-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Kd6LPlUCnNDyTUcbm3wOYnJGBYkE4e6/ZBf4sfYA7SDgMgspkdU8qay1WvZHnci7 38YNE9l91HArVdZmuPVQ1A== 0000950129-00-001538.txt : 20000331 0000950129-00-001538.hdr.sgml : 20000331 ACCESSION NUMBER: 0000950129-00-001538 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MERIDIAN RESOURCE CORP CENTRAL INDEX KEY: 0000869369 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760319553 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-10671 FILM NUMBER: 587155 BUSINESS ADDRESS: STREET 1: 15995 N BARKERS LANDING STE 300 CITY: HOUSTON STATE: TX ZIP: 77079 BUSINESS PHONE: 7135588080 MAIL ADDRESS: STREET 1: 15995 N BARKERS LANDING SUITE 300 STREET 2: 15995 N BARKERS LANDING SUITE 300 CITY: HOUSTON STATE: TX ZIP: 77079 FORMER COMPANY: FORMER CONFORMED NAME: TEXAS MERIDIAN RESOURCES CORPORATION DATE OF NAME CHANGE: 19930328 FORMER COMPANY: FORMER CONFORMED NAME: TEXAS MERIDIAN RESOURCES ACQUISITION CORPORATION DATE OF NAME CHANGE: 19600201 10-K 1 THE MERIDIAN RESOURCE CORPORATION - DATED 12/31/99 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-K ------- ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended: Commission file number: DECEMBER 31, 1999 1-10671 THE MERIDIAN RESOURCE CORPORATION (Exact name of registrant as specified in its charter) TEXAS 76-0319553 (State of incorporation) (I.R.S. Employer Identification No.) 1401 ENCLAVE PARKWAY, SUITE 300, HOUSTON, TEXAS 77077 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 281-597-7000 Securities registered pursuant to Section 12(b) of the Act: ----------------------------------------------------------- (Title of each class) (Name of each exchange on which registered) Common Stock, $0.01 par value New York Stock Exchange Securities registered pursuant to section 12(g) of the Act: None ---------------------------------------------------------------- ------- Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Aggregate market value of shares of common stock held by non-affiliates of the Registrant at March 7, 2000: $138,355,522 Number of shares of common stock outstanding at March 7, 2000: 46,414,417 DOCUMENTS INCORPORATED BY REFERENCE The information required by Part III of this Form (Items 10, 11, 12 and 13) is incorporated by reference from the registrant's Proxy Statement to be filed on or before April 29, 2000. Page 1 of 68 2 THE MERIDIAN RESOURCE CORPORATION INDEX TO FORM 10-K
PART I Page ---- Item 1. Business 3 Item 2. Properties 16 Item 3. Legal Proceedings 16 Item 4. Submission of Matters to a Vote of Security Holders 17 PART II Item 5. Market for Registrant's Common Equity and Related Shareholder Matters 18 Item 6. Selected Financial Data 19 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 20 Item 7. a. Quantitative and Qualitative Disclosures about Market Risk 31 Item 8. Financial Statements and Supplementary Data 33 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 62 PART III Item 10. Directors and Executive Officers of the Registrant 62 Item 11. Executive Compensation 62 Item 12. Security Ownership of Certain Beneficial Owners and Management 62 Item 13. Certain Relationships and Related Transactions 62 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 63 Signatures 68
-2- 3 PART I ITEM 1. BUSINESS GENERAL The Meridian Resource Corporation ("Meridian") is an independent oil and natural gas company that explores for, acquires and develops oil and natural gas properties utilizing 3-D seismic technology. Our operations are focused on the onshore oil and gas regions in south Louisiana, the Texas Gulf Coast and offshore in the Gulf of Mexico. As of December 31, 1999, we had proved reserves of approximately 365 Bcfe with a present value of future net cash flows before income taxes of $596 million. Approximately 55% of our proved reserves were natural gas and approximately 69% were classified as proved developed. We believe we are among the leaders in the use of 3-D seismic technology by independent oil and natural gas companies. We also believe we have a competitive advantage in the areas where we operate because of our large inventory of lease acreage, seismic data coverage and experienced geotechnical staff. During 1997, we expanded our operations into the Gulf of Mexico by merging with Cairn Energy USA, Inc. for shares of our common stock. This acquisition not only expanded the geographic scope of our operations, but also provided us with a greater prospect and data base from which to execute the same exploration strategy as that which we have in place onshore. During 1998, we acquired substantially all of Shell Oil Company's and its affiliates' (collectively, "Shell") onshore south Louisiana oil and gas property interests in two separate transactions (the "Shell Transactions"). The Shell Transactions were consummated on June 30, 1998, and positioned us as one of the leading operators and producers in south Louisiana. Additionally, the property interests acquired in the Shell Transactions allows us to focus on a blend of lower risk exploration and development projects with lesser dependence on higher risk exploration drilling. As a result of the Shell Transactions, Shell beneficially owns 39.9% of our common stock on a fully-diluted basis assuming the exercise of all outstanding stock options and warrants and conversion of all preferred stock. We believe that we have strategically positioned Meridian for improving our opportunities for growth from the drill bit in south Louisiana and the Texas Gulf Coast. We currently have interests in over 98,190 gross onshore acres in Louisiana and Texas and 306,095 gross offshore acres in the Gulf of Mexico. We also have rights or access to approximately 3,100 square miles of onshore 3-D seismic data and 1,200 square miles of offshore 3-D seismic data, which we believe to be one of the largest positions held by a company of its size operating in our core areas of operation. The Meridian Resource Corporation was incorporated in Texas in 1990, with headquarters located at 1401 Enclave Parkway, Suite 300, Houston, Texas 77077. EXPLORATION STRATEGY Meridian has focused its exploration strategy on prospects where large accumulations of oil and natural gas have been found and where we believe substantial oil and natural gas reserve additions can be achieved through exploratory drilling in which we use 3-D seismic technology. We also seek to identify prospects with multiple potential productive zones to maximize the probability of success. In an effort to mitigate the risk of dry holes, we engage in a rigorous and disciplined review of each prospect utilizing the latest in technological advances with respect to prospect analysis and evaluation. -3- 4 Our process of review of exploration prospects begins with a thorough analysis of the prospect using traditional methods of prospect development and computer technology to analyze all reasonably available 2-D seismic data and other geological and geophysical data with respect to the prospect. If the results of this analysis confirm the prospect potential, we seek to acquire 3-D seismic data over leasehold interests in, or options to acquire leasehold interests in, the prospect area. We then apply state-of-the-art processing technology to assimilate and correlate the 2-D and 3-D seismic data on the prospect with all available well-log information and other data to create a computer model that we design to identify the location and size of potential hydrocarbon accumulations in the prospect. If our analysis of the model continues to confirm the potential for hydrocarbon accumulations within our prospect objectives, we will then seek to identify the most desirable drilling location to test the prospect and to maximize production if the prospect is successful. The process of developing, reviewing and analyzing a prospect from the time we first identify it to the time that we drill it is generally a 12 to 36 month process in which we reject many potential prospects at various levels of the review. Although the cost of designing, acquiring, processing and interpreting 3-D seismic data and acquiring options and leases on prospects that we do not ultimately drill requires greater up-front costs per prospect than traditional exploration techniques, we believe that the elimination of prospects that are unlikely to be successful and that might otherwise have been drilled at a substantial cost results in significant lower finding costs. We also believe that its use of 3-D seismic technology minimizes development costs by allowing for the better placement of initial and, if necessary, development wells. We attempt to match our exploration risks with expected results by retaining working interests that historically have been between 50% and 75% in the Company's onshore wells. Our working interests may vary in certain prospects depending on participation structure, assessed risk, capital availability and other factors. In addition, working interests in offshore properties we acquired in the Cairn acquisition averages between 3% and 50% in each well. Our offshore properties generally involve higher drilling costs and risks commonly associated with offshore exploration, including costs of constructing exploration and production platforms and pipeline interconnections, as well as weather delays and other matters. 3-D SEISMIC TECHNOLOGY An integral part of Meridian's exploration strategy is the disciplined application of 3-D seismic technology to every exploration and development prospect which we drill. We begin with the geological idea, develop subsurface maps based on analogous wells in the region and use 2-D seismic data, where available, to define our prospect areas. If the prospect meets our standards of risk and opportunity, we will acquire a 3-D seismic survey over the prospect area as a last method to further define the objectives, reduce the risks of drilling a dry hole and/or improve our opportunity for success. The entire process from the geological concept to the final interpretation is controlled by Meridian's management and professional staff. People are our most important ingredient in this formula. Meridian has put together a high quality professional and technical staff that has successfully explored for oil and gas in its region of focus-south Louisiana, southeast Texas and offshore Gulf of Mexico. Meridian designs its 3-D seismic surveys in conjunction with its geological and geophysical staff, manages the field acquisition efforts with its geophysical staff, processes the 3-D data in house using Western Geophysical's Omega software system, in conjunction with the geological and geophysical technicians, and interprets the 3-D data utilizing Schlumberger's Geoquest interpretative software, where all of the respective disciplines interact to develop the final product. In addition, almost all of Meridian's producing properties have 3-D seismic surveys covering their fields, which we believe gives Meridian an advantage to develop and exploit the proved undeveloped and proved developed non-producing reserves from those fields without the added costs of acquiring surveys and the delays that would accompany the time associated with shooting, processing and interpreting those surveys. As a result, we believe that our disciplined method of exploration enables us to develop a more accurate definition of the risk profile of exploration prospects than was previously available using traditional exploration -4- 5 techniques. We therefore believe that our disciplined application of the 3-D technology is unique among independent exploration and production companies and increases our chances for success rates and reduces our dry-hole costs compared to companies that do not engage in a similar process. -5- 6 OIL AND GAS PROPERTIES The following table sets forth production and reserve information by region with respect to our proved oil and natural gas reserves as of December 31, 1999. The reserve volumes were prepared by T. J. Smith & Company, Inc., independent reservoir engineers.
GULF OF TEXAS LOUISIANA MEXICO TOTAL ------------- --------------- ------------- ------------ PRODUCTION FOR THE YEAR ENDED DECEMBER 31, 1999 Oil (MBbls) .......................... 20 4,177 257 4,454 Natural Gas (MMcf) ................... 1,169 14,126 7,416 22,711 RESERVES AS OF DECEMBER 31, 1999 Oil (MBbls) .......................... 63 26,219 1,073 27,355 Natural Gas (MMcf) ................... 4,647 165,071 30,747 200,465 ESTIMATED FUTURE NET CASH FLOWS ($000) (1) ........................................................ $ 892,692 PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE INCOME TAXES ($000)(1) .............................. $ 595,640 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS ($000)(1) ................................ $ 524,758
(1) The Standardized Measure of Discounted Future Net Cash Flows represents the Present Value of Future Net Cash Flows after income taxes discounted at 10%. For calculating the Present Value of Future Net Cash Flows as of December 31, 1999, we used the prices at December 31, 1999, which were $25.81 per Bbl of oil and $2.48 per Mcf of natural gas. PRODUCTIVE WELLS At December 31, 1999, 1998 and 1997, we held interests in the following productive wells. The majority of the 37 gross (7.4 net) wells in the Gulf of Mexico as of December 31, 1999, have multiple completions.
1999 1998 1997 ----------------------- ------------------------ -------------------------- GROSS NET GROSS NET GROSS NET ---------- ---------- ----------- ---------- ----------- ----------- Oil Wells 116 91 117 89 16 7 Natural Gas Wells 95 40 94 42 345 94 ---------- ---------- ----------- ---------- ----------- ----------- Total 211 131 211 131 361 101 ========== ========== =========== ========== =========== ===========
-6- 7 OIL AND NATURAL GAS RESERVES Presented below are our estimated quantities of proved reserves of crude oil and natural gas, Future Net Cash Flows, Present Value of Future Net Revenues and the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 1999. Information set forth in the following table is based on reserve reports prepared in accordance with the rules and regulations of the Securities and Exchange Commission (the "Commission"). The reserve volumes were prepared by T. J. Smith & Company, Inc., independent reservoir engineers, as of December 31, 1999.
PROVED RESERVES AT DECEMBER 31, 1999 ----------------------------------------------------------------------- DEVELOPED DEVELOPED PRODUCING NON-PRODUCING UNDEVELOPED TOTAL ------------ ---------------- ------------------ ------------------ (DOLLARS IN THOUSANDS) Net Proved Reserves: Oil (MBbls) ........................ 11,164 6,531 9,660 27,355 Natural Gas (MMcf) ................. 96,403 48,149 55,913 200,465 Natural Gas Equivalent (MMcfe) ..... 163,387 87,335 113,873 364,593 Future Net Cash Flows(1) ...................................................................... $ 892,692 Present Value of Future Net Cash Flows (before income taxes)(1) ............................... $ 595,640 Standardized Measure of Discounted Future Net Cash Flows(1) ................................... $ 524,758
- --------------- (1) The Standardized Measure of Discounted Future Net Cash Flows represents the Present Value of Future Net Cash Flows after income taxes discounted at 10%. For calculating the Future Net Cash Flows, the Present Value and Future Net Cash Flows and Standard Measure of Discounted Future Net Cash Flows as of December 31, 1999, we used the prices at December 31, 1999, which were $25.81 per Bbl of oil and $2.48 per Mcf of natural gas. You can read additional reserve information in our Consolidated Financial Statements and the Supplemental Oil and Gas Information (unaudited) included elsewhere herein. We have not included estimates of total proved reserves, comparable to those disclosed herein, in any reports filed with federal authorities other than the Commission. In general, our independent engineers based their estimates of economically recoverable oil and natural gas reserves and of the future net revenues therefrom on a number of variable factors and assumptions, such as historical production from the subject properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices and future operating costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and classifications of reserves which are based on the mechanical status of the completion, also may define the degree of speculation involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Therefore, the actual production, revenues, severance and excise taxes, and development and operating expenditures with respect to reserves likely will vary from such estimates, and such variances could be material. Estimates with respect to proved reserves that we may develop and produce in the future are often based on volumetric calculations and on analogy to similar types of reserves rather than actual production history. Estimates based on these methods generally are less reliable than those based on actual production history, and subsequent evaluation of the same reserves, based on production history, will result in variations, which may be substantial, in the estimated reserves. -7- 8 In accordance with applicable requirements of the Commission, the estimated discounted future net revenues from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. OIL AND NATURAL GAS DRILLING ACTIVITIES The following table sets forth the gross and net number of productive, dry and total exploratory and development wells that we drilled and completed in 1999, 1998 and 1997.
GROSS WELLS NET WELLS -------------------------------- -------------------------------- PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL ------------- ------- -------- ------------- ------- -------- EXPLORATORY WELLS Year ended December 31, 1999 ................... 8 7 15 3.4 4.9 8.3 Year ended December 31, 1998 ................... 8 12 20 2.9 6.3 9.2 Year ended December 31, 1997 ................... 7 9 16 4.4 3.5 7.9 DEVELOPMENT WELLS Year ended December 31, 1999 ................... 6 1 7 3.3 .7 4.0 Year ended December 31, 1998 ................... 6 1 7 4.5 .2 4.7 Year ended December 31, 1997 ................... 3 - 3 0.8 - 0.8
Meridian had 6 gross (3.6 net) wells in progress at December 31, 1999. -8- 9 PRODUCTION The following table summarizes the net volumes of oil and natural gas produced and sold, and the average prices received with respect to such sales, from all properties in which Meridian held an interest during 1999, 1998 and 1997.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------ 1999 1998 1997 ---------------- ----------------- ----------------- PRODUCTION: Oil (MBbls) ........................... 4,454 2,365 914 Natural gas (MMcf) .................... 22,711 20,603 14,603 Natural gas equivalent (MMcfe) ........ 49,438 34,793 20,087 AVERAGE PRICES: Oil ($/Bbl) ........................... $ 17.61 $ 12.19 $ 19.72 Natural Gas ($/Mcf) ................... $ 2.38 $ 2.16 $ 2.70 Natural gas equivalent ($/Mcfe) ....... $ 2.68 $ 2.11 $ 2.86 PRODUCTION EXPENSES: Lease operating expenses ($/Mcfe) ........................ $ 0.30 $ 0.37 $ 0.28 Severance and ad valorem taxes ($/Mcfe) .................. $ 0.23 $ 0.12 $ 0.11
ACREAGE The following table sets forth the developed and undeveloped oil and natural gas acreage in which Meridian held an interest as of December 31, 1999. Undeveloped acreage is considered to be those lease 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.
