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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, 1997 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. Employee identification No.)
15995 N. BARKERS LANDING, SUITE 300, HOUSTON, TEXAS 77079
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 281-558-8080
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
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. [ ]
Aggregate market value of shares of common stock held by non-affiliates
of the Registrant at March 27, 1998. $262,799,872
Number of shares of common stock outstanding at March 27, 1998. 33,479,514
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Form (Items 10, 11, 12 and 13) is
incorporated by reference from the registrant's Proxy Statement to be filed on
or before April 30, 1998.
Page 1 of 60
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
PART I PAGE
----
Item 1. Business 3
Item 2. Properties 16
Item 3. Legal Proceedings 16
Item 4. Submission of Matters to a Vote of Security Holders 17
PART II
Item 5. Market for Registrant's Common Equity and Related
Shareholder Matters 18
Item 6. Selected Financial Data 19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 20
Item 8. Financial Statements and Supplementary Data 30
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 55
PART III
Item 10. Directors and Executive Officers of the Registrant 55
Item 11. Executive Compensation 55
Item 12. Security Ownership of Certain Beneficial Owners
and Management 55
Item 13. Certain Relationships and Related Transactions 55
PART IV
Item 14. Exhibits, Financial Statements, Schedules and
Reports on Form 8-K 56
Signatures 60
2
PART I
ITEM 1. BUSINESS
GENERAL
The Meridian Resource Corporation, together with its subsidiaries (the "Company"
or "TMRC") is an independent oil and natural gas company engaged in the
exploration for and development of oil and natural gas properties utilizing 3-D
seismic technology. TMRC was one of the first independent oil and natural gas
companies in the industry to incorporate 3-D seismic technology as an integral
component of its exploration strategy and considers itself to be among the
leaders in the use of this technology by independent oil and natural gas
companies. TMRC believes that its expertise with and disciplined application of
3-D seismic technology provides it with a competitive advantage in the areas in
which it operates.
In recent years, TMRC has focused its exploratory efforts in the onshore and
coastal areas of Louisiana and the Texas Gulf Coast. With TMRC's merger with
Cairn Energy USA, Inc. ("Cairn") in November 1997, TMRC has expanded its
operations to the offshore waters in the Gulf of Mexico to 96 gross wells (20.7
net) and more than 50 3-D seismic based prospect opportunities offshore in the
Gulf of Mexico.
The Cairn merger was accounted for as a pooling-of-interests for financial
accounting purposes. As a result, historical revenue and production information
contained in this business section has been restated to reflect the reserve and
production data of the combined company. TMRC's estimated proved reserves as of
December 31, 1997 were approximately 9,731 MBbls of oil and 110.8 Bcf of natural
gas having an estimated Present Value of Proved Reserves of approximately $213.9
million.
On March 27, 1998, the Company and affiliates of Shell Oil Company (collectively
"Shell") executed a definitive merger agreement which, together with a separate
purchase and sale agreement (collectively referred to herein as the "Shell
Agreements" and the transactions contemplated by the Shell Agreements are
referred to herein as the "Shell Transactions"), will result in the Company
acquiring all of Shell's producing and exploration properties in South Louisiana
in exchange for shares of common and convertible preferred stock representing
39.9% of the common stock of the Company as of the closing, assuming exercise of
all stock options, warrants and conversion of the preferred stock, and $42.5
million in cash.
Following the Shell Transactions, the Company is expected to control over
329,000 gross onshore acres in Louisiana and Texas with approximately 2,800
square miles of onshore 3-D seismic data, which the Company believes to be one
of the largest positions held by a company with TMRC's market capitalization.
The Company estimates that is current production base following the Shell
Transactions will be approximately 22,000 net equivalent barrels of oil per day
and that proved reserves will total over 48.6 million equivalent barrels of oil
having an estimated reserve life of approximately six years.
3
TMRC was incorporated in Texas in 1990. TMRC's headquarters are located at 15995
N. Barkers Landing, Suite 300, Houston, Texas, 77079.
EXPLORATION STRATEGY
TMRC's exploration strategy is focused on prospects where large accumulations of
oil and natural gas have been found and where TMRC believes substantial oil and
natural gas reserve additions can be made through exploratory drilling utilizing
3-D seismic technology. TMRC also seeks to identify prospects with multiple
potential productive zones to maximize the probability of success. In an effort
to mitigate the risk of dry holes, TMRC engages in a rigorous and disciplined
review of each prospect utilizing the latest in technological advances with
respect to prospect analysis and evaluation.
TMRC's process of review of exploration prospects begins with a thorough
analysis of the prospect using traditional methods of prospect development and
computer technology to analyze all reasonably available 2-D seismic data and
other geological and geophysical data with respect to the prospect. If the
results of this analysis confirm the prospect potential, TMRC seeks to acquire
3-D seismic data over, and leasehold interests in or options to acquire
leasehold interests in, the prospect area. TMRC then applies state of the art
technology to assimilate and correlate the 2-D and 3-D seismic data on the
prospect with all available well log information and other data to create a
computer model that is designed to identify the location and size of potential
hydrocarbon accumulations in the prospect. If TMRC's analysis of the model
continues to confirm the potential for hydrocarbon accumulations within TMRC's
prospect objectives, TMRC will then seek to identify the most desirable drilling
location to test the prospect and to maximize production when the prospect is
successful.
The process of developing, reviewing and analyzing a prospect from the time it
is first identified to the time that it is drilled, is generally a 12 to 24
month process and results in a large number of potential prospects being
rejected 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 are not ultimately drilled requires greater
up-front costs per prospect than traditional exploration techniques, TMRC
believes that the elimination of prospects that are unlikely to be successful
and that might otherwise have been drilled at a substantial cost, results in
significant savings to TMRC and a higher than average success rate for large
reserve exploratory wells and thereby lower average finding costs per MCFE. TMRC
also believes that its use of 3-D seismic technology minimizes development costs
by allowing for the better placement of initial and, if necessary, development
wells.
TMRC attempts to match its exploration risks with expected results by retaining
working interests that historically have been between 50% and 75% in each well.
Working interests retained by TMRC may vary in certain prospects depending upon
participation structure, assessed risk, capital availability and other factors.
