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, 2003 Commission file number: 1-10671
THE MERIDIAN RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 76-0319553
(State of incorporation) (I.R.S. Employer Identification No.)
1401 ENCLAVE PARKWAY, SUITE 300, HOUSTON, TEXAS 77077
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-597-7000
Securities registered pursuant to Section 12(b) of the Act:
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(Title of each class) (Name of each exchange on which registered)
Common Stock, $0.01 par value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]
Aggregate market value of shares of common stock held by non-affiliates
of the Registrant at June 30, 2003 $ 233,536,842
Number of shares of common stock outstanding at March 1, 2004 62,545,493
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Form (Items 10, 11, 12, 13 and 14)
is incorporated by reference from the registrant's Proxy Statement to be filed
on or before April 29, 2004.
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
Page
----
PART I
Item 1. Business 3
Item 2. Properties 13
Item 3. Legal Proceedings 13
Item 4. Submission of Matters to a Vote of Security Holders 13
PART II
Item 5. Market for Registrant's Common Equity, Related Shareholder
Matters and Issuer Purchases of Equity Securities 14
Item 6. Selected Financial Data 15
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16
Item 7.A. Quantitative and Qualitative Disclosures about Market Risk 31
Item 8. Financial Statements and Supplementary Data 33
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 66
Item 9.A. Controls and Procedures 66
PART III
Item 10. Directors and Executive Officers of the Registrant 66
Item 11. Executive Compensation 66
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters 66
Item 13. Certain Relationships and Related Transactions 66
Item 14. Principal Accountant Fees and Services 66
PART IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 67
Signatures 71
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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, 2003, we had
proved reserves of approximately 146 Bcfe with a present value of future net
cash flows before income taxes of approximately $507 million. Approximately 68%
of our proved reserves were natural gas and approximately 77% 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.
Historically, Meridian's experienced technical team has internally generated the
majority of the Company's exploration projects. In addition, the Company
generally serves as the operator through all phases of drilling, completing and
producing its exploration and development projects. During the course of the
prior eleven years, we have generated and participated in the discovery of
approximately 800 Bcfe of new reserves. Recently, we have developed several
shallower, low-risk exploration projects that we believe provide the Company
with a higher level of confidence for success as well as better control of risks
and costs than the deep exploration plays we have traditionally developed and
drilled. Examples of this strategy include the Company's Thornwell and Biloxi
Marshlands fields. While this strategy has proven to be successful and will be
the focus of our efforts to develop new oil and gas reserves in our producing
region, it does not replace entirely the Company's continued efforts to explore
for deep reserves where the probability of success and the level of costs
justify the risks associated with such opportunities.
We currently have interests in leases and options to lease acreage in
approximately 280,000 gross acres in Louisiana, Texas and the Gulf of Mexico. We
also have rights or access to approximately 7,800 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.
The Company's common stock is traded on the New York Stock Exchange under the
ticker symbol "TMR." You can locate additional information on the internet at
www.tmrc.com and www.sec.gov.
EXPLORATION STRATEGY
Meridian has focused its exploration strategy on prospects where large
accumulations of oil and natural gas have been found and where we believe
substantial oil and natural gas reserve additions can be achieved through
exploratory drilling in which we use 3-D seismic technology. We also seek to
identify prospects with multiple potential productive zones to maximize the
probability of success. In an effort to mitigate the risk of dry holes, we
engage in a rigorous and disciplined review of each prospect utilizing the
latest in technological advances with respect to prospect analysis and
evaluation.
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
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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 focus region of 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, and interprets the 3-D data utilizing Schlumberger's
GeoQuest interpretative software, where all of the respective disciplines
interact to develop the final product. Substantially 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.
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, provides a greater cost savings to the Company. 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 100% 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. Our working interests in offshore properties average between 3%
and 50% in each well. Our offshore properties generally involve higher drilling
costs and risks commonly associated with offshore exploration, including costs
of constructing exploration and production platforms and pipeline
interconnections, as well as weather delays and other matters.
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
probability of success 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, 2003. The
reserve volumes were reviewed by T. J. Smith & Company, Inc., independent
reservoir engineers.
GULF OF
LOUISIANA MEXICO TOTAL
--------- ------- -----
PRODUCTION FOR THE YEAR ENDED DECEMBER 31, 2003
Oil (MBbls) 1,261 142 1,403
Natural Gas (MMcf) 18,532 1,610 20,142
RESERVES AS OF DECEMBER 31, 2003
Oil (MBbls) 6,866 1,026 7,892
Natural Gas (MMcf) 88,984 9,485 98,469
ESTIMATED FUTURE NET CASH FLOWS ($000)(1)...................................................... $ 694,126
PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE INCOME TAXES ($000)(1)........................... $ 506,937
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS ($000)(1)............................. $ 455,883
(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, 2003, we used the prices at December 31, 2003, which were
$32.05 per Bbl of oil and $6.07 per Mcf of natural gas and do not
reflect the impact of hedges.
PRODUCTIVE WELLS
At December 31, 2003, 2002 and 2001, we held interests in the following
productive wells. As of December 31, 2003, we own 23 gross (4.1 net) wells in
the Gulf of Mexico which are outside operated and net to 1.4 oil wells and 2.7
natural gas wells. In addition, of the total well count for 2003, 7 wells (1.9
net) are multiple completions.
2003 2002 2001
----------- ----------- -----------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Oil Wells..................... 31 20 67 42 61 41
Natural Gas Wells............. 60 27 71 28 79 34
-- -- --- -- --- --
Total................ 91 47 138 70 140 75
== == === == === ==
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,
2003. 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 estimates were reviewed by
T. J. Smith & Company, Inc., independent reservoir engineers, as of December 31,
2003.
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PROVED RESERVES AT DECEMBER 31, 2003
---------------------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
--------- ------------- ----------- -----
(DOLLARS IN THOUSANDS)
Net Proved Reserves:
Oil (MBbls)................................ 2,949 2,067 2,876 7,892
Natural Gas (MMcf)......................... 51,087 31,192 16,190 98,469
Natural Gas Equivalent (MMcfe)............. 68,781 43,594 33,446 145,821
Estimated Future Net Cash Flows(1)............................................................ $ 694,126
Present Value of Future Net Cash Flows (before income taxes)(1)............................... $ 506,937
Standardized Measure of Discounted Future Net Cash Flows(1)................................... $ 455,883
- ---------------
(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, 2003, we used
the prices at December 31, 2003, which were $32.05 per Bbl of oil and
$6.07 per Mcf of natural gas and do not reflect the impact of hedges.
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.
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.
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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 2003, 2002
and 2001.
GROSS WELLS NET WELLS
------------------------ -------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- --- -----
EXPLORATORY WELLS
Year ended December 31, 2003.................. 5 1 6 3.8 0.4 4.2
Year ended December 31, 2002.................. 6 1 7 3.7 0.9 4.6
Year ended December 31, 2001.................. 9 7 16 4.2 5.8 10.0
DEVELOPMENT WELLS
Year ended December 31, 2003.................. - 1 1 - 0.9 0.9
Year ended December 31, 2002.................. 2 1 3 1.4 0.9 2.3
Year ended December 31, 2001.................. 4 2 6 2.8 1.8 4.6
Meridian had 1 gross (0.7 net) well in progress at December 31, 2003.
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 2003, 2002 and 2001.
YEAR ENDED DECEMBER 31,
-------------------------------------
2003 2002 2001
---- ---- ----
PRODUCTION:
Oil (MBbls)............................... 1,403 2,213 2,918
Natural gas (MMcf)........................ 20,142 15,578 22,085
Natural gas equivalent (MMcfe)............ 28,563 28,856 39,594
AVERAGE PRICES:
Oil ($/Bbl)............................... $ 24.97 $ 24.67 $ 25.17
Natural gas ($/Mcf)....................... $ 5.07 $ 3.36 $ 4.67
Natural gas equivalent ($/Mcfe)........... $ 4.80 $ 3.71 $ 4.46
PRODUCTION EXPENSES:
Lease operating expenses ($/Mcfe)........ $ 0.39 $ 0.41 $ 0.42
Severance and ad valorem
taxes ($/Mcfe)......................... $ 0.27 $ 0.29 $ 0.30
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ACREAGE
The following table sets forth the developed and undeveloped oil and natural gas
leasehold acreage in which Meridian held an interest as of December 31, 2003.
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, 2003
-------------------------------------
DEVELOPED UNDEVELOPED
---------------- ----------------
REGION GROSS NET GROSS NET
------ ----- --- ----- ---
TEXAS..................... 425 53 960 --
LOUISIANA................. 29,156 16,186 21,269 18,766
GULF OF MEXICO............ 39,518 6,098 7,500 5,033
------ ------ ------ ------
TOTAL 69,099 22,337 29,729 23,799
====== ====== ====== ======
In addition to the above acreage, we currently have options or farm-ins to
acquire leases on approximately 181,219 gross (166,220 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 67 full-time non-union employees and seven
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.
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 posted
prices, less applicable transportation deductions, and the natural gas is sold
at posted indices, less applicable transportation, gathering and dehydration
charges, adjusted for the quality of natural gas and prevailing supply and
demand conditions. The natural gas production is sold under long- and short-term
contracts (all of which are based on a published index) 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 2003, 2002 and 2001.
YEAR ENDED DECEMBER 31,
------------------------
CUSTOMER 2003 2002 2001
-------- ---- ---- ----
Louisiana Intrastate Gas................ 24% 17% 20%
Superior Natural Gas.................... 19% -- 13%
Conoco, Inc. ........................... 10% 12% --
Equiva Trading Company(1)............... -- 33% 30%
(1) This entity is an affiliate of Shell.
Other purchasers for our oil and natural gas are available; therefore, we
believe that the loss of any of these purchasers would not have a material
adverse effect on our results of operations.
MARKET CONDITIONS
Our revenues, profitability and future rate of growth substantially depend on
prevailing prices for oil and
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natural gas. Oil and natural gas prices have been extremely volatile in recent
years and are affected by many factors outside our control. Since 1993, 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, 2003, was $4.80 per Mcfe compared to $3.71 per Mcfe during
the year ended December 31, 2002. The volatile nature of energy markets makes it
difficult to estimate future prices of oil and natural gas; however, any
prolonged period of depressed prices would have a material adverse effect on our
results of operations and financial condition.
The marketability of our production depends in part on the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. Federal and state regulation of oil and natural gas
production and transportation, general economic conditions, changes in supply
and changes in demand could adversely affect our ability to produce and market
our oil and natural gas. If market factors were to change dramatically, the
financial impact on us could be substantial. We do not control the availability
of markets and the volatility of product prices are beyond our control and
therefore represent significant risks.
COMPETITION
The oil and natural gas industry is highly competitive for prospects, acreage
and capital. Our competitors include numerous major and independent oil and
natural gas companies, individual proprietors, drilling and income programs and
partnerships. Many of these competitors possess and employ financial and
personnel resources substantially greater than ours and may, therefore, be able
to define, evaluate, bid for and purchase more oil and natural gas properties.
There is intense competition in marketing oil and natural gas production, and
there is competition with other industries to supply the energy and fuel needs
of consumers.
REGULATION
The availability of a ready market for any oil and natural gas production
depends on numerous factors that we do not control. These factors include
regulation of oil and natural gas production, federal and state regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by a well or proration unit, the amount of oil and natural
gas available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or lack of available natural gas pipeline capacity in
the areas in which we may conduct operations. State and federal regulations
generally are intended to prevent waste of oil and natural gas, protect rights
to produce oil and natural gas between multiple owners in a common reservoir,
control the amount of oil and natural gas produced by assigning allowable rates
of production and control contamination of the environment. Pipelines are
subject to the jurisdiction of various federal, state and local agencies.
Oil and natural gas production operations are subject to various types of
regulation by state and federal agencies. Legislation affecting the oil and
natural gas industry is under constant review for amendment or expansion. In
addition, numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations that govern the oil and
natural gas industry and its individual members, some of 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.
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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 Federal Energy Regulatory Commission ("FERC") regulates interstate natural
gas pipeline transportation rates and service conditions, both of which affect
the marketing of natural gas produced by us, as well as the revenues we receive
for sales of such natural gas. Since the latter part of 1985, culminating in
1992 in the Order No. 636 series of orders, the FERC has endeavored to make
natural gas transportation more accessible to gas buyers and sellers on an open
and non-discriminatory basis. The FERC believes "open access" policies are
necessary to improve the competitive structure of the interstate natural gas
pipeline industry and to create a regulatory framework that will put gas sellers
into more direct contractual relations with gas buyers. As a result of the Order
No. 636 program, the marketing and pricing of natural gas has been significantly
altered. The interstate pipelines' traditional role as wholesalers of natural
gas has been terminated and replaced by regulations which require pipelines to
provide transportation and storage service to others who buy and sell natural
gas. In addition, on February 9, 2000, FERC issued Order No. 637 and promulgated
new regulations designed to refine the Order No. 636 "open access" policies and
revise the rules applicable to capacity release transactions. These new rules
will, among other things, permit existing holders of firm capacity to release or
"sell" their capacity to others at rates in excess of FERC's regulated rate for
transportation services.
It is unclear what impact, if any, these new rules or increased competition
within the natural gas transportation industry will have on us and our gas sales
efforts. It is not possible to predict what, if any, effect the FERC's open
access or future policies will have on us. Additional proposals and/or
proceedings that might affect the natural gas industry may be considered by
FERC, Congress or state regulatory bodies. It is not possible to predict when or
if any of these proposals may become effective or what effect, if any, they may
have on our operations. We do not believe, however, that our operations will be
affected any differently than other gas producers or marketers with which we
compete.
Price Controls
Our sales of natural gas, crude oil, condensate and natural gas liquids are not
regulated and transactions occur at market prices.
State Regulation of Oil and Natural Gas Production
States where we conduct our oil and natural gas activities regulate the
production and sale of oil and natural 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 other 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
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substances that we can release into the environment in connection with drilling
and production activities; limit or prohibit our drilling activities on certain
lands lying within wilderness, wetlands and other protected areas; and impose
substantial liabilities for pollution resulting from our operations. Moreover,
the general trend toward stricter standards in environmental legislation and
regulation is likely to continue. For instance, as discussed below, legislation
has been proposed in Congress from time to time that would cause certain oil and
gas exploration and production wastes to be classified as "hazardous wastes",
which would make the wastes subject to much more stringent handling and disposal
requirements. If such legislation were enacted, it could have a significant
impact on our operating costs, as well as on the operating costs of the oil and
natural gas industry in general. Initiatives to further regulate the disposal of
oil and gas wastes have also been considered in the past by certain states, and
these various initiatives could have a similar impact on us. We believe that our
current operations substantially comply with applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on us.
OPA. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area where an offshore facility is
located. The OPA makes each responsible party liable for oil-removal costs and a
variety of public and private damages. While liability limits apply in some
circumstances, a party cannot take advantage of liability limits if the party
caused the spill by gross negligence or willful misconduct or if the spill
resulted from a violation of a federal safety, construction or operating
regulation. The liability limits likewise do not apply if the party fails to
report a spill or to cooperate fully in the cleanup. Few defenses exist to the
liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party, including the
requirement to maintain proof of financial responsibility to be able to cover at
least some costs if a spill occurs. In this regard, the OPA requires the lessee
or permittee of an offshore area in which a covered offshore facility is located
to establish and maintain evidence of financial responsibility in the amount of
$35 million ($10 million if the offshore facility is located landward of the
seaward boundary of a state) to cover liabilities related to a crude oil spill
for which such person is statutorily responsible. The amount of required
financial responsibility may be increased above the minimum amounts to an amount
not exceeding $150 million depending on the risk represented by the quantity or
quality of crude oil that is handled by the facility. The MMS has promulgated
regulations that implement the financial responsibility requirements of the OPA.
Under the MMS regulations, the amount of financial responsibility required for
an offshore facility is increased above the minimum amount if the "worst case"
oil spill volume calculated for the facility exceeds certain limits established
in the regulations.
The OPA also imposes other requirements, such as the preparation of an oil-spill
contingency plan. We have such a plan in place. Failure to comply with ongoing
requirements or inadequate cooperation during a spill may subject a responsible
party to civil or criminal enforcement actions. We are not aware of any action
or event that would subject us to liability under the OPA and we believe that
compliance with the OPA's financial responsibility and other operating
requirements will not have a material adverse impact on us.
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.
-11-
Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended
(the "Clean Water Act"), imposes restrictions and controls on the discharge of
produced waters and other oil and gas wastes into navigable waters. These
controls have become more stringent over the years, and it is possible that
additional restrictions will be imposed in the future. Permits must be obtained
to discharge pollutants into state and federal waters. Certain state regulations
and the general permits issued under the Federal National Pollutant Discharge
Elimination System program prohibit the discharge of produced waters and sand,
drilling fluids, drill cuttings and certain other substances related to the oil
and gas industry into certain coastal and offshore water. The Clean Water Act
provides for civil, criminal and administrative penalties for unauthorized
discharges for oil and other hazardous substances and imposes liability on
parties responsible for those discharges for the costs of cleaning up any
environmental damage caused by the release and for natural resource damages
resulting from the release. Comparable state statutes impose liability and
authorize penalties in the case of an unauthorized discharge of petroleum or its
derivatives, or other hazardous substances, into state waters. We believe that
our operations comply in all material respects with the requirements of the
Clean Water Act and state statutes enacted to control water pollution.
Resource Conservation and Recovery Act. The Resource Conservation and Recovery
Act ("RCRA") is the principle federal statute governing the treatment, storage
and disposal of hazardous wastes. RCRA imposes stringent operating requirements,
and liability for failure to meet such requirements, on a person who is either a
"generator" or "transporter" of hazardous waste or an "owner" or "operator" of a
hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows most crude oil and natural gas
exploration and production waste to be classified as nonhazardous waste. A
similar exemption is contained in many of the state counterparts to RCRA. As a
result, we are not required to comply with a substantial portion of RCRA's
requirements because our operations generate minimal quantities of hazardous
wastes. At various times in the past, proposals have been made to amend RCRA to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste. Repeal or modification of
the exemption by administrative, legislative or judicial process, or
modification of similar exemptions in applicable state statutes, would increase
the volume of hazardous waste we are required to manage and dispose of and could
cause us to incur increased operating expenses.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, we make only a cursory
review of title to undeveloped oil and natural gas leases at the time we acquire
them. However, before drilling commences, we search the title, and remedy any
material defects before we actually begin drilling the well. To the extent title
opinions or other investigations reflect title defects, we (rather than the
seller or lessor of the undeveloped property) typically are obligated to cure
any such title defects at our expense. If we are unable to remedy or cure any
title defects so that it would not be prudent for us to commence drilling
operations on the property, we could suffer a loss of our entire investment in
the property. We believe that we have good title to our oil and natural gas
properties, 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.
