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, 2001 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:
(Title of each class) (Name of each exchange on
which registered) New York Stock Exchange
Common Stock, $0.01 par value
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Aggregate market value of shares of common stock held by non-affiliates
of the Registrant at March 22, 2002: $221,199,101
Number of shares of common stock outstanding at March 22, 2002: 49,915,343
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Form (Items 10, 11, 12 and 13) is
incorporated by reference from the registrant's Proxy Statement to be filed on
or before April 30, 2002.
Page 1 of 64
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
PART I
Page
----
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 28
Item 8. Financial Statements and Supplementary Data 30
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 56
PART III
Item 10. Directors and Executive Officers of the Registrant 56
Item 11. Executive Compensation 56
Item 12. Security Ownership of Certain Beneficial Owners
and Management 56
Item 13. Certain Relationships and Related Transactions 56
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 57
Signatures 62
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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, 2001, we had
proved reserves of approximately 323 Bcfe with a present value of future net
cash flows before income taxes of approximately $429 million. Approximately 55%
of our proved reserves were natural gas and approximately 51% 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.
During 1998, we acquired substantially all of Shell Oil Company's and its
affiliates' (collectively, "Shell") onshore south Louisiana oil and gas property
interests in two separate transactions (the "Shell Transactions"). The Shell
Transactions were consummated on June 30, 1998, and positioned us as one of the
leading operators and producers in south Louisiana. Additionally, the property
interests acquired in the Shell Transactions allow us to blend lower risk
exploration and development projects with higher risk, higher potential
exploration projects. As a result of the Shell Transactions, Shell beneficially
owned 39.9% of our Common Stock on a fully diluted basis, assuming the exercise
of all outstanding stock options and warrants and conversion of all Preferred
Stock. On January 29, 2001, the Company completed the repurchase of all of the
outstanding Preferred Stock (convertible into 12.8 million shares of Common
Stock) and six million shares of Common Stock from Shell for $114 million
resulting in Shell's ownership being reduced to approximately 15% of our Common
Stock outstanding.
We currently have interests in leases and options to lease acreage in
approximately 383,000 gross acres in Louisiana, Texas and the Gulf of Mexico. We
also have rights or access to approximately 7,100 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.
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
-3-
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 averages between 3% and 50% in each well. Our offshore
properties generally involve higher drilling costs and risks commonly associated
with offshore exploration, including costs of constructing exploration and
production platforms and pipeline interconnections, as well as weather delays
and other matters.
3-D SEISMIC TECHNOLOGY
An integral part of Meridian's exploration strategy is the disciplined
application of 3-D seismic technology to every exploration and development
prospect 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, 2001. The
reserve volumes were reviewed by T. J. Smith & Company, Inc., independent
reservoir engineers.
GULF OF
TEXAS LOUISIANA MEXICO TOTAL
---- --------- ------- -----
PRODUCTION FOR THE YEAR ENDED DECEMBER 31, 2001
Oil (MBbls) 2 2,755 161 2,918
Natural Gas (MMcf) 201 19,720 2,164 22,085
RESERVES AS OF DECEMBER 31, 2001
Oil (MBbls) -- 23,551 795 24,346
Natural Gas (MMcf) -- 161,018 15,904 176,922
ESTIMATED FUTURE NET CASH FLOWS ($000)(1)...................................................... $ 669,214
PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE INCOME TAXES ($000)(1)........................... $ 429,109
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS ($000)(1)............................. $ 402,917
(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, 2001, we used the prices at December 31, 2001, which were
$19.41 per Bbl of oil and $2.63 per Mcf of natural gas.
PRODUCTIVE WELLS
At December 31, 2001, 2000 and 1999, 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, 2001, have multiple completions.
2001 2000 1999
----------------- ----------------- --------------------
GROSS NET GROSS NET GROSS NET
----- ------- ----- ----- ----- ------
Oil Wells..................... 61 41 118 96 116 91
Natural Gas Wells............. 79 34 96 46 95 40
--- -- --- --- --- ---
Total................ 140 75 214 142 211 131
=== == === === === ===
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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,
2001. 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,
2001.
PROVED RESERVES AT DECEMBER 31, 2001
------------------------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
---------- ------------- ----------- -----
(DOLLARS IN THOUSANDS)
Net Proved Reserves:
Oil (MBbls)................................ 7,426 3,326 13,594 24,346
Natural Gas (MMcf)......................... 63,570 37,827 75,525 176,922
Natural Gas Equivalent (MMcfe)............. 108,126 57,783 157,083 322,992
Estimated Future Net Cash Flows(1)............................................................ $ 669,214
Present Value of Future Net Cash Flows (before income taxes)(1)............................... $ 429,109
Standardized Measure of Discounted Future Net Cash Flows(1)................................... $ 402,917
---------------
(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, 2001, we used
the prices at December 31, 2001, which were $19.41 per Bbl of oil and
$2.63 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 2001, 2000
and 1999.
GROSS WELLS NET WELLS
-------------------------------------------------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- --- -----
EXPLORATORY WELLS
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
Year ended December 31, 1999.................. 8 7 15 3.4 4.9 8.3
DEVELOPMENT WELLS
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
Year ended December 31, 1999.................. 6 1 7 3.3 .7 4.0
Meridian had 1 gross (0.9 net) well in progress at December 31, 2001.
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 2001, 2000 and 1999.
YEAR ENDED DECEMBER
---------------------------------------------------------
2001 2000 1999
-------------- ------------ -------------
PRODUCTION:
Oil (MBbls)............................... 2,918 3,987 4,454
Natural gas (MMcf)........................ 22,085 27,672 22,711
Natural gas equivalent (MMcfe)............ 39,594 51,596 49,438
AVERAGE PRICES:
Oil ($/Bbl)............................... $ 25.17 $ 27.32 $ 17.61
Natural Gas ($/Mcf)....................... $ 4.67 $ 4.14 $ 2.38
Natural gas equivalent ($/Mcfe)........... $ 4.46 $ 4.33 $ 2.68
PRODUCTION EXPENSES:
Lease operating expenses($/Mcfe)......... $ 0.42 $ 0.35 $ 0.30
Severance and ad valorem
taxes ($/Mcfe)......................... $ 0.30 $ 0.30 $ 0.23
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ACREAGE
The following table sets forth the developed and undeveloped oil and natural gas
acreage in which Meridian held an interest as of December 31, 2001. 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, 2001
---------------------------------------------------------------
DEVELOPED UNDEVELOPED
----------------------------- ------------------------------
REGION GROSS NET GROSS NET
------ ------------- ----------- ------------ -------------
TEXAS........................................... 425 53 6,099 2,333
LOUISIANA....................................... 31,213 18,209 38,719 30,883
GULF OF MEXICO.................................. 46,529 8,083 81,747 35,678
-------- ------ ------- ------
TOTAL 78,167 26,345 126,565 68,894
======== ====== ======= ======
In addition to the above acreage, we currently have options or farm-ins to
acquire leases on approximately 178,430 gross (177,713 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 86 full-time non-union employees and 16 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 2001, 2000 and 1999.
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
CUSTOMER 2001 2000 1999
-------- ------------ --------- --------
Equiva Trading Company(1)............................. 30% 36% 43%
Louisiana Intrastate Gas.............................. 20% 12% --
Superior Natural Gas.................................. 13% 14% --
Tauber Oil Company.................................... -- -- 16%
(1) This entity is an affiliate of Shell.
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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, 2001, was $4.46 per Mcfe
compared to $4.33 per Mcfe during the year ended December 31, 2000. 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. Shell retains, and may obtain in the future, interests in
producing properties and exploration prospects in Louisiana state waters and
adjacent onshore areas where Shell competes with us. In addition, although Shell
currently does not have any significant working interests in producing
properties or exploration prospects onshore in south Louisiana, and has
indicated to us that it does not currently intend to obtain any such interests,
it may do so in the future.
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REGULATION
The availability of a ready market for any oil and natural gas production
depends on numerous factors that we do not control. These factors include
regulation of oil and natural gas production, federal and state regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by a well or proration unit, the amount of oil and natural
gas available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or lack of an available natural gas pipeline 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 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.
-10-
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 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.
-11-
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.
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,
-12-
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, 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
There are no 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 2001.
-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
----------------- --------------
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
2000:
First quarter............................... $ 4.25 $ 2.75
Second quarter.............................. 5.94 3.06
Third quarter............................... 7.06 4.38
Fourth quarter ............................. 8.88 5.94
The closing sale price of the Common Stock on March 22, 2002, as reported on the
New York Stock Exchange Composite Tape, was $4.50. As of March 22, 2002, we had
approximately 838 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 $2.0 million in
the aggregate for cash dividends on the Common Stock or for purchase of shares
of Common Stock without the prior consent of the lender.
-15-
ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with our Consolidated Financial
Statements and related notes thereto included throughout this report.