In addition, working interests in offshore properties acquired in the Cairn
acquisition average between 3% and 50% in each well. TMRC intends to increase
its offshore working interests over time so that they are closer to its
historical levels. TMRC's offshore properties also involve higher exploration
and 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
associated with offshore exploration. TMRC believes it has one of the industry's
most experienced exploration staffs among the independent oil and gas companies
in the regions in which TMRC operates.
4
3-D SEISMIC TECHNOLOGY
The application and reliance on 3-D seismic technology is an integral part of
TMRC's exploration strategy. TMRC believes that it has a competitive advantage
over many of its competitors through its application of a disciplined approach
to the use of 3-D seismic technology and its access to a substantial inventory
of 3-D seismic data covering its existing properties and new potential
prospects.
TMRC uses 3-D seismic technology as a key exploration and drilling tool and not
merely as a means of exploiting development opportunities or confirming the
potential viability of a prospect without engaging in the detailed process of
analyzing and correlating the data with other seismic and well data to identify
the most probable areas for hydrocarbon accumulations. TMRC believes that its
application of the technology enables it to develop a much more accurate
definition of the risk profile of an exploratory prospect than was previously
available using traditional exploration techniques. As a result, TMRC believes
its use of the technology increases its success rates and reduces its dry hole
costs compared to companies that do not engage in a similar process.
TMRC has also sought to achieve advantages over its competitors by acquiring
substantial 3-D seismic data over its prospects prior to drilling and by
securing access to new data over its existing and new prospect areas. TMRC
estimates that the inventory of both proprietary and non-proprietary data that
it owns or has rights to acquire has increased from approximately 1,025 square
miles at year end 1995 to approximately 2,280 square miles at year end 1997. In
addition, with the closing of the Shell Transactions, the Company expects to be
provided rights and access to approximately 5,000 miles of 2-D seismic data and
1,400 square miles of 3-D seismic data in Louisiana in addition to the Company's
already large inventory of 2-D and 3-D seismic data.
TMRC attempts to maximize the quality and usefulness of its 3-D seismic data by
participating in the original design of the survey whenever practicable. After
the survey is designed, TMRC conducts tests on such aspects of the design as the
amount and type of energy source, shot hole depths and layout, and type and
placement of recording devices to optimize data quality. TMRC also seeks to have
a representative on location during the acquisition process and conducts
periodic quality control checks as a survey progresses.
Testing of survey design is made possible in part by the fact that TMRC has the
ability to process the survey field data using its own staff, a capability that
is atypical among independent exploration and production companies. 3-D seismic
processing involves extracting data from magnetic tapes recorded in the field
and filtering that information with a variety of software programs that present
the data in a manner that can be utilized by interpretation software. TMRC
believes that having the capability to process internally gives it greater
control over not only the survey planning but also over the cost and timing of
processing the survey data, and gives it greater flexibility in the assumptions
used in processing the data.
Once processing is complete, TMRC analyzes the data utilizing state of the art
interpretation software and techniques, including amplitude variation with
offset ("AVO"), 3-D and 2-D pre-stack depth migration, coherency and inversion
techniques. In the areas where TMRC is active, the existence of complex geology
and variable acoustic velocities of the subsurface strata make interpretation of
the seismic data in imaging a subsurface structure a highly subjective process,
often requiring the application of combinations of interpretive techniques and
multiple iterations to yield the best solution. In addition to seismic data,
TMRC also utilizes all available subsurface data from wells previously drilled
in the surrounding areas to correlate structural position as well as to test the
validity of hydrocarbon indicators, where applicable. TMRC routinely performs
forward modeling techniques to compare the hypothetical seismic response of
assumed lithology for a target horizon to the actual response of a
lithologically similar interval in a preexisting well within the survey area, if
available. TMRC believes it is one of the few exploration companies to
consistently utilize what is known
5
as "Fault Seal Analysis" to evaluate the probability of a competent seal for
prospects that rely on subsurface faulting for structural closure.
GEOLOGIC AND GEOPHYSICAL EXPERTISE
TMRC currently employs 68 full-time non-union employees. TMRC's exploration
staff is made up of 38 persons, representing over half of TMRC's total
personnel. This staff includes 8 full-time geologists and 9 full-time
geophysicists, with between 8 and 35 years of experience in generating onshore
and offshore prospects in the Louisiana and Texas Gulf Coast and in the Gulf of
Mexico. TMRC's geologists and geophysicists generate and review all prospects
using computer hardware and software owned or licensed and operated by TMRC.
This assemblage of geologists and geophysicists significantly reduces TMRC's
dependence on outside technical consultants and enables TMRC to internally
generate most of its prospects rather than taking promoted prospects generated
by outside geologists.
In the interest of retaining talented technical personnel, TMRC has adopted an
incentive compensation system for its senior geologists and geophysicists that
ties each individual's compensation to the individual's contribution to the
success of TMRC's exploration activities by providing compensation based on
results of the prospects generated by the geologist or geophysicist.
MARKETING OF PRODUCTION
TMRC's production is marketed to third parties consistent with industry
practices. Typically, oil production from the Company's onshore wells is sold at
the wellhead at field posted prices and natural gas is sold under contract at a
negotiated price based upon factors normally considered in the industry, such as
price regulations, distance from the well to the pipeline, well pressure,
estimated reserves, quality of natural gas and prevailing supply and demand
conditions. Pursuant to a farmout by Phillips Petroleum Company ("Phillips") of
leases covering approximately 2,000 acres in the Chocolate Bayou Field to TMRC,
Phillips reserved a call on TMRC's oil and natural gas production from that
field. The gas contract entered into as a result of Phillips exercising its call
on production provides for a contract until December 31, 1998, which will be
renegotiated at that time. Phillips is currently purchasing 100% of TMRC's
natural gas production from the Chocolate Bayou Field at 100% of the quoted
Houston Ship Channel price. Gas production from the Company's onshore properties
is typically sold under short-term contracts or in the spot market.
TMRC's offshore oil production is sold to various purchasers under short-term
arrangements at prices negotiated by third parties, but at prices no less than
such purchasers' posted prices for the respective areas less standard
deductions. Offshore gas production is typically sold pursuant to short-term
contracts or in the spot market.
