UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: DECEMBER 31, 2002 Commission file number: 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. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]
Aggregate market value of shares of common stock held by non-affiliates
of the Registrant at June 30, 2002: $182,962,375
Number of shares of common stock outstanding at March 18, 2003: 50,089,118
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Form (Items 10, 11, 12, 13, 14 and
15) is incorporated by reference from the registrant's Proxy Statement to be
filed on or before April 30, 2003.
Page 1 of 84
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
Page
----
PART I
Item 1. Business 3
Item 2. Properties 14
Item 3. Legal Proceedings 14
Item 4. Submission of Matters to a Vote of Security Holders 14
PART II
Item 5. Market for Registrant's Common Equity and Related
Shareholder Matters 15
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 17
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 65
PART III
Item 10. Directors and Executive Officers of the Registrant 65
Item 11. Executive Compensation 65
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters 65
Item 13. Certain Relationships and Related Transactions 65
Item 14. Controls and Procedures 65
Item 15. Principal Accountant Fees and Services 65
PART IV
Item 16. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 66
Signatures 70
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PART I
ITEM 1. BUSINESS
GENERAL
The Meridian Resource Corporation ("Meridian" or the "Company") 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, 2002, we had
proved reserves of approximately 167 Bcfe with a present value of future net
cash flows before income taxes of approximately $460 million. Approximately 64%
of our proved reserves were natural gas and approximately 76% 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, land and
operational staff.
The Company generates and drills exploration projects primarily in the south
Louisiana and south Texas Gulf Coast region. During the course of the prior ten
years, we have generated and participated in the discovery of over 800 BCFE of
new reserves. Recently, we have developed several shallower, low-risk
exploration projects that we believe provide the Company with a higher level of
confidence for success as well as better control of risks and costs than the
deep exploration plays we have traditionally developed and drilled. Examples of
this strategy include the Company's Thornwell and Biloxi Marshlands fields.
While this strategy has proven to be successful and will be the focus of our
efforts to develop new oil and gas reserves in our producing region, it does not
replace entirely the Company's continued efforts to explore for deep reserves
where the probability of success and costs justify the risks associated with
such opportunities.
We currently have interests in leases and options to lease acreage in
approximately 299,000 gross acres in Louisiana, Texas and the Gulf of Mexico. We
also have rights or access to approximately 7,500 square miles of 3-D seismic
data, which we believe to be one of the largest positions held by a company of
our 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.
You can locate additional information on the internet at www.tmrc.com and
www.sec.gov.
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.
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
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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 significantly lower finding costs. We also believe
that our use of 3-D seismic technology minimizes development costs by allowing
for the better placement of the 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 a 1997 acquisition average 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 that 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 its fields, which we believe gives Meridian an advantage to
develop and exploit the proved undeveloped and proved developed non-producing
reserves from those fields.
As a result of our disciplined method of exploration we believe that we are able
to develop a more accurate definition of the risk profile of exploration
prospects than was previously available using traditional exploration techniques
or than is used by our competition in our areas of focus. We therefore believe
that our method of exploration utilizing the 3-D technology 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, 2002. The
reserve volumes were reviewed by T. J. Smith & Company, Inc., independent
reservoir engineers.
GULF OF
LOUISIANA MEXICO TOTAL
--------- -------- -----
PRODUCTION FOR THE YEAR ENDED DECEMBER 31, 2002
Oil (MBbls) 2,067 146 2,213
Natural Gas (MMcf) 13,959 1,619 15,578
RESERVES AS OF DECEMBER 31, 2002
Oil (MBbls) 9,150 775 9,925
Natural Gas (MMcf) 95,503 12,123 107,626
ESTIMATED FUTURE NET CASH FLOWS ($000)(1) .............................. $ 648,850
PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE INCOME TAXES ($000)(1) ... $ 459,703
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS ($000)(1) ..... $ 429,835
(1) 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, 2002, we used the prices at December 31, 2002, which were
$31.82 per Bbl of oil and $4.96 per Mcf of natural gas.
PRODUCTIVE WELLS
At December 31, 2002, 2001 and 2000, we held interests in the following
productive wells. The majority of the 31 gross (5.1 net) wells in the Gulf of
Mexico as of December 31, 2002, have multiple completions.
2002 2001 2000
---------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Oil Wells ........... 67 42 61 41 118 96
Natural Gas Wells ... 71 28 79 34 96 46
--- -- --- -- --- ---
Total ........ 138 70 140 75 214 142
=== == === == === ===
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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,
2002. 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 reviewed by T.
J. Smith & Company, Inc., independent reservoir engineers, as of December 31,
2002.
PROVED RESERVES AT DECEMBER 31, 2002
------------------------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
--------- ------------- ----------- -----
(DOLLARS IN THOUSANDS)
Net Proved Reserves:
Oil (MBbls) ................................... 4,233 2,608 3,084 9,925
Natural Gas (MMcf) ............................ 38,043 48,205 21,378 107,626
Natural Gas Equivalent (MMcfe) ................ 63,441 63,852 39,885 167,178
Estimated Future Net Cash Flows(1) ............ $648,850
Present Value of Future Net Cash Flows (before $459,703
income taxes)(1) ..............................
Standardized Measure of Discounted Future Net $429,835
Cash Flows(1) .................................
---------------
(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 Estimated Future Net Cash Flows,
the Present Value of Future Net Cash Flows and the Standardized Measure
of Discounted Future Net Cash Flows as of December 31, 2002, we used
the prices at December 31, 2002, which were $31.82 per Bbl of oil and
$4.96 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 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, that
are based on the mechanical status of the completion, may also 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 by analogy to similar
types of reserves rather than actual production history. Estimates based on
these methods are generally 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.
-6-
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 that 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 and dry
exploratory and development wells that we drilled and completed in 2002, 2001
and 2000.
GROSS WELLS NET WELLS
--------------------------- ----------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- --- -----
EXPLORATORY WELLS
Year ended December 31, 2002 .... 6 1 7 3.7 0.9 4.6
Year ended December 31, 2001 .... 9 7 16 4.2 5.8 10.0
Year ended December 31, 2000 .... 11 5 16 7.4 3.6 11.0
DEVELOPMENT WELLS
Year ended December 31, 2002 .... 2 1 3 1.4 0.9 2.3
Year ended December 31, 2001 .... 4 2 6 2.8 1.8 4.6
Year ended December 31, 2000 .... 7 -- 7 4.2 -- 4.2
Meridian had 1 gross (0.9 net) well in progress at December 31, 2002.
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 2002, 2001 and 2000.
YEAR ENDED DECEMBER 31,
------------------------------------------
2002 2001 2000
------- -------- -------
PRODUCTION:
Oil (MBbls) .......................... 2,213 2,918 3,987
Natural gas (MMcf) ................... 15,578 22,085 27,672
Natural gas equivalent (MMcfe) ....... 28,856 39,594 51,596
AVERAGE PRICES:
Oil ($/Bbl) .......................... $ 24.67 $ 25.17 $ 27.32
Natural gas ($/Mcf) .................. $ 3.36 $ 4.67 $ 4.14
Natural gas equivalent ($/Mcfe) ...... $ 3.71 $ 4.46 $ 4.33
PRODUCTION EXPENSES:
Lease operating expenses ($/Mcfe) .... $ 0.41 $ 0.42 $ 0.35
Severance and ad valorem
taxes ($/Mcfe) .................... $ 0.29 $ 0.30 $ 0.30
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ACREAGE
The following table sets forth the developed and undeveloped oil and natural gas
leasehold acreage in which Meridian held an interest as of December 31, 2002.
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, 2002
------------------------------------------
DEVELOPED UNDEVELOPED
------------------- ----------------
REGION GROSS NET GROSS NET
------ ----- ------ ----- ---
TEXAS ............................ 425 53 4,000 1,110
LOUISIANA ........................ 31,061 15,564 23,134 20,913
GULF OF MEXICO ................... 47,018 6,631 5,000 4,650
------ ------ ------ ------
TOTAL .......................... 78,504 22,248 32,134 26,673
====== ====== ====== ======
In addition to the above acreage, we currently have options or farm-ins to
acquire leases on approximately 188,283 gross (166,955 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.
GEOLOGIC AND GEOPHYSICAL EXPERTISE
Meridian employs approximately 87 full-time non-union employees and 12 contract
employees. This staff includes geologists, geophysicists and consultants with
over 350 combined 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. Talented
geoscientists with experience in finding oil and gas in large quantities and who
focus in our niche region of focus are unique and difficult to attract and
retain on a long-term basis.
MARKETING OF PRODUCTION
We market our production to third parties in a manner consistent with industry
practices. Typically, the oil production is sold at the wellhead at field-posted
prices, less gathering and gravity adjustments, and the natural gas is sold at
posted indices, less applicable gathering and dehydration charges, adjusted for
the quality of natural gas and prevailing supply and demand conditions. The
natural gas production is sold under 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 2002, 2001 and 2000.
YEAR ENDED DECEMBER 31,
----------------------------
CUSTOMER 2002 2001 2000
-------- ---- ---- ----
Equiva Trading Company(1) ........ 33% 30% 36%
Louisiana Intrastate Gas ......... 17% 20% 12%
Conoco, Inc ...................... 12% -- --
Superior Natural Gas ............. -- 13% 14%
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(1)This entity is an affiliate of Shell.
Other purchasers for our oil and natural gas are available; therefore, we
believe that the loss of any of these purchasers would not have a material
adverse effect on the results of operations.
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 $37.20 per Bbl and the Gulf Coast spot market natural gas price at
Henry Hub, Louisiana, has ranged from $1.08 to $9.98 per MMBtu. The average
price we received during the year ended December 31, 2002, was $3.71 per Mcfe
compared to $4.46 per Mcfe during the year ended December 31, 2001. The volatile
nature of 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
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 greater than ours 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.
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 available natural gas pipeline capacity 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 to issue rules and regulations that govern the oil and
natural gas industry and its individual members, some of
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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 our profitability.
All of our federal offshore oil and gas leases are granted by the federal
government and are administered by the U. S. Minerals 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.
Individual 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
The FERC regulates interstate natural gas pipeline transportation rates and
service conditions, both of which affect the marketing of natural gas produced
by us, as well as the revenues we receive for sales of such natural 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.
Price Controls
Our sales of natural gas, crude oil, condensate and natural gas liquids are not
regulated and transactions occur 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
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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 the 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.
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.
-11-
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.
Resource Conservation and Recovery Act. The Resource Conservation and 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 could
cause us to incur increased operating expenses.
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 our entire investment in
the property. We believe that we have good title to our oil and natural gas
properties,
-12-
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 mortgage on our oil and gas
properties of at least 90% of our present value of proved properties. 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.
-13-
ITEM 2. PROPERTIES
PRODUCING PROPERTIES
For information regarding Meridian's properties, see "Item 1. Business" above.
ITEM 3. LEGAL PROCEEDINGS
On October 29, 2002, Veritas DGC Land Inc. ("Veritas Land") filed a complaint
against Meridian. The dispute concerns a contract for seismic services for
Meridian's Biloxi Marsh project in St. Bernard Parish, Louisiana. Purporting to
invoke force majeure, Veritas Land, together with Veritas DGC Inc.
(collectively, "Veritas"), unilaterally terminated the parties' contract. The
main dispute is whether Veritas had breached the parties' contract before the
alleged force majeure events and/or when it terminated the contract; Meridian
has not made any payments to Veritas under the parties' contract. Veritas'
complaint seeks breach-of-contract damages of approximately $6.8 million
together with interest, costs and attorneys' fees.
On December 23, 2002, Meridian filed an answer denying the relief sought by
Veritas and asserting a counterclaim against Veritas (1) declaring that (i)
Meridian is not in breach of the parties' seismic contract, (ii) Meridian owes
no amounts to Veritas under the parties' seismic contract or otherwise, (iii)
Veritas materially breached the parties' contract, and (iv) Veritas Land is
solidarily liable to Meridian for all liability of Veritas DGC Inc., and (2)
seeking an award to Meridian of all attorneys' fees, court costs and other
expenses, amounts and damages incurred or suffered (or to be incurred or
suffered) by Meridian. On January 27, 2003, Veritas Land filed an answer to
Meridian's counterclaim, generally denying the counterclaim and asserting
various affirmative defenses thereto. Veritas DGC Inc. has not yet answered the
counterclaim.
No scheduling order has yet been issued. The parties have not yet issued
discovery to each other. Meridian intends to vigorously defend the claims
against it and to vigorously prosecute its counterclaim.
There are no other material legal proceedings to which Meridian or any of its
subsidiaries or partnerships is a party or to 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.
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 2002.
-14-
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
---- ---
2002:
First quarter ............. $ 4.99 $ 3.01
Second quarter ............ 4.94 2.80
Third quarter ............. 3.70 2.05
Fourth quarter ............ 2.28 0.50
2001:
First quarter ............. $ 9.31 $ 6.40
Second quarter ............ 7.98 6.10
Third quarter ............. 6.93 2.65
Fourth quarter ............ 4.30 3.02
The closing sale price of the Common Stock on March 18, 2003, as reported on the
New York Stock Exchange Composite Tape, was $1.24. As of March 18, 2003, we had
approximately 816 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 Credit Agreement from expending more than $2.0 million in
the aggregate for cash dividends on the Common Stock or for purchase of shares
of Common Stock without the prior consent of the lender.
-15-
ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with our Consolidated Financial
Statements and related notes thereto included throughout this report.