YEAR ENDED DECEMBER 31,
-------------------------------------------- --------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(In thousands, except prices and per share information)
A. SUMMARY OF OPERATING DATA
Production:
Oil (MBbls) 2,918 3,987 4,454 2,365 914
Natural gas (MMcf) 22,085 27,672 22,711 20,603 14,603
Natural gas equivalent (MMcfe) 39,594 51,596 49,438 34,793 20,087
Average Prices:
Oil ($/Bbl) $ 25.17 $ 27.32 $ 17.61 $ 12.19 $ 19.72
Natural gas ($/Mcf) 4.67 4.14 2.38 2.16 2.70
Natural gas equivalent ($/Mcfe) 4.46 4.33 2.68 2.11 2.86
B. SUMMARY OF OPERATIONS
Total revenues $ 178,060 $ 226,246 $ 133,361 $ 74,026 $ 58,333
Depletion and depreciation 67,450 69,648 54,222 45,390 26,337
Net earnings (loss)(1) 22,551 65,070 11,467 (230,708) (28,541)
Net earnings (loss) per share:(1)
Basic $ 0.47 $ 1.34 $ 0.25 $ (5.80) $ (0.85)
Diluted 0.43 1.06 0.25 (5.80) (0.85)
Dividends per:
Common share -- -- -- -- --
Preferred share $ 0.11 $ 1.36 $ 1.36 $ 0.68 --
Weighted average common
shares outstanding 48,350 48,646 45,995 39,774 33,383
C. SUMMARY BALANCE SHEET DATA
Total assets $ 507,666 $ 570,921 $ 477,719 $ 445,175 $ 292,558
Long-term obligations, inclusive
of current maturities 190,000 250,000 270,000 240,084 107,195
Stockholders' equity 188,221 270,322 163,860 148,808 145,102
(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.
We have achieved substantial growth in reserves, production, revenues and cash
flow since our inception. From the beginning of 1992 (when the Company had no
proved reserves or production of oil or natural gas) through December 31, 2001,
we have achieved a compound annual growth rate in production of 40% and an
average annual reserve replacement rate of 297%.
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, 2001, we had proved reserves of 323 Bcfe,
approximately 55% of which were natural gas, with a present value of future
pre-tax cash flows (PV-10) of $429 million. We own interests in approximately
383,000 gross (273,000 net) acres, including 26 fields and 140 wells, and we
operate approximately 75% of our total production. During 2001, we achieved 280%
replacement of production and increased reserves by 6% from a year-end 2000
total of 306 Bcfe to 323 Bcfe at the end of 2001, after producing approximately
40 Bcfe, selling approximately 55 Bcfe and making adjustments and revisions of
approximately 26 Bcfe. Our finding and development cost for 2001 was $1.21 per
Mcfe, and was $1.61 for the four-year period from 1998 through 2001. Our lease
operating expense or lifting cost averaged $0.42 per Mcfe for 2001 and $.37 per
Mcfe for the fourth quarter of 2001.
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 the successful growth we have
experienced year after year. With licenses and rights to over 7,100 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:
o Generate reserve growth through exploration, exploitation and development
drilling of a balanced portfolio of high potential prospects;
o Maintain a concise geographic focus applying professional and technical
knowledge and experience to the development of a high quality project
inventory;
o 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;
o Maximize percentage ownership in each drilling prospect relative to
probability of success, increasing the impact of discoveries on shareholder
value; and
o 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.
-17-
The Company has budgeted approximately $70 million in capital expenditures for
2002, subject to adjustment depending on drilling results, the number of wells
drilled, drilling conditions and other factors. The 2002 expenditures will be
spent on the development of its recently acquired Biloxi Marshlands
exploration/exploitation play in south Louisiana and the extension of recently
discovered fields in the Company's East Lake Arthur, Lakeside, Turtle Bayou,
Weeks Island, and Thornwell fields.
Recent Developments. Meridian recently purchased a dominant acreage position in
south Louisiana, referred to as the Biloxi Marshlands project, which comprises
approximately 200,000 acres. Additionally, the Company has underwritten a
large-scale proprietary 3-D seismic survey that will image approximately 500
square miles in three phases over the next three years. Based on 2-D and 3-D
seismic data acquired over a small portion of the acreage to date, the Company's
geologists have begun initial mapping of more than a dozen prospect leads.
Prospects in the area are defined by attribute analysis and appear as "bright
spots" on 3-D seismic data. The Biloxi Marshlands project focuses on relatively
shallow, normally pressured horizons. As a result, the project is anticipated to
be characterized by lower costs, reduced mechanical risks and higher probability
of success than the Company's traditional deep exploration plays. The first test
well is planned for the second quarter of 2002 with several additional wells
expected for the year, and up to 12 wells per year for the next several years,
depending on the results of 3-D seismic data.
In an effort to address the Company's liquidity and balance sheet issues and to
accelerate the recently acquired Biloxi Marshlands 3-D exploitation project, the
Company retained the investment banking firms of RBC Dominion and Credit
Lyonnais to assist it in the placement of a private preferred stock offering of
up to $75 million. As of March 28, 2002, as a result of the Company's efforts,
subscriptions for approximately $25 million have been received to date. Combined
with the estimated cash flow from operations for 2002, estimated expenditures
for the Biloxi Marshlands project for 2002 are available. Additional funds, if
any are elected to be pursued, would yield further improvements in the Company's
balance sheet and working capital.
Industry Conditions. Our revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for oil and natural gas. Oil and
natural gas prices have been extremely volatile in recent years and are affected
by many factors outside of our control. The average price we received during the
year ended December 31, 2001 was $4.46 per Mcfe compared to $4.33 per Mcfe
during the year ended December 31, 2000. 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.
Repurchase of Stock. Pursuant to the Option and Standstill Agreement (the
"Option Agreement"), on January 29, 2001, the Company completed the repurchase
of all of the 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 cash flow and proceeds from the sale of non-core properties. The
repurchase of these shares resulted in an immediate reduction in the fully
diluted share count of more than 25%. Shell remains Meridian's largest
shareholder, with approximately 7.1 million shares of Common Stock.
The six million shares of Common Stock were repurchased into the Company's
Treasury Stock account at a value of $48.2 million (using the closing price of
Meridian's Common Stock on the transaction date). In addition, the buyback of
the six million common shares along with the retirement of the Preferred Stock
resulted in an immediate reduction in the fully diluted share count of more than
25%. Finally, since the face value of the Preferred Stock was $135 million, the
repurchase at a discounted price of $114 million provided an immediate $21.0
million benefit to the equity of all common stockholders.
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.
-18-
Ceiling Test Write-down. A decline in oil and natural gas prices caused us to
recognize $6.6 million of non-cash write-downs of our oil and natural gas
properties under the full cost method of accounting during 2001. During 2000 and
1999, we recorded no write-down of the value of our oil and natural gas
properties. 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, 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.
-20-
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.
-21-
YEAR ENDED DECEMBER 31, 2000, COMPARED TO YEAR ENDED DECEMBER 31, 1999
Operating Revenues and Production.
Oil and natural gas revenues increased $90.8 million as a result of improved
commodity prices and increased production volumes. The production increase, net
of reductions from property sales and natural declines, was a direct result of
the inclusion of new wells being placed on production and an aggressive workover
program during the year 2000. The following table summarizes Meridian's
operating revenues, production volumes and average sales prices for the years
ended December 31, 2000 and 1999.
Year Ended
December 31, Increase
---------------------------------------------------
2000 1999 (Decrease)
---- ---- ----------
Production:
Oil (MBbls) 3,987 4,454 (10%)
Natural gas (MMcf) 27,672 22,711 22%
Natural gas equivalent (MMcfe) 51,596 49,438 4%
Average Sales Price:
Oil (per Bbl) $ 27.32 $ 17.61 55%
Natural gas (per Mcf) 4.14 2.38 74%
Natural gas equivalent (per Mcfe) 4.33 2.68 62%
Gross Revenues (000's):
Oil $ 108,930 $ 78,447 39%
Natural gas 114,490 54,129 112%
Total $ 223,420 $ 132,576 69%
Interest and Other Income.
Interest and other income increased $2.0 million to $2.8 million in 2000,
compared to $0.8 million for 1999. This increase was primarily due to invested
funds from the sale of properties and the Common Stock offering. These funds
were 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.
Operating Expenses.
Oil and natural gas operating expenses increased $3.6 million to $18.2 million
in 2000, compared to $14.6 million in 1999. This net increase was the result of
several factors. To take advantage of higher commodity prices, the Company
pursued an expanded well workover program to increase production during the year
2000; however, these marginal wells incur higher lifting costs. We implemented a
cost reduction program to reduce the operating costs on several properties, and
this partially offset the increase in costs from the expanded workovers on
marginal wells. Additional factors included the expense incurred in bringing new
reserves on production, which was partially offset by the property sales which
included several wells with high operating costs. The net impact of these
various factors was an increase in operating expenses when viewed year over
year. On an Mcfe basis, operating expenses were $0.35 per Mcfe for 2000,
compared to $0.30 per Mcfe for 1999.
-22-
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes increased $4.3 million to $15.6 million in 2000,
compared to $11.3 million in 1999. This increase is largely attributable to the
22% increase in natural gas production over the same period in 1999 and the 55%
increase in the average sales price of oil over 1999. Meridian's production is
primarily from southern Louisiana, and is therefore, subject to a tax rate of
12.5% of gross oil revenues and $0.097 per Mcf for natural gas, an increase from
$0.078 per Mcf effective in July 2000.