The following table sets forth purchasers of TMRC's oil and natural gas that
accounted for more than 10% of total revenues for the years indicated:
Year Ended December 31,
----------------------------
CUSTOMER 1997 1996 1995
---- ---- ----
Phillips Petroleum Company ................. 20% 22% 19%
Coastal Corporation ........................ 15% 21% 15%
Koch Oil Company ........................... 15% 12% 7%
6
TMRC believes that the loss of any of these purchasers would not have a material
adverse effect on its results of operations due to the availability of other
purchasers for its oil and natural gas.
MARKET CONDITIONS
TMRC's revenues, profitability and future rate of growth are substantially
dependent upon prevailing prices for natural gas and, to a lesser extent, oil.
Oil and natural gas prices have been extremely volatile in recent years and are
affected by many factors outside the control of TMRC. Since 1992, prices for
West Texas Intermediate ("WTI") crude have ranged from $23.39 to $11.00 per Bbl
and the monthly average of the Gulf Coast spot market natural gas price at Henry
Hub, Louisiana, has ranged from $3.97 to $1.08 per Mcf. In 1997, WTI posted
crude oil prices have ranged between $22.86 to $16.18 per Bbl, and spot natural
gas prices at Henry Hub, Louisiana, have ranged between $3.97 to $1.68 per Mcf.
Prices received by the Company for its oil production have been significantly
depressed since the fourth quarter of 1997 and the WTI postings reached an eight
year low on March 16, 1998 of $11.00 per Bbl. Natural gas prices have similarly
declined, but on a less dramatic basis. These declines in prices of oil and
natural gas have affected the results and associated cash flow of the Company's
properties. The volatile nature of the energy markets makes it difficult to
estimate future prices of oil and natural gas; however, any prolonged period of
depressed prices could have a material adverse effect on the Company's results
of operations and financial condition.
Because the majority of TMRC's production and targeted prospects are natural
gas, TMRC is affected more by changes in natural gas prices than crude oil
prices. Sales of oil and natural gas also have historically been seasonal in
nature, which may lead to substantial differences in cash flow at various times
throughout the year. The marketability of TMRC's production depends in part upon
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, all could adversely affect TMRC's ability to
produce and market its oil and natural gas. If market factors were to change
dramatically, the financial impact on TMRC could be substantial. The
availability of markets and the volatility of product prices are beyond the
control of TMRC and thus represent a significant risk.
COMPETITION
The oil and natural gas industry is highly competitive for prospects, acreage
(including offshore in the Gulf of Mexico) and capital. TMRC's competitors
include numerous major and independent oil and natural gas companies, individual
proprietors, drilling and income programs and partnerships. Many of these
competitors possess and employ financial and personnel resources substantially
in excess of those available to TMRC and may, therefore, be able to define,
evaluate, bid for and purchase a greater number of oil and natural gas
properties than TMRC. However, by utilizing technological advances, such as 3-D
seismic technology, TMRC believes it has enhanced its competitive position
relative to others in the industry that do not similarly rely on such
technology. 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 upon numerous factors beyond TMRC's 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,
7
a productive natural gas well may be "shut-in" because of an oversupply of
natural gas or lack of an available natural gas pipeline in the areas in which
TMRC 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 binding on 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 TMRC's cost of doing business and, consequently, affects
its profitability.
All of the Company's offshore oil and gas leases are granted by the federal
government and are administered by the Mineral Management Service (the "MMS").
Such 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
are generally restricted to United States citizens and domestic corporations.
Assignments of these leases or interests therein are subject to approval by the
MMS.
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.
Such 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 oil and gas can be produced from the Company's properties.
GAS PRICE CONTROLS
Prior to January 1993, certain natural gas was subject to regulation by the
Federal Energy Regulatory Commission ("FERC") under the Natural Gas Price Act
("NGPA") which prescribed maximum lawful prices for natural gas sales effective
December 1, 1978. Effective January 1, 1993, natural gas prices were completely
deregulated. Consequently, sales of TMRC's natural gas after such date may be
made at market prices.
The FERC regulates interstate natural gas pipeline transportation rates and
service conditions which affect the marketing of natural gas produced by TMRC,
as well as the revenues received by TMRC for sales of such natural gas. Since
the latter part of 1985, the FERC has adopted policies intended to make natural
gas transportation more accessible to gas buyers and sellers on an open and
non-discriminatory basis. The FERC's latest action in this area, Order No. 636,
reflected the FERC's finding that under the then current regulatory structure,
interstate pipelines and other gas merchants,including producers, did not
compete on a "level playing field" in selling gas. Order No. 636 instituted
individual pipeline service restructuring proceedings, designed specifically to
"unbundle" those services (e.g., transportation, sales and storage) provided by
many interstate pipelines so that buyers of natural gas may secure gas supplies
and delivery services from the most economical source, whether interstate
pipelines or other parties. The FERC has issued final orders in almost all
restructuring proceedings.
8
Although Order No. 636 does not regulate gas producers such as TMRC, the FERC
has stated that Order No. 636 is intended to foster increased competition within
all phases of the natural gas industry. It is unclear what impact, if any,
increased competition within the natural gas industry under Order No. 636 will
have on TMRC and its marketing efforts, although recent price declines for
natural gas may be attributable, in part, to better gas distribution resulting
from Order No. 636. In addition, numerous petitions seeking judicial review of
Order No. 636 and the individual pipeline restructuring orders have been filed.
It is not possible to predict what, if any, effect the final restructuring rule
will have on TMRC. TMRC does not believe, however, it will be affected by any
action taken with respect to Order No. 636 any differently than other gas
producers and marketers with which it competes.
The FERC has adopted a policy concerning "spin-downs" and "spin-offs" of
gathering systems operated by jurisdictional pipelines to non-jurisdictional
entities. Because TMRC utilizes gathering service for the transportation of gas
from the wellhead to gas transmission pipelines, TMRC could be affected by this
policy. In reviewing applications for "spin-downs" and" spin-offs," the FERC has
considered whether existing shippers have satisfactory contractual arrangements
for gathering in place. In instances in which this is not the case, the
gathering company has been required to offer a "default" contract for gathering
services. The impact that this new policy will have on the gathering rates paid
by TMRC or the gathering services received by TMRC cannot yet be determined.
Additional proposals and proceedings that might affect the natural gas industry
are pending before Congress, the FERC and the courts. The natural gas industry
historically has been very heavily regulated; therefore, there is no assurance
that the less stringent regulatory approach recently pursued by the FERC and
Congress will continue.
OIL PRICE CONTROLS
Sales of crude oil, condensate and gas liquids by TMRC are not regulated and are
made at market prices.
