ITEM 1. BUSINESS
BACKGROUND AND RECENT DEVELOPMENTS
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 expanded its production and reserve base in recent years through development drilling and exploitation activities and by acquiring producing and undeveloped properties. 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.
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. The Company uses 3-D seismic imaging and other advanced technologies in the development and exploitation of its properties.
ACQUISITIONS AND SUBSTANTIAL INDEBTEDNESS
During 1998, the Company implemented a growth strategy aimed at accomplishing strategic and complementary acquisitions that would expand its inventory of producing and undeveloped properties. To facilitate this strategy, in April 1998, the Company completed a $135 million debt offering of its 11 1/2% Series A Notes due 2005. By September 1998, all of the $135 million original principal amount of the Series A Notes had been exchanged for its 11 1/2% Series B Notes due 2005, the terms of which are substantially identical to the terms of the Series A Notes. The Series A and Series B Notes are sometimes referred to in this report as "Senior Notes."
The Company completed various acquisitions during 1998, each of which is described below. The Company financed these acquisitions primarily through proceeds from the issuance of the Senior Notes, applying approximately $90 million in net proceeds from the sale of its Senior Notes in connection with the closing of these acquisitions.
The issuance of the Senior Notes substantially increased the Company's level of indebtedness over historical levels. This increased level of indebtedness had several important effects on the Company's operations, including the following: (i) a substantial portion of the Company's cash flow from operations was dedicated to the payment of interest on its debt, thereby reducing funds available to it for other purposes; (ii) the Company's leveraged position substantially increased its vulnerability to adverse changes in general economic and industry conditions; and (iii) the Company's ability to obtain additional financing for working capital, capital expenditures and general corporate and other purposes became constrained. As a result of changes in industry conditions coupled with these factors, the Company's earnings and cash flows became insufficient to meet all of its fixed charges.
RECENT DEVELOPMENTS
During 1998 and 1999, the Company's results of operations and financial condition deteriorated significantly. This deterioration was a result of a combination of factors, including low oil and natural
gas prices during the second half of 1998 and the first four months of 1999, failure to successfully realize anticipated benefits from acquired properties and the significant debt burden incurred by the Company in 1998 to finance its acquisition strategy.
INDUSTRY CONDITIONS. Declines in oil and natural gas prices adversely affected the Company's financial condition, liquidity and results of operations in 1998 and 1999. Although oil and natural gas prices recovered during 1999, the effect of the price declines coupled with the Company's inability to service its outstanding indebtedness and the lack of alternate sources of capital on terms acceptable to management caused the Company to not achieve the levels of revenues and cash flows necessary in order to meet its substantial debt obligations.
EXECUTION OF VOTING AGREEMENT AND FILING OF PETITIONS IN BANKRUPTCY. Beginning in the second quarter of 1999, representatives of the Company and its financial advisor engaged during 1999, began meeting with certain holders of the Senior Notes to seek financial restructuring alternatives. An interest payment on the Senior Notes of approximately $7.8 million was due on October 1, 1999, but was not paid by the Company. A 30-day grace period under the Indenture governing the Senior Notes expired on October 31, 1999 without payment of interest on the Senior Notes, and, as a result, an event of default occurred under the Indenture. The Indenture provides that in the event of an event of default, the entire indebtedness under the Senior Notes may be declared due and payable.
During 1999, the Company experienced a number of covenant defaults under its secured credit facility (the "Credit Facility") with Christiania Bank og KreditKasse ("Christiania"). The Company was able to obtain a number of waivers to certain of these defaults during 1999, but under an amendment to the Credit Facility entered into in early 1999, the Company was to begin making $1.5 million monthly principal payments under the Credit Facility on October 31, 1999. The Company did not make the $1.5 million principal payment due October 31, 1999, which constituted an event of default under the Credit Facility.
Under the cross default provisions contained in the Indenture governing the Senior Notes and in the Credit Facility with Christiania, a default under either the Senior Notes or the Credit Facility constituted a default under the other instrument.
Effective December 10, 1999, the Company, its parent corporation, Michael Holdings, Inc. ("MHI"), and certain of its subsidiaries entered into an agreement (the "Voting Agreement") with certain holders of the Company's Senior Notes, which provided for (i) the filing of a Chapter 11 bankruptcy case by the Company, MHI and certain subsidiaries, (ii) a marketing process with respect to the Company and its assets under the Voting Agreement and (iii) the filing of a consensual joint plan of reorganization of the Company (the "Plan"). The Voting Agreement was signed by Holders of more than $90,000,000, or two-thirds, of the outstanding principal amount of the Senior Notes (the "Consenting Holders"). In accordance with the Voting Agreement, on December 10, 1999, the Company, MHI and certain of its subsidiaries filed petitions for relief under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas, Laredo Division (the "Bankruptcy Court"). As described below, the Voting Agreement generally obligated the Consenting Holders to vote in favor of the Plan so long as the Plan contained terms consistent with a term sheet attached to the Voting Agreement.
The bankruptcy petitions were filed in order to give the Company an opportunity to conserve its cash and restructure its debt. Since December 10, 1999, the Company, MHI and the filing subsidiaries have operated as debtors-in-possession under the Bankruptcy Code. The Company has curtailed its developmental drilling program, limiting expenditures to a one-rig drilling program. No trustee or
examiner has been appointed and the Company, MHI and these subsidiaries are paying their postpetition obligations (except those subject to Bankruptcy Court approval) as they become due.
On January 11, 2000, the Bankruptcy Court entered an agreed final order authorizing use of cash collateral, with the agreement of Christiania. Under the order, the Company must comply with certain financial covenants and pay interest weekly to Christiania. On April 5, 2000, the Court entered its Second Final Agreed Order Authorizing use of Cash Collateral and Granting Adequate Protection. This Order was entered with the agreement of Christiania, who consented to the Company's continued use of Christiania's cash collateral in accordance with the terms and conditions set forth in the Order until May 1, 2000, unless extended by the parties or further order of the Court after notice and a hearing. Among other things, the Order provides Christiania new, first priority and senior security interests in the Company's assets and requires the Company to make weekly adequate protection payments to Christiania during the term of the Order. The Order also imposes certain reporting requirements and cash collateral operating requirements on the Company.
THE VOTING AGREEMENT. The terms of the Voting Agreement contemplated that the Plan would provide for a sale of the Company or its assets in court-supervised proceedings under the Bankruptcy Code. Under the Voting Agreement, the Consenting Holders agreed to vote in favor of the Plan so long as the Plan was consistent in all material respects with the term sheet for the Plan attached to the Voting Agreement. The term sheet set forth, among other things, a process for the marketing and sale of the Company or its assets for a "Net Consideration" (as defined in the term sheet) of at least $120 million, as adjusted for certain costs and working capital items, the proceeds of which shall be applied first to the repayment of the Company's bank debt under the Credit Facility (approximately $24.3 million principal amount outstanding at December 31, 1999). The Voting Agreement provided that, so long as no "Termination Event" occurred, the Consenting Holders would:
1. vote to accept the Plan;
2. neither commence nor assist or encourage any other person to commence any other legal or enforcement actions concerning the Company's debts;
3. not take any position in the bankruptcy proceedings that conflicts with their obligation to support the Plan; and
4. vote their Senior Note claims to reject any bankruptcy plan for the Company other than the Plan.