-12-
ITEM 2. PROPERTIES
PRODUCING PROPERTIES
For information regarding Meridian's properties, see "Item 1. Business" above.
ITEM 3. LEGAL PROCEEDINGS
PETROQUEST LITIGATION. In December 1999, PetroQuest Energy, Inc. (formerly known
as Optima Energy (U.S.) Corporation) ("PetroQuest") sued Meridian for damages
"estimate[d] to exceed several million dollars" for Meridian's alleged gross
negligence and willful misconduct under certain agreements concerning certain
wells and property in the S.W. Holmwood and E. Lake Charles Prospects in
Calcasieu Parish and for alleged wrongful withholding of funds totaling
$886,153.31, as a result of Meridian's satisfying a prior adverse judgment in
favor of Amoco Production Company. Meridian filed an answer denying PetroQuest's
claims and asserted a counterclaim for attorney's fees, court costs and other
expenses and for declaratory relief that Meridian is entitled to retain the
amounts (with all interest thereon) that it had suspended from disbursement to
PetroQuest. In December 2003, the parties settled. Under their confidential
settlement agreement, Meridian was required to make two payments, which have now
been made. The settlement amount was fully reflected in the financial statements
at December 31, 2003. Judgments of dismissal were signed in January 2004.
RAMOS TITLE LITIGATION. Three different groups have asserted adverse title
claims to some or all of Section 80 within Meridian's "Thibodaux units" in the
Ramos Field. Another entity has asserted adverse title claims to a portion of
Section 36 within these same units. These claims turn primarily on the location
of the parish boundary between Terrebonne and Assumption Parishes and/or the
validity of various tax sales. Meridian's gas purchaser, Louisiana Intrastate
Gas Company LLC ("LIG"), has deposited into the Terrebonne Parish court registry
certain gas and plant-product proceeds attributable to 25 acres within these
units since October 2000, and Meridian has been suspending all remaining
proceeds attributable to these same 25 acres since December 2000. Meridian has
entered into a settlement discussion, but it has not yet reached an agreement
with the various parties. A trial has been set for March 16, 2004, in Assumption
Parish.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in four similar lawsuits concerning the Weeks
Island, Gibson, Bayou Pigeon and Napoleonville Fields. The lawsuits seek
injunctive relief and other relief, including unspecified amounts in both actual
and punitive damages for alleged breaches of mineral leases and alleged failure
to restore the plaintiffs' lands from alleged contamination and otherwise from
the defendants' oil and gas operations.
There are no other material legal proceedings to which Meridian or any of its
subsidiaries 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 2003.
-13-
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
------- -------
2003:
First quarter.............................. $ 1.78 $ 0.94
Second quarter............................. 4.73 0.92
Third quarter.............................. 5.16 4.00
Fourth quarter ............................ 6.14 3.88
2002:
First quarter.............................. $ 4.99 $ 3.01
Second quarter............................. 4.94 2.80
Third quarter.............................. 3.70 2.05
Fourth quarter ............................ 2.28 0.50
The closing sale price of the Common Stock on March 1, 2004, as reported on the
New York Stock Exchange Composite Tape, was $5.66. As of March 1, 2004, we had
approximately 835 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 $2.0 million in
the aggregate for cash dividends on Common Stock or for purchase of shares of
Common Stock without the prior consent of the lender.
-14-
ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with our Consolidated Financial
Statements and related notes thereto included in Item 8. and elsewhere
throughout this report.
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
(In thousands, except prices and per share information)
A. SUMMARY OF OPERATING DATA
Production:
Oil (MBbls) 1,403 2,213 2,918 3,987 4,454
Natural gas (MMcf) 20,142 15,578 22,085 27,672 22,711
Natural gas equivalent (MMcfe) 28,563 28,856 39,594 51,596 49,438
Average Prices:
Oil ($/Bbl) $ 24.97 $ 24.67 $ 25.17 $ 27.32 $ 17.61
Natural gas ($/Mcf) 5.07 3.36 4.67 4.14 2.38
Natural gas equivalent ($/Mcfe) 4.80 3.71 4.46 4.33 2.68
B. SUMMARY OF OPERATIONS
Total revenues $ 137,479 $ 107,470 $ 178,060 $ 226,246 $ 133,361
Depletion and depreciation 75,441 60,972 67,450 69,648 54,222
Net earnings (loss)(1) 7,246 (52,012) 22,551 65,070 11,467
Net earnings (loss) per share:(1)
Basic $ 0.14 $ (1.05) $ 0.47 $ 1.34 $ 0.25
Diluted 0.13 (1.05) 0.43 1.06 0.25
Dividends per:
Common share ----- ----- ----- ----- -----
Redeemable preferred share $ 8.46 $ 5.90 ----- ----- -----
Preferred share $ ----- $ ----- $ 0.11 $ 1.36 $ 1.36
Weighted average common
shares outstanding - Basic 53,325 49,763 48,350 48,646 45,995
C. SUMMARY BALANCE SHEET DATA
Total assets $ 448,749 $ 456,240 $ 507,900 $ 570,921 $ 477,719
Long-term obligations, inclusive
of current maturities 152,320 203,750 210,000 250,000 270,000
Redeemable preferred stock 60,446 69,690 ----- ----- -----
Stockholders' equity 184,335 133,393 188,221 270,322 163,860
(1) Applicable to common stockholders.
-15-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
Meridian is an independent oil and natural gas company that explores for,
acquires and develops oil and natural gas properties utilizing 3-D seismic
technology. Our operations are focused on the onshore oil and gas regions in
south Louisiana, the Texas Gulf Coast and offshore in the Gulf of Mexico.
Our reserves and strategic acreage position provide us with a significant
presence in our areas of focus, enabling us to manage a large asset base and to
add successful exploratory and development wells at relatively low incremental
costs. As of December 31, 2003, we had proved reserves of 146 Bcfe,
approximately 68% of which were natural gas, with a present value of future
pre-tax cash flows (PV-10) of $507 million. We own interests in approximately
280,000 gross (212,000 net) acres, including 18 fields and 90 wells, and we
operate approximately 85% of our total production.
The Company's business model utilizing 3-D seismic technology to explore for
large reserve accumulations in areas where others have overlooked or not
encountered commercial hydrocarbons because of the inability to resolve
structures or recognize hydrocarbon indicators with traditional 2-D seismic
data, has proven successful. During the period of 1992-2003, Meridian generated
and participated in the discovery of approximately 800 Bcfe of natural gas and
oil.
As demonstrated from the apparent declines in domestic production, fewer and
fewer economic projects are being recognized by the domestic industry. This is
partly a result of better technology that has improved the industry's ability to
determine probabilities of success, thereby impacting the number of economic
prospects available for drilling.
In addition, the conditions of the industry--price volatility and uncertainty as
well as declining prospect opportunities--and the overall economy have
influenced the availability of debt and equity capital for small capitalization
companies such as Meridian. This, combined with the geological/geophysical and
mechanical risks associated with drilling primarily deep, high-pressured wells
with large working interests, has resulted in a shift in the Company's strategy
for exploration. Recognizing the trend and risks resulting therefrom, beginning
in 2001, management embarked on its current strategy to continue to utilize its
application of 3-D seismic technology to generate and drill shallower,
higher-confidence, lower-risk plays, such as its Biloxi Marshlands project in
St. Bernard Parish, Louisiana, blended with its traditional deeper, higher risk,
but higher potential opportunities where its capital expenditure budget permits.
We have a large, balanced inventory of exploration, exploitation and development
drilling prospects in our producing region. In addition to a solid reserve base
and acreage position in our area of focus, we believe we possess the technical
knowledge and information necessary to sustain successful growth. With licenses
and rights to approximately 7,800 square miles of 3-D seismic data and 173,000
linear miles of 2-D seismic data, our technical and professional staff is in a
position to continue to generate future prospects for our growth.
Our Strategy. The key elements of our strategy are as follows:
- - Generate reserve additions through exploration, exploitation and
development drilling of a risk balanced portfolio of high potential
prospects;
- - Maintain a concise geographic focus in South Louisiana, the Texas Gulf
Coast and offshore in the Gulf of Mexico, applying professional and
technical knowledge and experience to the development of a high quality
project inventory;
- - Apply a disciplined methodology utilizing 3-D seismic technology to
reduce exploration risk, improve the probability of success, optimize
well locations and reduce our finding costs;
- - Maximize percentage ownership in each drilling prospect relative to
probability of success, increasing the impact of discoveries on
shareholder value; and
-16-
- - Maintain operational control to manage quality, costs and timing of our
drilling and production activities.
We use a disciplined approach in the generation of drilling projects, which
forms the basis of the Company's ability to grow its reserves, production and
cash flow. The Company's process of review begins with a thorough analysis of
each project area using traditional geological methods of prospect development,
combined with computer-aided technology to analyze all available 2-D and 3-D
seismic data and other geological and geophysical data with respect to the
opportunity. In addition, from time to time, we may purchase producing
properties through acquisitions that have substantial additional drilling
opportunities associated with them.
The Company previously announced that it intends to increase its capital budget
to approximately $95 million for 2004 or 25% over its 2003 spending, subject to
adjustments depending on drilling results, oil and natural gas prices and other
factors. During 2003, the Company turned production declines into growth with
drilling successes in its core area of south Louisiana where it used its
proprietary 3-D seismic to develop an inventory of low-risk exploration and
exploitation plays. The results are delivering solid production increases with
improved returns and enabling Meridian to increase drilling activities to an
expected level of 20-30 wells during 2004, primarily focused in its Biloxi
Marshlands project area. In addition to increased drilling activities, Meridian
expects to extend its proprietary 3-D data base at Biloxi Marshlands with the
shooting of 258 square miles of new data, the total of which ultimately will
provide over 578 square miles covering approximately 400,000 acres in St.
Bernard Parish, Louisiana. The 2004 exploration drilling and seismic acquisition
activities were initiated in January 2004. It is anticipated that the Biloxi
Marshlands project area will comprise a substantial portion of the Company's
future drilling inventory over the next several years as it continues to work
the entire 3-D data set ranging in depths from shallow to deep for new prospect
opportunities.
Review of 2003. During 2003, the Company focused on corporate fundamentals--
financial, seismic, land and production. The Company reduced total debt $51.4
million by reducing its Senior Bank facility from $165 million to $122.3 million
and by reducing the sub-debt from $18.7 million to $10 million. In addition,
outstanding Preferred Stock was reduced from a high of $72 million in stated
value of shares outstanding, to approximately $60.4 million as a result of
conversions to common stock. By year end 2003, the Company's debt to book
capitalization had been reduced from 50% to 39%.
In addition, during 2003, six wells were brought on line increasing production
from 65.7 Mmcfe per day to the current range of 90.0 Mmcfe to 95.0 Mmcfe per
day. With the drilling results of last year, coupled with completion of our
187-square mile 3-D seismic survey, and added cash flows, Meridian expects to
increase its drilling activities four to five fold, to 20-30 wells during 2004.
Growth in reserves, as in prior years, in a very high priority for the Company
in 2004.
Recent Developments. During the first quarter of 2004 the Company entered into a
conversion agreement with Kayne Anderson to convert $15.0 million of their 9
1/2% Convertible Subordinated Notes to Common Stock. In addition, the Company
has made $3.3 million in debt repayments and anticipates further simplifying its
capital structure and reducing total outstanding debt by $35-40 million
during 2004, based on current projections of commodity prices, production levels
and the current stock price.
In furthering its objective of organic reserve growth, the Company is continuing
to develop its Biloxi Marshlands play. To date the Company has drilled eight
wells, five of which have been completed and are producing at a gross rate of
approximately 64 Mmcfe per day. The Company has also reached total depth on its
sixth successful well in its Biloxi Marshlands project area and expects to place
it on production by May 31, 2004. The Biloxi Marshlands No. 19-1 well was
drilled to a total depth of 11,062 feet MD and electric logs have been run and
indicate apparent gas pay in the targeted Cris "I" sand interval with an overall
gross pay section of 87 feet MD. Meridian holds a 92% working interest in the
well and is the operator of the field.
-17-
Also, during the first quarter of 2004, the Company drilled the Lake Eugene
Land & Development No. 33-1 well in its Biloxi Marshlands project area and did
not encounter commercial production in the well. The well was drilled to test a
deeper Rob "L" sand interval target at a total depth of 12,215 feet MD. While
the well did not encounter commercial hydrocarbons, the Company believes many
other Rob "L" sand interval targets exist within its Biloxi Marshlands project
area, only one of which was scheduled for 2004.
During the last several months, the Company has participated in several State of
Louisiana oil and gas lease sales and has successfully bid on 23 additional
tracts in the area, covering 7,756 acres in and around our current lease
holdings. These new tracts together with the Company's land acreage position
provides the opportunity to drill 15 or more new wells during 2004 in our Biloxi
project area.
In an effort to further its development in the Biloxi project area for future
years, the Company began the third phase of its 3-D seismic program in January
2004. This approximately 258-square mile 3-D seismic survey is expected to be
completed in May 2004. Although Meridian's focus is currently on the Cris I
geological time horizon, the survey is designed to look at all shallow and for
deep objectives.
With the successful completion to the Myles Salt 29 ST well, we continue to
develop new opportunities in our Weeks Island Field. Currently, we are drilling
the Weeks Island Sand Unit A No. 25 well (the "WISU A-25"), and have logged an
overall gross pay section of 572 feet MD with 239 feet MD being net apparent oil
pay. The Company has drilled to a measured depth of 11,380 feet and, based on
electric logs, encountered oil pay in the "M" and "O" sand intervals between
depths of 10,662 and 11,234 feet MD. The Company is currently setting casing
through the oil pay section and once casing is set, will drill ahead to test
deeper "O" and "P" sand intervals. The test of the deeper intervals is expected
to take approximately ten days after which the Company will begin completion
operations and expects to have the well on production early in the second
quarter of 2004. The Company anticipates that the results of WISU A-25 well will
further define other drilling opportunities in the Weeks Island field through
the remainder of 2004. The Company owns a 92% working interest in the WISU A-25
well. The Company has currently scheduled several more wells in this field for
2004.
Also in the Weeks Island field, the Company has completed workover operations on
the Myles Salt Company No. 43 well and re-established production in the "O" sand
interval at rates of approximately 450 barrels of oil per day. Prior to the
workover, the Myles Salt No. 43 was producing at significantly lower rates. The
Company is currently performing workover operations on the Myles Salt Company
No. 32 well to replace corroded tubing and expects to return the well to
production at rates similar to the rates in the Myles Salt No. 43. The Company
has identified several other high potential workovers in the Weeks Island field.
Industry Conditions. Our revenues, profitability and cash flow are substantially
dependent upon prevailing prices for oil and natural gas. Oil and natural gas
prices have been extremely volatile in recent years and are affected by many
factors outside of our control. The average price we received during the year
ended December 31, 2003 was $4.80 per Mcfe compared to $3.71 per Mcfe during the
year ended December 31, 2002. Fluctuations in prevailing prices for oil and
natural gas have several important consequences to us, including affecting the
level of cash flow received from our producing properties, the timing of
exploration of certain prospects and our access to capital markets, which could
impact our revenues, profitability and ability to maintain or increase our
exploration and development program. Refer to Item 7.A. for a discussion of
commodity price risk management activities utilized to mitigate a portion of the
near term effects of this exposure to price volatility.
-18-
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2003, COMPARED TO YEAR ENDED DECEMBER 31, 2002
Oil and natural gas revenues increased $30.1 million, primarily as a result of
an increase in average commodity prices. The following table summarizes
Meridian's operating revenues, production volumes and average sales prices for
the years ended December 31, 2003 and 2002.
Year Ended
December 31, Increase
2003 2002 (Decrease)
---- ---- ----------
Production:
Oil (MBbls) 1,403 2,213 (37%)
Natural gas (MMcf) 20,142 15,578 29%
Natural gas equivalent (MMcfe) 28,563 28,856 (1%)
Average Sales Price:
Oil (per Bbl) $ 24.97 $ 24.67 1%
Natural gas (per Mcf) 5.07 3.36 51%
Natural gas equivalent (per Mcfe) 4.80 3.71 29%
Gross Revenues (000's):
Oil $ 35,032 $ 54,595 (36%)
Natural gas 102,092 52,397 95%
---------- ---------- ----
Total $ 137,124 $ 106,992 28%
========== ========== ====
Operating Expenses.
Oil and natural gas operating expenses decreased $0.6 million to $11.3 million
in 2003, compared to $11.9 million in 2002. Lease operating expenses reflect
savings realized on sold properties combined with other cost savings offset by
additional operating expenses associated with the Biloxi Marshlands project
area. On a unit basis, lease operating expenses decreased $0.02 per Mcfe to
$0.39 per Mcfe for the year 2003 from $0.41 per Mcfe for the year 2002. In 2004,
our anticipated future increases in production should result in a continued
reduction in operating costs on a per unit level.
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes decreased $0.6 million to $7.6 million in 2003,
compared to $8.2 million in 2002. This decrease is largely attributable to the
decrease in the average tax rate for natural gas and the decrease in oil
revenues from the 2002 levels, partially offset by an increase in natural gas
production. 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
$0.171 per Mcf for natural gas (effective July 2003). The tax rate for natural
gas for the first half of 2002 was $0.199 per Mcf and from July 2002 through
June 2003 was $0.122 per Mcf. On an equivalent unit of production basis,
severance and ad valorem taxes decreased to $0.27 per Mcfe from $0.29 per Mcfe
for the comparable period. The per Mcfe cost for 2004 will increase due to a
higher anticipated severance tax rate than what was experienced in 2003.
-19-
Depletion and Depreciation.
Depletion and depreciation expense increased $14.4 million to $75.4 million in
2003 from $61.0 million for 2002. This increase was primarily a result of an
increased depletion rate from 2002 levels, partially offset by the 1% decrease
in production on an Mcfe basis from the comparable period in 2002. On a unit
basis, depletion and depreciation expenses increased to $2.64 per Mcfe for 2003,
compared to $2.11 per Mcfe for 2002. The increase in the depletion rate is
primarily a result of the 2002 impairment of long-lived assets mentioned below.
We are expecting a downward trend in our 2004 depletion rate as we find and
develop new reserves during the year.
General and Administrative Expense.