STATE REGULATION OF OIL AND NATURAL GAS PRODUCTION
States in which TMRC conducts its oil and natural gas activities regulate the
production and sale of oil and natural gas, including requirements for obtaining
drilling permits, the method of developing new fields, the spacing and operation
of wells and the prevention of waste of natural gas and resources. In addition,
most states regulate the rate of production and may establish maximum daily
production allowables for wells on a market demand or conservation basis.
ENVIRONMENTAL REGULATION
TMRC's 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 the acquisition
of a permit before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution resulting from
TMRC's operations. Moreover, the recent trend toward stricter standards in
environmental legislation and regulation is likely to continue. For instance,
legislation has been proposed in Congress from time to time that would
reclassify certain oil and gas exploration and production wastes as "hazardous
wastes" which would make the reclassified wastes subject to much more stringent
handling, disposal and clean-up requirements. If such legislation were to be
enacted, it could have a significant impact on the operating costs of TMRC, as
well as the oil and natural gas industry
9
in general. Initiatives to further regulate the disposal of oil and gas wastes
are also pending in certain states, and these various initiatives could have a
similar impact on TMRC. Management believes that TMRC is in substantial
compliance with current applicable environmental laws and regulations and that
continued compliance with existing requirements will not have a material adverse
impact on TMRC.
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 in which an offshore facility is
located. The OPA assigns liability to each responsible party 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
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating regulation. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by the
OPA.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. On August 25, 1993, the MMS published an advance notice of its intention
to adopt a rule under the OPA that would require owners and operators of
offshore oil and gas facilities to establish $150 million in financial
responsibility. Under the proposed rule, financial responsibility could be
established through insurance, guaranty, indemnity, surety bond, letter of
credit, qualification as a self-insurer or a combination thereof. There is
substantial uncertainty as to whether insurance companies or underwriters will
be willing to provide coverage under the OPA because the statute provides for
direct lawsuits against insurers who provide financial responsibility coverage,
and most insurers have strongly protested this requirement. The financial tests
or other criteria that will be used to judge self-insurance are also uncertain.
The Company cannot predict the final form of the financial responsibility rule
that will be adopted by the MMS, but such rule has the potential to result in
the imposition of substantial additional annual costs on the Company or
otherwise materially adversely affect the Company. The impact of the rule should
not be any more adverse to the Company than it will be to other similarly
situated or less capitalized owners or operators in the Gulf of Mexico.
The OPA also imposes other requirements, such as the preparation of an oil spill
contingency plan. The Company has such a plan in place. Failure to comply with
ongoing requirements or inadequate cooperation during a spill event may subject
a responsible party to civil or criminal enforcement actions.
CERCLA. The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes 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 and under CERCLA such
persons or companies would 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. 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.
PRODUCING PROPERTIES
The following table sets forth reserve and production information by region with
respect to TMRC's proved oil and gas reserves as of January 1, 1998. Ryder Scott
Company, independent petroleum engineers, has reviewed the reserve volumes
estimated by TMRC.
10
PRESENT
VALUE 1997
RESERVES FUTURE PRODUCTION
------------------ NET ---------------------
OIL GAS REVENUES OIL GAS
REGION (MBBLS) (MMCF) (000)(1) (MBBLS) (MMCF)
------ ------- ------ -------- ------- ------
Texas........................... 563 22,629 $34,291 56 3,644
Louisiana....................... 4,269 10,860 49,173 538 1,741
Gulf of Mexico.................. 4,899 75,268 127,934 320 8,880
Appalachian..................... -- 2,028 2,519 -- 338
----- ------- -------- --- ------
Total................... 9,731 110,785 $213,917 914 14,603
===== ======= ======== === ======
- ---------------
(1) The Standardized Measure of Discounted Future Net Cash Flows prepared by
TMRC represents the Present Value of Future Net Revenues after income
taxes discounted at 10%. The prices used for calculating the Present
Value of Future Net Revenues were the prices being received by TMRC at
December 31, 1997, and were $ 17.31 per bbl of oil and $ 2.53 per Mcf of
natural gas.
PRODUCTIVE WELLS
At December 31, 1997, 1996, and 1995, TMRC held interests in the following
productive wells. The majority of the Company's 96 gross (20.7 net) wells in the
Gulf of Mexico have multiple completions.
December 31,
---------------------------------------------------------
1997 1996 1995
---------------- ---------------- -----------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Oil Wells............. 16 6.8 12 4.1 10 2.6
Gas Wells............. 345 94.0 337 90.9 316 83.4
--- ----- --- ---- --- ----
Total......... 361 100.8 349 95.0 326 86.0
=== ===== === ==== === ====
CURRENT PROSPECTS
TMRC is actively pursuing its exploration and development program with more than
150 prospects under various stages of review and has analyzed, acquired or has,
or expects to obtain rights to acquire interests in 3-D seismic data covering
approximately 1,850 square miles in south Louisiana and southeast Texas relating
to these prospects. Since December 31, 1997, TMRC has completed drilling 7
wells, 3 of which have been successful. TMRC also is currently drilling 3 wells
and expects to drill up to 25 additional wells during the remainder of 1998. The
total cost of TMRC's exploration and development program, including lease and
seismic data acquisition costs, through the end of 1998 is currently estimated
to be approximately $135 million, excluding any expenditures relating to the
Shell Transactions, subject to adjustment depending upon drilling results,
timely delivery and analysis of seismic data, the availability of drilling
equipment, availability of capital and other factors. TMRC has recently
reaffirmed its exploration strategy and is implementing a renewed effort at
accelerating and increasing its exploration program for the ensuing twelve
months.
11
OIL AND NATURAL GAS RESERVES
Presented below are the estimated quantities of proved reserves of crude oil and
natural gas, the Estimated Future Net Revenues (before income taxes), the
Present Value of Future Net Revenues and the Standardized Measure of Discounted
Future Net Cash Flows for TMRC as of December 31, 1997. Information set forth in
the following table is based upon reserve reports prepared by the Company in
accordance with the rules and regulations of the Securities and Exchange
Commission (the "Commission"). The reserve volumes estimated by TMRC were
reviewed by Ryder Scott Company.