YEAR ENDED DECEMBER 31,
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(In thousands, except prices and per share information)
A. SUMMARY OF OPERATING DATA
Production:
Oil (MBbls) 2,213 2,918 3,987 4,454 2,365
Natural gas (MMcf) 15,578 22,085 27,672 22,711 20,603
Natural gas equivalent (MMcfe) 28,856 39,594 51,596 49,438 34,793
Average Prices:
Oil ($/Bbl) $ 24.67 $ 25.17 $ 27.32 $ 17.61 $ 12.19
Natural gas ($/Mcf) 3.36 4.67 4.14 2.38 2.16
Natural gas equivalent ($/Mcfe) 3.71 4.46 4.33 2.68 2.11
B. SUMMARY OF OPERATIONS
Total revenues $ 107,470 $ 178,060 $ 226,246 $ 133,361 $ 74,026
Depletion and depreciation 60,972 67,450 69,648 54,222 45,390
Net earnings (loss)(1) (52,012) 22,551 65,070 11,467 (230,708)
Net earnings (loss) per share:(1)
Basic $ (1.05) $ 0.47 $ 1.34 $ 0.25 $ (5.80)
Diluted (1.05) 0.43 1.06 0.25 (5.80)
Dividends per:
Common share -- -- -- -- --
Redeemable preferred share $ 5.90 -- -- -- --
Preferred share $ $ 0.11 $ 1.36 $ 1.36 $ 0.68
Weighted average common
shares outstanding 49,763 48,350 48,646 45,995 39,774
C. SUMMARY BALANCE SHEET DATA
Total assets $ 456,240 $ 507,900 $ 570,921 $ 477,719 $ 445,175
Long-term obligations, inclusive
of current maturities 203,750 210,000 250,000 270,000 240,084
Redeemable preferred stock 69,690 -- -- -- --
Stockholders' equity 133,393 188,221 270,322 163,860 148,808
(1) Applicable to common stockholders.
-16-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
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.
Our reserves and strategic acreage position provide us with a significant
presence in our areas of focus, enabling us to manage a large asset base and to
add successful exploratory and development wells at relatively low incremental
costs. As of December 31, 2002, we had proved reserves of 167 Bcfe,
approximately 64% of which were natural gas, with a present value of future
pre-tax cash flows (PV-10) of $460 million. We own interests in approximately
299,000 gross (216,000 net) acres, including 25 fields and 138 wells, and we
operate approximately 70% of our total production.
The Company's business model utilizing 3-D seismic technology to explore for
large reserve accumulations in areas where others have overlooked or not
encountered commercial hydrocarbons because of the inability to resolve
structures or recognize hydrocarbon indicators with traditional 2-D seismic
data, has prove successful. During the period of 1992-2002, Meridian generated
and participated in the discovery of over 850 BCFE of natural gas and oil.
As demonstrated from the apparent declines in domestic production, fewer and
fewer economic projects are being recognized by the domestic industry. This is
partly a result of better technology that has improved the industry's ability to
determine probabilities of success, thereby impacting the number of economic
prospects available for drilling.
In addition, the conditions of the industry--price volatility and uncertainty as
well as declining prospect opportunities--and the overall economy have
influenced the availability of debt and equity capital for small capitalization
companies such as Meridian. This, combined with the geological/geophysical and
mechanical risks associated with drilling primarily deep, high-pressured wills
with large working interests, has resulted in a shift in the Company's strategy
for exploration. Recognizing the trend and risks resulting therefrom, beginning
in 2001, management embarked on its current strategy to continue to utilize its
application of 3-D seismic technology to generate and drill shallower,
higher-confidence, lower-risk plays, such as its Biloxi Marshlands project in
St. Bernard Parish, Louisiana, blended with its traditional deeper, higher risk,
but higher potential opportunities where its capital expenditure budget permits.
We have a large, balanced inventory of exploration, exploitation and development
drilling prospects in our producing region. In addition to a solid reserve base
and acreage position in our area of focus, we believe we possess the technical
knowledge and information necessary to sustain successful growth. With licenses
and rights to over 7,500 square miles of 3-D seismic data and 155,000 linear
miles of 2-D seismic data, our technical and professional staff is in a unique
position to continue to generate future prospects for our growth.
Our Strategy. The key elements of our strategy are as follows:
- Generate reserve additions through exploration, exploitation and development
drilling of a balanced portfolio of high potential prospects;
- When appropriate, oil and natural gas reserves will be purchased and/or
disposed of when deemed beneficial. See Management Liquidity Plans on
page 25.
- Maintain a concise geographic focus applying professional and technical
knowledge and experience to the development of a high quality project
inventory;
- Apply a disciplined methodology utilizing 3-D seismic technology to reduce
exploration risk, improve the probability of success, optimize well
locations and reduce our finding costs;
- Maximize percentage ownership in each drilling prospect relative to
probability of success, increasing the impact of discoveries on shareholder
value; and
- Maintain operational control to manage quality, costs and timing of our
drilling and production activities.
We use a disciplined approach in the generation of drilling projects, which
forms the basis of the Company's ability to grow its reserves, production and
cash flow. The Company's process of review begins with a thorough analysis of
each project area using traditional geological methods of prospect development,
combined with computer-aided technology to analyze all available 2-D and 3-D
seismic data and other geological and geophysical data with respect to the
opportunity. In addition, from time to time, we may purchase producing
properties through acquisitions that have substantial additional drilling
opportunities associated with them.
The Company has forecasted between $15 million and $20 million in capital
expenditures for 2003, subject to adjustment depending on drilling results, the
number of wells drilled, drilling conditions and other factors. The 2003
expenditures will be spent primarily on the development of its recently acquired
Biloxi Marshlands exploration/exploitation play in south Louisiana. Should
additional funding be obtained, 2003 capital expenditures could be increased by
$15 million to $20 million.
-17-
Recent Developments. As previously announced, Meridian successfully completed
its Biloxi Marshlands 6-1 well, located in St. Bernard Parish, Louisiana during
the fourth quarter of 2002. The well reached a total depth of 10,800' measured
depth (9,000' TVD) and encountered over 180' of net pay in the targeted Cris "I"
sand. The well was placed on production on March 15, 2003, and is currently
producing at a gross rate of approximately 11,000 Mcf per day, which represents
an increase of approximately 10% of current daily production. During March 2003,
the Company participated in the State of Louisiana oil and gas lease sale, and
successfully bid on five additional tracts in the area covering approximately
740 acres in and around this play. The Company's working interest in the Biloxi
Marshlands No. 6-1 well is 93% (net revenue interest is 69%). Several additional
development and exploratory wells are planned in the area during 2003.
Following the drilling of the Biloxi Marshlands 6-1 well, the Company
constructed a barge based production facility and installed approximately five
miles of 8" pipeline capable of processing and transporting the production from
the current well and future wells on the Biloxi Marshland acreage.
Meridian expects to begin the second phase of its 3-D seismic program on the
Biloxi Marshlands acreage during April 2003. The survey will encompass at least
105 square miles and is expected to be complete during the third quarter of
2003.
The Hughes No. 2 well in Jefferson Davis Parish, Louisiana has been drilled to a
total depth of 17,850' measured depth and a completion in the Bol Mex 5 sand
series is currently underway. The well is a replacement for the Hughes No. 1
that experienced cementing problems during the completion phase and was
subsequently abandoned. During February 2003, the Company completed the
construction of production facilities for the Hughes No. 2 and is currently
conducting final completion operations on the well. Because of the small
wellbore at depth (5 1/2") and the difficulties experienced with the cementing
of the casing in the Hughes No. 1 well, the Company attempted an open hole
completion. This attempt was not a successful as desired but did not preclude
future alternative methods of completion. It is currently planned to clean out
the bore and to complete the well under more traditional methods. Meridian is
the operator of the well and owns an approximate 94% working interest and a 70%
net revenue interest in the well.
Also in Jefferson Davis Parish, Louisiana, in the Company's Thornwell field,
Meridian participated in the drilling of the Blank Living Trust well, which
encountered 20' of pay at a depth of 11,960'. The well was placed on production
flowing at a rate of 9,000 Mcfe and 183 barrels of oil per day during the fourth
quarter of 2002. This field continues to generate new drill sites beyond early
expectations. The Company has identified several additional amplitude anomalies
which it expects to include in our drilling program for 2003. The Company owns
an approximate 26% working interest and a 17% net revenue interest in the well.
Recompletion operations are expected to be underway on the Thibodaux No. 1 well
in the Company's Ramos Field within the next 30-45 days. Once recompleted to the
Operc 3 interval, the Company expects the well to produce at rates of 10,000
Mcfe per day or more. Meridian is operator of the Ramos Field and owns a 65%
working interest and a 44% net revenue interest in the well.
In the Lakeside Field located in Cameron Parish, Louisiana, Meridian completed
its Lacassane No. 1 well in the 13' thick Alliance sand at a depth of
approximately 10,750'. The well initially tested at rates of 1,425 Mcfe of gas
per day from the lower part of the sand and additional perforations are now
being added to include the thicker upper member. The Company owns a 73% working
interest (47% net revenue interest) in the well.
The capital expenditure budget for 2003 is currently forecast between $15
million and $20 million for seismic and drilling activity, primarily focused in
the Biloxi Marshlands project area. The first development well is the Biloxi
Marshlands 6-2 well which is scheduled for April 2003. Other operations are
expected to include a 12,500' well in Ship Shoal Block 320, and certain other
shallow, lower risk opportunities including additional wells in the Biloxi
Marshlands project area. As previously announced, the Company has changed its
exploration focus to concentrate on multiple shallower, low risk projects with
broad exploitation/development potential interspersed with one or more of the
Company's traditional higher risk, but much higher potential, projects.
Industry Conditions. Our revenues, profitability and cash flow 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
-18-
affected by many factors outside of our control. The average price we received
during the year ended December 31, 2002 was $3.71 per Mcfe compared to $4.46 per
Mcfe during the year ended December 31, 2001. Fluctuations in prevailing prices
for oil and natural gas have several important consequences to us, including
affecting 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 our exploration and development program. Refer to Item 7.a. for a
discussion of commodity price risk management activities utilized to mitigate a
portion of the near term effects of this exposure to price volatility.
Full Cost Ceiling Write-down. During 2002, a negative revision in oil and
natural gas proved undeveloped reserves associated with the Kent Bayou Field
resulted in the Company recognizing a full cost ceiling write-down totaling
$69.1 million ($46.9 million after tax) of its oil and natural gas properties. A
decline in oil and natural gas prices caused us to recognize $6.6 million in
full cost ceiling write-downs during 2001. 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.
-19-
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2002, COMPARED TO YEAR ENDED DECEMBER 31, 2001
Oil and natural gas revenues decreased $69.6 million as a result of decreased
production volumes and a decrease in average commodity prices. The production
decrease was primarily a result of the property sales completed during 2001,
hurricane related production losses and natural production declines, partially
offset by the inclusion of new wells being placed on production. The following
table summarizes Meridian's operating revenues, production volumes and average
sales prices for the years ended December 31, 2002 and 2001.
Year Ended
December 31, Increase
2002 2001 (Decrease)
-------- -------- ---------
Production:
Oil (MBbls) 2,213 2,918 (24%)
Natural gas (MMcf) 15,578 22,085 (29%)
Natural gas equivalent (MMcfe) 28,856 39,594 (27%)
Average Sales Price:
Oil (per Bbl) $ 24.67 $ 25.17 (2%)
Natural gas (per Mcf) 3.36 4.67 (28%)
Natural gas equivalent (per Mcfe) 3.71 4.46 (17%)
Gross Revenues (000's):
Oil $ 54,595 $ 73,443 (26%)
Natural gas 52,397 103,203 (49%)
-------- -------- --
Total $106,992 $176,646 (39%)
======== ======== ==
Interest and Other Income.
Interest and other income decreased $0.9 million to $0.5 million in 2002,
compared to $1.4 million for 2001. This decrease was primarily due to a lower
average amount of invested funds and lower interest rates during 2002 than in
2001. A significant portion of the interest income for 2001 was earned on the
investment of funds accumulated from the sale of properties and a Common Stock
offering during 2000. These funds had been accumulated to exercise the option to
buy back the Company's Preferred Stock and six million shares of the Company's
Common Stock from Shell on January 29, 2001.
Operating Expenses.
Oil and natural gas operating expenses decreased $4.7 million to $11.9 million
in 2002, compared to $16.6 million in 2001. This decrease was primarily due to
the sale of high cost, non-core properties during 2001 and the reorganization of
field operations over the last thirteen months partially offset by the inclusion
of costs associated with returning the Company's properties to production
following hurricanes. This reorganization involved a reduction in field
operating personnel and increased emphasis on operating cost reductions. In
addition, the Company undertook an expanded well workover program during 2001 in
order to benefit from the higher commodity prices being realized at the time.
-20-
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes decreased $3.6 million to $8.2 million in 2002,
compared to $11.8 million in 2001. This decrease is largely attributable to the
decrease in natural gas production and the decrease in oil revenues from the
2001 levels, partially offset by an increase in the average tax rate for natural
gas. Meridian's production is primarily from southern Louisiana, and, therefore,
is subject to a current tax rate of 12.5% of gross oil revenues and $0.122 per
Mcf for natural gas. The tax rate for natural gas for the first half of 2001 was
$0.097 per Mcf and from July 2001 through June 2002 was $0.199 per Mcf.
Depletion and Depreciation.
Depletion and depreciation expense decreased $6.4 million to $61.0 million in
2002 from $67.4 million for 2001. This decrease was primarily a result of the
27% decrease in production on an Mcfe basis from 2001, partially offset by an
increase in the depletion rate from 2001 levels primarily due to the write-down
of the proved reserves associated with the Kent Bayou Field.
General and Administrative Expense.
General and administrative expense decreased $1.7 million to $11.8 million in
2002 compared to $13.5 million for the year 2001. This reduction was primarily
due to the savings realized from staff reductions and the purchase and
termination of certain outstanding well bonus plan interests at the end of 2001.
Interest Expense.
Interest expense decreased $5.8 million to $14.3 million in 2002 compared to
$20.1 million for 2001. The decrease is primarily a result of the reduction in
the debt balance and the Federal Reserve Bank's decrease in overall interest
rates which has led to a decrease in the average interest rate on the revolving
credit facilities.
Full Cost Ceiling Writedown.
During 2002, a negative revision in oil and natural gas proved undeveloped
reserves associated with an unsuccessful well drilled in the Kent Bayou Field
resulted in the Company recognizing a full cost ceiling write-down totaling
$69.1 million ($46.9 million after tax) of its oil and natural gas properties.
