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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, 2004 Commission file number: 1-10671
THE MERIDIAN RESOURCE CORPORATION
(Exact name of registrant as specified in its charter)
TEXAS 76-0319553
(State of incorporation) (I.R.S. Employer
Identification No.)
1401 ENCLAVE PARKWAY, SUITE 300, HOUSTON, TEXAS 77077
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-597-7000
Securities registered pursuant to Section 12(b) of the Act:
(Title of each class) (Name of each exchange on which registered)
- --------------------- -------------------------------------------
Common Stock, $0.01 par value New York Stock Exchange
Rights to Purchase Preferred Shares New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
----------
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [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, 2004 $495,384,386
Number of shares of common stock outstanding at March 1, 2005: 79,215,394
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 May 2, 2005.
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
Page
----
PART I
Item 1. Business 3
Item 2. Properties 14
Item 3. Legal Proceedings 14
Item 4. Submission of Matters to a Vote of Security Holders 15
PART II
Item 5. Market for Registrant's Common Equity, Related Shareholder
Matters and Issuer Purchases of Equity Securities 16
Item 6. Selected Financial Data 17
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 18
Item 7.A. Quantitative and Qualitative Disclosures about Market Risk 34
Item 8. Financial Statements and Supplementary Data 36
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 72
Item 9.A. Controls and Procedures 72
PART III
Item 10. Directors and Executive Officers of the Registrant 72
Item 11. Executive Compensation 72
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters 72
Item 13. Certain Relationships and Related Transactions 72
Item 14. Principal Accountant Fees and Services 72
PART IV
Item 15. Exhibits and Financial Statement Schedules 73
Signatures 77
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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, 2004, we had
proved reserves of 139 Bcfe with a present value of future net cash flows before
income taxes of approximately $545 million. The Company does not have any proved
undeveloped reserves assigned to its Biloxi Marshlands project area.
Seventy-three percent (73%) of our proved reserves were natural gas and
approximately eighty-two percent (82%) were classified as proved developed.
We believe that we are among the leaders in the industry in the application of
3-D seismic technology. 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 13 years, we have generated and participated in the discovery of
approximately 800 Bcfe of new reserves. Recently, we have added to our business
strategy the pursuit and development of shallower (above or just into
geo-preserved sections), lower-risk exploration projects that we believe provide
the Company better control of risks and costs than a purely deep exploration
strategy that the Company 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. In addition, the Company has introduced into its business
plan, a more aggressive review of the acquisition of proven reserves that also
contain exploration, exploitation and development upside in our area of focus.
We currently have interests in leases and options to lease acreage in
approximately 300,000 gross acres in Louisiana, Texas and the Gulf of Mexico. We
also have rights or access to approximately 8,000 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. We are aggressively pursuing
the reprocessing of our 3-D inventory for the development of new exploration
plays similar to those defined by our Biloxi Marshlands play. We have tested the
first of such exploration concepts at the Company's Turtle Island Prospect and
recently logged approximately 80 feet of apparent hydrocarbons.
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, including the
Company's filings with the Securities and Exchange Commission, 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 well and multiple potential targets to maximize
the profitability and increase of probability of success.
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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 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 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 and that our people, their knowledge and
experience, particularly in our focus region, provide us with a competitive
advantage.
-4-
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, 2004. 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, 2004
Oil (MBbls) ................................... 1,133 137 1,270
Natural Gas (MMcf) ............................ 26,249 1,590 27,839
RESERVES AS OF DECEMBER 31, 2004
Oil (MBbls) ................................... 5,377 987 6,364
Natural Gas (MMcf) ............................ 92,554 8,445 100,999
ESTIMATED FUTURE NET CASH FLOWS ($000)............ $719,375
PRESENT VALUE OF FUTURE NET CASH FLOWS BEFORE
INCOME TAXES ($000)(1)......................... $544,688
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
CASH FLOWS ($000)(1)........................... $470,357
(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, 2004, we used the prices at December 31, 2004, which were
$42.33 per Bbl of oil and $6.40 per Mcf of natural gas and do not reflect
the impact of hedges.
PRODUCTIVE WELLS
At December 31, 2004, 2003 and 2002, we held interests in the following
productive wells. As of December 31, 2004, we own 26 gross (4.5 net) wells in
the Gulf of Mexico which are outside operated and net to 1.5 oil wells and 3.0
natural gas wells. In addition, of the total well count for 2004, 4 wells (1.4
net) are multiple completions.
2004 2003 2002
----------- ----------- -----------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ----
Oil Wells........... 35 22 31 20 67 42
Natural Gas Wells... 68 34 60 27 71 28
--- --- --- --- --- ---
Total............ 103 56 91 47 138 70
=== === === === === ===
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,
2004. 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.
-5-
PROVED RESERVES AT DECEMBER 31, 2004
-------------------------------------------------
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
--------- ------------- ----------- --------
(DOLLARS IN THOUSANDS)
Net Proved Reserves:
Oil (MBbls)............................... 2,285 2,431 1,648 6,364
Natural Gas (MMcf)........................ 41,928 43,579 15,492 100,999
Natural Gas Equivalent (MMcfe)............ 55,638 58,165 25,380 139,183
Estimated Future Net Cash Flows........... $719,375
Present Value of Future Net Cash Flows
(before income taxes)(1)............... $544,688
Standardized Measure of Discounted
Future Net Cash Flows(1)............... $470,357
- ----------
(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, 2004, we used the prices at December 31,
2004, which were $42.33 per Bbl of oil and $6.40 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. 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.
-6-
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 2004, 2003
and 2002.
GROSS WELLS NET WELLS
------------------------ ------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- --- -----
EXPLORATORY WELLS
Year ended December 31, 2004... 16 11 27 14.7 8.9 23.6
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
DEVELOPMENT WELLS
Year ended December 31, 2004... 4 -- 4 3.2 -- 3.2
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
Meridian had 3 gross (2.4 net) wells in progress at December 31, 2004.
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 2004, 2003 and 2002.
YEAR ENDED DECEMBER 31,
---------------------------
2004 2003 2002
------- ------- -------
PRODUCTION:
Oil (MBbls)......................... 1,270 1,403 2,213
Natural gas (MMcf).................. 27,839 20,142 15,578
Natural gas equivalent (MMcfe)...... 35,457 28,563 28,856
AVERAGE PRICES:
Oil ($/Bbl)......................... $ 28.40 $ 24.97 $ 24.67
Natural gas ($/Mcf)................. $ 5.98 $ 5.07 $ 3.36
Natural gas equivalent ($/Mcfe)..... $ 5.71 $ 4.80 $ 3.71
PRODUCTION EXPENSES:
Lease operating expenses ($/Mcfe)... $ 0.40 $ 0.39 $ 0.41
Severance and ad valorem
Taxes ($/Mcfe)...................... $ 0.26 $ 0.27 $ 0.29
-7-
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, 2004.
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, 2004
---------------------------------
DEVELOPED UNDEVELOPED
--------------- ---------------
REGION GROSS NET GROSS NET
------ ------ ------ ------ ------
LOUISIANA........ 33,305 19,632 38,673 34,618
GULF OF MEXICO... 34,518 6,098 7,500 5,033
------ ------ ------ ------
TOTAL......... 67,823 25,730 46,173 39,651
====== ====== ====== ======
In addition to the above acreage, we currently have options or farm-ins to
acquire leases on approximately 185,806 gross (163,748 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. Our undeveloped acreage, including optioned
acreage, expires during the next three years at the rate of 154,000 acres in
2005, 12,000 acres in 2006, and 26,000 acres in 2007.
GEOLOGIC/LAND AND OPERATIONS GEOPHYSICAL EXPERTISE
Meridian employs approximately 68 full-time non-union employees and six contract
employees. This staff includes geologists, geophysicists, land and engineering
staff with over 480 combined years of experience in generating and developing
onshore and offshore prospects in the Louisiana and Texas Gulf Coast region. Our
geologists and geo-physicists 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 2004, 2003 and 2002.
YEAR ENDED DECEMBER 31,
-----------------------
CUSTOMER 2004 2003 2002
-------- ---- ---- ----
Superior Natural Gas........ 45% 19% --
Louisiana Intrastate Gas.... 22% 24% 17%
Conoco, Inc................. -- 10% 12%
Equiva Trading Company(1)... -- -- 33%
(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.
-8-
MARKET CONDITIONS
Our revenues, profitability and future rate of growth substantially depend on
prevailing prices for oil and natural gas. Oil and natural gas prices have been
extremely volatile in recent years and are affected by many factors outside our
control. Since 1993, prices for West Texas Intermediate crude have ranged from
$8.00 to $53.09 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, 2004, was $5.71 per Mcfe
compared to $4.80 per Mcfe during the year ended December 31, 2003. 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 is beyond our control and
therefore represent significant risks.
-9-
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.
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.
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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 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
-11-
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.
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 principal federal statute governing the treatment, storage
and disposal of hazardous wastes. RCRA imposes
-12-
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 75% of our present value of proved properties. Our own
oil and natural gas properties also typically are subject to royalty and other
similar noncost-bearing interests customary in the industry.
We acquired substantial portions of our 3-D seismic data through licenses and
other similar arrangements. Such licenses contain transfer and other
restrictions customary in the industry.
-13-
ITEM 2. PROPERTIES
PRODUCING PROPERTIES
For information regarding Meridian's properties, see "Item 1. Business" above.
ITEM 3. LEGAL PROCEEDINGS
PETROQUEST LITIGATION. This litigation was settled in December 2003 and all
claims were dismissed. In December 1999, PetroQuest Energy, Inc. (formerly known
as Optima Energy (U.S.) Corporation) ("PetroQuest") filed a claim against
Meridian for damages "estimate[d] to exceed several million dollars" alleging
that Meridian was liable for gross negligence and willful misconduct in the
execution of certain agreements related to property in the S.W. Holmwood and E.
Lake Charles Prospects in Calcasieu Parish and for an alleged withholding of
funds totaling $886,153.31, in conjunction with Meridian's having paid 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. Under the confidential settlement agreement,
Meridian agreed 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. This litigation was settled in March 2004 and all claims
were dismissed. Three different groups asserted adverse title claims to some or
all of Section 80 (640 acres) within Meridian's Thibodaux units in the Ramos
Field. Another entity asserted adverse title claims to a portion of Section 36
within these same units. These claims turned primarily on the location of the
parish boundary lines between Terrebonne and Assumption Parishes and/or the
validity of various tax sales in the chain of title. Meridian's gas purchaser,
Louisiana Intrastate Gas Company LLC ("LIG"), 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 suspended payment of
royalties and working interest attributable to these same 25 acres since
December 2000. Meridian and its partners and royalty owners reached an agreement
whereby the parties' plaintiff granted a lease on all of the disputed acreage to
the current interest owners for a lease bonus of $4.5 million and a future
royalty interest of 1.5%.
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated 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, as a result of Meridian's satisfying
a prior adverse judgment in favor of Amoco Production Company. Meridian will
file an answer denying Hawkins' claims and assert a counterclaim for attorney's
fees, court costs and other expenses, and for declaratory relief that Meridian
is entitled to retain the amounts that it had been paid by Hawkins. The Company
has not provided any amount for this matter in its financial statements at
December 31, 2004.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in various similar lawsuits concerning the Weeks
Island, Gibson, Bayou Pigeon, West Lake Verret and White Castle 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 which exceed our insurance limits
to which the Company 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.
-14-
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the annual meeting of shareholders held on October 27, 2004, the Company's
shareholders elected three Class I Directors, three Class II Directors and one
Class III Director. The following summarizes the number of votes for and against
each nominee:
Broker
Nominee For Withheld Non-Vote
- --------------------------- ---------- --------- ---------
David W. Tauber (I) 72,088,348 2,325,337 4,225,809
John B. Simmons (I) 72,082,852 2,330,833 4,225,809
James R. Montague (I) 72,751,131 1,662,554 4,225,809
E. L. Henry (II) 72,747,701 1,665,984 4,225,809
Joe E. Kares (II) 71,071,018 3,342,667 4,225,809
Gary A. Messersmith (II) 71,368,967 3,044,718 4,225,809
Fenner R. Weller, Jr. (III) 71,982,852 2,430,833 4,225,809
Directors Joseph A. Reeves, Jr. and Michael J. Mayell are not up for re-election
for another three-year term until the 2005 annual meeting.
