary 1998 81,300 20,900 $ 998 -0- -0- 1997 69,450 3,050 -0- -0- -0-
(1) Represents the estimated value of personal use of a Company vehicle. (2) Represents amounts paid or accrued to Mr. Holditch during 1998 pursuant to certain overriding royalty interests granted to him. No options were issued to or exercised by the Named Executive Officers in 1998. 51 STOCK OPTION AND OTHER EMPLOYEE COMPENSATION PLANS In July 1998, MHI adopted the Michael Holdings, Inc. 1998 Stock Option Plan (the "Option Plan") pursuant to which incentive stock options as defined in the Internal Revenue Code of 1986, as amended ("ISOs"), and non-qualified stock options ("NQOs") will be available for grant to key employees, consultants and directors of MHI and the Company. The Option Plan is administered by the Compensation Committee of the Board of Directors of MHI. A maximum of 194,000 shares, subject to adjustment for certain events of dilution, is available for grant under the Option Plan. The Option Plan provides that the Option Agreement applicable to the grant of options may provide that unmatured installments of outstanding options will accelerate and become fully vested upon a "change of control" of MHI (as defined in the Option Plan). As of December 31, 1998, a total of 73,350 options were granted under the Option Plan. Grants to employees and directors were granted at an exercise price equal to not less than the fair market value per share on the date of grant. All such options will have terms of not more than ten years and be exercisable in cumulative annual installments of 33.33% of the total number of shares subject to the option grants, beginning on the first anniversary of the date of grant. The Option Plan provides that the plan may be amended or modified by the Board of Directors of MHI without the approval of the shareholders of MHI, except for any amendment which would increase the total number of shares reserved for issuance under the Option Plan or amendments which require shareholder approval pursuant to applicable legal requirements or securities exchange rules. OVERRIDING ROYALTY INTERESTS The Company has had in place for a number of years an arrangement, and by written agreement dated July 24, 1997 the Company formalized such arrangement, pursuant to which it has granted to Jerry Holditch, Vice President--Exploration and a director of the Company, a 1.5% of 8/8ths overriding royalty interest in all leases acquired either directly or indirectly by the Company or its affiliates in Webb County or Zapata County, Texas. For the year ended December 31, 1996, 1997 and 1998, Mr. Holditch received from the Company $32,638, $104,946 and $274,690, respectively, under the overriding royalty interests. The overriding royalty interests will not apply to any producing properties acquired by the Company except for deepenings or sidetracks of existing wells and all new wells drilled on acquired producing properties. According to the terms of the agreement establishing the overriding royalty interests, the Company's obligation to assign overriding royalty interests to Mr. Holditch expires upon the death of Mr. Holditch or upon his termination, resignation or retirement from the Company; however, any overriding royalty interests assigned prior to such an event shall be unaffected by the occurrence of that event. The agreement also restricts Mr. Holditch's ability to compete with the Company in the Lobo Trend for a period of three years following any resignation or retirement of Mr. Holditch from the Company. If, following Mr. Holditch's retirement or resignation, the Company becomes financially incapable of drilling or completing wells on locations previously identified or selected by Mr. Holditch, the Company shall provide written authorization to Mr. Holditch to waive the three-year non-competition provision so that Mr. Holditch may pursue the development of such location prospects. The Company does not anticipate entering into any similar arrangements with any of its officers or directors in the future. EMPLOYMENT AGREEMENTS The Company has entered into employment agreements, effective April 1, 1998, with Glenn D. Hart, Michael G. Farmar and Jerry F. Holditch, pursuant to which Mr. Hart will serve as Chief Executive Officer of the Company, Mr. Farmar will serve as President of the Company and Mr. Holditch will serve as Vice President-Exploration. Each employment agreement is for a term of two years and is automatically renewed for a period of two years from and after the first day of each calendar quarter, commencing July 1, 1998, unless either party gives written notice at least 30 days prior to the end of the applicable period. The employment agreements provide for an annual base salary ($270,000 for Mr. Hart, $180,000 for Mr. Farmar and $100,000 for Mr. Holditch), which amount may be increased subject to periodic reviews. In addition, Messrs. Hart, Farmar and Holditch are eligible to receive an annual incentive bonus in an amount to be determined by the Board of Directors, but in no event will such bonus amount be less than 50% nor more than 100% of the employee's annual base salary. The employment agreements of Messrs. Hart and Farmar further provide that the employee shall be granted options under the Option Plan upon terms and conditions and in an amount to be determined by the Compensation Committee. If during the term of the agreement the employee's employment with the Company is terminated without "cause" (as defined therein) or due to his resignation 52 for "good reason" (as defined therein), the Company will be obligated to pay the employee payments in an amount equal to his base salary for the remaining term of the agreement plus his accrued but unpaid bonus as of the date of termination. The obligations of the Company under the employment agreements are guaranteed by MHI. COMPENSATION OF DIRECTORS Non-employee directors of the Company are eligible to receive grants of nonqualified stock options to purchase shares of Common Stock pursuant to the Option Plan. On August 1, 1998, based on their relative length of service as directors, Messrs. Tompkins and Patton were granted options to purchase 10,000 shares of Common Stock, and Mr. Smith was granted an option to purchase 20,000 shares of Common Stock, at exercise prices equal to the fair market value of the Common Stock on the date of grant. In addition, the Company's non-employee directors receive $2,000 plus out-of-pocket expenses for each meeting of the Board of Directors that they attend. BOARD COMMITTEES Pursuant to the Company's Bylaws, the Board of Directors has established standing Audit and Compensation Committees. The Audit Committee recommends to the Board the selection and discharge of the Company's independent auditors, reviews the professional services performed by the auditors, the plan and results of the auditing engagement and the amount of fees charged for audit services performed by the auditors and evaluates the Company's system of internal accounting controls. The Compensation Committee recommends to the Board the compensation to be paid to the Company's directors, executive officers and key employees and administers the compensation plans for the Company's executive officers and directors. The members of the Audit Committee are Messrs. Farmar, Smith and Tompkins. The members of the Compensation Committee are Messrs. Smith, Tompkins and Patton. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth, as of December 31, 1998, (i) the number of shares owned by each person known by the Company to own beneficially Common Stock of MHI, (ii) the number of shares owned beneficially by each director and (iii) the number of shares owned beneficially by all executive officers and directors as a group. MHI owns of record all of the issued and outstanding shares of common stock of the Company.