A decline in oil and natural gas prices caused us to recognize $6.6 million in
full cost ceiling write-downs during 2001.
Credit Facility Retirement Costs.
During 2002, the Company replaced its Chase Manhattan Bank Credit Facility with
a new three-year $175 million underwritten senior secured credit agreement with
Societe Generale and Fortis Capital Corp. Deferred debt costs associated with
the prior credit facility of $1.2 million were written off in 2002.
-21-
YEAR ENDED DECEMBER 31, 2001, COMPARED TO YEAR ENDED DECEMBER 31, 2000
Operating Revenues and Production.
Oil and natural gas revenues decreased $46.8 million as a result of decreased
production volumes partially offset by improved commodity prices. The production
decrease was primarily a result of the property sales in 2001 and 2000 and
natural production declines, partially offset by the inclusion of new wells
being placed on production. The following table summarizes Meridian's operating
revenues, production volumes and average sales prices for the years ended
December 31, 2001 and 2000.
Year Ended
December 31, Increase
2001 2000 (Decrease)
-------- --------- ----------
Production:
Oil (MBbls) 2,918 3,987 (27%)
Natural gas (MMcf) 22,085 27,672 (20%)
Natural gas equivalent (MMcfe) 39,594 51,596 (23%)
Average Sales Price:
Oil (per Bbl) $ 25.17 $ 27.32 (8%)
Natural gas (per Mcf) 4.67 4.14 13%
Natural gas equivalent (per Mcfe) 4.46 4.33 3%
Gross Revenues (000's):
Oil $ 73,443 $ 108,930 (33%)
Natural gas 103,203 114,490 (10%)
-------- --------- --
Total $176,646 $ 223,420 (21%)
======== ========= ==
Interest and Other Income.
Interest and other income decreased $1.4 million to $1.4 million in 2001,
compared to $2.8 million for 2000. This decrease was primarily due to invested
funds during 2000 from the sale of properties and the Common Stock offering that
was being accumulated for the amount required to exercise the option to buy back
the Company's Preferred Stock and six million shares of the Company's Common
Stock from Shell in January 2001.
Operating Expenses.
Oil and natural gas operating expenses decreased $1.6 million to $16.6 million
in 2001, compared to $18.2 million in 2000. This decrease was primarily due to
the decrease in the number of wells from the sale of high cost, non-core
properties and reorganization of field operation resulting in greater
efficiencies partially offset by non-recurring expenses from an expanded well
workover program and higher lifting costs on marginal wells.
-22-
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes decreased $3.8 million to $11.8 million in 2001,
compared to $15.6 million in 2000. This decrease is largely attributable to the
decrease in production from 2000 levels partially offset by an increase in the
tax rate for natural gas. Meridian's production is primarily from southern
Louisiana, and, therefore, is subject to a current tax rate of 12.5% of gross
oil revenues and $0.199 per Mcf for natural gas. The tax rate for natural gas
for the first half of 2000 was $0.078 per Mcf and from July 2000 through June
2001 was $0.097 per Mcf.
Depletion and Depreciation.
Depletion and depreciation expense decreased $2.2 million to $67.4 million in
2001 from $69.6 million for 2000. This decrease was primarily a result of the
23% decrease in production on an Mcfe basis from 2000, partially offset by an
increase in the depletion rate, reflecting the sale of non-core properties.
General and Administrative Expense.
General and administrative expense decreased $2.9 million to $13.5 million in
2001 compared to $16.4 million for the year 2000. This decrease was primarily a
result of staff reductions and decreases in salaries, wages, and other
compensation related to the provisions of the 1998 net profits and well bonus
plans. The plans provide for bonus payments to employees, which are calculated
using a formula derived from the actual net profits on each well in the plan for
the previous year. Decreased payouts in 2001 have resulted primarily due to
decreased production volumes and the purchase and termination of certain well
bonus plans during the latter portion of the year.
Interest Expense.
Interest expense decreased $5.4 million to $20.1 million in 2001 compared to
$25.5 million for 2000. The decrease is primarily a result of the overall
reduction in debt and the Federal Reserve Bank's decrease in overall interest
rates which has led to a decrease in the average interest rate on the credit
facility.
-23-
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. As of December 31, 2002, we had a cash balance of $7.3 million
and a working capital deficit of $47.1 million. The Company is evaluating a
number of opportunities to raise additional funds.
A part of the Company's focus is to satisfy our immediate funding obligations
under our various debt agreements and to implement a plan that will accomplish
an orderly reduction and restructuring of our debt capital, while taking
advantage of the strong asset base built over the years. As a part of the
restructuring and ultimate reduction of our debt, it is our intent to add future
reserves primarily through low risk, 3-D based drilling while maintaining a
disciplined approach to costs.
CREDIT FACILITY.
During August 2002, the Company replaced its Chase Manhattan Bank Credit
Facility with a new three-year $175 million underwritten senior secured credit
agreement (the "Credit Agreement") with Societe Generale, as administrative
agent, lead arranger and book runner, and Fortis Capital Corp., as co-lead
arranger and documentation agent. Deferred debt costs associated with the prior
credit facility of $1.2 million were written off in September 2002. The current
borrowing base under the existing Credit Agreement was established on September
23, 2002, at $165 million, with the borrowing base redetermination date
scheduled for November 30, 2002. The parties to the Credit Agreement have
entered into an amendment of the Agreement, effective March 31, 2003, to
eliminate the November 30, 2002, redetermination date and to reschedule the
borrowing base redetermination date for April 30, 2003, and quarterly
redetermination thereafter. The current borrowing base is $165 million, which is
the same as that established upon the signing of the original Credit Agreement.
On March 31, 2003, the Company received notice from its senior lenders that
effective April 30, 2003 the borrowing base will be established at $138.5
million. Accordingly, the Company has reflected the difference of $26.5 million
as a current maturity of its long-term debt and will be required to make up the
deficiency through the addition of reserves or value to its current reserve base
or pay the senior lenders this deficiency within 90 days of the effective date
of April 30, 2003. Though no assurances can be made that sufficient funds will
be available to pay this deficiency, management believes that it can satisfy
this deficiency through a combination of the addition of reserves, third-party
financing, property sales and cash flow. See Management Liquidity Plans on page
25 for further discussion.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders under the Credit Agreement 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 under the Credit Agreement are secured by pledges of
outstanding capital stock of the Company's subsidiaries and a mortgage on the
Company's oil and natural gas properties of at least 90% of its present value of
proved properties. The Credit Agreement contains various restrictive covenants,
including, among other items, maintenance of certain financial ratios and
restrictions on cash dividends on Common Stock and an unqualified audit report
on the Company's consolidated financial statements beginning with those as of
and for the year ended December 31, 2002. The Company has received from the
senior lenders a waiver of the covenant that would have triggered an event of
default as a result of the independent auditors' report which contained a "going
concern" modification for our 2002 consolidated financial statements. Borrowings
under the Credit Agreement mature on August 13, 2005.
Under the new Credit Agreement, the Company 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 plus an additional 0.5% to 1.5% depending
on the ratio of the aggregate outstanding loans and letters of credit to the
borrowing base; or a federal funds-based rate plus 1/2 of 1% or (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. The Credit Agreement also provides for commitment fees
ranging from 0.375% to 0.5% per annum.
-24-
SUBORDINATED CREDIT AGREEMENT. The Company extended and amended a short-term
subordinated credit agreement with Fortis Capital Corporation for $25 million on
April 5, 2002, with a maturity date of December 31, 2004. The interest rate is
the LIBOR plus 4.5% through December 31, 2002, LIBOR plus 5.5% from January 1,
2003, through August 31, 2003, and LIBOR plus 6.5% from September 1, 2003,
through December 31, 2004. Note payments of $5 million each are due on August
31, 2003, and April 30, 2004, with the remaining $5 million payable on December
31, 2004. Note payments totaling $6.25 million were paid in 2002, with an
additional $1.25 million being paid in January 2003. An additional $2.5 million
that is currently due has been deferred in conjunction with the March 31, 2003,
amendment to the Credit Agreement. No amounts are payable under this
subordinated debt until any and all borrowing base deficiencies under the Credit
Agreement are satisfied.
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.
During March 2002, the Company and the holders of the Notes amended the
conversion price from $7.00 to $5.00 per share. The Notes are convertible at any
time by the holders of the Notes into shares of the Company's Common Stock,
$0.01 par value utilizing 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
would be issued upon conversion of the Notes or issuance of the warrants
discussed below. We may prepay the Notes at any time without penalty or premium.
MANAGEMENT LIQUIDITY PLANS. As noted in our discussion of the Credit Facility,
there will be a $26.5 million borrowing base deficiency at April 30, 2003 that
must be satisfied by either sufficient additions to our proved reserves or
repayment on or before July 29, 2003 to avoid an event of default. An event of
default which is not cured results in the entire debt outstanding becoming due
and payable, unless it is waived by the senior lenders or the Credit Agreement
is otherwise amended. Also, repayment of $2.5 million, after our $1.25 million
January 2003 payment, under our subordinated debt agreement is due but is
deferred pending satisfaction of the borrowing base deficiency under the amended
Credit Agreement. The $5 million subordinated debt repayment that will become
due in August 2003 is also subject to deferral for any borrowing base
deficiencies that may exist at that time. The $34 million due in 2003 under
these agreements represents a significant component of our $47.1 million working
capital deficiency at December 31, 2002.
Based upon our expected level of production and considering a reduced level of
capital spending plan of $15 to $20 million, we project that our available cash
flow from operations is not expected to be sufficient to fund the April 30, 2003
borrowing base deficiency and amounts due or to become due in 2003 under our
subordinated debt agreement. In order to address this liquidity issue and
address the broader issue of aligning our capital structure with our long-term
business strategy, the following plans to sell non-strategic oil and gas
properties and secure new sources of capital through subordinated debt or
similar financing arrangements have been initiated.
In an effort to address the liquidity issue and the broader issue of aligning
our capital structure with our long-term business strategy, the Company is
pursuing several plans that it believes will remedy the current borrowing base
deficiency of $26.5 million.
First, it should be noted that, as of December 31, 2002, the Company's proved
developed reserves have a present value based on SEC regulations that include
prices in effect at year-end and a 10% discount rate, of approximately $460
million or approximately three (3) times its total senior credit facility.
Based on current cash flow projections and the Company's specific knowledge of
its drilling prospects and historical performance in the areas of anticipated
activity, potential opportunities for non-strategic property sales and/or third
party capital funding, it is management's judgment and belief that its business
plan will provide the Company with the means to meet the required coverage for
the new borrowing base by a combination of newly discovered reserves, proceeds
from strategic sales of non-essential properties, where appropriate, and/or the
infusion of third party capital in the form of sub-debt, all on or before July
31, 2003.
Currently, the Company has scheduled two (2) exploration and development wells
that can be drilled and logged prior to July 31, 2003, barring mechanical or
other issues out of the Company's control, such as permitting issues, weather or
equipment availability. The Company believes that these wells together have the
potential of adding reserves sufficient to remedy the borrowing base deficiency.
In addition, the Company has identified certain properties which are not
essential to its future growth and which it is in the process of marketing on a
limited basis. These include reserves of up to 100 BCFE and production of
approximately 50 mmcfe/d having an SEC PV10 value of over $281 million. It is
believed that a sale price of all or a sufficient portion of these properties
can be achieved on or before July 31, 2003.
Further, the Company is in discussions with third parties regarding the infusion
of capital of up to $45-50 million in the form of sub-debt capital. These
discussions are subject to certain due diligence verification of the reserves,
financial reported data and title examination as well as approval by the senior
lenders. The proceeds will be used to reduce the current indebtedness of the
senior credit facility as well as capital expenditures for calendar year 2003.
It is anticipated that the due diligence can be concluded on or before April 30,
2003. Assuming positive results on both the due diligence and of the terms and
conditions of the sub-debt facility by the senior lenders, it is anticipated
that this transaction could close on or before July 31, 2003.
-25-
Although there can be no assurances, management is confident that sufficient
proceeds from the sale of non-strategic oil and natural gas properties and new
subordinated debt or similar financing arrangements will be generated in
sufficient time to satisfy our funding obligations under both the Credit
Agreement and the subordinated debt agreement to permit an orderly reduction and
restructuring of our debt capital.
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. A private placement of $66.85
million of 8.5% redeemable convertible preferred stock was completed during May
2002. The preferred stock is convertible into shares of the Company's Common
Stock at a conversion price of $4.75 per share. Dividends are payable
semi-annually in cash or additional preferred stock. At the option of the
Company, one-third of the preferred shares can be forced to convert to Common
Stock if the closing price of the Company's Common Stock exceeds 150% of the
conversion price for 30 out of 40 consecutive trading days on the New York Stock
Exchange. Based on the above conversion criteria, the Company can elect to
convert up to one-third of the original issue provided that the conversion
occurs no sooner than twelve months from the most recent conversion. The
preferred stock is subject to redemption at the option of the Company after
March 2005, and mandatory redemption on March 31, 2009. The holders of the
preferred stock have been granted registration rights with respect to the shares
of Common Stock issued upon conversion of the preferred stock. Dividend payments
of $1.1 million were paid during the third quarter of 2002. Dividends of $3.9
million were accumulated during 2002, of which $1.1 million was paid in cash and
$2.8 million was satisfied with the issuance of additional shares of redeemable
preferred stock.
CAPITAL EXPENDITURES. Capital expenditures in 2002 consisted of $76.8 million
for property and equipment additions primarily related to exploration and
development of various prospects, including leases, seismic data acquisitions,
and drilling and workover activities. Our strategy is to blend exploration
drilling activities with high-confidence workover and development projects
selected from our broad asset inventory in order to capitalize on periods of
high commodity prices. This strategy brought on production and added reserves
sooner than the drilling of deep, higher risk exploration wells.
The 2003 capital expenditures plan is currently forecast between $15 and $20
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 2003 plan primarily utilizing cash flow from operations.
Where appropriate, excess cash flow from operations as a result of increased
rates or prices beyond that needed for the 2003 capital expenditures plan we
will use to de-lever the Company by development of exploration discoveries or
direct payment of debt.