Also at the 2004 annual meeting, shareholders voted on a shareholder proposal
that the Company nominate at least two candidates for each Board of Directors
position to be voted on by the shareholders. The proposal did not receive the
requisite number of votes for approval. The following summarizes the number of
votes for and against such proposal.
Broker
For Against Abstain Non-Vote
- --------- ---------- ------- ----------
9,265,077 28,160,038 274,071 36,714,499
-15-
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
----- -----
2004:
First quarter .... $6.37 $5.21
Second quarter ... 7.55 6.13
Third quarter .... 8.97 6.89
Fourth quarter ... 8.95 5.52
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
The closing sale price of the Common Stock on March 1, 2005, as reported on the
New York Stock Exchange Composite Tape, was $6.01. As of March 1, 2005, we had
approximately 790 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 any cash dividends on
Common Stock or for purchase of shares of Common Stock without the prior consent
of the lender.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth information as of December 31, 2004, with respect
to our compensation plans (including individual compensation arrangements) under
which equity securities are authorized for issuance:
Number of securities
remaining available for
Number of securities to Weighted-average future issuance under
be issued upon exercise exercise price of equity compensation plans
of outstanding options, outstanding options, (excluding securities
Plan Category warrants and rights warrants and rights reflected in column (a)(1))
- ------------------------------- ----------------------- -------------------- ---------------------------
Equity compensation plans
approved by security holders 6,725,478 $3.60 1,670,685
Equity compensation plans not
approved by security holders -- -- --
--------- ----- ---------
Total 6,725,478 $3.60 1,670,685
========= ===== =========
(1) Does not include 3,600,000 shares which have been reserved for issuance in
lieu of cash compensation under the Company's deferred compensation plan,
which plan was approved by security holders.
-16-
ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with our Consolidated Financial
Statements and related notes thereto included in Item 8 and elsewhere in this
report.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2004 2003 2002 2001 2000
-------- -------- -------- -------- --------
(In thousands, except prices and per share information)
A. SUMMARY OF OPERATING DATA
Production:
Oil (MBbls) 1,270 1,403 2,213 2,918 3,987
Natural gas (MMcf) 27,839 20,142 15,578 22,085 27,672
Natural gas equivalent (MMcfe) 35,457 28,563 28,856 39,594 51,596
Average Prices:
Oil ($/Bbl) $ 28.40 $ 24.97 $ 24.67 $ 25.17 $ 27.32
Natural gas ($/Mcf) 5.98 5.07 3.36 4.67 4.14
Natural gas equivalent ($/Mcfe) 5.71 4.80 3.71 4.46 4.33
B. SUMMARY OF OPERATIONS
Total revenues $203,118 $137,479 $107,470 $178,060 $226,246
Depletion and depreciation 102,915 75,441 60,972 67,450 69,648
Net earnings (loss)(1) 29,248 7,246 (52,012) 22,551 65,070
Net earnings (loss) per share:(1)
Basic $ 0.41 $ 0.14 $ (1.05) $ 0.47 $ 1.34
Diluted 0.37 0.13 (1.05) 0.43 1.06
Dividends per:
Common share -- -- -- -- --
Redeemable preferred share $ 8.50 $ 8.50 $ 5.90 -- --
Preferred share $ -- $ -- $ -- $ 0.11 $ 1.36
Weighted average common
shares outstanding - Basic 72,084 53,325 49,763 48,350 48,646
C. SUMMARY BALANCE SHEET DATA
Total assets $512,392 $448,400 $456,240 $507,900 $570,921
Long-term obligations, inclusive
of current maturities 75,129 152,320 203,750 210,000 250,000
Redeemable preferred stock 31,589 60,446 69,690 -- --
Stockholders' equity 316,041 184,335 133,393 188,221 270,322
(1) Applicable to common stockholders.
-17-
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.
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 1992-2004, 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 8,000 square miles of 3-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, development
and acquisition of a risk balanced portfolio of high potential projects;
- - 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 rigorous methodology utilizing 3-D seismic technology in the
generation and development of lower risk exploration prospects, maximize
our probability of success, optimize well locations and reduce our finding
costs;
- - Maximize percentage ownership in each drilling prospect relative to
probability of success, increasing the impact of discoveries on shareholder
value; and
- - Maintain operational control to manage quality, costs and timing of our
drilling and production activities.
-18-
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.
As of December 31, 2004, we had proved reserves of 139 Bcfe, approximately 73%
of which were natural gas, with a present value of future pre-tax cash flows
(PV-10) of $545 million. We own interests in approximately 300,000 gross
(229,000 net) acres, including 18 fields and 103 wells, and we operate
approximately 87% of our total production.
Our reserves, strategic acreage position and 2-D and 3-D seismic data base
provide us with a significant presence in our areas of focus, enabling us to
exploit a large asset base adding to our multi-year prospect inventory of
exploratory and development plays and prospects, at a low incremental costs
relative to our competition. We own over 8,000 square miles of 3-D seismic data.
It is no accident that we have focused in the Gulf Coast region of southeast
Texas and south Louisiana. Although we have drilled and operated in over 12
states and almost every producing basin in the domestic United
States--Appalachia, Mid-Continent, Rocky Mountains, Arkoma, west Texas, south
Texas, Louisiana and the Gulf of Mexico shelf. We chose this particular province
because it presented the greatest opportunity for growth though exploration and
exploitation. Complex geological fault traps capable of being resolved with 3-D
seismic and computer-aided technology by a company willing to adopt it earlier
than others, meant opportunities for by-passed reserves. Highly prolific,
potentially stacked producing sands with high producing rates compared to other
regions meant lower risk for failure and quicker return of investments from
successful wells. We were successful with our efforts generating and/or
participating in the discovery of over 800 Bcfe.
Yet, we recognized that long lead times were required to generate deep
exploration targets and that the ability to use the technology to place the
wells in optimum positions, high on structures and within traps frequently
resulted in single well prospects that required a continual treadmill of
exploration prospecting. The result was a perception of greater risk to replace
high flow rates and returns with a 4-7 year reserve life rather than the much
lower-rate, longer lived plays in other regions. During 2002, we expanded our
business plan to include lower-risk, multiple-well "play" opportunities using
the seismic technology to identify what we believe are hydrocarbon indicators in
shallower sections than we have historically drilled. To date, we have been
successful in the generation and development of several such plays, the first of
which was the Company's Thornwell field in Cameron Parish, Louisiana during
1999.
Since that time, we have successfully added our Biloxi Marshlands project area,
a play that has expanded and complemented our exploration strategy with a
uniquely large play that essentially gives Meridian control over approximately
400,000 contiguous acres with proprietary 3-D seismic covering over 400 square
miles. We have used these resources to identify multiple shallower, low-risk
prospects in the area we believe will extend our drilling and producing
operations for several years. The successful drilling and resulting increases in
production and cash flows from this play, together with the convergence of
higher commodity prices, has significantly improved the financial condition of
the Company, its capital structure, balance sheet and liquidity, all of which
combined with our large prospect inventory, provide the Company with the
potential for a very promising 2005. These include -
- Earnings per share applicable to common shareholders increased by
306%.
- Average daily production increased by 24% on a Mcf equivalent basis.
-19-
- Total revenues increased by 48% to $203.1 million.
- Discretionary cash flow increased by 59%, or $59.2 million to $159.8
million.
- Net cash provided by operating activities increased by 87% to $171.5
million.
- Debt to total capitalization declined to 18%.
There has been a lot of talk about the Biloxi Marshlands play recently--its
merits and future opportunity. Simply put, Biloxi is a cornerstone project for
the Company, one that not only confirmed our decision that we could reduce our
exploration risk profile in an area that was written off by many as
over-explored, but also one that has served as a prelude to the other similar
plays that we believe exist throughout our region of focus and where we own over
8,000 square miles of 3-D seismic data. Since inception in 2003, we have drilled
31 wells at Biloxi. Of them, 20 have been completed as producers with 10 wells
either plugged and abandoned or determined to be uneconomic, and one well
currently drilling. We have purchased and acquired public and proprietary 3-D
seismic data in the area totaling over 700 square miles, with plans to shoot an
additional 137 square miles during 2005. With over 400 square miles of 3-D
seismic proprietary data, we have been successful at State of Louisiana lease
sales with the purchase of 103 of the 105 state tracts bid on, resulting in the
acquisition of approximately 23,087 acres of state water bottoms over geological
leads identified by the Company.
Since December 2002, when we acquired our first land and seismic positions at
Biloxi, the Company has expended a total of approximately $147 million for all
land, seismic, drilling and completions, production facilities and pipelines,
over both evaluated and unevaluated areas. We have received net field cash flow
since first production in March 2003, or under two years, of $129 million.
Biloxi Marshlands represents a major and unique expansion of our Company's
exploration efforts in our region of focus. The project represents the reality
of a vision expanded by the hard work by a team of highly skilled and
knowledgeable professionals who made a commitment to redefine an exploration
plan that has positioned our Company to move forward to new and similar
multiple-prospect, multiple well, lower-risk exploration opportunities as the
industry experiences a declining domestic reserve base.
Management is committed to exploring the entire position in this play ensuring
our knowledge base for elections of acreage positions prior to the expiration of
our option period. With the extensions to the south and east of our original
discovery at Atlas, we have successfully developed new and better processing and
interpretive techniques that have provided a higher level of confidence for our
future drilling efforts, not only at Biloxi but also as we have taken and
applied them to other in-house surveys and extended the exploratory concept in
our region, our back-yard.
With this knowledge base and experience base, we have defined multiple other
such prospect opportunities which will be drilled and tested during 2005 and
which we believe have similar trapping conditions and producing characteristics
as Biloxi. The Company has set its capital budget at approximately $140 million
for new prospect opportunities ranging in depths from shallow to deep, exposing
the Company to unrisked reserves of approximately 200 Bcfe.
Review of 2004. During 2004, the Company focused on corporate
fundamentals--financial, seismic, land and production. The Company reduced total
debt by $77.2 million, reducing its Senior Bank facility from $122.3 million to
$75.1 million and sub-debt in full from $20 million. In addition, outstanding
Preferred Stock was reduced from a high of $72 million in stated value of shares
outstanding, to approximately $31.6 million as a result of conversions to common
stock. By year end 2004, the Company's debt to book capitalization had been
reduced from 38% to 18%.
During 2004, 20 wells were brought on line, increasing the 2003 average
production from 78.3 Mmcfe per day to 96.9 Mmcfe per day or a 24% increase.
During 2005, Meridian expects to further increase its reserves,
-20-
production cash flow and earnings as a result of its strong inventory of
prospects and 3-D data base.
Recent Developments. In furthering its focus on organic growth, the Company is
continuing to develop its Biloxi Marshlands and similar plays in south
Louisiana. Currently the Company's South Apollo prospect is expected to be
placed on production within 10-15 days; the Turtle Island Well is expected to be
placed on production within 30 days; the Hornet 5 Well has been drilled to its
total depth and is expected to be logged and tested during March 2005.
During the last several months, the Company has participated in several State of
Louisiana oil and gas lease sales and during 2004 successfully bid on 103 of 105
additional tracts in the area, covering 23,088 acres in and around our current
lease holdings. It is believed that our high rate of success is because we hold
the only proprietary 3-D seismic over the 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
2005. This approximately 137-square mile 3-D seismic survey is expected to be
completed in May 2005. Although Meridian's focus is currently on the Cris I
geological time horizon, the survey is designed to look at all shallow and deep
objectives.
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, 2004 was $5.71 per Mcfe compared to $4.80 per Mcfe during the
year ended December 31, 2003. 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., Quantitative and
Qualitative Disclosures about Market Risk, 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.