DECEMBER 31, 1999 --------------------------------------------------------------- DEVELOPED UNDEVELOPED ----------------------------- ------------------------------ REGION GROSS NET GROSS NET ------------- ------------ ------------- ------------- TEXAS ...................................... 3,485 2,706 8,262 3,758 LOUISIANA .................................. 43,308 33,013 43,135 25,955 GULF OF MEXICO ............................. 74,555 18,126 231,540 96,202 ------------- ------------ ------------- ------------- TOTAL ............................. 121,348 53,845 282,937 125,915 ============= ============ ============= =============
In addition to the above acreage, we currently have options or farm-ins to acquire leases on approximately 390 gross (189 net) acres of undeveloped land located in Louisiana. Our fee holdings of 5,000 acres have been included in the undeveloped acreage and have been reduced to reflect the interest that we have leased to third parties. -9- 10 GEOLOGIC AND GEOPHYSICAL EXPERTISE Meridian employs approximately 94 full-time non-union employees and 28 contract employees. The exploration staff consists of 65 persons, representing 53% of the total personnel. This staff includes 17 full-time geologists and 10 full-time geophysicists, with between 9 and 43 years of experience in generating onshore and offshore prospects in the Louisiana and Texas Gulf Coast region. Our geologists and geophysicists generate and review all prospects using 2-D and 3-D seismic technology and analogues to producing wells in the areas of interest. Quality geo-scientists with experience in finding oil and gas in large quantities like those on our staff and who focus in our niche region of focus are unique and difficult to attract and retain on long term contracts. In the interest of attracting and retaining talented technical personnel capable of finding oil and gas reserves with the success rates we strive for, we have adopted a net profits interest incentive compensation plan for the senior geologists, geophysicists, and executives that relates each individual's compensation to the success of our exploration activities on a well by well basis. We believe that this plan provides Meridian's staff with the proper incentive to find large quantities of oil and gas on behalf of it and its shareholders at higher than industry average success rates. MARKETING OF PRODUCTION We market our production to third parties in a manner consistent with industry practices. Typically, the onshore oil production is sold at the wellhead at field-posted prices plus a bonus, less gathering and gravity, and the natural gas is sold under contract at a negotiated price based on factors normally considered in the industry, such as price regulations, distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply and demand conditions. The onshore gas production is sold under short-term contracts or in the spot market. We sell offshore oil production to various purchasers under short-term arrangements at prices negotiated by third parties, but at prices no less than such purchasers' posted prices for the respective areas less standard deductions. The offshore gas production is sold pursuant to short-term contracts or in the spot market. The following table sets forth purchasers of our oil and natural gas that accounted for more than 10% of total revenues for 1999, 1998 and 1997.
YEAR ENDED DECEMBER 31, ----------------------------------------------------------- CUSTOMER 1999 1998 1997 -------- ----------------- ----------------- ----------------- Tauber Oil Company............................... 16% 32% -- Equiva Trading Company(1)........................ 43% 22% -- Coral Energy Resources(1)........................ -- 15% -- Phillips Petroleum Company....................... -- -- 20% Coastal Corporation.............................. -- -- 15% Koch Oil Company................................. -- -- 15%
(1) These entities are affiliates of Shell. We believe that the loss of any of these purchasers would not have a material adverse effect on the results of operations because other purchasers for our oil and natural gas are available. -10- 11 MARKET CONDITIONS Our revenues, profitability and future rate of growth substantially depend on prevailing prices for oil and natural gas. Oil and natural gas prices have been extremely volatile in recent years and are affected by many factors outside our control. Since 1992, prices for West Texas Intermediate crude have ranged from $8.00 to $29.00 per Bbl and the monthly average of the Gulf Coast spot market natural gas price at Henry Hub, Louisiana, has ranged from $1.08 to $3.97 per MMBtu. The average price we received during the year ended December 31, 1999, was $2.68 per Mcfe compared to $2.11 per Mcfe during the year ended December 31, 1998. The volatile nature of the energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices would have a material adverse effect on our results of operations and financial condition. The marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and natural gas production and transportation, general economic conditions, changes in supply and changes in demand could adversely affect our ability to produce and market our oil and natural gas. If market factors were to change dramatically, the financial impact on us could be substantial. We do not control the availability of markets and the volatility of product prices are beyond our control and therefore represent significant risks. COMPETITION The oil and natural gas industry is highly competitive for prospects, acreage (including offshore in the Gulf of Mexico) and capital. Our competitors include numerous major and independent oil and natural gas companies, individual proprietors, drilling and income programs and partnerships. Many of these competitors possess and employ financial and personnel resources substantially in excess of those available to us and may, therefore, be able to define, evaluate, bid for and purchase more oil and natural gas properties. There is intense competition in marketing oil and natural gas production, and there is competition with other industries to supply the energy and fuel needs of consumers. At present, we compete with Shell in the Gulf of Mexico for offshore prospects and we anticipate that such competition will continue. Shell also retains, and may obtain in the future, interests in producing properties and exploration prospects in Louisiana state waters and adjacent onshore areas where Shell competes with us. In addition, although Shell currently does not have any significant working interests in producing properties or exploration prospects onshore in south Louisiana, and has indicated to us that it does not currently intend to obtain any such interests, it may do so in the future. REGULATION The availability of a ready market for any oil and natural gas production depends on numerous factors that we do not control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be "shut-in" because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between multiple owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. Oil and natural gas production operations are subject to various types of regulation by state and federal agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. In addition, numerous departments and agencies, both federal and state, are authorized by statute -11- 12 to issue rules and regulations that bind the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects its profitability. All of our federal offshore oil and gas leases are granted by the federal government and are administered by the Mineral Management Service (the "MMS"). These leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations and the calculation of royalty payments to the federal government. Ownership interests in these leases generally are restricted to United States citizens and domestic corporations. The MMS must approve any assignments of these leases or interests therein. The federal authorities, as well as many state authorities, require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. These 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. The statutes and regulations of the federal authorities, as well as many state authorities, limit the rates at which we can produce oil and gas on our properties. Federal Regulation Prior to January 1993, the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Policy Act of 1978 ("NGPA"), prescribed maximum lawful prices for natural gas sales. Effective January 1, 1993, natural gas prices were completely deregulated. Consequently, sales of our natural gas after such date have been made at market prices. The FERC regulates interstate natural gas pipeline transportation rates and service conditions, both of which affect the marketing of gas produced by us, as well as the revenues received for sales of such gas. Since the latter part of 1985, culminating in 1992 in the Order No. 636 series of orders, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. The FERC believes "open access" policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put gas sellers into more direct contractual relations with gas buyers. As a result of the Order No. 636 program, the marketing and pricing of natural gas has been significantly altered. The interstate pipelines' traditional role as wholesalers of natural gas has been terminated and replaced by regulations which require pipelines to provide transportation and storage service to others who buy and sell natural gas. In addition, on February 9, 2000, FERC issued Order No. 637 and promulgated new regulations designed to refine the Order No. 636 "open access" policies and revise the rules applicable to capacity release transactions. These new rules will, among other things, permit existing holders of firm capacity to release or "sell" their capacity to others at rates in excess of FERC's regulated rate for transportation services. It is unclear what impact, if any, these new rules or increased competition within the natural gas transportation industry will have on us and our gas sales efforts. It is not possible to predict what, if any, effect the FERC's open access or future policies will have on us. Additional proposals and/or proceedings that might affect the natural gas industry may be considered by FERC, Congress, or state regulatory bodies. It is not possible to predict when or if any of these proposals may become effective or what effect, if any, they may have on our operations. We do not believe, however, that our operations will be affected any differently than other gas producers or marketers with which we compete. -12- 13 Oil Price Controls Our sales of crude oil, condensate and gas liquids are not regulated and are made at market prices. State Regulation of Oil and Natural Gas Production States where we conduct our oil and natural gas activities regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas and resources. In addition, most states regulate the rate of production and may establish maximum daily production allowables for wells on a market demand or conservation basis. Environmental Regulation Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require us to acquire a permit before we commence drilling, restrict the types, quantities and concentration of various substances that we can release into the environment in connection with drilling and production activities, limit or prohibit our drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Moreover, the general trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, as discussed below, legislation has been proposed in Congress from time to time that would cause certain oil and gas exploration and production wastes to be classified as "hazardous wastes", which would make the wastes subject to much more stringent handling and disposal requirements. If such legislation were enacted, it could have a significant impact on our operating costs, as well as on the operating costs of the oil and natural gas industry in general. Initiatives to further regulate the disposal of oil and gas wastes have also been considered in the past by certain states, and these various initiatives could have a similar impact on us. We believe that our current operations substantially comply with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. OPA. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of the area where an offshore facility is located. The OPA makes each responsible party liable for oil-removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the party caused the spill by gross negligence or willful misconduct or if the spill resulted from a violation of a federal safety, construction or operating regulation. The liability limits likewise do not apply if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on a responsible party, including the requirement to maintain proof of financial responsibility to be able to cover at least some costs if a spill occurs. In this regard, the OPA requires the lessee or permittee of an offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35 million ($10 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to a crude oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150 million depending on the risk represented by the quantity or quality of crude oil that is handled by the facility. The MMS has promulgated regulations that implement the financial responsibility requirements of the OPA. Under the MMS regulations, the amount of financial responsibility required for an offshore facility is increased above the minimum amount if the "worst case" oil spill volume calculated for the facility exceeds certain limits established in the regulations. -13- 14 The OPA also imposes other requirements, such as the preparation of an oil-spill contingency plan. We have such a plan in place. Failure to comply with ongoing requirements or inadequate cooperation during a spill may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under the OPA and we believe that compliance with the OPA's financial responsibility and other operating requirements will not have a material adverse impact on us. CERCLA. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, and comparable state statutes impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, persons or companies that are statutorily liable for a release could be subject to joint-and-several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We have not been notified by any governmental agency or third party that we are responsible under CERCLA or a comparable state statute for a release of hazardous substances. Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended (the "Clean Water Act"), imposes restrictions and controls on the discharge of produced waters and other oil and gas wastes into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into certain coastal and offshore water. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges for oil and other hazardous substances and imposes liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. Comparable state statutes impose liability and authorize penalties in the case of an unauthorized discharge of petroleum or its derivatives, or other hazardous substances, into state waters. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution. Resources Conservation Recovery Act. The Resource Conservation Recovery Act ("RCRA") is the principle federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most crude oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA's requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes crude oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses. -14- 15 TITLE TO PROPERTIES As is customary in the oil and natural gas industry, we make only a cursory review of title to undeveloped oil and natural gas leases at the time we acquire them. However, before drilling commences, we search the title, and remedy any material defects before we actually begin drilling the well. To the extent title opinions or other investigations reflect title defects, we (rather than the seller or lessor of the undeveloped property) typically are obligated to cure any such title defects at our expense. If we are unable to remedy or cure any title defects so that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of its entire investment in the property. We believe that we have good title to our oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. Under the terms of our credit facility, we may not grant liens on various properties and must grant to our lenders a lien on such property in the event of certain defaults. Our own oil and natural gas properties also typically are subject to royalty and other similar noncost-bearing interests customary in the industry. We acquired substantial portions of our 3-D seismic data through licenses and other similar arrangements. Such licenses contain transfer and other restrictions customary in the industry. -15- 16 ITEM 2. PROPERTIES PRODUCING PROPERTIES For information regarding Meridian's properties, see "Item 1. Business" above. ITEM 3. LEGAL PROCEEDINGS In June 1996, Amoco Production Company ("Amoco") filed suit against us in Louisiana State Court in Calcasieu Parish with respect to a dispute involving our drilling of our Ben Todd No. 1 (TMRC) well in the Southwest Holmwood Field in which we and Amoco each hold a 50% leasehold interest. The case was removed to the United States District Court for the Western District of Louisiana in July 1996. We drilled the Ben Todd No. 1 (TMRC) well under a Participation Agreement between us and Amoco pursuant to which Amoco had a right to participate in the well. We drilled the well after providing notice to Amoco pursuant to the participation agreement that we intended to drill the well and that Amoco had failed to take action to elect to participate in the well. Amoco alleged in its suit that the Participation Agreement did not permit us to drill the well and sought to recover all the revenues from the well or to stop us from producing from the well. Amoco requested that the trial court cancel the Participation Agreement and our leasehold interest in the prospect, which included our 50% interest in the Ben Todd No. 2 (Amoco) well that Amoco drilled prior to the Ben Todd No. 1 (TMRC) well on an agreed basis. We filed counterclaims for breach of contract, unfair practices and other claims. On December 22, 1997, the United States District Court for the Western District of Louisiana entered a judgment against us in this matter and ordered that the Participation Agreement did not permit us to drill the Ben Todd No. 1 (TMRC) well and that the Participation Agreement and related lease had been terminated by virtue of our drilling the well. The trial court also dismissed our counterclaims against Amoco. The trial court further ordered a reversion of our rights to the Ben Todd No. 1 (TMRC) well and the Ben Todd No. 2 (Amoco) well and directed us to account for all production and monies we received from the date of the cancellation of the lease. We recorded a charge of $6.2 million in the fourth quarter of 1997, representing our estimated portion of the potential loss. We have reported no reserves related to these properties as of December 31, 1997 or thereafter. In July 1999, the United States Court of Appeals for the Fifth Circuit upheld the trial court's decision. In September 1999, we satisfied all payment obligations of the judgment, including post judgment interest and attorneys fees, by payment to Amoco of approximately $5.7 million net to us. In November 1998, Enron Capital & Trade Resources Corp. ("Enron") filed an action in the District Court of Harris County, Texas, 11th Judicial District, Texas, which was a proceeding against certain Shell affiliates ("Shell") and us. The pleadings alleged causes of action against Shell and us for trespass and tortious interference with contract and sought declaratory and injunctive relief. Enron further asserted that our drilling and operation of certain Louisiana oil and gas wells had and would trespass upon Enron's Louisiana property interests and tortiously interfere with a Participation Agreement dated June 12, 1996 between Enron and Shell. Enron asserted that it was being denied its right to participate in certain drilling projects allegedly included under the Participation Agreement, including interests in wells drilled in the Weeks Island Field. In response to Enron's claims, we filed an action against Enron in the 31st Judicial District for the Parish of Jefferson Davis, Louisiana seeking injunctive relief from Enron's interference with our rights to operate our wells and properties located in Louisiana that we purchased and contracted with Shell to own and operate. In December 1999, Enron, Shell and Meridian executed settlement agreements with respect to this matter, the terms of which will not have a material adverse effect on our financial condition or results of operations. There are no other material legal proceedings to which Meridian or any of its subsidiaries or partnerships is a party or by which any of its property is subject, other than ordinary and routine litigation incidental to the business of producing and exploring for crude oil and natural gas. -16- 17 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of Meridian's security holders during the fourth quarter of 1999. -17- 18 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY Our Common Stock is traded on the New York Stock Exchange under the symbol "TMR." The following table sets forth, for the periods indicated, the high and low sale prices per share for the Common Stock as reported on the New York Stock Exchange:
HIGH LOW --------- ------- 1999: First quarter ................................................... 3 7/8 2 Second quarter .................................................. 6 7/16 2 15/16 Third quarter ................................................... 5 3/4 3 1/2 Fourth quarter .................................................. 5 3/16 2 9/16 1998: First quarter ................................................... 9 9/16 7 3/16 Second quarter .................................................. 9 7/16 6 1/8 Third quarter ................................................... 7 1/4 2 3/4 Fourth quarter .................................................. 5 1/2 2
The closing sale price of the Common Stock on March 7, 2000, as reported on the New York Stock Exchange Composite Tape, was $4.125. As of March 7, 2000, we had approximately 924 shareholders of record. Meridian has not paid cash dividends on the common stock and does not intend to pay cash dividends on the Common Stock in the foreseeable future. We currently intend to retain our cash for the continued development of our business, including exploratory and development drilling activities. We also are currently restricted under our Chase Manhattan Bank Credit Agreement from expending more than $2.0 million in the aggregate for cash dividends on the Common Stock or for purchase of shares of Common Stock without the prior consent of the lender. -18- 19 ITEM 6. SELECTED FINANCIAL DATA All financial data should be read in conjunction with our Consolidated Financial Statements and related notes thereto included elsewhere in this report.