General and administrative expense decreased $0.2 million to $11.6 million in
2003 compared to $11.8 million for the year 2002. As previously announced,
during the first quarter of 2003 the Company initiated reductions in staff to
reflect a change in exploration strategy to lower-risk, higher probability
projects, maintaining focus in south Louisiana and southeast Texas. Although the
full impact of these reductions has not been fully recognized due to the
severance packages included, it is anticipated that these changes will result in
future savings in costs without sacrificing the Company's exploration efforts or
opportunities. In addition to the reduction in staff during the year,
professional services decreased partially offset by an increase in insurance
costs primarily for Company directors and officers. On an equivalent unit of
production basis, general and administrative expenses were comparable for the
two years.
Interest Expense.
Interest expense decreased $2.4 million to $11.5 million in 2003 compared to
$13.9 million for 2002. The decrease is primarily a result of the reduction in
long-term debt by $51.4 million and the Federal Reserve Bank's decrease in
overall interest rates which has led to a decrease in the average interest rate
on the revolving credit facilities. The funds for the reduction in debt were the
result of the August 2003 stock offering, improved cash flow from operations and
the sale of certain non-strategic oil and gas properties.
Impairment of Long-Lived Assets.
In 2002, a write-down in oil and natural gas proved undeveloped reserves
resulted in the Company recognizing a non-cash impairment of $69.1 million of
its oil and natural gas properties under the full cost method of accounting.
This was due to a negative revision associated with an unsuccessful well drilled
in the Kent Bayou Field in 2002. If oil and natural gas price were to
significantly drop during 2004, the risk of future impairments exists.
Credit Facility Retirement Costs.
During August 2002, the Company replaced its Chase Manhattan Bank Credit
Facility with a new three-year $175 million underwritten senior secured
agreement with Societe Generale and Fortis Capital Corp. Deferred debt costs
associated with the prior credit facility of $1.2 million were written off in
September 2002.
Taxes on Income.
The provision for income taxes for 2003 is $4.2 million. Income taxes were
provided on book income after taking into account permanent differences between
book income and taxable income, and after reducing the income tax valuation
allowance by $2.7 million.
The income tax for 2002 was a credit of $22.0 million. This credit resulted from
the 2002 book loss after taking into account permanent differences between book
income and taxable income. This credit was limited to the amount of the
Company's deferred tax liability at December 31, 2001.
-20-
Adoption of Statement of Financial Accounting Standards No. 143.
On January 1, 2003, the Company adopted Statement of Financial Accounting
Standards No. 143 ("SFAS No. 143"), "Accounting for Asset Retirement
Obligations." As a result, the Company recorded a long-term liability of $4.5
million representing the discounted present value of the estimated retirement
obligations and an increase in capitalized oil and gas properties of $3.2
million. The liability will be accreted to its future value in subsequent
reporting periods and will be charged to earnings on the Company's Consolidated
Statement of Operations as "Accretion Expense." As a result of adoption of SFAS
No. 143, the Company has charged approximately $0.7 million to earnings as
accretion expense during 2003. The cumulative effect of the change in accounting
principle for prior years totaled $1.3 million or $0.02 per share, and was
charged to earnings in the first quarter of 2003.
YEAR ENDED DECEMBER 31, 2002, COMPARED TO YEAR ENDED DECEMBER 31, 2001
Oil and natural gas revenues decreased $69.6 million as a result of decreased
production volumes and a decrease in average commodity prices. The production
decrease was primarily a result of the property sales completed during 2001,
hurricane related production losses and natural production declines, partially
offset by the inclusion of new wells being placed on production. The following
table summarizes Meridian's operating revenues, production volumes and average
sales prices for the years ended December 31, 2002 and 2001.
Year Ended
December 31, Increase
2002 2001 (Decrease)
---- ---- ----------
Production:
Oil (MBbls) 2,213 2,918 (24%)
Natural gas (MMcf) 15,578 22,085 (29%)
Natural gas equivalent (MMcfe) 28,856 39,594 (27%)
Average Sales Price:
Oil (per Bbl) $ 24.67 $ 25.17 (2%)
Natural gas (per Mcf) 3.36 4.67 (28%)
Natural gas equivalent (per Mcfe) 3.71 4.46 (17%)
Gross Revenues (000's):
Oil $ 54,595 $ 73,443 (26%)
Natural gas 52,397 103,203 (49%)
--------- ----------- ----
Total $ 106,992 $ 176,646 (39%)
========= =========== ====
Interest and Other Income.
Interest and other income decreased $0.9 million to $0.5 million in 2002,
compared to $1.4 million for 2001. This decrease was primarily due to a lower
average amount of invested funds and lower interest rates during 2002 than in
2001. A significant portion of the interest income for 2001 was earned on the
investment of funds accumulated from the sale of properties and a Common Stock
offering during 2000. These funds had been accumulated to exercise the option to
buy back the Company's Preferred Stock and six million shares of the Company's
Common Stock from Shell on January 29, 2001.
Operating Expenses.
Oil and natural gas operating expenses decreased $4.7 million to $11.9 million
in 2002, compared to $16.6 million in 2001. This decrease was primarily due to
the sale of high cost, non-core properties during 2001 and the reorganization of
field operations over the last thirteen months partially offset by the inclusion
of costs
-21-
associated with returning the Company's properties to production following
hurricanes. This reorganization involved a reduction in field operating
personnel and increased emphasis on operating cost reductions. In addition, the
Company undertook an expanded well workover program during 2001 in order to
benefit from the higher commodity prices being realized at the time.
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes decreased $3.6 million to $8.2 million in 2002,
compared to $11.8 million in 2001. This decrease is largely attributable to the
decrease in natural gas production and the decrease in oil revenues from the
2001 levels, partially offset by an increase in the average tax rate for natural
gas. Meridian's production is primarily from southern Louisiana, and, therefore,
is subject to a current tax rate of 12.5% of gross oil revenues and $0.122 per
Mcf for natural gas. The tax rate for natural gas for the first half of 2001 was
$0.097 per Mcf and from July 2001 through June 2002 was $0.199 per Mcf.
Depletion and Depreciation.
Depletion and depreciation expense decreased $6.4 million to $61.0 million in
2002 from $67.4 million for 2001. This decrease was primarily a result of the
27% decrease in production on an Mcfe basis from 2001, partially offset by an
increase in the depletion rate from 2001 levels primarily due to the write-down
of the proved reserves associated with the Kent Bayou Field.
General and Administrative Expense.
General and administrative expense decreased $1.7 million to $11.8 million in
2002 compared to $13.5 million for the year 2001. This reduction was primarily
due to the savings realized from staff reductions and the purchase and
termination of certain outstanding well bonus plan interests at the end of 2001.
Interest Expense.
Interest expense decreased $5.4 million to $13.9 million in 2002 compared to
$20.1 million for 2001. The decrease is primarily a result of the reduction in
the debt balance and the Federal Reserve Bank's decrease in overall interest
rates which has led to a decrease in the average interest rate on the revolving
credit facility.
Full Cost Ceiling Writedown.
During 2002, a negative revision in oil and natural gas proved undeveloped
reserves associated with an unsuccessful well drilled in the Kent Bayou Field
resulted in the Company recognizing a full cost ceiling write-down of its oil
and natural gas properties totaling $69.1 million ($46.9 million after tax).
A decline in oil and natural gas prices caused us to recognize $6.6 million in
full cost ceiling write-downs during 2001.
Credit Facility Retirement Costs.
During 2002, the Company replaced its Chase Manhattan Bank Credit Facility with
a new three-year $175 million underwritten senior secured credit agreement with
Societe Generale and Fortis Capital Corp. Deferred debt costs associated with
the prior credit facility of $1.2 million were written off in 2002.
-22-
FLIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS. Net cash flows provided by operating activities were $91.6 million
for the year ended December 31, 2003, as compared to $42.5 million for the year
ended December 31, 2002, an increase of $49.1 million or 116%. This increase was
primarily attributable to a $30.1 million increase in revenue due to price
increases. The year-over-year change in operating assets and liability from
December 31, 2002, to December 31, 2003, also accounted for approximately $14.8
million of increase in net cash flows provided by operating activities.
Net cash flows used in investing activities were $67.0 million for the year
ended December 31, 2003, as compared to $77.1 million for the year ended
December 31, 2002. The decrease was due to a decrease in capital expenditures of
$4.9 million, coupled with the selling of a non-strategic field for $4.9
million.
Net cash flows used in financing activities were $19.1 million for the year
ended December 31, 2003, as compared to net cash flows provided from financing
activities of $27.5 million. During 2003, the Company retired $51.4 million in
long-term debt, partially offset by the $33.2 million raised by selling common
stock. During 2002, the Company raised $66.9 million by selling redeemable
preferred stock which funded the retirement of $31.3 million in long-term debt
and capital expenditures in excess of net cash flows provided by operating
activities.
CREDIT FACILITY.
During August 2002, the Company replaced its Chase Manhattan Bank Credit
Facility with a new three-year $175 million underwritten senior secured credit
agreement (the "Credit Agreement") with Societe Generale as administrative
agent, lead arranger and book runner, and Fortis Capital Corporation, as co-lead
arranger and documentation agent. Borrowings under the Credit Agreement mature
on August 13, 2005. The borrowing base is currently set at $130.0 million and is
scheduled to be redetermined and be effective on April 30, 2004. Credit Facility
payments of $42.7 million were made during 2003, bringing the outstanding
balance to $122.3 million as of December 31, 2003. During the first two months
of 2004, the Company made $3.3 million in additional debt repayments and
anticipates that it will continue to make debt repayments during the remainder
of the year.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders or borrower, under the Credit Agreement, have the right to redetermine
the borrowing base at any time, once during each calendar year. Borrowings under
the Credit Agreement are secured by pledges of outstanding capital stock of the
Company's subsidiaries and a mortgage on the Company's oil and natural gas
properties of at least 90% of its present value of proved properties. The Credit
Agreement contains various restrictive covenants, including, among other items,
maintenance of certain financial ratios and restrictions on cash dividends on
Common Stock and under certain circumstances Preferred Stock, and an unqualified
audit report on the Company's consolidated financial statements beginning with
those as of and for the year ended December 31, 2002. The auditor's report on
the 2002 consolidated financial statements contained a "going concern"
modification. The Company obtained a waiver of the related covenant that would
have triggered a violation of the loan agreement.
Under the Credit Agreement, the Company may secure either (i) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate, plus an additional 0.5% to 1.5% depending
on the ratio of the aggregate outstanding loans and letters of credit to the
borrowing base or a federal funds-based rate plus 1/2 of 1% or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At December 31, 2003, the three-month LIBOR interest rate
was 1.15188%. The Credit Agreement also provides for commitment fees ranging
from 0.375% to 0.5% per annum.
-23-
SUBORDINATED CREDIT AGREEMENT. The Company extended and amended a short-term
subordinated credit agreement with Fortis Capital Corporation for $25 million on
April 5, 2002, with a maturity date of December 31, 2004. The interest rate is
LIBOR plus 4.5% through December 31, 2002, LIBOR plus 5.5% from January 1, 2003,
through August 31, 2003, and LIBOR plus 6.5% from September 1, 2003, through
December 31, 2004. At December 31, 2003, the three-month LIBOR interest rate was
1.15188%. A note payment of $5 million is due on April 30, 2004, with the
remaining $5 million payable on December 31, 2004. Note payments totaling $8.75
million were paid in 2003. The outstanding balance is $10.0 million as of
December 31, 2003.
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 are unsecured and contain customary events of
default, but do not contain any maintenance or other restrictive covenants.
Interest is payable on a quarterly basis.
During March 2002, the Company and the holders of the Notes amended the
conversion price from $7.00 to $5.00 per share. The Notes are convertible at any
time by the holders of the Notes into shares of the Company's Common Stock,
$0.01 par value utilizing the conversion price. The conversion price is subject
to customary anti-dilution provisions. We may prepay the Notes at any time
without penalty or premium.
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. A private placement of $66.85
million of 8.5% redeemable convertible preferred stock was completed during May
2002. The preferred stock is convertible into shares of the Company's Common
Stock at a conversion price of $4.45 per share. Dividends are payable
semi-annually in cash or additional preferred stock. At the option of the
Company, one-third of the preferred shares can be forced to convert to Common
Stock if the closing price of the Company's Common Stock exceeds 150% of the
conversion price for 30 out of 40 consecutive trading days on the New York Stock
Exchange. Based on the above conversion criteria, the Company can elect to
convert up to one-third of the original issue provided that the conversion
occurs no sooner than twelve months from the most recent conversion. The
preferred stock is subject to redemption at the option of the Company after
March 2005, and mandatory redemption on March 31, 2009. The holders of the
preferred stock have been granted registration rights with respect to the shares
of Common Stock issued upon conversion of the preferred stock. In the last
quarter of 2003, $12.2 million of preferred stock was converted into 2.7 million
shares of Common Stock. In addition, $3.6 million of preferred stock was
converted into 0.8 million shares of Common Stock during January and February
2004.
Dividends of $6.0 million were accumulated (net of $0.6 million of deferred
preferred stock offering costs amortized during 2003) during 2003, of which $3.0
million was satisfied with the issuance of additional shares of redeemable
preferred stock, and $3.0 million was paid in cash in January 2004. Dividends of
$3.9 million were accumulated in 2002, of which $1.1 million was paid in cash
and $2.8 million was satisfied with the issuance of additional shares of
redeemable preferred stock.
CAPITAL EXPENDITURES. Capital expenditures in 2003 consisted of $71.9 million
for property and equipment additions primarily related to exploration and
development of various prospects, including leases, seismic data acquisitions,
production facilities, and related drilling and workover activities. Our
strategy is to blend exploration drilling activities with high-confidence
workover and development projects selected from our broad asset inventory in
order to capitalize on periods of high commodity prices. This strategy brought
on production and added reserves sooner than the drilling of deep, higher risk
exploration wells.
The 2004 capital expenditures plan is currently forecast at approximately $95
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 2004 plan primarily utilizing cash flow from operations.
When appropriate, excess cash flow from operations as a result of increased
rates or prices beyond that needed for the 2004 capital expenditures plan will
be used to de-lever the Company by development of exploration discoveries or
direct payment of debt.
-24-
SALE OF PROPERTIES. During 2003, the Company sold certain non-strategic oil and
gas properties located in south Louisiana for approximately $4.9 million. The
sale was comprised of approximately 4 Bcfe proved developed reserves and 1 Bcfe
of undeveloped reserves. Benefits of the sale include the reduction of total
debt by an additional $4.9 million resulting in an immediate savings in interest
costs on the Company's senior bank debt, the elimination of $3.1 million in
future capital expenditures associated with the properties, and the elimination
of over $1.5 million in annual lease operating expenses.
CASH OBLIGATIONS. The following summarizes the Company's contractual obligations
at December 31, 2003 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 $ 10,000 $ 142,320 $ --- $ 152,320
Non-cancelable operating leases 1,603 2,871 --- 4,474
---------- ---------- ----- ----------
Total contractual cash obligations $ 11,603 $ 145,191 $ --- $ 156,794
DIVIDENDS. It is our policy to retain existing cash for reinvestment in our
business, and therefore, we do not anticipate that dividends will be paid with
respect to the Common Stock in the foreseeable future. Dividends on the
redeemable preferred stock aggregating $6.0 million were accrued for in 2003. Of
that amount, $3.0 million was satisfied with the issuance of additional shares
of redeemable preferred stock, and $3.0 million was paid in cash in January
2004. During 2003, $0.6 million of deferred preferred stock offering costs was
amortized.
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 accepted in the
United States of America. The following summarizes several of our critical
accounting policies. See a complete list of significant accounting policies in
Note 1 to the Consolidated Financial Statements.
USE OF ESTIMATES. The preparation of these financial statements requires the
Company to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses, and disclosure of contingent assets
and liabilities, if any, at the date of the financial statements. The Company
analyzes its estimates, including those related to oil and gas revenues, bad
debts, oil and gas properties, marketable securities, income taxes and
contingencies and litigation. The Company bases its estimates on historical
experience and various other assumptions that are believed to be reasonable
under the circumstances. Actual results may differ from these estimates under
different assumptions or conditions. The Company believes the following critical
accounting policies affect its more significant judgments and estimates used in
the preparation of its consolidated financial statements.
PROPERTY AND EQUIPMENT. The Company follows the full cost method of accounting
for its investments in oil and natural gas properties. All costs incurred with
the acquisition, exploration and development of oil and natural gas properties,
including unproductive wells, are capitalized. Under the full cost method of
accounting, such costs may be incurred both prior to or after the acquisition of
a property and include lease acquisitions, geological and geophysical services,
drilling, completion and equipment. Included in capitalized costs are general
and administrative costs that are directly related to acquisition, exploration
and development activities, and which are not related to production, general
corporate overhead or similar activities. For the years 2003, 2002, and 2001,
such capitalized costs totaled $10.0 million, $11.7 million, and $13.5 million,
respectively. General and administrative costs related to production and general
overhead are expensed as incurred.
-25-
Proceeds from the sale of oil and natural gas properties are credited to the
full cost pool, except in transactions involving a significant quantity of
reserves or where the proceeds received from the sale would significantly alter
the relationship between capitalized costs and proved reserves, in which case a
gain or loss would be recognized.
Future development, site restoration, and dismantlement and abandonment costs,
net of salvage values, are estimated property by property based upon current
economic conditions and are included in our amortization of our oil and natural
gas property costs.
The provision for depletion and amortization of oil and natural gas properties
is computed by the unit-of-production method. Under this computation, the total
unamortized costs of oil and natural gas properties (including future
development, site restoration, and dismantlement and abandonment costs, net of
salvage value), excluding costs of unproved properties, are divided by the total
estimated units of proved oil and natural gas reserves at the beginning of the
period to determine the depletion rate. This rate is multiplied by the physical
units of oil and natural gas produced during the period.
The cost of unevaluated oil and natural gas properties not being amortized is
assessed quarterly to determine whether such properties have been impaired. In
determining impairment, an evaluation is performed on current drilling results,
lease expiration dates, current oil and gas industry conditions, and available
geological and geophysical information. Any impairment assessed is added to the
cost of proved properties being amortized.
FULL-COST CEILING TEST. At the end of each quarter, the unamortized cost of oil
and natural gas properties, after deducting the asset retirement obligation, net
of related deferred income taxes, is limited to the sum of the estimated future
net revenues from proved properties using period-end prices, after giving effect
to cash flow hedge positions, discounted at 10%, and the lower of cost or fair
value of unproved properties adjusted for related income tax effects.
The calculation of the ceiling test and the provision for depletion and
amortization are based on estimates of proved reserves. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in
projecting the future rates of production, timing, and plan of development. The
accuracy of any reserves estimate is a function of the quality of available data
and of engineering and geological interpretation and judgement. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify a revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of oil and natural gas that are ultimately
recovered.