COMMON STOCK BENEFICIALLY PERCENTAGE OF NAME OF PERSON OR GROUP OWNED(1) OWNERSHIP - ----------------------- -------- --------- EXECUTIVE OFFICERS AND DIRECTORS Glenn D. Hart 281,900 36.5% Michael G. Farmar 234,200 30.3% Jerry F. Holditch 64,500 8.3% Jim R. Smith 80,650 10.4% Jack I. Tompkins 20,300 2.6% Bryant H. Patton -- -- Scott R. Sampsell 24,200 3.1% Douglas R. Fogle 34,275 4.4% Robert L. Swanson -- -- All executive officers and directors, as a group 760,525 98.3%
(1) Except as otherwise noted, the named shareholder has sole voting, investment and dispositive power. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Company currently markets all of its natural gas through Upstream Energy Services, L.L.C. ("Upstream") pursuant to a Natural Gas Sales Agreement dated as of November 1, 1998. The Company and the predecessor to Upstream had similar marketing arrangements prior to April 1996. During the year ended December 31, 1996, 1997 and 1998, the Company paid Upstream or its predecessor marketing fees of $106,000, $220,000 and $253,000, respectively, under these arrangements. Until August 1997, Glenn D. Hart, the Company's Chairman and Chief Executive Officer, owned 20% of the equity securities of Upstream and its predecessor. In such capacity, Mr. Hart 53 received dividends of $26,875 and $6,000 in the year ended December 31, 1996 and 1997, respectively. Additionally, Upstream executed a promissory note in an aggregate principal amount of $20,000 payable to Mr. Hart in connection with the purchase by Upstream of Mr. Hart's interest. Interest on the indebtedness accrues at a rate of 8.25% per annum. Neither Mr. Hart nor the Company or any other officer or director of the Company currently owns any interest in Upstream. The Company has granted to Jerry F. Holditch, Vice President-Exploration and a director of the Company, a 1.5% of 8/8ths overriding royalty interest in all leases acquired either directly or indirectly by the Company or its affiliates in Webb County and Zapata County, Texas. See Item 11. Executive Compensation. On June 10, 1997, Glenn D. Hart, Chairman of the Board and Chief Executive Officer of the Company, entered into an agreement with the Company pursuant to which Mr. Hart granted the Company an option to purchase an undivided two-thirds working interest, which Mr. Hart owns in his individual capacity, in a leasehold interest. The Company exercised this option and purchased this lease. The leasehold interest expires on May 30, 2000 and covers approximately 750 acres in Webb County, Texas. The exercise price of the option was $87,500 plus approximately $2,000 in carrying fees. In addition, pursuant to the agreement. Mr. Hart reserved a 1% overriding royalty interest. Concurrently with the closing of the sale of the Senior Notes, the Company acquired, for a purchase price of $11.0 million, the Net Profits Interest from Cambrian, at which time Cambrian received a warrant from MHI to acquire 38,671 shares of Common Stock at an exercise price of $8.00 per share. See Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations--Financing Arrangements." Although the Company has no present intention to do so, it may in the future enter into other transactions and agreements incidental to its business with its directors, officers and principal shareholders. The Company intends any such transactions and agreements to be on terms no less favorable to the Company than could be obtained from unaffiliated parties on an arms' length basis. MHI has entered into Indemnity Agreements with each of the directors of MHI (who also serve as the directors of the Company), pursuant to which MHI has agreed to indemnify each director to the fullest extent permitted under the Texas Business Corporation Act. In addition, pursuant to the Agreement, MHI shall advance reasonable expenses incurred by each director under certain circumstances in any proceeding in which each director was, is or is threatened to be named a defendant. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULTES AND REPORTS ON FORM 8-K (a) 1. CONSOLIDATED FINANCIAL STATEMENTS See Index on page 30. 2. FINANCIAL STATEMENT SCHEDULES None. 54 3. EXHIBITS The following instruments are included as exhibits to this report.
EXHIBIT NUMBER DESCRIPTION ------ ----------- 3.1* Articles of Incorporation of the Company. 3.2* By-Laws of the Company. 4.2* Indenture, dated as of April 2, 1998, between the Company and State Street Bank and Trust Company as Trustee 10.1*** Michael Holdings, Inc. 1998 Stock Option Plan. 10.2** Employment Agreement dated April 1, 1998 between the Company and Glenn D. Hart. 10.3** Employment Agreement dated April 1, 1998 between the Company and Michael G. Farmar. 10.4** Employment Agreement dated April 1, 1998 between the Company and Jerry F. Holditch. 10.5* Purchase and Sale Agreement dated February 20, 1998 by and between the Company and Conoco, Inc. 10.6* Purchase and Sale Agreement dated February 5, 1998 by and between the Company and Enron Oil and Gas Company 10.7* Stock Purchase Warrant granted by Michael Holdings, Inc. to Cambrian Capital Partners, L.P., dated April 2, 1998. 10.8* Form of Indemnification Agreement by and between the Company and its directors. 10.9* Assets Agreement dated April 20, 1998 by and between the Company and Mobil Exploration & Producing U.S. Inc. acting as Agent for Mobil Producing Texas & New Mexico Inc. 10.10* Oil and Gas Lease dated April 20, 1998 by and between the Company and Mobil Producing Texas & New Mexico Inc. 10.11* Warrant to Purchase Shares of Common Stock granted by Michael Holdings, Inc. to Dale L. Schwartzhoff. 10.12* First Amended and Restated Shareholders Agreement of the Company. 10.13* Credit Agreement dated May 15, 1998 among the Company, Christiania and the lenders named therein. 10.14* Master Commodity Swap Agreement dated May 15, 1998 between Christiania and the Company. 10.15*** Natural Gas Marketing, Transportation and Processing Agreement dated as of November 1, 1998 by and between the Company and Upstream Energy Services Company. 10.16*** First Amendment to Credit Agreement dated March 29, 1999 among the Company, Christiania and the lenders named therein. 10.17*** Letter Agreement dated March 30, 1999 between the Company and Christiania. 27.1*** Financial Data Schedule.
* Previously filed as an Exhibit (with a corresponding Exhibit number) to the Company's Registration Statement on Form S-4 filed May 8, 1998, No. 333-52263, and incorporated herein by reference. ** Management compensation or incentive plan previously filed. *** Filed herewith. (b) REPORTS ON FORM 8-K. None. (c) EXHIBITS REQUIRED BY ITEM 601 OF REGULATION S-K Not applicable. 55 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. MICHAEL PETROLEUM CORPORATION Dated: April 1, 1999 By: /s/ MICHAEL G. FARMAR ----------------------- Michael G. Farmar President and Chief Operating Officer POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Michael G. Farmar and Glenn D. Hart and each of them, as true and lawful attorneys-in-fact and agents with full power of substitution and resubstitution for him and in his name, place and stead, in any and all capacities, to sign any and all documents relating to the Annual Report on Form 10-K, for the fiscal year ended December 31, 1998, including any and all amendments and supplements thereto, and to file the same with all exhibits thereto and other documents in connection therewith with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully as to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or their or his substitute or substitutes may lawfully do or cause to be done by virtue hereof. PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS ANNUAL REPORT ON FORM 10-K HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE COMPANY AND IN THE CAPACITIES INDICATED ON THE 1 DAY OF APRIL, 1999.
NAME: CAPACITIES: /s/ GLENN D. HART Chairman of the Board and Chief Executive Officer - --------------------- (Principal Executive Officer) Glenn D. Hart /s/ MICHAEL G. FARMAR President, Chief Operating Officer and Director - --------------------- Michael G. Farmar /s/ JERRY F. HOLDITCH Vice President-Geosciences and Director - --------------------- Jerry F. Holditch /s/ ROBERT L. SWANSON Vice President-Finance - --------------------- (Principal Accounting and Financial Officer) Robert L. Swanson /s/ SCOTT R. SAMPSELL Vice President-Accounting, Treasurer, and Secretary - --------------------- Scott R. Sampsell 56 /s/ JIM R. SMITH Director - --------------------- Jim R. Smith /s/ JACK I. TOMPKINS Director - --------------------- Jack I. Tompkins /s/ BRYANT H. PATTON Director - --------------------- Bryant H. Patton