SALE OF PROPERTIES. On May 17, 2001, the Company sold certain non-strategic oil
and gas properties located in south Louisiana and the Texas Gulf Coast for
approximately $30 million. The sale was comprised of approximately 25 Bcfe
proved developed reserves and 24 Bcfe of undeveloped reserves. Benefits of the
sale include the reduction of total debt by an additional $30 million resulting
in an immediate savings in interest costs on the Company's senior bank debt, the
elimination of $9.5 million in future capital expenditures associated with the
properties, and the elimination of over $5 million in annual lease operating
expenses. On December 20, 2001, we sold additional properties in south Louisiana
for approximately $2.5 million.
CASH OBLIGATIONS. The following summarizes the Company's contractual obligations
at December 31, 2002 and the effect such obligations are expected to have on its
liquidity and cash flow in future periods (in
-26-
thousands):
LESS THAN 1-3 AFTER
ONE YEAR YEARS 3 YEARS TOTAL
--------- ------------ ----------- ------------
Short and long term debt $ 35,250 $ 168,500 $ -- $ 203,750
Non-cancelable operating leases 1,554 3,243 1,230 6,027
--------- ------------ ----------- ------------
Total contractual cash obligations $ 36,804 $ 171,743 $ 1,230 $ 209,777
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. Dividends on the
Redeemable Preferred Stock aggregating $3.9 million were accrued for in 2002. Of
that amount, $1.1 million was paid in cash and $2.8 million was satisfied with
the issuance of additional shares of redeemable preferred stock.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Company's discussion and analysis of its financial condition and results of
operation are based upon consolidated financial statements, which have been
prepared in accordance with accounting principles generally adopted in the
United States. The following summarizes several of our critical accounting
policies. See a complete list of significant accounting policies in Note 1 to
the Consolidated Financial Statements.
USE OF ESTIMATES. The preparation of these financial statements requires the
Company to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses, and disclosure of contingent assets
and liabilities, if any, at the date of the financial statements. The Company
analyzes its estimates, including those related to oil and gas revenues, bad
debts, oil and gas properties, marketable securities, income taxes and
contingencies and litigation. The Company bases its estimates on historical
experience and various other assumptions that are believed to be reasonable
under the circumstances. Actual results may differ from these estimates under
different assumptions or conditions. The Company believes the following critical
accounting policies affect its more significant judgments and estimates used in
the preparation of its consolidated financial statements.
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. Under the full cost method of
accounting, such costs may be incurred both prior to or after the acquisition of
a property and include lease acquisitions, geological and geophysical services,
drilling, completion and equipment. Included in capitalized costs are general
and administrative costs that are directly related with acquisition, exploration
and development activities, and which are not related to production, general
corporate overhead or similar activities. For the years 2002, 2001, and 2000,
such capitalized costs totaled $11.7 million, $13.5 million, and $14.5 million,
respectively. General and administrative costs related to production and general
overhead are expensed as incurred.
Proceeds from the sale of oil and natural gas properties are credited to the
full cost pool, except in transactions involving a significant quantity of
reserves or where the proceeds received from the sale would significantly alter
the relationship between capitalized costs and proved reserves, in which case a
gain or loss would be recognized.
Future development, site restoration, and dismantlement and abandonment costs,
net of salvage values, are estimated property by property based upon current
economic conditions and are included in our amortization of
-27-
our oil and natural gas property costs.
The provision for depletion and amortization of oil and natural gas properties
is computed by the unit-of-production method. Under this computation, the total
unamortized costs of oil and natural gas properties (including future
development, site restoration, and dismantlement and abandonment costs, net of
salvage value), excluding costs of unproved properties, are divided by the total
estimated units of proved oil and natural gas reserves at the beginning of the
period to determine the depletion rate. This rate is multiplied by the physical
units of oil and natural gas produced during the period.
The cost of unevaluated oil and natural gas properties not being amortized is
assessed quarterly to determine whether such properties have been impaired. In
determining impairment, an evaluation is performed on current drilling results,
lease expiration dates, current oil and gas industry conditions, and available
geological and geophysical information. Any impairment assessed is added to the
cost of proved properties being amortized.
FULL-COST CEILING TEST. At the end of each quarter, the unamortized cost of oil
and natural gas properties, net of related deferred income taxes, is limited to
the sum of the estimated future net revenues from proved properties using
unhedged period-end prices, discounted at 10%, and the lower of cost or fair
value of unproved properties adjusted for related income tax effects.
The calculation of the ceiling test and the provision for depletion and
amortization is based on estimates of proved reserves. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in
projecting the future rates of production, timing, and plan of development. The
accuracy of any reserves estimate is a function of the quality of available data
and of engineering and geological interpretation and judgement. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify a revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of oil and natural gas that are ultimately
recovered.
During 2002, a negative revision in oil and natural gas proved undeveloped
reserves associated with the Kent Bayou Field resulted in the Company
recognizing a full cost ceiling write-down totaling $69.1 million ($46.9 million
after tax) of its oil and natural gas properties. A decline in oil and natural
gas prices caused us to recognize $6.6 million in full cost ceiling write-downs
during 2001. Due to the inherent imprecision in estimating oil and natural gas
revenues as well as 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 write-downs in the future 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.
PRICE RISK MANAGEMENT ACTIVITIES. The Company follows the Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" which requires that changes in the derivatives fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. The statement also establishes accounting and reporting standards requiring
that every derivative instrument be reported in the balance sheet as either an
asset or liability measured at its fair value. Special hedge accounting for
qualifying hedges allow the gains and losses on derivatives to offset related
results on the hedged item in the earnings statements and would require that a
company formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. We adopted FAS 133 effective January
1, 2001.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered
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into various swap agreements. These swaps allow the Company to predict with
greater certainty the effective oil and natural gas prices to be received for
our hedged production. Although derivatives often fail to achieve 100%
effectiveness for accounting purposes, our derivative instruments continue to be
highly effective in achieving the risk management objectives for which they were
intended.
These swaps have been designated as cash flow hedges as provided by FAS 133 and
any changes in fair value of the cash flow hedge resulting from ineffectiveness
of the hedge is reported in the consolidated statement of operation as revenues.
The estimated December 31, 2002, fair value of the Company's oil and natural gas
swaps is an unrealized loss of $7.3 million ($4.8 million net of tax) recognized
in other comprehensive income. Based upon December 31, 2002, oil and natural gas
commodity prices, approximately $5.9 million of the loss deferred in other
comprehensive income is expected to lower gross revenues over the next twelve
months when the revenues are generated. The swap agreements expire at various
dates through July 31, 2005.
Payments under these swap agreements reduced oil and natural gas revenues by
$1,183,000 for the year ended December 31, 2002. During the year ended December
31, 2001, the Company had no material open hedging agreements. During the year
ended December 31, 2000, payments under swap agreements reduced oil and natural
gas revenues by $5,419,000.
See Item 7.a. for additional discussion of disclosures about market risk.
FAIR VALUE OF FINANCIAL INSTRUMENTS. Our financial instruments consist of cash
and cash equivalents, accounts receivable, accounts payable, bank borrowings and
subordinated notes. The carrying amounts of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value due to the highly liquid
nature of these short-term instruments. The fair values of the bank borrowings
approximate the carrying amounts as of December 31, 2002 and 2001, and were
determined based upon variable interest rates currently available to us for
borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair values of our subordinated notes due 2005 were $18.9
million and $20.0 million at December 31, 2002 and 2001, respectively. The
carrying value of our subordinated notes was $20 million at December 31, 2002
and 2001.
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
-29-
the level of such production are subject to wide fluctuations and depend on
numerous factors that we do 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 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 against which we are not
fully insured 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.
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 we cannot measure in an exact manner, and
the accuracy of any reserve estimate is a function of the quality of those
accumulations of 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.
Borrowing base for the Credit Facility. The Credit Agreement with Societe
Generale and Fortis Capital Corp. is presently scheduled for borrowing base
redetermination dates on a quarterly basis beginning April 30, 2003. The
borrowing base is redetermined on numerous factors including current reserve
estimates, reserves that have recently been added, current commodity prices,
current production rates and estimated future net cash flows. These factors have
associated risks with each of them. Significant reductions or increases in the
borrowing base will be determined by these factors, which, to a significant
extent, are not under the Company's control.
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ITEM 7.a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is from time to time exposed to market risk from changes in interest
rates and hedging contracts. A discussion of the market risk exposure in
financial instruments follows.
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 principal due December 31,
2004 under our Subordinated Credit Agreement. Since interest charged borrowings
under the Credit Facility floats 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 $183.7 million remains borrowed under the Credit Facility
and $10 million remains borrowed under the Subordinated Credit Agreement, we
estimate our annual interest expense will change by $1.838 million for each 100
basis point change in the applicable interest rates utilized under the Credit
Facility and $10 million from the Subordinated Credit Agreement. 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 $5.00 per share
of our Common Stock.
HEDGING CONTRACTS
Meridian may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. From
time to time, we may enter into swaps and other derivative contracts to hedge
the price risks associated with a portion of anticipated future oil and gas
production. While the use of hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at or prior to expiration or exchanged for physical delivery
contracts. Meridian does not obtain collateral to support the agreements, but
monitors the financial viability of counter-parties and believes its credit risk
is minimal on these transactions. In the event of nonperformance, we would be
exposed to price risk. Meridian has some risk of accounting loss since the price
received for the product at the actual physical delivery point may differ from
the prevailing price at the delivery point required for settlement of the
hedging transaction.
In 2002, we entered into certain swap agreements as summarized in the table
below. The Notional Amount is equal to the total net volumetric hedge position
of Meridian during the periods indicated. The positions effectively hedge
approximately 44% of our proved developed natural gas production and 70% of our
proved developed oil production. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at December 31, 2002 (in
Amount ($ per unit) thousands)
--------- ---------------- ------------------------
Natural Gas (mmbtu)
January 2003 - June 2005 8,610,000 $ 3.80 $ 4,721
Oil (bbls)
January 2003 - July 2005 3,320,000 $ 24.55 $ 2,592
----------
$ 7,313
-31-
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 is calculated 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 Securities and Exchange Commission guidelines, net of
estimated production and future development costs, using prices and
costs as of the date of estimation without future escalation, without
giving effect to non-property related expenses such as general and
administrative expenses, debt service, future income tax expenses and
depreciation, depletion and amortization, and discounted using an
annual discount rate of 10%.
"Tcf" means trillion cubic feet.
-32-
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, 2002 35
Consolidated Balance Sheets--December 31, 2002 and 2001 36
Consolidated Statements of Cash Flows
-- For each of the three years in the period ended December 31, 2002 38
Consolidated Statements of Changes in Stockholders' Equity
-- For each of the three years in the period ended December 31, 2002 39
Notes to Consolidated Financial Statements 40
Consolidated Supplemental Oil and Natural Gas Information (Unaudited) 60
-33-
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, 2002 and 2001, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the three years in the period ended December 31, 2002. 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 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, 2002 and 2001, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States.
As discussed in Note 5 to the 2002 financial statements, the Company's working
capital deficiency, including amounts due under its revolving credit agreement
as a result of a borrowing base redetermination effective April 30, 2003, and
the provisions in that agreement for additional redeterminations of the
borrowing base during 2003, raise substantial doubt about its ability to
continue as a going concern. Management's plans in regard to these matters are
also described in Note 5. The financial statements do not include any
adjustments to reflect the possible future effects on the recoverability and
classification of assets or the amounts and classification of liabilities that
may result from the outcome of this uncertainty.
ERNST & YOUNG LLP
Houston, Texas
April 8, 2003, except for Note 4,
as to which the date is April 15, 2003
34
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share)
YEAR ENDED DECEMBER 31,
-----------------------
2002 2001 2000
-------------- -------------- ------------
REVENUES:
Oil and natural gas $ 106,992 $ 176,646 $ 223,420
Interest and other 478 1,414 2,826
-------------- -------------- ------------
107,470 178,060 226,246
-------------- -------------- ------------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 11,935 16,625 18,234
Severance and ad valorem taxes 8,235 11,761 15,578
Depletion and depreciation 60,972 67,450 69,648
General and administrative 11,820 13,506 16,383
Issuance of stock grants -- 5,566 --
Impairment of long-lived assets 69,124 6,580 --
-------------- -------------- ------------
162,086 121,488 119,843
-------------- -------------- ------------
EARNINGS (LOSS) BEFORE INTEREST
AND INCOME TAXES (54,616) 56,572 106,403
-------------- -------------- ------------
OTHER EXPENSES:
Interest expense 14,253 20,092 25,533
Credit facility retirement costs 1,202 -- --
-------------- -------------- ------------
EARNINGS (LOSS) BEFORE INCOME TAXES (70,071) 36,480 80,870
-------------- -------------- ------------
INCOME TAXES:
Current 298 (300) 1,900
Deferred (22,300) 13,800 8,500
-------------- -------------- ------------
(22,002) 13,500 10,400
-------------- -------------- ------------
NET EARNINGS (LOSS) (48,069) 22,980 70,470
DIVIDENDS ON PREFERRED STOCK 3,943 429 5,400
-------------- -------------- ------------
NET EARNINGS (LOSS) APPLICABLE
TO COMMON STOCKHOLDERS $ (52,012) $ 22,551 $ 65,070
============== ============= ============
NET EARNINGS (LOSS) PER SHARE:
Basic $ (1.05) $ 0.47 $ 1.34
============== ============= ============
Diluted $ (1.05) $ 0.43 $ 1.06
============== ============= ============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES:
Outstanding 49,763 48,350 48,646
Assuming dilution 49,763 55,842 67,521
See notes to consolidated financial statements.