During 2002, a negative revision in oil and natural gas proved undeveloped
reserves associated with the Kent Bayou Field resulted in the Company
recognizing a full cost ceiling write-down totaling $69.1 million ($46.9 million
after tax) of its oil and natural gas properties. A decline in oil and natural
gas prices caused us to recognize $6.6 million in full cost ceiling write-downs
during 2001.
Due to the inherent imprecision in estimating oil and natural gas revenues as
well as the potential volatility in oil and gas prices and their effect on the
carrying value of our proved oil and gas reserves, there can be no assurance
that write-downs in the future will not be required as a result of factors that
may negatively affect the present value of proved oil and natural gas reserves
and the carrying value of oil and natural gas properties, including volatile oil
and natural gas prices, downward revisions in estimated proved oil and natural
gas reserve quantities and unsuccessful drilling activities.
PRICE RISK MANAGEMENT ACTIVITIES. The Company follows the Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" which requires that changes in the derivatives' fair value be
recognized currently in earnings unless specific cash flow hedge accounting
criteria
-26-
are met. The statement also establishes accounting and reporting standards
requiring that every derivative instrument be reported in the balance sheet as
either an asset or liability measured at its fair value. Cash flow hedge
accounting for qualifying hedges allows the gains and losses on derivatives to
offset related results on the hedged item in the earnings statements and
requires that a company formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting. We adopted FAS 133
effective January 1, 2001.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered into various swap
agreements. These swaps allow the Company to predict with greater certainty the
effective oil and natural gas prices to be received for our hedged production.
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, our derivative instruments continue to be highly effective in
achieving the risk management objectives for which they were intended. These
swaps have been designated as cash flow hedges as provided by FAS 133 and any
changes in fair value are recorded in other comprehensive income until earnings
are affected by the variability in cash flows of the designated hedged item. Any
changes in fair value resulting from the ineffectiveness of the hedge are
reported in the consolidated statement of operations as a component of revenues.
The Company recognized minimal losses related to hedge ineffectiveness during
the three years ended December 31, 2003.
At December 31, 2003, the change in estimated fair value of the Company's oil
and natural gas swaps was an unrealized loss of $11.6 million ($7.5 million net
of tax) which is recognized in other comprehensive income. Based upon December
31, 2003, oil and natural gas commodity prices, approximately $9.8 million of
the loss deferred in other comprehensive income could potentially lower gross
revenues in 2004. The swap agreements expire at various dates through July 31,
2005.
Net settlements under these swap agreements reduced oil and natural gas revenues
by $14,916,000 and $1,183,000 for the years ended December 31, 2003 and 2002,
respectively. During the year ended December 31, 2001, the Company had no
material open hedging agreements.
See Item 7.A. for additional discussion of disclosures about market risk.
FAIR VALUE OF FINANCIAL INSTRUMENTS. Our financial instruments consist of cash
and cash equivalents, accounts receivable, accounts payable, bank borrowings and
subordinated notes. The carrying amounts of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value due to the highly liquid
nature of these short-term instruments. The fair values of the bank borrowings
approximate the carrying amounts as of December 31, 2003 and 2002, and were
determined based upon variable interest rates currently available to us for
borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair values of our subordinated notes due 2005 were $19.6
million and $18.9 million at December 31, 2003 and 2002, respectively. The
carrying value of our subordinated notes was $20 million at December 31, 2003
and 2002.
NEW ACCOUNTING PRONOUNCEMENTS. A reporting issue has arisen regarding the
application of certain provisions of SFAS No. 142 "Goodwill and Other Intangible
Assets" to companies in the extractive industries, including oil and gas
companies. The issue is whether SFAS No. 142 requires registrants to classify
the costs of mineral rights held under lease or other contractual arrangements
associated with extracting oil and gas as intangible assets in the balance
sheet, apart from other capitalized oil and gas property costs, and provide
specific footnote disclosures. Historically, the Company has included the costs
of such mineral rights associated with extracting oil and gas as a component of
oil and gas properties. If it is ultimately determined that SFAS No. 142
requires oil and gas companies to classify costs of mineral rights held under
lease or other contractual arrangement associated with extracting oil and gas as
a separate intangible assets line item on the balance sheet, the Company would
be required to reclassify approximately $16.2 million at December 31, 2003, and
$15.8 million at December 31, 2002, respectively, out of oil and gas properties
and into a separate intangible assets line item. The Company's cash flows and
results of operations would not be affected since
-27-
such intangible assets would continue to be depleted and assessed for impairment
in accordance with full cost accounting rules. Further, the Company does not
believe the classification of the costs of mineral rights associated with
extracting oil and gas as intangible assets would have any impact on the
Company's compliance with covenants under its debt agreements.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires the fair value of a liability for an asset
retirement obligation to be recognized in the period in which it is incurred if
a reasonable estimate of fair value can be made. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
SFAS No. 143 was effective for the Company on January 1, 2003. See Note 3. for
discussion of the impact on the Company's consolidated financial statements.
During December 2003, the FASB issued Interpretation No. 46R, "Consolidation of
Variable Interest Entities" ("FIN 46"), which requires the consolidation of
certain entities that are determined to be variable interest entities ("VIE's").
An entity is considered to be a VIE when either (i) the entity lacks sufficient
equity to carry on its principal operations, (ii) the equity owners of the
entity cannot make decisions about the entity's activities or (iii) the entity's
equity neither absorbs losses or benefits from gains. Meridian owns no interests
in variable interest entities, and therefore this new interpretation has not
affected the Company's consolidated financial statements.
In May 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. The adoption of this statement did
not have a material effect on the Company's financial statements.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150
establishes the standards on how companies classify and measure certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that the Company classify as liabilities the fair value of
all mandatorily redeemable financial instruments that had previously been
recorded as equity or elsewhere in the consolidated financial statements. This
statement is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise effective for all existing financial instruments
beginning in the third quarter of 2003. We do not believe that this statement
will have any impact on the Company's consolidated financial statements.
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.
-28-
Actual results and trends in the future may differ materially depending on a
variety of factors including, but not limited to the following:
Changes in the price of oil and natural gas. The prices we receive for our oil
and natural gas production and the level of such production are subject to wide
fluctuations and depend on numerous factors that 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.
-29-
Borrowing base for the Credit Facility. The Credit Agreement with Societe
Generale and Fortis Capital Corp. is presently scheduled for borrowing base
redetermination dates on a quarterly basis, with the next such redetermination
scheduled for April 30, 2004. The borrowing base is redetermined on numerous
factors including current reserve estimates, reserves that have recently been
added, current commodity prices, current production rates and estimated future
net cash flows. These factors have associated risks with each of them.
Significant reductions or increases in the borrowing base will be determined by
these factors, which, to a significant extent, are not under the Company's
control.
-30-
ITEM 7.A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is from time to time exposed to market risk from changes in interest
rates and hedging contracts. A discussion of the market risk exposure in
financial instruments follows.
INTEREST RATES
We are subject to interest rate risk on our long-term fixed interest rate debt
and variable interest rate borrowings. Our long-term borrowings primarily
consist of borrowings under the Credit Facility and principal due December 31,
2004 under our Subordinated Credit Agreement. Since interest charged borrowings
under the Credit Facility floats with prevailing interest rates (except for the
applicable interest period for Eurodollar loans), the carrying value of
borrowings under the Credit Facility should approximate the fair market value of
such debt. Changes in interest rates, however, will change the cost of
borrowing. Assuming $122.3 million remains borrowed under the Credit Facility
and $10 million remains borrowed under the Subordinated Credit Agreement, we
estimate our annual interest expense will change by $1.223 million for each 100
basis point change in the applicable interest rates utilized under the Credit
Facility and $10 million from the Subordinated Credit Agreement. Changes in
interest rates would, assuming all other things being equal, cause the fair
market value of debt with a fixed interest rate, such as the Notes, to increase
or decrease, and thus increase or decrease the amount required to refinance the
debt. The fair value of the Notes is dependent on prevailing interest rates and
our current stock price as it relates to the conversion price of $5.00 per share
of our Common Stock.
HEDGING CONTRACTS
Meridian may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. From
time to time, we may enter into swaps and other derivative contracts to hedge
the price risks associated with a portion of anticipated future oil and gas
production. While the use of hedging arrangements limits the downside risk of
adverse price movements, it may also limit future gains from favorable
movements. Under these agreements, payments are received or made based on the
differential between a fixed and a variable product price. These agreements are
settled in cash at or prior to expiration or exchanged for physical delivery
contracts. Meridian does not obtain collateral to support the agreements, but
monitors the financial viability of counter-parties and believes its credit risk
is minimal on these transactions. In the event of nonperformance, we would be
exposed to price risk. Meridian has some risk of accounting loss since the price
received for the product at the actual physical delivery point may differ from
the prevailing price at the delivery point required for settlement of the
hedging transaction.
In 2002, we entered into certain swap agreements as summarized in the table
below. The Notional Amount is equal to the total net volumetric hedge position
of Meridian during the periods indicated. The positions effectively hedge
approximately 11% of our proved developed natural gas production and 79% of our
proved developed oil production during the respective terms of the swap
agreements. The fair values of the cash flow hedges are based on the difference
between the strike price and the New York Mercantile Exchange future prices for
the applicable trading months.
Weighted Average Fair Value (unrealized) at
Notional Strike Price December 31, 2003 (in
Amount ($ per unit) thousands)
--------- ---------------- --------------------------
Natural Gas (mmbtu)
January 2004 - June 2005 3,550,000 $ 3.73 $ (5,630)
Oil (bbls)
January 2004 - July 2005 978,000 $ 23.49 $ (5,938)
------------
$ (11,568)
============
-31-
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The definitions set forth below apply to the indicated terms commonly used in
the oil and natural gas industry and in this Form 10-K. Mcfe is calculated using
the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural
gas liquids, which approximates the relative energy content of crude oil,
condensate and natural gas liquids as compared to natural gas. Prices have
historically been substantially higher for crude oil than natural gas on an
energy equivalent basis. Any reference to net wells or net acres was determined
by multiplying gross wells or acres by our working percentage interest therein.
"Bbl" means barrel and "Bbls" means barrels.
"Bcf" means billion cubic feet.
"Bcfe" means billion cubic feet of natural gas equivalent.
"Btu" means British Thermal Unit.
"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.
"MD" means measured depth.
"MMBbls" means million barrels.
"MMBtu" means million Btus.
"MMcf" means million cubic feet.
"MMcfe" means million cubic feet of natural gas equivalent.
"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%.
"TVD" means true vertical depth.
-32-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements
Page
----
Reports of Independent Auditors 33
Consolidated Statements of Operations
-- For each of the three years in the period ended December 31, 2003 35
Consolidated Balance Sheets--December 31, 2003 and 2002 36
Consolidated Statements of Cash Flows
-- For each of the three years in the period ended December 31, 2003 38
Consolidated Statements of Stockholders' Equity
-- For each of the three years in the period ended December 31, 2003 39
Consolidated Statements of Comprehensive Income
-- For each of the three years in the period ended December 31, 2003 40
Notes to Consolidated Financial Statements 41
-33-
REPORT OF INDEPENDENT AUDITORS
To the Stockholders and Board of Directors
The Meridian Resource Corporation
We have audited the accompanying consolidated balance sheet of The Meridian
Resource Corporation and subsidiaries as of December 31, 2003 and the related
consolidated statements of operations, stockholders' equity, cash flows, and
comprehensive (loss) income for the year then ended. 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 audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. 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 audit provides a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of The Meridian
Resource Corporation and subsidiaries at December 31, 2003 and the results of
their operations and their cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States of America.
As discussed in Note 3. to the consolidated financial statements, effective
January 1, 2003, the Company changed its method of accounting for asset
retirement obligations.
BDO SEIDMAN, LLP
Houston, Texas
March 1, 2004
-34-
REPORT OF INDEPENDENT AUDITORS
Board of Directors and Stockholders
The Meridian Resource Corporation
We have audited the accompanying consolidated balance sheets of The Meridian
Resource Corporation and subsidiaries as of December 31, 2002, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
each of the two years in the period ended December 31, 2002. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of The Meridian
Resource Corporation and subsidiaries at December 31, 2002, and the consolidated
results of their operations and their cash flows for each of the two years in
the period ended December 31, 2002, in conformity with accounting principles
generally accepted in the United States.
As discussed in Note 5 to the 2002 financial statements, the Company's working
capital deficiency, including amounts due under its revolving credit agreement
as a result of a borrowing base redetermination effective April 30, 2003, and
the provisions in that agreement for additional redeterminations of the
borrowing base during 2003, raise substantial doubt about its ability to
continue as a going concern. Management's plans in regard to these matters are
also described in Note 5. The financial statements do not include any
adjustments to reflect the possible future effects on the recoverability and
classification of assets or the amounts and classification of liabilities that
may result from the outcome of this uncertainty.
Ernst & Young, LLP
Houston, Texas
April 8, 2003, except for Note 4,
as to which the date is April 15, 2003
-35-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share data)
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2001
----------- ----------- -----------
REVENUES:
Oil and natural gas $ 137,124 $ 106,992 $ 176,646
Interest and other 355 478 1,414
----------- ----------- -----------
137,479 107,470 178,060
----------- ----------- -----------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 11,260 11,935 16,625
Severance and ad valorem taxes 7,608 8,235 11,761
Depletion and depreciation 75,441 60,972 67,450
General and administrative 11,610 11,820 13,506
Accretion expense 667 ----- -----
Issuance of stock grants ----- ----- 5,566
Impairment of long-lived assets ----- 69,124 6,580
----------- ----------- -----------
106,586 162,086 121,488
----------- ----------- -----------
EARNINGS (LOSS) BEFORE INTEREST & INCOME TAXES 30,893 (54,616) 56,572
----------- ----------- -----------
OTHER EXPENSES:
Interest expense 11,496 13,928 20,092
Credit facility retirement costs ----- 1,202 -----
----------- ----------- -----------
EARNINGS (LOSS) BEFORE INCOME TAXES 19,397 (69,746) 36,480
----------- ----------- -----------
INCOME TAXES:
Current (731) 298 (300)
Deferred 4,980 (22,300) 13,800
----------- ----------- -----------
4,249 (22,002) 13,500
----------- ----------- -----------
EARNINGS (LOSS) BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 15,148 (47,744) 22,980
Cumulative effect of change in accounting principle (1,309) ----- -----
----------- ----------- -----------
NET EARNINGS (LOSS) 13,839 (47,744) 22,980
Dividends on preferred stock 6,593 4,268 429
----------- ----------- -----------
NET EARNINGS (LOSS) APPLICABLE
TO COMMON STOCKHOLDERS $ 7,246 $ (52,012) $ 22,551
=========== =========== ===========
NET EARNINGS (LOSS) PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE:
Basic $ 0.16 $ (1.05) $ 0.47
Diluted $ 0.15 $ (1.05) $ 0.43
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE PER SHARE:
Basic and Diluted $ (0.02) $ ----- $ -----
----------- ----------- -----------
NET EARNINGS (LOSS) PER SHARE:
Basic $ 0.14 $ (1.05) $ 0.47
=========== =========== ===========
Diluted $ 0.13 $ (1.05) $ 0.43
=========== =========== ===========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 53,325 49,763 48,350
Diluted 57,144 49,763 55,842
See notes to consolidated financial statements.
-36-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
DECEMBER 31,
------------
2003 2002
---- ----
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 12,821 $ 7,287
Accounts receivable, less allowance for doubtful accounts
$251 [2003] and $833 [2002] 24,703 24,167
Due from affiliates 349 1,557
Prepaid expenses and other 1,586 2,221
Assets from price risk management activities 584 604
------------ ------------
Total current assets 40,043 35,836
------------ ------------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$30,542 [2003] and $18,993 [2002] not
subject to depletion) 1,230,643 1,162,436
Land 478 478
Equipment 9,931 9,913
------------ ------------
1,241,052 1,172,827
Less accumulated depletion and depreciation 836,368 761,854
------------ ------------
Total property and equipment, net 404,684 410,973
------------ ------------
OTHER ASSETS:
Assets from price risk management activities ----- 292
Deferred tax asset ----- 2,560
Other 4,022 6,579
------------ ------------
Total other assets 4,022 9,431
------------ ------------
Total assets $ 448,749 $ 456,240
============ ============
See notes to consolidated financial statements.
-37-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
DECEMBER 31,
------------
2003 2002
---- ----
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 8,692 $ 16,842
Revenues and royalties payable 13,087 12,378
Notes payable 194 831
Accrued liabilities 12,074 9,958
Liabilities from price risk management activities 9,768 6,781
Abandonment costs 953 -----
Current income taxes payable 415 931
Current portion long-term debt 10,000 35,250
----------- -----------
Total current liabilities 55,183 82,971
----------- -----------
LONG-TERM DEBT 122,320 148,500
----------- -----------
9 1/2% CONVERTIBLE SUBORDINATED NOTES 20,000 20,000
----------- -----------
OTHER:
Liabilities from price risk management activities 2,385 1,686
Abandonment costs 3,149 -----
Deferred income taxes 931 -----
----------- -----------
6,465 1,686
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES 6, 7 AND 11) ----- -----
----------- -----------
REDEEMABLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000) shares authorized,
604,460 [2003] and 696,900 [2002] shares of Series C
Redeemable Convertible Preferred Stock issued at stated value) 60,446 69,690
----------- -----------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
61,724,597 [2003] and 53,868,343 [2002] issued) 644 557
Additional paid-in capital 394,177 378,215
Accumulated deficit (202,492) (209,738)
Accumulated other comprehensive loss (7,704) (4,938)
Unamortized deferred compensation (290) (356)
----------- -----------
184,335 163,740
Less treasury stock, at cost 3,779,225 [2002] shares ----- 30,347
----------- -----------
Total stockholders' equity 184,335 133,393
----------- -----------
Total liabilities and stockholders' equity $ 448,749 $ 456,240
=========== ===========
See notes to consolidated financial statements.