The Voting Agreement contemplated that the Company and its subsidiaries would continue to operate as debtors-in-possession subject to the supervision of the Bankruptcy Court, and that the Plan would provide for the payment of all trade creditors' claims as and when they come due in the ordinary course or in full on the effective date of the Plan.
The Voting Agreement provided that the obligations of the Consenting Holders may terminate upon a "Termination Event," which included any failure under the marketing process to timely achieve certain milestones, including the receipt of at least one final bid to purchase the Company or its assets by March 17, 2000 in an amount equal to at least $120 million, subject to adjustment for certain costs and working capital items. As of March 17, 2000, the Company had not received a final bid in such an amount sufficient to meet this requirement. The Company and its advisors have continued to negotiate with the holders of the Senior Notes and with prospective purchasers for a consensual Plan. The
Company expects to file the Plan and related disclosure statement with the Bankruptcy Court in April 2000.
On April 3, 2000, the Bankruptcy Court entered an agreed order extending the period during which the Company would have exclusivity to file its Plan and disclosure statement to April 17, 2000.
At this time, it is not possible to predict the outcome of the bankruptcy proceedings, or the effect on the Company's business or on the interests of its creditors, royalty owners or stockholders, or whether certain executory contracts will be assumed or rejected. As a result of the bankruptcy filing, certain of the Company's liabilities are subject to compromise.
1998 ACQUISITIONS
The Company significantly expanded its asset base and operations during 1998 through acquisitions and investments.
ENRON ACQUISITION
In March 1998, the Company closed its acquisition of Lobo Trend properties with Enron Oil and Gas Company ("Enron"). Under 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 Senior Notes. In addition, the Company granted to Enron a non-exclusive license to use the seismic data it conveyed to the Company.
CONOCO ACQUISITION
The Company completed its acquisition of properties from Conoco Inc. ("Conoco") 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 Senior Notes to pay the purchase price of the Conoco Acquisition.
LOBO LEASE TRANSACTION
By agreement dated April 20, 1998, the Company acquired from a subsidiary of Mobil Corporation ("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 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 (bearing interest at 12% per annum) to 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 note became past due on December 15, 1999 and this receivable has been fully reserved by the Company.
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 adversely affected the Company's financial condition, liquidity and results of operations in 1998 and 1999.
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.
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 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:
The Sales Agreement is effective for a one-year period and is renewable automatically for successive one-year periods thereafter. 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 an acquisition by the Company of Lobo Trend properties made in 1996, Conoco (as the successor in interest to the seller) and the Company entered into a Gas Exchange Agreement whereby the parties agreed that the Company would deliver to Conoco all of the natural gas produced from the leases acquired in that acquisition at the point(s) at which the 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 ranges from $0.11 to $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 Inc., EOG Resources Inc. and numerous independent oil and natural gas companies. 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 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 and the pending bankruptcy proceedings. 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 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 any future acquisitions in this area. There can be no assurance that financing will be available, or if so, on terms that are acceptable to the Company. Failure to secure such financing or to locate industry partners will 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 Conditions." The Company's current financial condition and the fact it is subject to Bankruptcy Court jurisdiction is a negative competitive condition presently affecting the Company.
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. Since 1985, 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.
The FERC has also announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000 concerning alternatives to its traditional cost-of-service ratemaking methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC's pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.
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 public health and the environment affect the Company's oil and natural gas operations and costs. 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 investigation, rendering a person or entity liable for environmental investigation cleanup costs and for national resource damages 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 for the release of a "hazardous substance" into the environment. These persons include the current or former owner or operator of any site where a release historically 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. It should be noted that CERCLA excludes petroleum from the definition of hazardous substance. 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.
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 Clean Water Act ("CWA") imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. 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 CWA 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. The Oil Pollution Act ("OPA") amends and augments oil spill
provisions of the CWA. 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 CWA 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
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 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, 1999, the Company employed 28 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.
On March 27, 2000, the Bankruptcy Court approved an Employee Retention Bonus Plan. Under the terms of the Employee Retention Bonus Plan, eligible employees are entitled to a bonus equal to three months salary if the employee remains employed with the Company through the effective date of the plan of reorganization. The estimated cost of the Employee Retention Bonus Plan is approximately $400,000.
ITEM 2.
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, 1999. 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 primarily geologic target in the Lobo Trend is the Lobo sand series of the Lower Wilcox formation, which contained multiple pay sands. The primary objectives in the Lobo Trend are the Lobo l 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. The introduction of 3-D seismic to the area in the early 1990's 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, 1997, 1998 and 1999. The reserve data and present values presented have been estimated by Netherland Sewell & Assoc., Inc. for the year ended December 31, 1999 and Huddleston & Co., Inc. for the years ended December 31, 1998 and 1997. 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."
(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 Securities and Exchange Commission (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, 1999 were $23.80 per Bbl of oil and $2.33 per Mcf of natural gas, compared to $9.17 per Bbl of oil and $1.85 per Mcf of natural gas as of December 31, 1998, and $15.91 per Bbl of oil and $2.42 per Mcf of natural gas as of December 31, 1997.
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, 1997, 1998, and 1999.
(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, 1999:
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, 1999.
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, 1997, 1998 and 1999.
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, 2000 to March 31, 2000, the Company participated in drilling activities on a total of 3 gross (2 net) wells, 2 gross (2 net) of which have been completed as productive wells, with one well still in progress.
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 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 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 includable 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.
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.
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.
WORKOVER. Operations on a producing well to restore or increase production.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On December 10, 1999, the Company, MHI, and certain of its subsidiaries filed petitions for relief under Chapter 11 of the Bankruptcy Code in order to facilitate the restructuring of the Company's liabilities. The Company continues to operate as a debtor-in-possession subject to the Bankruptcy Court's supervision and orders. The filing was made in the U.S. Bankruptcy Court for the Southern District of Texas, Laredo Division. See Item 1. - - "Business - Background and Recent Developments."
On March 27, 2000, the Company received a demand letter from a royalty owner. The demand letter challenges certain deductions used by the Company to calculate prices for oil and gas royalties. The Company believes that it has substantial defenses to this claim and intends to vigoriously assert such defenses. However, the investigation into this claim is in the early phases and the potential range of loss, if any, cannot presently be determined.
On March 31, 2000, the Company received correspondence from counsel to the Official Committee of Unsecured Creditors requesting the Company to take legal action on behalf of the Company's Estate against Glenn D. Hart, Michael G. Farmar and the directors of Company, alleging certain misstatements in connection with the issuance of the Senior Notes and certain breaches of fiduciary duties to the creditors. The Company is currently evaluating the claims made under these allegations, but currently knows of no basis for their assertion.