YEAR ENDED DECEMBER 31, 1999 1998 1997 1996 1995 --------- -------- -------- -------- -------- (In thousands, except prices and per share information) A. SUMMARY OF OPERATING DATA Production: Oil (MBbls) 4,454 2,365 914 751 650 Natural gas (MMcf) 22,711 20,603 14,603 15,783 14,598 Natural gas equivalent (MMcfe) 49,438 34,793 20,087 20,289 18,498 Average Prices: Oil ($/Bbl) $ 17.61 $ 12.19 $ 19.72 $ 21.92 $ 18.04 Natural gas ($/Mcf) 2.38 2.16 2.70 2.44 1.71 Natural gas equivalent ($/Mcfe) 2.68 2.11 2.86 2.71 1.99 B. SUMMARY OF OPERATIONS Total revenues $ 133,361 $ 74,026 $ 58,333 $ 56,733 $ 38,230 Depletion and depreciation 54,222 45,390 26,337 25,342 18,491 Net earnings (loss)(1) 11,467 (230,708) (28,541) 16,692 7,458 Net earnings (loss) per share:(1) Basic $ 0.25 $ (5.80) $ (0.85) $ 0.50 $ 0.25 Diluted 0.25 (5.80) (0.85) 0.47 0.23 Dividends per: Common share -- -- -- -- -- Preferred share $ 1.36 $ 0.68 -- -- -- Weighted average common shares outstanding 45,995 39,774 33,383 33,399 30,207 C. SUMMARY BALANCE SHEET DATA Total assets $ 477,719 $ 445,175 $ 292,558 $ 245,757 $ 193,134 Long-term obligations, inclusive of current maturities 270,000 240,084 107,195 42,000 15,500 Stockholders' equity 163,860 148,808 145,102 171,432 154,924
(1) Applicable to common stockholders. -19- 20 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL The Meridian Resource Corporation is an independent oil and natural gas exploration and production company with operations primarily focused in the onshore and offshore south Louisiana and southeast Texas Gulf Coast region. As an integral part of our business strategy, we take a very disciplined approach to each project and incorporate 3-D seismic over every prospective area prior to our drilling of a first well. We place emphasis on the research and development of every technological tool available and applicable to each prospect prior to commencing drilling. As of December 31, 1999, Meridian's reserves totaled 365 Bcfe, representing an increase of 20% over year-end 1998, with a present value of future net cash flows before income taxes of $596 million, an increase of $303 million, or 103%, over year-end 1998, based on prices of $25.81 per Bbl of oil and $2.48 per Mcf of natural gas. Our reserves are comprised of approximately 55% natural gas with 69% being proved developed reserves and 31% proved undeveloped reserves and have an average reserve life of 7 years. In addition to the proved reserves, Meridian holds 125,915 net undeveloped acres, 53,845 net developed acres, rights and licenses to over 4,300 square miles of 3-D seismic data and access to over 156,065 miles of 2-D seismic data. We believe that we are in a strong position relative to others in our industry who compete in the south Louisiana and southeast Texas onshore transition zone region. The difference is several fold and includes primarily (1) our technical and professional staff and its experience in exploring for and producing oil and natural gas in our focus area at low relative costs; (2) our large land and seismic inventories which form the foundation of the Company's future prospects and growth; (3) our method of approach to the development of original prospects and the understanding of what works best technically in our region; and (4) our relationship with Shell Oil Company ("Shell") as a 40% shareholder and access to its technical research and entire 2-D seismic inventory in south Louisiana. Because of the Shell acquisition and merger, we are now in a better position to balance the allocation of capital expenditures between our exploration activities and development/exploitation activities, which provides us with greater flexibility during the volatile price environments we have experienced in the past. The same holds true for calendar year 2000 and the projects currently scheduled for drilling. Management has set out and taken an aggressive "three-point" plan designed to improve profitability and shareholder value, reduce debt and increase reserves and production levels. The first step is the potential sale of approximately 20% of the Company's daily production. Chase Securities has been retained to represent Meridian in this process with bids due on April 6, 2000. The proceeds of the proposed sale would be primarily used to reduce the Company's bank debt, which would result in lower interest costs, and would reduce lease operating expenses and general and administrative costs. Second, Meridian is in discussions with Shell regarding the Stock Rights and Restrictions Agreement to which the Company and an affiliate of Shell are parties. This issue is being addressed by both Meridian and Shell to achieve the best results for ultimate shareholder value. Third, we have established a budget plan that, based on our reasonable expectations of product prices ($22.00 per Bbl of oil and $2.40 per Mcf of natural gas), will provide Meridian with an $85 million capital budget for the year 2000 to further expose the Company to high impact prospects. Key fields of interest which we will be focusing on this year include North Turtle Bayou/Ramos, Weeks Island, Thornwell, Turtle Bayou and South Timbalier Block 139. -20- 21 Industry Conditions. Our revenues, profitability and future rate of growth are substantially dependent upon prevailing prices for oil and natural gas. Oil and natural gas prices have been extremely volatile in recent years and are affected by many factors outside of our control. In this regard, average worldwide oil and natural gas prices have increased substantially from levels existing during 1998. As a result of these increases, the average price received by us during the year ended December 31, 1999 was $2.68 per Mcfe compared to $2.11 per Mcfe during the year ended December 31, 1998. These industry conditions, and any continuation thereof, will have several important consequences to us, including the level of cash flow received from our producing properties, the timing of exploration of certain prospects and our access to capital markets, which could impact our revenues, profitability and ability to maintain or increase its exploration and development program. Shell Transactions. On June 30, 1998, we acquired (the "LOPI Transaction") Louisiana Onshore Properties Inc. ("LOPI"), an indirect subsidiary of Shell, pursuant to a merger of a wholly-owned subsidiary with LOPI. The consideration paid in the LOPI Transaction consisted of 12,082,030 shares of our common stock, $.01 par value ("Common Stock"), and a new issue of convertible preferred stock (the "Preferred Stock") that is convertible into 12,837,428 shares of Common Stock, which together provided Shell Louisiana Onshore Properties Inc., an indirect subsidiary of Shell ("SLOPI"), with beneficial ownership of 39.9% of our common stock on a fully-diluted basis assuming the exercise of all outstanding stock options and warrants and conversion of all Preferred Stock. In a transaction separate from the LOPI Transaction, we also acquired on June 30, 1998 from Shell Western E&P Inc., an indirect subsidiary of Shell ("SWEPI"), various other oil and gas property interests located onshore in south Louisiana for a total cash consideration of $38.6 million (the "SWEPI Acquisition"). The LOPI Transaction and the SWEPI Acquisition (together, the "Shell Transactions") were effected to substantially increase our reserves, lease acreage positions and exploration prospects in Louisiana. The Shell Transactions were accounted for utilizing the purchase method of accounting. Therefore, operations relating to the Shell properties are included in our results of operations beginning with the third quarter of 1998. Cairn Merger. On November 5, 1997, we consummated a merger (the "Cairn Merger") with Cairn Energy USA, Inc. ("Cairn"). In connection with the Cairn Merger, we issued approximately 19.0 million shares of Common Stock. We recorded a one-time charge in the fourth quarter of 1997 of approximately $10 million for costs associated with the Cairn Merger. Ceiling Test Write-down. During 1999, crude oil and natural gas prices were significantly improved over 1998. Therefore, no write-down of the value of our oil and natural gas properties was recorded. A significant decline in oil and natural gas prices was the primary cause of our recognition of $245.0 million of non-cash write-downs of its oil and natural gas properties under the full cost method of accounting during 1998. Due to the potential volatility in oil and gas prices and their effect on the carrying value of our proved oil and gas reserves, there can be no assurance that future write-downs will not be required as a result of factors that may negatively affect the present value of proved oil and natural gas reserves and the carrying value of oil and natural gas properties, including volatile oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve quantities and unsuccessful drilling activities. -21- 22 RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998 Operating Revenues and Production. Oil and natural gas revenues increased $59.2 million as a result of increased volumes and improved prices. The production increase was a direct result of the inclusion of results for the entire year from the Louisiana properties purchased from Shell as compared to their inclusion for only six months for 1998, as well as new wells being placed on production during 1999. The following table summarizes Meridian's operating revenues, production volumes and average sales prices for the years ended December 31, 1999 and 1998.
Year Ended December 31, Increase 1999 1998 (Decrease) ---------- ---------- ---------- Production: Oil (MBbls) 4,454 2,365 88% Natural gas (MMcf) 22,711 20,603 10% Natural gas equivalent (MMcfe) 49,438 34,793 42% Average Sales Price: Oil (per Bbl) $ 17.61 $ 12.19 44% Natural gas (per Mcf) 2.38 2.16 10% Natural gas equivalent (per Mcfe) 2.68 2.11 27% Gross Revenues (000's): Oil $ 78,447 $ 28,911 171% Natural gas 54,129 44,425 22% ---------- ---------- ---------- Total $ 132,576 $ 73,336 81% ========== ========== ==========
Operating Expenses. Oil and natural gas operating expenses increased $1.8 million to $14.6 million in 1999, compared to $12.8 million in 1998. The increase was primarily due to the additional operating expenses related to increased production and the inclusion of costs and expenses from the Shell properties for the full year as well as new wells brought on production in the last twelve months, but reflects an actual decrease in operating costs to $0.30 per Mcfe for 1999 compared to $0.37 per Mcfe for 1998. This reduction was due to our efforts to reduce operating costs on all of our properties, especially those purchased from Shell which had a higher cost of operations associated with them upon assuming control on June 30, 1998. Severance and Ad Valorem Taxes. Severance and ad valorem taxes increased $7.2 million to $11.3 million in 1999, compared to $4.1 million in 1998. Meridian's oil and natural gas is primarily produced from south Louisiana, and, therefore, is subject to Louisiana's severance tax. Louisiana's severance tax rates are $0.078 per Mcf for natural gas and 12.5% of gross oil revenue. Our 1999 severance tax increase of $7.2 million was largely tied to the increase of oil and natural gas production over 1998 and the fact that our average oil price increased 44% over last year. -22- 23 Depletion and Depreciation. Depletion and depreciation expenses increased $8.8 million to $54.2 million in 1999, compared to $45.4 million in 1998. The increase is primarily due to the increased production in 1999 over 1998 levels. General and Administrative Expense. General and administrative expenses increased $4.3 million to $13.9 million in 1999, compared to $9.6 million in 1998. This increase was primarily a result of increases in salaries, wages, other compensation and related employee costs associated with the increase in employees related to the Shell properties acquisition and the development and exploitation opportunities associated with the properties and the 3-D seismic surveys covering them. In addition, because of increased oil and natural gas volumes and prices, the net profit interest distributions increased accordingly. Interest Expense. Interest expense increased $9.7 million to $22.9 million in 1999 compared to $13.2 million in 1998. The increase is primarily a result of additional borrowings under the credit facility for the full year of 1999 versus only one half year for 1998, and the issuance in June 1999 of $20 million of 9 1/2% Convertible Subordinated Notes, due June 18, 2005. These additional funds were utilized in our capital expenditures program to further the exploration and development activities during a period when many in the industry were not as active in their drilling programs and drilling and service costs were lower. -23- 24 YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997 Operating Revenues and Production. The $15.7 million increase in operating revenues was primarily due to increased volumes, partially offset by lower prices for all products. The increase in production was a direct result of the addition of the Shell properties at June 30, 1998, as well as offshore platforms and new wells brought online in 1998. The following table summarizes Meridian's operating revenues, production volumes and average sales prices for the years ended December 31, 1998 and 1997.
Year Ended December 31, Increase 1998 1997 (Decrease) --------- --------- --------- Production: Oil (MBbls) 2,365 914 159% Natural gas (MMcf) 20,603 14,603 41% Natural gas equivalent (MMcfe) 34,793 20,087 73% Average Sales Price: Oil (per Bbl) $ 12.19 $ 19.72 (38%) Natural gas (per Mcf) 2.16 2.70 (20%) Natural gas equivalent (per Mcfe) 2.11 2.86 (26%) Gross Revenues (000's): Oil $ 28,911 $ 18,242 58% Natural gas 44,425 39,398 13% --------- --------- --------- Total $ 73,336 $ 57,640 27% ========= ========= =========
Operating Expenses. Oil and natural gas operating expenses increased $7.1 million to $12.8 million in 1998, compared to $5.7 million in 1997. The increase was primarily due to the additional operating expenses related to the inclusion of costs and expenses from the Shell properties as well as new wells brought on production in 1998. Operating expenses increased 32% in 1998 to $0.37 per Mcfe from $0.28 per Mcfe for 1997. This increase was primarily attributable to the operating costs for the more mature fields acquired from Shell being higher than those of our existing properties with higher per well flow rates. Severance and Ad Valorem Taxes. Severance and ad valorem taxes increased $1.9 million to $4.1 million in 1998, compared to $2.2 million in 1997. This increase is largely attributed to the additional production as a result of the purchase of the Shell properties, which are located entirely onshore south Louisiana and subject to Louisiana's severance tax rates of $0.078 per Mcf for natural gas and 12.5% of gross oil revenue. Depletion and Depreciation. Depletion and depreciation expenses increased $19.1 million to $45.4 million in 1998, compared to $26.3 million in 1997. The increase is primarily due to the increased production levels for 1998 over 1997. -24- 25 General and Administrative Expense. General and administrative expenses increased $2.4 million to $9.6 million in 1998, compared to $7.2 million in 1997. This increase was primarily a result of increases in salaries and wages and related employee costs associated with the increase in employees related to the Shell and Cairn acquisitions and the development and exploitation opportunities associated with the properties and the 3-D seismic surveys covering them. Interest Expense. Interest expense increased $8.1 million to $13.2 million in 1998 compared to $5.1 million in 1997. The increase is a combination of increased borrowings of approximately $37 million utilized to fund the purchase of certain properties in the Shell Transactions and continued borrowings to fund our capital expenditures program to further the exploration and development activities during 1998, when many in the industry were not as active in their drilling programs and drilling and service costs were lower. Impairment of Long-Lived Assets. As previously described, during 1998 we recorded write-downs totaling $245 million of its oil and natural gas properties under the full cost method of accounting due to significant decreases in crude oil and natural gas prices. Income Tax Expense. We recognized a $28.1 million deferred income tax benefit in 1998 associated with the reduction in the difference between book and income tax bases, principally due to the previously described oil and gas property write-downs. -25- 26 LIQUIDITY AND CAPITAL RESOURCES WORKING CAPITAL. During 1999, our liquidity needs were met from cash from operations, additional borrowings under the credit facility and the proceeds of $20 million from the 9 1/2% Convertible Subordinated Notes issued in June 1999. As of December 31, 1999, we had a cash balance of $6.6 million and a working capital deficit of $7.4 million. The decrease in the cash balance and the increase in the working capital deficit from levels existing at December 31, 1998, primarily reflect the capital expenditures related to our continuing exploration and development activities. CREDIT FACILITY. We entered into an amended and restated credit facility with The Chase Manhattan Bank as Administrative Agent (the "Credit Facility") to provide for maximum borrowings, subject to borrowing base limitations, of up to $250 million. The borrowing base was reaffirmed on August 23, 1999, and is currently set at $250 million, with a scheduled redetermination on March 31, 2000. In addition to regularly scheduled semi-annual borrowing base redeterminations, the lenders under the Credit Facility have the right to redetermine the borrowing base at any time once during each calendar year and we have the right to obtain a redetermination by the banks of the borrowing base once during each calendar year. Borrowings under the Credit Facility are secured by pledges of the outstanding capital stock of our subsidiaries and a mortgage on all offshore oil and natural gas properties and several onshore oil and natural gas properties. Borrowings under the Credit Facility mature on May 22, 2003. The Credit Facility includes various restrictive covenants including an interest coverage ratio of 3.0 to 1.0, a minimum net worth requirement of approximately $82 million, and a total debt leverage ratio (based upon total indebtedness to 12-month trailing pro forma EBITDA) of 3.25 to 1.00 at December 31, 1999, and thereafter. Assuming that we continue to be successful in the development and exploration program during the next 12 months, management believes that we will be able to comply with the Credit Facility covenants primarily due to the increase in production scheduled to begin in the near-term at two of the most recent discoveries in addition to the positive effects of higher oil and natural gas prices; however, any declines in oil and natural gas commodity prices or unanticipated declines or delays in production may adversely affect the ability to comply with the Credit Facility covenants. Under the Credit Facility, as amended, we may secure either (i) an alternative base rate loan that bears interest at a rate per annum equal to the greater of the administrative agent's prime rate, a certificate of deposit based rate or a federal funds based rate plus 0.25% to 1.0% or (ii) a Eurodollar base rate loan that bears interest, generally, at a rate per annum equal to the London interbank offered rate plus 1.25% to 2.5%, depending on the ratio of the aggregate outstanding loans and letters of credit to the borrowing base. The Credit Facility also provides for commitment fees ranging from .3% to .5% per annum. LINE OF CREDIT AGREEMENT. We entered into a short-term committed line of credit with Chase Manhattan Bank for $5 million which will expire on January 1, 2001. The interest rate is Chase's prime rate plus 1%, and interest payments are due on the last day of March, June, September and December. It is renewable by mutual agreement of the parties. The full amount of this line was available to be drawn at December 31, 1999, and $3 million was available to be drawn at March 7, 2000. 9 1/2% CONVERTIBLE SUBORDINATED NOTES. During June 1999, we completed private placements of an aggregate of $20 million of our 9 1/2% Convertible Subordinated Notes due June 18, 2005 (the "Notes"). The Notes are unsecured and contain customary events of default, but do not contain any maintenance or other restrictive covenants. Interest is payable on a quarterly basis. The Notes are convertible at any time by the holders of the Notes into shares of our common stock, utilizing a conversion price of $7.00 per share (the "Conversion Price"). The Conversion Price is subject to customary anti-dilution provisions. The holders of the Notes have been granted registration rights with respect to the shares of Common Stock that are issued upon conversion of the Notes or issuance of the warrants discussed below. -26- 27 We may prepay the Notes at any time without penalty or premium; however, if we redeem or prepay the Notes on or before June 21, 2001, we will issue to the holders of the Notes warrants to purchase that number of shares of Common Stock into which such Notes would have been convertible on the date of prepayment. The warrants will have exercise prices equal to the Conversion Price in effect on the date of issuance and will expire on June 21, 2001, regardless of the date such warrants are issued. CAPITAL EXPENDITURES. Capital expenditures consisted of $108.2 million for property and equipment additions primarily related to exploration and development of various prospects, including leases, seismic data acquisitions, and drilling and completion costs. Results were as follows:
NET RESERVES FROM DISCOVERIES & EXTENSION CAPITAL WELLS DRILLED OIL GAS EXPENDITURES GROSS NET MBBLS MMCF ($000)(1) --------- --------- --------- --------- --------- Property acquisition expenditures $ 17,803 Exploration expenditures 15.0 8.3 6,382 71,484 52,739 Development expenditures 7.0 4.0 34,478 Other capital expenditures 3,171 --------- --------- --------- --------- --------- Total 22.0 12.3 6,382 71,484 $ 108,191 ========= ========= ========= ========= =========
(1) Capital expenditures include amounts associated with prior, current and future years discoveries and extensions of our net reserves. The capital expenditures budget for the year 2000 exploration and development program has been established at approximately $85 million. The final projects will be determined based on a variety of factors, including prevailing prices for oil and natural gas, our expectations as to future pricing and the level of cash flow from operations. We currently anticipate funding the 2000 budget utilizing cash flow from operations and any availability under our line of credit. We do not anticipate spending any additional capital other than that from cash flow for our exploration and development program. We anticipate that any excess cash flow from operations as a result of increased rates or prices beyond the above $85 million would be used to pay down our debt. C. M. THIBODAUX NO. 2. During late June 1999, the C. M. Thibodaux No. 2 well experienced uncontrolled gas flows and a fire for a short period, which was capped with a diverting well head. A replacement well, the C. M. Thibodaux No. 3, was drilled, completed in the same producing horizon and put on production at 12 MMcf of natural gas per day and 250 Bbls of associated condensate per day as reported in Meridian's press release dated November 12, 1999. No injuries to human life were sustained nor any pollution recorded by the state of Louisiana or U. S. Coast Guard as a result of this incident. We believe that we have adequate insurance coverage to substantially offset any economic losses and other damages arising out of these events, if any are proved to exist. POTENTIAL SALE OF PROPERTIES. In an effort to reduce bank debt and supplement internal cash flow to fund our inventory of exploration and development projects scheduled for drilling in 2000 and beyond, we announced on January 14, 2000, the initiation of a formal process to pursue the sale of certain non-strategic oil and gas properties located in south Louisiana, the Texas Gulf Coast and offshore in the Gulf of Mexico. The properties designated for sale account for approximately 20% of our current net average daily production, or approximately 30 Mmcfe per day. We cannot assure you that we will be able to find a buyer for such properties at a price that is acceptable to us. -27- 28 DIVIDENDS. It is our policy to retain existing cash for reinvestment in our business, and therefore, we do not anticipate that dividends will be paid with respect to the Common Stock in the foreseeable future. The Preferred Stock issued upon closing of the LOPI Transaction accrues an annual cash dividend of 4% of its stated value with the dividend ceasing to accrue incrementally on one-third of the shares of Preferred Stock on June 30, 2001, 2002 and 2003 so that no dividends will accrue on any shares of Preferred Stock after June 30, 2003. Dividends on the Preferred Stock aggregating $5.4 million were accrued for 1999, of which $2.7 million had been paid as of December 31, 1999. STOCK RIGHTS AND RESTRICTIONS AGREEMENT. In light of the large ownership position issued to SLOPI in the LOPI Transaction and in recognition of both Meridian's and SLOPI's desire that Meridian functions as an independent oil and gas company, we entered into a Stock Rights and Restrictions Agreement with SLOPI that defines and limits our respective rights and obligations. These agreements will limit SLOPI's and its affiliates' control while protecting their interests in the context of certain extraordinary transactions by (i) allowing SLOPI to maintain representation on our Board of Directors, (ii) restricting SLOPI's and its affiliates' ability to effect certain business combinations with us or to propose certain business combinations with us, (iii) restricting the ability of SLOPI and its affiliates to sell certain portions of their shares of Common Stock and Preferred Stock, subject to certain exceptions designed to permit them to sell those shares over time and to sell those shares in the event of certain business combinations involving us, (iv) limiting SLOPI's and its affiliates' discretionary voting rights to 23% of the total voting shares, except with respect to certain extraordinary events and in situations in which the price of the Common Stock for a period of time has been less than $5.50 per share or we are in material breach of our obligations under the agreements governing the LOPI Transaction, (v) permitting SLOPI and its affiliates to purchase additional amounts of our securities in order to maintain a 21% beneficial ownership interest in our Common Stock or securities convertible into our Common Stock, (vi) extending certain statutory and corporate restrictions on business combinations applicable to SLOPI and its affiliates and (vii) obligating us, at our option, to either issue a currently indeterminable number of additional shares of Common Stock in the future or pay cash in satisfaction of a make-whole provision contained in the Stock Rights and Restrictions Agreement in the event SLOPI ultimately receives less than approximately $10.52 per share on the sale of any Common Stock that is issuable upon conversion of the Preferred Stock. SLOPI currently is restricted from selling shares of Common Stock owned by it until July 1, 2000. Unless an earlier sale of shares is requested by Shell, and approved by the Meridian Board of Directors, Shell can only sell shares of Common Stock under SEC Reg. 144 or by requesting Meridian to permit the sale through one of eight registration rights granted to Shell for the period of its holding. Beginning on July 1, 2000, SLOPI may sell 25% of the Common Stock owned by it and may sell an incremental 25% of the Common Stock owned by it each year until June 30, 2004, at which time it is free to sell any Common Stock owned by it. SLOPI is prohibited from selling all of its common stock upon conversion of its preferred stock except as set out above. We are currently in discussion with Shell concerning terms and conditions of the Stock Rights and Restrictions Agreement. However, in the event SLOPI decided to sell all of the Common Stock issued to it upon conversion of the Preferred Stock at market prices existing on December 31, 1999, the make-whole provisions would be approximately $24 million per year or a total of $96 million after the four years. Meridian may satisfy this provision at its election in cash or Common Stock. Based on oil and natural gas prices effective December 31, 1999 and, assuming such oil and natural gas prices continue at or about those levels, we believe sufficient cash resources from operating activities will be generated during the year 2000 to pay any make-whole obligations owed to Shell in cash rather than issue Common Stock, and we believe it would make any such payments in cash assuming it is able to obtain the requisite waivers under the Credit Facility. This obligation could significantly dilute all holders of our Common Stock other than Shell, or significantly reduce our ability to raise additional funds for exploration and development. -28- 29 YEAR 2000 UPDATE In prior years, we discussed the nature and progress of our plans to ensure that our systems are Year 2000 compliant. In late 1999, we completed our remediation and testing of systems. As a result of those planning and implementation efforts, we experienced no significant disruptions in mission critical information technology and non-information technology systems and believe those systems successfully responded to the Year 2000 date change. We expensed less than $250,000 during 1999 in connection with remediating its systems. We are not aware of any material problems resulting from Year 2000 issues, either with our products, our internal systems, or the products and services of third parties. We will continue to monitor our mission critical computer applications and those of its suppliers and vendors throughout the year 2000 to ensure that any latent Year 2000 matters that may arise are addressed promptly. FORWARD-LOOKING INFORMATION From time to time, we may make certain statements that contain "forward-looking" information as defined in the Private Securities Litigation Reform Act of 1995 and that involve risk and uncertainty. These forward-looking statements may include, but are not limited to exploration and seismic acquisition plans, anticipated results from current and future exploration prospects, future capital expenditure plans, anticipated results from third party disputes and litigation, expectations regarding compliance with our credit facility, the anticipated results of wells based on logging data and production tests, future sales of production, earnings, margins, production levels and costs, market trends in the oil and natural gas industry and the exploration and development sector thereof, environmental and other expenditures and various business trends. Forward-looking statements may be made by management orally or in writing including, but not limited to, the Management's Discussion and Analysis of Financial Condition and Results of Operations section and other sections of our filings with the Securities and Exchange Commission under the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended. Actual results and trends in the future may differ materially depending on a variety of factors including, but not limited to the following: Changes in the price of oil and natural gas. The prices we receive for our oil and natural gas production and the level of such production are subject to wide fluctuations and depend on numerous factors that it does not control, including seasonality, worldwide economic conditions, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other oil-producing and natural-gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic government regulation, legislation and policies. Material declines in the prices received for oil and natural gas could make the actual results differ from those reflected in our forward-looking statements. Operating Risks. The occurrence of a significant event for which we are not fully insured against could have a material adverse effect on our financial position and results of operations. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater and shoreline contamination), blowouts, cratering, mechanical difficulties, fires, explosions, unusual or unexpected formation pressures, pollution and environmental hazards, each of which could result in damage to or destruction of oil and natural gas wells, production facilities or other property, or injury to persons. In addition, we are subject to other operating and production risks such as title problems, weather conditions, compliance with government permitting requirements, shortages of or delays in obtaining equipment, reductions in product prices, limitations in the market for products, litigation and disputes in the ordinary course of business. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against certain of these risks either because such insurance is not available or because of high premium costs. We cannot predict if or when any such risks could affect our operations. The occurrence of a significant event for which we are not adequately insured could cause our actual results to differ from those reflected in our forward-looking statements. -29- 30 Drilling Risks. Our decision to purchase, explore, develop or otherwise exploit a prospect or property will depend in part on the evaluation of data obtained through geophysical and geological analysis, production data and engineering studies, which are inherently imprecise. Therefore, we cannot assure you that all of our drilling activities will be successful or that we will not drill uneconomical wells. The occurrence of unexpected drilling results could cause the actual results to differ from those reflected in our forward-looking statements. Uncertainties in Estimating Reserves and Future Net Cash Flows. Reserve engineering is a subjective process of estimating the recovery from 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 judgement. Reserve estimates are inherently imprecise and may be expected to change as additional information becomes available. There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Because all reserve estimates are to some degree speculative, the quantities of oil and natural gas that we ultimately recover, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Significant downward revisions to our existing reserve estimates could cause the actual results to differ from those reflected in our forward-looking statements. -30- 31 ITEM 7. a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are currently exposed to market risk from hedging contracts changes and changes in interest rates. A discussion of the market risk exposure in financial instruments follows. HEDGING CONTRACTS Meridian addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. We enter into swaps and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at or prior to expiration or exchanged for physical delivery contracts. Meridian does not obtain collateral to support the agreements, but monitors the financial viability of counter-parties and believes its credit risk is minimal on these transactions. In the event of nonperformance, we would be exposed to price risk. Meridian has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. Effective July 16, 1999, we entered into certain hedging contracts as summarized in the table below. The Notional Amount is equal to the total net volumetric hedge position of Meridian during the periods. The positions effectively hedge approximately 60% of our current oil production. The fair values of the hedge are based on the difference between the strike price and the New York Mercantile Exchange future prices for the applicable trading months of 2000.
Weighted Average Fair Value at Notional Strike Price December 31, 1999 Amount ($ per unit) (in thousands) ----------- ---------------------- ----------------- Oil (MBbls): Floor Ceiling ------- --------- January 2000 - June 2000 1,274 $ 16.00 $ 24.00 $ (2,787)
INTEREST RATES We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Our long-term borrowings primarily consist of borrowings under the Credit Facility and the $20 million principal of 9 1/2% Convertible Subordinated Notes due June 18, 2005. Since borrowings under the Credit Facility float with prevailing interest rates (except for the applicable interest period for Eurodollar loans), the carrying value of borrowings under the Credit Facility should approximate the fair market value of such debt. Changes in interest rates, however, will change the cost of borrowing. Assuming $250 million remains borrowed under the Credit Facility, we estimate our annual interest expense will change by $2.5 million for each 100 basis point change in the applicable interest rates utilized under the Credit Facility. Changes in interest rates would, assuming all other things being equal, cause the fair market value of debt with a fixed interest rate, such as the Notes, to increase or decrease, and thus increase or decrease the amount required to refinance the debt. The fair value of the Notes is dependent on prevailing interest rates and our current stock price as it relates to the conversion price of $7.00 per share of our Common Stock. -31- 32 GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS The definitions set forth below apply to the indicated terms commonly used in the oil and natural gas industry and in this Form 10-K. Mcfe's are determined using the ratio of six Mcf of natural gas to one barrel of 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 substantially higher for crude oil than natural gas on an energy equivalent basis. Any reference to net wells or net acres was determined by multiplying gross wells or acres by our working percentage interest therein. "Bbl" means barrel and "Bbls" means barrels. "Bcf" means billion cubic feet. "Bcfe" means billion cubic feet of natural gas equivalent. "Btu" means British Thermal Unit. "EPA" means Environmental Protection Agency. "FERC" means the Federal Energy Regulatory Commission. "MBbls" means thousand barrels. "Mcf" means thousand cubic feet. "Mcfe" means thousand cubic feet of natural gas equivalent. "MMBbls" means million barrels. "MMBtu" means million Btus. "MMcf" means million cubic feet. "MMcfe" means million cubic feet of natural gas equivalent. "NGPA" means the Natural Gas Policy Act of 1978, as amended. "Present Value of Future Net Cash Flows" or "Present Value of Proved Reserves" means the present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. "Tcf" means trillion cubic feet. -32- 33 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Index to Financial Statements
Page ---- Report of Independent Auditors 34 Consolidated Statements of Operations -- For each of the three years in the period ended December 31, 1999 35 Consolidated Balance Sheets--December 31, 1999 and 1998 36 Consolidated Statements of Cash Flows -- For each of the three years in the period ended December 31, 1999 38 Consolidated Statements of Changes in Stockholders' Equity -- For each of the three years in the period ended December 31, 1999 39 Notes to Consolidated Financial Statements 40 Consolidated Supplemental Oil and Natural Gas Information (Unaudited) 57
-33- 34 REPORT OF INDEPENDENT AUDITORS Board of Directors and Stockholders The Meridian Resource Corporation We have audited the accompanying consolidated balance sheets of The Meridian Resource Corporation and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of The Meridian Resource Corporation and subsidiaries at December 31, 1999 and 1998, and the consolidated 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. ERNST & YOUNG LLP Houston, Texas February 23, 2000 -34- 35 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (thousands of dollars, except per share)