-38-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2001
---- ---- ----
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 13,839 $ (47,744) $ 22,980
Adjustments to reconcile net earnings (loss) to net
cash provided by operating activities:
Cumulative effect of change in accounting principle 1,309 ----- -----
Depletion and depreciation 75,441 60,972 67,450
Amortization of other assets 1,715 2,057 2,070
Non-cash compensation 1,330 1,630 7,605
Credit facility retirement costs ----- 1,202 -----
Accretion expense 667 ----- -----
Impairment of long-lived assets ----- 69,124 6,580
Deferred income taxes 4,980 (22,300) 13,800
Changes in assets and liabilities:
Accounts receivable (536) (58) 11,964
Due from affiliates 1,208 (713) (1,600)
Prepaid expenses and other 635 (396) (722)
Accounts payable (8,150) (19,110) 18,119
Revenues and royalties payable 709 2,582 8,343
Accrued liabilities and other (1,525) (4,723) (3,102)
---------- ---------- ----------
Net cash provided by operating activities 91,622 42,523 153,487
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (71,920) (76,842) (134,125)
Sale of property and equipment 4,893 (272) 30,624
---------- ---------- ----------
Net cash used in investing activities (67,027) (77,114) (103,501)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redeemable preferred stock ----- 66,850 -----
Proceeds from long-term debt ----- 165,000 -----
Reductions in long-term debt (51,430) (196,250) (40,000)
Proceeds - Notes payable 1,888 1,592 28,018
Reductions - Notes payable (2,525) (1,524) (2,638)
Repurchase of stock ----- ----- (114,000)
Issuance of stock/exercise of stock options 33,185 307 1,740
Preferred dividends ----- (1,102) (3,129)
Additions to deferred loan costs (179) (7,335) (759)
---------- ---------- ----------
Net cash provided by (used in) financing activities (19,061) 27,538 (130,768)
---------- ---------- ----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 5,534 (7,053) (80,782)
Cash and cash equivalents at beginning of year 7,287 14,340 95,122
---------- ---------- ----------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 12,821 $ 7,287 $ 14,340
========== ========== ==========
See notes to consolidated financial statements.
-39-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2001, 2002 AND 2003 (in thousands)
Accumulated
Preferred Stock Common Stock Additional Accumulated Other
------------------- ------------------ Paid-In Earnings Comprehensive
Shares Par Value Shares Par Value Capital (Deficit) Loss
------ --------- ------ --------- ---------- ---------- ----
Balance, December 31, 2000 3,983 $ 135,000 53,763 $ 550 $315,603 $ (180,277) $ (185)
Issuance of rights to common stock (3,983) (135,000) (6,000) ----- 69,180 ----- -----
Company's 401(k) plan contribution ----- ----- ----- 2 1,666 ----- -----
Issuance of shares as compensation ----- ----- 79 ----- (275) ----- -----
Exercise of stock options ----- ----- 4 ----- 34 ----- -----
Compensation expense ----- ----- 128 1 317 ----- -----
Shares issued to SLOPI ----- ----- ----- ----- ----- ----- -----
Issuance of shares from stock ----- ----- ----- ----- 6,755 ----- -----
offering
Preferred dividends ----- ----- ----- ----- ----- (429) -----
Net earnings ----- ----- ----- ----- ----- 22,980 -----
------ --------- ------ --------- -------- ---------- -------------
Balance, December 31, 2001 ----- ----- 47,974 553 393,280 (157,726) (185)
Issuance of rights to common stock ----- ----- ----- 4 1,596 ----- -----
Company's 401(k) plan contribution ----- ----- 172 ----- (1,075) ----- -----
Issuance of shares as compensation ----- ----- 1,941 ----- (15,586) ----- -----
Fractional share adjustments ----- ----- 2 ----- ----- ----- -----
Compensation expense ----- ----- ----- ----- ----- ----- -----
Accum. other comprehensive
loss, net of taxes of $2,560 ----- ----- ----- ----- ----- ----- (4,753)
Preferred dividends ----- ----- ----- ----- ----- (4,268) -----
Net earnings ----- ----- ----- ----- ----- (47,744) -----
------ --------- ------ --------- -------- ---------- -------------
Balance, December 31, 2002 ----- ----- 50,089 557 378,215 (209,738) (4,938)
Issuance of rights to common stock ----- ----- ----- 8 1,256 ----- -----
Company's 401(k) plan contribution ----- ----- 109 ----- (498) ----- -----
Exercise of stock options ----- ----- 80 1 78 ----- -----
Compensation expense ----- ----- ----- ----- ----- ----- -----
Issuance of shares from stock ----- ----- 8,704 50 3,456 ----- -----
offering
Accum. other comprehensive loss ----- ----- ----- ----- ----- ----- (2,766)
Issuance for conversion of pref stock ----- ----- 2,743 28 11,670 ----- -----
Preferred dividends ----- ----- ----- ----- ----- (6,593) -----
Net earnings ----- ----- ----- ----- ----- 13,839 -----
------ --------- ------ --------- -------- ---------- -------------
Balance, December 31, 2003 ----- $ ----- 61,725 $ 644 $394,177 $ (202,492) $ (7,704)
====== ========= ====== ========= ======== ========== =============
Unamortized Treasury Stock
Deferred -----------------
Compensation Shares Cost Total
------------ ------ ---- -----
Balance, December 31, 2000 $ (369) ----- $ ----- $ 270,322
Issuance of rights to common stock ----- 6,000 (48,180) (114,000)
Company's 401(k) plan contribution (1,668) ----- ----- -----
Issuance of shares as compensation ----- (79) 629 354
Exercise of stock options ----- ----- ----- 34
Compensation expense ----- (29) 236 554
Shares issued to SLOPI 1,651 ----- ----- 1,651
Issuance of shares from stock ----- ----- ----- 6,755
offering
Preferred dividends ----- ----- ----- (429)
Net earnings ----- ----- ----- 22,980
------ ------ ------- -------
Balance, December 31, 2001 (386) 5,892 (47,315) 188,221
Issuance of rights to common stock (1,600) ----- ----- -----
Company's 401(k) plan contribution ----- (172) 1,382 307
Issuance of shares as compensation ----- (1,941) 15,586 -----
Fractional share adjustments ----- ----- ----- -----
Compensation expense 1,630 ----- ----- 1,630
Accum. other comprehensive
loss, net of taxes of $2,560 ----- ----- ----- (4,753)
------ ------ ------- -------
Preferred dividends ----- ----- ----- (4,268)
Net earnings ----- ----- ----- (47,744)
------ ------ ------- -------
Balance, December 31, 2002 (356) 3,779 (30,347) 133,393
Issuance of rights to common stock (1,264) ----- ----- -----
Company's 401(k) plan contribution ----- (93) 747 249
Exercise of stock options ----- (22) 177 256
Compensation expense 1,330 ----- ----- 1,330
Issuance of shares from stock ----- (3,664) 29,423 32,929
offering
Accum. other comprehensive loss ----- ----- ----- (2,766)
Issuance for conversion of pref stock ----- ----- ----- 11,698
Preferred dividends ----- ----- ----- (6,593)
Net earnings ----- ----- ----- 13,839
------ ------ ------- -------
Balance, December 31, 2003 (290) ----- $ ----- $ 184,335
====== ====== ======= =======
See notes to consolidated financial statements.
-40-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2001
---- ---- ----
Net earnings (loss) applicable to common stockholders $ 7,246 $ (52,012) $ 22,551
---------- ---------- ----------
Other comprehensive income (loss), net of tax,
for unrealized losses from hedging activities:
Unrealized holding losses arising during period (12,461) (5,522) -----
Reclassification adjustments on settlement of
commodity hedge contracts 9,695 769 -----
---------- ---------- ----------
(2,766) (4,753) -----
---------- ---------- ----------
Total comprehensive income (loss) $ 4,480 $ (56,765) $ 22,551
========== ========== ==========
See notes to consolidated financial statements.
-41-
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 Texas corporation.
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 in 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, reduced by the asset retirement obligation, 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 as adjusted for the
Company's cash flow hedge positions, plus the lower of cost or estimated fair
market value of unproved properties adjusted for related income tax effects.
Capitalized costs of proved oil and natural gas properties are depleted on a
unit of production method using proved oil and natural gas reserves. Costs
depleted include net capitalized costs subject to depletion and estimated future
dismantlement, restoration, and abandonment costs. Estimated future abandonment,
dismantlement and site restoration costs include costs to dismantle, relocate
and dispose of the Company's offshore production platforms, gathering systems,
wells and related structures, considering related salvage values.
Equipment, which includes computer equipment, hardware and software, furniture
and fixtures, leasehold improvements and automobiles, is recorded at cost and is
generally depreciated on a straight-line basis over the estimated useful lives
of the assets, which range in periods of three to seven years.
Repairs and maintenance are charged to expense as incurred.
-42-
STATEMENT OF CASH FLOWS
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 $9.6 million, $11.7 million and $21.5 million in 2003, 2002 and
2001, respectively. Cash payments for income taxes (federal and state, net of
receipts) were $23,000 for 2003, none for 2002, and $2.27 million for 2001.
CONCENTRATIONS OF CREDIT RISK
Substantially all of the Company's receivables are due from oil and natural gas
purchasers and other oil and natural gas producing companies located in the
United States. Accounts receivable are generally not collateralized.
Historically, credit losses incurred on receivables of the Company have not been
significant.
REVENUE RECOGNITION
Meridian recognizes oil and natural gas revenue from its interests in producing
wells as oil and natural gas is produced and sold from those wells (the sales
method). Oil and natural gas sold is not significantly different from the
Company's share of production.
EARNINGS PER SHARE
Basic earnings per share amounts are calculated based on the weighted average
number of shares of Common Stock outstanding during each period. Diluted
earnings per share is based on the weighted average number of shares of Common
Stock outstanding for the periods, including the dilutive effects of stock
options, warrants granted and convertible debt. Dilutive options and warrants
that are issued during a period or that expire or are canceled during a period
are reflected in the computations for the time they were outstanding during the
periods being reported. Options where the exercise price of the options exceeds
the average price for the period are considered antidilutive, and therefore are
not included in the calculation of dilutive shares.
STOCK OPTIONS
As permitted by SFAS No. 123, "Accounting for Stock Based Compensation," the
Company will continue to follow the existing accounting requirements for stock
options and stock-based awards contained in Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees," and related Interpretations
and consensus of the Emerging Issues Task Force in terms of measuring
compensation expense.
SFAS 123, "Accounting for Stock-Based Compensation," as amended by SFAS 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure,"
established accounting and disclosure requirements using a fair value-based
method of accounting for stock-based employee compensation plans. As provided
for under SFAS 123, there has been no amount of compensation expense recognized
for the Company's stock option plans. The Company accounts for stock-based
compensation using the intrinsic value method prescribed in Accounting
Principles Board Opinion 25, "Accounting for Stock Issued to Employees."
Compensation expense is recorded for restricted stock awards over the requisite
vesting periods based upon the market value on the date of the grant. No
stock-based compensation expense was recorded in the years ended December 31,
2003, 2002 or 2001.
The following is a reconciliation of reported earnings (loss) and earnings
(loss) per share as if the Company used the fair value method of accounting for
stock-based compensation. Fair value is calculated using the Black-Scholes
option-pricing model.
-43-
2003 2002 2001
---- ---- ----
Net earnings (loss) applicable to common stockholders
as reported $ 7,246 $ (52,012) $ 22,551
Stock-based compensation (expense) benefit determined
under fair value method for all awards, net of tax 63 (39) (1,035)
--------- ----------- ----------
Net earnings (loss) applicable to common stockholders
pro forma $ 7,309 $ (52,051) $ 21,516
========= =========== ==========
Basic earnings (loss) per share:
As reported $ 0.14 $ (1.05) $ 0.47
Pro forma $ 0.14 $ (1.05) $ 0.45
Diluted earnings (loss) per share:
As reported $ 0.13 $ (1.05) $ 0.43
Pro forma $ 0.13 $ (1.05) $ 0.42
Fair value was estimated at the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions: risk-free
interest rate of 2.87%, 2.54% and 4.7%; dividend yield of 0%; volatility factors
of the expected market price of the Company's Common Stock of 1.02, 0.81 and
0.82 for 2003, 2002 and 2001, respectively; and a weighted-average expected life
of five years. These assumptions resulted in a weighted average grant date fair
value of $3.44, $1.97 and $4.08 for options granted in 2003, 2002 and 2001,
respectively. For purposes of the pro forma disclosures, the estimated fair
value is amortized to expense over the awards' vesting period.
The Black-Scholes option valuation model was developed for use in estimating the
fair value of traded options which have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions including the expected stock price volatility. Because
the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its employee stock options. Pro forma compensation
cost reflected above may not be representative of the cost to be expected in
future years.
FAIR VALUE OF FINANCIAL INSTRUMENTS.
Our financial instruments consist of cash and cash equivalents, accounts
receivable, accounts payable, bank borrowings and subordinated notes. The
carrying amounts of cash and cash equivalents, accounts receivable and accounts
payable approximate fair value due to the highly liquid nature of these
short-term instruments. The fair values of the bank borrowings approximate the
carrying amounts as of December 31, 2003 and 2002, and were determined based
upon variable interest rates currently available to us for borrowings with
similar terms. Based on quoted market prices as of the respective dates, the
fair values of our subordinated notes due 2005 were $19.6 million and $18.9
million at December 31, 2003 and 2002, respectively. The carrying value of our
subordinated notes was $20 million at December 31, 2003 and 2002.
DERIVATIVE FINANCIAL INSTRUMENTS
In June 1998 the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Certain Hedging Activities. In June 2000 the FASB issued SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activity, an Amendment of SFAS 133. SFAS No. 133 and SFAS No. 138 require that
all derivative instruments be recorded on the balance sheet at their respective
fair values. SFAS No. 133 and SFAS No. 138 are effective for all fiscal quarters
of all fiscal years beginning after June 30, 2000; the Company adopted
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SFAS No. 133 and SFAS No. 138 on January 1, 2001.
The Company enters into swaps, options, collars and other derivative contracts
to hedge the price risks associated with a portion of anticipated future oil and
gas production. The Company's derivative financial instruments have not been
entered into for trading purposes and the Company has the ability and intent to
hold these instruments to maturity. Counterparties to the Company's interest
rate swap agreements are major financial institutions.
All derivatives are recognized on the balance sheet at their fair value. On the
date the derivative contract is entered into, the Company designates the
derivative as either a hedge of the fair value of a recognized asset or
liability or of an unrecognized firm commitment ("fair value" hedge) or a hedge
of a forecasted transaction or the variability of cash flows to be received or
paid related to a recognized asset or liability ("cash flow" hedge). The Company
formally documents all relationships between hedging instruments and hedged
items, as well as its risk management objective and strategy for undertaking
various hedge transactions. This process includes linking all derivatives that
are designated as fair-value or cash-flow hedges to specific assets and
liabilities on the balance sheet or to specific firm commitments or forecasted
transactions. The Company also formally assesses, both at the hedge's inception
and on an ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair values or cash
flows of hedged items.
Changes in the fair value of a derivative that is highly effective and that is
designated and qualifies as a cash-flow hedge are recorded in other
comprehensive income, until earnings are affected by the variability in cash
flows of the designated hedged item. The Company recognized minimal losses
related to hedge ineffectiveness during the three years ended December 31, 2003.
The Company discontinues cash flow hedge accounting prospectively when it is
determined that the derivative is no longer effective in offsetting changes in
the fair value or cash flows of the hedged item, the derivative expires or is
sold, terminated, or exercised, the derivative is redesignated as a hedging
instrument because it is unlikely that a forecasted transaction will occur, or
management determines that designation of the derivative as a hedging instrument
is no longer appropriate.
When cash flow hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the Company continues to carry the
derivative on the balance sheet at its fair value with subsequent changes in
fair value included in earnings, and gains and losses that were accumulated in
other comprehensive income are recognized immediately in earnings. In all other
situations in which hedge accounting is discontinued, the Company continues to
carry the derivative at its fair value on the balance sheet and recognizes any
subsequent changes in its fair value in earnings. Gains or losses accumulated in
other comprehensive income at the time the hedge relationship is terminated are
recorded in earnings over the original life of the derivative instrument.
EARLY ADOPTION OF FAS NO. 145
On July 1, 2002, we adopted the provisions of Statement of Financial Accounting
Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" ("SFAS No. 145"). The
applicable portion of this Statement rescinds Statement of Financial Accounting
Standards No. 4 "Reporting Gains and Losses from Extinguishment of Debt" which
required all gains and losses from extinguishment of debt to be aggregated and,
when material, classified as an extraordinary item, net of related income tax
effect. Consistent with SFAS No. 145, the $1.2 million in unamortized debt costs
associated with the termination of the Company's revolving credit agreement in
August 2002 were recognized as credit facility retirement costs in the
Consolidated Statement of Operations. SFAS No. 145 also amends Statement of
Financial Accounting Standards No. 13 "Accounting for Leases" ("SFAS No. 13") to
require that certain lease modifications having economic effects similar to
sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. This portion of SFAS No. 145 did not have any
effect on our financial position or results of operations for any periods
presented.
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NEW ACCOUNTING PRONOUNCEMENTS
A reporting issue has arisen regarding the application of certain provisions of
SFAS No. 142 "Goodwill and Other Intangible Assets" to companies in the
extractive industries, including oil and gas companies. The issue is whether
SFAS No. 142 requires registrants to classify the costs of mineral rights held
under lease or other contractual arrangements associated with extracting oil and
gas as intangible assets in the balance sheet, apart from other capitalized oil
and gas property costs, and provide specific footnote disclosures. Historically,
the Company has included the costs of such mineral rights associated with
extracting oil and gas as a component of oil and gas properties. If it is
ultimately determined that SFAS No. 142 requires oil and gas companies to
classify costs of mineral rights held under lease or other contractual
arrangement associated with extracting oil and gas as a separate intangible
assets line item on the balance sheet, the Company would be required to
reclassify approximately $16.5 million at December 31, 2003, and $15.8 million
at December 31, 2002, respectively, out of oil and gas properties and into a
separate intangible assets line item. The Company's cash flows and results of
operations would not be affected since such intangible assets would continue to
be depleted and assessed for impairment in accordance with full cost accounting
rules. Further, the Company does not believe the classification of the costs of
mineral rights associated with extracting oil and gas as intangible assets would
have any impact on the Company's compliance with covenants under its debt
agreements.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires the fair value of a liability for an asset
retirement obligation to be recognized in the period in which it is incurred if
a reasonable estimate of fair value can be made. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
SFAS No. 143 was effective for the Company on January 1, 2003. See Note 3. for
discussion of the impact on the Company's consolidated financial statements.
During December 2003, the FASB issued Interpretation No. 46R, "Consolidation of
Variable Interest Entities" ("FIN 46"), which requires the consolidation of
certain entities that are determined to be variable interest entities ("VIE's").
An entity is considered to be a VIE when either (i) the entity lacks sufficient
equity to carry on its principal operations, (ii) the equity owners of the
entity cannot make decisions about the entity's activities or (iii) the entity's
equity neither absorbs losses or benefits from gains. Meridian owns no interests
in variable interest entities, and therefore this new interpretation has not
affected the Company's consolidated financial statements.