Proved Reserves at December 31, 1997
---------------------------------------------------------
Developed Developed
Producing Non-producing Undeveloped Total
--------- ------------- ----------- -----
(dollars in thousands)
Net Proved Reserves:
Oil (MBbls)............................ 1,664 3,641 4,426 9,731
Gas (MMcf)............................. 34,501 46,999 29,285 110,785
MMCFE.................................. 44,485 68,845 55,841 169,171
Estimated Future Net Revenues (Before Income Taxes)........................................ $341,776
Present Value of Future Net Revenues....................................................... $213,917
Standardized Measure of Discounted Future Net Cash Flows(1)................................ $213,917
- ---------------
(1) The Standardized Measure of Discounted Future Net Cash Flows prepared by
TMRC represents the Present Value of Future Net Revenues after income
taxes discounted at 10%. The prices used for calculating the Present
Value of Future Net Revenues were the prices being received by TMRC at
December 31, 1997, and were $ 17.31 per bbl of oil and $ 2.53 per Mcf of
natural gas.
Subsequent to December 31, 1997, prices of oil and natural gas have declined. If
prices in effect at March 1, 1998, were to be applied to the Company's reserves
at December 31, 1997, the Standardized Measure of Discounted Future Net Cash
Flows would have been $ 40 to $ 45 million less than it was at year end.
Additional reserve information is set forth in TMRC's Consolidated Financial
Statements and the Supplemental Oil and Gas Information (unaudited) included
elsewhere herein. TMRC has 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, estimates of economically recoverable oil and natural gas reserves
and of the future net revenues therefrom are based upon a number of variable
factors and assumptions, such as historical production from the subject
properties, the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices and future operating
costs, all of which may vary considerably from actual results. All such
estimates are to some degree speculative, and classifications of reserves are
only attempts to define the degree of speculation involved. For these reasons,
estimates of the economically recoverable oil and natural gas reserves
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery and estimates of the future net revenues
expected therefrom, prepared by different engineers or by the same engineers at
different times, may vary substantially. Therefore, the actual production,
revenues, severance and excise taxes, development and operating expenditures
with respect to TMRC's reserves will
12
likely vary from such estimates, and such variances could be material.
Estimates with respect to proved reserves that may be developed and produced in
the future are often based upon volumetric calculations and upon 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 upon
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 such date. Actual future prices and costs may be
materially higher or lower. Actual future net revenues also will be affected by
factors such as actual production, supply and demand for oil and natural gas,
curtailments or increases in consumption by natural gas purchasers, changes in
governmental regulations or taxation and the impact of inflation on costs.
OIL AND NATURAL GAS DRILLING ACTIVITIES
The following table sets forth the gross and net number of productive, dry and
total exploratory and development wells that TMRC drilled in each of 1997, 1996
and 1995.
Gross Wells Net Wells
----------- ---------
Productive Dry Total Productive Dry Total
---------- --- ----- ---------- --- -----
Exploratory Wells
Year Ended December 31, 1997 7 9 16 4.4 3.5 7.9
Year Ended December 31, 1996 15 13 28 6.0 5.3 11.3
Year Ended December 31, 1995 11 7 18 3.7 2.2 5.9
Development Wells
Year Ended December 31, 1997 3 -- 3 .8 -- .8
Year Ended December 31, 1996 -- -- -- -- -- --
Year Ended December 31, 1995 1 -- 1 .8 -- .8
13
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 TMRC held an interest during the last three years.
Year Ended December 31,
-----------------------
1997 1996 1995
---- ---- ----
Production:
Oil (MBbls).................................... 914 751 650
Natural Gas (MMcf) ............................ 14,603 15,783 14,598
MMCFE.......................................... 20,087 20,289 18,498
Average Prices:
Oil ($/Bbl).................................... $19.72 $21.92 $18.04
Natural Gas ($/Mcf)............................ $2.70 $2.44 $1.71
MCFE ($/Mcf)................................... $2.86 $2.71 $1.99
Production Expenses:
Lease operating expenses ($/MCFE).............. $0.28 $0.23 $0.20
Severance and ad valorem taxes ($/MCFE)........ $0.11 $0.08 $0.05
ACREAGE
The following table sets forth the developed and undeveloped oil and natural gas
acreage in which TMRC held an interest as of December 31, 1997. 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.
Region Developed Undeveloped
------ --------- -----------
Gross Net Gross Net
----- --- ----- ---
Texas.......................... 1,510 1,172 53 53
Louisiana...................... 1,523 883 17,603 11,449
Gulf of Mexico................. 124,860 30,605 266,120 105,650
Appalachian ................... 12,000 3,226 -- --
-------- ------- ------- -------
Total.................... 139,893 35,886 283,776 117,152
======= ====== ======= =======
In addition to the above acreage, TMRC currently has options or farm-ins to
acquire leases on 49,391 Gross (36,362 net) acres of undeveloped land located in
Texas and Louisiana. TMRC's fee holdings of 4,915 acres has been included in the
undeveloped acreage and has been reduced to reflect the interest which has been
leased to third parties.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, TMRC makes only a cursory
review of title to undeveloped oil and natural gas leases at the time they are
acquired by TMRC. However, before drilling commences,
14
TMRC causes a thorough title search to be conducted, and any material defects in
title are remedied prior to the time actual drilling of a well on the lease
begins. To the extent title opinions or other investigations reflect title
defects, TMRC, rather than the seller or lessor of the undeveloped property, is
typically obligated to cure any such title defects at its expense. If TMRC were
unable to remedy or cure any title defect of a nature such that it would not be
prudent to commence drilling operations on the property, TMRC could suffer a
loss of its entire investment in the property. TMRC believes that it has good
title to its oil and natural gas properties, some of which are subject to
immaterial encumbrances, easements and restrictions. Under the terms of TMRC's
credit agreement, TMRC is prohibited from granting liens on various of its
properties and is required to grant to its bank a lien on such property in the
event of certain defaults. The oil and natural gas properties owned by TMRC are
also typically subject to royalty and other similar non-cost bearing interests
customary in the industry. TMRC is currently in a dispute with respect to its
interest in the Southwest Holmwood field and its interest in this field is
subject to the outcome of this litigation. See "--Amoco Litigation."
Substantial portions of TMRC's 3-D seismic data has been acquired through
licenses and other similar arrangements. Such licenses contain transfer and
other restrictions customary in the industry.