-21-
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2004, COMPARED TO YEAR ENDED DECEMBER 31, 2003
Oil and natural gas revenues, which include oil and natural gas hedging
activities (see note 12 of notes to consolidated financial statements), during
the twelve months ended December 31, 2004, increased $65.3 million (48%) as
compared to 2003 revenues due primarily to a 24% increase in production volumes
primarily from the Company's previously announced drilling results in the Biloxi
Marshlands ("BML") project area and Weeks Island, coupled with successful
workover operations in the Company's Ramos and Weeks Island fields, partially
offset by natural production declines and property sales during 2003. Further,
revenues were enhanced by a 19% increase in average commodity prices on a
natural gas equivalent basis. Drilling and workover success increased our
average daily production from 78.3 Mmcfe during 2003 to 96.9 Mmcfe for 2004. Oil
and natural gas production volume totaled 35,457 Mmcfe for 2004, compared to
28,563 Mmcfe for 2003. During 2004, the Company's drilling activity was
primarily focused in the Biloxi Marshlands ("BML") project area and the Weeks
Island field. During 2004, the Company drilled or participated in the drilling
of 31 wells of which 20 wells were completed and placed on production,
representing a 65% success rate. The following table summarizes Meridian's
operating revenues, production volumes and average sales prices for the years
ended December 31, 2004 and 2003.
Year Ended
December 31,
------------------- Increase
2004 2003 (Decrease)
-------- -------- ----------
Production:
Oil (MBbls) 1,270 1,403 (10%)
Natural gas (MMcf) 27,839 20,142 38%
Natural gas equivalent (MMcfe) 35,457 28,563 24%
Average Sales Price:
Oil (per Bbl) $ 28.40 $ 24.97 14%
Natural gas (per Mcf) 5.98 5.07 18%
Natural gas equivalent (per Mcfe) 5.71 4.80 19%
Operating Revenues (000's):
Oil $ 36,060 $ 35,032 3%
Natural gas 166,387 102,092 63%
-------- -------- ---
Total $202,447 $137,124 48%
======== ======== ===
Operating Expenses.
Oil and natural gas operating expenses on an aggregate basis increased $2.7
million (25%) to $14.0 million in 2004, compared to $11.3 million in 2003. On a
unit basis, lease operating expenses increased $0.01 per Mcfe to $0.40 per Mcfe
for the year 2004 from $0.39 per Mcfe for the year 2003. Oil and natural gas
operating expenses increased primarily due to additional operating expenses
associated with new wells and facilities in the BML project area and to
increased workover activity in the Weeks Island, Ramos and Turtle Bayou fields
during the year, partially offset by savings resulting from sold properties in
the latter portion of 2003, combined with other cost savings initiated during
the current year. In 2005, we expect our anticipated future increases in
production to result in a continued reduction in operating costs on a per unit
level.
Severance and Ad Valorem Taxes.
Severance and ad valorem taxes increased $1.8 million (23%) to $9.4 million in
2004, compared to $7.6 million in 2003, primarily because of an increase in
natural gas production and a higher natural gas tax rate,
-22-
partially offset by a tax refund from Louisiana for prior periods. Meridian's
oil and natural gas production is primarily from Louisiana and is therefore
subject to Louisiana severance tax. The severance tax rates for Louisiana are
12.5% of gross oil revenues and $0.208 per Mcfe (effective July 1, 2004) for
natural gas. For the first six months of 2004, and the last six months of 2003,
the rate was $0.171 per Mcf for natural gas, an increase from $0.122 per Mcf for
the first half of 2003. On an equivalent unit of production basis, severance and
ad valorem taxes decreased to $0.26 per Mcfe for 2004 from $0.27 per Mcfe for
2003, reflecting a tax refund from Louisiana for prior periods. The per Mcfe
cost for 2005 will increase due to a higher anticipated average severance tax
rate than what was experienced in 2004.
Depletion and Depreciation.
Depletion and depreciation expense increased $27.5 million (36%) during 2004 to
$102.9 million compared to $75.4 million for 2003. This was primarily the result
of the 24% increase in production volumes in 2004 over 2003 levels, and an
increase in the depletion rate as compared to the 2003 period. On a unit basis,
depletion and depreciation expenses increased to $2.90 per Mcfe for 2004,
compared to $2.64 per Mcfe for 2003. We are expecting a downward trend in our
2005 depletion rate as we find and develop new reserves during the year.
General and Administrative Expense.
General and administrative expenses, which are net of costs capitalized in our
oil and gas properties (see note 18 of notes to consolidated financial
statements), increased $3.6 million (31%) to $15.2 million in 2004 compared to
$11.6 million for the year 2003, primarily due to an increase in accounting and
professional fees associated with implementing the expanded compliance burden
required by the Sarbanes-Oxley Act of 2002, an increase in insurance costs
primarily due to additional coverage and to increased production activity. On an
equivalent unit of production basis, general and administrative expenses
increased $0.02 per Mcfe to $0.43 per Mcfe for 2004 compared to $0.41 per Mcfe
for 2003. In 2005, we anticipate a reduction in accounting and professional
fees.
Interest Expense.
Interest expense decreased $4.3 million (38%) to $7.2 million in 2004 compared
to $11.5 million for 2003. The decrease was primarily a result of the reduction
in long-term borrowings. With the conversion of the $20 million convertible
subordinated notes into common stock and the 2004 net repayments of $57.2
million on our long-term debt, the Company will realize additional future
savings in interest. The reduction in long-term debt was partly the result of
our August 2004 common stock offering.
Taxes on Income.
The provision for income taxes for 2004 was $19.3 million as compared to $4.2
million for 2003. 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 in 2003.
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 began recording long-term liabilities
representing the discounted present value of the estimated asset retirement
obligations with offsetting increases in capitalized oil and gas properties.
This liability will continue to be accreted to its future value in subsequent
reporting periods. The Company has charged approximately $0.6 million and $0.7
million to earnings as accretion expense during 2004 and 2003, respectively. In
2003, 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 cumulative
effect of the change in accounting principle for 2003 totaled $1.3 million or
$0.02 per share, and was charged to earnings in 2003.
-23-
YEAR ENDED DECEMBER 31, 2003, COMPARED TO YEAR ENDED DECEMBER 31, 2002
Oil and natural gas revenues, which include oil and natural gas hedging
activities (see note 12 of notes to consolidated financial statements),
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%
Operating 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 reflected
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.
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 was 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.
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 was
primarily a result of the 2002 impairment of long-lived assets mentioned below.
-24-
General and Administrative Expense.
General and administrative expenses, which are net of costs capitalized in our
oil and gas properties (see note 18 of notes to consolidated financial
statements), decreased $0.2 million to $11.6 million in 2003 compared to $11.8
million for the year 2002. 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. 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 was 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 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.
Credit Facility Retirement Costs.
During August 2002, the Company replaced its Chase Manhattan Bank Credit
Facility with a 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 was $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.
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.
-25-
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS. Net cash flows provided by operating activities were $171.2 million
for the year ended December 31, 2004, as compared to $91.6 million for the year
ended December 31, 2003, an increase of $79.6 million or 87%. This increase was
primarily attributable to a $65.3 million increase in revenue due to production
and commodity price increases. The year-over-year change in operating assets and
liability from December 31, 2003, to December 31, 2004, also accounted for
approximately $12 million of increase in net cash flows provided by operating
activities.
Net cash flows used in investing activities were $142.5 million for the year
ended December 31, 2004, as compared to $67.0 million for the year ended
December 31, 2003. The increase was due to an increase in capital expenditures
of $70.5 million.
Net cash flows used in financing activities were $17.2 million for the year
ended December 31, 2004, as compared to net cash flows used in financing
activities of $19.1 million for 2003. During 2004, the Company retired $58.3
million in long-term debt and paid $5.2 million of preferred stock dividends,
partially offset by the $45.8 million raised by selling common stock.
COMMON STOCK. In August 2004, the Company completed a public offering of
13,800,000 shares of Common Stock at a price of $7.25 per share. The total
proceeds of the offering, net of issuance costs, received by the Company were
approximately $94.6 million. The Company repurchased all of the 7,082,030 shares
of its Common Stock that were beneficially owned by Shell Oil Company for $49.3
million and a portion of the remaining proceeds of that equity offering were
used to repay borrowings under the Company's senior secured credit agreement,
which resulted in an increase in funds available to the Company to accelerate
planned capital expenditures for drilling activities and related pipeline
construction. The repurchased 7,082,030 shares of Common Stock that were held in
Treasury Stock were retired as of September 30, 2004.
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-term debt, with the remainder of the proceeds being used for exploration
activities and other general corporate purposes. As discussed below, during the
nine months ended September 30, 2004, approximately 6.5 million shares of common
Stock and approximately 4.2 million shares of Common stock were issued for the
early conversion and retirement of the 9 1/2 % Convertible Subordinated Notes.
CURRENT CREDIT FACILITY. On December 23, 2004, the Company amended its existing
credit facility to provide for a four-year $200 million senior secured credit
facility (the "Credit Facility") with Fortis Capital Corp., as administrative
agent, sole lead arranger and bookrunner; Comerica Bank as syndication agent;
and Union Bank of California as documentation agent. Bank of Nova Scotia and
Allied Irish Banks p.l.c. completed the syndication group. The initial borrowing
base under the Credit Facility is $130 million. As of December 31, 2004,
outstanding borrowings under the Credit Facility totaled $75.1 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its present value of
proved oil and gas properties. In addition, the Company is required to deliver
to the lenders and maintain satisfactory title opinions covering not less than
70% of the present value of proved oil and gas properties. The Credit Facility
also contains other restrictive covenants, including, among other items,
maintenance of certain financial ratios, restrictions on cash dividends on
Common Stock and under certain
-26-
circumstances Preferred Stock, limitations on the redemption of Preferred Stock
and an unqualified audit report on the Company's consolidated financial
statements, with all of which the Company is in compliance.
Under the Credit Facility, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus 1/2
of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base 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 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At December 31, 2004, the three-month LIBOR interest rate
was 2.56%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Credit Facility.
FORMER CREDIT FACILITY. During August 2002, the Company replaced its Chase
Manhattan Bank Credit Facility with a three-year $175 million underwritten
senior secured credit agreement (the "Former 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 Former Credit Agreement were to mature on November 15, 2005, as
extended by an amendment dated November 8, 2004. The amendment was subject to an
extension fee of $450,000 to be paid in the event the Credit Facility had not
been paid or refinanced by January 3, 2005.
The borrowing base was set at $127.5 million effective on October 31, 2004.
Credit Facility payments of $48.3 million were made during the first nine months
of 2004, bringing the outstanding balance to $74 million as of September 30,
2004. The Company made a final debt repayment of $74 million on December 23,
2004, which paid off in full this loan agreement.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders or borrower, under the Former Credit Agreement, had the right to
redetermine the borrowing base at any time, once during each calendar year.
Borrowings under the Former Credit Agreement were 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. On October 25, 2004, the Company notified Societe Generale
that the present value of the mortgaged oil and gas properties total 86%. The
Company received a waiver of the 90% test in anticipation of the new Fortis
senior secured credit facility requiring only a 75% mortgage test. The Former
Credit Agreement contained 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.
Under the Former Credit Agreement, the Company could have secured either (i) (a)
an alternative base rate loan that bears interest at a rate per annum equal to
the greater of the administrative agent's prime rate; or (b) federal funds-based
rate plus 0.5%, 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; (ii)
a Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. The Former Credit Agreement also provided 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 were
unsecured and contained customary events of default, but did not contain any
maintenance or other restrictive covenants. The interest rate was 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, 2004, the
three-month LIBOR rate was 2.56%. Note payments totaling $6.25 million were paid
in 2002, with an additional $8.75 million paid in 2003. A note payment of $5
million was made during April 2004, with the remaining $5 million paid in
December 2004.
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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 were unsecured and contained
customary events of default, but did not contain any maintenance or other
restrictive covenants. Interest was payable on a quarterly basis. The Company
was 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 were 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 was
subject to customary anti-dilution provisions. The holders of the Notes were
granted registration rights with respect to the shares of Common Stock that
would be issued upon conversion of the Notes.
During March 2004, the notes were converted into 4.0 million shares of the
Company's Common Stock at a conversion price of $5.00 per share, and included an
additional non-cash conversion expense of approximately $1.2 million that was
incurred and paid via the issuance of Common Stock priced at market. All of the
Common Stock issued in connection with the conversion of the notes was issued
under Section 4(2) of the Securities Act.