Depletion and Depreciation.
Depletion and depreciation expenses increased $15.4 million to $69.6 million in
2000, compared to $54.2 million in 1999. This increase was primarily a result of
the 4% increase in production on an Mcfe basis over the comparable period in
1999 and an increase in the depletion rate, reflecting the movement of $15.7
million for the year 2000 from the unevaluated to the full cost pool subject to
depletion, the sale of non-core properties and revisions of prior reserve
estimates.
General and Administrative Expense.
General and administrative expenses increased $2.5 million to $16.4 million in
2000, compared to $13.9 million in 1999. This increase was primarily a result of
our expanded exploration and production activities; costs included additional
salaries, wages and other compensation and related employee expenses and
increased rent related expenses, partially offset by a decrease in franchise
taxes, legal expenses and other related administrative expenses.
Interest Expense.
Interest expense increased $2.6 million to $25.5 million in 2000 compared to
$22.9 million in 1999. The increase is primarily a result of the issuance of the
Subordinated Notes in June 1999, and due to the Federal Reserve Bank's increase
during 2000 in overall interest rates, leading to an increase in the average
interest rate on the credit facility, partially offset by a decrease in the
balance outstanding on the credit facility to $230 million.
-23-
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During 2001, capital expenditures were internally financed from
the Company's cash flow generated from operations. We completed the sale of
certain non-strategic assets resulting in cash proceeds of approximately $30
million. As of December 31, 2001, we had a cash balance of $14.3 million and a
working capital deficit of $46.3 million, including the $25 million short-term
note payable. The Company is evaluating a number of various alternatives of
raising additional funds.
Our strategy is to grow the Company prudently, taking advantage of the strong
asset base built over the years to add reserves through the drill bit while
maintaining a disciplined approach to costs. Where appropriate, we will allocate
excess cash above capital expenditures to reduce leverage.
CREDIT FACILITY. We entered into an amended and restated credit facility with
The Chase Manhattan Bank as Administrative Agent (the "Credit Facility") to
provide for maximum borrowings, subject to borrowing base limitations, of up to
$250 million. During 2001, the borrowing base was reduced to $190 million. The
Company is currently negotiating its scheduled borrowing base redetermination
with its banks. Borrowings under the Credit Facility are secured by pledges of
the outstanding capital stock of our subsidiaries and a mortgage on the oil and
natural gas properties of at least 90% of its present value of proved
properties. The Credit Facility contains various restrictive covenants,
including, among other items, maintenance of certain financial ratios and
restrictions on cash dividends on the Common Stock. Borrowings under the Credit
Facility mature on May 22, 2003.
Under the Credit Facility, as amended, we may secure either (i) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate, a certificate of deposit based rate or a
federal funds based rate plus 0.25% to 1.0% or (ii) a Eurodollar base rate loan
that bears interest, generally, at a rate per annum equal to the London
interbank offered rate plus 1.25% to 2.75%, depending on the ratio of the
aggregate outstanding loans and letters of credit to the borrowing base. The
Credit Facility also provides for commitment fees ranging from 0.3% to 0.5% per
annum.
SHORT-TERM NOTE AGREEMENT. The Company entered into a short-term subordinated
credit agreement with Fortis Capital Corporation for $25 million, effective
January 5, 2001, with a maturity date of December 31, 2001. We extended and
amended the agreement on December 5, 2001. The interest rate is the London
interbank offered rate ("LIBOR") plus 3.5% through March 31, 2002, LIBOR plus
4.5% from April 1, 2002, through September 30, 2002, and LIBOR plus 5.5% from
October 1, 2002, through December 31, 2002. Interest payments are due on the
last day of March, June, September and December. Note payments of $5 million
each are due on September 1, 2002, and December 1, 2002, with the remaining $15
million payable on December 31, 2002.
9 1/2% CONVERTIBLE SUBORDINATED NOTES. During June 1999, we completed private
placements of an aggregate of $20 million of our 9 1/2% Convertible Subordinated
Notes due June 18, 2005 (the "Notes"). The Notes are unsecured and contain
customary events of default, but do not contain any maintenance or other
restrictive covenants. Interest is payable on a quarterly basis.
The Notes are convertible at any time by the holders of the Notes into shares of
our Common Stock, utilizing a conversion price of $7.00 per share (the
"Conversion Price"). The Conversion Price is subject to customary anti-dilution
provisions. The holders of the Notes have been granted registration rights with
respect to the shares of Common Stock that 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.
-24-
CAPITAL EXPENDITURES. Capital expenditures in 2001 consisted of $134.1 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. During 2001, the Company expanded workover
activities to take advantage of higher commodity prices. 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 workover additions came from key producing fields,
primarily West Lake Verret, Weeks Island and Good Hope.
The 2002 capital expenditures plan has been established at approximately $70
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 2002 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 2002 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, 2001 and the effect such obligations are expected to have on its
liquidity and cash flow in future periods (in thousands):
LESS THAN 1-3 AFTER
ONE YEAR YEARS 3 YEARS TOTAL
-------------- ------------- ------------ -------------
Short and long term debt $ 25,763 $ 190,000 $ 20,000 $ 235,763
Non-cancelable operating leases 1,463 4,525 1,162 7,150
-------------- ------------- ------------ -------------
Total contractual cash obligations $ 27,226 $ 194,525 $ 21,162 $ 242,913
============== ============= ============ =============
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
Preferred Stock aggregating $0.4 million were accrued for 2001 on a pro-rata
basis up until the exercise date of the option to purchase the Preferred Stock
held by Shell. Dividends of $3.1 million on that Preferred Stock were paid
during 2001.
STOCK RIGHTS AND RESTRICTIONS AGREEMENT. Pursuant to the Option and Standstill
Agreement (the "Option Agreement"), on January 29, 2001, the Company completed
the repurchase of all of the 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 cash flow and proceeds from the sale of
non-core properties. The repurchase of these shares resulted in an immediate
reduction in the fully diluted share count of more than 25%. Shell remains
Meridian's largest shareholder, with approximately 7.1 million shares of Common
Stock. The six million shares of Common Stock were repurchased into the
Company's Treasury Stock account at a value of $48.2 million (using the closing
price of Meridian's Common Stock on the transaction date). In
-25-
addition, the buyback of the six million common shares along with the retirement
of the Preferred Stock resulted in an immediate reduction in the fully diluted
share count of more than 25%. Finally, since the face value of the Preferred
Stock was $135 million, the repurchase at a discounted price of $114 million
provided an immediate $21.0 million benefit to the equity of all common
stockholders.
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 preparation of these financial statements requires the
Company to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses. 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.
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. 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 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.
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:
-26-
Changes in the price of oil and natural gas. The prices we receive for our oil
and natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors that 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.
-27-
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 the $20 million principal of
9 1/2% Convertible Subordinated Notes due June 18, 2005. 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 $190 million remains borrowed under the Credit Facility, we
estimate our annual interest expense will change by $1.9 million for each 100
basis point change in the applicable interest rates utilized under the Credit
Facility. Changes in interest rates would, assuming all other things being
equal, cause the fair market value of debt with a fixed interest rate, such as
the Notes, to increase or decrease, and thus increase or decrease the amount
required to refinance the debt. The fair value of the Notes is dependent on
prevailing interest rates and our current stock price as it relates to the
conversion price of $7.00 per share of our Common Stock.
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.
-28-
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.
-29-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements
Page
----
Report of Independent Auditors 31
Consolidated Statements of Operations
-- For each of the three years in the period ended December 31, 2001 32
Consolidated Balance Sheets--December 31, 2001 and 2000 33
Consolidated Statements of Cash Flows
-- For each of the three years in the period ended December 31, 2001 35
Consolidated Statements of Changes in Stockholders' Equity
-- For each of the three years in the period ended December 31, 2001 36
Notes to Consolidated Financial Statements 37
Consolidated Supplemental Oil and Natural Gas Information (Unaudited) 51
-30-
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, 2001 and 2000, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the three years in the period ended December 31, 2001. 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, 2001 and 2000, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States.
ERNST & YOUNG LLP
Houston, Texas
February 27, 2002
-31-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share)
YEAR ENDED DECEMBER 31,
----------------------------------------------
2001 2000 1999
---- ---- ----
REVENUES:
Oil and natural gas $ 176,646 $ 223,420 $ 132,576
Interest and other 1,414 2,826 785
----------- ---------- ----------
178,060 226,246 133,361
----------- ---------- ----------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 16,625 18,234 14,604
Severance and ad valorem taxes 11,761 15,578 11,338
Depletion and depreciation 67,450 69,648 54,222
General and administrative 13,506 16,383 13,928
Issuance of stock grants 5,566 -- --
Impairment of long-lived assets 6,580 -- --
Litigation expenses and loss provision -- -- (477)
----------- ---------- ----------
121,488 119,843 93,615
----------- ---------- ----------
EARNINGS BEFORE INTEREST
AND INCOME TAXES 56,572 106,403 39,746
----------- ---------- ----------
OTHER EXPENSES:
Interest expense 20,092 25,533 22,879
Taxes on income 13,500 10,400 -----
----------- ---------- ----------
33,592 35,933 22,879
----------- ---------- ----------
NET EARNINGS 22,980 70,470 16,867
DIVIDENDS ON PREFERRED STOCK 429 5,400 5,400
----------- ---------- ----------
NET EARNINGS APPLICABLE
TO COMMON STOCKHOLDERS $ 22,551 $ 65,070 $ 11,467
========== ========== ==========
NET EARNINGS PER SHARE:
Basic $ 0.47 $ 1.34 $ 0.25
========== ========== ==========
Diluted $ 0.43 $ 1.06 $ 0.25
========== ========== ==========
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES:
Outstanding 48,350 48,646 45,995
Assuming dilution 55,842 67,521 45,995
See notes to consolidated financial statements.