57 EX-10.1 2 EXHIBIT 10.1 MICHAEL HOLDINGS, INC. 1998 STOCK OPTION PLAN 1. OBJECTIVES. This 1998 Stock Option Plan (the "Plan") is intended as an incentive to attract and retain selected employees of Michael Holdings, Inc. (the "Company") or its Affiliates, to retain and attract persons of training, experience and ability to serve as independent Directors on the Board of Directors of the Company and to provide consideration for services rendered by consultants and independent contractors for the Company and its Affiliates, to encourage the sense of proprietorship of such persons and to stimulate the active interest of such persons in the development and financial success of the Company. It is further intended that the options granted pursuant to this Plan (the "Options") will be either incentive stock options or nonqualified stock options. 2. DEFINITIONS. As used herein, the terms set forth below shall have the following respective meanings: "AFFILIATES" means any Parent Corporation or Subsidiary. "BOARD" means the Board of Directors of the Company. "CODE" means the United States Internal Revenue Code of 1986, as amended from time to time. "COMMITTEE" means the Board or such committee of the Board as is designated by the Board to administer the Plan. At all times after the date, if any, on which the Company first registers the Common Stock under Section 12 of the Exchange Act, the membership of the Committee shall comply with Rule 16b-3. With respect to any grant hereunder which is intended to comply with the requirements of Section 162(m) of the Code, the Committee shall consist of only "outside directors," as such term is described in Section 162(m) of the Code and the accompanying regulations. "COMMON STOCK" means the Common Stock, par value $0.01 per share, of the Company. "DIRECTOR" means any individual serving as a member of the Board of Directors of the Company. "EFFECTIVE DATE" means the date the Plan is approved by the Board of Directors of the Company. "EXCHANGE ACT" means the United States Securities Exchange Act of 1934, as amended from time to time. "FAIR MARKET VALUE" means, as of a particular date, (a) if the shares of Common Stock are listed on a national securities exchange, the closing sales price per share of Common Stock on the consolidated transaction reporting system for the principal such securities exchange on that date, or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported, (b) if the shares of Common Stock are not so listed but are quoted on the Nasdaq National Market System, the closing sales price per share of Common Stock on the Nasdaq National Market System on that date, or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported, (c) if the Common Stock is not so listed or quoted, the mean between the closing bid and asked price on that date, or, if there are no quotations available for such date, on the last preceding date on which such quotations shall be available, as reported by Nasdaq, or, if not reported by Nasdaq, by the National Quotation Bureau, Inc. or (d) if none of the above is applicable, such amount as may be determined by the Board (or an Independent Third Party, should the Board elect in its sole discretion to instead utilize an Independent Third Party for this purpose), in good faith, to be the fair market value per share of Common Stock. "INDEPENDENT THIRD PARTY" means an individual or entity independent of the Company (and any transferor or transferee of Common Stock acquired upon the exercise of an Option under the Plan, if applicable) having experience in providing investment banking appraisal or valuation services and with expertise generally in the valuation of securities or other property for purposes of this Plan. The Company's independent accountants shall be deemed to satisfy the criteria for an Independent Third Party if selected by the Board for that purpose. The Board may utilize one or more Independent Third Parties. "ISO" means an incentive stock option within the meaning of Code Section 422. "NONEMPLOYEE DIRECTOR" means any Director who is not an employee of the Company or any Affiliate. "NONQUALIFIED OPTION" means a nonqualified stock option within the meaning of Code Section 83. "OPTION AGREEMENT" means a written agreement between the Company and an Optionee that sets forth the terms, conditions and limitations applicable to an Option. "OPTIONEE" means an employee of the Company or any of its Affiliates, a consultant, independent contractor or a Nonemployee Director to whom an Option has been granted under this Plan. "PARENT CORPORATION" means any corporation (other than the Company) in an unbroken chain of corporations beginning with the Company if, at the time of the granting of the Option, each of the corporations other than the last corporation in the unbroken chain owns stock possessing 50% or more of the total combined voting power of all classes of stock in one of the other corporations in such chain. "RULE 16b-3" means Rule 16b-3 promulgated under the Exchange Act, or any successor rule. "SUBSIDIARY" means (i) with respect to grants of Nonqualified Options, any corporation, limited liability company or similar entity of which the Company directly or indirectly owns shares representing more than 50% of the voting power of all classes or series of equity securities of such entity, which have the right to vote generally on matters submitted -2- to a vote of the holders of equity interests in such entity, and (ii) with respect to grants of ISOs, any subsidiary within the meaning of Section 424(f) of the Code or any successor provision. 3. ELIGIBILITY. All employees of the Company and its Affiliates and all Nonemployee Directors are eligible for Options under this Plan. The Committee shall select the Optionees in the Plan from time to time by the grant of Options under the Plan. The Committee may select, by the grant of options under this Plan, certain consultants and independent contractors to be Optionees. The granting of Options under this Plan shall be entirely discretionary and nothing in this Plan shall be deemed to give any employee, consultant or independent contractor of the Company or its Affiliates or any Nonemployee Director any right to participate in this Plan or to be granted an Option. 4. OPTION AGREEMENT. (a) The Committee shall determine the type or types of Options to be granted to each Optionee under this Plan. Each Option granted hereunder shall be embodied in an Option Agreement, which shall contain such terms, conditions and limitations as shall be determined by the Committee in its sole discretion and shall be signed by the Optionee and by the Chief Executive Officer or any other authorized officer of the Company for and on behalf of the Company. An Option Agreement may include provisions for the repurchase by the Company of Common Stock acquired pursuant to the Plan and the repurchase of an Optionee's option rights under the Plan. Options may be granted in combination or in tandem with, in replacement of, or as alternatives to grants or rights under this Plan or any other employee plan of the Company or any of its Affiliates, including the plan of any acquired entity. An Option may provide for the granting or issuance of additional, replacement or alternative Options upon the occurrence of specified events, including the exercise of the original Option. (b) Notwithstanding anything herein to the contrary, no Optionee may be granted Options during any three-year period exercisable for more than 60,000 shares of Common Stock under this Plan, subject to adjustment as provided in Section 14. 5. COMMON STOCK RESERVED FOR THE PLAN. The maximum number of shares of Common Stock issuable pursuant to the exercise of Options granted under the Plan shall be 194,000 shares of Common Stock. The Board and the appropriate officers of the Company shall from time to time take whatever actions are necessary to execute, acknowledge, file and deliver any documents required to be filed with or delivered to any governmental authority or any stock exchange or transaction reporting system on which shares of Common Stock are listed or quoted in order to make shares of Common Stock available for issuance pursuant to this Plan. Shares of Common Stock subject to Options that (i) are forfeited or terminated, (ii) expire unexercised, (iii) are settled in cash in lieu of Common Stock, or (iv) are exchanged for Common Stock owned by the Optionee upon exercise of an Option, shall immediately become available for the granting of Options. The Committee may from time to time adopt and observe such procedures concerning the counting of shares against the Plan maximum as it may deem appropriate under Rule 16b-3. 6. ADMINISTRATION. This Plan shall be administered by the Committee, which shall have full and exclusive power to interpret this Plan and to adopt such rules, regulations and guidelines for carrying out this Plan as it may deem necessary or proper, all of which powers shall be exercised in the best interests of the Company and in keeping with the -3- objectives of this Plan. The Committee may, in its discretion but subject to any necessary approvals of any stock exchange or regulatory body having jurisdiction over the securities of the Company, provide for the extension of the exercisability of an Option, accelerate the vesting or exercisability of an Option, eliminate or make less restrictive any restrictions contained in an Option, waive any restriction or other provision of this Plan or an Option or otherwise amend or modify an Option in any manner that is either (a) not adverse to the Optionee holding such Option or (b) consented to by such Optionee, including (in either case) an amendment or modification that may result in an ISO's losing its status as an ISO. The Committee may correct any defect or supply any omission or reconcile any inconsistency in this Plan or in any Option in the manner and to the extent the Committee deems necessary or desirable to carry it into effect. Any decision of the Committee in the interpretation and administration of this Plan shall lie within its sole and absolute discretion and shall be final, conclusive and binding on all parties concerned. No member of the Committee or officer of the Company to whom it has delegated authority in accordance with the provisions of Section 7 of this Plan shall be liable for anything done or omitted to be done by him or her, by any member of the Committee or by any officer of the Company in connection with the performance of any duties under this Plan, except for his or her own willful misconduct or as expressly provided by statute. 