8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. A private placement under Section
4(2) and Regulation D of the Securities Act 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. 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 June 2004, the Company exercised its right, as described above, to convert
one-third of its remaining issued and outstanding preferred stock into shares of
Common Stock. The conversion was completed on a pro-rata basis and included a
cash payment for accrued and unpaid dividends through the June 8, 2004,
conversion date, at which time dividends ceased to accrue on the converted
shares. During the year 2004, a total of $28.9 million of preferred stock was
converted into 6.5 million shares of Common Stock.
CAPITAL EXPENDITURES. Capital expenditures in 2004 consisted of $142 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 2005 capital expenditures plan is currently forecast at approximately $140
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 2005 plan primarily utilizing cash flow from operations.
When appropriate, excess cash flow from operations beyond that needed for the
2005 capital expenditures plan will be used to de-lever the Company by
development of exploration discoveries or direct payment of debt.
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
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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, 2004 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 $ 870 $ -- $75,129 $ 75,999
Interest 3,381 6,762 3,306 13,449
Dividends 2,685 5,370 3,356 11,411
Non-cancelable operating leases 2,537 1,847 25 4,409
------ ------- ------- --------
Total contractual cash obligations $9,473 $13,979 $81,816 $105,268
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.
For the year ended December 31, 2004, $3.5 million of dividends were accumulated
(net of $0.4 million of deferred preferred stock offering costs amortized during
2004), of which $2.2 million was paid in cash in July 2004 and $1.3 million was
paid in cash in January 2005. 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
(net of $0.4 million of deferred preferred stock offering costs amortized 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.
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 2004, 2003, and 2002,
such capitalized costs totaled $11.9 million, $10.0 million, and $11.7 million,
respectively. General and administrative costs related to production and general
overhead are expensed as incurred.
-29-
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.
Due to the 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 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
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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 two years ended December 31, 2003, and a gain of $126,000 during the year
ended December 31, 2004.
During the year ended December 31, 2004, the change in estimated fair value of
the Company's oil and natural gas swaps was an unrealized loss of $2.4 million
($1.6 million net of tax) which is recognized in other comprehensive income.
Based upon December 31, 2004, oil and natural gas commodity prices,
approximately $2.4 million of the loss deferred in other comprehensive income
could potentially lower gross revenues in 2005. The swap agreements expire at
various dates through October 31, 2005.
Net settlements under these swap agreements reduced oil and natural gas revenues
by $18,624,000 and $14,916,000 and $1,183,000 for the years ended December 31,
2004, 2003, and 2002, respectively.
See Item 7.A., Quantitative and Qualitative Disclosures about Market Risk, 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, 2004 and 2003, 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 value of our subordinated notes due 2005 was $19.6
million at December 31, 2003. The carrying value of our subordinated notes was
$20 million at December 31, 2003.
NEW ACCOUNTING PRONOUNCEMENTS. On September 28, 2004, the SEC released Staff
Accounting Bulletin ("SAB") 106 regarding the application of SFAS 143,
"Accounting for Asset Retirement Obligations ("AROs")," by oil and gas producing
companies following the full cost accounting method. Pursuant to SAB 106, oil
and gas producing companies that have adopted SFAS 143 should exclude the future
cash outflows associated with settling AROs (ARO liabilities) from the
computation of the present value of estimated future net revenues for the
purposes of the full cost ceiling calculation. In addition, estimated
dismantlement and abandonment costs, net of estimated salvage values, that have
been capitalized (ARO assets) should be included in the amortization base for
computing depreciation, depletion and amortization expense. Disclosures are
required to include discussion of how a company's ceiling test and depreciation,
depletion and amortization calculations are impacted by the adoption of SFAS
143. SAB 106 is effective prospectively as of the beginning of the first fiscal
quarter beginning after October 4, 2004. Since our adoption of SFAS 143 on
January 1, 2003, we have calculated the ceiling test and our depreciation,
depletion and amortization expense in accordance with the interpretations set
forth in SAB 106; therefore, the adoption of SAB 106 had no effect on our
financial statements.
In December 2004, the FASB issued SFAS No. 123R which is a replacement statement
to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS
Statement 95. This statement addresses
-31-
the accounting for share-based payment transactions in which an enterprise
receives employee services in exchange for (a) equity instruments of the
enterprise or (b) liabilities that are based on the fair value of the
enterprise's equity instruments or that may be settled by the issuance of such
equity instruments. The statement would eliminate the ability to account for
share-based compensation transactions using APB Opinion No. 25, "Accounting for
Stock Issued to Employees," and generally would require instead that such
transactions be accounted for using a fair-value-based method. This statement
would be effective for interim periods beginning after June 15, 2005. The impact
on the results of operations would be similar to the pro forma disclosures
included in the notes to the 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.
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 may be imprecise. Therefore, we cannot assure you that all of our
drilling
-32-
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 available
data and of engineering and geological interpretation and judgment. Reserve
estimates may be 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. The quantities of oil and natural gas that we
ultimately recover, production and operating costs, the amount and timing of
future development expenditures and future oil and natural gas sales prices may
differ from those assumed in these estimates. Significant downward revisions to
our existing reserve estimates could cause the actual results to differ from
those reflected in our forward-looking statements.
Borrowing base for the Credit Facility. The Credit Agreement with Fortis Capital
Corp. is presently scheduled for borrowing base redetermination dates on a
semi-annual basis, with the next such redetermination scheduled for April 30,
2005. 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.
-33-
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. 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 $75.1 million remains borrowed under the Credit Facility, we
estimate our annual interest expense will change by $0.75 million for each 100
basis point change in the applicable interest rates utilized under the Credit
Facility.
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.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 41% of our proved developed natural gas production and 38% of our
proved developed oil production during the respective terms of the hedging
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.
The fair value of our hedging agreements is recorded on our consolidated balance
sheet as assets or liabilities. The estimated fair value of our hedging
agreements as of December 31, 2004, is provided below (see the Company's
website at www.tmrc.com for a quarterly breakdown of the Company's hedge
position for 2005 and beyond):
Fair Value
Swap / Floor Ceiling December 31,
Notional Price Price 2004
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ------------ --------------
NATURAL GAS (MMBTU)
Jan 2005 - Jun 2005 Swap 910,000 $ 3.74 N/A $(2,175)
Apr 2005 - Oct 2005 Swap 2,610,000 $ 6.34 N/A 492
Jan 2005 - Mar 2005 Collar 2,970,000 $ 7.00 $13.00 2,942
Apr 2005 - Oct 2005 Collar 2,600,000 $ 6.50 $ 7.90 1,751
-------
Total Natural Gas 3,010
-------
CRUDE OIL (BBLS)
Jan 2005 - Jul 2005 Swap 266,000 $23.00 N/A (5,308)
-------
Total Crude Oil (5,308)
-------
$(2,298)
=======
-34-
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.
"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.
"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%.
-35-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements
Below is an index to the financial statements and notes contained in Financial
Statements and Supplementary Data.
Page
----
Reports of Independent Registered Public Accounting Firms................ 37
Consolidated Statements of Operations.................................... 39
Consolidated Balance Sheets.............................................. 40
Consolidated Statements of Cash Flows.................................... 42
Consolidated Statements of Stockholders' Equity.......................... 43
Consolidated Statements of Comprehensive Income (Loss)................... 44
Notes to Consolidated Financial Statements............................... 45
1. Organization and Basis of Presentation.......................... 45
2. Summary of Significant Accounting Policies...................... 45
3. Asset Retirement Obligations.................................... 50
4. Impairment of Long-lived Assets................................. 51
5. Debt............................................................ 51
6. Lease Obligations............................................... 53
7. Commitments and Contingencies................................... 53
8. Taxes on Income................................................. 55
9. 8.5% Redeemable Convertible Preferred Stock..................... 57
10. Stockholders' Equity............................................ 57
11. Profit Sharing and Savings Plan................................. 60
12. Oil and Natural Gas Hedging Activities.......................... 62
13. Major Customers................................................. 63
14. Related Party Transactions...................................... 63
15. Earnings Per Share.............................................. 65
16. Accrued Liabilities............................................. 65
17. Subsequent Event................................................ 66
18. Quarterly Results of Operations (Unaudited)..................... 66
19. Supplemental Oil and Natural Gas Disclosures (Unaudited)........ 67
-36-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors
The Meridian Resource Corporation
We have audited the accompanying consolidated balance sheets of The Meridian
Resource Corporation and subsidiaries as of December 31, 2004 and 2003, and the
related consolidated statements of operations, stockholders' equity, cash flows,
and comprehensive income (loss) for the years 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 audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of The Meridian
Resource Corporation and subsidiaries at December 31, 2004 and 2003, and the
results of their operations and their cash flows for the years 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 10, 2005
-37-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
The Meridian Resource Corporation
We have audited the accompanying consolidated statements of operations,
stockholders' equity, and cash flows of The Meridian Resource Corporation and
subsidiaries for the year 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 the standards of the Public Company
Accounting Oversight Board (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 audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated results of operations and cash flows of
The Meridian Resource Corporation and subsidiaries for the year ended December
31, 2002, in conformity with U.S. generally accepted accounting principles.
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
-38-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share data)
YEAR ENDED DECEMBER 31,
------------------------------
2004 2003 2002
-------- -------- --------
REVENUES:
Oil and natural gas $202,447 $137,124 $106,992
Price risk management activities 126 -- --
Interest and other 545 355 478
-------- -------- --------
203,118 137,479 107,470
-------- -------- --------
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating 14,035 11,260 11,935
Severance and ad valorem taxes 9,394 7,608 8,235
Depletion and depreciation 102,915 75,441 60,972
General and administrative 15,169 11,610 11,820
Accretion expense 601 667 --
Write-down of securities held 195 -- --
Impairment of long-lived assets -- -- 69,124
-------- -------- --------
142,309 106,586 162,086
-------- -------- --------
EARNINGS (LOSS) BEFORE OTHER EXPENSES & INCOME TAXES 60,809 30,893 (54,616)
-------- -------- --------
OTHER EXPENSES:
Interest expense 7,154 11,496 13,928
Debt conversion expense 1,188 -- --
Credit facility retirement costs -- -- 1,202
-------- -------- --------
8,342 11,496 15,130
-------- -------- --------
EARNINGS (LOSS) BEFORE INCOME TAXES 52,467 19,397 (69,746)
-------- -------- --------
INCOME TAXES:
Current 834 (731) 298
Deferred 18,508 4,980 (22,300)
-------- -------- --------
19,342 4,249 (22,002)
-------- -------- --------
EARNINGS (LOSS) BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 33,125 15,148 (47,744)
Cumulative effect of change in accounting principle -- (1,309) --
-------- -------- --------
NET EARNINGS (LOSS) 33,125 13,839 (47,744)
Dividends on preferred stock 3,877 6,593 4,268
-------- -------- --------
NET EARNINGS (LOSS) APPLICABLE
TO COMMON STOCKHOLDERS $ 29,248 $ 7,246 $(52,012)
======== ======== ========
NET EARNINGS (LOSS) PER SHARE BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE:
Basic $ 0.41 $ 0.16 $ (1.05)
Diluted $ 0.37 $ 0.15 $ (1.05)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE PER SHARE:
Basic and Diluted $ -- $ (0.02) $ --
NET EARNINGS (LOSS) PER SHARE:
Basic $ 0.41 $ 0.14 $ (1.05)
Diluted $ 0.37 $ 0.13 $ (1.05)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic 72,084 53,325 49,763
Diluted 79,033 57,144 49,763
See notes to consolidated financial statements.
-39-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(thousands of dollars)
DECEMBER 31,
-----------------------
2004 2003
---------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 24,297 $ 12,821
Restricted cash 891 --
Accounts receivable, less allowance for doubtful accounts
$242 [2004] and $251 [2003] 27,763 24,703
Prepaid expenses and other 2,263 1,586
Assets from price risk management activities 5,705 584
---------- ----------
Total current assets 60,919 39,694
---------- ----------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$34,731 [2004] and $30,542 [2003] not
subject to depletion) 1,377,649 1,230,643
Land 478 478
Equipment 10,039 9,931
---------- ----------
1,388,166 1,241,052
Less accumulated depletion and depreciation 938,965 836,368
---------- ----------
Total property and equipment, net 449,201 404,684
---------- ----------
OTHER ASSETS 2,272 4,022
---------- ----------
TOTAL ASSETS $ 512,392 $ 448,400
========== ==========
See notes to consolidated financial statements.