-32-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
DECEMBER 31,
---------------------
2001 2000
---- ----
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 14,340 $ 95,122
Accounts receivable, less allowance for doubtful accounts
$891 [2001 and 2000] 23,875 36,073
Due from affiliates 844 --
Prepaid expenses and other 1,825 1,103
---------- ------------
Total current assets 40,884 132,298
---------- ------------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$30,247 [2001] and $47,027 [2000] not
subject to depletion) 1,085,656 982,566
Land 478 478
Equipment 9,578 10,283
---------- ------------
1,095,712 993,327
Accumulated depletion and depreciation 631,758 558,843
---------- ------------
463,954 434,484
---------- ------------
OTHER ASSETS, NET 2,828 4,139
---------- ------------
$ 507,666 $ 570,921
========== ------------
See notes to consolidated financial statements.
-33-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
DECEMBER 31,
-----------------------------
2001 2000
---- ----
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 35,952 $ 17,833
Revenues and royalties payable 9,562 1,453
Due to affiliates -- 756
Notes payable 25,763 383
Accrued liabilities 15,895 19,774
Current income taxes payable (27) 1,900
----------- -----------
Total current liabilities 87,145 42,099
----------- -----------
LONG-TERM DEBT 190,000 230,000
----------- -----------
9 1/2% CONVERTIBLE SUBORDINATED NOTES 20,000 20,000
----------- -----------
DEFERRED INCOME TAXES 22,300 8,500
----------- -----------
STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value (25,000,000 shares authorized,
3,982,906 [2000] shares of Series A Cumulative
Convertible Preferred Stock issued at stated value) -- 135,000
Common stock, $0.01 par value (200,000,000 shares
authorized, 53,866,694 [2001] and 53,763,285 [2000]
issued) 553 550
Additional paid-in capital 393,280 315,603
Accumulated deficit (157,726) (180,277)
Unrealized loss on securities held for resale (185) (185)
Unamortized deferred compensation (386) (369)
----------- -----------
235,536 270,322
Less treasury stock, at cost (5,892,342 shares [2001]) 47,315 --
Total stockholders' equity 188,221 270,322
----------- -----------
$ 507,666 $ 570,921
=========== ===========
See notes to consolidated financial statements.
-34-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------------------------
2001 2000 1999
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 22,980 $ 70,470 $ 16,867
Adjustments to reconcile net earnings to net
cash provided by operating activities:
Depletion and depreciation 67,450 69,648 54,222
Amortization of other assets 2,070 1,276 1,244
Non-cash compensation 7,605 2,729 3,685
Impairment of long-lived assets 6,580 -- --
Deferred income taxes 13,800 8,500 --
Changes in assets and liabilities:
Accounts receivable 12,198 (7,595) 4,080
Due to (from) affiliates (1,600) 921 4,683
Prepaid expenses and other (722) 131 160
Accounts payable 18,119 (3,526) 2,221
Revenues and royalties payable 8,109 (3,275) (1,771)
Notes payable 25,380 383 --
Accrued liabilities and other (3,102) 3,902 (14,224)
------------ ----------- -----------
Net cash provided by operating activities 178,867 143,564 71,167
------------ ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (134,125) (102,679) (108,191)
Sale of property and equipment 30,624 35,054 8,917
------------ ----------- -----------
Net cash used in investing activities (103,501) (67,625) (99,274)
------------ ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt -- 2,000 40,000
Reductions in long-term debt (40,000) (22,000) (10,084)
Preferred dividends (3,129) (5,400) (4,050)
Issuance of stock/exercise of stock options (112,260) 38,663 85
Additions to deferred loan costs (759) (697) (705)
------------ ----------- -----------
Net cash provided by financing activities (156,148) 12,566 25,246
------------ ----------- -----------
NET CHANGE IN CASH AND CASH EQUIVALENTS (80,782) 88,505 (2,861)
Cash and cash equivalents at beginning of year 95,122 6,617 9,478
------------ ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 14,340 $ 95,122 $ 6,617
============ =========== ============
See notes to consolidated financial statements.
-35-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS'
EQUITY YEARS ENDED DECEMBER 31, 1998, 1999 AND 2000
(in thousands)
Preferred Stock Common Stock Additional Accumulated
------------------- --------------------- Paid-In Earnings
Shares Par Value Shares Par Value Capital (Deficit)
------ --------- ------ --------- ------- ---------
Balance, December 31, 1998 3,983 135,000 45,817 461 270,477 (256,814)
Exercise of stock options -- -- 32 -- 85 --
Company's 401(k) plan contribution -- -- 138 2 562 --
Issuance of rights to common stock -- -- -- 5 1,492 --
Issuance of shares as compensation -- -- 423 4 1,682 --
Compensation expense -- -- -- -- -- --
Realization on securities held -- -- -- -- -- --
Preferred dividends -- -- -- -- -- (5,400)
Net earnings -- -- -- -- -- 16,867
------ --------- ------ ---- -------- ---------
Balance, December 31, 1999 3,983 135,000 46,410 472 274,298 (245,347)
Issuance of rights to common stock -- -- -- 4 1,596 --
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 -- -- -- -- -- --
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)
Repurchase of stock (3,983) (135,000) (6,000) -- 69,180 --
Issuance of rights to common stock -- -- -- 2 1,666 --
Company's 401(k) plan contribution -- -- 79 -- (275) --
Issuance of shares as compensation -- -- 4 -- 34 --
Exercise of stock options -- -- 128 1 317 --
Compensation expense -- -- -- -- -- --
Issuance of stock grants -- -- -- -- 6,755 --
Preferred dividends -- -- -- -- -- (429)
Net earnings -- -- -- -- -- 22,980
------ --------- ------ ---- -------- ---------
Balance, December 31, 2001 -- $ -- 47,974 $553 $393,280 $(157,726)
====== ========= ====== ==== ======== =========
Unamortized Unrealized Treasury Stock
Deferred Loss On ----------------
Compensation Securities Shares Cost Total
------------ ---------- ------ ---- -----
Balance, December 31, 1998 (293) -- 1 (23) 148,808
Exercise of stock options -- -- -- -- 85
Company's 401(k) plan contribution -- -- (1) 23 587
Issuance of rights to common stock (1,497) -- -- -- --
Issuance of shares as compensation -- -- -- -- 1,686
Compensation expense 1,412 -- -- -- 1,412
Realization on securities held -- (185) -- -- (185)
Preferred dividends -- -- -- -- (5,400)
Net earnings -- -- -- -- 16,867
------ ----- ----- -------- ---------
Balance, December 31, 1999 (378) (185) -- -- 163,860
Issuance of rights to common stock (1,600) -- -- -- --
Company's 401(k) plan contribution -- -- -- -- 336
Issuance of shares as compensation -- -- -- -- 784
Exercise of stock options -- -- -- -- 70
Compensation expense 1,609 -- -- -- 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 (369) (185) -- -- 270,322
Repurchase of stock -- -- 6,000 (48,180) (114,000)
Issuance of rights to common stock (1,668) -- -- -- --
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 -- -- -- 1,651
Issuance of stock grants -- -- -- -- 6,755
Preferred dividends -- -- -- -- (429)
Net earnings -- -- -- -- 22,980
------ ----- ----- -------- ---------
Balance, December 31, 2001 $ (386) $(185) 5,892 $(47,315) $ 188,221
====== ===== ===== ======== =========
See notes to consolidated financial statements.
-36-
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. Such costs related to onshore properties, net of
estimated salvage values, are not expected to be significant.
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.
-37-
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 $21.5 million, $25.3 million and $23.2 million in 2001, 2000 and
1999, respectively. Cash payments for income taxes (federal and state, net of
receipts) were $2.27 million for 2001, and none for 2000 and 1999.
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 are not
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. 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.
DERIVATIVE INSTRUMENTS
The Company enters into swaps, options, collars and other derivative contracts
to hedge the price risks associated with a portion of anticipated future oil and
gas production. Realized gains and losses on settled derivative contracts are
deferred and recognized as adjustments to oil and gas revenues in the applicable
period(s) hedged. In applying hedge accounting, the Company periodically
monitors the correlation of changes in the value of its derivative contracts
with that of the prices the Company realized for its production. In the event of
a lack of significant correlation, as might occur in the event of a major market
disturbance, certain of the Company's derivative contracts no longer may qualify
for hedge accounting, and would be marked to market accordingly. The Company may
also enter into interest rate swaps to manage risk associated with interest
rates and reduce the Company's exposure to interest rate fluctuations. Interest
rate swaps are valued on a periodic basis, with resulting differences recognized
as an adjustment to interest and other financing costs over the term of the
agreement. The Company only enters into derivative contracts for hedging
purposes.