In addition to the matters noted above, 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, 1999, there were no threatened or pending legal matters, other than the matters noted above, which would have a material impact on the Company's consolidated financial position, results of operations or cash flows.
ITEM 4.
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 1999.
ITEM 5.
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 31, 2000, substantially all of the common stock of MHI was 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, 1998 and 1999. 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 Senior Notes and the Credit Facility restrict the Company's ability to declare and pay cash dividends.
ITEM 6.
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, 1999. The financial data for each of the years ended, and as of, December 31, 1995, 1996, 1997, 1998 and 1999 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.
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. The financial data set forth below is derived from the historical financial statements of the Company, and based on the uncertainties associated with the Company's ongoing reorganization proceedings, may not be considered as indicative of the Company's future performance. (See Item 1. - "Business - Background and Recent Developments."
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, 1999. 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
Effective December 10, 1999, the Company, MHI and certain of its subsidiaries entered into the Voting Agreement with certain holders of the Company's Senior Notes for a consensual joint plan of reorganization of the Company. The terms of the Voting Agreement contemplated that the Plan will provide for a sale of the Company or its assets in court-supervised proceedings under the Bankruptcy Code. On December 10, 1999, the Company, MHI and certain of its subsidiaries filed petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Company expects to file the Plan and related disclosure statement with the Bankruptcy Court in April 2000. In addition to the approval of the Bankruptcy Court, the consummation of the plan of reorganization will be subject to the consent of the requisite number and amount of certain of the Company's creditors. The Voting Agreement contemplated that the Company and its subsidiaries will continue to operate as debtors-in-possession subject to the supervision of the Bankruptcy Court, and that the Plan will provide for the payment of all trade creditors' claims as and when they come due in the ordinary course or in full on the effective date of the Plan. There can be no assurance that the Bankruptcy Court will approve the Plan.
The Voting Agreement provided that the obligations of the parties thereto may terminate upon a "Termination Event," which includes any failure under the marketing process to timely achieve certain milestones, including the receipt of at least one final bid by March 17, 2000 in an amount equal to at least $120 million, as adjusted for certain costs and working capital items. As of March 17, 2000, the Company had not received a final bid in such an amount sufficient to meet this requirement. The Company and its advisors continue to negotiate with the holders of the Senior Notes and with prospective purchasers for a consensual plan of reorganization.
As of December 10, 1999, the Company discontinued the accrual of interest on unsecured liabilities subject to compromise, which consist primarily of the Senior Notes. As such, approximately $936,000 of interest expense pertaining to the Senior Notes was not recognized for the period from December 10, 1999 through December 31, 1999.
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, 1997, 1998 and 1999:
(1) Includes effects of hedging transactions.
COMPARISON OF YEARS ENDED DECEMBER 31, 1999 AND 1998
Oil and natural gas revenues for the year ended December 31, 1999 increased 51% to $34.2 million from $22.7 million for the year ended December 31, 1998. Production volumes for oil and natural gas for the year ended December 31, 1999 increased 35% to 14,817 MMcfe from 10,984 MMcfe for the year ended 1998. Average oil and natural gas prices (including the effect of hedging transactions) increased 12% to $2.30 per Mcfe for 1999 from $2.06 per Mcfe for 1998. The increase in natural gas production in 1999 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, 1999 increased 32% to $5.4 million from $4.1 million for the year ended December 31, 1998, primarily due to the increase in production. However, actual production costs per equivalent unit remained unchanged at $0.37 per Mcfe for the years ended December 31, 1999 and 1998.
Depletion, depreciation and amortization ("DD&A") expense for the year ended December 31, 1999 increased 43% to $18.0 million from $12.6 million for the same period in 1998. The increase in DD&A expense was due to higher production volumes. The depletion rate per Mcfe increased from $1.14 for 1998 to $1.21 for 1999. The increase in rate was primarily due to cost overruns for certain wells completed in the first quarter of 1999, plus below average reserves per well completed under the Company's 1998 drilling program.
Impairment charges decreased to $3.8 million for the year ended December 31, 1999 compared to $5.4 million for the year ended December 31, 1998. Impairment charges incurred in 1999 and 1998 were primarily due to development dry holes drilled on certain oil and gas leases that resulted in a reduction in the estimated proved reserves. The impairment charge was calculated using discounted cash flows of proved reserves using prices and costs consistent with those used for internal decision making purposes.
General and administrative expense increased 21% to $2.2 million in 1999 from $1.8 million for the same period in 1998 due to the addition of several new employees and their related benefits, plus increases in office expenses and legal and professional fees.
Interest expense and loan amortization costs, net of capitalized interest, for the year ended December 31, 1999 increased 32% to $16.2 million compared to $12.3 million for 1998. The increase was due to the higher levels of outstanding debt and increased interest rates for the Credit Facility during 1999. The increases in the interest rates for the Credit Facility were due to the payment of default interest rates charged during 1999 and was partially offset by the discontinuance of interest on the Senior Notes beginning December 10, 1999 due to the bankruptcy proceedings. As such, approximately $936,000 of interest expense pertaining to the Senior Notes was not recognized for the period from December 10, 1999 through December 31, 1999.
For the year ended December 31, 1999, the Company recorded in interest income and other, an allowance for bad debts totaling $1.5 million pertaining to a note receivable from a Texas limited liability company. The allowance was established as a result of a contract cancellation by a third party with a joint venture partner of the Texas limited liability company.
For the year ended December 31, 1999, the Company had incurred $1.5 million which consisted of approximately $792,000 of restructuring costs (consisting principally of investment banking, legal and professional fees) and approximately $721,000 of bankruptcy reorganization costs (legal and other fees) pertaining to the Company's proposed capital restructuring discussed under "Liquidity and Capital
Resources." These restructuring costs were expensed during the fourth quarter due to the Bankruptcy filing on December 10, 1999. No restructuring or reorganization costs were incurred in the year ended December 31, 1998.
Income tax expense was $1.9 million for the year ended December 31, 1999 as a valuation allowance of $7.2 million was recorded by the Company, compared to an income tax benefit of $4.9 million for the same period in 1998. The valuation allowance recorded by the Company is the principal reconciling item between the expected tax benefit and the recorded tax amount. The Company's net operating loss carryforward was fully reserved as of December 31, 1999 as the status of the current and future drilling program, uncertainty about the availability of capital and the bankruptcy proceedings resulted in uncertainty as to whether sufficient taxable income will be available to utilize the entire net operating loss carryforward. Any restructuring of the Company's indebtedness may result in a significant stock ownership change which would significantly affect the timing of the utilization of the net operating loss carryforward. The valuation allowance related to tax assets could be adjusted in the future due to changes in estimates of future taxable income and the outcome of the Bankruptcy proceedings.
The extraordinary loss of $531,000 (net of the income tax benefit of $285,000) for the year ended December 31, 1998 was due to the early extinguishment of the previous credit facility. No extraordinary items were recognized in the year ended December 31, 1999.