-40-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)
DECEMBER 31,
---------------------
2004 2003
--------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 14,983 $ 8,692
Revenues and royalties payable 8,117 12,435
Due to affiliates 3,866 303
Notes payable 870 194
Accrued liabilities 21,406 12,074
Liabilities from price risk management activities 8,003 9,768
Asset retirement obligations 1,331 953
Current income taxes payable 105 415
Current portion long-term debt -- 10,000
--------- ---------
Total current liabilities 58,681 54,834
--------- ---------
LONG-TERM DEBT 75,129 122,320
--------- ---------
9 1/2% CONVERTIBLE SUBORDINATED NOTES -- 20,000
--------- ---------
OTHER:
Deferred income taxes 22,639 931
Liabilities from price risk management activities -- 2,385
Asset retirement obligations 8,293 3,149
Other 20 --
--------- ---------
30,952 6,465
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTES 6, 7 AND 11) -- --
--------- ---------
REDEEMABLE PREFERRED STOCK:
Preferred stock, $1.00 par value (1,500,000 shares authorized,
315,886 [2004] and 604,460 [2003] shares of Series C
Redeemable Convertible Preferred Stock issued at stated value) 31,589 60,446
--------- ---------
STOCKHOLDERS' EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized,
79,215,394 [2004] and 61,724,597 [2003] issued) 821 644
Additional paid-in capital 490,351 394,177
Accumulated deficit (173,244) (202,492)
Accumulated other comprehensive loss (1,574) (7,704)
Unamortized deferred compensation (313) (290)
--------- ---------
Total stockholders' equity 316,041 184,335
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 512,392 $ 448,400
========= =========
See notes to consolidated financial statements.
-41-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
YEAR ENDED DECEMBER 31,
--------------------------------
2004 2003 2002
--------- -------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss) $ 33,125 $ 13,839 $ (47,744)
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 102,915 75,441 60,972
Amortization of other assets 1,506 1,715 2,057
Non-cash compensation 1,577 1,330 1,630
Non-cash price risk management activities (126) -- --
Credit facility retirement costs -- -- 1,202
Debt conversion expense 1,188 -- --
Write-down of securities held 195 -- --
Accretion expense 601 667 --
Impairment of long-lived assets -- -- 69,124
Deferred income taxes 18,508 4,980 (22,300)
Changes in assets and liabilities:
Restricted cash (891) -- --
Accounts receivable (3,060) (536) (58)
Due from affiliates -- 1,557 (713)
Prepaid expenses and other (677) 635 (396)
Accounts payable 6,291 (8,150) (19,110)
Due to affiliates 3,563 303 --
Revenues and royalties payable (4,318) 57 2,582
Accrued liabilities and other 11,094 (1,525) (4,723)
--------- -------- ---------
Net cash provided by operating activities 171,491 91,622 42,523
--------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (142,436) (71,920) (76,842)
Sale of property and equipment (72) 4,893 (272)
--------- -------- ---------
Net cash used in investing activities (142,508) (67,027) (77,114)
--------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Redeemable preferred stock -- -- 66,850
Proceeds from long-term debt 75,129 -- 165,000
Reductions in long-term debt (132,320) (51,430) (196,250)
Proceeds - Notes payable 2,537 1,888 1,592
Reductions - Notes payable (1,861) (2,525) (1,524)
Repurchase of common stock (49,291) -- --
Issuance of stock/exercise of stock options 94,777 33,185 307
Preferred dividends (5,248) -- (1,102)
Additions to deferred loan costs (1,230) (179) (7,335)
--------- -------- ---------
Net cash provided by (used in) financing activities (17,507) (19,061) 27,538
--------- -------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 11,476 5,534 (7,053)
Cash and cash equivalents at beginning of year 12,821 7,287 14,340
--------- -------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 24,297 $ 12,821 $ 7,287
========= ======== =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Non-cash financing activities:
Conversion of preferred stock $ (27,734) $ -- $ --
Conversion of subordinated debt $ (20,000) $ -- $ --
See notes to consolidated financial statements.
-42-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 2002, 2003 AND 2004 (in thousands)
Accumulated
Common Stock Additional Other
------------------ Paid-In Accumulated Comprehensive
Shares Par Value Capital (Deficit) Loss
------ --------- ---------- ----------- -------------
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 loss -- -- -- (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 frm stock
offering 8,704 50 3,456 -- --
Accum. other comprehensive
income -- -- -- -- (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)
Issuance of rights to common
stock -- 3 1,597 -- --
Company's 401(k) plan
contribution 52 -- 343 -- --
Exercise of stock options 27 -- 131 -- --
Compensation expense -- -- -- -- --
Accum. other comprehensive
income -- -- -- -- 5,945
Write-down of securities held -- -- -- -- 185
Issuance for conversion of
pref stock 6,484 65 27,669 -- --
Issuance for conversion of sub
debt 4,209 42 21,146 -- --
Issuance of shares frm stock
offering 13,800 138 94,508 -- --
Repurchase of common stock -- -- -- -- --
Retirement of treasury stock
(09/04) (7,082) (71) (49,220) -- --
Preferred dividends -- -- -- (3,877) --
Net earnings -- -- -- 33,125 --
------ ---- -------- --------- -------
Balance, December 31, 2004 79,215 $821 $490,351 $(173,244) $(1,574)
====== ==== ======== ========= =======
Unamortized Treasury Stock
Deferred ------------------
Compensation Shares Cost Total
------------ ------- -------- --------
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 loss -- -- -- (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 frm stock
offering -- (3,664) 29,423 32,929
Accum. other comprehensive
income -- -- -- (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
Issuance of rights to common
stock (1,600) -- -- --
Company's 401(k) plan
contribution -- -- -- 343
Exercise of stock options -- -- -- 131
Compensation expense 1,577 -- -- 1,577
Accum. other comprehensive
income -- -- -- 5,945
Write-down of securities held -- -- -- 185
Issuance for conversion of
pref stock -- -- -- 27,734
Issuance for conversion of sub
debt -- -- -- 21,188
Issuance of shares frm stock
offering -- -- -- 94,646
Repurchase of common stock -- (7,082) (49,291) (49,291)
Retirement of treasury stock
(09/04) -- 7,082 49,291 --
Preferred dividends -- -- -- (3,877)
Net earnings -- -- -- 33,125
------- ------ -------- --------
Balance, December 31, 2004 $ (313) -- $ -- $316,041
======= ====== ======== ========
See notes to consolidated financial statements.
-43-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(thousands of dollars)
YEAR ENDED DECEMBER 31,
-----------------------------
2004 2003 2002
------- -------- --------
Net earnings (loss) applicable to common stockholders $29,248 $ 7,246 $(52,012)
Other comprehensive income (loss), net of tax, for
unrealized losses from hedging activities:
Unrealized holding losses arising during period (6,161) (12,461) (5,522)
Reclassification adjustments on settlement of contracts 12,106 9,695 769
Write-down of securities held 185 -- --
------- -------- --------
6,130 (2,766) (4,753)
------- -------- --------
Total comprehensive income (loss) $35,378 $ 4,480 $(56,765)
======= ======== ========
See notes to consolidated financial statements.
-44-
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.
RESTRICTED CASH
The Company classifies cash balances as restricted cash when cash is restricted
as to withdrawal or usage. The restricted cash balance at December 31, 2004, was
$891,000, and at December 31, 2003, was $0. The restricted cash is related to a
contractual obligation related to royalties payable.
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
units 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.
-45-
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 $6.3 million, $9.6 million and $11.7 million in 2004, 2003 and 2002,
respectively. Cash payments for income taxes (federal and state, net of
receipts) were $950,000 for 2004, $23,000 for 2003, and none for 2002.
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.
The Company maintains its cash in bank deposit accounts which, at times, may
exceed federally insured limits. Accounts are guaranteed by the Federal Deposit
Insurance Corporation (FDIC) up to $100,000. At December 31, 2004, and December
31, 2003, the Company had approximately $22,970,000 and $12,360,000,
respectively, in excess of FDIC insured limits. The Company has not experienced
any losses in such accounts.
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,
2004, 2003 or 2002.
-46-
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 (thousands of dollars, except per share information):
2004 2003 2002
------- ------ --------
Net earnings (loss) applicable to common stockholders
as reported $29,248 $7,246 $(52,012)
Stock-based compensation (expense) benefit determined
under fair value method for all awards, net of tax (119) 63 (39)
------- ------ --------
Net earnings (loss) applicable to common stockholders
pro forma $29,129 $7,309 $(52,051)
======= ====== ========
Basic earnings (loss) per share:
As reported $ 0.41 $ 0.14 $ (1.05)
Pro forma $ 0.40 $ 0.14 $ (1.05)
Diluted earnings (loss) per share:
As reported $ 0.37 $ 0.13 $ (1.05)
Pro forma $ 0.37 $ 0.13 $ (1.05)
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 3.37%, 2.87% and 2.54%; dividend yield of 0%; volatility
factors of the expected market price of the Company's Common Stock of 0.96, 1.02
and 0.81 for 2004, 2003 and 2002, respectively; and a weighted-average expected
life of five years. These assumptions resulted in a weighted average grant date
fair value of $5.92, $3.44 and $1.97 for options granted in 2004, 2003 and 2002,
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, 2004 and 2003, 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 value of our subordinated notes was $19.6 million at December 31, 2003. The
carrying value of our subordinated notes was $20 million at December 31, 2003.
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
-47-
Activity, an Amendment of SFAS 133. SFAS No. 133 and SFAS No. 138 require that
all derivative instruments be recorded on the balance sheet at their respective
fair values. SFAS No. 133 and SFAS No. 138 are effective for all fiscal quarters
of all fiscal years beginning after June 30, 2000; the Company adopted SFAS No.
133 and SFAS No. 138 on January 1, 2001.
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 derivative
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 two years ended December 31, 2003,
and a gain of $126,000 during the year ended December 31, 2004.
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 SFAS 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
-48-
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.
NEW ACCOUNTING PRONOUNCEMENTS
On September 28, 2004, the Securities and Exchange Commission released Staff
Accounting Bulletin ("SAB") 106 regarding the application of SFAS 143,
"Accounting for Asset Retirement Obligation ("AROs")," by oil and gas producing
companies following the full cost accounting method. Pursuant to SAB 106, oil
and gas producing companies that have adopted SFAS 143 should exclude the future
cash outflows associated with settling AROs (ARO liabilities) from the
computation of the present value of estimated future net revenues for the
purposes of the full cost ceiling calculation. In addition, estimated
dismantlement and abandonment costs, net of estimated salvage values, that have
been capitalized (ARO assets) should be included in the amortization base for
computing depreciation, depletion and amortization expense. Disclosures are
required to include discussion of how a company's ceiling test and depreciation,
depletion and amortization calculations are impacted by the adoption of SFAS
143. SAB 106 is effective prospectively as of the beginning of the first fiscal
quarter beginning after October 4, 2004. Since our adoption of SFAS 143 on
January 1, 2003, we have calculated the ceiling test and our depreciation,
depletion and amortization expense in accordance with the interpretations set
forth in SAB 106; therefore, the adoption of SAB 106 had no effect on our
financial statements.
In December 2004, the FASB issued SFAS No. 123R which is a replacement statement
to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS
Statement 95. This statement addresses the accounting for share-based payment
transactions in which an enterprise receives employee services in exchange for
(a) equity instruments of the enterprise or (b) liabilities that are based on
the fair value of the enterprise's equity instruments or that may be settled by
the issuance of such equity instruments. The statement would eliminate the
ability to account for share-based compensation transactions using APB Opinion
No. 25, "Accounting for Stock Issued to Employees," and generally would require
instead that such transactions be accounted for using a fair-value-based method.
This statement would be effective for the Company for interim periods beginning
after June 15, 2005. The impact on the results of operations would be similar to
the pro forma disclosures made above.