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ACCOUNTING PRONOUNCEMENT
In June 1999, the Financial Accounting Standards Board issued SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133," which is effective for fiscal years
beginning after June 15, 2000, with earlier adoption encouraged. FASB Statement
No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
requires companies to record derivatives on the balance sheet as assets and
liabilities, measured at fair value. Gains or losses resulting from changes in
the values of those derivatives would be accounted for depending on the use of
the derivative and whether it qualifies for hedge accounting. The Company has
determined SFAS No. 133 will not have any effect on the current results of
operations and financial position. The Company adopted accounting standard as
required on January 1, 2001. The Company implementation of this standard has not
had significant impact on the Company's financial statements.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
3. IMPAIRMENT OF LONG-LIVED ASSETS
A decline in oil and natural gas prices during 2001 resulted in the Company
recognizing non-cash write-downs totaling $6.6 million of its oil and natural
gas properties under the full cost method of accounting.
Due to the potential volatility in oil and gas prices and their effect on the
carrying value of the Company's proved oil and gas reserves, there can be no
assurance that future write-downs will not be required as a result of factors
that may negatively affect the present value of proved oil and natural gas
reserves and the carrying value of oil and natural gas properties, including
volatile oil and natural gas prices, downward revisions in estimated proved oil
and natural gas reserve quantities and unsuccessful drilling activities.
4. DEBT
LONG-TERM DEBT
In May 1998, the Company amended and restated the Company's credit facility with
The Chase Manhattan Bank as Administrative Agent (the "Credit Facility") to
provide for maximum borrowings, subject to borrowing base limitations, of up to
$250 million. In November 1998, the Company amended the Credit Facility to
increase the then-existing borrowing base from $200 million to $250 million. In
December 2001, we amended the Credit Facility to maintain our borrowing base at
$190 million until the March 2002 borrowing base redetermination, which will be
based on the December 31, 2001, reserve report. If our lenders do not
unanimously agree upon the borrowing base amount as calculated under the March
2002 redetermination, the borrowing base will be automatically redetermined to
equal $180 million until a new borrowing base has been agreed upon by all of the
lenders. In addition to the regularly scheduled semi-annual borrowing base
redeterminations, the lenders under the Credit Facility have the right to
redetermine the borrowing base at any time once during each calendar year and
the Company has the right to obtain a redetermination by the banks of the
borrowing base once during each calendar year. Borrowings under the Credit
Facility are secured by pledges of the outstanding capital stock of the
Company's material 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 Facility contains various restrictive covenants, including, among other
items,
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maintenance of certain financial ratios and restrictions on cash dividends on
the Common Stock. Borrowings under the Credit Facility mature on May 22, 2003.
Under the Credit Facility, as amended, the Company may secure either (i) an
alternative base rate loan that bears interest at a rate per annum equal to the
greatest of the administrative agent's prime rate, a certificate of deposit
based rate or federal funds based rate plus 0.25% to 1.0% or (ii) a Eurodollar
base rate loan that bears interest, generally, at a rate per annum equal to the
London interbank offered rate plus 1.25% to 2.75%, depending on the Company's
ratio of the aggregate outstanding loans and letters of credit to the borrowing
base. The Credit Facility also provides for commitment fees ranging from 0.3% to
0.5% per annum. At December 31, 2001, the Company had outstanding borrowings of
$190 million under the Credit Facility.
9 1/2% CONVERTIBLE SUBORDINATED NOTES
During June 1999, the Company completed private placements of an aggregate of
$20 million of its 9 1/2% Convertible Subordinated Notes due June 18, 2005 (the
"Notes"). The Notes are unsecured and contain customary events of default, but
do not contain any maintenance or other restrictive covenants. Interest is
payable on a quarterly basis.
The Notes are convertible at any time by the holders of the Notes into shares of
the Company's Common Stock, $.01 par value ("Common Stock"), utilizing a
conversion price of $7.00 per share (the "Conversion Price"). The Conversion
Price is subject to customary anti-dilution provisions. The holders of the Notes
have been granted registration rights with respect to the shares of Common Stock
would be issued upon conversion of the Notes.
SHORT-TERM NOTE AGREEMENT
The Company entered into a short-term subordinated credit agreement with Fortis
Capital Corporation for $25 million, effective January 5, 2001, with a maturity
date of December 31, 2001. We extended and amended the agreement on December 5,
2001. The interest rate is the London interbank offered rate ("LIBOR") plus 3.5%
through March 31, 2002, LIBOR plus 4.5% from April 1, 2002, through September
30, 2002, and LIBOR plus 5.5% from October 1, 2002, through December 31, 2002.
Interest payments are due on the last day of March, June, September and
December. Note payments of $5 million each are due on September 1, 2002, and
December 1, 2002, with the remaining $15 million payable on December 31, 2002.
5. LEASE OBLIGATIONS
The Company has a seven-year operating lease for office space with a primary
term expiring in September 2006. The Company also has operating leases for
equipment with various terms, none exceeding three years. Rental expense
amounted to approximately $2.1 million, $1.9 million and $1.4 million in 2001,
2000 and 1999, respectively. Future minimum lease payments under all
non-cancelable operating leases having initial terms of one year or more are
estimated to be $1.5 million for each of the years 2002 - 2004, $1.6 million for
the year 2005, and $1.2 million thereafter.
6. COMMITMENTS AND CONTINGENCIES
LITIGATION
There are no other material legal proceedings to which Meridian or any of our
subsidiaries or partnerships is a party or by which any of our property is
subject, other than ordinary and routine litigation incidental to the business
of producing and exploring for crude oil and natural gas.
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7. TAXES ON INCOME
Provisions (benefits) for federal and state income taxes are as follows
(thousands of dollars):
YEAR ENDED DECEMBER 31,
-------------------------------------
2001 2000 1999
---- ---- ----
Current:
Federal $ 77 $ 779 --
State (377) 1,121 --
Deferred:
Federal 13,800 8,500 --
-------- --------- ------
$ 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,
-------------------------------------
2001 2000 1999
---- ---- ----
Income tax provision (benefit)
computed at statutory rate $ 12,768 $ 28,305 $ 5,903
Nondeductible costs 977 1,175 870
State income tax net of federal
tax benefit (245) 729 --
Net operating loss carryforwards
not benefited in the income tax
provision -- -- --
Change in valuation allowance -- (19,809) (6,773)
--------- ----------- ----------
$ 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,
------------------------------------
2001 2000
---- ----
Deferred tax assets:
Net operating tax loss carryforward $ 60,538 $ 37,964
Statutory depletion carryforward 950 950
Tax credits 856 779
Other 3,120 2,484
Valuation allowance (500) (500)
----------- -----------
Total deferred tax assets 64,964 41,677
----------- -----------
Deferred tax liabilities:
Book in excess of tax basis in oil and gas properties 87,194 50,107
Basis differential in long-term investments 70 70
----------- -----------
Total deferred tax liabilities 87,264 50,177
----------- -----------
Net deferred tax liability $ 22,300 $ 8,500
=========== ===========
As of December 31, 2001, the Company has approximately $173.0 million of tax net
operating loss carryforwards which begin to expire in 2005. Some of the net
operating loss carryforwards are subject to change in ownership and separate
return limitations. The net operating loss carryforwards assume that certain
items, primarily intangible drilling costs, have been written off in the current
year. However, the Company has not made a final determination if an election
will be made to capitalize all or part of these items for tax purposes.
8. 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
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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 outstanding Preferred Stock. See following notes
below.
SHELL OPTION AGREEMENT
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.
EXERCISE OF OPTION AND STANDSTILL AGREEMENT
On January 29, 2001, the Company completed the repurchase of all of the
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, 2001:
NUMBER OF EXERCISE
WARRANTS SHARES PRICE EXPIRATION DATE
-------- -------- -------- ---------------
Executive Officers 1,428,000 $ 5.85 *
General Partner 971,672 $ 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, 2001, 2000 and 1999, 642,897, 915,997 and 810,588 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, 1998 4,900,993 5.35
Granted 9,500 4.56
Exercised (31,425) 2.69
Canceled (200,635) 9.46
--------- -------
Outstanding at December 31, 1999 4,678,433 5.19
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
========= =======
Shares exercisable:
December 31, 2001 4,051,075 $ 4.53
December 31, 2000 3,527,941 $ 5.05
December 31, 1999 2,961,419 $ 6.00
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------ ------------------------------------------
WEIGHTED WEIGHTED
RANGE OF OUTSTANDING AT AVERAGE EXERCISABLE AT AVERAGE
EXERCISABLE PRICES DECEMBER 31, 2001 EXERCISE PRICE DECEMBER 31, 2001 EXERCISE PRICE
------------------ ----------------- -------------- ----------------- --------------
$2.44 - $4.94 3,365,425 $ 3.43 3,336,425 $ 3.43
$5.17 - $9.00 499,000 8.13 419,500 8.48
$10.38 - $13.25 295,150 11.35 295,150 11.35
----------------- -------------- ----------------- --------------
4,159,575 $ 4.56 4,051,075 % 4.53
================= ============== ================= ==============
The weighted average remaining contractual life of options outstanding at
December 31, 2001, was approximately seven years.