-35-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
DECEMBER 31,
------------
2002 2001
------------- --------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 7,287 $ 14,340
Accounts receivable, less allowance for doubtful accounts
$833 [2002] and $891 [2001] 24,167 24,109
Due from affiliates 1,557 844
Prepaid expenses and other 2,221 1,825
Assets from price risk management activities 604 --
------------- --------------
Total current assets 35,836 41,118
------------- --------------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$18,993 [2002] and $30,247 [2001] not subject to depletion) 1,162,436 1,085,656
Land 478 478
Equipment 9,913 9,578
------------- --------------
1,172,827 1,095,712
Less accumulated depletion and depreciation 761,854 631,758
------------- --------------
Total property and equipment, net 410,973 463,954
------------- --------------
OTHER ASSETS:
Assets from price risk management activities 292 --
Deferred tax asset 2,560 --
Other 6,579 2,828
------------- --------------
Total other assets 9,431 2,828
------------- --------------
Total assets $ 456,240 $ 507,900
============= ==============
See notes to consolidated financial statements.
-36-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
DECEMBER 31,
2002 2001
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 16,842 $ 35,952
Revenues and royalties payable 12,378 9,796
Notes payable 831 25,763
Accrued liabilities 9,958 15,895
Liabilities from price risk management activities 6,781 --
Current income taxes payable 931 (27)
Current portion long-term debt 35,250 --
-------------- -------------
Total current liabilities 82,971 87,379
-------------- -------------
LONG-TERM DEBT 148,500 190,000
-------------- -------------
9 1/2% CONVERTIBLE SUBORDINATED NOTES 20,000 20,000
-------------- -------------
OTHER:
Liabilities from price risk management activities 1,686 --
Deferred income taxes -- 22,300
-------------- -------------
1,686 22,300
-------------- -------------
REDEEMABLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized,
696,900 shares of Series C Redeemable Convertible
Preferred Stock issued at stated value) 69,690 --
-------------- -------------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
53,868,343 [2002] and 53,866,694 [2001] issued) 557 553
Additional paid-in capital 378,215 393,280
Accumulated deficit (209,738) (157,726)
Accumulated other comprehensive loss (4,938) (185)
Unamortized deferred compensation (356) (386)
-------------- -------------
163,740 235,536
Less treasury stock, at cost (3,779,225 shares [2002] and
5,892,342 [2001] shares) 30,347 47,315
-------------- -------------
Total stockholders' equity 133,393 188,221
-------------- -------------
Total liabilities and stockholder's equity $ 456,240 $ 507,900
============== =============
See notes to consolidated financial statements.
-37-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
YEAR ENDED DECEMBER 31,
2002 2001 2000
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ (48,069) $ 22,980 $ 70,470
Adjustments to reconcile net earnings (loss) to net
cash provided by operating activities:
Depletion and depreciation 60,972 67,450 69,648
Amortization of other assets 2,382 2,070 1,276
Non-cash compensation 1,630 7,605 2,729
Credit facility retirement costs 1,202 -- --
Impairment of long-lived assets 69,124 6,580 --
Deferred income taxes (22,300) 13,800 8,500
Changes in assets and liabilities:
Accounts receivable (58) 11,964 (7,595)
Due from affiliates (713) (1,600) 921
Prepaid expenses and other (396) (722) 131
Accounts payable (19,110) 18,119 (3,526)
Revenues and royalties payable 2,582 8,343 (3,275)
Accrued liabilities and other (4,723) (3,102) 3,902
------------ ----------- ----------
Net cash provided by operating activities 42,523 153,487 143,181
------------ ----------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (76,842) (134,125) (102,679)
Sale of property and equipment (272) 30,624 35,054
------------ ----------- ----------
Net cash used in investing activities (77,114) (103,501) (67,625)
------------ ----------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redeemable preferred stock 66,850 -- --
Proceeds from long-term debt 165,000 -- 2,000
Reductions in long-term debt (196,250) (40,000) (22,000)
Proceeds - Notes payable 1,592 28,018 2,921
Reductions - Notes payable (1,524) (2,638) (2,538)
Repurchase of stock -- (114,000) --
Issuance of stock/exercise of stock options 307 1,740 38,663
Preferred dividends (1,102) (3,129) (5,400)
Additions to deferred loan costs (7,335) (759) (697)
------------ ----------- ----------
Net cash provided by (used in) financing activities 27,538 (130,768) 12,949
------------ ----------- ----------
NET CHANGE IN CASH AND CASH EQUIVALENTS (7,053) (80,782) 88,505
Cash and cash equivalents at beginning of year 14,340 95,122 6,617
------------ ----------- ----------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 7,287 $ 14,340 $ 95,122
============= =========== ==========
See notes to consolidated financial statements.
-38-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2000, 2001 AND 2002 (in thousands)
Preferred Stock Common Stock Additional Accumulated Unamortized
------------------- ------------------- Paid-In Earnings Deferred
Shares Par Value Shares Par Value Capital (Deficit) Compensation
------ --------- ------ --------- ---------- ---------- ------------
Balance, December 31, 1999 3,983 $ 135,000 46,410 $ 472 $ 274,298 $ (245,347) $ (378)
Issuance of rights to common stock -- -- -- 4 1,596 -- (1,600)
Company's 401(k) plan contribution -- -- 58 1 335 -- --
Issuance of shares as compensation -- -- 256 3 781 -- --
Exercise of stock options -- -- 18 -- 70 -- --
Compensation expense -- -- -- -- -- -- 1,609
Shares issued to SLOPI -- -- 1,000 10 (10) -- --
Issuance of shares from stock
offering -- -- 6,021 60 38,533 -- --
Preferred dividends -- -- -- -- -- (5,400) --
Net earnings -- -- -- -- -- 70,470 --
------ --------- ------ --------- ---------- ---------- ------------
Balance, December 31, 2000 3,983 135,000 53,763 550 315,603 (180,277) (369)
Repurchase of stock (3,983) (135,000) (6,000) -- 69,180 -- --
Issuance of rights to common stock -- -- -- 2 1,666 -- (1,668)
Company's 401(k) plan contribution -- -- 79 -- (275) -- --
Issuance of shares as compensation -- -- 4 -- 34 -- --
Exercise of stock options -- -- 128 1 317 -- --
Compensation expense -- -- -- -- -- -- 1,651
Issuance of stock grants -- -- -- -- 6,755 -- --
Preferred dividends -- -- -- -- -- (429) --
Net earnings -- -- -- -- -- 22,980 --
------ --------- ------ --------- ---------- ---------- ------------
Balance, December 31, 2001 -- -- 47,974 553 393,280 (157,726) (386)
Issuance of rights to common stock -- -- -- 4 1,596 -- (1,600)
Company's 401(k) plan contribution -- -- 172 -- (1,075) -- --
Issuance of shares as compensation -- -- 1,941 -- (15,586) -- --
Fractional share adjustments -- -- 2 -- -- -- --
Compensation expense -- -- -- -- -- -- 1,630
Accum. Other Compr. Loss, net of taxes
of $2,560 -- -- -- -- -- -- --
Preferred dividends -- -- -- -- -- (3,943) --
Net earnings -- -- -- -- -- (48,069) --
------ --------- ------ --------- --------- ---------- ------------
Balance, December 31, 2002 -- $ -- 50,089 $ 557 $ 378,215 $ (209,738) $ (356)
====== ========= ====== ========= ========= ========== ============
Accumulated
Other Treasury Stock
Comprehensive --------------
Loss Shares Cost Total
------------- ------ -------- ----------
Balance, December 31, 1999 $ (185) -- $ -- $ 163,860
Issuance of rights to common stock -- -- -- --
Company's 401(k) plan contribution -- -- -- 336
Issuance of shares as compensation -- -- -- 784
Exercise of stock options -- -- -- 70
Compensation expense -- -- -- 1,609
Shares issued to SLOPI -- -- -- --
Issuance of shares from stock
offering -- -- -- 38,593
Preferred dividends -- -- -- (5,400)
Net earnings -- -- -- 70,470
------------- ------ -------- ----------
Balance, December 31, 2000 (185) -- -- 270,322
Repurchase of stock -- 6,000 (48,180) (114,000)
Issuance of rights to common stock -- -- -- --
Company's 401(k) plan contribution -- (79) 629 354
Issuance of shares as compensation -- -- -- 34
Exercise of stock options -- (29) 236 554
Compensation expense -- -- -- 1,651
Issuance of stock grants -- -- -- 6,755
Preferred dividends -- -- -- (429)
Net earnings -- -- -- 22,980
------------- ------ -------- ----------
Balance, December 31, 2001 (185) 5,892 (47,315) 188,221
Issuance of rights to common stock -- -- -- --
Company's 401(k) plan contribution -- (172) 1,382 307
Issuance of shares as compensation -- (1,941) 15,586 --
Fractional share adjustments -- -- -- --
Compensation expense -- -- -- 1,630
Accum. Other Compr. Loss, net of taxes
of $2,560 (4,753) -- -- (4,753)
Preferred dividends -- -- -- (3,943)
Net earnings -- -- -- (48,069)
------------- ------ -------- ----------
Balance, December 31, 2002 $ (4,938) 3,779 $(30,347) $ 133,393
============= ====== ======== ==========
See notes to consolidated financial statements.
-39-
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.
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, considering related salvage values.
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.
Repairs and maintenance are charged to expense as incurred.
-40-
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 $11.7 million, $21.5 million and $25.3 million in 2002, 2001 and
2000, respectively. Cash payments for income taxes (federal and state, net of
receipts) were none for 2002, $2.27 million for 2001, and none for 2000.
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 not been
significant.
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 (the sales
method). 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, warrants granted and convertible debt. 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.
If compensation expense for these plans had been determined based on the fair
value of the options consistent with SFAS No. 123, our net earnings (loss) and
earnings (loss) per share would have been adjusted to the following pro forma
amounts (thousands of dollars, except per share):
FAIR VALUE OF FINANCIAL INSTRUMENTS
Our financial instruments consist of cash and cash equivalents, accounts
receivable, accounts payable, bank borrowings and subordinated notes. The
carrying amounts of cash and cash equivalents, accounts receivable and accounts
payable approximate fair value due to the highly liquid nature of these
short-term instruments. The fair values of the bank borrowings approximate the
carrying amounts as of December 31, 2002 and 2001, and were determined based
upon variable interest rates currently available to us for borrowings with
similar terms. Based on quoted market prices as of the respective dates, the
fair values of our subordinated notes due 2005 were $18.9 million and $20.0
million at December 31, 2002 and 2001, respectively. The carrying value of our
subordinated notes was $20 million at December 31, 2002 and 2001.
-41-
2002 2001 2000
Net earnings (loss) as reported $(52,012) $ 22,551 $ 65,070
Stock-based compensation expense determined
under fair value method for all awards, net of tax 39 1,035 167
Net earnings (loss) pro forma (52,051) 21,516 64,903
Basic earnings (loss) per share:
As reported $ (1.05) 0.47 1.34
Pro forma $ (1.05) 0.45 1.33
Diluted earnings (loss) per share:
As reported $ (1.05) 0.43 1.06
Pro forma $ (1.05) 0.42 1.06
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 2.54%, 4.7% and 4.8%; dividend
yield of 0%; volatility factors of the expected market price of the Company's
Common Stock of 0.81, 0.82 and 0.84 for 2002, 2001 and 2000, respectively; and a
weighted-average expected life of five years. These assumptions resulted in a
weighted average grant date fair value of $1.97, $4.08 and $2.73 for options
granted in 2002, 2001 and 2000, respectively. For purposes of the pro forma
disclosures, the estimated fair value is amortized to expense over the awards'
vesting period.
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. Pro forma compensation
cost reflected above may not be representative of the cost to be expected in
future years.
DERIVATIVE FINANCIAL INSTRUMENTS
In June 1998 the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Certain Hedging Activities. In June 2000 the FASB issued SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activity, an Amendment of SFAS 133. SFAS No. 133 and SFAS No. 138 require that
all derivative instruments be recorded on the balance sheet at their respective
fair values. SFAS No. 133 and SFAS No. 138 are effective for all fiscal quarters
of all fiscal years beginning after June 30, 2000; the Company adopted SFAS No.
133 and SFAS No. 138 on January 1, 2001.
-42-
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. The Company's derivative financial instruments have not been
entered into for trading purposes and the Company has the ability and intent to
hold these instruments to maturity. Counterparties to the Company's interest
rate swap agreements are major financial institutions.
All derivatives are recognized on the balance sheet at their fair value. On the
date the derivative contract is entered into, the Company designates the
derivative as either a hedge of the fair value of a recognized asset or
liability or of an unrecognized firm commitment ("fair value" hedge) or a hedge
of a forecasted transaction or the variability of cash flows to be received or
paid related to a recognized asset or liability ("cash flow" hedge) The Company
formally documents all relationships between hedging instruments and hedged
items, as well as its risk management objective and strategy for undertaking
various hedge transactions. This process includes linking all derivatives that
are designated as fair-value or cash-flow hedges to specific assets and
liabilities on the balance sheet or to specific firm commitments or forecasted
transactions. The Company also formally assesses, both at the hedge's inception
and on an ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair values or cash
flows of hedged items.
Changes in the fair value of a derivative that is highly effective and that is
designated and qualifies as a cash-flow hedge are recorded in other
comprehensive income, until earnings are affected by the variability in cash
flows of the designated hedged item. The Company reflected no gain or loss
related to hedge ineffectiveness during the each of the two years ended December
31, 2002.
The Company discontinues hedge accounting prospectively when it is determined
that the derivative is no longer effective in offsetting changes in the fair
value or cash flows of the hedged item, the derivative expires or is sold,
terminated, or exercised, the derivative is redesignated as a hedging instrument
because it is unlikely that a forecasted transaction will occur, or management
determines that designation of the derivative as a hedging instrument is no
longer appropriate.
When hedge accounting is discontinued because it is probable that a forecasted
transaction will not occur, the Company continues to carry the derivative on the
balance sheet at its fair value with subsequent changes in fair value included
in earnings, and gains and losses that were accumulated in other comprehensive
income are recognized immediately in earnings. In all other situations in which
hedge accounting is discontinued, the Company continues to carry the derivative
at its fair value on the balance sheet and recognizes any subsequent changes in
its fair value in earnings. Gains or losses accumulated in other comprehensive
income at the time the hedge relationship is terminated are recorded in earnings
over the original life of the derivative instrument.