USE OF ESTIMATES
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.
-49-
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 $601 thousand and $667 thousand in 2004 and 2003, respectively.
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):
2004 2003 2002
------- ------ --------
Net earnings (loss) applicable to
common stockholders $29,248 $7,246 $(52,012)
Additional accretion expense -- -- (470)
Cumulative effect of accounting change -- 1,309 --
------- ------ --------
Pro forma net earnings (loss) applicable to
common stockholders $29,248 $8,555 $(52,482)
------- ------ --------
Pro forma earnings (loss) per share:
Basic $ 0.41 $ 0.16 $ (1.05)
Diluted $ 0.37 $ 0.15 $ (1.05)
-50-
The following table describes the change in the Company's asset retirement
obligations for the years ended December 31, 2004 and 2003 (thousands of
dollars):
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
Additional retirement obligations recorded in 2004 1,051
Settlements during 2004 (972)
Revisions to estimates during 2004 4,842
Accretion expense for 2004 601
-------
Asset retirement obligation at December 31, 2004 $ 9,624
=======
Our revisions to estimates represent changes to the expected amount and timing
of payments to settle our asset retirement obligations. These changes primarily
result from obtaining new information about the timing of our obligations to
plug our natural gas and oil wells and costs to do so.
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.
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
CURRENT REVOLVING CREDIT AGREEMENT
On December 23, 2004, the Company amended its existing credit facility to
provide for a four-year $200 million senior secured credit facility (the "Credit
Facility") with Fortis Capital Corp., as administrative agent, sole lead
arranger and bookrunner; Comerica Bank as syndication agent; and Union Bank of
California as documentation agent. Bank of Nova Scotia and Allied Irish Banks
p.l.c. completed the syndication group. The initial borrowing base under the
Credit Facility is $130 million. As of December 31, 2004, outstanding borrowings
under the Credit Facility totaled $75.1 million.
The Credit Facility is subject to semi-annual borrowing base redeterminations on
April 30 and October 31 of each year. In addition to the scheduled semi-annual
borrowing base redeterminations, the lenders or the Company, have the right to
redetermine the borrowing base at any time, provided that no party can request
more than one such redetermination between the regularly scheduled borrowing
base redeterminations.
Obligations under the Credit Facility are secured by pledges of outstanding
capital stock of the Company's subsidiaries and by a first priority lien on not
less than 75% (95% in the case of an event of default) of its present value of
proved oil and gas properties. In addition, the Company is required to deliver
to the lenders
-51-
and maintain satisfactory title opinions covering not less than 70% of the
present value of proved oil and gas properties. The Credit Facility also
contains other restrictive covenants, including, among other items, maintenance
of certain financial ratios, restrictions on cash dividends on Common Stock and
under certain circumstances Preferred Stock, limitations on the redemption of
Preferred Stock and an unqualified audit report on the Company's consolidated
financial statements, all of which the Company is in compliance.
Under the Credit Facility, the Company may secure either (i) (a) an alternative
base rate loan that bears interest at a rate per annum equal to the greater of
the administrative agent's prime rate; or (b) federal funds-based rate plus 1/2
of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate
outstanding loans and letters of credit to the borrowing base 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 2.25%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. At December 31, 2004, the three-month LIBOR interest rate
was 2.56%. The Credit Facility also provides for commitment fees of 0.375%
calculated on the difference between the borrowing base and the aggregate
outstanding loans under the Credit Facility.
FORMER REVOLVING CREDIT AGREEMENT
During August 2002, the Company replaced its Chase Manhattan Bank Credit
Facility with a three-year $175 million underwritten senior secured credit
agreement (the "Former 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
Former Credit Agreement were to mature on November 15, 2005, as extended by an
amendment dated November 8, 2004. The amendment was subject to an extension fee
of $450,000 to be paid in the event the Credit Facility has not been paid or
refinanced by January 3, 2005.
The borrowing base was set at $127.5 million effective on October 31, 2004.
Credit Facility payments of $48.3 million were made during the first nine months
of 2004, bringing the outstanding balance to $74 million as of September 30,
2004. The Company made a final debt repayment of $74 million on December 23,
2004, which paid off in full this loan agreement.
In addition to the scheduled quarterly borrowing base redeterminations, the
lenders or borrower, under the Former Credit Agreement, had the right to
redetermine the borrowing base at any time, once during each calendar year.
Borrowings under the Former 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. On October 25, 2004, the Company notified Societe Generale
that the present value of the mortgaged oil and gas properties totaled 86%. The
Company received a waiver of the 90% test in anticipation of the new Fortis
senior secured credit facility requiring only a 75% mortgage test. The Former
Credit Agreement contained 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.
Under the Former Credit Agreement, the Company could have secured either (i) (a)
an alternative base rate loan that bears interest at a rate per annum equal to
the greater of the administrative agent's prime rate; or (b) federal funds-based
rate plus 0.5%, 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; (ii)
a Eurodollar base rate loan that bears interest, generally, at a rate per annum
equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.5%,
depending on the ratio of the aggregate outstanding loans and letters of credit
to the borrowing base. The Former Credit Agreement also provided 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
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Corporation for $25 million on April 5, 2002, with a maturity date of December
31, 2004. The notes were unsecured and contained customary events of default,
but did not contain any maintenance or other restrictive covenants. The interest
rate was 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, 2004, the three-month LIBOR rate was 2.56%. Note payments totaling $6.25
million were paid in 2002, with an additional $8.75 million paid in 2003. A note
payment of $5 million was made during April 2004, with the remaining $5 million
paid in December 2004.
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 were unsecured and contained customary events of default, but did not
contain any maintenance or other restrictive covenants. Interest was payable on
a quarterly basis. The Company was 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 were 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 was
subject to customary anti-dilution provisions. The holders of the Notes were
granted registration rights with respect to the shares of Common Stock that
would be issued upon conversion of the Notes.
During March 2004, the notes were converted into 4.0 million shares of the
Company's Common Stock at a conversion price of $5.00 per share, and included an
additional non-cash conversion expense of approximately $1.2 million that was
incurred via the issuance of Common Stock priced at market.
CURRENT DEBT MATURITIES
Scheduled debt maturities for the next five years and thereafter, as of December
31, 2004, are as follows: none in 2005, 2006, or 2007, $75.1 million in 2008,
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 $2.4 million, $2.3 million and $2.2 million in 2004,
2003 and 2002, respectively. Future minimum lease payments under all
non-cancelable operating leases having initial terms of one year or more are
$2.5 million for 2005, $1.8 million for 2006, $0.1 million for 2007 and none
thereafter.
7. COMMITMENTS AND CONTINGENCIES
LITIGATION
PETROQUEST LITIGATION. This litigation was settled in December 2003 and all
claims were dismissed. In December 1999, PetroQuest Energy, Inc. (formerly known
as Optima Energy (U.S.) Corporation) ("PetroQuest") filed a claim against
Meridian for damages "estimate[d] to exceed several million dollars" alleging
that Meridian was liable for gross negligence and willful misconduct in the
execution of certain agreements related to property in the S.W. Holmwood and E.
Lake Charles Prospects in Calcasieu Parish, Louisiana and for an alleged
withholding of funds totaling $886,153.31, in conjunction with Meridian's having
paid 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. Under the confidential settlement
agreement, Meridian agreed to make two
-53-
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. This litigation was settled in March 2004 and all claims
were dismissed. Three different groups asserted adverse title claims to some or
all of Section 80 (640 acres) within Meridian's Thibodaux units in the Ramos
Field. Another entity asserted adverse title claims to a portion of Section 36
within these same units. These claims turned primarily on the location of the
parish boundary lines between Terrebonne and Assumption Parishes and/or the
validity of various tax sales in the chain of title. Meridian's gas purchaser,
Louisiana Intrastate Gas Company LLC ("LIG"), 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 suspended payment of
royalties and working interest attributable to these same 25 acres since
December 2000. Meridian and its partners and royalty owners reached an agreement
whereby the parties' plaintiff granted a lease on all of the disputed acreage to
the current interest owners for a lease bonus of $4.5 million and a future
royalty interest of 1.5%.
H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a
claim against Meridian for damages "estimated 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, as a result of Meridian's satisfying
a prior adverse judgment in favor of Amoco Production Company. Meridian will
file an answer denying Hawkins' claims and assert a counterclaim for attorney's
fees, court costs and other expenses, and for declaratory relief that Meridian
is entitled to retain the amounts that it had been paid by Hawkins. The Company
has not provided any amount for this month in its financial statements at
December 31, 2004.
ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with
numerous other oil companies) in various similar lawsuits concerning the Weeks
Island, Gibson, Bayou Pigeon, West Lake Verret and White Castle 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 which exceed our insurance limits
to which the Company 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.
-54-
8. TAXES ON INCOME
Provisions (benefits) for federal and state income taxes are as follows
(thousands of dollars):
YEAR ENDED DECEMBER 31,
---------------------------
2004 2003 2002
------- ------ --------
Current:
Federal $ 905 $ (568) $ 327
State (71) (163) (29)
Deferred:
Federal 18,160 4,980 (22,300)
State 348 -- --
------- ------ --------
Income tax expense (benefit) $19,342 $4,249 $(22,002)
======= ====== ========
The 2004 provision for Federal income taxes currently payable is the result of
alternative minimum tax.
The Company's income tax provision is attributed to the following items:
YEAR ENDED DECEMBER 31,
----------------------------
2004 2003 2002
------- ------- --------
Earnings (loss) before cumulative effect of
change in accounting principle $19,342 $ 4,249 $(22,002)
Losses on derivatives recognized in other
comprehensive income (loss) 3,199 (1,489) (2,560)
------- ------- --------
Total income tax provision $22,541 $ 2,760 $(24,562)
======= ======= ========
Income tax expense (benefit) as reported is reconciled to the federal statutory
rate (35%) as follows (thousands of dollars):
YEAR ENDED DECEMBER 31,
----------------------------
2004 2003 2002
------- ------- --------
Income tax provision (benefit) computed at
statutory rate $18,364 $ 6,331 $(24,525)
Nondeductible costs 607 758 308
State income tax, net of federal tax benefit 302 (106) (19)
Decrease in net operating loss carryover
due to expiration 69 -- --
Change in valuation allowance -- (2,734) 2,234
------- ------- --------
Income tax expense (benefit) $19,342 $ 4,249 $(22,002)
======= ======= ========
-55-
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,
------------------
2004 2003
-------- -------
Deferred tax assets:
Net operating tax loss carryforward $ 41,244 $39,208
Statutory depletion carryforward 950 950
Tax credits 1,987 1,083
Unrealized hedge loss 850 4,049
Other 4,698 4,631
-------- -------
Total deferred tax assets 49,729 49,921
-------- -------
Deferred tax liabilities:
Book in excess of tax basis in oil and gas properties 72,298 50,782
Basis differential in long-term investments 70 70
-------- -------
Total deferred tax liabilities 72,368 50,852
-------- -------
Net deferred tax asset (liability) $(22,639) $ (931)
======== =======
As of December 31, 2004, the Company has approximately $117.8 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 2006 and extend through
2023. A portion of the net operating loss carryforwards is subject to change in
ownership and separate return limitations that could restrict the Company's
ability to utilize such losses in the future.
As of December 31, 2004, the Company had net operating loss carryforwards for
regular tax and alternative minimum taxable income (AMT) purposes available to
reduce future taxable income. These carryforwards expire as follows (in
thousands of dollars):
NET AMT
YEAR OF OPERATING OPERATING
EXPIRATION LOSS LOSS
- ---------- --------- ---------
2006 $ 699 $ 699
2018 11,621 --
2019 47,730 44,404
2020 31 31
2021 36 36
2022 13,053 13,786
2023 44,669 44,516
-------- --------
TOTAL $117,839 $103,472
======== ========
As of December 31, 2004, the Company had approximately $1,987,415 of alternative
minimum tax (credit) carryover that does not expire.
-56-
Generally Accepted Accounting Principles require 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 2004.