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Pro forma information is required by SFAS No. 123 to reflect the estimated
effect on net earnings and net earnings per share as if the Company had
accounted for the stock options and other awards granted using the fair value
method described in that Statement. The fair value was estimated at the date of
grant using the Black-Scholes option pricing model with the following weighted
average assumptions: risk-free interest rate of 4.7%, 4.8% and 6.48%; dividend
yield of 0%; volatility factors of the expected market price of the Company's
Common Stock of 0.82, 0.84 and 0.56 for 2001, 2000 and 1999, respectively; and a
weighted-average expected life of five years. These assumptions resulted in a
weighted average grant date fair value of $4.08, $2.73 and $2.90 for options
granted in 2001, 2000 and 1999, respectively. For purposes of the pro forma
disclosures, the estimated fair value is amortized to expense over the awards'
vesting period. Reflecting the amortization of this hypothetical expense for
2001, 2000 and 1999 income results in pro forma net earnings of $21.5 million,
$64.9 million and $9.9 million, respectively, and pro forma basic net earnings
(loss) per share of $0.45, $1.33 and $0.22, respectively, and proforma diluted
net earnings (loss) per share of $0.42, $1.06 and $0.22, respectively.
The Black-Scholes option valuation model was developed for use in estimating the
fair value of traded options which have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions including the expected stock price volatility. Because
the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its employee stock options.
DEFERRED COMPENSATION
In July 1996, the Company through the Compensation Committee of the board of
Directors offered to Messrs. Reeves and Mayell (the Company's Chief Executive
Officer and President, respectively) the option to accept in lieu of cash
compensation for their respective base salaries Common Stock pursuant to the
Company's Long Term Incentive Plan. Under such grants, Messrs. Reeves and Mayell
each elected to defer $400,000 for 1999 and 2000, and $417,000 for 2001, 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, and at June 30, 2001, for deferrals during the
second half of 2001. At December 31, 2001, the plan had reserved 2,000,000
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
$1,651,000, $1,609,000 and $1,412,000 for 2001, 2000 and 1999 periods,
respectively, relating to these grants is reflected in general and
administrative expense for the years ended December 31, 2001, 2000 and 1999,
respectively.
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STOCKHOLDER RIGHTS PLAN
On May 5, 1999, the Company's Board of Directors declared a dividend
distribution of one Right for each then-current and future outstanding share of
Common Stock. Each Right entitles the registered holder to purchase one
one-thousandth interest in a share of the Company's Series B Preferred Stock
with a par value of $.01 per share and an exercise price of $30. Unless earlier
redeemed by the Company at a price of $.01 each, the Rights become exercisable
only in certain circumstances constituting a potential change in control of the
Company and will expire on May 5, 2009.
Each share of Series B Junior Participating Preferred Stock purchased upon
exercise of the Rights will be entitled to certain minimum preferential
quarterly dividend payments as well as a specified minimum preferential
liquidation payment in the event of a merger, consolidation or other similar
transaction. Each share will also be entitled to 100 votes to be voted together
with the Common stockholders and will be junior to any other series of Preferred
Stock authorized or issued by the Company, unless the terms of such other series
provides otherwise.
In the event of a potential change in control, each holder of a Right, other
than Rights beneficially owned by the acquiring party (which will have become
void), will have the right to receive upon exercise of a Right that number of
shares of Common Stock of the Company, or, in certain instances, Common Stock of
the acquiring party, having a market value equal to two times the current
exercise price of the Right.
9. PROFIT SHARING AND SAVINGS PLAN
The Company has a 401(k) profit sharing and savings plan (the "Plan") that
covers substantially all employees and entitles them to contribute up to 15% of
their annual compensation, subject to maximum limitations imposed by the
Internal Revenue Code. The Company matches 100% of each employee's contribution
up to 6.5% of annual compensation subject to certain limitations as outlined in
the Plan. In addition, the Company may make discretionary contributions which
are allocable to participants in accordance with the Plan.
During 1998, the Company implemented a 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 $7.0 million, $12.0 million
and $5.3 million in 2001, 2000 and 1999, respectively. A portion of these
amounts has been capitalized. The Executive Committee of the Board of Directors,
which is comprised of Messrs. Reeves and Mayell, administers each of the Well
Bonus Plans. The participants in each of the Well Bonus Plans are designated by
the Executive Committee in its sole discretion. Participants in the Management
Plan are limited to executive officers of the Company and other key management
personnel designated by the Executive Committee. Neither Messrs. Reeves or
Mayell will participate in the Management Plan. 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. Additionally, certain interests in the Well Bonus Plans were
repurchased and terminated from current and former employees for issuance of
stock grants (see Note 10).
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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 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.
10. ISSUANCE OF STOCK GRANTS
In December 2001, an offer was made 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. The Board of Directors and the
individuals involved agreed to have the effective date of this transaction to be
December 31, 2001.
11. 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.
During the year ended December 31, 2001, the Company had no material open
hedging agreements. During the years ended December 31, 2000 and 1999, oil and
natural gas revenues were reduced by $5,419,000 and $551,000, respectively, as a
result of hedging transactions.
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12. MAJOR CUSTOMERS
Major customers for the years ended December 31, 2001, 2000 and 1999, 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 2001 2000 1999
-------- ----------- --------- ------
Equiva Trading Company(1)............................. 30% 36% 43%
Louisiana Intrastate Gas.............................. 20% 12% --
Superior Natural Gas.................................. 13% 14% --
Tauber Oil Company.................................... ----- ----- 16%
(1) Equiva Trading Company is an affiliate of Shell.
13. RELATED PARTY TRANSACTIONS
Historically since 1994, 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 $4,846,000,
$3,027,000, and $3,974,000 for the years ended December 31, 2001, 2000 and 1999,
respectively, in oil and natural gas drilling activities for which the Company
was the operator. Net amounts due to TODD and Mr. Reeves were approximately
$202,000 and $588,000 as of December 31, 2001 and 2000, respectively. Net
amounts due to (from) Sydson and Mr. Mayell were approximately ($1,046,000) and
$168,000 as of December 31, 2001 and 2000, respectively.
Effective July 15, 1999, the Company, with the approval of the Board of
Directors, acquired the Kings Bayou, Backridge and Chocolate Bayou interests
held by TODD, Sydson and Messrs. Reeves and Mayell. Proceeds of $2.0 million to
each of TODD and Sydson and $1.4 million to each of Messrs. Reeves and Mayell
due from the acquisition were applied directly to current and/or future costs
and expenses related to TODD and Sydson's working interest rather than paid in
cash.
Mr. Joe Kares, a Director of Meridian, is a partner in the public accounting
firm of Kares & Cihlar, which provided the Company with accounting services for
the years ended December 31, 2001, 2000 and 1999 and received fees of
approximately $269,000, $304,000, and $283,000, 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 year ended December 31, 2001, and received fees
of approximately $58,000. 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, 2000 and 1999 and received fees of
approximately $66,000, $124,000 and $49,000, respectively. In addition, the
Company has Looper, Reed and McGraw on a retainer of $8,333 per month relating
to Mr. Messersmith's services provided to the Company. Prior to August 2001, Mr.
Messersmith was on a personal retainer of $8,333 per month relating to his
services provided to the Company. Mr. Messersmith also participated in the
Management Plan described in Note 9 above pursuant to which he was paid
approximately $401,000 during 2001, $383,000 and received 11,472 shares of the
Company's Common Stock during 2000, and $46,000 and received 19,000 shares of
the Company's Common Stock during 1999.
-48-
14. EARNINGS PER SHARE
(in thousands, except per share)
The following table sets forth the computation of basic and diluted earnings per
share:
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2001 2000 1999(1)
---- ---- -------
Numerator:
Net earnings applicable to common stockholders $ 22,551 $ 65,070 $ 11,467
Plus income impact of assumed conversions:
Preferred stock dividends 429 5,400 --
Interest on convertible subordinated notes 1,211 1,256 --
Net earnings applicable to common stockholders
plus assumed conversions $ 24,191 $ 71,726 $ 11,467
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 48,350 48,646 45,995
Effect of potentially dilutive common shares:
Convertible preferred stock 985 12,837 --
Convertible subordinated notes 2,857 2,857 --
Employee and director stock options 1,263 1,103 N/A
Warrants 2,387 2,078 N/A
Denominator for diluted earnings per
share - weighted-average shares
outstanding and assumed conversions 55,842 67,521 45,995
========== =========== =========
Basic earnings per share $ 0.47 $ 1.34 $ 0.25
========== =========== =========
Diluted earnings per share $ 0.43 $ 1.06 $ 0.25
========== =========== =========
(1) Anti-dilutive
-49-
15. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the years ended December 31, 2001 and 2000,
were (thousands of dollars, except per share):
QUARTER ENDED
----------------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
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 6,545
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)
2000
Revenues $ 48,061 $ 51,890 $ 62,781 $ 63,514
Results of operations from
exploration and production
activities(1) 21,332 26,659 37,094 36,446
Net earnings (loss)(2) $ 9,501 $ 14,699 $ 25,373 $ 15,497
Net earnings (loss) per share:(2)
Basic $ 0.20 $ 0.31 $ 0.53 $ 0.30
Diluted 0.18 0.25 0.40 0.23
(1) Results of operations from exploration and production activities, which
approximates gross profit, are computed as operating revenues less
lease operating expenses, severance and ad valorem taxes, depletion and
impairment of oil and natural gas properties (after tax).