The net loss for the year ended December 31, 1999 was $16.4 million compared to a loss of $9.2 million for the year ended December 31, 1998, primarily as a result of the factors discussed above.
COMPARISON OF YEARS ENDED DECEMBER 31, 1998 AND 1997
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 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. The impairment charge was calculated using discounted cash flows of proved reserves using prices and costs consistent with those used for internal decision making purposes.
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 had 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 as of at least $19.5 million would 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 believed it was more likely than not that the net operating loss would 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 pertained to development dry holes, intangible drilling costs, capitalized interest and depletion and depreciation of oil and gas and other properties. Differences in these items began 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 Company's net operating loss carryforward was fully reserved as of December 31, 1999 as the status of the current and future drilling program, uncertainty about the availability of capital and the bankruptcy proceedings resulted in uncertainty as to whether sufficient taxable income will be available to utilize the entire net operating loss carryforward. Any restructuring of the Company's indebtedness may result in a significant stock ownership change which would significantly affect the timing of the utilization of the net operating loss carryforward. The valuation allowance related to tax assets could be adjusted in the future due to changes in estimates of future taxable income and the outcome of the Bankruptcy proceedings.
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 write-off of the remaining loan costs relating to the Company's previous credit facility, 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.
LIQUIDITY AND CAPITAL RESOURCES
BANKRUPTCY PROCEEDINGS
On December 10, 1999, the Company, MHI and certain of Company's subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in order to facilitate the restructuring of the Company's liabilities. The Company has operated as a debtor-in-possession subject to the Bankruptcy Court's supervision and orders.
The bankruptcy petitions were filed in order to preserve cash and to give the Company the opportunity to restructure its debt. The consummation of a plan of reorganization is the primary objective of the Company. The plan of reorganization will set forth the means for satisfying claims, including liabilities subject to compromise, and interests in the Company. A plan of reorganization may result in, among other things, the sale of the Company's oil and natural gas producing assets. The consummation of a plan of reorganization will require approval of the Bankruptcy Court.
At this time, it is not possible to predict the outcome of the bankruptcy proceedings, in general, or the effect on the business of the Company or on the interests of creditors, royalty owners or stockholders. There can be no assurance that the plan of reorganization to be submitted by the Company will be approved or that the Bankruptcy Court will permit the Company to continue to operate as a debtor-in-possession. As a result, there is substantial doubt about the Company's ability to continue as a going concern. See the Consolidated Financial Statements of the Company included under Item 8 of this report.
In the ordinary course of business, the Company makes substantial capital expenditures for the exploration and development of oil and natural gas reserves. Historically, the Company has financed its capital expenditures, debt service and working capital requirements with cash flow from operations, public offerings of debt, and a senior credit facility. Cash flow from operations is sensitive to the prices the Company receives for its oil and natural gas. Reductions in capital spending or an extended decline in oil and gas prices would result in less than anticipated cash flow from operations which would likely have a further material adverse effect on the Company. Proceeds from oil and natural gas sales are received at approximately the same time that production-related burdens, such as royalties, production taxes and drilling program obligations, are payable.
Presently, the Company is operating pursuant to the cash collateral order authorizing the use of cash collateral and the related budget. To the extent that on-going expenses are for post-petition goods and services after December 10, 1999, are within the ordinary course of business and are reflected on the court-approved budget, the Company is permitted to make such expenditures without further Bankruptcy Court Approval. Any expenditure, however, that is outside the ordinary course of business or that is not reflected on the budget, must be specifically authorized by the Bankruptcy Court.
On January 11, 2000, the Company and its senior secured lender entered into a cash collateral agreement, which contains certain financial covenants and provides for weekly payments of interest by the Company at the rate of prime plus 3.50% per annum (12.5% as of March 31, 2000). On April 5, 2000, the Court entered its Second Final Agreed Order Authorizing use of Cash Collateral and Granting Adequate Protection. This Order was entered with the agreement of Christiania, who consented to the Company's continued use of Christiania's cash collateral in accordance with the terms and conditions set forth in the Order until May 1, 2000, unless extended by the parties or further order of the Court after notice and a hearing. Among other things, the Order provides Christiania new, first priority and senior security interests in the Company's assets and requires the Company to make weekly adequate protection payments to Christiania during the term of the Order. The Order also imposes certain reporting requirements and cash collateral operating requirements on the Company.
CASH FLOWS
Cash flows provided by operating activities were $3.5 million, $5.3 million, and $15.4 million for the years ended December 31, 1997, 1998 and 1999, respectively. The increases in 1998 and 1999 were primarily attributable to increased production resulting from the acquisitions, new wells placed on line as a result of the Company's drilling activities and changes in working capital. Cash and working capital in 2000 are expected to be provided through internally generated cash flows and borrowings, if available . See "-Financing Arrangements" below.
Cash flows used in investing activities by the Company were $15.0 million, $116.3 million and $25.9 million in 1997, 1998 and 1999, 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 1997, 1998 and 1999 resulted primarily from the acquisition and development of the Lobo Trend properties.
Cash flows provided by the Company's financing activities were $11.1 million, $110.7 million and $11.0 million in 1997, 1998 and 1999, respectively. In 1998, the financing cash flows were primarily from proceeds from the Senior Notes and borrowings under the Credit Facility. In 1999, the financing cash flows were primarily proceeds from borrowings under 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 prior credit facility in place. Approximately $90 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 have had an adverse effect, and would have a further 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.
For the years ended December 31, 1998 and 1999, the Company recorded impairment provisions on producing properties of $5.4 million and $3.8 million, respectively. The impairment provisions were determined based on an assessment of recoverability of net property costs from estimated future net cash flows from those properties. The impairment charge was calculated using discounted cash flows of proved reserves using prices and costs consistent with those used for internal decision making purposes. If oil and gas prices decline in the future, the Company may be required to record further impairment provisions, which may be material.
The Company has made, and will continue to make, ordinary course capital expenditures for the development, and exploitation of oil and natural gas reserves, subject to economic conditions and in accordance with the rulings and procedures set forth by the Bankruptcy Court. Throughout the Chapter 11 filing, the Company has operated a one-rig drilling program. In addition, the Company plans to make capital expenditures in the ordinary course to enhance current production through workovers, recompletions, and other production enhancing activities deemed to be economic. See " - Bankruptcy Proceedings" above.
The Company has currently budgeted approximately $16.1 million in capital expenditures related to its oil and gas properties in 2000, of which approximately $15.6 million would be for development and exploitation activities, and approximately $500,000 would be for delay rentals, lease bonuses, geological and geophysical costs. Actual amounts to be expended by the Company for these activities will be dependent upon a number of factors, including Bankruptcy Court approval, oil and natural gas prices, the availability of capital, seismic and contract service costs, availability of drilling rigs and future drilling results. The Company is not contractually committed to expend the budgeted funds. See " - Capital Expenditures and Outlook" below.