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. 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 June 2004, the Company exercised its right, as described above, to convert
one-third of its remaining issued and outstanding preferred stock into shares of
Common Stock. The conversion was completed on a pro-rata basis and included a
cash payment for accrued and unpaid dividends through the June 8, 2004,
conversion date, at which time dividends ceased to accrue on the converted
shares. During the year 2004, a total of $28.9 million of preferred stock was
converted into 6.5 million shares of Common Stock. No gain or loss was recorded
as a result of the conversion.
For the year ended December 31, 2004, $3.5 million of dividends were accumulated
(net of $0.4 million of deferred preferred stock offering costs amortized during
2004), of which $2.2 million was paid in cash in July 2004 and $1.3 million was
paid in cash in January 2005. 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
(net of $0.4 million of deferred preferred stock offering costs amortized 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
In August 2004, the Company completed a public offering of 13,800,000 shares of
Common Stock at a price of $7.25 per share. The total proceeds of the offering,
net of issuance costs, received by the Company were approximately $94.6 million.
The Company repurchased all of the 7,082,030 shares of its Common Stock that
were beneficially owned by Shell Oil Company for $49.3 million and a portion of
the remaining proceeds of that equity offering was used to repay borrowings
under the Company's senior secured credit agreement, which resulted in an
increase in funds available to the Company to accelerate planned capital
expenditures for drilling activities and related pipeline construction. The
repurchased 7,082,030 shares of Common Stock that were held in Treasury Stock
were retired as of September 30, 2004.
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-term debt, and the remainder of the proceeds is being used for exploration
activities and for other general corporate purposes.
-57-
WARRANTS
The Company had the following warrants outstanding at December 31, 2004:
NUMBER OF EXERCISE
WARRANTS SHARES PRICE EXPIRATION DATE
- -------- --------- -------- -----------------
Executive Officers 1,428,000 $5.85 *
General Partner 1,604,428 $0.12 December 31, 2015
* A date one year following the date on which the respective officer ceases
to be an employee of the Company.
As of December 31, 2004, the Company had outstanding (i) warrants (the "General
Partner Warrants") that entitle Joseph A. Reeves, Jr. and Michael J. Mayell to
purchase an aggregate of 1,604,428 shares of Common Stock at an exercise price
of $0.12 per share through December 31, 2015 and (ii) executive officer warrants
that entitle each of Joseph A. Reeves, Jr. and Michael J. Mayell to purchase an
aggregate of 714,000 shares of Common Stock at an exercise price of $5.85 for a
period until one year following the date on which the respective individual
ceases to be an employee of the Company ("Executive Officer Warrants").
The number of shares of Common Stock purchasable upon the exercise of each
warrant described above and its corresponding exercise price are subject to
customary anti-dilution adjustments. In addition to such customary adjustments,
the number of shares of Common Stock and exercise price per share of the General
Partner Warrants are subject to adjustment for any issuance of Common Stock by
the Company such that each warrant will permit the holder to purchase at the
same aggregate exercise price, a number of shares of Common Stock equal to the
percentage of outstanding shares of the Common Stock that the holder could
purchase before the issuance. Currently each of these warrants permits the
holder to purchase approximately 1% of the outstanding shares of the Common
Stock for an aggregate exercise price of $94,303. The General Partner Warrants
were issued to Messrs. Reeves and Mayell in conjunction with certain
transactions with Messrs. Reeves and Mayell that took place in anticipation of
the Company's consolidation in December 1990 and were a component of the total
consideration issued for various interests that Messrs. Reeves and Mayell had as
general partners in TMR, Ltd., a predecessor entity 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.
-58-
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, 2004, 2003 and 2002, 1,670,685, 2,130,334, and 445,765
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, 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
Granted 173,750 7.94
Exercised (34,875) 4.49
Canceled (4,650) 5.78
--------- -----
Outstanding at December 31, 2004 3,693,050 $4.25
========= =====
Shares exercisable:
December 31, 2002 4,089,450 $4.53
December 31, 2003 3,510,700 $4.06
December 31, 2004 3,498,050 $4.06
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------------- ----------------------------------
WEIGHTED WEIGHTED
RANGE OF OUTSTANDING AT AVERAGE EXERCISABLE AT AVERAGE
EXERCISABLE PRICES DECEMBER 31, 2004 EXERCISE PRICE DECEMBER 31, 2004 EXERCISE PRICE
- ------------------ ----------------- -------------- ----------------- --------------
$3.00 - $4.75 3,126,150 $ 3.38 3,111,150 $ 3.38
$5.45 - $9.00 368,250 8.10 188,250 8.25
$10.38 - $11.13 198,650 10.84 198,650 10.84
--------- ------ --------- ------
3,693,050 $ 4.25 3,498,050 $ 4.06
========= ====== ========= ======
The weighted average remaining contractual life of options outstanding at
December 31, 2004, was approximately four years.
-59-
DEFERRED COMPENSATION
In July 1996, the Company through the Compensation Committee of the Board of
Directors offered to Messrs. Reeves and Mayell (the Company's Chief Executive
Officer and President, respectively) the option to accept in lieu of cash
compensation for their respective base salaries Common Stock pursuant to the
Company's Long Term Incentive Plan. Under such grants, Messrs. Reeves and Mayell
each elected to defer $400,000 for 2004, $316,000 for 2003 and $415,000 for
2002, which is substantially all of their salaried compensation for each of the
years. In exchange for and in consideration of their accepting this option to
reduce the Company's cash payments to each of Messrs. Reeves and Mayell, the
Company granted to each officer a matching deferral equal to 100% of that amount
deferred, which is subject to a one-year vesting period. Under the terms of the
grants, the employee and matching deferrals are allocated to a Common Stock
account in which units are credited to the accounts of the officer based on the
number of shares that could be purchased at the market price of the Common
Stock. 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, 2004, the plan had reserved 3,600,000 shares
of Common Stock for future issuance and 2,931,308 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
$1,577,000, $1,330,000 and $1,630,000 for 2004, 2003 and 2002 periods,
respectively, and is reflected in general and administrative expense and in oil
and gas properties for the years ended December 31, 2004, 2003 and 2002,
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
-60-
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 $299,000, $331,000 and $306,000 in 2004, 2003, and
2002, 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 $6.9 million, $4.3 million and
$4.2 million in 2004, 2003 and 2002, 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.
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.
-61-
12. 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 natural 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 two years ended December 31, 2003, and a gain of $126,000 during the year
ended December 31, 2004.
For the year ended December 31, 2004, the change in estimated fair value of the
Company's oil and natural gas swaps was an unrealized loss of $2.4 million ($1.6
million net of tax) which is recognized in other comprehensive income. Based
upon December 31, 2004, oil and natural gas commodity prices approximately $2.4
million of the loss deferred in other comprehensive income could potentially
lower gross revenues in 2005. These swap agreements expire at various dates
through October 31, 2005.
Net settlements under these swap agreements reduced oil and natural gas revenues
by $18,624,000, $14,916,000 and $1,183,000 for the years ended December 31,
2004, 2003, and 2002 respectively, as a result of hedging transactions.
The Notional Amount is equal to the total net volumetric hedge position of the
Company during the periods presented. The positions effectively hedge
approximately 41% of our proved developed natural gas production and 38% of our
proved developed oil production during the respective terms of the hedging
agreements. The fair values of the hedges are based on the difference between
the strike price and the New York Mercantile Exchange future prices for the
applicable trading months.
The fair value of our hedging agreements is recorded on our consolidated balance
sheet as assets or liabilities. The estimated fair value of our hedging
agreements as of December 31, 2004, is provided below:
-62-
Swap / Floor Fair Value
Notional Price Ceiling Price December 31, 2004
Type Amount ($ per unit) ($ per unit) (in thousands)
------ --------- ------------ ----------------- -----------------
NATURAL GAS (MMBTU)
Jan 2005 - Jun 2005 Swap 910,000 $ 3.74 N/A $(2,175)
Apr 2005 - Oct 2005 Swap 2,610,000 $ 6.34 N/A 492
Jan 2005 - Mar 2005 Collar 2,970,000 $ 7.00 $13.00 2,942
Apr 2005 - Oct 2005 Collar 2,600,000 $ 6.50 $ 7.90 1,751
-------
Total Natural Gas 3,010
-------
CRUDE OIL (BBLS)
Jan 2005 - Jul 2005 Swap 266,000 $23.00 N/A (5,308)
-------
Total Crude Oil (5,308)
-------
$(2,298)
=======
See Note 17, Subsequent Events, for additional information.
13. MAJOR CUSTOMERS
Major customers for the years ended December 31, 2004, 2003 and 2002, were as
follows (based on purchases exceeding 10% of oil and natural gas as a percent of
total oil and natural gas sales):
YEAR ENDED DECEMBER 31,
-----------------------
CUSTOMER 2004 2003 2002
-------- ---- ---- ----
Superior Natural Gas ........ 45% 19% --
Louisiana Intrastate Gas .... 22% 24% 17%
Conoco, Inc. ................ -- 10% 12%
Equiva Trading Company(1) ... -- -- 33%
(1) Equiva Trading Company is an affiliate of Shell.
14. 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"), JAR Resources
LLC ("JAR") 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% to
4% 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, JAR and Sydson invested $8,539,000, $5,161,000 and $3,289,000 for the
years ended December 31, 2004, 2003 and 2002, respectively, in oil and natural
gas drilling activities for which the Company was the operator. Net amounts due
to TODD and Mr. Reeves were approximately $1,751,000 and $321,000 as of December
31, 2004 and 2003, respectively. Net amounts due to/(from) Sydson and Mr. Mayell
were approximately $2,115,000 and ($18,000) as of December 31, 2004 and 2003,
respectively.
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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, 2004, 2003 and 2002 and received fees of
approximately $255,000, $210,000 and $282,000, 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 $298,000 during 2004 and $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, 2004, 2003 and 2002,
and received fees of approximately $12,000, $49,000 and $27,000, respectively.
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 $688,000 during 2004, $360,000 during 2003 and
$377,000 during 2002.
Mr. Joseph A. Reeves, Jr., an officer and Director of Meridian, has two
relatives currently employed by the Company. J.Drew Reeves, his son, is a staff
member in the Finance Department. He has a Masters degree in Business
Administration from Louisiana State University and was employed as a Landman for
the firm of Land Management LLC in Metairie, Louisiana, prior to joining
Meridian in 2003. Mr. Drew Reeves was paid $80,000 and $40,000 for the years
2004 and 2003, respectively. Jeff Robinson is the son-in-law of Joseph A.
Reeves, Jr. and is employed as the Manager of the Company's Information
Technology Department and has been paid $101,000 and $42,000 for the years 2004
and 2003, respectively. Mr. Robinson earned his undergraduate degree in MIS from
Auburn University and was employed by BSI Consulting for 5 years prior to
joining Meridian in 2003. J. Todd Reeves, a partner in the law firm of
Creighton, Richards, Higdon and Reeves in Covington, Louisiana, is the son of
Joseph A. Reeves, Jr. This law firm provided legal services for the Company for
the year ended December 31, 2004, and received fees of approximately $67,000.
Such fees exceeded 5% of the gross revenues for this firm for 2004. 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.
James T. Bond, former Director of Meridian, is the father-in-law of Michael J.
Mayell, an officer and Director of Meridian, and has provided consultant
services to the Company and received fees in the amount of $124,000, $115,000,
and $48,000, for the years 2004, 2003 and 2002, respectively.
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15. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings
(loss) per share:
(in thousands, except per share)
YEAR ENDED DECEMBER 31,
--------------------------------
2004 2003 2002(1)
------- ------- --------
Numerator:
Net earnings (loss) applicable to common stockholders $29,248 $ 7,246 $(52,012)
Plus income impact of assumed conversions:
Preferred stock dividends N/A N/A N/A
Interest on convertible subordinated notes 270 N/A N/A
------- ------- --------
Net earnings (loss) applicable to common stockholders
plus assumed conversions $29,518 $ 7,246 $(52,012)
------- ------- --------
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 72,084 53,325 49,763
Effect of potentially dilutive common shares:
Warrants 4,508 3,393 N/A
Employee and director stock options 1,589 426 N/A
Convertible subordinated notes 852 N/A N/A
Redeemable preferred stock N/A N/A N/A
------- ------- --------
Denominator for diluted earnings per share
- weighted-average shares outstanding and
assumed conversions 79,033 57,144 49,763
======= ======= ========
Basic earnings (loss) per share $ 0.41 $ 0.14 $ (1.05)
======= ======= ========
Diluted earnings (loss) per share $ 0.37 $ 0.13 $ (1.05)
======= ======= ========
(1) Anti-dilutive in 2002.