15
ITEM 2. PROPERTIES
PRODUCING PROPERTIES
For information regarding the Company's properties, see "Item 1. Business"
above.
ITEM 3. LEGAL PROCEEDINGS
In June 1996, Amoco Production Company ("Amoco") filed suit against the Company
in Louisiana State Court in Calcasieu Parish with respect to a dispute involving
the drilling by the Company of the Company's Ben Todd No. 1 (TMRC) well in the
Southwest Holmwood Field in which the Company ET AL and Amoco each hold a 50%
leasehold interest. The case was removed to the United States District Court for
the Western District of Louisiana in July 1996. The Ben Todd No. 1 (TMRC) well
was drilled by the Company under a participation agreement between the Company
and Amoco in which Amoco had a right to participate in the well. The well was
drilled by the Company after providing notice to Amoco pursuant to the
participation agreement of the Company's intent to drill the well and Amoco's
failure to take action to elect to participate in the well. Prior to the
drilling of the well, the Company had been advised by its advisors that the
drilling of the well by the Company was permitted under the participation
agreement by virtue of Amoco's refusal to reasonably consent to the well
following TMRC's request to do so. Amoco also did not seek to enjoin the
drilling of the well and accepted the benefits of the well following the
drilling thereof as well as other benefits under the participation agreement and
lease. Amoco alleged in its suit that the well was not permitted to be drilled
under the agreement and sought to recover all the revenues from the well or have
the production from the well stopped. Amoco requested that the trial court
cancel the participation agreement and the Company's leasehold interest in the
prospect, which includes the Company's 50% interest in the Ben Todd No. 2
(Amoco) well that was drilled prior to the Ben Todd No. 1 (TMRC) well on an
agreed basis. The Company filed a counterclaim for breach of contract, unfair
practices and other claims.
On December 22, 1997, the Federal District Court entered a judgment against the
Company in this matter and ordered that the Company was not permitted under the
participation agreement to drill the Ben Todd No. 1 (TMRC) well and that the
participation agreement and related lease had been terminated by virtue of the
Company's drilling of the well. The trial court also dismissed the Company's
counterclaims against Amoco. The trial court further ordered a reversion of the
Company's rights with respect to the Ben Todd No. 1 (TMRC) and the Ben Todd No.
2 (Amoco) and directed TMRC to account for all production and monies received by
it from the date of the cancellation of the lease. The Company has calculated
the production and revenues received by it as operator from these properties to
which the trial court has ordered to be returned to Amoco to be approximately
4.0 Bcfe and $10.2 million. The Company recorded a charge of $6.2 million in the
fourth quarter of 1997, representing its estimated portion of the potential
loss, which is net of approximately $4.0 million of amounts that would be
recoverable from third parties with respect to the Amoco lawsuit. Management
does not expect any material additional charges to be made with respect to this
matter. The Company has reported no reserves related to these properties as of
December 31, 1997.
16
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the Special Meeting of Shareholders of the Company held on November 5, 1997,
the Company's shareholders voted in favor of a proposal to approve and adopt an
Agreement and Plan of Merger dated as of July 3, 1997, pursuant to which the
Company combined with Cairn. The number of shares voted for and against and the
number of abstentions for with respect to the proposal was as follows:
BROKER
NON-VOTES/
PROPOSAL FOR AGAINST ABSTAIN
- -------- --- ------- -------
Merger of Cairn into the Company 9,653,343 156,740 31,221
17
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The common stock is traded on the New York Stock Exchange under the symbol
"TMR." Prior to April 3, 1997, the Common Stock was traded on the American Stock
Exchange (the "AMEX"). 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 Composite Tape and the AMEX:
HIGH LOW
---- ---
1997:
First quarter.......................... 16 7/8 12 1/2
Second quarter......................... 13 3/8 11 1/8
Third quarter.......................... 14 1/8 9 7/8
Fourth quarter ........................ 14 1/8 8
1996:
First quarter.......................... 14 10 3/4
Second quarter......................... 13 9
Third quarter.......................... 15 1/8 9 5/16
Fourth quarter......................... 18 1/2 14 5/8
The closing sale price of the common stock on March 27, 1998, as reported on the
New York Stock Exchange Composite Tape, was $ 8.00. As of March 27, 1998, the
Company had approximately 955 shareholders of record.
The Company 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. The Company
currently intends to retain its cash for the continued development of its
business, including exploratory and development drilling activities. The Company
is also currently restricted under its Chase Manhattan Bank Credit Agreement
from expending more than $500,000 in the aggregate for cash dividends on the
common stock or for purchases of shares of common stock without the prior
consent of the lender.
18
ITEM 6. RESTATED SELECTED FINANCIAL DATA
All financial data which has been restated for the merger with Cairn should be
read in conjunction with the Consolidated Financial Statements of TMRC and
related notes thereto included elsewhere in this report. The merger with Cairn
was accounted for as a pooling-of-interest, and accordingly all financial data
has been restated to include the financial position and results of operations
for Cairn for all periods presented.
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
(In thousands, except per share data)
A. SUMMARY OF OPERATING DATA
Production Data:
Oil (MBbl) 914 751 650 163 140
Natural gas (Mmcf) 14,603 15,783 14,598 7,116 7,048
Natural gas equivalent (Mmcfe) 20,087 20,289 18,498 8,094 7,888
Average Prices:
Oil ($/Bbl) $19.72 $21.92 $18.04 $15.14 $16.20
Natural gas ($/Mcf) $2.70 $2.44 $1.71 $2.01 $2.23
Natural gas equivalent ($/Mcfe) $2.86 $2.71 $1.99 $2.07 $2.28
B. SUMMARY OF OPERATIONS
Total revenues $58,333 $56,733 $38,230 $17,752 $18,549
Depletion and depreciation $26,337 $25,342 $18,491 $7,788 $7,494
Net income (loss) ($28,541) $16,692 $7,458 $1,661 ($1,980)
Net income (loss) per share:
Basic ($ .85) $ .50 $ .25 $ .07 ($ .11)
Diluted ($ .85) $ .47 $ .23 $ .06 ($ .11)
Dividends per common share ----- ----- ----- ----- -----
Weighted average common
shares outstanding 33,383 33,399 30,207 24,485 18,815
C. SUMMARY BALANCE SHEET DATA
Total assets $292,558 $245,757 $193,134 $126,124 $82,067
Long-term obligations, inclusive
of current maturities $107,195 $42,000 $15,500 $23,500 $9,600
Stockholders' equity $145,102 $171,432 $154,924 $93,685 $66,899
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
ACQUISITION OF SHELL PROPERTIES. On March 27, 1998, the Company and affiliates
of Shell Oil Company (collectively, "Shell") executed a definitive merger
agreement which, together with a separate purchase and sale agreement
(collectively referred to herein as the "Shell Agreements" and the transactions
contemplated by the Shell Agreements are referred to herein as the "Shell
Transactions"), will result in the Company acquiring all of Shell's producing
and exploration properties in South Louisiana in exchange for shares of common
and convertible preferred stock representing 39.9% of the common stock of the
Company as of the closing, assuming exercise of all stock options, warrants and
conversion of the preferred stock, and $42.5 million in cash.