FINANCING ARRANGEMENTS
In August 1996, the Company entered into a comprehensive financing with a limited partnership ("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 canceled, and MHI issued to Cambrian a warrant to acquire 38,671 shares of its Common Stock at a exercise price of $8.00 per share.
In May 1998, the Company entered into its Credit Facility with Christiania as lender and administrative agent. 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, the borrowing base effective April 1, 1999, was reduced to $23 million.
The Company was in violation of certain administrative and one financial covenant under the Credit Facility as of December 31, 1998. The Company obtained a waiver with respect to those violations from Christiania. The Company was in violation of certain administrative and one financial covenant under the Credit Facility as of December 31, 1999. During 1999, the Company entered into a number of amendments to and waivers under the Credit Facility, including an amendment requiring the principal amount outstanding to be decreased by mandatory reductions of $1.5 million per month, beginning October 31, 1999. The principal reduction amount due on October 31, 1999 was not paid by the Company, resulting in an additional default under the Credit Facility. During 1999, Christiania began charging the default rate of interest as provided for under terms of the Credit Facility. In January 2000, the Company and Christiania entered into a cash collateral agreement, which contains certain financial covenants and provides for weekly payments of interest by the Company. This rate of interest is currently prime plus 3.5% per annum (12.5% as of March 31, 2000). The cash collateral order has been extended to expire on May 1, 2000.
The Company granted liens to Christiania on substantially all of the Company's oil and natural gas properties. The Credit Facility contains a number of covenants to be complied with by the Company, including limitations on additional indebtedness and investments, and restrictions on dividends and other distributions. The Credit Facility also requires the Company to maintain and comply with certain financial covenants and ratios, including the maintenance of a minimum interest coverage, a minimum current ratio, and a limitation on general and administrative expenses.
The Company had $24.3 million of indebtedness outstanding under the Credit Facility at December 31, 1999. Pursuant to the cross default provisions contained in the indenture governing the
Senior Notes and under the Credit Facility, a default under either the Senior Notes or the Credit Facility constitutes a default under the other instrument. As such, both the Senior Notes and the Credit Facility have been classified as current obligations of the Company as of December 31, 1999, as a result of these events.
See Note 3 of Notes to Consolidated Financial Statements.
11 1/2% SENIOR NOTES DUE 2005
The Indenture governing the Senior Notes 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, create liens, enter into transactions with affiliates, sell assets or enter into certain mergers and consolidations.
CAPITAL EXPENDITURES AND OUTLOOK
The following table sets forth the Company's capital expenditures for the three years ended December 31, 1999 (in thousands):
The Company currently has budgeted capital expenditures of approximately $16.1 million for 2000. 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 20 gross (16 net) wells in 2000. The Company's existing cash and cash flows from operations will not be sufficient to fund this level of planned capital expenditures for its existing properties through 2000. The Company will require additional capital to fund property acquisitions and planned drilling activities, and access to these markets could be restricted due to the Bankruptcy proceedings. 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, 1997, 1998, or 1999.
EFFECTS OF INFLATION AND CHANGES IN PRICE
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 costs 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 generally requires 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 Company believes it has completed the necessary modifications to its internal information computer systems in preparation for the Year 2000. The Company's Year 2000 project incurred costs of approximately $10,000, funded by cash from operations. The Company also believes that it has completed its review of the Year 2000 compliance status of field equipment, including compressor stations, gas control systems and data logging equipment.
The Company did not experience any significant operational difficulties or incur any other significant expenses in connection with Year 2000 issues. The Company will continue to monitor all critical systems for incidents of delayed complications or disruptions and problems encountered through third parties with whom the Company deals so that they may be timely addressed.
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 concerning the effects of and potential outcomes from the Company's Chapter 11 proceeding or other claims against the Company or its officers and directors, statements regarding the levels of capital expenditures for 2000 and succeeding periods, the availability of sources of capital to fund 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 capital, the Company's success in dealing with its creditors, future governmental regulation, future oil and natural gas reserves, future drilling and development opportunities and operations, future production of oil and natural gas (and the prices thereof and costs therefor), anticipated results of hedging activities, 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) actions and approvals of the Bankruptcy Court, (ii) the degree of success and outcome resulting from the Company's negotiations with its creditors, (iii) factors such as natural gas price fluctuations and markets, uncertainties of estimates of reserves and future net revenues, the success of the Company's drilling activities, 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, (iv) the ability of the Company to obtain other sources of capital to fund its activities, (v) uncertainties inherert in contested or adversarial proceedings, (vi) adverse changes to the Company's properties acquired or developed, (vii) adverse changes in the market for the Company's oil and natural gas production and (viii)
those additional factors discussed 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.
All of the forward-looking statements made in this Annual Report on Form 10-K are qualified by these cautionary statements and there can be no assurance that the actual results or developments anticipated by the Company will be realized or, even if substantially realized, that they will have the expected consequences to or effects on the Company or its business or operations. Such statements are not guarantees of future performance and actual results or developments may differ materially from those anticipated in these statements.
ITEM 7A.
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 72%, 48% and 57% of the Company's production was hedged during the years ended December 31, 1997, 1998 and 1999, respectively. The Company's weighted average natural gas price received per Mcf (including the effects of hedging transactions) was $2.33, $2.07 and $2.28 during the years ended December 31, 1997, 1998 and 1999, respectively. Hedging transactions resulted in a ($0.32), $0.01 and ($0.04) (reduction) increase in the Company's weighted average natural gas price received per Mcf in 1997, 1998 and 1999, respectively. The fair value of these hedging contracts was $(1.1 million), $2.1 million and $441,000 as of December 31, 1997, 1998, and 1999, respectively.
The Company entered into commodity price hedging contracts with respect to its gas production for 1999 and 2000 as follows:
These hedging transactions were to be 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.
In October 1999, Christiania terminated two costless collar contracts which hedged a monthly volume of 300,000 MMBtu, with floor prices of $1.98 and $2.15 and ceiling prices of $2.22 and $2.36, respectively. The termination cost of approximately $1.3 million was added to the outstanding balance of the Credit Facility. Gains and losses on hedge contracts terminated prior to maturity are deferred until the related hedged item is recognized in income.
In January 2000, a third party terminated the remaining hedge contracts open as of December 31, 1999. The third party is seeking a claim of approximately $450,000 as a result of the termination of these contracts. The Company does not concur with the third party's calculation of the amount of this claim.
Because all of the Company's natural gas hedge contracts have been terminated as of January 2000, a tabular presentation of the hedge positions as of December 31, 1999 has not been provided.
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, 2000.
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, 1999, the Company can not estimate the impact of SFAS 133 on its future consolidated financial position, results of operations or cash flows.