7. DELEGATION OF AUTHORITY. The Committee may delegate to the Chief Executive Officer and to other senior officers of the Company its duties under this Plan pursuant to such conditions or limitations as the Committee may establish, except that the Committee may not delegate to any person the authority to grant Options to, or take other action with respect to, Optionees who are subject to Section 16 of the Exchange Act or who are "covered employees," as that term is defined under Section 162(m) of the Code. 8. STOCK OPTIONS. Only employees of the Company or an Affiliate may receive grants of ISOs. Employees, consultants, independent contractors and Nonemployee Directors may receive grants of Nonqualified Options. (a) INCENTIVE STOCK OPTIONS. An ISO shall consist of a right to purchase a specified number of shares of Common Stock at an exercise price specified by the Committee in the Option Agreement or otherwise, which shall not be less than the Fair Market Value of the Common Stock on the grant date; provided, however, that the exercise price of an ISO may not be less than 110% of such Fair Market Value if the ISO is awarded to any person who, at the time of grant, owns stock representing more than 10% of the combined voting power of all classes of stock of the Company or any Affiliate. Each ISO shall expire not later than ten years after the grant date (or not later than five years after the grant date if the ISO is awarded to any person who, at the time of grant, owns stock representing more than 10% of the combined voting power of all classes of stock of the Company or any Affiliate), with the expiration date to be specified by the Committee in the Option Agreement. Any ISO granted must, in addition to being subject to applicable terms, conditions and limitations established by the Committee, comply with Section 422 of the Code. Pursuant to the ISO requirements of Code Section 422, notwithstanding anything herein to the contrary, (a) no ISO can be granted under the Plan on or after the tenth anniversary of the Effective Date of the Plan, and (b) no Optionee may be granted an ISO to the extent that, upon the grant of the ISO, the aggregate Fair Market Value (determined as of the date the Option is granted) of the Common Stock with respect to which ISOs (including Options hereunder) are exercisable for the first time by the Optionee during any calendar year (under all plans of the Company and any Affiliate) would exceed $100,000. -4- (b) NONQUALIFIED OPTIONS. A Nonqualified Option shall consist of a right to purchase a specified number of shares of Common Stock at an exercise price specified by the Committee in the Option Agreement or otherwise. Each Option shall expire not later than ten years after the grant date, with the expiration date to be specified by the Committee in the Option Agreement. 9. EXERCISE OF OPTIONS. (a) Options granted to employees, consultants, independent contractors and Nonemployee Directors shall be exercisable in accordance with the terms of the applicable Option Agreement. (b) Except as otherwise provided in Section 13, an Option may be exercised solely by the Optionee during his lifetime or after his death by the person or persons entitled thereto under his will or the laws of descent and distribution. (c) The purchase price of the shares as to which an Option is exercised shall be paid in full at the time of the exercise. Such purchase price shall be payable (i) in cash, (ii) if permitted by the Committee, by means of tendering Common Stock or surrendering all or part of that or any other Option, valued at Fair Market Value on the date of exercise, or (iii) any combination thereof. The Committee may provide for procedures to permit the exercise or purchase of Options by (a) loans from the Company or (b) use of the proceeds to be received from the sale of Common Stock issuable pursuant to an Option. No holder of an Option shall be, or have any of the rights or privileges of, a shareholder of the Company in respect of any shares subject to any Option unless and until certificates evidencing such shares shall have been issued by the Company to such holder. 10. SHAREHOLDERS' AGREEMENT. As a condition to receiving shares of Common Stock upon exercise of an Option, the Optionee must execute the Shareholders' Agreement then in effect, if any, among the shareholders of the Company. 11. TAX WITHHOLDING. The Company shall have the right to deduct applicable taxes with respect to each Option and withhold, at the time of delivery of cash or shares of Common Stock under this Plan, an appropriate amount of cash or number of shares of Common Stock or a combination thereof for payment of taxes required by law or to take such other action as may be necessary in the opinion of the Company to satisfy all obligations for withholding of such taxes. The Committee may also permit withholding to be satisfied by the transfer to the Company of shares of Common Stock theretofore owned by the holder of the Option with respect to which withholding is required. If shares of Common Stock are used to satisfy tax withholding, such shares shall be valued based on the Fair Market Value when the Committee determines that tax withholding is required to be made. 12. TERMINATION OF EMPLOYMENT OR TERMINATION OF DIRECTOR STATUS. Upon the termination of employment for any reason of an Optionee who is an employee of the Company or any Affiliate, the termination of service for any reason of an Optionee who is a consultant or independent contractor of the Company or any Affiliates, or in the event any Optionee who is a Nonemployee Director ceases to be a Director, any unexercised Options shall be treated as provided in the specific Option Agreement evidencing the Option. In the event of such a termination, the Committee may, in its discretion, provide for the extension of the exercisability -5- of an Option for any period that is not beyond the applicable expiration date thereof, accelerate the vesting or exercisability of an Option, eliminate or make less restrictive any restrictions contained in an Option, waive any restriction or other provision of this Plan or an Option or otherwise amend or modify the Option in any manner that is either (a) not adverse to such Optionee or (b) consented to by such Optionee. 13. ASSIGNABILITY. Except as otherwise provided herein or as provided in the Option Agreement, no Option granted under this Plan shall be assignable or otherwise transferable by the Optionee (or his or her authorized legal representative) during the Optionee's lifetime and, after the death of the Optionee, other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order (as defined in Section 401(a)(13) of the Code or Section 206(d)(3) of the United States Employee Retirement Income Security Act of 1974, as amended); and any attempted assignment or transfer in violation of this Section 13(b) shall be null and void. Upon the Optionee's death, the personal representative or other person entitled to succeed to the rights of the Optionee (the "Successor Optionee") may exercise such rights. A Successor Optionee must furnish proof satisfactory to the Company of his or her right to exercise the Option under the Optionee's will or under the applicable laws of descent and distribution. Subject to approval by the Committee in its sole discretion, all or a portion of the Nonqualified Options granted to an Optionee under the Plan may be transferable by the Optionee to (i) the spouse, ex-spouse, children, step-children or grandchildren of the Optionee ("Immediate Family Members"), (ii) a trust or trusts for the exclusive benefit of such Immediate Family Members ("Immediate Family Member Trusts"), (iii) a partnership or partnerships, or limited liability company, in which such Immediate Family Members or Immediate Family Member Trusts have at least 99% of the equity, profit and loss interests ("Immediate Family Member Partnerships"), (iv) an entity exempt from federal income tax pursuant to Section 501(c)(3) of the Code, (v) a split interest trust or pooled income fund described in Section 2522(c)(2) of the Code, and/or (vi) upon approval by the Committee, any other persons or entities, including an individual, corporation, partnership, limited partnership, limited liability partnership, limited liability company, professional corporation, trust, estate, custodian, trustee, executor, administrator, nominee, charity or other entity in its own or a representative capacity; provided that the Option Agreement pursuant to which such Options are granted (or an amendment thereto) must expressly provide for transferability in a manner consistent with this Section. Subsequent transfers of transferred Options shall be prohibited except by will or the laws of descent and distribution or pursuant to a qualified domestic relations order (as described above), unless such transfers are made to the original Optionee or a person to whom the original Optionee could have made a transfer in the manner described herein. No transfer shall be effective unless and until written notice of such transfer is provided to the Company, in the form and manner prescribed by the Company. Following transfer, any such Options shall continue to be subject to the same terms and conditions as were applicable immediately prior to transfer, and, except as otherwise provided herein, the term "Optionee" shall be deemed to refer to the transferee. The events of termination of service in Section 12 shall continue to be applied with respect to the original Optionee, following which the Options shall be exercisable by the transferee only to the extent and for the periods specified in Section 12 or the Option Agreement. The Committee and the Company shall have no obligation to inform any transferee of an Option of any expiration, termination, lapse or acceleration of such Option. The designation by an Optionee of a beneficiary will not constitute a transfer of the Option. -6- 14. ADJUSTMENTS; CHANGE IN CONTROL. (a) The existence of outstanding Options shall not affect in any manner the right or power of the Company or its shareholders to make or authorize any or all adjustments, recapitalizations, reorganizations or other changes in the share capital of the Company or its business or any merger or consolidation of the Company, or any issue of bonds, debentures, preferred or prior preference shares (whether or not such issue is prior to, on a parity with or junior to the shares of Common Stock) or the dissolution or liquidation of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding of any kind, whether or not of a character similar to that of the acts or proceedings enumerated above. (b) In