Following the Shell Transactions, the Company is expected to control over
329,000 gross onshore acres in Louisiana and Texas with approximately 2,800
square miles of onshore 3-D seismic data, which the Company believes to be one
of the largest positions held by a company with TMRC's market capitalization.
The Company estimates that is current production base following the Shell
Transactions will be approximately 22,000 equivalent barrels of oil per day and
that proved reserves will total over 48.6 million equivalent barrels of oil
having an estimated reserve life of approximately six years.
The terms of the Shell Agreements call for Shell to receive a fixed 39.9% of the
post-transaction common stock of the Company, assuming exercise of all stock
options, warrants and conversion of the preferred stock, comprised of 12.082
million shares of Common Stock and shares of a new series of preferred stock
(the "Preferred Stock") convertible into approximately 12.827 million shares of
Common Stock. The Preferred Stock will have a stated value of $135 million, a 4%
annual dividend for a period of five years (with the dividend reducing in amount
by one-third in each year starting at the end of two years so that no dividends
will be payable after five years) and a conversion price of approximately $10.52
per share. The Preferred Stock will convert automatically into Common Stock if
the market price of the Common Stock is greater than or equal to 150% of the
conversion price for 75 consecutive trading days. Terms of the Shell
Transactions are not subject to changes in the market price of the Common Stock.
To insure the Company's ability to function as an independent oil and gas
company, Shell has agreed to restrict its discretionary voting rights on
non-extraordinary corporate issues requiring a shareholder vote to 23% of the
outstanding voting shares, with the remainder of its holdings to be voted in the
same ratio as the shares voted by other shareholders and Shell's unrestricted
shares. Shell also has agreed to restrictions on its ability to sell shares and
will be provided with certain rights to purchase additional shares to the extent
necessary to maintain at least a 21% beneficial ownership interest in the
Company. Shell will be entitled to one seat on the Company's board of directors.
The consummation of the Shell Transactions is subject to approval of the
shareholders of the Company and certain other customary conditions. The Company
currently anticipates that a closing of the Shell Transactions will occur either
late in the second quarter or early in the third quarter of 1998.
CAIRN MERGER. On November 5, 1997, the Company acquired by merger (the "Merger")
Cairn. In the Merger, the Company issued approximately 19.0 million shares of
Common Stock, $0.01 par value ("Common Stock"). The Merger more than doubled the
Company's proved reserves and substantially increased the production and cash
flow of the Company. In connection with the Merger, the Company expanded its
working capital line of credit to $125.0 million and repaid all of Cairn's
outstanding bank debt. The Merger was accounted for as a pooling of interests
and the Company's historical financial statements and operating results and the
discussion of such results in this Management's Discussion and Analysis of
Financial Conditions and Results of Operations have been restated to reflect the
combined operations of the Company and Cairn for the periods presented. The
Company recorded a one-time charge in the fourth quarter of approximately $10
million for costs associated with the Merger.
20
CEILING WRITEDOWN AND INDUSTRY CONDITIONS. The Company's revenues, profitability
and future rate of growth are substantially dependent upon prevailing prices for
natural gas and, to a lesser extent, oil. Oil and natural gas prices have been
extremely volatile in recent years and are affected by many factors outside the
control of TMRC. Since 1992, prices for West Texas Intermediate ("WTI") crude
have ranged from $23.39 to $11.00 per Bbl and the monthly average of the Gulf
Coast spot market natural gas price at Henry Hub, Louisiana, has ranged from
$3.97 to $1.08 per Mcf. In 1997, WTI crude oil prices have ranged between $23.39
to $16.18 per Bbl, and spot natural gas prices at Henry Hub, Louisiana, have
ranged between $3.97 to $1.68 per Mcf. Prices received by the Company for its
oil production have been significantly depressed since the fourth quarter of
1997 and WTI posting reached an eight year low of $11.00 on March 16, 1998.
Natural gas prices have similarly declined, but on a less dramatic basis. These
declines in prices of oil and natural gas have affected the results and
associated cash flow of the Company's properties. The volatile nature of the
energy markets makes it difficult to estimate future prices of oil and natural
gas; however, any prolonged period of depressed prices could have a material
adverse effect on the Company's results of operations and financial condition.
The Company follows the full cost method of accounting for its investments in
oil and natural gas properties, which requires that the net carrying value of
oil and natural gas properties is limited to the sum of the present value (10%
discount rate) of the estimated future net cash flows from proved reserves,
based on the current prices and costs, plus the lower of cost or estimated value
of unproved properties. Due to prevailing market conditions as of December 31,
1997, the average prices utilized by the Company in determining the net carrying
value of its oil and natural gas properties were $2.53 per Mcf and $17.31 per
Bbl, compared to $4.10 per Mcf and $24.36 per Bbl utilized to calculate such
value at December 31, 1996. As a result of this significant decline in oil and
natural gas prices, the Company recognized a $24.1 million non-cash write-down
of its oil and natural gas properties under the full cost method of accounting.
Since the net carrying value of the Company's oil and natural gas properties
have been reduced due to the full cost ceiling limitation such that the present
value of the Company's proved oil and gas reserves do not exceed the Company's
net oil and gas properties recorded on its balance sheet, there is an increased
risk of future property write-downs due to factors that negatively affect the
present value of proved oil and gas reserves, including volatile oil and gas
prices, downward revisions in estimated proved oil and natural gas quantities
and unsuccessful exploratory operations. In this regard, because prices have
further declined since December 31, 1997, the Company expects to record an
additional write-down during the first quarter of 1998. Based upon oil and
natural gas prices in effect at March 1, 1998, this writedown is expected to be
between $40 million and $45 million, and further write-downs are possible if
market conditions do not improve.