The borrowings under the Credit Facility and the value of the Senior Notes are subject to market fluctuations as influenced by certain economic factors and events. The interest rate for borrowings under the Credit Facility is determined based on the Cash Collateral Agreement approved by the Bankruptcy Court. The interest rate on the outstanding borrowings as of December 31, 1999 is the Christiania Bank prime rate plus 3.5%. The fair value of the Credit Facility approximates its market value. The fair value of the Senior Notes was approximately $97 million and $61 million at December 31, 1998 and 1999, respectively. The effective interest rates for the years ended December 31, 1998 and 1999 were 12.04% and 11.56%, respectively.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Michael Petroleum Corporation (Debtor-in-Possession):
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 (Debtor-in-Possession) at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. 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 auditing standards generally accepted in the United States, 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.
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note 1 of the consolidated financial statements, the Company has filed voluntarily under Chapter 11 of the U. S. Bankruptcy Code, has incurred losses from operations in 1999 and 1998 and has an accumulated deficit. These matters raise substantial doubt about the Company's ability to continue a going concern. Management's plan in regard to these matters is also described in Note 1 to the consolidated financial statements. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
PricewaterhouseCoopers LLP
Houston, Texas April 10, 2000
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) CONSOLIDATED BALANCE SHEETS (In thousands of dollars, except share data)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) CONSOLIDATED STATEMENT OF OPERATIONS (In thousands of dollars)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) CONSOLIDATED STATEMENT OF STOCKHOLDER'S DEFICIT For the years ended December 31, 1997, 1998 and 1999 (In thousands of dollars, except per share data)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) CONSOLIDATED STATEMENT OF CASH FLOWS (In thousands of dollars)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE FINANCIAL STATEMENTS.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) 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 96% and 87% of the Company's proved reserves at December 31, 1999 and 1998, respectively.
CHAPTER 11 BANKRUPTCY FILING AND LIQUIDITY
Effective on December 10, 1999, the Company, MHI and certain of its subsidiaries entered into the Voting Agreement with certain holders of the Company's Senior Notes for a consensual joint plan of reorganization of the Company (the "Plan"). The terms of the Voting Agreement contemplated that the Plan would provide for a sale of the Company or its assets in court-supervised proceedings under the Bankruptcy Code. The Voting Agreement also contemplated that the Company and its subsidiaries would continue to operate as debtors-in-possession subject to the supervision of the Bankruptcy Court, and that the Plan would provide for the payment of all trade creditors' claims as and when they come due in the ordinary course or in full on the effective date of the Plan. On December 10, 1999, the Company, MHI and certain of its subsidiaries filed petitions for relief under Chapter 11 of the Bankruptcy Code in Bankruptcy Court. The bankruptcy petitions were filed in order to give the Company an opportunity to conserve its cash and restructure its debt. Since December 10, 1999, the Company, MHI and the filing subsidiaries have operated as debtors-in-possession under the Bankruptcy Code. The Company has curtailed its developmental drilling program, limiting expenditures to a one-rig drilling program. No trustee or examiner has been appointed and the Company, MHI and these subsidiaries are paying their postpetition obligations (except those subject to Bankruptcy Court approval) as they become due. See also discussion of cash collateral agreement with Christiania at Note 3.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Voting Agreement provided that the obligations of the parties thereto may terminate upon a "Termination Event," which included any failure under the marketing process to timely achieve certain milestones, including the receipt of at least one final bid by March 17, 2000 in an amount equal to at least $120 million, as adjusted for certain costs and working capital items. Although the Company received several bids, as of March 17, 2000, the Company had not received a final bid in such an amount sufficient to meet this requirement.
The accompanying financial statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of the bankruptcy filing and related events, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be liquidated or settled for the amounts recorded. In addition, a plan of reorganization, or rejection thereof, could change the amounts reported in the financial statements. As a result, there is substantial doubt about the Company's ability to continue as a going concern. The ability of the Company to continue as a going concern is dependent upon confirmation of a plan of reorganization, adequate sources of capital and the ability to sustain positive results of operations and cash flows sufficient to continue to explore for and develop oil and gas reserves.
In the ordinary course of business, the Company makes substantial capital expenditures for the exploration and development of oil and natural gas reserves. Historically, the Company has financed its capital expenditures, debt service and working capital requirements with cash flow from operations, public offerings of debt and a senior credit facility. Cash flow from operations is sensitive to the prices the Company receives for its oil and natural gas. A reduction in planned capital spending or an extended decline in oil and gas prices could result in less than anticipated cash flow from operations, which would likely have a further material adverse effect on the Company.
Management's plan is to continue the marketing and sale of the Company or its assets or reorganize the capital structure of the Company. The Company and its advisors have continued to negotiate with the holders of the Senior Notes and with prospective purchasers for a consensual plan of reorganization.
The Company expects to file a plan and related disclosure statement with the Bankruptcy Court in April 2000. In addition to the approval of the Bankruptcy Court, the consummation of the plan will be subject to the consent of the requisite number and amount of certain of the Company's creditors. At this time, it is not possible to predict the outcome of the bankruptcy proceedings, the effect on the Company's business or on the interests of its creditors, royalty owners or stockholders or whether certain executory contracts will be assumed or rejected. As a result of the bankruptcy filing, certain of the Company's liabilities are subject to compromise. Through December 31, 1999, the Company has incurred expenses of approximately $1.5 million which consisted of approximately $792,000 pertaining to restructuring costs (consisting principally of investment banking, legal and professional fees) and approximately $721,000 pertaining to the bankruptcy proceedings (legal, professional and other fees).
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 one financial institution. The Company periodically assesses the financial condition of the institutions and believes that any possible credit risk is minimal.
OIL AND GAS PROPERTIES
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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. Impairment charges calculated are based on discounted cash flows determined based on proved reserves using prices and costs consistent with those used for internal decision making purposes.
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, 1998 and 1999.
OTHER ASSETS
Other assets include loan origination costs which are amortized on a straight-line basis over the term of the related obligation. In addition, the non-current portion of the unamortized hedging termination costs are included in other assets. Gains and losses on hedge contracts terminated prior to maturity are deferred until the related hedged item is recognized in income.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INCOME TAXES
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.
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 other than as described in Note 8.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts reported in the balance sheet for cash and cash equivalents, receivables, and accounts payable other than those subject to compromise approximate their fair value. The fair value of the Company's long-term debt and derivative financial instruments are estimated using current market quotes. Due to the bankruptcy filing (see Note 1), the Company is uncertain as to the timing and amount of liquidation or settlement of liabilities subject to compromise. Accordingly, except for debt which has quoted market prices, the Company does not believe it is practicable to estimate the fair value of those liabilities.
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 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):
3. DEBT:
Debt consisted of the following (in thousands):
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 rates under the Senior Notes for the years ended December 31, 1998 and 1999 was 12.0% and 11.6%, respectively. 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 estimated fair value of the Senior Notes was $97 million and $61 million at December 31, 1998 and 1999, respectively. As the Senior Notes are unsecured obligations subject to compromise under the Bankruptcy proceeding, beginning December 10, 1999, the Company discontinued accruing interest under the Indenture which would
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
have been approximately $936,000 through December 31, 1999. An interest payment on the Senior Notes of approximately $7.8 million was due on October 1, 1999, but was not paid by the Company. A 30-day grace period under the Indenture governing the Senior Notes expired on October 31, 1999 without payment of interest on the Senior Notes, and, as a result, an event of default occurred under the Indenture. The Indenture provides that in the event of an event of default, the entire indebtedness under the Senior Notes may be declared due and payable.