(2) Applicable to common stockholders.
-50-
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,
-----------------------------------------
2001 2000 1999
---- ---- ----
Costs incurred during the year:(1)
Property acquisition costs
Unproved $ 11,330 $ 2,665 $ 14,542
Proved -- -- 3,261
Exploration 80,168 63,378 52,739
Development 42,207 35,200 34,478
----------- --------- ---------
$ 133,705 $ 101,243 $ 105,020
=========== ========= =========
(1) Costs incurred during the years ended December 31, 2001, 2000 and 1999
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of
third party reimbursements, of $13,459,000, $14,477,000 and $9,951,000,
respectively.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
DECEMBER 31,
----------------------------------
2001 2000
---- ----
Capitalized costs $ 1,085,656 $ 982,566
Accumulated depletion 626,509 553,947
----------- ----------
Net capitalized costs $ 459,147 $ 428,619
=========== ==========
At December 31, 2001 and 2000, unevaluated costs of $30,247,000 and $47,027,000,
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.
-51-
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
YEAR ENDED DECEMBER 31,
---------------------------------------------
2001 2000 1999
---- ---- ----
Oil and natural gas revenues $ 176,646 $ 223,420 $ 132,576
Less:
Oil and natural gas operating costs 16,625 18,234 14,604
Severance and ad valorem taxes 11,761 15,578 11,338
Depletion 65,982 68,077 53,002
Impairment of long-lived assets 6,580 -- --
Income tax 13,500 10,400 --
--------- --------- ----------
114,448 112,289 78,944
--------- --------- ----------
Results of operations from oil and
natural gas producing activities $ 62,198 $ 111,131 $ 53,632
========= ========= ==========
Depletion expense per Mcfe $ 1.67 $ 1.32 $ 1.07
========= ========= ==========
-52-
ESTIMATED QUANTITIES OF PROVED RESERVES
The following table sets forth the net proved reserves of the Company as of
December 31, 2001, 2000 and 1999, and the changes therein during the years then
ended. The reserve information was reviewed by T. J. Smith & Company, Inc.,
independent petroleum engineers, for 2001, 2000 and 1999. 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, 1998 22,377 169,887
Production during 1999 (4,454) (22,711)
Discoveries and extensions 6,382 71,484
Purchase of reserves-in-place 335 2,379
Sale of reserves-in-place (67) (2,633)
Revisions of previous quantity estimates and other 2,782 (17,941)
------ --------
BALANCE AT DECEMBER 31, 1999 27,355 200,465
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 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
PROVED DEVELOPED RESERVES:
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
Balance at December 31, 1998 14,592 120,233
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.
-53-
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,
------------------------
2001 2000
---- ----
Future cash flows $ 892,642 $ 2,364,261
Future production costs (158,674) (204,898)
Future development costs (64,754) (75,375)
--------- -----------
Future net cash flows before income taxes 669,214 2,083,988
Future taxes on income (115,031) (607,070)
--------- -----------
Future net cash flows 554,183 1,476,918
Discount to present value at 10 percent per annum (151,266) (484,664)
--------- -----------
Standardized measure of discounted future net cash flows $ 402,917 $ 992,254
========= ===========
The average price for natural gas in the above computations was $2.63 and $10.20
per Mcf at December 31, 2001 and 2000, respectively. The average price used for
crude oil in the above computations was $19.41 and $26.20 per Bbl at December
31, 2001 and 2000, respectively.
-54-
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, 2001, 2000 and 1999
(thousands of dollars):
YEAR ENDED DECEMBER 31,
-----------------------------------------
2001 2000 1999
---- ---- ----
Balance at Beginning of Period $ 992,254 $ 524,758 $ 293,377
Sales of oil and gas, net of production costs (148,260) (189,608) (106,634)
Changes in sales & transfer prices, net of production costs (795,374) 838,072 248,633
Revisions of previous quantity estimates (38,680) (141,858) (2,737)
Sales of reserves-in-place (199,245) (33,291) (4,753)
Current year discoveries, extensions
and improved recovery 190,073 232,674 165,055
Purchase of reserves-in-place -- -- 6,808
Changes in estimated future
development costs (11,366) (14,341) (25,887)
Development costs incurred during the period 30,471 35,200 34,478
Accretion of discount 99,225 52,476 29,338
Net change in income taxes 319,905 (346,097) (70,882)
Change in production rates (timing) and other (36,086) 34,269 (42,038)
----------- --------- ----------
Net change (589,337) 467,496 231,381
----------- --------- ----------
Balance at End of Period $ 402,917 $ 992,254 $ 524,758
=========== ========= ==========
-55-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
The information required in Items 10, 11, 12 and 13 is incorporated by reference
to the Company's definitive Proxy Statement to be filed with the Securities and
Exchange Commission on or before April 30, 2002.
-56-
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Independent Auditor's Report
(ii) Consolidated Balance Sheets as of December 31, 2001 and
2000
(iii) Consolidated Statements of Operations for each of the three
years in the period ended December 31, 2001 (iv)
Consolidated Statements of Changes in Stockholders' Equity
for each of the three years in the period ended December
31, 2001
(v) Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 2001
(vi) Notes to Consolidated Financial Statements
(vii) Consolidated Supplemental Oil and Gas Information
(Unaudited)
2. Financial Statement Schedule:
(i) All schedules are omitted as they are not applicable, not
required or the required information is included in the
consolidated financial statements or notes thereto.
3. Exhibits:
2.1 Agreement and Plan of Merger dated March 27, 1998, between
the Company, LOPI Acquisition Corp., Shell Louisiana
Onshore Properties, Inc. and Louisiana Onshore Properties,
Inc. (incorporated by reference from the Company's Current
Report on Form 8-K dated June 30, 1998).
2.2 Purchase and Sale Agreement dated effective October 1,
1997, by and between The Meridian Resource Corporation and
Shell Western E&P Inc. (incorporated by reference from the
Company's Current Report on Form 8-K dated June 30, 1998).
3.1 Third Amended and Restated Articles of Incorporation of the
Company (incorporated by reference to the Company's
Quarterly Report on Form 10- Q for the three months ended
September 30, 1998).
3.2 Amended and Restated Bylaws of the Company (incorporated by
reference to the Company's Quarterly Report on Form 10-Q
for the three months ended September 30, 1998).
3.3 Certificate of Designation for Preferred Stock dated June
30, 1998 (incorporated by reference from the Company's
Current Report on Form 8-K dated June 30, 1998).
4.1 Specimen Common Stock Certificate (incorporated by
reference to Exhibit 4.1 of the Company's Registration
Statement on Form S-1, as amended (Reg. No. 33-65504)).
*4.2 Common Stock Purchase Warrant of the Company dated October
16, 1990, issued to Joseph A. Reeves, Jr. (incorporated by
reference to Exhibit 10.8 of the Company's
-57-
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 Amended and Restated Credit Agreement dated May 22, 1998,
among the Company, the several banks and financial
institutions and other entities from time to time parties
thereto (the "Lenders"), The Chase Manhattan Bank, as
administrative agent for the Lenders, Bankers Trust
Company, as syndication agent, Chase Securities Inc., as
advisor to the Company, Chase Securities Inc., B. T. Alex.
Brown Incorporated, Toronto Dominion (Texas), Inc. and
Credit Lyonnais New York Branch as co-arrangers, and
Toronto Dominion (Texas), Inc. and Credit Lyonnais New York
Branch, as co-documentation agents (incorporated by
reference from the Company's current report on Form 8-K
dated June 30, 1998).
4.8 Second Amended and Restated Guarantee dated June 30, 1998,
between the Guarantors signatory thereto and The Chase
Manhattan Bank, as Administrative Agent for the Lenders
(incorporated by reference from the Company's current
report on Form 8-K dated June 30, 1998).
4.9 Amended and Restated Pledge Agreement, dated May 22, 1998,
between the Company and The Chase Manhattan Bank, as
Administrative Agent (incorporated by reference from the
Company's current report on Form 8-K dated June 30, 1998).
4.10 First Amendment to Amended and Restated Pledge Agreement
dated June 30, 1998 (incorporated by reference from the
Company's current report on Form 8-K dated June 30, 1998).
4.11 Amendment No. 2 dated November 13, 1998 to Amended and
Restated Credit Agreement dated May 22, 1998, by and among
the Company, The Chase Manhattan Bank as administrative
agent, and the various lenders party thereto (incorporated
by reference from the Company's Quarterly Report on Form
10-Q for the three months ended September 30, 1998).
