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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
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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:
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(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
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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
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THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
PART I Page
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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
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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.
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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
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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.
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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
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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
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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
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(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.
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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.
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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,
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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
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DEVELOPED UNDEVELOPED
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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
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TOTAL ............................. 121,348 53,845 282,937 125,915
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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.
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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,
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CUSTOMER 1999 1998 1997
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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.
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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
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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.
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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.
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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.
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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.
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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.
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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.
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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 $2.0 million in the aggregate for cash dividends on the Common Stock or for
purchase of shares of Common Stock without the prior consent of the lender.
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ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with our Consolidated Financial
Statements and related notes thereto included elsewhere in this report.
YEAR ENDED DECEMBER 31,
1999 1998 1997 1996 1995
--------- -------- -------- -------- --------
(In thousands, except prices and per share information)
A. SUMMARY OF OPERATING DATA
Production:
Oil (MBbls) 4,454 2,365 914 751 650
Natural gas (MMcf) 22,711 20,603 14,603 15,783 14,598
Natural gas equivalent (MMcfe) 49,438 34,793 20,087 20,289 18,498
Average Prices:
Oil ($/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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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
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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
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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.
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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.
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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.
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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.
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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.
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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".
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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
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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
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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.
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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.
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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
============ ============= =============
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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.
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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.
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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.
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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.
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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.
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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
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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.
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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,
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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
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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.
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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.
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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.
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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
========= ========= =========
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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.
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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.
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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
========= ========= =========
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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.
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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).
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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).
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*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).
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*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).
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**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.
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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
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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