Under the cross default provisions contained in the Indenture governing the Senior Notes and in the Credit Facility described below, a default under either the Senior Notes or the Credit Facility constituted a default under the other instrument (see Note 1 discussing bankruptcy proceedings). Consequently, balances outstanding under the Senior Notes and Credit Faciltiy have been classified as current liabilities as of December 31, 1999.
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.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
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 initial terms of 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 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. The principal balance outstanding was due and payable on May 28, 2002, and each letter of credit was to be reimbursable by the Company when drawn, or if not then otherwise reimbursed, paid pursuant to a loan under the Credit Facility.
Effective April 1, 1999, the new borrowing base was reduced to $23 million and certain terms of the Credit Faciltiy were amended. 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 was not only to 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. The Company did not make the $1.5 million principal payment due October 31, 1999, which constituted an event of default under the Credit Facility.
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 and pending a stay by the bankruptcy court, either repay such excess in full or provide additional collateral acceptable to Christiania.
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%. Due to violations of certain covenants during 1999, Christiania began charging the default rate of interest which was prime plus 3.5% per annum. The effective interest rates under the Credit Facility for the years ended December 31, 1998 and 1999 was 6.8% and 9.3%, respectively. 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
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
proceeds of the Credit Facility were used for general corporate purposes.
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 obtained a waiver with respect to those violations from Christiania, which agreed not to assert any default based on such violations. The Company and Christiania also amended certain financial covenants. The Company was in violation of certain administrative and two financial covenants of the Credit Facility as of December 31, 1999.
On January 11, 2000, the Company and Christiania entered into a cash collateral agreement, which contains certain financial covenants and provides for weekly payments of interest by the Company. The cash collateral agreement modified the previous financial covenants which were in violation at December 31, 1999, but did not modify the administrative covenants which the Company had violated. On April 5, 2000, the Court entered its Second Final Agreed Order Authorizing use of Cash Collateral and Granting Adequate Protection. This Order was entered with the agreement of Christiania, who consented to the Company's continued use of Christiania's cash collateral in accordance with the terms and conditions set forth in the Order until May 1, 2000, unless extended by the parties or further order of the Court after notice and a hearing. Among other things, the Order provides Christiania new, first priority and senior security interests in the Company's assets and requires the Company to make weekly adequate protection payments to Christiania during the term of the Order. The Order also imposes certain reporting requirements and cash collateral operating requirements on the Company.
4. FEDERAL INCOME TAXES:
The components of the net deferred taxes are as follows (in thousands):
Income tax expense was $1.9 million for the year ended December 31, 1999 as a full valuation allowance was recorded by the Company for the net deferred tax assets which existed at December 31, 1999. The net deferred asset as December 31, 1998 of $1.9 million was recorded based on management's belief that it was
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
more likely than not that future taxable income, which included the effect of certain tax planning strategies, would be sufficient to fully utilize existing net operating losses prior to expiration. However, a portion of the net operating loss carryforward (approximately $30.6 million as of December 31, 1999) was reserved as of December 31, 1999 as the status of the current and future drilling program and uncertainty about the availability of capital resulted in uncertainty as to whether sufficient taxable income will be available to utilize the entire net operating loss carryforward. Any restructuring of the Company's indebtedness may result in a significant stock ownership change which would significantly affect the timing of the utilization of the net operating loss carryforward. The valuation allowance related to tax assets could be adjusted in the future due to changes in estimates of future taxable income and the outcome of the Bankruptcy proceedings.
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):
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 72%, 48% and 57% of the Company's production was hedged during the years ended December 31, 1997, 1998 and 1999, respectively. The Company's weighted average natural gas price received per Mcf (including the effects of hedging transactions) was $2.33, $2.07 and $2.28 during the years ended December 31, 1997, 1998 and 1999, respectively. Hedging transactions resulted in a ($0.32), $0.01 and ($0.04) (reduction) increase in the Company's weighted average natural gas price received per Mcf in 1997, 1998 and 1999, respectively. The unrealized gain (loss) related the hedging contracts was ($1.1) million, $2.1 million and $441,000 as of December 31, 1997, 1998 and 1999, respectively.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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:
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.
In October 1999, Christiania terminated two costless collar contracts which hedged a monthly volume of 300,000 MMBtu, with floor prices of $1.98 and $2.15 and ceiling prices of $2.22 and $2.36, respectively. The termination cost of approximately $1.3 million was added to the outstanding balance of the Credit Facility. Gains and losses on hedge contracts terminated prior to maturity are deferred until the related hedged item is recognized in income.
In January 2000, a third party terminated the remaining hedge contracts open as of December 31, 1999. The third party is seeking a claim of approximately $450,000 as a result of the termination of these contracts. The Company does not concur with the third party's calculation of the amount of the claim.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Because the Company's natural gas hedge contracts have been terminated as of January 2000, a tabular presentation of the hedge positions as of December 31, 1999 has not been provided.
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. As of December 31, 1999, MHI granted, at exercise prices in excess of the fair market value per share, options covering a total of 15,000 shares to two employees 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. As of December 31, 1999, the following is a summary of all stock options activity for 1998 and 1999. The Company did not have a stock option plan in 1997.
At December 31, 1998 and 1999, the Company had an additional 120,650 and 131,550 shares, respectively 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.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The weighted average fair value of options granted during 1998 and 1999 was $18.12 and $17.31, respectively.
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 and 1999: no dividend yield; expected volatility of 0.00%; risk-free interest rates ranging from 5.1% to 5.4% and an expected option life of 5 years.
The following table summarizes information about stock options outstanding and exercisable at December 31, 1999:
Exercisable stock options and weighted average exercise prices at December 31, 1998 follow.
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 or 1999.
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 and 1999 would have approximated the pro forma amount below (in thousands):
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
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $-0-, $18,000 and $26,000 for the years ended December 31, 1997, 1998 and 1999, respectively.
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, 2000. 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, 1999, 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 CEO 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:
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Sales Agreement is effective for a one-year period and is renewable automatically for successive one-year periods thereafter.
Marketing fees paid to Upstream were approximately $220,000, $253,000 and $278,000 for the years ended December 31, 1997, 1998 and 1999, respectively. During the years ended December 31, 1997, 1998 and 1999, Upstream purchased gas produced by the Company for approximately $9.7 million, $20.8 million and $32.2, respectively. At December 31, 1998 and 1999, receivables from Upstream of approximately $5.2 million and $7.8 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. Substantially all of the Company's operated oil and natural gas is sold to three customers.
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, 1997, 1998 and 1999, the Vice President - Geosciences received from the Company approximately $105,000, $275,000 and $433,000, 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 1999, the Company loaned $135,000 to its Chairman and CEO. The note is unsecured, due on demand, and bears interest at 10%.