N/A = Not Applicable, meaning anti-dilutive for periods present. Due to its
anti-dilutive effect on earnings per share, approximately 9.8 million shares in
2004, 22.7 million shares in 2003, and 27.7 million shares in 2002, related to
our redeemable preferred stock, convertible subordinated notes, stock options
and warrants were excluded from the dilutive shares.
16. ACCRUED LIABILITIES
Below is the detail of our accrued liabilities on our balance sheets as of
December 31:
2004 2003
------- -------
Capital expenditures $12,662 $ 3,508
Bonuses 3,355 1,715
Dividends 1,346 3,057
Other 4,043 3,794
------- -------
TOTAL $21,406 $12,074
======= =======
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17. SUBSEQUENT EVENT
During January 2005, the Company entered into a series of hedging contracts to
hedge a portion of its expected oil production for 2005 and 2006. The hedge
contracts were completed in the form of costless collars. The costless collars
provide the Company with a lower floor price and an upper limit ceiling price on
the hedged volumes. The floor price represents the lowest price the Company will
receive for the hedged volumes while the ceiling price represents the highest
price the Company will receive for the hedged volumes. The costless collars will
be settled monthly based on the daily settlement price of the NYMEX futures
contract of oil during each respective month. The following table summarizes the
contracted volumes and price for the costless collars.
Contracted Ceiling
Volume Floor Price Price
Production Month (Bbl) ($/Bbl) ($/Bbl)
---------------- ---------- ------------ -------
August 2005 - July 2006 209,000 $37.50 $47.50
August 2005 - July 2006 48,000 $40.00 $50.00
18. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the year ended December 31, 2004 were
(thousands of dollars, except per share):
QUARTER ENDED
---------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
2004
Revenues $46,192 $50,103 $53,037 $53,786
Results of operations from exploration
and production activities(1) 17,229 19,545 19,428 20,272
Net earnings (loss)(2) $ 5,287 $ 7,745 $ 7,786 $ 8,430
Net earnings (loss) per share:(2)
Basic $ 0.08 $ 0.11 $ 0.10 $ 0.11
Diluted 0.08 0.10 0.09 0.10
Results of operations by quarter for the year ended December 31, 2003 were
(thousands of dollars, except per share) as follows:
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) 10,159 10,187 11,996 10,791
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
(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, accretion
and impairment of oil and natural gas properties.
(2) Applicable to common stockholders
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19. 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,
----------------------------
2004 2003 2002
-------- ------- -------
Costs incurred during the year:(1)
Property acquisition costs
Unproved $ 16,687 $ 4,107 $ 5,217
Proved -- -- --
Exploration 93,682 42,081 32,293
Development 31,610 25,586 38,998
Asset retirement cost accruals, net 4,921 1,326 --
-------- ------- -------
$146,900 $73,100 $76,508
======== ======= =======
(1) Costs incurred during the years ended December 31, 2004, 2003 and 2002
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of third
party reimbursements, of $11,924,000, $10,030,000 and $11,684,000,
respectively.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
DECEMBER 31,
-----------------------
2004 2003
---------- ----------
Capitalized costs $1,377,649 $1,230,643
Accumulated depletion 931,033 829,089
---------- ----------
Net capitalized costs $ 446,616 $ 401,554
========== ==========
At December 31, 2004 and 2003, unevaluated costs of $34,731,000 and $30,542,000,
respectively, were excluded from the depletion base. These costs are expected to
be evaluated within the next three years. These costs consist primarily of
acreage acquisition costs and related geological and geophysical costs.
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RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES
(thousands of dollars)
YEAR ENDED DECEMBER 31,
------------------------------
2004 2003 2002
-------- -------- --------
Operating Revenues:
Oil $ 36,060 $ 35,032 $ 54,595
Natural Gas 166,387 102,092 52,397
-------- -------- --------
202,447 137,124 106,992
-------- -------- --------
Less:
Oil and natural gas operating costs 14,035 11,260 11,935
Severance and ad valorem taxes 9,394 7,608 8,235
Depletion 101,944 74,456 59,799
Accretion expense(1) 601 667 --
Impairment of long-lived assets -- -- 69,124
Income tax 19,342 4,249 (22,002)
-------- -------- --------
145,316 98,240 127,091
-------- -------- --------
Results of operations from oil and
natural gas producing activities $ 57,131 $ 38,884 $(20,099)
======== ======== ========
Depletion expense per Mcfe $ 2.88 $ 2.61 $ 2.07
======== ======== ========
(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 for the year 2002.
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ESTIMATED QUANTITIES OF PROVED RESERVES
The following table sets forth the net proved reserves of the Company as of
December 31, 2004, 2003 and 2002, and the changes therein during the years then
ended. The reserve information was reviewed by T. J. Smith & Company, Inc.,
independent reservoir engineers, for 2004, 2003 and 2002. 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, 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
Production during 2004 (1,270) (27,839)
Discoveries and extensions 212 21,783
Revisions of previous quantity estimates and other (470) 8,586
------- -------
BALANCE AT DECEMBER 31, 2004 6,364 100,999
======= =======
PROVED DEVELOPED RESERVES:
Balance at December 31, 2001 10,752 101,397
Balance at December 31, 2002 6,841 86,248
Balance at December 31, 2003 5,016 82,279
Balance at December 31, 2004 4,716 85,507
(1) Primarily as a result of Kent Bayou. See Note 4. to Notes to Consolidated
Financial Statements for additional information.
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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,
---------------------------------
2004 2003 2002
--------- --------- ---------
Future cash flows $ 897,839 $ 842,945 $ 829,538
Future production costs (139,112) (118,775) (137,215)
Future development costs (39,352) (30,044) (43,474)
--------- --------- ---------
Future net cash flows before income taxes 719,375 694,126 648,849
Future taxes on income (135,472) (116,570) (99,852)
--------- --------- ---------
Future net cash flows 583,903 577,556 548,997
Discount to present value at 10 percent per annum (113,546) (121,673) (119,162)
--------- --------- ---------
Standardized measure of discounted future net cash flows $ 470,357 $ 455,883 $ 429,835
========= ========= =========
The average price for natural gas in the above computations was $6.40, $6.07 and
$4.96 per Mcf at December 31, 2004, 2003, and 2002, respectively. The average
price used for crude oil in the above computations was $42.33, $32.05 and $31.82
per Bbl at December 31, 2004, 2003, and 2002, respectively.
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CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following table sets forth the changes in standardized measure of discounted
future net cash flows for the years ended December 31, 2004, 2003 and 2002
(thousands of dollars):
YEAR ENDED DECEMBER 31,
---------------------------------
2004 2003 2002
--------- --------- ---------
Balance at Beginning of Period $ 455,883 $ 429,835 $ 402,917
Sales of oil and gas, net of production costs (179,018) (118,256) (86,822)
Changes in sales & transfer prices, net of production costs 32,203 82,200 348,960
Revisions of previous quantity estimates 22,468 (24,563) (373,928)
Sales of reserves-in-place -- (5,026) --
Current year discoveries, extensions
and improved recovery 117,178 67,676 40,376
Changes in estimated future
development costs (11,331) (7,824) (9,840)
Development costs incurred during the period 9,851 20,511 38,998
Accretion of discount 45,588 42,983 40,292
Net change in income taxes (23,278) (21,186) (3,676)
Change in production rates (timing) and other 813 (10,467) 32,558
--------- --------- ---------
Net change 14,474 26,048 26,918
--------- --------- ---------
Balance at End of Period $ 470,357 $ 455,883 $ 429,835
========= ========= =========
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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 2004.
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 2004 that could
significantly affect these controls except as noted below.
In the course of preparing our first management report on internal control over
financial reporting as required by Section 404 of the Sarbanes-Oxley Act, we
identified, and remediated in the fourth quarter of 2004, certain material
weaknesses in the system of internal controls. The adjustments to the Company's
consolidated financial statements resulting from such remediation were not
material, either individually or in the aggregate. The material weaknesses that
were remediated related to (a) a lack of effective controls over the coding of
certain workover invoices, (b) controls over the revenue accrual process and (c)
a lack of proper segregation of duties associated with the initiation and
execution of wire transfers.
In accordance with an exemptive order by the SEC, management's annual report on
internal control over financial reporting, required by Item 308(a) of Regulation
S-K, and the related Attestation report of the Company's independent auditors,
required by Item 308(b) of Regulation S-K, are not required to be filed on the
date that this report is otherwise due to be filed. Such information will be
filed on or before May 2, 2005 by an amendment to this report.
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 May 2, 2005.
-72-
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Independent Registered Public Accounting Firms' Reports
(ii) Consolidated Balance Sheets as of December 31, 2004 and 2003
(iii) Consolidated Statements of Operations for each of the three
years in the period ended December 31, 2004
(iv) Consolidated Statements of Changes in Stockholders' Equity for
each of the three years in the period ended December 31, 2004
(v) Consolidated Statements of Cash Flows for each of the three years
in the period ended December 31, 2004
(vi) Notes to Consolidated Financial Statements
(vii) Consolidated Supplemental Oil and Gas Information (Unaudited)
2. Financial Statement Schedules:
(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.
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Reeves, Jr. and Michael J. Mayell (incorporated by
reference to Exhibit 10.7 of the Company's Registration
Statement on Form S-4, as amended (Reg. No. 33-37488)).
*4.5 Warrant Agreement dated June 7, 1994, between the Company
and Joseph A. Reeves, Jr. (incorporated by reference to
Exhibit 4.1 of the Company's Quarterly Report on Form 10-Q
for the quarter ended June 30, 1994).
*4.6 Warrant Agreement dated June 7, 1994, between the Company
and Michael J. Mayell (incorporated by reference to
Exhibit 4.1 of the Company's Quarterly Report on Form 10-Q
for the quarter ended June 30, 1994).
4.7 Amended and Restated Credit Agreement, dated December 23,
2004, among the Company, Fortis Capital Corp., as
Administrative Agent, Sole Lead Arranger and Bookrunner,
Comerica Bank, as Syndication Agent, Union Bank of
California, N.A., as 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 December 23, 2004).
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 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).
4.10 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).
-74-
*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).
*10.14 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.
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**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.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
THE MERIDIAN RESOURCE CORPORATION
BY: /s/ JOSEPH A. REEVES, JR.
--------------------------------------
Chief Executive Officer
(Principal Executive Officer)
Director and Chairman of the Board
Date: March 15, 2005
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, 2005
------------------------------- (Principal Executive Officer)
Joseph A. Reeves, Jr. Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director March 15, 2005
-------------------------------
Michael J. Mayell
BY: /s/ LLOYD V. DELANO Chief Accounting Officer March 15, 2005
-------------------------------
Lloyd V. DeLano
BY: /s/ E. L. HENRY Director March 15, 2005
-------------------------------
E. L. Henry
BY: /s/ JOE E. KARES Director March 15, 2005
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Joe E. Kares
BY: /s/ GARY A. MESSERSMITH Director March 15, 2005
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Gary A. Messersmith
BY: /s/ DAVID W. TAUBER Director March 15, 2005
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David W. Tauber
-77-
BY: /s/ JOHN B. SIMMONS Director March 15, 2005
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John B. Simmons
BY: /s/ FENNER R. WELLER, JR. Director March 15, 2005
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Fenner R. Weller, Jr.
BY: /s/ JAMES R. MONTAGUE Director March 15, 2005
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James R. Montague
-78-
INDEX TO EXHIBITS
Exhibit
No. Description
- ------- -----------
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 Amended and Restated Credit Agreement, dated December 23, 2004, among
the Company, Fortis Capital Corp., as Administrative Agent, Sole Lead
Arranger and Bookrunner, Comerica Bank, as Syndication Agent, Union
Bank of California, N.A., as 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
December 23, 2004).
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 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).
4.10 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).
*10.14 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.