YEAR ENDED DECEMBER 31, ----------------------- 1999 1998 1997 --------- --------- --------- REVENUES: Oil and natural gas $ 132,576 $ 73,336 $ 57,640 Interest and other 785 690 693 --------- --------- --------- 133,361 74,026 58,333 --------- --------- --------- OPERATING COSTS AND EXPENSES: Oil and natural gas operating 14,604 12,841 5,680 Severance and ad valorem taxes 11,338 4,069 2,165 Depletion and depreciation 54,222 45,390 26,337 General and administrative 13,928 9,564 7,192 Impairment of long-lived assets -- 245,011 24,141 Merger expenses -- -- 9,998 Litigation expenses and loss provision (477) -- 6,205 --------- --------- --------- 93,615 316,875 81,718 --------- --------- --------- EARNINGS (LOSS) BEFORE INTEREST AND INCOME TAXES 39,746 (242,849) (23,385) --------- --------- --------- OTHER EXPENSES: Interest expense 22,879 13,211 5,149 Taxes on income -- (28,052) 7 --------- --------- --------- NET EARNINGS (LOSS) 16,867 (228,008) (28,541) DIVIDENDS ON PREFERRED STOCK 5,400 2,700 -- --------- --------- --------- NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCKHOLDERS $ 11,467 $(230,708) $ (28,541) ========= ========= ========= NET EARNINGS (LOSS) PER SHARE: Basic $ 0.25 $ (5.80) $ (0.85) ========= ========= ========= Diluted $ 0.25 $ (5.80) $ (0.85) ========= ========= ========= WEIGHTED AVERAGE NUMBER OF COMMON SHARES: Outstanding 45,995 39,774 33,383 ========= ========= ========= Assuming dilution 45,995 39,774 33,383 ========= ========= =========
See notes to consolidated financial statements. -35- 36 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (thousands of dollars)
DECEMBER 31, ------------------- 1999 1998 -------- -------- ASSETS CURRENT ASSETS: Cash and cash equivalents $ 6,617 $ 9,478 Accounts receivable, less allowance for doubtful accounts $1,003 [1999] and $121 [1998] 28,478 32,558 Due from affiliates 165 4,848 Prepaid expenses and other 1,234 1,394 -------- -------- Total current assets 36,494 48,278 -------- -------- PROPERTY AND EQUIPMENT: Oil and natural gas properties, full cost method (including $62,686,000 [1999] and $94,077,000 [1998] not subject to depletion) 916,495 820,322 Land 478 478 Equipment 8,737 6,775 -------- -------- 925,710 827,575 Accumulated depletion and depreciation 489,203 436,120 -------- -------- 436,507 391,455 -------- -------- OTHER ASSETS, NET 4,718 5,442 -------- -------- $477,719 $445,175 ======== ========
See notes to consolidated financial statements. -36- 37 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (continued) (thousands of dollars)
DECEMBER 31, ------------ 1999 1998 --------- --------- LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable $ 21,359 $ 19,138 Revenues and royalties payable 4,728 6,500 Accrued liabilities 17,772 24,440 Current maturities of long-term debt -- 84 --------- --------- Total current liabilities 43,859 50,162 --------- --------- LONG-TERM DEBT 250,000 240,000 --------- --------- 9 1/2% CONVERTIBLE SUBORDINATED NOTES 20,000 -- --------- --------- LITIGATION LIABILITIES -- 6,205 --------- --------- STOCKHOLDERS' EQUITY: Preferred stock, $1.00 par value (25,000,000 shares authorized 3,982,906 [1999 and 1998] shares of Series A Cumulative Convertible Preferred Stock issued at stated value) 135,000 135,000 Common stock, $0.01 par value (200,000,000 shares authorized, 46,409,980 [1999] and 45,817,319 [1998] issued) 472 461 Additional paid-in capital 274,298 270,477 Accumulated deficit (245,347) (256,814) Unrealized loss on securities held for resale (185) -- Unamortized deferred compensation (378) (293) 163,860 148,831 Treasury stock, at cost (none [1999] and 1,275 [1998] shares) -- (23) --------- --------- Total stockholders' equity 163,860 148,808 --------- --------- $ 477,719 $ 445,175 ========= =========
See notes to consolidated financial statements. -37- 38 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (thousands of dollars)
YEAR ENDED DECEMBER 31, ----------------------- 1999 1998 1997 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net earnings (loss) $ 16,867 $(228,008) $ (28,541) Adjustments to reconcile net earnings (loss) to net cash provided by operating activities: Depletion and depreciation 54,222 45,390 26,337 Amortization of other assets 1,244 345 671 Non-cash compensation 3,685 1,948 1,815 Impairment of long-lived assets -- 245,011 24,141 Deferred income taxes -- (28,052) -- Litigation expenses and loss provision -- -- 6,205 Changes in assets and liabilities: Accounts receivable 4,080 (21,638) 1,100 Due from affiliates 4,683 (1,810) (2,181) Prepaid expenses and other 160 (264) (543) Accounts payable 2,221 11,403 (2,793) Revenues and royalties payable (1,771) 509 461 Accrued liabilities and other (14,224) 2,760 4,063 --------- --------- --------- Net cash provided by operating activities 71,167 27,594 30,735 --------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment (108,191) (155,989) (111,901) Sale of property and equipment 8,917 2,045 -- --------- --------- --------- Net cash used in investing activities (99,274) (153,944) (111,901) --------- --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt 40,000 143,000 156,234 Reductions in long-term debt (10,084) (10,111) (91,039) Preferred dividends (4,050) (1,350) -- Exercise of stock options 85 1,293 396 Additions to deferred loan costs (705) (5,087) (47) --------- --------- --------- Net cash provided by financing activities 25,246 127,745 65,544 --------- --------- --------- NET CHANGE IN CASH AND CASH EQUIVALENTS (2,861) 1,395 (15,622) Cash and cash equivalents at beginning of year 9,478 8,083 23,705 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR $ 6,617 $ 9,478 $ 8,083 ========= ========= =========
See notes to consolidated financial statements. -38- 39 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999 (in thousands)
Preferred Stock Common Stock Additional Accumulated --------------- ------------ Paid-In Earnings Shares Par Value Shares Par Value Capital (Deficit) --------- --------- --------- --------- --------- --------- Balance, December 31, 1996 -- -- 33,422 334 170,086 2,435 Exercise of stock options -- -- 55 1 395 -- Company's 401(k) plan contribution -- -- 4 -- (57) -- Issuance of rights to common stock -- -- -- 1 1,599 -- Compensation expense -- -- -- -- -- -- Net loss -- -- -- -- -- (28,541) --------- --------- --------- --------- Balance, December 31, 1997 -- -- 33,481 336 172,023 (26,106) Exercise of stock options -- -- 254 3 1,290 -- Company's 401(k) plan contribution -- -- -- -- (487) -- Issuance of rights to common stock -- -- -- 1 1,599 -- Compensation expense -- -- -- -- -- -- Issuance of Shares - Shell Transaction: -- Preferred Stock 3,983 $ 135,000 -- -- -- -- Common Stock -- -- 12,082 121 96,052 -- Preferred dividends -- -- -- -- -- (2,700) Net loss -- -- -- -- -- (228,008) --------- --------- --------- --------- --------- --------- Balance, December 31, 1998 3,983 135,000 45,817 461 270,477 (256,814) Exercise of stock options -- -- 32 -- 85 -- Company's 401(k) plan contribution -- -- 138 2 562 -- Issuance of rights to common stock -- -- -- 5 1,492 -- Issuance of shares as compensation -- -- 423 4 1,682 -- Compensation expense -- -- -- -- -- -- Realization on securities held -- -- -- -- -- -- Preferred dividends -- -- -- -- -- (5,400) Net earnings -- -- -- -- -- 16,867 --------- --------- --------- --------- --------- --------- Balance, December 31, 1999 3,983 $ 135,000 46,410 $ 472 $ 274,298 $(245,347) ========= ========= ========= ========= ========= ========= Unamortized Unrealized Treasury Stock Deferred Loss On -------------- Compensation Securities Shares Cost Total --------- --------- --------- --------- --------- Balance, December 31, 1996 (343) -- 60 (1,080) 171,432 Exercise of stock options -- -- -- -- 396 Company's 401(k) plan contribution -- -- (13) 238 181 Issuance of rights to common stock (1,600) -- -- -- -- Compensation expense 1,634 -- -- -- 1,634 Net loss -- -- -- -- (28,541) --------- --------- --------- --------- --------- Balance, December 31, 1997 (309) -- 47 (842) 145,102 Exercise of stock options -- -- -- -- 1,293 Company's 401(k) plan contribution -- -- (46) 819 332 Issuance of rights to common stock (1,600) -- -- -- -- Compensation expense 1,616 -- -- -- 1,616 Issuance of Shares - Shell Transaction: Preferred Stock -- -- -- -- 135,000 Common Stock -- -- -- -- 96,173 Preferred dividends -- -- -- -- (2,700) Net loss -- -- -- -- (228,008) --------- --------- --------- --------- --------- Balance, December 31, 1998 (293) -- 1 (23) 148,808 Exercise of stock options -- -- -- -- 85 Company's 401(k) plan contribution -- -- (1) 23 587 Issuance of rights to common stock (1,497) -- -- -- - Issuance of shares as compensation -- -- -- -- 1,686 Compensation expense 1,412 -- -- -- 1,412 Realization on securities held -- (185) -- -- (185) Preferred dividends -- -- -- -- (5,400) Net earnings -- -- -- -- 16,867 --------- --------- --------- --------- --------- Balance, December 31, 1999 $ (378) (185) -- -- 163,860 ========= ========= ========= ========= =========
See notes to consolidated financial statements. -39- 40 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND BASIS OF PRESENTATION The Meridian Resource Corporation and its subsidiaries, (the "Company" or "Meridian") explores for, acquires, develops and produces oil and natural gas reserves, principally located onshore in south Louisiana, the Texas Gulf Coast and offshore in the Gulf of Mexico. The Company was initially organized in 1985 as a master limited partnership and operated as such until 1990 when it converted into a corporation through a merger with a limited partnership of which the Company was the sole limited and general partner. On November 5, 1997, Cairn Energy USA, Inc. ("Cairn") merged with a subsidiary of the Company. The merger was accounted for as a pooling of interests, and accordingly, the accompanying financial statements have been restated to include the financial position and results of operations of Cairn for all periods presented. The Company acquired in two separate transactions (the "Shell Transactions") certain Louisiana onshore properties from Shell Oil Company ("Shell") as described in note 7 below. The Shell Transactions were accounted for as purchases for financial accounting purposes. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. PROPERTY AND EQUIPMENT The Company follows the full cost method of accounting for its investments in oil and natural gas properties. All costs incurred with the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. Included in capitalized costs are general and administrative costs that are directly related with acquisition, exploration and development activities. Proceeds from the sale of oil and natural gas properties are credited to the full cost pool, unless the sale involves a significant quantity of reserves, in which case a gain or loss is recognized. Under the rules of the Securities and Exchange Commission ("SEC") for the full cost method of accounting, the net carrying value of oil and natural gas properties is limited to the sum of the present value (10% discount rate) of the estimated future net cash flows from proved reserves, based on the current prices and costs, plus the lower of cost or estimated fair market value of unproved properties. Capitalized costs of proved oil and natural gas properties are depleted on a unit of production method using proved oil and natural gas reserves. Costs depleted include net capitalized costs subject to depletion and estimated future dismantlement, restoration, and abandonment costs. Estimated future abandonment, dismantlement and site restoration costs include costs to dismantle, relocate and dispose of the Company's offshore production platforms, gathering systems, wells and related structures. Such costs related to onshore properties, net of estimated salvage values, are not expected to be significant. In January 1999, Meridian closed a property trade that exchanged substantially all of its properties located in East Cameron 349/350 in the Gulf of Mexico for three onshore Louisiana properties, $3.5 million in cash and other considerations. The effective date for this exchange was August 1, 1998. The Company accounted for the exchange of interests as a nonmonetary transaction whereby the basis in the exchanged properties became the new basis in the properties received as reduced by the cash consideration. No gain or loss was recognized as a result of the exchange of interests in accordance with the Statement of Financial Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies". -40- 41 Equipment, which includes computer equipment, hardware and software, furniture and fixtures, leasehold improvements and automobiles, is recorded at cost and is generally depreciated on a straight-line basis over the estimated useful lives of the assets, which range in periods of three to seven years. CASH AND CASH EQUIVALENTS For purposes of the statements of cash flows, cash equivalents include time deposits, certificates of deposit and all highly liquid instruments with original maturities of three months or less. The Company made cash payments for interest of $23.2 million, $12.3 million and $3.9 million in 1999, 1998 and 1997, respectively. Cash payments for income taxes amounted to $7,000 for 1997 and none for 1999 or 1998. CONCENTRATIONS OF CREDIT RISK Substantially all of the Company's receivables are due from oil and natural gas purchasers and other oil and natural gas producing companies located in the United States. Accounts receivable are generally not collateralized. Historically, credit losses incurred on receivables of the Company have been immaterial. REVENUE RECOGNITION Meridian recognizes oil and natural gas revenue from its interests in producing wells as oil and natural gas is produced and sold from those wells. Oil and natural gas sold is not significantly different from the Company's share of production. EARNINGS PER SHARE Basic earnings per share amounts are calculated based on the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share is based on the weighted average number of shares of common stock outstanding for the periods, including the dilutive effects of stock options and warrants granted. Dilutive options and warrants that are issued during a period or that expire or are canceled during a period are reflected in the computations for the time they were outstanding during the periods being reported. Options where the exercise price of the options exceeds the average price for the period are considered antidilutive, and therefore are not included in the calculation of dilutive shares. STOCK OPTIONS As permitted by SFAS No. 123, "Accounting for Stock Based Compensation," the Company will continue to follow the existing accounting requirements for stock options and stock-based awards contained in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations and consensus of the Emerging Issues Task Force in terms of measuring compensation expense. DERIVATIVE INSTRUMENTS The Company enters into swaps, options, collars and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and gas production. Realized gains and losses on settled derivative contracts are deferred and recognized as adjustments to oil and gas revenues in the applicable period(s) hedged. In applying hedge accounting, the Company periodically monitors the correlation of changes in the value of its derivative contracts with that of the prices the Company realized for its production. In the event of a lack of significant correlation, as might occur in the event of a major market disturbance, certain of the Company's derivative contracts no longer may qualify for hedge accounting, and would be marked to market accordingly. The Company may also enter into interest rate swaps to manage risk associated with interest rates and reduce the Company's exposure to interest rate fluctuations. Interest rate swaps are valued -41- 42 on a periodic basis, with resulting differences recognized as an adjustment to interest and other financing costs over the term of the agreement. The Company only enters into derivative contracts for hedging purposes. ACCOUNTING PRONOUNCEMENT In June 1999, the Financial Accounting Standards Board issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133," which is effective for fiscal years beginning after June 15, 2000, with earlier adoption encouraged. FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities," requires companies to record derivatives on the balance sheet as assets and liabilities, measured at fair value. Gains or losses resulting from changes in the values of those derivatives would be accounted for depending on the use of the derivative and whether it qualifies for hedge accounting. The Company has not yet determined what the effect, if any, of SFAS No. 133 will be on results of operations and financial position. The Company will adopt this accounting standard as required by January 1, 2001. 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. Actual results could differ from those estimates. RECLASSIFICATION OF PRIOR PERIOD STATEMENTS Certain reclassifications have been made to the prior period financial statements to conform to current year presentation. 3. IMPAIRMENT OF LONG-LIVED ASSETS A significant decline in oil and natural gas prices during 1998 and 1997 resulted in the Company recognizing non-cash write-downs totaling $245.0 million and $24.1 million, respectively, of its oil and natural gas properties under the full cost method of accounting. Due to the potential volatility in oil and gas prices and their effect on the carrying value of the Company's proved oil and gas reserves, there can be no assurance that future write-downs will not be required as a result of factors that may negatively affect the present value of proved oil and natural gas reserves and the carrying value of oil and natural gas properties, including volatile oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve quantities and unsuccessful drilling activities. 4. DEBT LONG-TERM DEBT In May 1998, the Company amended and restated the Company's credit facility with The Chase Manhattan Bank as Administrative Agent (the "Credit Facility") to provide for maximum borrowings, subject to borrowing base limitations, of up to $250 million. In November 1998, the Company amended the Credit Facility to increase the then-existing borrowing base from $200 million to $250 million. The borrowing base, currently set at $250 million, is scheduled to be redetermined on March 31, 2000. In addition to the regularly scheduled semi-annual borrowing base redeterminations, the lenders under the Credit Facility have the right to redetermine the borrowing base at any time once during each calendar year and the Company has the right to obtain a redetermination by the banks of the borrowing base once during each calendar year. Borrowings -42- 43 under the Credit Facility are secured by pledges of the outstanding capital stock of the Company's material subsidiaries and a mortgage of all of the Company's offshore oil and natural gas properties and several onshore oil and natural gas properties. In the event of a default, the Company is obligated to pledge additional properties representing, in the aggregate, at least 75% of its present value of proved properties. The Credit Facility contains various restrictive covenants, including, among other things, maintenance of certain financial ratios and restrictions on cash dividends on the Common Stock. Borrowings under the Credit Facility mature on May 22, 2003. The Credit Facility includes various restrictive covenants including an interest coverage ratio of 3.0 to 1.0, a minimum net worth requirement of approximately $82 million, and a total debt leverage ratio (based upon total indebtedness to 12-month trailing pro forma EBITDA) of 3.25 to 1.00 at December 31, 1999, and thereafter. Assuming that we continue to be successful in the development and exploration program during the next 12 months, management believes that we will be able to comply with the Credit Facility covenants primarily due to the increase in production scheduled to begin in the near-term at two of the most recent discoveries in addition to the positive effects of higher oil and natural gas prices; however, any declines in oil and natural gas commodity prices or unanticipated declines or delays in production may adversely affect the ability to comply with the Credit Facility covenants. Under the Credit Facility, as amended, the Company may secure either (i) an alternative base rate loan that bears interest at a rate per annum equal to the greatest of the administrative agent's prime rate, a certificate of deposit based rate or federal funds based rate plus 0.25% to 1.0% or (ii) a Eurodollar base rate loan that bears interest, generally, at a rate per annum equal to the London interbank offered rate plus 1.25% to 2.5%, depending on the Company's ratio of the aggregate outstanding loans and letters of credit to the borrowing base. The Credit Facility also provides for commitment fees ranging from .3% to .5% per annum. At December 31, 1999, the Company had outstanding borrowings of $250 million under the Credit Facility. LINE OF CREDIT AGREEMENT The Company entered into a short-term line of credit with Chase Manhattan Bank for $5 million on a committed basis. This credit line will expire on January 1, 2001. The interest rate is the Prime Rate plus 1%, and interest payments are due on the last day of March, June, September and December. It is renewable by mutual consent of the parties. The full amount was available to be drawn at December 31, 1999. 