EARLY ADOPTION OF FAS NO. 145
On July 1, 2002, we adopted the provisions of Statement of Financial Accounting
Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" ("SFAS No. 145"). The
applicable portion of this Statement rescinds Statement of Financial Accounting
Standards No. 4 "Reporting Gains and Losses from Extinguishment of Debt" which
required all gains and losses from extinguishment of debt to be aggregated and,
when material, classified as an extraordinary item, net of related income tax
effect. Consistent with SFAS No. 145, the $1.2 million in unamortized debt costs
associated with the termination of the Company's revolving credit agreement in
August 2002 were recognized as credit facility retirement costs in the
Consolidated Statement of Operations. SFAS No. 145 also amends Statement of
Financial Accounting Standards No. 13 "Accounting for Leases" ("SFAS No. 13") to
require that certain lease modifications having economic effects similar to
sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. This portion of SFAS No. 145 did not have any
effect on our financial position or results of operations for any periods
presented.
-43-
NEW ACCOUNTING PRONOUNCEMENT
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143
"Accounting for Asset Retirement Obligations." The statement requires entities
to record the fair value of a liability for legal obligations associated with
the retirement obligations of tangible long-lived assets in the period in which
it is incurred. When the liability is initially recorded, the entity increases
the carrying amount of the related long-lived asset. Over time, accretion of the
liability is recognized each period, and the capitalized cost is depreciated
over the useful life of the related asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss upon settlement. This standard will require us to record a liability for
the fair value of our dismantlement an abandonment costs, excluding salvage
values. The standard is effective for fiscal years beginning after June 15,
2002. The Company has completed its assessment of SFAS No. 143. At January 1,
2003, we estimated the impact of SFAS No. 143 and expect to record an after tax
loss of between $0.5 million and $2.5 million as a cumulative effect of change
in accounting principle. Additionally, the Company expects to record an asset
retirement obligation liability of between $4.0 million and $5.0 million and an
increase to net properties and equipment of between $2.5 million and $3.5
million. The application of SFAS No. 143 in 2003 and future years will result in
the recognition of accretion expense related to the discounted liability for the
asset retirement obligation and should not have a material impact on the
Company's depletion rate. There will be no impact on the Company's cash flow as
a result of adopting SFAS No. 143. This cumulative effect of change in
accounting principle will be a non-cash charge to net income in the first
quarter of 2003.
USE OF ESTIMATES
The preparation of these financial statements requires the Company to make
estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses, and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements. The Company analyzes its
estimates, including those related to oil and gas revenues, bad debts, oil and
gas properties, marketable securities, income taxes and contingencies and
litigation. The Company bases its estimates on historical experience and various
other assumptions that are believed to be reasonable under the circumstances.
Actual results may differ from these estimates under different assumptions or
conditions.
RECLASSIFICATION OF PRIOR PERIOD STATEMENTS
Certain minor reclassifications have been made to the prior period financial
statements to conform to current year presentation.
3. IMPAIRMENT OF LONG-LIVED ASSETS
In the third quarter 2002, a negative revision in oil and natural gas proved
undeveloped reserves associated with an unsuccessful well drilled in Kent Bayou
Field resulted in a full cost ceiling write-down totaling $69.1 million ($46.9
million after tax) of its oil and natural gas properties.
A decline in oil and natural gas prices during 2001 resulted in the Company
recognizing full cost ceiling write-downs totaling $6.6 million of its oil and
natural gas properties.
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.
-44-
4. DEBT
REVOLVING CREDIT AGREEMENT
During August 2002, the Company replaced its Chase Manhattan Bank Credit
Facility with a new three-year $175 million underwritten senior secured credit
agreement (the "Credit Agreement") with Societe Generale, as administrative
agent, lead arranger and book runner, and Fortis Capital Corp., as co-lead
arranger and documentation agent. The remaining unamortized deferred debt costs
associated with the prior credit facility of $1.2 million were written off in
September 2002. The current borrowing base under the existing Credit Agreement
was established on September 23, 2002, at $165 million, with the borrowing base
redetermination date scheduled for November 30,2002. The parties to the Credit
Agreement have entered into an amendment of the Agreement, effective March 31,
2003, to eliminate the November 30, 2002, redetermination date and to reschedule
the borrowing base redetermination date for April 30, 2003, and quarterly
redetermination thereafter. The current borrowing base is $165 million, which is
the same as that established upon the signing of the original Credit Agreement.
On March 31, 2003, the Company received notice from its senior lenders that
effective April 30, 2003 the borrowing base will be established at $138.5
million. Accordingly, the Company will reflect the difference of $26.5 million
as a current maturity of its long-term debt and will be required to make up the
deficiency through the addition of reserves or value to its current reserve base
or pay the senior lenders this deficiency within 90 days of the effective date
of April 30, 2003. Though no assurances can be made that sufficient funds will
be available to pay this deficiency, management believes that it can satisfy
this deficiency through a combination of the addition of reserves, third-party
financing, property sales and cash flow.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders under the Credit Agreement 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 under the Credit Agreement are secured by pledges of
outstanding capital stock of the Company's subsidiaries and a mortgage on the
Company's oil and natural gas properties of at least 90% of its present value of
proved properties. The Credit Agreement contains various restrictive covenants,
including, among other items, maintenance of certain financial ratios and
restrictions on cash dividends on Common Stock. The Company has received from
the senior lenders a waiver of the covenant that would have triggered an event
of default as a result of the independent auditors' report which contained a
"going concern" modification for our 2002 consolidated financial statements.
Borrowings under the Credit Agreement mature on August 13, 2005.
Under the new Credit Agreement, the Company 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 plus an additional 0.5% to 1.5% depending
on the ratio of the aggregate outstanding loans and letters of credit to the
borrowing base; or a federal funds-based rate plus 1/2 of 1% or (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. The Credit Agreement also provides for commitment fees
ranging from 0.375% to 0.5% per annum.
SUBORDINATED CREDIT AGREEMENT
The Company extended and amended a short-term subordinated credit agreement with
Fortis Capital Corporation for $25 million on April 5, 2002, with a maturity
date of December 31, 2004. The notes are unsecured and contain customary events
of default, but do not contain any maintenance or other restrictive covenants.
The interest rate is the London interbank offered rate ("LIBOR") plus 4.5%
through December 31, 2002, LIBOR plus 5.5% from January 1, 2003, through August
31, 2003, and LIBOR plus 6.5% from September 1, 2003, through December 31, 2004.
Note payments of $5 million each are due on August 31, 2003 and April 30, 2004,
with the remaining $5 million payable on December 31, 2004. Note payments
totaling $6.25 million were paid in 2002, with an additional $1.25 million being
paid in January 2003. An
-45-
additional $2.5 million that is currently due has been deferred in conjunction
with the March 31, 2003, amendment to the Credit Agreement. No amounts are
payable under this subordinated debt until any and all borrowing base
deficiencies under the Credit Agreement are satisfied. The Company is in
compliance under this agreement.
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 Company is in compliance under this agreement.
During March 2002, the Company and the holders of the Notes amended the
conversion price from $7.00 to $5.00 per share. The Notes are convertible at any
time by the holders of the Notes into shares of the Company's Common Stock,
$0.01 par value, utilizing 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
would be issued upon conversion of the Notes.
Scheduled maturities for the next five years and thereafter, as of December 31,
2002, are as follows: $35.25 million in 2003, $10.0 million in 2004, $158.5
million in 2005, and none thereafter.
5. CAPITAL RESOURCES AND LIQUIDITY
As noted in our discussion of the Credit Facility, there will be a $26.5 million
borrowing base deficiency at April 30, 2003 that must be satisfied by either
sufficient additions to our proved reserves or repayment on or before July 29,
2003 to avoid an event of default. An event of default which is not cured
results in the entire debt outstanding becoming due and payable, unless it is
waived by the senior lenders or the Credit Agreement is otherwise amended. Also,
repayment of $2.5 million, after our $1.25 million January 2003 payment, under
our subordinated debt agreement is due but is deferred pending satisfaction of
the borrowing base deficiency under the amended Credit Agreement. The $5 million
subordinated debt repayment that will become due in August 2003 is also subject
to deferral for any borrowing base deficiencies that may exist at that time. The
$34 million due in 2003 under these agreements represents a significant
component of our $47.1 million working capital deficiency at December 31, 2002.
Based upon our expected level of production and considering a reduced level of
capital spending plan of $15 to $20 million, we project that our available cash
flow from operations is not expected to be sufficient to fund the April 30, 2003
borrowing base deficiency and amounts due or to become due in 2003 under our
subordinated debt agreement. In order to address this liquidity issue and
address the broader issue of aligning our capital structure with our long-term
business strategy, the following plans to sell non-strategic oil and gas
properties and secure new sources of capital through subordinated debt or
similar financing arrangements have been initiated.
In an effort to address the liquidity issue and the broader issue of aligning
our capital structure with our long-term business strategy, the Company is
pursuing several plans that it believes will remedy the current borrowing base
deficiency of $26.5 million.
First, it should be noted that, as of December 31, 2002, the Company's proved
developed reserves have a present value based on SEC regulations that include
prices in effect at year-end and a 10% discount rate, of approximately $460
million or approximately three (3) times its total senior credit facility.
Based on current cash flow projections and the Company's specific knowledge of
its drilling prospects and historical performance in the areas of anticipated
activity, potential opportunities for non-strategic property sales and/or third
party capital funding, it is management's judgment and belief that its business
plan will provide the Company with the means to meet the required coverage for
the new borrowing base by a combination of newly discovered reserves, proceeds
from strategic sales of non-essential properties, where appropriate, and/or the
infusion of third party capital in the form of sub-debt, all on or before July
31, 2003.
Currently, the Company has scheduled two (2) exploration and development wells
that can be drilled and logged prior to July 31, 2003, barring mechanical or
other issues out of the Company's control, such as permitting issues, weather or
equipment availability. The Company believes that these wells together have the
potential of adding reserves sufficient to remedy the borrowing base deficiency.
In addition, the Company has identified certain properties which are not
essential to its future growth and which it is in the process of marketing on a
limited basis. These include reserves of up to 100 BCFE and production of
approximately 50 mmcfe/d having an SEC PV10 value of over $281 million. It is
believed that a sale price of all or a sufficient portion of these properties
can be achieved on or before July 31, 2003.
Further, the Company is in discussions with third parties regarding the infusion
of capital of up to $45-50 million in the form of sub-debt capital. These
discussions are subject to certain due diligence verification of the reserves,
financial reported data and title examination as well as approval by the senior
lenders. The proceeds will be used to reduce the current indebtedness of the
senior credit facility as well as capital expenditures for calendar year 2003.
It is anticipated that the due diligence can be concluded on or before April 30,
2003. Assuming positive results on both the due diligence and of the terms and
conditions of the sub-debt facility by the senior lenders, it is anticipated
that this transaction could close on or before July 31, 2003.
-46-
Although there can be no assurances, management is confident that sufficient
proceeds from the sale of non-strategic oil and natural gas properties and new
subordinated debt or similar financing arrangements will be generated in
sufficient time to satisfy our funding obligations under both the Credit
Agreement and the subordinated debt agreement to permit an orderly reduction and
restructuring of our debt capital.
6. 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 $2.2 million, $2.1 million and $1.9 million in 2002,
2001 and 2000, respectively. Future minimum lease payments under all
non-cancelable operating leases having initial terms of one year or more are
$1.6 million for each of the years 2003 - 2005, $1.2 million for the year 2006,
and none thereafter.
7. COMMITMENTS AND CONTINGENCIES
LITIGATION
On October 29, 2002, Veritas DGC Land Inc. ("Veritas Land") filed a complaint
against Meridian. The dispute concerns a contract for seismic services for
Meridian's Biloxi Marsh project in St. Bernard Parish, Louisiana. Purporting to
invoke force majeure, Veritas Land, together with Veritas DGC Inc.
(collectively, "Veritas"), unilaterally terminated the parties' contract. The
main dispute is whether Veritas had breached the parties' contract before the
alleged force majeure events and/or when it terminated the contract; Meridian
has not made any payments to Veritas under the parties' contract. Veritas'
complaint seeks breach-of-contract damages of approximately $6.8 million
together with interest, costs and attorneys' fees.
On December 23, 2002, Meridian filed an answer denying the relief sought by
Veritas and asserting a counterclaim against Veritas (1) declaring that (i)
Meridian is not in breach of the parties' seismic contract, (ii) Meridian owes
no amounts to Veritas under the parties' seismic contract or otherwise, (iii)
Veritas materially breached the parties' contract, and (iv) Veritas Land is
solidarily liable to Meridian for all liability of Veritas DGC Inc., and (2)
seeking an award to Meridian of all attorneys' fees, court costs and other
expenses, amounts and damages incurred or suffered (or to be incurred or
suffered) by Meridian. On January 27, 2003, Veritas Land filed an answer to
Meridian's counterclaim, generally denying the counterclaim and asserting
various affirmative defenses thereto. Veritas DGC Inc. has not yet answered the
counterclaim.
No scheduling order has yet been issued. The parties have not yet issued
discovery to each other. Meridian intends to vigorously defend the claims
against it and to vigorously prosecute its counterclaim.
-47-
There are no other material legal proceedings to which Meridian or any of its
subsidiaries or partnerships is a party or to 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.