In May 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under FASB Statement No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. The adoption of this statement did
not have a material effect on the Company's financial statements.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150
establishes the standards on how companies classify and measure certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that the Company classify as liabilities the fair value of
all mandatorily redeemable financial instruments that had previously been
recorded as equity or elsewhere in the consolidated financial statements. This
statement is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise effective for all existing financial instruments
beginning in the third quarter of 2003. We do not believe that this statement
will have any impact on the Company's consolidated financial statements.
USE OF ESTIMATES
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The preparation of financial statements in accordance with accounting principles
generally accepted in the United States of America requires the Company to make
estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses, and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements. The Company analyzes its
estimates, including those related to oil and gas revenues, bad debts, oil and
gas properties, income taxes and contingencies and litigation. The Company bases
its estimates on historical experience and various other assumptions that are
believed to be reasonable under the circumstances. Actual results may differ
from these estimates under different assumptions or conditions.
RECLASSIFICATION OF PRIOR PERIOD STATEMENTS
Certain minor reclassifications have been made to the prior period financial
statements to conform to current year presentation.
3. ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset
Retirement Obligations." This statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement
obligations of tangible long-lived assets in the period in which it is incurred.
The fair value of asset retirement obligation liabilities has been calculated
using an expected present value technique. Fair value, to the extent possible,
should include a market risk premium for unforeseeable circumstances. No market
risk premium was included in the Company's asset retirement obligations fair
value estimate since a reasonable estimate could not be made. When the liability
is initially recorded, the entity increases the carrying amount of the related
long-lived asset. Over time, accretion of the liability is recognized each
period, and the capitalized cost is amortized over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement.
This standard requires the Company to record a liability for the fair value of
the dismantlement and abandonment costs, excluding salvage values.
Upon adoption, the Company recorded transition amounts for liabilities related
to its wells, and the associated costs to be capitalized. A liability of $4.5
million was recorded to long-term liabilities and a net asset of $3.2 million
was recorded to oil and natural gas properties on January 1, 2003. This resulted
in a cumulative effect of an accounting change of ($1.3) million. Accretion
expenses subsequent to the adoption of this accounting statement decreased net
earnings $667 thousand in 2003.
The pro forma effects of the application of SFAS 143, as if the statement had
been adopted on January 1, 2001, is presented below (thousands of dollars except
per share information):
2003 2002 2001
---- ---- ----
Net earnings (loss) applicable to
common stockholders $ 7,246 $ (52,012) $ 22,551
Additional accretion expense -- (470) (414)
Cumulative effect of accounting change 1,309 -- --
---------- ---------- ----------
Pro forma net earnings (loss) $ 8,555 $ (52,482) $ 22,137
Pro forma earnings (loss) per share:
Basic $ 0.16 $ (1.05) $ 0.46
Diluted $ 0.15 $ (1.05) $ 0.42
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The following table describes the change in the Company's asset retirement
obligations for the year ended December 31, 2003, and the pro forma amounts for
the year ended December 31, 2002 (thousands of dollars):
Asset retirement obligation at January 1, 2002 $ 4,053
Accretion expense for 2002 470
---------
Asset retirement obligation at December 31, 2002 4,523
Additional retirement obligations recorded in 2003 338
Reduction due to property sale in 2003 (1,010)
Other revisions during 2003 (416)
Accretion expense for 2003 667
---------
Asset retirement obligation at December 31, 2003 $ 4,102
=========
4. IMPAIRMENT OF LONG-LIVED ASSETS
In the third quarter of 2002, a negative revision in oil and natural gas proved
undeveloped reserves associated with an unsuccessful well drilled in the Kent
Bayou Field resulted in a full cost ceiling write-down of oil and natural gas
properties totaling $69.1 million.
A decline in oil and natural gas prices during 2001 resulted in the Company
recognizing a full cost ceiling write-down totaling $6.6 million of its oil and
natural gas properties.
Due to the potential volatility in oil and gas prices and their effect on the
carrying value of the Company's proved oil and gas reserves, there can be no
assurance that future write-downs will not be required as a result of factors
that may negatively affect the present value of proved oil and natural gas
reserves and the carrying value of oil and natural gas properties, including
volatile oil and natural gas prices, downward revisions in estimated proved oil
and natural gas reserve quantities and unsuccessful drilling activities.
5. DEBT
REVOLVING CREDIT AGREEMENT
During August 2002, the Company replaced its Chase Manhattan Bank Credit
Facility with a new three-year $175 million underwritten senior secured credit
agreement (the "Credit Agreement") with Societe Generale as administrative
agent, lead arranger and book runner, and Fortis Capital Corporation, as co-lead
arranger and documentation agent. Borrowings under the Credit Agreement mature
on August 13, 2005. The borrowing base is currently set at $130.0 million and is
scheduled to be redetermined and be effective on April 30, 2004. Credit Facility
payments of $42.7 million were made during 2003, bringing the outstanding
balance to $122.3 million as of December 31, 2003. During 2004, the Company has
made $3.3 million in debt repayments and anticipates that it will continue to
make debt repayments during the remainder of the year.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders or borrower, under the Credit Agreement, have the right to redetermine
the borrowing base at any time, once during each calendar year. Borrowings under
the Credit Agreement are secured by pledges of outstanding capital stock of the
Company's subsidiaries and a mortgage on the Company's oil and natural gas
properties of at least 90% of its present value of proved properties. The Credit
Agreement contains various restrictive covenants, including, among other items,
maintenance of certain financial ratios and restrictions on cash dividends on
Common Stock and under certain circumstances Preferred Stock, and an unqualified
audit report on the Company's consolidated financial statements beginning with
those as of and for the year ended December 31, 2002. The auditor's report on
the 2002 consolidated financial statements contained a "going concern"
modification. The Company obtained a waiver of the related covenant that would
have triggered a violation of the loan agreement. The Company is in compliance
with the financial covenants under this agreement.
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Under the Credit Agreement, the Company may secure either (i) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate, plus an additional 0.5% to 1.5% depending
on the ratio of the aggregate outstanding loans and letters of credit to the
borrowing base or a federal funds-based rate plus 1/2 of 1% or; (ii) a
Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At December 31, 2003, the three-month LIBOR interest rate
was 1.15188%. The Credit Agreement also provides for commitment fees ranging
from 0.375% to 0.5% per annum.
SUBORDINATED CREDIT AGREEMENT
The Company extended and amended a short-term subordinated credit agreement with
Fortis Capital Corporation for $25 million on April 5, 2002, with a maturity
date of December 31, 2004. The notes are unsecured and contain customary events
of default, but do not contain any maintenance or other restrictive covenants.
The interest rate is the London interbank offered rate ("LIBOR") plus 4.5%
through December 31, 2002, LIBOR plus 5.5% from January 1, 2003, through August
31, 2003, and LIBOR plus 6.5% from September 1, 2003, through December 31, 2004.
At December 31, 2003, the three-month LIBOR interest rate was 1.15188%. A note
payment of $5 million is due on April 30, 2004, with the remaining $5 million
payable on December 31, 2004. Note payments totaling $6.25 million were paid in
2002, with an additional $8.75 million being paid in 2003. The outstanding
balance is $10.0 million as of December 31, 2003. The Company is in compliance
with the financial covenants under this agreement.
9 1/2% CONVERTIBLE SUBORDINATED NOTES
During June 1999, the Company completed private placements of an aggregate of
$20 million of its 9 1/2% Convertible Subordinated Notes due June 18, 2005. The
Notes are unsecured and contain customary events of default, but do not contain
any maintenance or other restrictive covenants. Interest is payable on a
quarterly basis. The Company is in compliance with the financial covenants under
this agreement.
During March 2002, the Company and the holders of the Notes amended the
conversion price from $7.00 to $5.00 per share. The Notes are convertible at any
time by the holders of the Notes into shares of the Company's Common Stock,
$0.01 par value, utilizing the conversion price. The conversion price is subject
to customary anti-dilution provisions. The holders of the Notes have been
granted registration rights with respect to the shares of Common Stock that
would be issued upon conversion of the Notes.
Scheduled debt maturities for the next five years and thereafter, as of December
31, 2003, are as follows: $10.0 million in 2004, $142.3 million in 2005, and
none thereafter.
6. LEASE OBLIGATIONS
The Company has a seven-year operating lease for office space with a primary
term expiring in September 2006. The Company also has operating leases for
equipment with various terms, none exceeding three years. Rental expense
amounted to approximately $2.3 million, $2.2 million and $2.1 million in 2003,
2002 and 2001, respectively. Future minimum lease payments under all
non-cancelable operating leases having initial terms of one year or more are
$1.6 million for each of the years 2004 and 2005, $1.2 million for the year
2006, and none thereafter.
7. COMMITMENTS AND CONTINGENCIES
LITIGATION
PETROQUEST LITIGATION. In December 1999, PetroQuest Energy, Inc. (formerly known
as Optima Energy (U.S.) Corporation) ("PetroQuest") sued Meridian for damages
"estimate[d] to exceed several million dollars" for
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Meridian's alleged gross negligence and willful misconduct under certain
agreements concerning certain wells and property in the S.W. Holmwood and E.
Lake Charles Prospects in Calcasieu Parish and for alleged wrongful withholding
of funds totaling $886,153.31, as a result of Meridian's satisfying a prior
adverse judgment in favor of Amoco Production Company. Meridian filed an answer
denying PetroQuest's claims and asserted a counterclaim for attorney's fees,
court costs and other expenses and for declaratory relief that Meridian is
entitled to retain the amounts (with all interest thereon) that it had suspended
from disbursement to PetroQuest. In December 2003, the parties settled. Under
their confidential settlement agreement, Meridian was required to make two
payments, which have now been made. The settlement amount was fully reflected in
the financial statements at December 31, 2003. Judgments of dismissal were
signed in January 2004.
RAMOS TITLE LITIGATION. Three different groups have asserted adverse title
claims to some or all of Section 80 within Meridian's "Thibodaux units" in the
Ramos Field. Another entity has asserted adverse title claims to a portion of
Section 36 within these same units. These claims turn primarily on the location
of the parish boundary between Terrebonne and Assumption Parishes and/or the
validity of various tax sales. Meridian's gas purchaser, Louisiana Intrastate
Gas Company LLC ("LIG"), has deposited into the Terrebonne Parish court registry
certain gas and plant-product proceeds attributable to 25 acres within these
units since October 2000, and Meridian has been suspending all remaining
proceeds attributable to these same 25 acres since December 2000. Meridian has
entered into a settlement discussion, but it has not yet reached an agreement
with the various parties. A trial has been set for March 16, 2004, in Assumption
Parish.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in four similar lawsuits concerning the Weeks
Island, Gibson, Bayou Pigeon and Napoleonville Fields. The lawsuits seek
injunctive relief and other relief, including unspecified amounts in both actual
and punitive damages for alleged breaches of mineral leases and alleged failure
to restore the plaintiffs' lands from alleged contamination and otherwise from
the defendants' oil and gas operations.
There are no other material legal proceedings to which Meridian or any of its
subsidiaries 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.
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8. TAXES ON INCOME
Provisions (benefits) for federal and state income taxes are as follows
(thousands of dollars):
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2001
---------- ---------- ----------
Current:
Federal $ (568) $ 327 $ 77
State (163) (29) (377)
Deferred:
Federal 4,980 (22,300) 13,800
---------- ---------- ----------
$ 4,249 $ (22,002) $ 13,500
========== ========== ==========
Income tax expense as reported is reconciled to the federal statutory rate (35%)
as follows (thousands of dollars):
YEAR ENDED DECEMBER 31,
--------------------------------------------
2003 2002 2001
---------- ---------- ----------
Income tax provision (benefit) computed at statutory rate $ 6,331 $ (24,525) $ 12,768
Nondeductible costs 758 308 977
State income tax, net of federal tax benefit (106) (19) (245)
Change in valuation allowance (2,734) 2,234 --
---------- ---------- ----------
$ 4,249 $ (22,002) $ 13,500
========== ========== ==========
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,
------------
2003 2002
---- ----
Deferred tax assets:
Net operating tax loss carryforward $ 39,208 $ 54,521
Statutory depletion carryforward 950 950
Tax credits 1,083 1,651
Unrealized hedge loss 4,049 2,560
Other 4,631 4,110
Valuation allowance -0- (2,734)
---------- ----------
Total deferred tax assets 49,921 61,058
---------- ----------
Deferred tax liabilities:
Book in excess of tax basis in oil and gas properties 50,782 58,428
Basis differential in long-term investments 70 70
---------- ----------
Total deferred tax liabilities 50,852 58,498
---------- ----------
Net deferred tax asset (liability) $ (931) $ 2,560
========== ==========
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As of December 31, 2003, the Company has approximately $112.0 million of tax net
operating loss carryforwards. The net operating loss carryforwards assume that
certain items, primarily intangible drilling costs, have been deducted to the
maximum extent allowed under the tax laws for the current year. However, the
Company has not made a final determination if an election will be made to
capitalize all or part of these items for tax purposes.
The net operating loss carryforwards begin to expire in 2004 and extend through
2020. A portion of the net operating loss carryforwards are subject to change in
ownership and separate return limitations that could restrict the Company's
ability to utilize such losses in the future.
Accounting policy requires a valuation allowance to be recognized if, based on
the weight of available evidence, it is more likely than not that some portion
or all of the deferred tax asset will not be realized. The Company expects to
fully utilize its net operating loss carryforward tax benefits, and therefore
did not record a valuation allowance in 2003.
9. 8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK
A private placement of $66.85 million of 8.5% redeemable convertible preferred
stock was completed during May 2002. The preferred stock is convertible into
shares of the Company's Common Stock at a conversion price of $4.45 per share.
Dividends are payable semi-annually in cash or additional preferred stock. At
the option of the Company, one-third of the preferred shares can be forced to
convert to Common Stock if the closing price of the Company's Common Stock
exceeds 150% of the conversion price for 30 out of 40 consecutive trading days
on the New York Stock Exchange. If the above conversion criteria occurs, the
Company can elect to convert up to one-third of the original issue provided that
the conversion occurs no sooner than twelve months from the most recent
conversion. The preferred stock is subject to redemption at the option of the
Company after March 2005, and mandatory redemption on March 31, 2009. The
holders of the preferred stock have been granted registration rights with
respect to the shares of Common Stock issued upon conversion of the preferred
stock. In the last quarter of 2003, $12.2 million of preferred stock was
converted into 2.7 million shares of Common Stock. In additional, $3.6 million
of preferred stock was converted into 0.8 million shares of Common Stock during
January and February 2004.
During 2003, dividends of $6.0 million were accumulated (net of $0.6 million of
deferred preferred stock offering costs amortized during 2003), of which $3.0
million was satisfied with the issuance of additional shares of redeemable
preferred stock and $3.0 million was paid in cash in January 2004. Dividends of
$3.9 million were accumulated during 2002, of which $1.1 million was paid in
cash and $2.84 million was satisfied with the issuance of additional shares of
redeemable preferred stock.
10. STOCKHOLDERS' EQUITY
COMMON STOCK
On September 29, 2000, the Company announced that it sold to certain investors
an aggregate of 6,021,500 shares of Common Stock at a price of $6 5/8 per share
under the terms of the prospectus supplement dated September 28, 2000. The
shares were placed with certain investors on a best-efforts basis. In connection
with the placement of the shares, the Company paid the placement agents a total
fee of approximately $1.2 million, resulting in proceeds of approximately $38.7
million to the Company. The Company used the proceeds from this sale to fund in
part the exercise of the option to repurchase Preferred and Common Stock from
Shell for $114 million on January 29, 2001.
In August 2003, the Company completed a private offering of 8,703,537 shares of
common stock at a price of $3.87 per share. The total proceeds of the offering,
net of issuance costs, received by the Company were approximately $33.0 million.
The Company used the majority of these funds to retire $31.8 million in
long-
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term debt, and the remainder of the proceeds is being used for exploration
activities and for other general corporate purposes.
PREFERRED STOCK
On June 30, 1998, the Company issued to SLOPI 3,982,906 shares of the Company"s
Preferred Stock. The Preferred Stock had an aggregate stated value of $135
million and ranked prior to the Common Stock as to distribution of assets and
payment of dividends. The holder thereof had the right to convert the Preferred
Stock into an aggregate of 12,837,428 shares of Common Stock. The Preferred
Stock was entitled to receive, when and as declared by the Board of Directors, a
cash dividend at the rate of 4% per annum on the stated value per share. On
January 29, 2001, the Company completed the repurchase of all of the then
outstanding Preferred Stock. See following notes below.
Meridian and SLOPI, on July 18, 2000, announced a definitive agreement granting
Meridian an option to repurchase all of the outstanding shares of Meridian
Preferred Stock (convertible into 12.8 million shares of Common Stock), plus six
million shares of Meridian Common Stock then held by Shell, for an aggregate
cash price of $114 million. The "Option and Standstill Agreement" was
exercisable in a single transaction through January 31, 2001. As consideration
for the grant of the option, Meridian issued Shell one million shares of
Meridian Common Stock in July 2000.
On January 29, 2001, the Company completed the repurchase of all of the then
outstanding Preferred Stock (convertible into 12.8 million shares of Common
Stock) and six million shares of Common Stock from Shell for $114 million. The
$114 million stock buyback price was generated through a balanced financing
structure including $38.7 million in net proceeds from the issuance of Common
Stock at $6 5/8 per share; $25 million in subordinated debt; and $50.3 million
of available cash flow and proceeds from the sale of non-core properties. Shell
remains Meridian"s largest shareholder, with approximately 7.1 million shares of
Common Stock.