In December 1998, the Company loaned $1.5 million (at interest bearing 12% per annum) to a Texas limited liability company that participated in the drilling of natural gas wells in Northern Mexico. The note became past due on December 15, 1999 and this receivable has been fully reserved by the Company.
9. SUPPLEMENTAL CASH FLOW INFORMATION:
Cash payments for interest are as follows (in thousands):
Non-cash investing and financing transactions not reflected in the statement of cash flows include the following (in thousands):
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. COMMITMENTS AND CONTINGENCIES:
LEASES
The Company has entered into two noncancelable operating lease agreements for office space in Houston, Texas and Laredo, Texas. The lease terms expire in 2004, with two options to renew the lease for a period of five years each for the Houston office lease. Future minimum lease payments required as of December 31, 1999 related to noncancelable operating leases are as follows (in thousands):
Rent expense for the years ended December 31, 1997, 1998 and 1999 was approximately $69,000, $154,000 and $193,000, respectively.
LEGAL PROCEEDINGS
On December 10, 1999, the Company, MHI, and certain of its subsidiaries filed petitions for relief under Chapter 11 of the Bankruptcy Code in order to facilitate the restructuring of the Company's liabilities. The Company continues to operate as a debtor-in-possession subject to the Bankruptcy Court's supervision and orders. The filing was made in the U.S. Bankruptcy Court for the Southern District of Texas, Laredo Division.
On March 27, 2000, the Company received a demand letter from a royalty owner. The demand letter challenges certain deductions used by the Company to calculate prices for oil and gas royalties. The Company believes that it has substantial defenses to this claim and intends to vigorously assert such defenses. However, the investigation into this claim is in its early phases and the potential range of loss, if any, cannot presently be determined by the Company.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On March 31, 2000, the Company received correspondence from counsel to the Official Committee of Unsecured Creditors requesting the Company to take legal action on behalf of the Company's Estate against Glenn D. Hart, Michael G. Farmar and the directors of Company, alleging certain misstatements in connection with the issuance of the Senior Notes and certain breaches of fiduciary duties to the creditors. The Company is currently evaluating the claims made under these allegations, but currently knows of no basis for their assertion.
In addition to the matters noted above, 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, 1999, there were no threatened or pending legal matters, other than the matters noted above, which would have a material impact on the Company's consolidated financial position, results of operations or cash flows.
EMPLOYEE RETENTION PLAN
On March 27, 2000, the Bankruptcy Court approved an Employee Retention Bonus Plan. Under the terms of the Employee Retention Bonus Plan, eligible employees are entitled to a bonus equal to three months salary if the employee remains employed with the Company through the effective date of the plan of reorganization. The estimated cost of the Employee Retention Bonus Plan is approximately $400,000.
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 ranges from $0.11 to $0.17 per Mcf for compression, transportation and dehydration.
11. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (Unaudited):
CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) 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):
OIL AND GAS RESERVE QUANTITIES
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 and evolving production history. Continual reassessment of the viability of production under varying economic conditions requires additional capital, the source of which is unclear due in part to the Company's operations under Chapter 11 bankruptcy proceedings. 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 and could result in different estimates of proved reserve quantities and related future net cash flows.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The reserve information as of December 31, 1999 was prepared by Netherland Sewell and Associates, Inc. The reserve information as of December 31, 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, 1999 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
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, 1999:
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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):
(1) The increase in production costs from the year ended December 31, 1999 compared to December 31, 1998 was primarily related to longer economic lives of certain natural gas wells, higher estimated severance taxes, and higher estimated lease operating expenses.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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):
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable
PART III
ITEM 10.
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.
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
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 has a B.B.A. in Accounting from Texas Tech University and is a Certified Public Accountant, a member of the American Institute of Certified Public Accountants and the Texas Society of Certified Public Accountants.
Sarah Ruddock joined the Company in 1994 and was promoted to Land Manager in 1995 and Vice President - Land in 1999. Prior to 1994, Ms. Ruddock served as Director of Supply for National Gas Resources, Inc. She has also worked for Gulf Oil Corp. as a natural gas trader and as a U.S. Gulf Coast Landman. Ms. Ruddock is a graduate of the University of Texas at Austin where she received a B.B.A. in Petroleum Land Management. Ms. Ruddock is a Certified Professional Landman and a member of the Houston Association of Professional Landmen and the American Association of Professional Landmen.
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.
During October 1999, two directors of the Company, Bryant H. Patton and Jack I. Tompkins, resigned.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ITEM 11.
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, 1998 and 1999.
(1) Represents the estimated value of personal use of a Company vehicle. (2) Represents amounts paid or accrued to Mr. Holditch pursuant to certain overriding royalty interests granted to him.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
No options were issued to or exercised by the Named Executive Officers in 1997, 1998 or 1999.
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, 1999, a total of 62,550 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, 1997, 1998 and 1999, Mr. Holditch received from the Company $104,946, $274,690 and $432,885, 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
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
administers the compensation plans for the Company's executive officers and directors. The members of the Audit Committee are Messrs. Farmar and Smith. The only member of the Compensation Committee is Mr. Smith.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as of December 31, 1999, (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.
(1) Except as otherwise noted, the named shareholder has sole voting, investment and dispositive power.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In December 1999, the Company loaned $135,000 to its Chairman and Chief Executive Officer. The note is unsecured, due on the earlier to occur of June 1, 2000 or demand by the Company, and bears interest at 10% per annum.
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, 1997, 1998 and 1999, the Company paid Upstream or its predecessor marketing fees of $220,000, $253,000 and $278,000, 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 received dividends of $6,000 in the year ended December 31, 1997. 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.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 as $87,500 plus approximately $3,000 in carrying fees. In addition, pursuant to the agreement, Mr. Hart reserved a 1% overriding royalty interest. No royalties were paid in 1998 or 1999.
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.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements
See Index on page 35.
2. Financial Statement Schedules
None.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. EXHIBITS
The following instruments are included as exhibits to this report.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(b) Reports on Form 8-K.
In October 1999, the Company filed a Current Report on Form 8-K dated October 6, 1999 under Item 5. "Other Events" concerning the Company's presentation to certain holders of its Senior Notes.
In November 1999, the Company filed a Current Report on Form 8-K dated November 1, 1999 under Item 5. "Other Events" reporting the Company's failure to pay the interest payment on its Senior Notes due on October 1, 1999 following a 30-day grace period.
In December 1999, the Company filed a Current Report on Form 8-K dated December 13, 1999, under Item 3. - "Bankruptcy or in Receivership" reporting the filing of the petitions for relief under Chapter 11 of the Bankruptcy Code.
(c) Exhibits required by Item 601 of Regulation S-K
See (a) 3. - "Exhibits" above of this Item 14.
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.
Dated: April 10, 2000 MICHAEL PETROLEUM CORPORATION
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.
MICHAEL PETROLEUM CORPORATION (DEBTOR-IN-POSSESSION) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 10th day of April, 1999.