9 1/2% CONVERTIBLE SUBORDINATED NOTES During June 1999, the Company completed private placements of an aggregate of $20 million of its 9 1/2% Convertible Subordinated Notes due June 18, 2005 (the "Notes"). The Notes are unsecured and contain customary events of default, but do not contain any maintenance or other restrictive covenants. Interest is payable on a quarterly basis. The Notes are convertible at any time by the holders of the Notes into shares of the Company's common stock, $.01 par value ("Common Stock"), utilizing a conversion price of $7.00 per share (the "Conversion Price"). The Conversion Price is subject to customary anti-dilution provisions. The holders of the Notes have been granted registration rights with respect to the shares of Common Stock that are issued upon conversion of the Notes or issuance of the warrants discussed below. The Notes may be prepaid by the Company at any time without penalty or premium; however, in the event the Company redeems or prepays the Notes on or before June 21, 2001, the Company will issue to the holders of the Notes warrants to purchase that number of shares of Common Stock into which such Notes would have been convertible on the date of prepayment. Such warrants will have exercise prices equal to the Conversion Price in effect on the date of issuance and will expire on June 21, 2001, regardless of the date such warrants are issued. -43- 44 5. LEASE OBLIGATIONS The Company has a seven-year operating lease for office space with a primary term expiring in September 2006. The Company also has operating leases for equipment with various terms, none exceeding three years. Rental expense amounted to approximately $1.4 million, $0.7 million and $0.6 million in 1999, 1998 and 1997, respectively. Future minimum lease payments under all non-cancelable operating leases having initial terms of one year or more are estimated to be $1.3 million for each of the years 2000 - 2003, $1.4 million for the year 2004, and $2.7 million thereafter. 6. COMMITMENTS AND CONTINGENCIES LITIGATION In June 1996, Amoco Production Company ("Amoco") filed suit against us in Louisiana State Court in Calcasieu Parish with respect to a dispute involving our drilling of our Ben Todd No. 1 (TMRC) well in the Southwest Holmwood Field in which we and Amoco each hold a 50% leasehold interest. The case was removed to the United States District Court for the Western District of Louisiana in July 1996. We drilled the Ben Todd No. 1 (TMRC) well under a Participation Agreement between us and Amoco pursuant to which Amoco had a right to participate in the well. We drilled the well after providing notice to Amoco pursuant to the participation agreement that we intended to drill the well and that Amoco had failed to take action to elect to participate in the well. Amoco alleged in its suit that the Participation Agreement did not permit us to drill the well and sought to recover all the revenues from the well or to stop us from producing from the well. Amoco requested that the trial court cancel the Participation Agreement and our leasehold interest in the prospect, which included our 50% interest in the Ben Todd No. 2 (Amoco) well that Amoco drilled prior to the Ben Todd No. 1 (TMRC) well on an agreed basis. We filed counterclaims for breach of contract, unfair practices and other claims. On December 22, 1997, the United States District Court for the Western District of Louisiana entered a judgment against us in this matter and ordered that the Participation Agreement did not permit us to drill the Ben Todd No. 1 (TMRC) well and that the Participation Agreement and related lease had been terminated by virtue of our drilling the well. The trial court also dismissed our counterclaims against Amoco. The trial court further ordered a reversion of our rights to the Ben Todd No. 1 (TMRC) well and the Ben Todd No. 2 (Amoco) well and directed us to account for all production and monies we received from the date of the cancellation of the lease. We recorded a charge of $6.2 million in the fourth quarter of 1997, representing our estimated portion of the potential loss. We have reported no reserves related to these properties as of December 31, 1997 or thereafter. In July 1999, the United States Court of Appeals for the Fifth Circuit upheld the trial court's decision. In September 1999, we satisfied all payment obligations of the judgment, including post judgment interest and attorneys fees, by payment to Amoco of approximately $5.7 million net to us. In November 1998, Enron Capital & Trade Resources Corp. ("Enron") filed an action in the District Court of Harris County, Texas, 11th Judicial District, Texas, which was a proceeding against certain Shell affiliates ("Shell") and us. The pleadings alleged causes of action against Shell and us for trespass and tortious interference with contract and sought declaratory and injunctive relief. Enron further asserted that our drilling and operation of certain Louisiana oil and gas wells had and would trespass upon Enron's Louisiana property interests and tortiously interfere with a Participation Agreement dated June 12, 1996 between Enron and Shell. Enron asserted that it was being denied its right to participate in certain drilling projects allegedly included under the Participation Agreement, including interests in wells drilled in the Weeks Island Field. In response to Enron's claims, we filed an action against Enron in the 31st Judicial District for the Parish of Jefferson Davis, Louisiana seeking injunctive relief from Enron's interference with our rights to operate our wells and properties located in Louisiana that we purchased and contracted with Shell to own and operate. -44- 45 In December 1999, Enron, Shell and Meridian executed settlement agreements with respect to this matter, the terms of which will not have a material adverse effect on our financial condition or results of operations. There are no other material legal proceedings to which Meridian or any of its subsidiaries or partnerships is a party or by which any of its property is subject, other than ordinary and routine litigation incidental to the business of producing and exploring for crude oil and natural gas. 7. SHELL TRANSACTIONS On June 30, 1998, the Company acquired (the "LOPI Transaction") Louisiana Onshore Properties Inc. ("LOPI"), an indirect subsidiary of Shell, pursuant to a merger of a wholly-owned subsidiary of the Company with LOPI. The consideration paid in the LOPI Transaction consisted of 12,082,030 shares of the Company's common stock, $.01 par value ("Common Stock"), and a new issue of convertible preferred stock of the Company (the "Preferred Stock") that is convertible into 12,837,428 shares of Common Stock, which together provided Shell Louisiana Onshore Properties Inc., an indirect subsidiary of Shell ("SLOPI"), with beneficial ownership of 39.9% of the outstanding shares of Common Stock as of the closing of the LOPI Transaction, assuming exercise of all outstanding options and warrants and the conversion of the Preferred Stock. In a transaction separate from the LOPI Transaction, the Company also acquired on June 30, 1998 from Shell Western E&P, Inc., an indirect subsidiary of Shell, various other oil and gas property interests located onshore in south Louisiana for a total cash consideration of $38.6 million (together with the LOPI Transaction, the "Shell Transactions"). The combined purchase price of $303.5 million, including related deferred tax liability of $28 million, was allocated to oil and gas properties, including $37 million of unevaluated costs. The following summarized unaudited proforma financial information assumes the Shell Transactions occurred on January 1 of each of the years 1998 and 1997 (thousands of dollars, except per share):
PROFORMA INFORMATION YEAR ENDED DECEMBER 31, ----------------------- 1998 1997 ---- ---- Revenues $ 105,703 $ 159,361 Net loss $ (211,683) $ (50,618) Net loss per share $ (4.63) $ (1.23)
The pro forma results do not necessarily represent results that would have occurred if the transaction had taken place on the basis assumed above. 8. TAXES ON INCOME Provisions (benefits) for federal and state income taxes are as follows (thousands of dollars):
YEAR ENDED DECEMBER 31, ----------------------- 1999 1998 1997 ------------ ------------- ------------- Current -- -- $ 7 Deferred -- (28,052) -- ------------ ------------- ------------- -- $ (28,052) $ 7 ============ ============= =============
-45- 46 Income tax expense as reported is reconciled to the federal statutory rate (35%) as follows (thousands of dollars):
YEAR ENDED DECEMBER 31, ----------------------- 1999 1998 1997 ---------- ---------- ---------- Income tax provision (benefit) computed at statutory rate $ 5,903 $ (89,621) $ (9,987) Nondeductible costs 825 3,265 2,355 Decrease (increase) in percentage depletion carryover -- -- 18 Net operating loss carryforwards not benefited in the income tax provision -- 39,836 -- Change in valuation allowance (6,773) 18,328 7,597 Other 45 140 24 ---------- ---------- ---------- -- $ (28,052) $ 7 ========== ========== ==========
Deferred income taxes reflect the net tax effects of net operating losses, depletion carryovers, and temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company's deferred tax assets and liabilities are as follows (thousands of dollars):
DECEMBER 31, ------------ 1999 1998 ---------- ---------- Deferred tax assets: Net operating tax loss carryforward $ 60,108 $ 55,430 Statutory depletion carryforward 950 950 Other 2,130 3,596 Valuation allowance (20,309) (27,082) ---------- ---------- Total deferred tax assets 42,879 32,894 ---------- ---------- Deferred tax liabilities: Book in excess of tax basis in oil and gas properties 42,809 32,824 Basis differential in long-term investments 70 70 ---------- ---------- Total deferred tax liabilities 42,879 32,894 ---------- ---------- Net deferred tax asset (liability) -- -- ========== ==========
As of December 31, 1999, the Company has approximately $171.7 million of net operating loss carryforwards which begin to expire in 2005. Some of the net operating loss carryforwards are subject to change in ownership and separate return limitations. The net operating loss carryforwards assume that certain items, primarily intangible drilling costs, have been written off in the current year. However, the Company has not made a final determination if an election will be made to capitalize all or part of these items for tax purposes. -46- 47 9. STOCKHOLDERS' EQUITY PREFERRED STOCK On June 30, 1998, the Company issued to SLOPI 3,982,906 shares of the Company's Preferred Stock. The Preferred Stock has an aggregate stated value of $135 million and ranks prior to the Common Stock as to distribution of assets and payment of dividends. The Preferred Stock is entitled to receive, when and as declared by the Board of Directors, a cash dividend at the rate of 4% per annum on the stated value per share; provided, however, dividends shall cease to accrue on an incremental one-third of the shares of Preferred Stock on the third, fourth and fifth anniversaries of the LOPI Transaction so that no dividends will accrue on any shares of Preferred Stock after June 30, 2003. Each share of Preferred Stock is entitled to one vote on matters submitted to the Company's shareholders for their approval. Until the earlier of (i) the termination of a Stock Rights and Restrictions Agreement between SLOPI and the Company (the "Stock Rights and Restrictions Agreement") and (ii) SLOPI and its affiliates beneficially own less than 21% of the outstanding Common Stock, the holders of the Preferred Stock may elect at least one member of the Company's Board of Directors and additional members in the event the number of Board seats is increased to ten or more so that SLOPI is able to nominate that number of directors that equals the product (rounded downward to the nearest whole number, but in no event less than one) of the total number of directors following such election multiplied by 20%. The Preferred Stock may be converted into an aggregate of 12,837,428 shares of Common Stock at any time by the holder thereof. In addition, on or after June 30, 2001, the Preferred Stock will automatically convert into Common Stock in the event the mean Per Share Market Value (as defined in the Certificate of Designation) exceeds 150% of the conversion price, which is approximately $10.52 per share (the "Conversion Price"), for 75 consecutive trading days. In addition, pursuant to the Stock Rights and Restrictions Agreement, SLOPI is prohibited, subject to certain exceptions, from selling shares of Common Stock issued upon conversion of Preferred Stock until June 30, 2000, at which time SLOPI is permitted to sell approximately 25% of the Common Stock owned by it, and an incremental 25% each year until June 30, 2003, at which time it will be able to sell all shares of Common Stock owned by it. We are currently in discussion with Shell concerning terms and conditions of the Stock Rights and Restrictions Agreement. Pursuant to the Stock Rights and Restrictions Agreement, when SLOPI sells shares of Common Stock acquired upon conversion of the Preferred Stock at a share price less than approximately $10.52, the Conversion Price, the Company has agreed to pay to SLOPI the difference between the sale price and the Conversion Price, which payment may be in cash or shares of Common Stock, at the option of the Company. TREASURY STOCK On December 9, 1996, the Board of Directors authorized the acceptance of 60,000 shares of the Company's common stock, based on the closing price of $18.00 per share, in satisfaction of certain obligations owed by affiliates of Joseph A. Reeves, Jr. and Michael J. Mayell. The acquired stock was used to fund the Company's contributions to the employees' 401(k) plan. -47- 48 WARRANTS The Company had the following warrants outstanding at December 31, 1999:
NUMBER OF EXERCISE WARRANTS SHARES PRICE EXPIRATION DATE -------- ------ ----- --------------- Executive Officers 1,428,000 $5.85 * General Partner 939,986 $0.20 December 31, 2015
* A date one year following the date on which the respective officer ceases to be an employee of the Company. On June 7, 1994, the shareholders of the Company approved a conversion of Class "B" Warrants held by Joseph A. Reeves, Jr. and Michael J. Mayell, which entitled each of them to purchase an aggregate of 714,000 shares of common stock, to Executive Officer Warrants. The Warrants expire one year following the date on which the respective officer ceases to be an employee of the Company. The Warrants further provide that in the event the officer's employment with the Company is terminated by the Company without "cause" or by the officer for "good reason," the officer will have the option to require the Company to purchase some or all of the Warrants held by the officer for an amount per Warrant equal to the difference between the exercise price, $5.85 per share, and the then prevailing market price of the common stock. The Company may satisfy this obligation with shares of common stock. -48- 49 STOCK OPTIONS Options to purchase the Company's common stock have been granted to officers, employees, nonemployee directors and certain key individuals, under various stock option plans. Options generally become exercisable in 25% cumulative annual increments beginning with the date of grant and expire at the end of ten years. At December 31, 1999, 1998 and 1997, 810,588, 74,425 and 851,024 shares, respectively, were available for grant under the plans. A summary of option transactions follows:
WEIGHTED NUMBER AVERAGE OF SHARES EXERCISE PRICE ---------- -------------- Outstanding at December 31, 1996 1,951,880 8.30 Granted 332,926 11.79 Exercised (55,327) 7.17 Canceled (157,292) 9.26 ---------- ------ Outstanding at December 31, 1997 2,072,187 8.81 Granted 3,229,550 3.37 Exercised (256,804) 5.04 Canceled (143,940) 11.40 ---------- ------ Outstanding at December 31, 1998 4,900,993 5.35 Granted 9,500 4.56 Exercised (31,425) 2.69 Canceled (200,635) 9.46 ---------- ------ Outstanding at December 31, 1999 4,678,433 $ 5.19 ========== ====== Shares exercisable: December 31, 1999 2,961,419 $ 6.00 December 31, 1998 2,262,085 $ 6.97 December 31, 1997 1,621,025 $ 8.95
OPTIONS OUTSTANDING OPTIONS EXERCISABLE -------------------------------------- ------------------------------------ RANGE OF OUTSTANDING AT WEIGHTED AVERAGE EXERCISABLE AT WEIGHTED AVERAGE EXERCISABLE PRICES DECEMBER 31, 1999 EXERCISE PRICE DECEMBER 31, 1999 EXERCISE PRICE - ------------------ ----------------- --------------- ----------------- -------------- $2.44 - $4.88 3,357,550 $ 3.43 1,733,650 $ 3.49 $5.56 - $10.00 770,095 8.51 755,095 8.52 $10.38 - $16.38 550,788 11.29 472,674 11.17 --------- ------ --------- ------ 4,678,433 $ 5.19 2,961,419 $ 6.00 ========= ====== ========= ======