WARRANTS
The Company had the following warrants outstanding at December 31, 2003:
NUMBER OF EXERCISE
WARRANTS SHARES PRICE EXPIRATION DATE
-------- --------- -------- ---------------
Executive Officers 1,428,000 $ 5.85 *
General Partner 1,250,170 $ 0.15 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, 2003, 2002 and 2001, 2,130,334, 445,765 and 642,897
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, 2000 4,390,395 $ 4.74
Granted 73,500 6.01
Exercised (128,320) 4.31
Canceled (176,000) 9.88
--------- ---------
Outstanding at December 31, 2001 4,159,575 $ 4.56
Granted 15,000 3.00
Exercised -- --
Canceled (10,500) 5.22
--------- ---------
Outstanding at December 31, 2002 4,164,075 $ 4.55
Granted 15,000 4.51
Exercised (80,000) 3.19
Canceled (540,250) 7.87
--------- ---------
Outstanding at December 31, 2003 3,558,825 $ 4.08
========= =========
Shares exercisable:
December 31, 2003 3,510,700 $ 4.06
December 31, 2002 4,089,450 $ 4.53
December 31, 2001 4,051,075 $ 4.53
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------- --------------------------------------
WEIGHTED WEIGHTED
RANGE OF OUTSTANDING AT AVERAGE EXERCISABLE AT AVERAGE
EXERCISABLE PRICES DECEMBER 31, 2003 EXERCISE PRICE DECEMBER 31, 2003 EXERCISE PRICE
- ------------------ ----------------- -------------- ----------------- --------------
$ 3.00 - $ 4.75 3,145,175 $ 3.38 3,119,550 $ 3.38
$ 5.63 - $ 9.00 214,500 8.00 192,000 8.15
$ 10.38 - $ 11.13 199,150 10.84 199,150 10.84
--------- --------- --------- ---------
3,558,825 $ 4.08 3,510,700 $ 4.06
========= ========= ========= =========
The weighted average remaining contractual life of options outstanding at
December 31, 2003, was approximately seven years.
-54-
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 $417,000 for 2001, $415,000 for 2002 and $316,000 for
2003, 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. For 1997, the price was determined at December 31, 1996, and for all
years subsequent to 1997, it was determined on a semi-annual basis at December
31st and June 30th. At December 31, 2003, the plan had reserved 3,600,000 shares
of Common Stock for future issuance and 2,678,296 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
$1,330,000, $1,630,000 and $1,651,000 for 2003, 2002 and 2001 periods,
respectively, and is reflected in general and administrative expense for the
years ended December 31, 2003, 2002 and 2001, respectively.
STOCKHOLDER RIGHTS PLAN
On May 5, 1999, the Company's Board of Directors declared a dividend
distribution of one "Right" for each then-current and future outstanding share
of Common Stock. Each Right entitles the registered holder to purchase one
one-thousandth percent interest in a share of the Company's Series B Junior
Participating 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.
11. PROFIT SHARING AND SAVINGS PLAN
The Company has a 401(k) profit sharing and savings plan (the "Plan") that
covers substantially all employees and entitles them to contribute up to 15% of
their annual compensation, subject to maximum limitations imposed by the
Internal Revenue Code. The Company matches 100% of each employee's contribution
up to
-55-
6.5% of annual compensation subject to certain limitations as outlined in the
Plan. In addition, the Company may make discretionary contributions which are
allocable to participants in accordance with the Plan. Total expense related to
the Company's 401(k) plan was $331,000, $306,000 and $292,000 in 2003, 2002, and
2001, respectively.
During 1998, the Company implemented a net profits program that was adopted
effective as of November 1997. All employees participate in this program.
Pursuant to this program, the Company adopted three separate well bonus plans:
(i) The Meridian Resource Corporation Geoscientist Well Bonus Plan (the
"Geoscientist Plan"); (ii) The Meridian Resource Corporation TMR Employees Trust
Well Bonus Plan (the "Trust Plan") and (iii) The Meridian Resource Corporation
Management Well Bonus Plan (the "Management Plan" and with the Management Plan
and the Geoscientist Plan, the "Well Bonus Plans"). Payments under the plans are
calculated based on revenues from production on previously discovered reserves,
as realized by the Company at current commodity prices, less operating expenses.
Total compensation related to these plans totaled $4.3 million, $4.2 million and
$7.1 million in 2003, 2002 and 2001, respectively. A portion of these amounts
has been capitalized with regard to personnel engaged in activities associated
with exploratory projects. The Executive Committee of the Board of Directors,
which is comprised of Messrs. Reeves and Mayell, administers each of the Well
Bonus Plans. The participants in each of the Well Bonus Plans are designated by
the Executive Committee in its sole discretion. Participants in the Management
Plan are limited to executive officers of the Company and other key management
personnel designated by the Executive Committee. Neither Messrs. Reeves nor
Mayell participate in the Management Plan. The participants in the Trust Plan
generally will be employees of the Company that do not participate in one of the
other Well Bonus Plans. Effective March 2001, the participants in the
Geoscientist Plan were notified that no additional future wells would be placed
into the plan. During 2002, the Executive Committee decided to modify this
position and for certain key geoscientists the plan will include future new
wells. Additionally, certain interests in the Well Bonus Plans were repurchased
and terminated from current and former employees for issuance of stock grants
(see Note 12).
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, 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.
-56-
12. ISSUANCE OF STOCK GRANTS
Effective December 2001, an agreement was executed to repurchase and terminate
certain interests in the Well Bonus Plans from current and former employees in
exchange for the issuance of Common Stock. The offering was for a total of
1,940,991 shares of our Common Stock. The Common Stock was issued on February 4,
2002, at the last reported sales price of $3.48 per share.
13. OIL AND NATURAL GAS HEDGING ACTIVITIES
The Company may address market risk by selecting instruments whose value
fluctuations correlate strongly with the underlying commodity being hedged. The
Company enters into swaps and other derivative contracts to hedge the price
risks associated with a portion of anticipated future oil and gas production.
While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit future gains from favorable movements. Under these
agreements, payments are received or made based on the differential between a
fixed and a variable product price. These agreements are settled in cash at or
prior to expiration or exchanged for physical delivery contracts. The Company
does not obtain collateral to support the agreements, but monitors the financial
viability of counter-parties and believes its credit risk is minimal on these
transactions. In the event of nonperformance, the Company would be exposed to
price risk. The Company has some risk of accounting loss since the price
received for the product at the actual physical delivery point may differ from
the prevailing price at the delivery point required for settlement of the
hedging transaction.
The Company's results of operations and operating cash flows are impacted by
changes in market prices for oil and natural gas. To mitigate a portion of the
exposure to adverse market changes, the Company has entered into various swap
agreements. These swaps allow the Company to predict with greater certainty the
effective oil and natural gas prices to be received for hedged production.
Although derivatives often fail to achieve 100% effectiveness for accounting
purposes, these derivative instruments continue to be highly effective in
achieving the risk management objectives for which they were intended. These
swaps have been designated as cash flow hedges as provided by FAS 133 and any
changes in fair value are recorded in other comprehensive income until earnings
are affected by the variability in cash flows of the designated hedged item. Any
changes in fair value resulting from the ineffectiveness of the hedge are
reported in the consolidated statement of operations as a component of revenues.
The Company recognized minimal losses related to hedge ineffectiveness during
the three years ended December 31, 2003.
At December 31, 2003, the change in estimated fair value of the Company's oil
and natural gas swaps was an unrealized loss of $11.6 million ($7.5 million net
of tax) which is recognized in other comprehensive income. Based upon December
31, 2003, oil and natural gas commodity prices approximately $9.8 million of the
loss deferred in other comprehensive income could potentially lower gross
revenues in 2004. The swap agreements expire at various dates through July 31,
2005.
Net settlements under these swap agreements reduced oil and natural gas revenues
by $14,916,000 and $1,183,000 for the years ended December 31, 2003 and 2002,
respectively, as a result of hedging transactions. During the year ended
December 31, 2001, the Company had no material hedging agreements.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 11% of our proved developed natural gas production and 79% of our
proved developed oil production during the respective terms of the swap
agreements. The fair values of the hedges are based on the difference between
the strike price and the New York Mercantile Exchange future prices for the
applicable trading months.
-57-
Weighted Average Fair Value (unrealized)
Notional Strike Price at December 31, 2003 (in
Amount ($ per unit) thousands)
-------- ---------------- ------------------------
Natural Gas (mmbtu)
January 2004 - June 2005 3,550,000 $ 3.73 $ (5,630)
Oil (bbls)
January 2004 - July 2005 978,000 $ 23.49 $ (5,938)
------------
$ (11,568)
============
14. MAJOR CUSTOMERS
Major customers for the years ended December 31, 2003, 2002 and 2001, 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 2003 2002 2001
-------- ---- ---- ----
Louisiana Intrastate Gas.............................. 24% 17% 20%
Superior Natural Gas.................................. 19% -- 13%
Conoco, Inc........................................... 10% 12% --
Equiva Trading Company(1)............................. -- 33% 30%
(1) Equiva Trading Company is an affiliate of Shell.
15. RELATED PARTY TRANSACTIONS
Historically since 1994, affiliates of Meridian have been permitted to hold
interests in projects of the Company. With the approval of the Board of
Directors, Texas Oil Distribution and Development, Inc. ("TODD") and Sydson
Energy, Inc. ("Sydson"), entities controlled by Joseph A. Reeves, Jr. and
Michael J. Mayell, respectively, have each invested in all Meridian drilling
locations on a promoted basis, where applicable, at a 1.5% working interest
basis. The maximum percentage that either may elect to participate in any
prospect is a 4% working interest. On a collective basis, TODD and Sydson
invested $5,161,000, $3,289,000 and $4,846,000 for the years ended December 31,
2003, 2002 and 2001, respectively, in oil and natural gas drilling activities
for which the Company was the operator. Net amounts due from TODD and Mr. Reeves
were approximately $5,000 and $186,000 as of December 31, 2003 and 2002,
respectively. Net amounts due from Sydson and Mr. Mayell were approximately
$344,000 and $1,370,000 as of December 31, 2003 and 2002, respectively.
Mr. Joe Kares, a Director of Meridian, is a partner in the public accounting
firm of Kares & Cihlar, which provided the Company with accounting services for
the years ended December 31, 2003, 2002 and 2001 and received fees of
approximately $210,000, $282,000 and $269,000, 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.
Kares also participated in the Management Plan described in Note 11 above,
pursuant to which he was paid approximately $61,000 during 2003.
Mr. Gary A. Messersmith, a Director of Meridian, is currently a partner in the
law firm of Looper, Reed and McGraw in Houston, Texas, which provided legal
services for the Company for the years ended December 31, 2003, 2002 and 2001,
and received fees of approximately $49,000, $27,000 and $58,000, respectively.
He previously was a partner in the law firm of Fouts & Moore, L.L.P., in
Houston, Texas, which
-58-
provided legal services for the Company for the years ended December 31, 2001
and received fees of approximately $66,000. 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. In addition, the Company has Mr.
Messersmith on a personal retainer of $8,333 per month relating to his services
provided to the Company and a bonus in the form of personal property valued at
$12,500 was awarded during 2002. Mr. Messersmith also participated in the
Management Plan described in Note 11 above, pursuant to which he was paid
approximately $360,000 during 2003, $377,000 during 2002, $401,000 during 2001.
16. EARNINGS PER SHARE (in thousands, except per share)
The following table sets forth the computation of basic and diluted earnings
(loss) per share:
YEAR ENDED DECEMBER 31,
--------------------------------------------------
2003 2002(1) 2001
---- ---- ----
Numerator:
Net earnings (loss) applicable to common stockholders $ 7,246 $ (52,012) $ 22,551
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A 429
Interest on convertible subordinated notes N/A N/A 1,211
------------ ------------ ------------
Net earnings (loss) applicable to common stockholders
plus assumed conversions $ 7,246 $ (52,012) $ 24,191
------------ ------------ ------------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 53,325 49,763 48,350
Effect of potentially dilutive common shares:
Warrants 3,393 N/A 2,387
Employee and director stock options 426 N/A 1,263
Convertible preferred stock -- -- 985
Convertible subordinated notes N/A N/A 2,857
Redeemable preferred stock N/A N/A --
------------ ------------ ------------
Denominator for diluted earnings per share
- weighted-average shares outstanding and
assumed conversions 57,144 49,763 55,842
============ ============ ============
Basic earnings (loss) per share $ 0.14 $ (1.05) $ 0.47
============ ============ ============
Diluted earnings (loss) per share $ 0.13 $ (1.05) $ 0.43
============ ============ ============
(1) Anti-dilutive in 2002.
N/A = Not Applicable, meaning anti-dilutive for periods present.
-59-
17. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the years ended December 31, 2003 and 2002,
were (thousands of dollars, except per share):
QUARTER ENDED
-------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
2003
Revenues $ 29,025 $ 29,654 $ 39,337 $ 39,463
Results of operations from
exploration and production
activities(1) 10,287 10,315 12,141 11,057
Net earnings (loss)(2) $ 1,721 $ 1,924 $ 2,965 $ 636
Net earnings (loss) per share:(2)
Basic $ 0.03 $ 0.04 $ 0.06 $ 0.01
Diluted 0.03 0.04 0.05 0.01
2002
Revenues $ 23,848 $ 32,473 $ 26,775 $ 24,374
Results of operations from
exploration and production
activities(1) 5,753 12,982 (65,894) 5,058
Net earnings (loss)(2) $ (1,577) $ 3,172 $ (51,384) $ (2,223)
Net earnings (loss) per share:(2)
Basic $ (0.03) $ 0.06 $ (1.03) $ (0.04)
Diluted (0.03) 0.06 (1.03) (0.04)
(1) Results of operations from exploration and production activities, which
approximate gross profit, are computed as operating revenues less lease
operating expenses, severance and ad valorem taxes, depletion and
impairment of oil and natural gas properties.
(2) Applicable to common stockholders.
-60-
18. SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (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,
------------------------------------------
2003 2002 2001
---- ---- ----
Costs incurred during the year:(1)
Property acquisition costs
Unproved $ 4,107 $ 5,217 $ 11,330
Proved -- -- --
Exploration 42,081 32,293 91,904
Development 25,586 38,998 30,471
Asset retirement cost accruals, net 1,326 -- --
---------- ---------- ------------
$ 73,100 $ 76,508 $ 133,705
========== ========== ============
(1) Costs incurred during the years ended December 31, 2003, 2002 and 2001
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of
third party reimbursements, of $10,030,000, $11,684,000 and
$13,459,000, respectively.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
DECEMBER 31,
------------
2003 2002
---- ----
Capitalized costs $ 1,230,643 $ 1,162,436
Accumulated depletion 829,089 755,433
------------ -------------
Net capitalized costs $ 401,554 $ 407,003
============ =============
At December 31, 2003 and 2002, unevaluated costs of $30,542,000 and $18,993,000,
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.
-61-
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2001
---- ---- ----
Oil and natural gas revenues $ 137,124 $ 106,992 $ 176,646
Less:
Oil and natural gas operating costs 11,260 11,935 16,625
Severance and ad valorem taxes 7,608 8,235 11,761
Depletion 74,456 59,799 65,982
Accretion expense(1) 667 -- --
Impairment of long-lived assets -- 69,124 6,580
Income tax 4,249 (22,002) 13,500
----------- ----------- -----------
98,240 127,091 114,448
----------- ----------- -----------
Results of operations from oil and
natural gas producing activities $ 38,884 $ (20,099) $ 62,198
=========== =========== ===========
Depletion expense per Mcfe $ 2.61 $ 2.07 $ 1.67
=========== =========== ===========
(1) On January 1, 2003, the company adopted SFAS 143. The pro forma effects
of the application of SFAS 143, as if the statement had been adopted on
January 1, 2001, would have been an additional accretion expense of
$470 thousand and $414 thousand for the years 2002 and 2001,
respectively.
-62-
ESTIMATED QUANTITIES OF PROVED RESERVES
The following table sets forth the net proved reserves of the Company as of
December 31, 2003, 2002 and 2001, and the changes therein during the years then
ended. The reserve information was reviewed by T. J. Smith & Company, Inc.,
independent petroleum engineers, for 2003, 2002 and 2001. 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, 2000 22,341 172,427
Production during 2001 (2,918) (22,085)
Discoveries and extensions(1) 11,605 68,226
Sale of reserves-in-place (5,558) (21,447)
Revisions of previous quantity estimates and other (1,124) (20,199)
------- -------
BALANCE AT DECEMBER 31, 2001 24,346 176,922
Production during 2002 (2,213) (15,578)
Discoveries and extensions 41 13,786
Revisions of previous quantity estimates and other(1) (12,249) (67,504)
------- -------
BALANCE AT DECEMBER 31, 2002 9,925 107,626
Production during 2003 (1,403) (20,142)
Discoveries and extensions 31 18,474
Sale of reserves-in-place (571) (1,238)
Revisions of previous quantity estimates and other (90) (6,251)
------- -------
BALANCE AT DECEMBER 31, 2003 7,892 98,469
======= =======
PROVED DEVELOPED RESERVES:
Balance at December 31, 2003 5,016 82,279
Balance at December 31, 2002 6,841 86,248
Balance at December 31, 2001 10,752 101,397
Balance at December 31, 2000 15,549 127,742
(1) Primarily as a result of Kent Bayou. See Note 4. to Notes to
Consolidated Financial Statements for additional information.
-63-
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The information that follows has been developed pursuant to SFAS No. 69 and
utilizes reserve and production data prepared or reviewed by independent
petroleum consultants. Reserve estimates are inherently imprecise and estimates
of new discoveries are less precise than those of producing oil and natural gas
properties. Accordingly, these estimates are expected to change as future
information becomes available.
The estimated discounted future net cash flows from estimated proved reserves
are based on prices and costs as of the date of the estimate unless such prices
or costs are contractually determined at such date. Actual future prices and
costs may be materially higher or lower. Actual future net revenues also will be
affected by factors such as actual production, supply and demand for oil and
natural gas, curtailments or increases in consumption by natural gas purchasers,
changes in governmental regulations or taxation and the impact of inflation on
costs. Future income tax expense has been reduced for the effect of available
net operating loss carryforwards.
(thousands of dollars)
AT DECEMBER 31,
2003 2002 2001
---- ---- ----
Future cash flows $ 842,945 $ 829,538 $ 892,642
Future production costs (118,775) (137,215) (158,674)
Future development costs (30,044) (43,474) (64,754)
----------- ----------- -----------
Future net cash flows before income taxes 694,126 648,849 669,214
Future taxes on income (116,570) (99,852) (115,031)
----------- ----------- -----------
Future net cash flows 577,556 548,997 554,183
Discount to present value at 10 percent per annum (121,673) (119,162) (151,266)
----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 455,883 $ 429,835 $ 402,917
=========== =========== ===========
The average price for natural gas in the above computations was $6.07, $4.96 and
$2.63 per Mcf at December 31, 2003, 2002, and 2001, respectively. The average
price used for crude oil in the above computations was $32.05, $31.82 and $19.41
per Bbl at December 31, 2003, 2002, and 2001, respectively.