the event of any subdivision or consolidation of outstanding shares of Common Stock (including by way of stock split or reverse split) or declaration of a dividend payable in shares of Common Stock or capital reorganization or reclassification or other transaction involving an increase or reduction in the number of outstanding shares of Common Stock, the Committee shall adjust proportionally: (i) the number of shares of Common Stock reserved under this Plan and covered by outstanding Options; (ii) the exercise price of such Options; (iii) the number of shares to be subject to future Options; (iv) the appropriate Fair Market Value and other price determinations for such Options; and (v) the maximum number of shares that may be granted to an Optionee under Section 4(b). In the event of any other recapitalization or capital reorganization of the Company, consolidation or merger of the Company with another corporation or entity or the adoption by the Company of a plan of exchange affecting the shares of Common Stock or any distribution to holders of shares of Common Stock of securities or property (other than normal cash dividends or dividends payable in shares of Common Stock), the Committee shall make such adjustments or other provisions to outstanding Options as it may deem equitable, including adjustments to avoid fractional shares, to give proper effect to such event; provided that such adjustments shall only be such as are necessary to maintain the proportionate interest of the Optionees and preserve, without exceeding, the value of the Options. In the event of a corporate merger, consolidation, acquisition of property or stock, separation, reorganization or liquidation, the Committee shall be authorized (i) to issue or assume stock options, regardless of whether in a transaction to which Section 424(a) of the Code applies, by means of substitution of new Options for previously issued Options or an assumption of previously issued Options as a part of such adjustment; (ii) to make provision, prior to the transaction, for the acceleration of the vesting and exercisability of, or lapse of restrictions with respect to, Options and the termination of Options that remain unexercised at the time of such transaction; or (iii) to provide for the acceleration of the vesting and exercisability of the Options and the cancellation thereof in exchange for such payment as shall be mutually agreeable to the Optionee and the Committee. (c) If so provided in the Option Agreement, an Option shall become fully exercisable upon a Change in Control (as hereinafter defined) of the Company. For purposes of this Plan, a "Change in Control" shall be conclusively deemed to have occurred if (and only if) any of the following events shall have occurred: -7- (i) prior to the closing of an initial public offering (an "IPO") of shares of capital stock of the Company, (A) a complete sale of the Company's assets or a complete liquidation of the Company, or (B) any other event that the Committee determines to be a Change in Control; and (ii) subsequent to the closing of an IPO of the Company, (A) there shall be consummated any merger or consolidation pursuant to which shares of the Company's Common Stock would be converted into cash, securities or other property, or any sale, lease, exchange or other disposition (excluding disposition by way of mortgage, pledge or hypothecation), in one transaction or a series of related transactions, of all or substantially all of the assets of the Company (a "Business Combination"), in each case unless, following such Business Combination, the holders of the outstanding Common Stock immediately prior to such Business Combination beneficially own, directly or indirectly, more than 51% of the outstanding common stock or equivalent equity interests of the corporation or entity resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company's assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the outstanding Common Stock, (B) the shareholders of the Company approve any plan or proposal for the complete liquidation or dissolution of the Company, (C) any "person" (as such term is defined in Section 3(a)(9) or Section 13(d)(3) under the Exchange Act or any "group" (as such term is used in Rule 13d-5 promulgated under the Exchange Act), other than the Company, any successor of the Company or any Subsidiary or any employee benefit plan of the Company or any Subsidiary (including such plan's trustee), becomes a beneficial owner for purposes of Rule 13d-3 promulgated under the Exchange Act, directly or indirectly, of securities of the Company representing 30% or more of the Company's then outstanding securities having the right to vote in the election of directors, (D) during any period of two consecutive years, individuals who, at the beginning of such period constituted the entire Board, cease for any reason (other than death) to constitute a majority of the directors, unless the election, or the nomination for election by the Company's shareholders, of each new director was approved by a vote of at least a majority of the directors then still in office who were directors at the beginning of the period, or (E) there shall occur any other event which the Committee determines to be a Change in Control. 15. RESTRICTIONS. This Plan, and the granting and exercise of Options hereunder, and the obligation of the Company to sell and deliver Common Stock under such Options, shall be subject to all applicable foreign and United States laws, rules and regulations, and to such approvals on the part of any governmental agencies or stock exchanges or transaction reporting systems as may be required. No Common Stock or other form of payment shall be issued with respect to any Option unless the Company shall be satisfied based on the advice of its counsel that such issuance will be in compliance with applicable federal and state securities laws and the requirements of any regulatory authority having jurisdiction over the securities of the Company. Unless the Options and Common Stock covered by this Plan have been registered under the Securities Act of 1933, as amended, each person exercising an Option under this Plan may be required by the Company to give a representation in writing in form and substance satisfactory to the Company to the effect that he is acquiring such shares for his own account for investment and not with a view to, or for sale in connection with, the distribution of such shares or any part thereof. If any provision of this Plan is found not to be in compliance with such rules, such provision shall be null and void to the extent required to permit this Plan to comply with such rules. Certificates evidencing shares of Common Stock delivered under this -8- Plan may be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the rules, regulations and other requirements of the Securities and Exchange Commission, any securities exchange or transaction reporting system upon which the Common Stock is then listed and any applicable federal, foreign and state securities law. The Committee may cause a legend or legends to be placed upon any such certificates to make appropriate reference to such restrictions. 16. AMENDMENTS OR TERMINATION. Subject to the limitations set forth in this Section 16, the Board may at any time and from time to time, without the consent of the Optionees, alter, amend, revise, suspend, or terminate the Plan in whole or in part. In the event of any such amendment to the Plan, the holder of any Option outstanding under the Plan shall, upon request of the Committee and as a condition to the exercisability thereof, execute a conforming amendment in the form prescribed by the Committee to any Option Agreement relating thereto within such reasonable time as the Committee shall specify in such request. Notwithstanding anything contained in this Plan to the contrary, unless required by law, no action contemplated or permitted by this Section 16 shall adversely affect any rights of Optionees or obligations of the Company to Optionees with respect to any Options theretofore granted under the Plan without the consent of the affected Optionee. Notwithstanding the foregoing, no amendment or modification shall be made, without the approval of the shareholders of the Company: (i) Which would increase the total number of shares reserved for the purposes of the Plan under Section 5, except as provided in Section 14; or (ii) To the extent shareholder approval is otherwise required by applicable legal requirements or applicable stock exchange regulations. Any amendment or modification to the Plan shall also be subject to any necessary approvals of any stock exchange or regulatory body having jurisdiction over the securities of the Company. 17. UNFUNDED PLAN. Insofar as it provides for awards of Common Stock or rights thereto, this Plan shall be unfunded. Although bookkeeping accounts may be established with respect to Optionees who are entitled to Common Stock or rights thereto under this Plan, any such accounts shall be used merely as a bookkeeping convenience. The Company shall not be required to segregate any assets that may at any time be represented by Common Stock or rights thereto, nor shall this Plan be construed as providing for such segregation, nor shall the Company, the Board or the Committee be deemed to be a trustee of any Common Stock or rights thereto to be granted under this Plan. Any liability or obligation of the Company to any Optionee with respect to a grant of Common Stock or rights thereto under this Plan shall be based solely upon any contractual obligations that may be created by this Plan and any Option Agreement, and no such liability or obligation of the Company shall be deemed to be secured by any pledge or other encumbrance on any property of the Company. None of the Company, the Board or the Committee shall be required to give any security or bond for the performance of any obligation that may be created by this Plan. 18. NO EMPLOYMENT GUARANTEED; NO ELECTION AS DIRECTOR GUARANTEED. No provision of this Plan or any Option Agreement hereunder shall confer any right upon any employee, consultant or independent contractor to continued employment or service with the -9- Company or any Affiliate. In addition, the granting of any Option shall not impose upon the Company, the Board or any other Directors of the Company any obligation to nominate any Nonemployee Director for election as a director and the right of the shareholders of the Company to remove any person as a director of the Company shall not be diminished or affected by reason of the fact that an Option has been granted to such person. 