The weighted average remaining contractual life of options outstanding at December 31, 1999, was approximately eight years. -49- 50 Pro forma information is required by SFAS No. 123 to reflect the estimated effect on net earnings and net earnings per share as if the Company had accounted for the stock options and other awards granted using the fair value method described in that Statement. The fair value was estimated at the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions: risk-free interest rate of 6.48%, 5.8% and 5.6%; dividend yield of 0%; volatility factors of the expected market price of the Company's common stock of 0.56, 0.59 and 0.31 for 1999, 1998 and 1997, respectively; and a weighted-average expected life of five years. These assumptions resulted in a weighted average grant date fair value of $ 2.90, $1.89 and $3.90 for options granted in 1999, 1998 and 1997, respectively. For purposes of the pro forma disclosures, the estimated fair value is amortized to expense over the awards' vesting period. Reflecting the amortization of this hypothetical expense for 1999, 1998 and 1997 income results in pro forma net earnings (loss) of $ 9.9 million, ($232.5) million and ($29.6) million, respectively, and pro forma basic net earnings (loss) per share of $0.22, ($5.85) and ($0.89), respectively. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. DEFERRED COMPENSATION In July 1996, the Company through the Compensation Committee of the board of Directors offered to Messrs. Reeves and Mayell (the Company's Chief Executive Officer and President, respectively) the option to accept in lieu of cash compensation for their respective base salaries Common Stock pursuant to the Company's Long Term Incentive Plan. Under such grants, Messrs. Reeves and Mayell each elected to defer $400,000 of their compensation for each of the years 1997, 1998 and 1999. In exchange for and in consideration of their accepting this option to reduce the Company's cash payments to each of Messrs. Reeves and Mayell, the company granted to each officer a matching deferral equal to 100 % of that amount deferred, which is subject to a one-year vesting period. Under the terms of the grants, the employee and matching deferrals are allocated to a common stock account in which units are credited to the accounts of the officer based on the number of shares that could be purchased at the market price of the common stock at December 31, 1996, for deferrals in 1997, at December 31, 1997, for deferrals during the first half of 1998, at June 30 1998, for deferrals during the second half of 1998, at December 31, 1998, for deferrals during the first half of 1999, and at June 30, 1999, for deferrals during the second half of 1999. At December 31, 1999, the plan had reserved 1,500,000 shares of common stock for future issuance and 814,012 rights have been granted. No actual shares of common stock are issued and the officer has no rights with respect to any shares unless and until there is a distribution. Distributions are to be made upon the death, retirement or termination of employment of the officer. The obligations of the Company with respect to the deferrals are unsecured obligations. The shares of common stock that may be issuable upon distribution of deferrals have been treated as a common stock equivalent in the financial statements of the Company. Although no cash has been paid, to either Mr. Reeves or Mr. Mayell for their base salaries during these periods, the compensation expense required to be reported by the Company for the equity grants was $1,412,000, $1,616,000 and $1,634,000 for 1999, 1998 and 1997 periods, respectively, relating to these grants is reflected in general and administrative expense for the years ended December 31, 1999, 1998 and 1997, respectively. -50- 51 STOCKHOLDER RIGHTS PLAN On May 5, 1999, the Company's Board of Directors declared a dividend distribution of one Right for each then-current and future outstanding share of Common stock. Each Right entitles the registered holder to purchase one one-thousandth interest in a share of the Company's Series B Preferred Stock with a par value of $.01 per share and an exercise price of $30. Unless earlier redeemed by the Company at a price of $.01 each, the Rights become exercisable only in certain circumstances constituting a potential change in control of the Company and will expire on May 5, 2009. Each share of Series B Junior Participating Preferred Stock purchased upon exercise of the Rights will be entitled to certain minimum preferential quarterly dividend payments as well as a specified minimum preferential liquidation payment in the event of a merger, consolidation or other similar transaction. Each share will also be entitled to 100 votes to be voted together with the Common stockholders and will be junior to any other series of Preferred Stock authorized or issued by the Company, unless the terms of such other series provides otherwise. In the event of a potential change in control, each holder of a Right, other than Rights beneficially owned by the acquiring party (which will have become void), will have the right to receive upon exercise of a Right that number of shares of Common stock of the Company, or, in certain instances, Common Stock of the acquiring party, having a market value equal to two times the current exercise price of the Right. 10. PROFIT SHARING AND SAVINGS PLAN The Company has a 401(k) profit sharing and savings plan (the "Plan") that covers substantially all employees and entitles them to contribute up to 15% of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. The Company matches 100% of each employee's contribution up to 6.5% of annual compensation subject to certain limitations as outlined in the Plan. In addition, the Company may make discretionary contributions which are allocable to participants in accordance with the Plan. During 1998, the Company implemented a new net profits program that was adopted effective as of November 1997. All employees participate in this program. Pursuant to this program, the Company adopted three separate well bonus plans: (i) The Meridian Resource Corporation Geoscientist Well Bonus Plan (the "Geoscientist Plan"); (ii) The Meridian Resource Corporation TMR Employees Trust Well Bonus Plan (the "Trust Plan") and (iii) The Meridian Resource Corporation Management Well Bonus Plan (the "Management Plan", and with the Management Plan and the Geoscientist Plan, the "Well Bonus Plans"). Total compensation related to these plans total $5.3 million and $0.9 million in 1999 and 1998, respectively. A portion of these amounts has been capitalized. The Executive Committee of the Board of Directors, which is comprised of Messrs. Reeves and Mayell, administers each of the Well Bonus Plans. The participants in each of the Well Bonus Plans are designated by the Executive Committee in its sole discretion. Participants in the Management Plan are limited to executive officers of the Company and other key management personnel designated by the Executive Committee. Neither Messrs. Reeves or Mayell will participate in the Management Plan, except with respect to a small number of wells and prospects not covered by their original net profit grants described below. The participants in the Trust Plan generally will be all employees of the Company that do not participate in one of the other Well Bonus Plans. Pursuant to the Well Bonus Plans, the Executive Committee designates, in its sole discretion, the individuals and wells that will participate in each of the Well Bonus Plans. The Executive Committee also determines the percentage bonus that will be paid under each well and the individuals that will participate thereunder. The Well Bonus Plans cover all properties on which the Company expends funds during each participant's employment with the Company, with the percentage bonus generally ranging from less than .1% to .5%, depending on the level of the employee. It is intended that these well bonuses function similar to an actual net profit interests, except that the employee will not have a real property interest and his or her rights to such bonuses will be subject to a one-year vesting period, except for grants in 1998 for which all employees were -51- 52 deemed vested, and will be subject to the general credit of the Company. Payments under vested bonus rights will continue to be made after an employee leaves the employment of the Company based on their adherence to the obligations required in their non-compete agreement upon termination. The Company has the option to make payments in whole, or in part, utilizing shares of Common Stock. The determination whether to pay cash or issue Common Stock will be based upon a variety of factors, including the Company's current liquidity position and the fair market value of the Common Stock at the time of issuance. In connection with the execution of their employment contracts in 1994, both Messrs. Reeves and Mayell were granted a 2% net profit interest in the oil and natural gas production from the Company's properties to the extent the Company acquires a mineral interest therein. The net profits interest for Messrs. Reeves and Mayell applies to all properties on which the Company expends funds during their employment with the Company. Each grant of a net profits interest is reflected at a value based on a third party appraisal of the interest granted. Total compensation related to this plan totaled approximately $100 thousand and $200 thousand in 1997 and 1998, respectively. The net profit interests represent real property rights that are not subject to vesting or continued employment with the Company. Messrs. Reeves and Mayell will not participate in the Well Bonus Plans for any particular property to the extent the original net profit interest grants covers such property. 11. OIL AND NATURAL GAS HEDGING ACTIVITIES The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. The Company enters into swaps and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at or prior to expiration or exchanged for physical delivery contracts. The Company does not obtain collateral to support the agreements, but monitors the financial viability of counter-parties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. -52- 53 Effective July 16, 1999, we entered into certain hedging contracts as summarized in the table below. The Notional Amount is equal to the total net volumetric hedge position of Meridian during the periods. The positions effectively hedge approximately 60% of our current oil production. The fair values of the hedge are based on the difference between the strike price and the New York Mercantile Exchange future prices for the applicable trading months of 2000.
Weighted Average Fair Value at Notional Strike Price December 31, 1999 Amount ($ per unit) (in thousands) ----------- ---------------------- ----------------- Oil (thousands of barrels): Floor Ceiling ------- --------- January 2000 - June 2000 1,274 $16.00 $24.00 $ (2,787)
During the year ended December 31, 1999, oil and natural gas revenues were reduced by $551,000 as a result of hedging transactions. As of December 31, 1998 and 1997, the Company had no material open hedging agreements. 12. MAJOR CUSTOMERS Major customers for the years ended December 31, 1999, 1998 and 1997 were as follows (based on purchases of oil and natural gas as a percent of total oil and natural gas sales):
YEAR ENDED DECEMBER 31, --------------------------- CUSTOMER 1999 1998 1997 - ----------------- ----- ------ ----- Tauber Oil Company............... 16% 32% -- Equiva Trading Company(1)........ 43% 22% -- Coral Energy Resources(1)........ -- 15% -- Phillips Petroleum Company....... -- -- 20% Coastal Corporation.............. -- -- 15% Koch Oil Company................. -- -- 15%
(1) Equiva Trading Company and Coral Energy Resources are both affiliates of Shell Oil Company. 13. RELATED PARTY TRANSACTIONS Historically since 1992, with the approval of the Board of Directors, Texas Oil Distribution and Development, Inc. ("TODD") and Sydson Energy, Inc. ("Sydson"), entities controlled by Joseph A. Reeves, Jr. and Michael J. Mayell, respectively, have invested in all Meridian drilling locations on a promoted basis, where applicable, at a 3% collective working interest. The participation is not elective on a prospect by prospect basis, but is rather a "blind" across the board participation. On a collective basis, TODD and Sydson invested $3,974,000, $2,126,000 and $2,315,000 for the years ended December 31, 1999, 1998 and 1997, respectively, in oil and natural gas drilling activities for which the Company was the operator. Collective amounts due from such entities for such activities were approximately $178,000 and $4,450,000 as of December 31, 1999 and 1998, respectively, net of amounts owed to them from the Company. Effective July 15, 1999, the Company, with the approval of the Board of Directors, acquired the Kings Bayou, -53- 54 Backridge and Chocolate Bayou interests held by TODD, Sydson and Messrs. Reeves and Mayell. Proceeds of $2.0 million to each of TODD and Sydson and $1.4 million to each of Messrs. Reeves and Mayell due from the acquisition were applied directly to current and/or future costs and expenses related to TODD and Sydson's working interest rather than paid in cash. Mr. Joe Kares, a Director of Meridian, is a partner in the public accounting firm of Kares & Cihlar, which provided the Company with accounting services for the years ended December 31, 1999, 1998 and 1997 and received fees of approximately $283,000, $57,000 and $27,000, respectively. Such fees exceeded 5% of the gross revenues of Kares & Cihlar for those respective years. Management believes that such fees were equivalent to fees that would have been paid to similar firms providing such services in arm's length transactions. Mr. Gary A. Messersmith, a Director of Meridian, is a partner in the law firm of Fouts & Moore, L.L.P. in Houston, Texas, which provided legal services for the Company for the years ended December 31, 1999, 1998 and 1997 and received fees of approximately $49,000, $52,000 and $15,000, respectively. In addition, the Company has Mr. Messersmith on personal retainer of $8,333 per month relating to services provided to the Company personally by Mr. Messersmith. Mr. Messersmith also participates in the plan described in Note 10 above pursuant to which he was paid approximately $46,000 and received 19,000 shares of the Company's common stock during 1999 and $22,600 during 1998. 14. EARNINGS PER SHARE (in thousands, except per share) The following table sets forth the computation of basic and diluted earnings (loss) per share:
YEAR ENDED DECEMBER 31, ----------------------- 1999 1998 1997 --------- --------- --------- Numerator: Net earnings (loss) $ 16,867 $(228,008) $ (28,541) Less: Preferred dividend requirement 5,400 2,700 -- Net earnings (loss) used in per share calculation $ 11,467 $(230,708) $ (28,541) Denominator: Denominator for basic earnings (loss) per share - weighted-average shares outstanding 45,995 39,774 33,383 Effect of potentially dilutive common shares: Convertible preferred stock -- -- -- Convertible subordinated notes -- -- -- Employee and director stock options N/A N/A N/A Warrants N/A N/A N/A Denominator for diluted earnings (loss) per share - weighted-average shares outstanding and assumed conversions 45,995 39,774 33,383 ========= ========= ========= Basic earnings (loss) per share $ 0.25 $ (5.80) $ (0.85) ========= ========= ========= Diluted earnings (loss) per share $ 0.25 $ (5.80) $ (0.85) ========= ========= =========
On June 30, 1998, the Company acquired (the "LOPI Transaction") Louisiana Onshore Properties, Inc., an -54- 55 indirect subsidiary of Shell Oil Company ("Shell") pursuant to a merger of a wholly-owned subsidiary with LOPI. In conjunction with the other consideration paid to Shell, the Company issued a new convertible preferred stock that is convertible into 12,837,428 shares of Common Stock. In the event Shell elects to sell any shares of Common Stock issued upon conversion of the Preferred Stock (the "Make-Whole Shares"), as more fully described in the Agreement and Plan of Merger dated March 27, 1998, and included in the Company's proxy statement dated June 10, 1998, the Company has agreed to pay Shell the amount, if any, that the consideration received by Shell is less than $10.52 per share. Such payment may be made in cash or Common Stock, or a combination thereof, at the Company's election. It is the Company's policy to settle this type of transaction with a cash payment. Based upon current oil and natural gas prices and assuming such oil and natural gas prices continue, the Company believes sufficient cash resources from operating activities will be generated during the year 2000 to pay any make-whole obligations owed to Shell in cash rather than issue Common Stock, and believes it would make any such payments in cash assuming it is able to obtain the requisite waivers under the Credit Facility. Therefore, the Make-Whole Shares have been removed from the earnings per share calculations included in the financial statements. 15. SUBSEQUENT EVENT In an effort to reduce bank debt and supplement internal cash flow to fund the inventory of exploration and development projects scheduled for drilling in 2000 and beyond, the Company announced on January 14, 2000, the initiation of a formal process to pursue the sale of certain non-strategic oil and gas properties located in south Louisiana, the Texas Gulf Coast and offshore in the Gulf of Mexico. The properties scheduled for sale account for approximately 20% of the Company's current net average daily production, or approximately 30 Mmcfe per day. The anticipated closing will be late second quarter. -55- 56 16. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) Results of operations by quarter for the years ended December 31, 1999 and 1998, were (thousands of dollars, except per share):
QUARTER ENDED ------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31(2) ---------- --------- --------- ---------- 1999 - ---- Revenues $ 23,306 $ 30,969 $ 38,947 $ 40,139 Results of operations from exploration and production activities(1) 4,320 11,569 18,137 19,606 Net earnings (loss)(3) $ (4,989) $ 1,440 $ 6,389 $ 8,627 Net earnings (loss) per share:(3) Basic $ (0.11) $ 0.03 $ 0.14 $ 0.19 Diluted(4) (0.11) 0.03 0.13 0.16 1998 - ---- Revenues $ 11,897 $ 11,742 $ 23,238 $ 27,149 Results of operations from exploration and production activities(1) (36,529) (130,567) 1,165 (38,949) Net earnings (loss)(3) $ (40,927) $(135,400) $ (6,521) $ (47,860) Net earnings (loss) per share:(3) Basic $ (1.22) $ (4.01) $ (0.14) $ (1.04) Diluted (1.22) (4.01) (0.14) (1.04)
(1) Results of operations from exploration and production activities, which approximates gross profit, are computed as operating revenues less lease operating expenses, severance and ad valorem taxes, depletion and impairment of oil and natural gas properties (after tax). (2) Fourth quarter 1998 results include impairment of $48.9 million related to oil and natural gas properties. (3) Applicable to common stockholders. (4) Reflects conversion of preferred stock for third quarter 1999 and reflects conversion of preferred stock and subordinated notes for fourth quarter 1999. -56- 57 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) The following information is being provided as supplemental information in accordance with the provisions of SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (thousands of dollars)
YEAR ENDED DECEMBER 31, ----------------------- 1999 1998 1997 -------- -------- -------- Costs incurred during the year:(1) Property acquisition costs Unproved $ 14,542 $ 16,545 $ 11,610 Proved 3,261 259,502 -- Exploration 52,739 83,156 73,441 Development 34,478 51,809 25,813 -------- -------- -------- $105,020 $411,012 $110,864 ======== ======== ========
(1) Costs incurred during the years ended December 31, 1999, 1998 and 1997 include general and administrative costs related to acquisition, exploration and development of oil and natural gas properties, net of third party reimbursements, of $9,951,000, $6,651,000 and $3,958,000, respectively. CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES (thousands of dollars)
DECEMBER 31, ------------ 1999 1998 -------- -------- Capitalized costs $916,495 $820,322 Accumulated depletion 485,870 432,868 -------- -------- Net capitalized costs $430,625 $387,454 ======== ========
At December 31, 1999 and 1998, costs of $62,686,000 and $94,077,000, respectively, were excluded from the depletion base. These costs are expected to be evaluated within the next three years. These costs consist primarily of acreage acquisition costs and related geological and geophysical costs. -57- 58 RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES (thousands of dollars)
YEAR ENDED DECEMBER 31, ----------------------- 1999 1998 1997 --------- --------- --------- Oil and natural gas revenues $ 132,576 $ 73,336 $ 57,640 Less: Oil and natural gas operating costs 14,604 12,841 5,680 Severance and ad valorem taxes 11,338 4,069 2,165 Depletion 53,002 44,347 25,573 Impairment of long-lived assets -- 245,011 24,141 Income tax benefit -- (28,052) -- --------- --------- --------- 78,944 278,216 57,559 --------- --------- --------- Results of operations from oil and natural gas producing activities $ 53,632 $(204,880) $ 81 ========= ========= ========= Depletion expense per Mcfe $ 1.07 $ 1.27 $ 1.27 ========= ========= =========
-58- 59 ESTIMATED QUANTITIES OF PROVED RESERVES The following table sets forth the net proved reserves of the Company as of December 31, 1999, 1998 and 1997, and the changes therein during the years then ended. The reserve information was prepared by T. J. Smith & Company, Inc., independent petroleum engineers, for 1999 and 1998. Ryder Scott Company, independent petroleum engineers, reviewed the reserve information for 1997. All of the Company's oil and natural gas producing activities are located in the United States.