*4.12 The Meridian Resource Corporation Directors' Stock Option
Plan (incorporated by reference to Exhibit 10.5 of the
Company's Annual Report on Form 10-K for the year
-58-
ended December 31, 1991, as amended by the Company's Form 8
filed March 4, 1993).
4.13 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).
4.14 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).
4.15 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).
4.16 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)).
4.17 Ninth Amendment to Amended and Restated Credit Agreement,
dated as of November 28, 2001, among Meridian, JP Morgan
Chase Bank as administrative agent, and the various lenders
party thereto (incorporated by reference to Exhibit 4.18 of
the Company's Registration statement on Form S-3, as
amended (Reg. No. 333-75414)).
10.1 See exhibits 4.2 through 4.17 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).
-59-
*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 Employment Agreement with P. Richard Gessinger effective
December 1, 1997 (incorporated by reference from the
Company's Quarterly Report on Form 10-Q for the three
months ended September 30, 1998).
*10.16 The Meridian Resource Corporation TMR Employee Trust Well
Bonus Plan (incorporated by reference from the Company's
Annual Report on Form 10-K for the year ended December 31,
1998).
*10.17 The Meridian Resource Corporation Management Well Bonus
Plan (incorporated by reference from the Company's Annual
Report on Form 10-K for the year ended December 31, 1998).
*10.18 The Meridian Resource Corporation Geoscientist Well Bonus
Plan (incorporated by reference from the Company's Annual
Report on Form 10-K for the year ended December 31, 1998).
*10.19 Modification Agreement effective January 2, 1999, by and
among the Company and affiliates of Joseph A. Reeves, Jr.
(incorporated by reference from the Company's Annual Report
on Form 10-K for the year ended December 31, 1998).
*10.20 Modification Agreement effective January 2, 1999, by and
among the Company and affiliates of Michael J. Mayell
(incorporated by reference from the Company's Annual Report
on Form 10-K for the year ended December 31, 1998).
10.21 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.
**23.1 Consent of Ernst & Young LLP.
-60-
**23.2 Consent of T. J. Smith & Company, Inc.
*Management contract or compensation plan.
**Filed herewith.
(b) Reports on Form 8-K.
None
-61-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
THE MERIDIAN RESOURCE CORPORATION
BY: /s/ JOSEPH A. REEVES, JR.
-----------------------------------
Chief Executive Officer
(Principal Executive Officer)
Director and Chairman of the Board
Date: March 27, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
Name Title Date
---- ----- ----
BY: /s/ JOSEPH A. REEVES, JR. Chief Executive Officer March 27, 2002
------------------------------------------ (Principal Executive Officer)
Joseph A. Reeves, Jr. Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director March 27, 2002
------------------------------------------
Michael J. Mayell
BY: /s/ LLOYD V. DELANO Chief Accounting Officer March 27, 2002
-------------------------------------------
Lloyd V. DeLano
BY: /s/ JAMES H. SHONSEY Vice President - Finance March 27, 2002
------------------------------------------- and Capital Markets
James H. Shonsey
BY: /s/ JAMES T. BOND Director March 27, 2002
-------------------------------------------
James T. Bond
BY: /s/ JOE E. KARES Director March 27, 2002
-------------------------------------------
Joe E. Kares
BY: /s/ GARY A. MESSERSMITH Director March 27, 2002
-------------------------------------------
Gary A. Messersmith
-62-
EXHIBIT INDEX
Exhibits: Description
2.1 Agreement and Plan of Merger dated March 27, 1998, between the
Company, LOPI Acquisition Corp., Shell Louisiana Onshore
Properties, Inc. and Louisiana Onshore Properties, Inc.
(incorporated by reference from the Company's Current Report on
Form 8-K dated June 30, 1998).
2.2 Purchase and Sale Agreement dated effective October 1, 1997, by and
between The Meridian Resource Corporation and Shell Western E&P
Inc. (incorporated by reference from the Company's Current Report
on Form 8-K dated June 30, 1998).
3.1 Third Amended and Restated Articles of Incorporation of the Company
(incorporated by reference to the Company's Quarterly Report on
Form 10- Q for the three months ended September 30, 1998).
3.2 Amended and Restated Bylaws of the Company (incorporated by
reference to the Company's Quarterly Report on Form 10-Q for the
three months ended September 30, 1998).
3.3 Certificate of Designation for Preferred Stock dated June 30, 1998
(incorporated by reference from the Company's Current Report on
Form 8-K dated June 30, 1998).
4.1 Specimen Common Stock Certificate (incorporated by reference to
Exhibit 4.1 of the Company's Registration Statement on Form S-1, as
amended (Reg. No. 33-65504)).
*4.2 Common Stock Purchase Warrant of the Company dated October 16,
1990, issued to Joseph A. Reeves, Jr. (incorporated by reference to
Exhibit 10.8 of the Company's Annual Report on Form 10-K for the
year ended December 31, 1991, as amended by the Company's Form 8
filed March 4, 1993).
*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 e
Company, Joseph A. Reeves, Jr. and Michael J. Mayell (incorporated
by reference to Exhibit 10.7 of the Company's Registration
Statement on Form S-4, as amended (Reg. No. 33- 37488)).
*4.5 Warrant Agreement dated June 7, 1994, between the Company and
Joseph A. Reeves, Jr. (incorporated by reference to Exhibit 4.1 of
the Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1994).
*4.6 Warrant Agreement dated June 7, 1994, between the Company and
Michael J. Mayell (incorporated by reference to Exhibit 4.1 of the
Company's Quarterly Report on Form 10-Q for the quarter ended June
30, 1994).
4.7 Amended and Restated Credit Agreement dated May 22, 1998, among the
Company, the several banks and financial institutions and other
entities from time to time parties thereto (the "Lenders"), The
Chase Manhattan Bank, as administrative agent for the Lenders,
Bankers Trust Company, as syndication agent, Chase Securities Inc.,
as advisor to the Company, Chase Securities Inc., B. T. Alex. Brown
Incorporated, Toronto Dominion (Texas), Inc. and Credit Lyonnais
New York Branch as co-arrangers, and Toronto Dominion (Texas), Inc.
and Credit Lyonnais New York Branch, as co-documentation agents
(incorporated by reference from the Company's current report on
Form 8-K dated June 30, 1998).
4.8 Second Amended and Restated Guarantee dated June 30, 1998, between
the Guarantors signatory thereto and The Chase Manhattan Bank, as
Administrative Agent for the Lenders (incorporated by reference
from the Company's current report on Form 8-K dated June 30, 1998).
4.9 Amended and Restated Pledge Agreement, dated May 22, 1998, between
the Company and The Chase Manhattan Bank, as Administrative Agent
(incorporated by reference from the Company's current report on
Form 8-K dated June 30, 1998).
4.10 First Amendment to Amended and Restated Pledge Agreement dated June
30, 1998 (incorporated by reference from the Company's current
report on Form 8-K dated June 30, 1998).
4.11 Amendment No. 2 dated November 13, 1998 to Amended and Restated
Credit Agreement dated May 22, 1998, by and among the Company, The
Chase Manhattan Bank as administrative agent, and the various
lenders party thereto (incorporated by reference from the Company's
Quarterly Report on Form 10-Q for the three months ended September
30, 1998).
*4.12 The Meridian Resource Corporation Directors' Stock Option Plan
(incorporated by reference to Exhibit 10.5 of the Company's Annual
Report on Form 10-K for the year ended December 31, 1991, as
amended by the Company's Form 8 filed March 4, 1993).
4.13 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).
4.14 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).
4.15 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).
4.16 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)).
4.17 Ninth Amendment to Amended and Restated Credit Agreement, dated as
of November 28, 2001, among Meridian, JP Morgan Chase Bank as
administrative agent, and the various lenders party thereto
(incorporated by reference to Exhibit 4.18 of the Company's
Registration statement on Form S-3, as amended (Reg. No.
333-75414)).
10.1 See exhibits 4.2 through 4.17 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 Employment Agreement with P. Richard Gessinger effective December
1, 1997 (incorporated by reference from the Company's Quarterly
Report on Form 10-Q for the three months ended September 30, 1998).
*10.16 The Meridian Resource Corporation TMR Employee Trust Well Bonus
Plan (incorporated by reference from the Company's Annual Report on
Form 10-K for the year ended December 31, 1998).
*10.17 The Meridian Resource Corporation Management Well Bonus Plan
(incorporated by reference from the Company's Annual Report on Form
10-K for the year ended December 31, 1998).
*10.18 The Meridian Resource Corporation Geoscientist Well Bonus Plan
(incorporated by reference from the Company's Annual Report on Form
10-K for the year ended December 31, 1998).
*10.19 Modification Agreement effective January 2, 1999, by and among the
Company and affiliates of Joseph A. Reeves, Jr. (incorporated by
reference from the Company's Annual Report on Form 10-K for the
year ended December 31, 1998).
*10.20 Modification Agreement effective January 2, 1999, by and among the
Company and affiliates of Michael J. Mayell (incorporated by
reference from the Company's Annual Report on Form 10-K for the
year ended December 31, 1998).
10.21 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.
**23.1 Consent of Ernst & Young LLP.
**23.2 Consent of T. J. Smith & Company, Inc.
*Management contract or compensation plan.
**Filed herewith.