19. GOVERNING LAW. This Plan and all determinations made and actions taken pursuant hereto, to the extent not otherwise governed by mandatory provisions of the Code or applicable securities laws, shall be governed by and construed in accordance with the laws of the State of Texas. 20. EFFECTIVE DATE OF PLAN. This Plan shall be effective as of the Effective Date. Notwithstanding the foregoing, the adoption of this Plan is expressly conditioned upon the approval of the holders of a majority of shares of Common Stock present, or represented, and entitled to vote at a meeting of the Company's shareholders held on or before the date one year after the Effective Date. If the shareholders of the Company should fail so to approve this Plan prior to such date, this Plan shall terminate and cease to be of any further force or effect and all grants of Options hereunder shall be null and void. Attested to by the Secretary of Michael Holdings, Inc. as adopted by the Board of Directors of Michael Holdings, Inc. effective as of the 27th day of March, 1998 (the "Effective Date"), and approved by shareholders of Michael Holdings, Inc. on the 16th day of July, 1998. /s/ SCOTT SAMPSELL ------------------------- Scott Sampsell, Secretary Michael Holdings, Inc. -10- EX-10.15 3 EXHIBIT 10.15 NATURAL GAS MARKETING, TRANSPORTATION AND PROCESSING AGENCY AGREEMENT UPSTREAM ENERGY SERVICES COMPANY (AS AGENT) AND MICHAEL PETROLEUM CORPORATION (AS CLIENT) This agreement is made and entered into by and between Los Miquelitos, L.L.C. a Texas Limited Liability Company, d/b/a Upstream Energy Services Company ("UES"), as agent, and Michael Petroleum Corporation ("MPC"), as client, herein referred to collectively as "the Parties" and individually as "Party", as of November 1, 1998. WHEREAS, MPC owns and or controls an interest in certain oil, gas and mineral lease production in the State of Texas; and WHEREAS, UES is engaged in the marketing, processing and transportation of natural gas and the provision of risk management services on behalf of owners of natural gas producing interests; and WHEREAS, MPC desires to employ the services of UES as a business agent to market, manage and administrate its natural gas interests. NOW THEREFORE, in consideration for remuneration described herein and the mutual covenants and agreements herein set forth, the parties hereto have agreed that UES will provide natural gas marketing, transportation, processing, risk management, and business management services on behalf of MPC under the terms and conditions set forth hereunder: 1. TERM OF AGREEMENT 1.1 This agreement shall be in force for an initial term of one (1) year from the effective date hereof (the "Initial Term") and shall automatically extend quarterly thereafter subject to termination by either party under the provisions of Section 1.2 below. 1.2 This agreement may be terminated by either Party delivering written notice to the other party (herein "Termination Notice"). Termination shall become effective as of the last day of the Transition Period as defined in Article 1.3 below. 1.3 Beginning on the date of any such Termination Notice, this Agreement shall remain in full force and effect for a transition period of twelve (12) months from the end of the month when such Termination Notice is given (the "Transition Period"). If a Termination Notice is given during the Initial Term and MPC does not exercise its buyout option pursuant to Article 3 herein, then the Transition Period shall run through October 31, 2000. On the conclusion of the Transition Period, this Agreement shall terminate and be of no further force or effect. UPSTREAM ENERGY SERVICES MPC-UES Marketing Services [LOGO] Page 2 of 7 - ------------------------------------------------------------------------------- 2. DEDICATION 2.1 MPC dedicates to this Agreement one hundred percent (100%) of the natural gas production operated by MPC, less and excepting gas taken in-kind by other interest owners, as identified and described on Exhibit "A" attached hereto. 3. AGENT'S COMPENSATION 3.1 UES shall be paid a volumetrically tiered agency fee as measured at the pipeline sales flowmeters where MPC delivers gas to a third party pipeline (the "Agency Fee"). The Agency Fee shall be netted-out from the revenues of natural gas sales proceeds. The agency fees hereunder shall be calculated as follows:
Volumetric Tier (MMBtu/day) Agency Fee - --------------------------- ------------ 1. First 20,000 $0.03 /MMBtu 2. 20,001 to 40,000 $0.02 /MMBtu 3. all volumes over 40,000 $0.01 /MMBtu
3.2 In the event UES operates and manages a natural gas processing agreement on behalf of MPC, UES shall charge a monthly flat fee of $1,500 for each such processing agreement utilized to generate revenues from the sale of Natural Gas Liquids Products, either directly or through a third party. No fee shall be charged by UES in the months where gas is not processed under such processing agreements. 3.3 UES shall charge MPC an agency fee of one half cent (1/2 CENTS) per gas equivalent MMBtu for all futures contracts, options contracts, or structured derivative instruments traded on behalf of MPC on any commodities exchange or over-the-counter (OTC) market. 4. PREMATURE TERMINATION 4.1 During the Initial Term, MPC may elect to terminate this agreement and forego the Transition Period upon sixty (60) days written notice. By exercising this right, MPC will then be liable to pay UES a premature termination buy-out fee ("PTBO Fee"). When such premature termination notice has been made, premature termination of this agreement shall become effective on the last day of the month of the sixtieth (60th) day following the notice of premature termination. At such time, the PTBO Fee will be due in full. 4.2 The PTBO Fee to be paid by MPC shall be the product of the following calculation: PTBO FEE = REMAINING EFFECTIVE TERM x EXPECTED DAILY PRODUCTION x $0.015 Where: "REMAINING EFFECTIVE TERM" is equal to the minimum number of days from the effective date of premature termination, including the Transition Period, in which UES would continue to market production on behalf of MPC under this Agreement were the premature termination notice not served by MPC. UPSTREAM ENERGY SERVICES MPC-UES Marketing Services [LOGO] Page 3 of 7 - ------------------------------------------------------------------------------- "EXPECTED DAILY PRODUCTION" is equal to the daily average of MPC's operated production for the sixty (60) day period immediately following the issuance of the premature termination notice by MPC. "$0.015 " is equal to one and one-half cents per MMBtu. 5. SPOT MARKETING 5.1 Until and unless otherwise instructed, UES shall market MPC's natural gas production which is not committed under long-term sales contracts on a month-to-month spot basis with the objective of selling only to creditworthy customers and maximizing the net price received by MPC from such creditworthy customers. Upon instructions from MPC, UES agrees to market such spot volumes on a daily basis. 6. CONTRACTS 6.1 UES shall not enter into any gas sale, risk management, transportation or processing contract, on behalf of or for the benefit of MPC, with a term greater than thirty (30) days without MPC's express written consent. For any such contract with a term greater than 30 days, every effort will be made to have MPC the counterparty with UES named as MPC's agent in the contract. 7. THIRD PARTY SERVICE AGREEMENTS 7.1 Where requested by MPC, UES shall enter into sales, and transportation agreements on behalf of and for the benefit of MPC. Whereas in some cases UES may utilize such agreements for the benefit of other agency clients, the costs and burdens associated with such use shall always and in every way be proportionately assigned to the clients by UES and MPC shall never bear an disproportionate burden by virtue of shared utilization of any such agreement with another party. 7.2 Notwithstanding the terms of Article 4 herein, in the event MPC consents to and requests that UES enter into a third party service agreement on behalf of or for the benefit of MPC which term survives the Term of this Agreement, such third party service agreement shall extend this Agreement to the term and volume necessary to fulfill any and all commitments undertaken by UES therein. 8. NOMINATIONS 8.1 All pipeline volume and sales nominations shall be UES's responsibility. All pipeline or storage imbalances shall be monitored and managed by UES on behalf of MPC with the intent to keep imbalances near zero by balancing volumes each month. 8.2 MPC hereby grants UES all reasonable and available analytical support information in the preparation of the nomination(s). MPC authorizes UES to use and rely on such information support and agrees that the ultimate responsibility for the nominations and the ultimate effect that such nominations may have on gas balancing or gas prices shall in all ways reside with MPC. UPSTREAM ENERGY SERVICES MPC-UES Marketing Services [LOGO] Page 4 of 7 - ------------------------------------------------------------------------------- 9. REPORTING 9.1 In the first week of each month under this Agreement, UES shall report to MPC regarding expected gas sales prices, transportation and marketing costs and netbacks in the current production month. 