8. TAXES ON INCOME
Provisions (benefits) for federal and state income taxes are as follows
(thousands of dollars):
YEAR ENDED DECEMBER 31,
-----------------------
2002 2001 2000
---- ---- ----
Current:
Federal $ 327 $ 77 $ 779
State (29) (377) 1,121
Deferred:
Federal (22,300) 13,800 8,500
------------ ----------- ------------
$ (22,002) $ 13,500 $ 10,400
============ =========== ============
Income tax expense as reported is reconciled to the federal statutory rate (35%)
as follows (thousands of dollars):
YEAR ENDED DECEMBER 31,
-----------------------
2002 2001 2000
---- ---- ----
Income tax provision (benefit) computed at statutory rate $ (24,525) $ 12,768 $ 28,305
Nondeductible costs 308 977 1,175
State income tax net of federal tax benefit (19) (245) 729
Net operating loss carryforwards not benefited
in the income tax provision -- -- --
Change in valuation allowance 2,234 -- (19,809)
------------- ----------- ------------
$ (22,002) $ 13,500 $ 10,400
============= =========== ============
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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,
------------
2002 2001
---- ----
Deferred tax assets:
Net operating tax loss carryforward $ 54,521 $ 60,538
Statutory depletion carryforward 950 950
Tax credits 1,651 856
Unrealized hedge loss 2,560 --
Other 4,110 3,120
Valuation allowance (2,734) (500)
----------- -----------
Total deferred tax assets 61,058 64,964
----------- -----------
Deferred tax liabilities:
Book in excess of tax basis in oil and gas properties 58,428 87,194
Basis differential in long-term investments 70 70
----------- -----------
Total deferred tax liabilities 58,498 87,264
----------- -----------
Net deferred tax (liability) $ 2,560 $ (22,300)
=========== ===========
As of December 31, 2002, the Company has approximately $155.8 million of tax net
operating loss carryforwards which begin to expire in 2004. The net operating
loss carryforwards assume that certain items, primarily intangible drilling
costs, have been deducted to the maximum extent allowed under the tax laws for
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.
A significant portion of the net operating loss carryforwards are subject to
change in ownership and separate return limitations that could restrict the
Company's ability to utilize such losses in the future. Appropriate accounting
policy requires a valuation allowance to be recognized if, based on the weight
of available evidence, it is more likely than not that some portion or all of
the deferred tax asset will not be realized. Accordingly, the Company has
recorded a valuation allowance against a portion of its net operating loss
carryforward, the realization of which is not reasonably assured. The net
deferred tax asset relates to the tax effects associated with the deferred hedge
loss from commodity price risk management activities reflected as a component of
other comprehensive income (loss).
-49-
9. 8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK
A private placement of $66.85 million of 8.5% redeemable convertible preferred
stock was completed during May 2002. The preferred stock is convertible into
shares of the Company's Common Stock at a conversion price of $4.75 per share.
Dividends are payable semi-annually in cash or additional preferred stock. At
the option of the Company, one-third of the preferred shares can be forced to
convert to Common Stock if the closing price of the Company's Common Stock
exceeds 150% of the conversion price for 30 out of 40 consecutive trading days
on the New York Stock Exchange. Based on the above conversion criteria, the
Company can elect to convert up to one-third of the original issue provided that
the conversion occurs no sooner than twelve months from the most recent
conversion. The preferred stock is subject to redemption at the option of the
Company after March 2005, and mandatory redemption on March 31, 2009. The
holders of the preferred stock have been granted registration rights with
respect to the shares of Common Stock issued upon conversion of the preferred
stock. Dividends of $3.9 million were accumulated during 2002, of which $1.1
million was paid in cash and $2.84 million was satisfied with the issuance of
additional shares of redeemable preferred stock.
10. STOCKHOLDERS' EQUITY
COMMON STOCK
On September 29, 2000, the Company announced that it sold to certain investors
an aggregate of 6,021,500 shares of Common Stock at a price of $6 5/8 per share
under the terms of the prospectus supplement dated September 28, 2000. The
shares were placed with certain investors on a best-efforts basis. In connection
with the placement of the shares, the Company paid the placement agents a total
fee of approximately $1.2 million, resulting in proceeds of approximately $38.7
million to the Company. The Company used the proceeds from this sale to fund in
part the exercise of the option to repurchase Preferred and Common Stock from
Shell for $114 million on January 29, 2001.
PREFERRED STOCK
On June 30, 1998, the Company issued to SLOPI 3,982,906 shares of the Company's
Preferred Stock. The Preferred Stock had an aggregate stated value of $135
million and ranked prior to the Common Stock as to distribution of assets and
payment of dividends. The holder thereof had the right to convert the Preferred
Stock into an aggregate of 12,837,428 shares of Common Stock. The Preferred
Stock was 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. On
January 29, 2001, the Company completed the repurchase of all of the then
outstanding Preferred Stock. See following notes below.
Meridian and SLOPI, on July 18, 2000, announced a definitive agreement granting
Meridian an option to repurchase all of the outstanding shares of Meridian
Preferred Stock (convertible into 12.8 million shares of Common Stock), plus six
million shares of Meridian Common Stock then held by Shell, for an aggregate
cash price of $114 million. The "Option and Standstill Agreement" was
exercisable in a single transaction through January 31, 2001. As consideration
for the grant of the option, Meridian issued Shell one million shares of
Meridian Common Stock in July 2000.
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On January 29, 2001, the Company completed the repurchase of all of the then
outstanding Preferred Stock (convertible into 12.8 million shares of Common
Stock) and six million shares of Common Stock from Shell for $114 million. The
$114 million stock buyback price was generated through a balanced financing
structure including $38.7 million in net proceeds from the issuance of Common
Stock at $6 5/8 per share; $25 million in subordinated debt; and $50.3 million
of available cash flow and proceeds from the sale of non-core properties. Shell
remains Meridian's largest shareholder, with approximately 7.1 million shares of
Common Stock.
WARRANTS
The Company had the following warrants outstanding at December 31, 2002:
NUMBER OF EXERCISE
WARRANTS SHARES PRICE EXPIRATION DATE
-------- ------ ----- ---------------
Executive Officers 1,428,000 $ 5.85 *
General Partner 1,014,504 $ 0.19 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, 2002, 2001 and 2000, 445,765, 642,897 and 915,997 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, 1999 4,678,433 5.19
Granted 183,945 4.45
Exercised (17,750) 3.95
Canceled (454,233) 9.31
--------- -------
Outstanding at December 31, 2000 4,390,395 4.74
Granted 73,500 6.01
Exercised (128,320) 4.31
Canceled (176,000) 9.88
--------- -------
Outstanding at December 31, 2001 4,159,575 $ 4.56
Granted 15,000 3.00
Exercised -- --
Canceled (10,500) 5.22
--------- -------
Outstanding at December 31, 2002 4,164,075 $ 4.55
========= =======
Shares exercisable:
December 31, 2002 4,089,450 $ 4.53
December 31, 2001 4,051,075 $ 4.53
December 31, 2000 3,527,941 $ 5.05
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------- -------------------
WEIGHTED WEIGHTED
RANGE OF OUTSTANDING AT AVERAGE EXERCISABLE AT AVERAGE
EXERCISABLE PRICES DECEMBER 31, 2002 EXERCISE PRICE DECEMBER 31, 2002 EXERCISE PRICE
------------------ ----------------- -------------- ----------------- --------------
$2.44 - $4.94 3,374,925 $ 3.43 3,356,550 $ 3.43
$5.31 - $9.00 495,500 8.15 439,250 8.38
$10.38 - $13.25 293,650 11.35 293,650 11.35
--------- -------- --------- --------
4,164,075 $ 4.55 4,089,450 $ 4.53
========= ======== ========= ========
The weighted average remaining contractual life of options outstanding at
December 31, 2002, was approximately seven years.
DEFERRED COMPENSATION
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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 for 2000, $417,000 for 2001 and $415,000 for
2002, which is substantially all of their salaried compensation for each of the
years. 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,
at June 30, 1999, for deferrals during the second half of 1999, at December 31,
1999, for deferrals during the first half of 2000, at June 30, 2000, for
deferrals during the second half of 2000, at December 31, 2000, for deferrals
during the first half of 2001, at June 30, 2001, for deferrals during the second
half of 2001, at December 31, 2001, for deferrals during the first half of 2002,
and at June 30, 2002, for deferrals during the second half of 2002. At December
31, 2002, the plan had reserved 3,600,000 shares of Common Stock for future
issuance and 1,427,804 rights have been granted. No actual shares of Common
Stock have been 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
$1,630,000, $1,651,000 and $1,609,000 for 2002, 2001 and 2000 periods,
respectively, and is reflected in general and administrative expense for the
years ended December 31, 2002, 2001 and 2000, respectively.
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.
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11. 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. Total expense related
to the to Company's 401(k) plan was $306,000, $292,000, and $361,000 in 2002,
2001, and 2000, respectively.
During 1998, the Company implemented a 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"). Payments under the plans are
calculated based on revenues from production on previously discovered reserves,
as realized by the Company at current commodity prices, less operating expenses.
Total compensation related to these plans totaled $4.2 million, $7.1 million and
$12.0 million in 2002, 2001 and 2000, respectively. A portion of these amounts
has been capitalized with regard to personnel engaged in activities associated
with exploratory projects. 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. 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. Effective March 2001, the participants in the
Geoscientist Plan were notified that no additional future wells would be placed
into the plan. During 2002, the Executive Committee decided to modify this
position and for certain key geoscientists the plan will include future new
wells. Additionally, certain interests in the Well Bonus Plans were repurchased
and terminated from current and former employees for issuance of stock grants
(see Note 11).
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
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
-54-
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. 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.
12. ISSUANCE OF STOCK GRANTS
Effective December 2001, an agreement was executed to repurchase and terminate
certain interests in the Well Bonus Plans from current and former employees in
exchange for the issuance of Common Stock. The offering was for a total of
1,940,991 shares of our Common Stock. The Common Stock was issued on February 4,
2002, at the last reported sales price of $3.48 per share.
13. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address 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.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered into various swap
agreements. These swaps allow the Company to predict with greater certainty the
effective oil and natural gas prices to be received for our hedged production.
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, our derivative instruments continue to be highly effective in
achieving the risk management objectives for which they were intended.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered into various swap
agreements. These swaps allow the Company to predict with greater certainty the
effective oil and natural gas prices to be received for our hedged production.
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, our derivative instruments continue to be highly effective in
achieving the risk management objectives for which they were intended.
These swaps have been designated as cash flow hedges as provided by FAS 133 and
any changes in fair value of the cash flow hedge resulting from ineffectiveness
of the hedge is reported in the consolidated statement of operation as revenues.
The estimated December 31, 2002, fair value of the Company's oil and natural gas
swaps is an unrealized loss of $7.3 million ($4.8 million net of tax) recognized
in other comprehensive income. Based upon December 31, 2002, oil and natural gas
commodity prices approximately $5.9 million of the loss deferred in other
comprehensive income is expected to lower gross revenues over the next twelve
months when the revenues are generated. The swap agreements expire at various
dates through July 31, 2005.
-55-
Payments under these swap agreements reduced oil and natural gas revenues by
$1,183,000 for the year ended December 31, 2002, as a result of hedging
transactions. During the year ended December 31, 2001, the Company had no
material open hedging agreements. During the year ended December 31, 2000,
payments under swap agreements reduced oil and natural gas revenues by
$5,419,000.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 44% of our proved developed natural gas production and 70% of our
proved developed oil production. The fair values of the hedges are based on the
difference between the strike price and the New York Mercantile Exchange future
prices for the applicable trading months.
Weighted Average Fair Value (unrealized)
Notional Strike Price at December 31, 2002
Amount ($ per unit) (in thousands)
-------- ---------------- ----------------------
Natural Gas (mmbtu)
January 2003 - June 2005 8,610,000 $ 3.80 $ 4,721
Oil (bbls)
January 2003 - July 2005 3,320,000 $ 24.55 $ 2,592
--------
$ 7,313
--------
14. MAJOR CUSTOMERS
Major customers for the years ended December 31, 2002, 2001 and 2000, 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 2002 2001 2000
-------- ---- ---- ----
Equiva Trading Company(1)............................. 33% 30% 36%
Louisiana Intrastate Gas.............................. 17% 20% 12%
Conoco, Inc........................................... 12% -- --
Superior Natural Gas.................................. -- 13% 14%
(1) Equiva Trading Company is an affiliate of Shell.
15. RELATED PARTY TRANSACTIONS
Historically since 1994, affiliates of Meridian have been permitted to hold
interests in projects of the Company. 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 each invested in all Meridian drilling
locations on a promoted basis, where applicable, at a 1.5% working interest
basis. The maximum percentage that either may elect to participate in any
prospect is a 4% working interest. On a collective basis, TODD and Sydson
invested $3,289,000, $4,846,000 and $3,027,000 for the years ended December 31,
2002, 2001 and 2000, respectively, in oil and natural gas drilling activities
for which the Company was the operator. Net amounts due from (to) TODD and Mr.
Reeves were approximately $186,000 and ($202,000) as of December 31, 2002 and
2001, respectively. Net amounts due from Sydson and Mr. Mayell were
approximately $1,370,000 and $1,046,000 as of December 31, 2002 and 2001,
respectively.
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, 2002, 2001 and 2000 and
-56-
received fees of approximately $282,000, $269,000 and $304,000, 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 currently a partner in the
law firm of Looper, Reed and McGraw in Houston, Texas, which provided legal
services for the Company for the years ended December 31, 2002 and 2001, and
received fees of approximately $27,000 and $58,000, respectively. He previously
was 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, 2001
and 2000 and received fees of approximately $66,000 and $124,000, respectively.
In addition, the Company has Mr. Messersmith on a personal retainer of $8,333
per month relating to his services provided to the Company and a bonus in the
form of personal property valued at $12,500 was awarded during 2002. Mr.
Messersmith also participated in the Management Plan described in Note 10 above
pursuant to which he was paid approximately $377,000 during 2002, $401,000
during 2001 and $383,000 and received 11,472 shares of the Company's Common
Stock during 2000.
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16. 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,
-----------------------
2002(1) 2001 2000
---- ---- ----
Numerator:
Net earnings (loss) applicable to common stockholders $ (52,012) $ 22,551 $ 65,070
Plus income impact of assumed conversions:
Preferred stock dividends 3,943 429 5,400
Interest on convertible subordinated notes 1,236 1,211 1,256
Net earnings (loss) applicable to common stockholders
plus assumed conversions $ (46,833) $ 24,191 $ 71,726
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 49,763 48,350 48,646
Effect of potentially dilutive common shares:
Convertible preferred stock -- 985 12,837
Redeemable preferred stock N/A -- --
Convertible subordinated notes N/A 2,857 2,857
Employee and director stock options N/A 1,263 1,103
Warrants N/A 2,387 2,078
--------- --------- ---------
Denominator for diluted earnings per
share - weighted-average shares
outstanding and assumed conversions 49,763 55,842 67,521
========= ========= =========
Basic earnings (loss) per share $ (1.05) $ 0.47 $ 1.34
========= ========= =========
Diluted earnings (loss) per share $ (1.05) $ 0.43 $ 1.06
========= ========= =========
(1) Anti-dilutive in 2002.