Oil Gas TOTAL PROVED RESERVES: (MBbls) (MMcf) -------- -------- BALANCE AT DECEMBER 31, 1996 9,416 107,406 Production during 1997 (914) (14,603) Discoveries and extensions 1,990 31,844 Revisions of previous quantity estimates and other (761) (13,862) -------- -------- BALANCE AT DECEMBER 31, 1997 9,731 110,785 Production during 1998 (2,365) (20,603) Discoveries and extensions 6,556 37,854 Purchase of reserves-in-place 12,602 83,472 Sale of reserves-in-place (1,059) (8,047) Revisions of previous quantity estimates and other (3,088) (33,574) -------- -------- BALANCE AT DECEMBER 31, 1998 22,377 169,887 Production during 1999 (4,454) (22,711) Discoveries and extensions 6,382 71,484 Purchase of reserves-in-place 335 2,379 Sale of reserves-in-place (67) (2,633) Revisions of previous quantity estimates and other 2,782 (17,941) -------- -------- BALANCE AT DECEMBER 31, 1999 27,355 200,465 PROVED DEVELOPED RESERVES: Balance at December 31, 1999 17,695 144,552 Balance at December 31, 1998 14,592 120,233 Balance at December 31, 1997 5,305 81,500 Balance at December 31, 1996 4,361 81,192
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The information that follows has been developed pursuant to SFAS No. 69 and utilizes reserve and production data prepared or reviewed by independent petroleum consultants. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. -59- 60 The estimated discounted future net cash flows from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. At December 31, 1998, the Company had no future income taxes as the deductible tax basis and available net operating loss carryforwards exceeded future net cash flows. Future income tax expense has been reduced for the effect of available net operating loss carryforwards.
(thousands of dollars) AT DECEMBER 31, --------------- 1999 1998 ----------- ----------- Future cash flows $ 1,155,570 $ 592,114 Future production costs (184,161) (133,558) Future development costs (78,717) (50,893) ----------- ----------- Future net cash flows before income taxes 892,692 407,663 Future taxes on income (189,304) -- ----------- ----------- Future net cash flows 703,388 407,663 Discount to present value at 10 percent per annum (178,630) (114,286) ----------- ----------- Standardized measure of discounted future net cash flows $ 524,758 $ 293,377 =========== ===========
The average price for natural gas in the above computations was $2.48 and $2.14 at December 31, 1999 and 1998, respectively. The average price used for crude oil in the above computations was $25.81 and $10.13 at December 31, 1999 and 1998, respectively. -60- 61 CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The following table sets forth the changes in standardized measure of discounted future net cash flows for the years ended December 31, 1999, 1998 and 1997 (thousands of dollars):
YEAR ENDED DECEMBER 31, ----------------------- 1999 1998 1997 --------- --------- --------- Balance at Beginning of Period $ 293,377 $ 213,917 $ 313,623 Sales of oil and gas, net of production costs (106,634) (56,426) (49,796) Changes in prices, and production costs 248,633 (90,882) (165,406) Revisions of previous quantity estimates (2,737) (33,938) (28,574) Sales of reserves-in-place (4,753) (24,219) -- Current year discoveries, extensions and improved recovery 165,055 63,292 50,274 Purchase of reserves-in-place 6,808 185,119 -- Changes in estimated future development costs (25,887) (18,139) (3,564) Development costs incurred during the period 34,478 51,809 27,666 Accretion of discount 29,338 21,392 39,451 Net change in income taxes (70,882) -- 80,884 Change in production rates (timing) and other (42,038) (18,548) (50,641) --------- --------- --------- Net change 231,381 79,460 (99,706) --------- --------- --------- Balance at End of Period $ 524,758 $ 293,377 $ 213,917 ========= ========= =========
-61- 62 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III The information required in Items 10, 11, 12 and 13 is incorporated by reference to the Company's definitive Proxy Statement to be filed with the Securities and Exchange Commission on or before April 29, 2000. -62- 63 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Documents filed as part of this report: 1. Financial Statements included in Item 8: (i) Independent Auditor's Report (ii) Consolidated Balance Sheets as of December 31, 1999 and 1998 (iii) Consolidated Statements of Operations for each of the three years in the period ended December 31, 1999 (iv) Consolidated Statements of Changes in Stockholders' Equity for each of the three years in the period ended December 31, 1999 (v) Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1999 (vi) Notes to Consolidated Financial Statements (vii) Consolidated Supplemental Oil and Gas Information (Unaudited) 2. Financial Statement Schedule: (i) All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto. 3. Exhibits: 2.1 Agreement and Plan of Merger dated March 27, 1998, between the Company, LOPI Acquisition Corp., Shell Louisiana Onshore Properties, Inc. and Louisiana Onshore Properties, Inc. (incorporated by reference from the Company's Current Report on Form 8-K dated June 30, 1998). 2.2 Purchase and Sale Agreement dated effective October 1, 1997, by and between The Meridian Resource Corporation and Shell Western E&P Inc. (incorporated by reference from the Company's Current Report on Form 8-K dated June 30, 1998). 3.1 Third Amended and Restated Articles of Incorporation of the Company (incorporated by reference to the Company's Quarterly Report on Form 10- Q for the three months ended September 30, 1998). 3.2 Amended and Restated Bylaws of the Company (incorporated by reference to the Company's Quarterly Report on Form 10-Q for the three months ended September 30, 1998). 3.3 Certificate of Designation for Preferred Stock dated June 30, 1998 (incorporated by reference from the Company's Current Report on Form 8-K dated June 30, 1998). 4.1 Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company's Registration Statement on Form S-1, as amended (Reg. No. 33-65504)). 4.2 Common Stock Purchase Warrant of the Company dated October 16, 1990, issued to Joseph A. Reeves, Jr. (incorporated by reference to Exhibit 10.8 of the Company's Annual Report on Form 10-K for the year ended December 31, 1991, as amended by the Company's Form 8 filed March 4, 1993). -63- 64 4.3 Common Stock Purchase Warrant of the Company dated October 16, 1990, issued to Michael J. Mayell (incorporated by reference to Exhibit 10.9 of the Company's Annual Report on Form 10-K for the year ended December 31, 1991, as amended by the Company's Form 8 filed March 4, 1993). *4.4 Registration Rights Agreement dated October 16, 1990, among the Company, Joseph A. Reeves, Jr. and Michael J. Mayell (incorporated by reference to Exhibit 10.7 of the Company's Registration Statement on Form S-4, as amended (Reg. No. 33- 37488)). *4.5 Warrant Agreement dated June 7, 1994, between the Company and Joseph A. Reeves, Jr. (incorporated by reference to Exhibit 4.1 of the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1994). *4.6 Warrant Agreement dated June 7, 1994, between the Company and Michael J. Mayell (incorporated by reference to Exhibit 4.1 of the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1994). 4.7 Amended and Restated Credit Agreement dated May 22, 1998, among the Company, the several banks and financial institutions and other entities from time to time parties thereto (the "Lenders"), The Chase Manhattan Bank, as administrative agent for the Lenders, Bankers Trust Company, as syndication agent, Chase Securities Inc., as advisor to the Company, Chase Securities Inc., B. T. Alex. Brown Incorporated, Toronto Dominion (Texas), Inc. and Credit Lyonnais New York Branch as co-arrangers, and Toronto Dominion (Texas), Inc. and Credit Lyonnais New York Branch, as co-documentation agents (incorporated by reference from the Company's current report on Form 8-K dated June 30, 1998). 4.8 Second Amended and Restated Guarantee dated June 30, 1998, between the Guarantors signatory thereto and The Chase Manhattan Bank, as Administrative Agent for the Lenders (incorporated by reference from the Company's current report on Form 8-K dated June 30, 1998). 4.9 Amended and Restated Pledge Agreement, dated May 22, 1998, between the Company and The Chase Manhattan Bank, as Administrative Agent (incorporated by reference from the Company's current report on Form 8-K dated June 30, 1998). 4.10 First Amendment to Amended and Restated Pledge Agreement dated June 30, 1998 (incorporated by reference from the Company's current report on Form 8-K dated June 30, 1998). 4.11 Amendment No. 2 dated November 13, 1998 to Amended and Restated Credit Agreement dated May 22, 1998, by and among the Company, The Chase Manhattan Bank as administrative agent, and the various lenders party thereto (incorporated by reference from the Company's Quarterly Report on Form 10-Q for the three months ended September 30, 1998). -64- 65 *4.12 The Meridian Resource Corporation Directors' Stock Option Plan (incorporated by reference to Exhibit 10.5 of the Company's Annual Report on Form 10-K for the year ended December 31, 1991, as amended by the Company's Form 8 filed March 4, 1993). 4.13 Stock Rights and Restrictions Agreement dated as of June 30, 1998, by and between The Meridian Resource Corporation and Shell Louisiana Onshore Properties Inc. (incorporated by reference from the Company's Current Report on Form 8-K dated June 30, 1998). 4.14 Registration Rights Agreement dated June 30, 1998, by and between The Meridian Resource Corporation and Shell Louisiana Onshore Properties Inc. (incorporated by reference from the Company's Current Report on Form 8-K dated June 30, 1998). 10.1 See exhibits 4.2 through 4.14 for additional material contracts. *10.2 The Meridian Resource Corporation 1990 Stock Option Plan (incorporated by reference to Exhibit 10.6 of the Company's Annual Report on Form 10-K for the year ended December 31, 1991, as amended by the Company's Form 8 filed March 4, 1993). *10.3 Employment Agreement dated August 18, 1993, between the Company and Joseph A. Reeves, Jr. (incorporated by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 1995). *10.4 Employment Agreement dated August 18, 1993, between the Company and Michael J. Mayell (incorporated by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 1995). *10.5 Form of Indemnification Agreement between the Company and its executive officers and directors (incorporated by reference to Exhibit 10.6 of the Company's Annual Report on Form 10-K for the year ended December 31, 1994). *10.6 Deferred Compensation agreement dated July 31, 1996, between the Company and Joseph A. Reeves, Jr. (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996). *10.7 Deferred Compensation agreement dated July 31, 1996, between the Company and Michael J. Mayell (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996). *10.8 Texas Meridian Resources Corporation 1995 Long-Term Incentive Plan (incorporated by reference to the Company's Annual Report on Form 10-K for the year-ended December 31, 1996). *10.9 Texas Meridian Resources Corporation 1997 Long-Term Incentive Plan (incorporated by reference from the Company's Quarterly Report on Form 10-Q for the three months ended June 30, 1997). *10.10 Cairn Energy USA, Inc. 1993 Stock Option Plan, as amended (incorporated by reference to Cairn Energy USA, Inc.'s Annual Report on Form 10-K for the year ended December 31, 1993). -65- 66 *10.11 Cairn Energy USA, Inc. 1993 Directors Stock Option Plan, as amended (incorporated by reference to Cairn Energy USA, Inc.'s Registration Statement on Form S-1 (Reg. No.33-64646). *10.14 Employment Agreement with Lloyd V. DeLano effective November 5, 1997 (incorporated by reference from the Company's Quarterly Report on Form 10-Q for the three months ended September 30, 1998). *10.15 Employment Agreement with P. Richard Gessinger effective December 1, 1997 (incorporated by reference from the Company's Quarterly Report on Form 10-Q for the three months ended September 30, 1998). *10.16 The Meridian Resource Corporation TMR Employee Trust Well Bonus Plan (incorporated by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 1998). *10.17 The Meridian Resource Corporation Management Well Bonus Plan (incorporated by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 1998). *10.18 The Meridian Resource Corporation Geoscientist Well Bonus Plan (incorporated by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 1998). *10.19 Modification Agreement effective January 2, 1999, by and among the Company and affiliates of Joseph A. Reeves, Jr. (incorporated by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 1998). *10.20 Modification Agreement effective January 2, 1999, by and among the Company and affiliates of Michael J. Mayell (incorporated by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 21.1 Subsidiaries of the Company (incorporated by reference from the Company's Annual Report on Form 10-K for the year ended December 31, 1998). -66- 67 **23.1 Consent of Ernst & Young LLP. **23.2 Consent of T. J. Smith & Company, Inc. **23.3 Consent of Ryder Scott Company. **27.1 Financial Data Schedule. * Management contract or compensation plan. ** Filed herewith. (b) Reports on Form 8-K. None. -67- 68 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. THE MERIDIAN RESOURCE CORPORATION BY: /s/ JOSEPH A. REEVES, JR. ---------------------------------- Chief Executive Officer (Principal Executive Officer) Director and Chairman of the Board Date: March 30, 2000 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Name Title Date ---- ----- ---- BY: /s/ JOSEPH A. REEVES, JR. Chief Executive Officer March 30, 2000 -------------------------- (Principal Executive Officer) Joseph A. Reeves, Jr. Director and Chairman of the Board BY: /s/ MICHAEL J. MAYELL President and Director March 30, 2000 -------------------------- Michael J. Mayell BY: /s/ P. RICHARD GESSINGER Chief Financial Officer March 30, 2000 -------------------------- P. Richard Gessinger BY: /s/ LLOYD V. DELANO Chief Accounting Officer March 30, 2000 -------------------------- Lloyd V. DeLano BY: /s/ JAMES T. BOND Director March 30, 2000 -------------------------- James T. Bond BY: /s/ JOE E. KARES Director March 30, 2000 -------------------------- Joe E. Kares BY: /s/ GARY A. MESSERSMITH Director March 30, 2000 -------------------------- Gary A. Messersmith
-68- 69 INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION - ----------- ----------- 23.1 Consent of Ernest & Young LLP 23.2 Consent of T. J. Smith & Company, Inc. 23.3 Consent of Ryder Scott Company 27.1 Financial Data Schedule
EX-23.1 2 CONSENT OF ERNST & YOUNG LLP 1 EXHIBIT 23.1 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-86788) pertaining to the Non-Employee Directors' Stock Option Plan, 1990 Stock Option Plan, 1994 Executive Officer Warrants and 1993 Non-Employee Director Stock Options plan and in the Registration Statement (Form S-8 No. 333-40009) pertaining to the Texas Meridian Resources Corporation 1995 Long-Term Incentive Plan, Texas Meridian Resources Corporation 1997 Long-Term Incentive Plan, Cairn Energy USA, Inc. 1993 Stock Option Plan, As Amended, and Cairn Energy USA, Inc. Directors Stock Option Plan, As Amended, of The Meridian Resource Corporation of our report dated February 23, 2000, with respect to the consolidated financial statements of The Meridian Resource Corporation included in the Annual Report (Form 10-K) for the year ended December 31, 1999. ERNST & YOUNG LLP Houston, Texas March 29, 2000 EX-23.2 3 CONSENT OF T.J. SMITH & COMPANY, INC. 1 EXHIBIT 23.2 CONSENT OF T. J. SMITH & COMPANY, INC. March 7, 2000 The Meridian Resource Corporation 1401 Enclave Parkway, Suite 300 Houston, TX 77077 Re: Consent of Independent Petroleum Engineers Gentlemen: We hereby consent to the references to our reviews dated February 25, 1999 and February 15, 2000, which were used to prepare the Estimated Future Reserves Attributable to Certain Leasehold Interests of The Meridian Resource Corporation as of December 31, 1998 and December 31, 1999, respectively, in your Form 10-K and to the reference to T. J. Smith & Company, Inc. as experts in the field of petroleum engineering. Very truly yours, T. J. Smith & Company, Inc. By: --------------------------------- T. J. Smith, P.E. EX-23.3 4 CONSENT OF RYDER SCOTT COMPANY 1 EXHIBIT 23.3 CONSENT OF RYDER SCOTT COMPANY PETROLEUM ENGINEERS We hereby consent to the references to our reviews dated February 19, 1997 and February 23, 1998, which were used to prepare the Estimated Future Reserves Attributable to Certain Leasehold Interests of Texas Meridian Resources Corporation as of December 31, 1996 and December 31, 1997, respectively, and to the reference to Ryder Scott Company Petroleum Engineers as experts in the field of petroleum engineering, which were incorporated by reference in your Form 10-K Registration Statement for the fiscal year ended December 31, 1999. RYDER SCOTT COMPANY, L.P. Houston, Texas March 9, 2000 EX-27 5 FINANCIAL DATA SCHEDULE
5 12-MOS DEC-31-1999 DEC-31-1999 6,617 0 28,478 1,003 0 36,494 925,710 489,203 477,719 43,859 270,000 0 135,000 472 28,388 477,719 132,576 133,361 78,944 78,944 0 0 22,879 16,867 0 16,867 0 0 0 16,867 0.25 0.25
-----END PRIVACY-ENHANCED MESSAGE-----