9.2 UES shall deliver projections to MPC regarding expected processing yields for all gas processing agreements managed by UES on behalf of MPC. Such reports shall provide a recommended course of action by UES and shall be delivered to MPC's designated representative at least twenty four (24) hours prior to any processing elections falling due to third party processing companies. 9.3 UES shall provide timely reports to MPC regarding all details incidental to the marketing of MPC's production. 10. ROYALTIES AND TAXES 10.1 Except in the cases where UES markets royalty owners or other working interest owners natural gas, UES shall not be responsible to pay, report or handle any share of royalty payments, gross production, severance or other taxes attributable to production from the lands described on Exhibit A hereto. 11. INVOICING, ESCROW AGREEMENT AND PAYMENT 11.1 UES shall, on or before the fifteenth (15th) day of every month following a production month hereunder, invoice all customers for gas sales made hereunder on behalf of MPC. UES shall use its commercially reasonable best efforts to cause all funds be paid by the customers no later than the 25th day of the month into an escrow account similar in form to the one attached hereto as Exhibit B. ("the Escrow"). 11.2 MPC and UES shall provide joint and uniform instructions to the Escrow Agent directing the prompt distribution of funds according to the instructions contained therein. All disbursements of funds from the Escrow shall be made in conformance with the procedures detailed in the Escrow. UPSTREAM ENERGY SERVICES MPC-UES Marketing Services [LOGO] Page 5 of 7 - ------------------------------------------------------------------------------- 12. NOTICES 12.1 All notices, invoices, statements, payments and other communications made pursuant to this Agreement ("Notices") shall be made to the addresses following or to other such addresses as specified in writing by the respective parties from time to time. UES AS AGENT: MPC NOTICES Upstream Energy Services Co. Michael Petroleum Corp. 13101 Northwest Freeway 13101 Northwest Freeway Suite 325 Suite 320 Houston, TX 77040 Houston, TX 77040 Attention: Contract Admin. Attention: Mr. Michael Farmar MPC for Payments, Invoices, Statements: Same as above, except: Attn: Scott Sampsell 12.2 Notice shall be given when received by the addressee on a business day, meaning any day except Saturday, Sunday or Federal Reserve Bank holidays. 12.3 All Notices required hereunder may be sent by facsimile or mutually acceptable electronic means, a nationally recognized overnight courier service, first class mail or hand delivered. 13. MANAGEMENT OF UES 13.1 Should Mr. Petrick be away from UES for a period of ninety (90) consecutive days or longer, then MPC shall have the right at any time thereafter to deliver a Termination Notice. Notwithstanding the provisions of Articles 1&3, a Termination Notice given under this Article 12 shall cause this Agreement to terminate and be of no further force or effect ninety (90) days after such notice is given. 14. ARBITRATION 14.1 All controversies and claims arising out of or relating to this agreement, or the breach thereof, shall be settled by arbitration in accordance with the commercial arbitration rules ("AAA Rules") of the American Arbitration Association, excepting where the AAA Rules conflict with specific provisions of this agreement, in which case this agreement shall control. Judgment on any award rendered by the arbitrator(s) may be entered in any court having jurisdiction thereof. The arbitration hearing shall be held at the office of the American Arbitration Association in Houston, Texas. Any demand for arbitration must UPSTREAM ENERGY SERVICES MPC-UES Marketing Services [LOGO] Page 6 of 7 - ------------------------------------------------------------------------------- be filed within two years after the date of which dispute arises or the alleged breach occurs. 15. YEAR 2000 COMPLIANCE 15.1 Both Parties are in the process of ensuring that all of their critical systems will be able to correctly process date information before, during and after midnight, December 31, 1999. MPC and UES are each in the process of ensuring that all of their critical suppliers are also compliant, both in regards to their products and services and also in their internal business processes. Each Party agrees to promptly provide the other with information requested regarding Year 2000 Compliance. 16. MISCELLANEOUS 16.1 This contract shall be governed by and interpreted in accordance with the laws of the State of Texas and all financial transactions referenced herein shall be made in US currency. 16.2 Each party shall have the right, at its own cost and expense, to examine the records of the other party to the extent necessary to verify the accuracy of any statement or payment made hereunder. Any error discovered in any payment made shall be promptly corrected, except for errors discovered more than two years subsequent to the statement or payment in question. 16.3 Each Party reserves to itself all rights, set-offs, counterclaims, and other defenses which it is or may be entitled to arising from this Agreement. 16.4 MPC warrants that it has title to gas UES sells hereunder and agrees herein that MPC shall at all times be deemed to be in exclusive control and possession thereof and responsible for any damage, claim, liability or injury caused thereby. 16.5 This contract may not be assigned, in whole or in part, by either party, except to an entity controlled by or under common control with the assigning party without the express written consent of the other party, which shall not be unreasonably withheld. 16.6 This Agreement shall be binding upon MPC and UES and their subsidiaries and their respective executors, administrators, trustees, successors and assigns. 16.7 The headings used for the Sections herein are for convenience and reference purposes only and shall in no way affect the meaning or interpretation of the provisions of the Agreement. 16.8 Both Parties hereto acknowledge that each Party was actively involved in the negotiation and drafting of this Agreement and that no law or rule of construction shall be raised or used in which the provisions of this Agreement shall be construed in favor or against either Party hereto because one is deemed to be the author thereof. UPSTREAM ENERGY SERVICES MPC-UES Marketing Services [LOGO] Page 7 of 7 - ------------------------------------------------------------------------------- This Agreement evidences the full and complete agreement between the Parties and supersedes any prior agreements, whether written or oral, and may not be modified or amended unless evidenced in writing by both Parties hereto. Accepted and agreed to on this Accepted and agreed to on this _____ day of November, 1998. _____ day of November, 1998. LOS MIGUELITOS, L.L.P. D/B/A MICHAEL PETROLEUM CORPORATION UPSTREAM ENERGY SERVICES - ---------------------------------- ----------------------------------- Brad L. Petrick, Michael Farmar, President President WITNESS: WITNESS: -------------------------- ------------------------------ EXHIBIT "A" DESCRIPTION OF PRODUCING LANDS Pursuant to the Natural Gas Marketing, Transportation and Processing Agency Agreement dated November ___, 1998 by and between Los Miguelitos, Inc. a Texas Limited Liability Company, d/b/a Upstream Energy Services Company ("UES"), as agent, and Michael Petroleum Corporation ("MPC"), as client, the parties hereby confirm that the gas production to be marketed by UES under the terms of said agreement shall be defined as natural gas and entrained hydrocarbons, not taken-in-kind by other interest owners, produced from gas wells operated by MPC and its subsidiaries and their respective executors, administrators, trustees, successors and assigns. Accepted and agreed to on this Accepted and agreed to on this _____ day of November, 1998. _____ day of November, 1998. LOS MIGUELITOS, L.L.P. D/B/A MICHAEL PETROLEUM CORPORATION UPSTREAM ENERGY SERVICES - ---------------------------------- -------------------------------------- Brad L. Petrick, Michael Farmar, President President WITNESS: WITNESS: -------------------------- ------------------------------ EX-10.16 4 EXHIBIT 10.16 FIRST AMENDMENT TO CREDIT AGREEMENT (March 29, 1999) THIS FIRST AMENDMENT TO CREDIT AGREEMENT (the "AMENDMENT") is made and entered into as of March 29, 1999, among MICHAEL PETROLEUM CORPORATION, a Texas corporation (the "BORROWER"), the entities listed on the signature pages hereof as Lenders (collectively, the "Lenders"), and CHRISTIANIA BANK OG KREDITKASSE ASA ("CHRISTIANIA") as administrative agent (in such capacity, the "Agent"). W I T N E S S E T H WHEREAS, the Borrower, the Agent and the Lenders entered into that certain Credit Agreement dated as of May 15, 1999 (the "CREDIT AGREEMENT"); and WHEREAS, the Borrower, the Agent and the Lenders wish to amend the Credit Agreement and provider for certain other matters as set forth herein; NOW, THEREFORE, for and in consideration of the mutual promises, the mutual agreements contained herein and for other good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto do hereby agree as follows: 1. DEFINITIONS. (a) Capitalized terms used and not defined in this Amendment shall have the meanings specified in the Credit Agreement. (b) The definitions of "ABR" and "EURODOLLAR RATE" in Article I of the Credit Agreement are hereby deleted in their entirety and replaced by the following definitions of such terms: ABR means the highest of (i) the rate of interest publicly announced by Agent as its prime rate in effect at its principal office in New York City (the "Prime Rate") plus 0.5%, (ii) the secondary market rate for three-month certificates of deposit (adjusted for statutory reserve requirements) PLUS 1.5% and (iii) the Federal Funds Rate PLUS 1.0%. EURODOLLAR RATE means the rate (adjusted for statutory reserve requirements for eurocurrency liabilities) at which eurodollar deposits for one, two, three, or six (or, if available and acceptable to Required Lenders, nine or twelve) months (as selected by Borrower) are offered to Agent in the Interbank eurodollar market, PLUS 2.25%. 