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17. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the years ended December 31, 2002 and 2001,
were (thousands of dollars, except per share):
QUARTER ENDED
-------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
2002
Revenues $ 23,848 $ 32,473 $ 26,775 $ 24,374
Results of operations from exploration and
production activities(1) 5,753 12,982 (65,894) 5,058
Net earnings (loss)(2) $ (1,577) $ 3,172 $ (51,384) $ (2,223)
Net earnings (loss) per share:(2)
Basic $ (0.03) $ 0.06 $ (1.03) $ (0.04)
Diluted (0.03) 0.06 (1.03) (0.04)
2001
Revenues $ 70,069 $ 46,026 $ 33,758 $ 28,207
Results of operations from exploration and
production activities(1) 44,073 22,486 9,174 (35)
Net earnings (loss)(2) $ 19,668 $ 7,691 $ 1,233 $ (6,041)
Net earnings (loss) per share:(2)
Basic $ 0.40 $ 0.16 $ 0.03 $ (0.13)
Diluted 0.34 0.15 0.03 (0.13)
(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.
(2) Applicable to common stockholders.
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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,
-----------------------
2002 2001 2000
---- ---- ----
Costs incurred during the year:(1)
Property acquisition costs
Unproved $ 4,757 $ 11,330 $ 2,665
Proved -- -- --
Exploration 32,293 91,904 63,378
Development 38,998 30,471 35,200
------------ ------------ -------------
$ 76,048 $ 133,705 $ 101,243
============ ============ =============
(1) Costs incurred during the years ended December 31, 2002, 2001 and 2000
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of
third party reimbursements, of $11,684,000, $13,459,000 and
$14,477,000, respectively.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
DECEMBER 31,
------------
2002 2001
---- ----
Capitalized costs $ 1,161,976 $ 1,085,656
Accumulated depletion 755,433 626,509
------------- -------------
Net capitalized costs $ 406,543 $ 459,147
============= =============
At December 31, 2002 and 2001, unevaluated costs of $18,993,000 and $30,247,000,
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.
-60-
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------
2002 2001 2000
---- ---- ----
Oil and natural gas revenues $ 106,992 $ 176,646 $ 223,420
Less:
Oil and natural gas operating costs 11,935 16,625 18,234
Severance and ad valorem taxes 8,235 11,761 15,578
Depletion 59,799 65,982 68,077
Impairment of long-lived assets 69,124 6,580 --
Income tax (22,002) 13,500 10,400
-------------- -------------- --------------
127,091 114,448 112,289
-------------- -------------- --------------
Results of operations from oil and
natural gas producing activities $ (20,099) $ 62,198 $ 111,131
============== ============== ==============
Depletion expense per Mcfe $ 2.07 $ 1.67 $ 1.32
============== ============== ==============
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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, 2002, 2001 and 2000, and the changes therein during the years then
ended. The reserve information was reviewed by T. J. Smith & Company, Inc.,
independent petroleum engineers, for 2002, 2001 and 2000. All of the Company's
oil and natural gas producing activities are located in the United States.
Oil Gas
(MBbls) (MMcf)
------- ------
TOTAL PROVED RESERVES:
BALANCE AT DECEMBER 31, 1999 27,355 200,465
Production during 2000 (3,987) (27,672)
Discoveries and extensions 3,103 33,475
Sale of reserves-in-place (369) (26,139)
Revisions of previous quantity estimates and other (3,761) (7,702)
------- -------
BALANCE AT DECEMBER 31, 2000 22,341 172,427
Production during 2001 (2,918) (22,085)
Discoveries and extensions(1) 11,605 68,226
Sale of reserves-in-place (5,558) (21,447)
Revisions of previous quantity estimates and other (1,124) (20,199)
------- -------
BALANCE AT DECEMBER 31, 2001 24,346 176,922
Production during 2002 (2,213) (15,578)
Discoveries and extensions 41 13,786
Revisions of previous quantity estimates and other(1) (12,249) (67,504)
------- -------
BALANCE AT DECEMBER 31, 2002 9,925 107,626
PROVED DEVELOPED RESERVES:
Balance at December 31, 2002 6,841 86,248
Balance at December 31, 2001 10,752 101,397
Balance at December 31, 2000 15,549 127,742
Balance at December 31, 1999 17,695 144,552
(1) Primarily as a result of Kent Bayou. See Note 3 to Notes to
Consolidated Financial Statements for additional information.
-62-
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 less precise than those of producing oil and natural gas
properties. Accordingly, these estimates are expected to change as future
information becomes available.
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. Future income tax expense has been reduced for the effect of available
net operating loss carryforwards.
(thousands of dollars) AT DECEMBER 31,
---------------
2002 2001
---- ----
Future cash flows $ 829,538 $ 892,642
Future production costs (137,215) (158,674)
Future development costs (43,474) (64,754)
------------- -------------
Future net cash flows before income taxes 648,849 669,214
Future taxes on income (99,852) (115,031)
------------- -------------
Future net cash flows 548,997 554,183
Discount to present value at 10 percent per annum (119,162) (151,266)
------------- -------------
Standardized measure of discounted future net cash flows $ 429,835 $ 402,917
============= =============
The average price for natural gas in the above computations was $4.96 and $2.63
per Mcf at December 31, 2002 and 2001, respectively. The average price used for
crude oil in the above computations was $31.82 and $19.41 per Bbl at December
31, 2002 and 2001, respectively.
-63-
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, 2002, 2001 and 2000
(thousands of dollars):
YEAR ENDED DECEMBER 31,
-----------------------
2002 2001 2000
---- ---- ----
Balance at Beginning of Period $ 402,917 $ 992,254 $ 524,758
Sales of oil and gas, net of production costs (86,822) (148,260) (189,608)
Changes in sales & transfer prices, net of production costs 348,960 (795,374) 838,072
Revisions of previous quantity estimates (373,928) (38,680) (141,858)
Sales of reserves-in-place -- (199,245) (33,291)
Current year discoveries, extensions
and improved recovery 40,376 190,073 232,674
Changes in estimated future
development costs (9,840) (11,366) (14,341)
Development costs incurred during the period 38,998 30,471 35,200
Accretion of discount 40,292 99,225 52,476
Net change in income taxes (3,676) 319,905 (346,097)
Change in production rates (timing) and other 32,558 (36,086) 34,269
--------- ----------- ----------
Net change 26,918 (589,337) 467,496
--------- ----------- ----------
Balance at End of Period $ 429,835 $ 402,917 $ 992,254
========= =========== ==========
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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, 13, 14 and 15 is incorporated by
reference to the Company's definitive Proxy Statement to be filed with the
Securities and Exchange Commission on or before April 30, 2003.
-65-
PART IV
ITEM 16. 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, 2002 and
2001
(iii) Consolidated Statements of Operations for each of the
three years in the period ended December 31, 2002
(iv) Consolidated Statements of Changes in Stockholders'
Equity for each of the three years in the period ended
December 31, 2002
(v) Consolidated Statements of Cash Flows for each of the
three years in the period ended December 31, 2002
(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 Series C Redeemable
Convertible Preferred Stock dated March 28, 2002
(incorporated by reference to Exhibit 3.1 of the
Company's Quarterly Report on Form 10-Q for the three
months ended March 31, 2002).
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)).
-66-
*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).
*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 Credit Agreement, dated August 13, 2002, among the
Company, Societe Generale, as Administrative Agent, Lead
Arranger and Bookrunner, Fortis Capital Corp., as
Co-Lead Arranger and Documentation Agent, and the
several lenders from time to time parties thereto
(incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K dated August 13,
2002).
4.8 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).
4.9 Registration Rights Agreement dated January 29, 2001, 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 January 29, 2001).
4.10 Termination Agreement, dated January 29, 2001, by and
between the Company and Shell Louisiana Onshore
Properties Inc. (incorporated by reference from the
Company's Current Report on Form 8-K dated January 29,
2001).
4.11 Amendment No. 1, dated as of January 29, 2001, to Rights
Agreement, dated as of May 5, 1999, by and between the
Company and American Stock Transfer & Trust Co., as
rights agent (incorporated by reference from the
Company's Current Report on Form 8-K dated January 29,
2001).
4.12 First Amendment to Subordinated Credit Agreement, dated
December 5, 2001, between Meridian and Fortis Capital
Corp. (incorporated by reference to Exhibit 4.17 of the
Company's Registration statement on Form S-3, as amended
(Reg. No. 333-75414)).
10.1 See exhibits 4.2 through 4.12 for additional material
contracts.
-67-
*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).
*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 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).
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*10.16 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).
*10.17 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).
*10.18 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).
*10.19 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).
10.20 Subordinated Credit Agreement, dated January 5, 2001,
between the Company and Fortis Capital Corporation.
(incorporated by reference from the Company's Annual
Report on Form 10-K for the year ended December 31,
2000).
21.1 Subsidiaries of the Company (incorporated by reference
to Exhibit 21.1 of the Company's Annual Report on Form
10-K for the year ended December 31, 2000).
**23.1 Consent of Ernst & Young LLP.
**23.2 Consent of T. J. Smith & Company, Inc.
**99.1 Certificate of Chief Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
**99.2 Certificate of President pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
**99.3 Certificate of Chief Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
**99.4 Certificate of Chief Accounting Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
*Management contract or compensation plan.
**Filed herewith.
(b) Reports on Form 8-K.
None
-69-
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: April 15, 2003
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 April 15, 2003
------------------------------------------ (Principal Executive Officer)
Joseph A. Reeves, Jr. Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director April 15, 2003
------------------------------------------
Michael J. Mayell
BY: /s/ JAMES H. SHONSEY Chief Financial Officer April 15, 2003
-------------------------------------------
James H. Shonsey
BY: /s/ LLOYD V. DELANO Chief Accounting Officer April 15, 2003
-------------------------------------------
Lloyd V. DeLano
BY: /s/ JAMES T. BOND Director April 15, 2003
-------------------------------------------
James T. Bond
BY: /s/ JOE E. KARES Director April 15, 2003
-------------------------------------------
Joe E. Kares
BY: /s/ GARY A. MESSERSMITH Director April 15, 2003
-------------------------------------------
Gary A. Messersmith
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CERTIFICATIONS
I, Joseph A. Reeves, Jr., certify that:
1. I have reviewed this annual report on Form 10-K of The Meridian
Resource Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
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6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: April 15, 2003
/s/ Joseph A. Reeves, Jr.
-------------------------------------
Joseph A. Reeves, Jr.
Chief Executive Officer
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CERTIFICATIONS
I, Michael J. Mayell, certify that:
1. I have reviewed this annual report on Form 10-K of The Meridian
Resource Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
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6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: April 15, 2003
/s/ Michael J. Mayell
------------------------------------
Michael J. Mayell
President
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CERTIFICATIONS
I, James H. Shonsey, certify that:
1. I have reviewed this annual report on Form 10-K of The Meridian
Resource Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
-75-
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: April 15, 2003
/s/ James H. Shonsey
---------------------------------------
James H. Shonsey
Chief Financial Officer
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CERTIFICATIONS
I, Lloyd V. DeLano, certify that:
1. I have reviewed this annual report on Form 10-K of The Meridian
Resource Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
(a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
-77-
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: April 15, 2003
/s/ Lloyd V. DeLano
----------------------------------
Lloyd V. DeLano
Chief Accounting Officer
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EXHIBIT INDEX
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 Series C Redeemable
Convertible Preferred Stock dated March 28, 2002
(incorporated by reference to Exhibit 3.1 of the
Company's Quarterly Report on Form 10-Q for the three
months ended March 31, 2002).
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).
*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 Credit Agreement, dated August 13, 2002, among the
Company, Societe Generale, as Administrative Agent, Lead
Arranger and Bookrunner, Fortis Capital Corp., as
Co-Lead Arranger and Documentation Agent, and the
several lenders from time to time parties thereto
(incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K dated August 13,
2002).
4.8 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).
4.9 Registration Rights Agreement dated January 29, 2001, 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 January 29, 2001).
4.10 Termination Agreement, dated January 29, 2001, by and
between the Company and Shell Louisiana Onshore
Properties Inc. (incorporated by reference from the
Company's Current Report on Form 8-K dated January 29,
2001).
4.11 Amendment No. 1, dated as of January 29, 2001, to Rights
Agreement, dated as of May 5, 1999, by and between the
Company and American Stock Transfer & Trust Co., as
rights agent (incorporated by reference from the
Company's Current Report on Form 8-K dated January 29,
2001).
4.12 First Amendment to Subordinated Credit Agreement, dated
December 5, 2001, between Meridian and Fortis Capital
Corp. (incorporated by reference to Exhibit 4.17 of the
Company's Registration statement on Form S-3, as amended
(Reg. No. 333-75414)).
10.1 See exhibits 4.2 through 4.12 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).
*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 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).
*10.16 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).
*10.17 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).
*10.18 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).
*10.19 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).
10.20 Subordinated Credit Agreement, dated January 5, 2001,
between the Company and Fortis Capital Corporation.
(incorporated by reference from the Company's Annual
Report on Form 10-K for the year ended December 31,
2000).
21.1 Subsidiaries of the Company (incorporated by reference
to Exhibit 21.1 of the Company's Annual Report on Form
10-K for the year ended December 31, 2000).
**23.1 Consent of Ernst & Young LLP.
**23.2 Consent of T. J. Smith & Company, Inc.
**99.1 Certificate of Chief Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
**99.2 Certificate of President pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
**99.3 Certificate of Chief Financial Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
**99.4 Certificate of Chief Accounting Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
*Management contract or compensation plan.
**Filed herewith.
(b) Reports on Form 8-K.
None