-64-
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, 2003, 2002 and 2001
(thousands of dollars):
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002 2001
---- ---- ----
Balance at Beginning of Period $ 429,835 $ 402,917 $ 992,254
Sales of oil and gas, net of production costs (118,256) (86,822) (148,260)
Changes in sales & transfer prices, net of production costs 82,200 348,960 (795,374)
Revisions of previous quantity estimates (24,563) (373,928) (38,680)
Sales of reserves-in-place (5,026) -- (199,245)
Current year discoveries, extensions
and improved recovery 67,676 40,376 190,073
Changes in estimated future
development costs (7,824) (9,840) (11,366)
Development costs incurred during the period 20,511 38,998 30,471
Accretion of discount 42,983 40,292 99,225
Net change in income taxes (21,186) (3,676) 319,905
Change in production rates (timing) and other (10,467) 32,558 (36,086)
----------- ----------- -----------
Net change 26,048 26,918 (589,337)
----------- ----------- -----------
Balance at End of Period $ 455,883 $ 429,835 $ 402,917
=========== =========== ===========
-65-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
On September 25, 2003, the Company retained the services of BDO Seidman LLP as
its new independent accountant, replacing Ernst & Young LLP, to audit the
Company's financial statements. The Company's Current Report on Form 8-K, dated
September 25, 2003, is incorporated by reference in this Form 10-K, and the
information included in Item 4 of the Form 8-K is included as Exhibit 99.1 to
this Form 10-K.
ITEM 9A. CONTROLS AND PROCEDURES
We conducted an evaluation under the supervision and with the participation of
Meridian's management, including our Chief Executive Officer and Chief
Accounting Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rule 13a-14(c) under the
Securities Exchange Act of 1934) as of the end of the fourth quarter of 2003.
Based upon that evaluation, our Chief Executive Officer and Chief Accounting
Officer concluded that the design and operation of our disclosure controls and
procedures are effective. There have been no significant changes in our internal
controls or in other factors during the fourth quarter of 2003 that could
significantly affect these controls.
PART III
The information required in Items 10, 11, 12, 13 and 14 is incorporated by
reference to the Company's definitive Proxy Statement to be filed with the
Securities and Exchange Commission on or before April 29, 2004.
-66-
PART IV
ITEM 15. 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 Auditors' Reports
(ii) Consolidated Balance Sheets as of December 31, 2003
and 2002
(iii) Consolidated Statements of Operations for each of the
three years in the period ended December 31, 2003
(iv) Consolidated Statements of Changes in Stockholders'
Equity for each of the three years in the period
ended December 31, 2003
(v) Consolidated Statements of Cash Flows for each of the
three years in the period ended December 31, 2003
(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:
3.1 Third Amended and Restated Articles of Incorporation
of the Company (incorporated by reference to the
Company's Quarterly Report on Form 10-Q for the three
months ended September 30, 1998).
3.2 Amended and Restated Bylaws of the Company
(incorporated by reference to the Company's Quarterly
Report on Form 10-Q for the three months ended
September 30, 1998).
3.3 Certificate of Designation for Series C Redeemable
Convertible Preferred Stock dated March 28, 2002
(incorporated by reference to Exhibit 3.1 of the
Company's Quarterly Report on Form 10-Q for the three
months ended March 31, 2002).
4.1 Specimen Common Stock Certificate (incorporated by
reference to Exhibit 4.1 of the Company's
Registration Statement on Form S-1, as amended (Reg.
No. 33-65504)).
*4.2 Common Stock Purchase Warrant of the Company dated
October 16, 1990, issued to Joseph A. Reeves, Jr.
(incorporated by reference to Exhibit 10.8 of the
Company's Annual Report on Form 10-K for the year
ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
*4.3 Common Stock Purchase Warrant of the Company dated
October 16, 1990, issued to Michael J. Mayell
(incorporated by reference to Exhibit 10.9 of the
Company's Annual Report on Form 10-K for the year
ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
*4.4 Registration Rights Agreement dated October 16, 1990,
among the Company, Joseph A.
-67-
Reeves, Jr. and Michael J. Mayell (incorporated by
reference to Exhibit 10.7 of the Company's
Registration Statement on Form S-4, as amended (Reg.
No. 33-37488)).
*4.5 Warrant Agreement dated June 7, 1994, between the
Company and Joseph A. Reeves, Jr. (incorporated by
reference to Exhibit 4.1 of the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30,
1994).
*4.6 Warrant Agreement dated June 7, 1994, between the
Company and Michael J. Mayell (incorporated by
reference to Exhibit 4.1 of the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30,
1994).
4.7 Credit Agreement, dated August 13, 2002, among the
Company, Societe Generale, as Administrative Agent,
Lead Arranger and Bookrunner, Fortis Capital Corp.,
as Co-Lead Arranger and Documentation Agent, and the
several lenders from time to time parties thereto
(incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K dated August 13,
2002).
4.8 The Meridian Resource Corporation Directors' Stock
Option Plan (incorporated by reference to Exhibit
10.5 of the Company's Annual Report on Form 10-K for
the year ended December 31, 1991, as amended by the
Company's Form 8 filed March 4, 1993).
4.9 Registration Rights Agreement dated January 29, 2001,
by and between The Meridian Resource Corporation and
Shell Louisiana Onshore Properties Inc. (incorporated
by reference from the Company's Current Report on
Form 8-K dated January 29, 2001).
4.10 Termination Agreement, dated January 29, 2001, by and
between the Company and Shell Louisiana Onshore
Properties Inc. (incorporated by reference from the
Company's Current Report on Form 8-K dated January
29, 2001).
4.11 Amendment No. 1, dated as of January 29, 2001, to
Rights Agreement, dated as of May 5, 1999, by and
between the Company and American Stock Transfer &
Trust Co., as rights agent (incorporated by reference
from the Company's Current Report on Form 8-K dated
January 29, 2001).
4.12 First Amendment to Subordinated Credit Agreement,
dated December 5, 2001, between Meridian and Fortis
Capital Corp. (incorporated by reference to Exhibit
4.17 of the Company's Registration statement on Form
S-3, as amended (Reg. No. 333-75414)).
10.1 See exhibits 4.2 through 4.12 for additional material
contracts.
*10.2 The Meridian Resource Corporation 1990 Stock Option
Plan (incorporated by reference to Exhibit 10.6 of
the Company's Annual Report on Form 10-K for the year
ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
*10.3 Employment Agreement dated August 18, 1993, between
the Company and Joseph A. Reeves, Jr. (incorporated
by reference from the Company's Annual Report on Form
10-K for the year ended December 31, 1995).
*10.4 Employment Agreement dated August 18, 1993, between
the Company and Michael J. Mayell (incorporated by
reference from the Company's Annual Report on Form
10-K for the year ended December 31, 1995).
-68-
*10.5 Form of Indemnification Agreement between the Company
and its executive officers and directors
(incorporated by reference to Exhibit 10.6 of the
Company's Annual Report on Form 10-K for the year
ended December 31, 1994).
*10.6 Deferred Compensation agreement dated July 31, 1996,
between the Company and Joseph A. Reeves, Jr.
(incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1996).
*10.7 Deferred Compensation agreement dated July 31, 1996,
between the Company and Michael J. Mayell
(incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1996).
*10.8 Texas Meridian Resources Corporation 1995 Long-Term
Incentive Plan (incorporated by reference to the
Company's Annual Report on Form 10-K for the
year-ended December 31, 1996).
*10.9 Texas Meridian Resources Corporation 1997 Long-Term
Incentive Plan (incorporated by reference from the
Company's Quarterly Report on Form 10-Q for the three
months ended June 30, 1997).
*10.10 Cairn Energy USA, Inc. 1993 Stock Option Plan, as
amended (incorporated by reference to Cairn Energy
USA, Inc.'s Annual Report on Form 10-K for the year
ended December 31, 1993).
*10.11 Cairn Energy USA, Inc. 1993 Directors Stock Option
Plan, as amended (incorporated by reference to Cairn
Energy USA, Inc.'s Registration Statement on Form S-1
(Reg. No.33-64646).
*10.14 Employment Agreement with Lloyd V. DeLano effective
November 5, 1997 (incorporated by reference from the
Company's Quarterly Report on Form 10-Q for the three
months ended September 30, 1998).
*10.15 The Meridian Resource Corporation TMR Employee Trust
Well Bonus Plan (incorporated by reference from the
Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
*10.16 The Meridian Resource Corporation Management Well
Bonus Plan (incorporated by reference from the
Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
*10.17 The Meridian Resource Corporation Geoscientist Well
Bonus Plan (incorporated by reference from the
Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
*10.18 Modification Agreement effective January 2, 1999, by
and among the Company and affiliates of Joseph A.
Reeves, Jr. (incorporated by reference from the
Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
*10.19 Modification Agreement effective January 2, 1999, by
and among the Company and affiliates of Michael J.
Mayell (incorporated by reference from the Company's
Annual Report on Form 10-K for the year ended
December 31, 1998).
-69-
10.20 Subordinated Credit Agreement, dated January 5, 2001,
between the Company and Fortis Capital Corporation.
(incorporated by reference from the Company's Annual
Report on Form 10-K for the year ended December 31,
2000).
21.1 Subsidiaries of the Company (incorporated by
reference to Exhibit 21.1 of the Company's Annual
Report on Form 10-K for the year ended December 31,
2000).
**23.1 Consent of BDO Seidman LLP.
**23.2 Consent of Ernst & Young LLP.
**23.3 Consent of T. J. Smith & Company, Inc.
**31.1 Certification of Chief Executive Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as amended.
**31.2 Certification of President pursuant to Rule 13a-14(a)
or Rule 15d-14(a) under the Securities Exchange Act
of 1934, as amended.
**31.3 Certification of Chief Accounting Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as amended.
**32.1 Certification of Chief Executive Officer pursuant to
Rule 13a-14(b) or Rule 15d-14(b) under the Securities
Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350.
**32.2 Certification of President pursuant to Rule 13a-14(b)
or Rule 15d-14(b) under the Securities Exchange Act
of 1934, as amended, and 18 U.S.C. Section 1350.
**32.3 Certification of Chief Accounting Officer pursuant
Rule 13a-14(b) or Rule 15d-14(b) under the Securities
Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350.
**99.1 Item 4 of the Company's Current Report on Form 8-K,
dated September 25, 2003.
*Management contract or compensation plan.
**Filed herewith.
(b) Reports on Form 8-K.
None
-70-
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 15, 2004
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 15, 2004
------------------------------------------ (Principal Executive Officer)
Joseph A. Reeves, Jr. Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director March 15, 2004
------------------------------------------
Michael J. Mayell
BY: /s/ LLOYD V. DELANO Chief Accounting Officer March 15, 2004
-------------------------------------------
Lloyd V. DeLano
BY: /s/ JAMES T. BOND Director March 15, 2004
-------------------------------------------
James T. Bond
BY: /s/ JOE E. KARES Director March 15, 2004
-------------------------------------------
Joe E. Kares
BY: /s/ GARY A. MESSERSMITH Director March 15, 2004
-------------------------------------------
Gary A. Messersmith
BY: /s/ DAVID W. TAUBER Director March 15, 2004
-------------------------------------------
David W. Tauber
-71-
INDEX TO EXHIBITS
3.1 Third Amended and Restated Articles of Incorporation
of the Company (incorporated by reference to the
Company's Quarterly Report on Form 10-Q for the three
months ended September 30, 1998).
3.2 Amended and Restated Bylaws of the Company
(incorporated by reference to the Company's Quarterly
Report on Form 10-Q for the three months ended
September 30, 1998).
3.3 Certificate of Designation for Series C Redeemable
Convertible Preferred Stock dated March 28, 2002
(incorporated by reference to Exhibit 3.1 of the
Company's Quarterly Report on Form 10-Q for the three
months ended March 31, 2002).
4.1 Specimen Common Stock Certificate (incorporated by
reference to Exhibit 4.1 of the Company's
Registration Statement on Form S-1, as amended (Reg.
No. 33-65504)).
*4.2 Common Stock Purchase Warrant of the Company dated
October 16, 1990, issued to Joseph A. Reeves, Jr.
(incorporated by reference to Exhibit 10.8 of the
Company's Annual Report on Form 10-K for the year
ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
*4.3 Common Stock Purchase Warrant of the Company dated
October 16, 1990, issued to Michael J. Mayell
(incorporated by reference to Exhibit 10.9 of the
Company's Annual Report on Form 10-K for the year
ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
*4.4 Registration Rights Agreement dated October 16, 1990,
among the Company, Joseph A.
Reeves, Jr. and Michael J. Mayell (incorporated by
reference to Exhibit 10.7 of the Company's
Registration Statement on Form S-4, as amended (Reg.
No. 33-37488)).
*4.5 Warrant Agreement dated June 7, 1994, between the
Company and Joseph A. Reeves, Jr. (incorporated by
reference to Exhibit 4.1 of the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30,
1994).
*4.6 Warrant Agreement dated June 7, 1994, between the
Company and Michael J. Mayell (incorporated by
reference to Exhibit 4.1 of the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30,
1994).
4.7 Credit Agreement, dated August 13, 2002, among the
Company, Societe Generale, as Administrative Agent,
Lead Arranger and Bookrunner, Fortis Capital Corp.,
as Co-Lead Arranger and Documentation Agent, and the
several lenders from time to time parties thereto
(incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K dated August 13,
2002).
4.8 The Meridian Resource Corporation Directors' Stock
Option Plan (incorporated by reference to Exhibit
10.5 of the Company's Annual Report on Form 10-K for
the year ended December 31, 1991, as amended by the
Company's Form 8 filed March 4, 1993).
4.9 Registration Rights Agreement dated January 29, 2001,
by and between The Meridian Resource Corporation and
Shell Louisiana Onshore Properties Inc. (incorporated
by reference from the Company's Current Report on
Form 8-K dated January 29, 2001).
4.10 Termination Agreement, dated January 29, 2001, by and
between the Company and Shell Louisiana Onshore
Properties Inc. (incorporated by reference from the
Company's Current Report on Form 8-K dated January
29, 2001).
4.11 Amendment No. 1, dated as of January 29, 2001, to
Rights Agreement, dated as of May 5, 1999, by and
between the Company and American Stock Transfer &
Trust Co., as rights agent (incorporated by reference
from the Company's Current Report on Form 8-K dated
January 29, 2001).
4.12 First Amendment to Subordinated Credit Agreement,
dated December 5, 2001, between Meridian and Fortis
Capital Corp. (incorporated by reference to Exhibit
4.17 of the Company's Registration statement on Form
S-3, as amended (Reg. No. 333-75414)).
10.1 See exhibits 4.2 through 4.12 for additional material
contracts.
*10.2 The Meridian Resource Corporation 1990 Stock Option
Plan (incorporated by reference to Exhibit 10.6 of
the Company's Annual Report on Form 10-K for the year
ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
*10.3 Employment Agreement dated August 18, 1993, between
the Company and Joseph A. Reeves, Jr. (incorporated
by reference from the Company's Annual Report on Form
10-K for the year ended December 31, 1995).
*10.4 Employment Agreement dated August 18, 1993, between
the Company and Michael J. Mayell (incorporated by
reference from the Company's Annual Report on Form
10-K for the year ended December 31, 1995).
*10.5 Form of Indemnification Agreement between the Company
and its executive officers and directors
(incorporated by reference to Exhibit 10.6 of the
Company's Annual Report on Form 10-K for the year
ended December 31, 1994).
*10.6 Deferred Compensation agreement dated July 31, 1996,
between the Company and Joseph A. Reeves, Jr.
(incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1996).
*10.7 Deferred Compensation agreement dated July 31, 1996,
between the Company and Michael J. Mayell
(incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1996).
*10.8 Texas Meridian Resources Corporation 1995 Long-Term
Incentive Plan (incorporated by reference to the
Company's Annual Report on Form 10-K for the
year-ended December 31, 1996).
*10.9 Texas Meridian Resources Corporation 1997 Long-Term
Incentive Plan (incorporated by reference from the
Company's Quarterly Report on Form 10-Q for the three
months ended June 30, 1997).
*10.10 Cairn Energy USA, Inc. 1993 Stock Option Plan, as
amended (incorporated by reference to Cairn Energy
USA, Inc.'s Annual Report on Form 10-K for the year
ended December 31, 1993).
*10.11 Cairn Energy USA, Inc. 1993 Directors Stock Option
Plan, as amended (incorporated by reference to Cairn
Energy USA, Inc.'s Registration Statement on Form S-1
(Reg. No.33-64646).
*10.14 Employment Agreement with Lloyd V. DeLano effective
November 5, 1997 (incorporated by reference from the
Company's Quarterly Report on Form 10-Q for the three
months ended September 30, 1998).
*10.15 The Meridian Resource Corporation TMR Employee Trust
Well Bonus Plan (incorporated by reference from the
Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
*10.16 The Meridian Resource Corporation Management Well
Bonus Plan (incorporated by reference from the
Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
*10.17 The Meridian Resource Corporation Geoscientist Well
Bonus Plan (incorporated by reference from the
Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
*10.18 Modification Agreement effective January 2, 1999, by
and among the Company and affiliates of Joseph A.
Reeves, Jr. (incorporated by reference from the
Company's Annual Report on Form 10-K for the year
ended December 31, 1998).
*10.19 Modification Agreement effective January 2, 1999, by
and among the Company and affiliates of Michael J.
Mayell (incorporated by reference from the Company's
Annual Report on Form 10-K for the year ended
December 31, 1998).
10.20 Subordinated Credit Agreement, dated January 5, 2001,
between the Company and Fortis Capital Corporation.
(incorporated by reference from the Company's Annual
Report on Form 10-K for the year ended December 31,
2000).
21.1 Subsidiaries of the Company (incorporated by
reference to Exhibit 21.1 of the Company's Annual
Report on Form 10-K for the year ended December 31,
2000).
**23.1 Consent of BDO Seidman LLP.
**23.2 Consent of Ernst & Young LLP.
**23.3 Consent of T. J. Smith & Company, Inc.
**31.1 Certification of Chief Executive Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as amended.
**31.2 Certification of President pursuant to Rule 13a-14(a)
or Rule 15d-14(a) under the Securities Exchange Act
of 1934, as amended.
**31.3 Certification of Chief Accounting Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities
Exchange Act of 1934, as amended.
**32.1 Certification of Chief Executive Officer pursuant to
Rule 13a-14(b) or Rule 15d-14(b) under the Securities
Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350.
**32.2 Certification of President pursuant to Rule 13a-14(b)
or Rule 15d-14(b) under the Securities Exchange Act
of 1934, as amended, and 18 U.S.C. Section 1350.
**32.3 Certification of Chief Accounting Officer pursuant
Rule 13a-14(b) or Rule 15d-14(b) under the Securities
Exchange Act of 1934, as amended, and 18 U.S.C.
Section 1350.
**99.1 Item 4 of the Company's Current Report on Form 8-K,
dated September 25, 2003.
*Management contract or compensation plan.
**Filed herewith.