2. WAIVER REGARDING LATE PRODUCTION REPORT. The Agent and the Lenders acknowledge that they have received the Production Report required under the terms of SECTION 5.1 of the Credit Agreement to be delivered no later than 45 days after (the "REQUIRED DELIVERY DATE") the last day of the calendar quarter commencing October 1, 1998 and hereby waive any Potential Default or Default arising from the delivery of such Production Report after the Required Delivery Date. 3. ACKNOWLEDGMENT AND WAIVER REGARDING NON-COMPLIANCE WITH SECTION 7.17. The Agent and the Lenders acknowledge that they received timely (within the requirements of SECTION 5.4 of the Credit Agreement) notice of the failure by Borrower to comply with the Minimum Interest Coverage Ratio covenant set forth in SECTION 7.17 of the Credit Agreement as of the last day of the fiscal quarter ended December 31, 1998 and the Lenders hereby waive the Default arising from such failure. 4. AMENDMENT TO SECTION 7.17. SECTION 7.17 of the Credit Agreement is deleted in its entirety and replaced by the following SECTION 7.17: "Section 7.17 MINIMUM INTEREST COVERAGE RATIO. Borrower shall not permit the Interest Coverage Ratio to be less than 1.3 to 1.0 as of the last day of the fiscal quarters ending March 31 and June 30, 1999, 1.4 to 1.0 as of the last day of the fiscal quarter ending September 30, 1999; 1.5 to 1.0 for the fiscal quarter ending December 31, 1999; or 2.0 to 1.0 as of the last day of any fiscal quarter ending after December 31, 1999." 5. CONDITIONS TO EFFECTIVENESS OF AMENDMENT. The obligations of the Lenders herein and the effectiveness of the other provisions of this Amendment shall be subject to the fulfillment of the following conditions precedent in a manner satisfactory to the Agent: (a) The Agent shall have received all the following (each of the following documents in form and substance satisfactory to the Agent): (i) A copy of the resolutions of the Board of Directors of the Borrower, dated on the date hereof, certified by the Secretary of Assistant Secretary of the Borrower, authorizing the execution, delivery and performance by the Borrower of this Amendment and any other document to be delivered by the Borrower pursuant hereto; (ii) A certificate of the Secretary or an Assistant Secretary of the Borrower, dated on the date hereof, as to the incumbency and signature of the officers of the Borrower authorized to sign this Amendment and any other document to be delivered by the Borrower pursuant hereto, together with evidence of the incumbency of such Secretary or Assistant Secretary; -2- (iii) All consents, approvals, waivers, authorizations and orders of any courts or governmental authorities (including, without limitation, federal and state banking authorities) or third parties required in connection with the execution, delivery and performance by the Borrower of this Amendment and each document to be delivered by Borrower pursuant hereto and the performance of the transaction contemplated hereby; and (iv) All other documents the Agent may reasonably request with respect to any matter relevant to this Amendment and the transactions contemplated hereby; (b) The representations and warranties contained in the Credit Agreement, as amended hereby, shall be true and correct in all material respects on and as of the date hereof and on and as of the date of actual execution and delivery hereof by the Borrower; and (c) All corporate and legal proceedings and all documents required to be completed and executed by the provisions of, and all instruments to be executed in connection with the transactions contemplated by, this Amendment and any related agreements shall be satisfactory in form and substance to the Agent, and the Agent shall have received all information and copies of all documents, including records of corporate proceedings, required by this Amendment and any related agreements to be executed or which the Agent may reasonably have requested in connection therewith, such documents, where appropriate, to be certified by proper corporate or governmental authorities. 6. DEFAULTS AND POTENTIAL DEFAULTS. The Borrower represents and warrants that after giving effect to this Amendment no Default or Potential Default exists under the Credit Agreement. 7. EXPENSES. The Borrower shall pay all out-of-pocket expenses of the Agent arising in connection with the Loans and the preparation, execution delivery and administration of this Amendment, including, but not limited to, all reasonable legal fees and expenses incurred by the Agent. 8. CONTINUED EFFECT. Except to the extent expressly provided herein, all terms, provisions and conditions of the Credit Agreement shall continue in full force and effect and the Credit Agreement shall remain enforceable and binding in accordance with its terms. The Borrower further ratifies, affirms, renews and extends the liens and security interests in the Collateral granted pursuant to the Security Documents. 9. CHOICE OF LAW. This Amendment shall be governed by and construed in accordance with the laws of the State of New York. -3- 10. COUNTERPARTS. This Amendment may be executed in any number of counterparts, all of which when taken together shall constitute one and the same document, and each party hereto may execute this Amendment by signing any of such counterparts. 11. SUCCESSORS. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns; provided, however, that the Borrower shall not assign any of its rights hereunder without the prior written consent of the Lenders. 12. ENTIRE AGREEMENT. THE LOAN DOCUMENTS, INCLUDING THIS AMENDMENT, REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers, to be effective as of the date first above written. MICHAEL PETROLEUM CORPORATION By: /s/ROBERT L. SWANSON ------------------------------------ Name: ---------------------------------- Title: VICE PRESIDENT - FINANCE --------------------------------- CHRISTIANIA BANK OG KREDITKASSE, ASA, as the Agent and sole Lender By: /S/WILLIAM S. PHILLIPS ------------------------------------ Name: ---------------------------------- Title: FIRST VICE PRESIDENT --------------------------------- -4- EX-10.17 5 EXHIBIT 10.17 March 30, 1999 Mr. Robert L. Swanson Vice President - Finance 13101 Northwest Freeway, Suite 320 Houston, Texas 77040 Re: Credit Agreement dated May 15, 1998 by and between Michael Petroleum Corporation ("Borrower") and Christiania Bank og Kreditkasse ASA, as Administrative Agent (the "Christiania" or "Agent") Dear Robert: As you know, we are in the process of redetermining the Borrowing Base under the captioned Agreement pursuant to Article 2.11. Based on this review, Christiania has determined the Borrowing Base, as of April 1, 1999 to be $23,000,000. Furthermore, the Borrowing Base shall be subject to the following terms and conditions: Borrowing Base: During the period commencing April 1, 1999 until the Borrowing Base is redetermined in accordance with Article 2.11 (a) of the captioned Agreement, the amount of the Borrowing Base shall be $23,000,000. The Borrowing Base shall be reduced on the last day of each month by an amount equal to $1,500,000, (the "BB Reduction Amount"), commencing October 31, 1999, and thereafter until the outstanding loan amount is repaid in full. The Agent preserves its right under the captioned Agreement to perform additional redeterminations of the Borrowing Base and the BB Reduction amount (an "Unscheduled Redetermination") at their sole discretion as provided for under Article 2.11 (d) of the captioned Agreement. Notwithstanding the above, Christiania will redetermine the Borrowing Base at the next mid-year review. Use of Proceeds: Borrower is permitted to use proceeds from the Credit Facility to fund the April 1, 1999 interest payment due under its $135,000,000 Senior Notes (the "Notes"). Thereafter, Borrower is prohibited from using funds from the credit facility to fund interest and principal payment under the Notes. Interest Margin: As documented in the First Amendment to Credit Agreement, the interest rate margin shall increase by 50 bps effective April 1, 1999 for Prime Rate and Eurodollar Rate draws. Security: Borrower agrees to work with Agent to insure first lien coverage on at least 90% of Borrower's oil and gas reserve PV10 value (PV10 value as of the Huddleston & Co. reserve report dated March 31, 1999). Debt Service Reserve: Borrower agrees to set aside on a monthly basis, beginning May 1, 1999, funds from internal cash flow to insure payment of the interest payment on the Notes due October 1, 1999. If requested by Agent, Borrower agrees to set aside these funds in an account designated by Agent. Borrower agrees to provide Agent a monthly accounting of funds on deposit in the Debt Service Reserve Account.
Please acknowledge your agreement with the terms and conditions of the Borrowing Base by signing in the appropriate place below: MICHAEL PETROLEUM CORPORATION As the Borrower By: /S/ROBERT L. SWANSON ------------------------------------ Name: ---------------------------------- Title: VICE PRESIDENT --------------------------------- CHRISTIANIA BANK OG KREDITKASSE, ASA AS THE Agent and sole Lender By: /S/WILLIAM S. PHILLIPS ------------------------------------ Name: ---------------------------------- Title: FIRST VICE PRESIDENT --------------------------------- By: /S/PETER DODGE ------------------------------------ Name: ---------------------------------- Title: SENIOR VICE PRESIDENT --------------------------------- EX-27.1 6 EXHIBIT 27.1
5 1,000 YEAR DEC-31-1998 JAN-01-1998 DEC-31-1998 430 0 7,866 0 0 8,951 155,867 (24,989) 147,282 13,596 144,842 0 0 1 (11,157) 147,282 0 22,718 0 24,049 0 0 12,281 (13,377) (4,667) (8,710) 0 (531) 0 (9,241) 0 0
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