AMOCO LITIGATION. In June 1996, Amoco Production Company ("Amoco") filed suit
against the Company in Louisiana State Court in Calcasieu Parish with respect to
a dispute involving the drilling by the Company of the Company's Ben Todd No. 1
(TMRC) well in the Southwest Holmwood Field in which the Company ET AL and Amoco
each hold a 50% leasehold interest. The case was removed to the United States
District Court for the Western District of Louisiana in July 1996. The Ben Todd
No. 1 (TMRC) well was drilled by the Company under a participation agreement
between the Company and Amoco in which Amoco had a right to participate in the
well. The well was drilled by the Company after providing notice to Amoco
pursuant to the participation agreement of the Company's intent to drill the
well and Amoco's failure to take action to elect to participate in the well.
Prior to the drilling of the well, the Company had been advised by its advisors
that the drilling of the well by the Company was permitted under the
participation agreement by virtue of Amoco's refusal to reasonably consent to
the well following TMRC's request to do so. Amoco also did not seek to enjoin
the drilling of the well and accepted the benefits of the well following the
drilling thereof as well as other benefits under the participation agreement or
lease. Amoco alleged in its suit that the well was not permitted to be drilled
under the agreement and sought to recover all the revenues from the well or have
the production from the well stopped. Amoco requested that the trial court
cancel the participation agreement and the Company's leasehold interest in the
prospect, which includes the Company's 50% interest in the Ben Todd No. 2
(Amoco)
21
well that was drilled prior to the Ben Todd No. 1 (TMRC) well on an agreed
basis. The Company filed a counterclaim for breach of contract, unfair practices
and other claims.
On December 22, 1997, the Federal District Court entered a judgment against the
Company in this matter and ordered that the Company was not permitted under the
participation agreement to drill the Ben Todd No. 1 (TMRC) well and that the
participation agreement and related lease had been terminated by virtue of the
Company's drilling of the well. The trial court also dismissed the Company's
counterclaims against Amoco. The trial court further ordered a reversion of the
Company's rights with respect to the Ben Todd No. 1 (TMRC) and the Ben Todd No.
2 (Amoco) and directed TMRC to account for all production and monies received by
it from the date of the cancellation of the lease. The Company has calculated
the production and revenues received by it as operator from those properties to
which the trial court has ordered to be returned to Amoco to be approximately
4.0 Bcfe and $10.2 million. The Company recorded a charge of $6.2 million in the
fourth quarter of 1997, representing its estimated portion of the potential
loss, which is net of approximately $4.0 million of amounts that would be
recoverable from third parties with respect to the Amoco lawsuit. Management
does not expect any material additional charges to be made with respect to this
matter. The Company has reported no reserves related to these properties as of
December 31, 1997.
RESULTS OF OPERATIONS
TWELVE MONTHS ENDED DECEMBER 31, 1997 COMPARED TO THE TWELVE MONTHS ENDED
DECEMBER 31, 1996
OPERATING REVENUES AND PRODUCTION.
During 1997, production remained relatively flat compared to 1996. Although the
Company experienced production increases during 1997 attributable to the
continuing increase in exploration and development activities by the Company and
the addition of 10 new producing wells, those increases were offset by normal
declines in oil and natural gas production from older wells as well as a
significant decline in production from wells in the Company's Southwest Holmwood
Field in Louisiana during the third quarter of 1997 due to poor production
performance from the wells in this field as well as the elimination of
production from these wells during the fourth quarter of 1997 as a result of the
Amoco litigation described above. In addition, during the fourth quarter of
1997, production from certain offshore wells was temporarily interrupted due to
a ruptured pipeline. The following table summarizes operating revenues,
production volumes and average sales prices for the Company for the twelve
months ended December 31, 1997 and 1996.
22
YEAR ENDED PERCENTAGE
DECEMBER 31 INCREASE
1997 1996 (DECREASE)
---- ---- ----------
Production
Natural Gas (MMcf) 14,603 15,783 (7%)
Oil (MBbls) 914 751 22%
MMCFE 20,087 20,289 (1%)
Average Sales Price:
Natural Gas ($/Mcf) $2.70 $2.44 11%
Oil ($/Bbl) $19.72 $21.92 (10%)
MCFE ($/Mcf) $2.86 $2.71 6%
Gross Revenues (000's)
Natural Gas $39,398 $38,454 2%
Oil 18,021 16,462 9%
Pipeline 221 207 7%
--------- --------- ------------
Total: $57,640 $55,123 5%
========= ========= ============
OPERATING EXPENSES.
Oil and natural gas operating expenses increased $984,000 to $5,680,000 in 1997,
compared to $4,696,000 in 1996. The increase was primarily due to added
operating expenses related to 10 additional wells brought on production during
1997. As a percentage of operating revenues, oil and natural gas operating
expenses increased to 9.9% for 1997, compared to 8.5% for 1996. This increase is
primarily attributable to the Company placing a higher proportion of oil wells
on stream during the year, which historically have had higher operating expenses
than natural gas wells.
SEVERANCE AND AD VALOREM TAXES.
Severance and ad valorem taxes increased $488,000 to $2,165,000 in 1997,
compared to $1,677,000 in 1996. This increase is partially the result of
increased revenues relating to increased oil production and increased natural
gas prices. In addition, severance and ad valorem taxes in 1996 were more
heavily affected than in 1997 by a Louisiana severance tax reduction incentive
for new field discoveries and wells drilled below 15,000 feet.
DEPLETION AND DEPRECIATION.
Depletion and depreciation expenses for the Company increased $995,000 to
$26,337,000 in 1997, compared to $25,342,000 in 1996. The increase is primarily
related to a 4% increase in the depletion rate during 1997.
INTEREST AND OTHER INCOME.
Interest and other income decreased $917,000 to $693,000 for 1997 as compared to
$1,610,000 for 1996. The decrease was due primarily to decreases in cash
balances.
GENERAL AND ADMINISTRATIVE EXPENSE.
General and administrative expenses increased $1,422,000 to $7,192,000 in 1997,
compared to $5,770,000 in 1996. This increase was primarily due to increases in
salaries and wages and related employee costs associated with the Company's
expanded exploration and overall growth activities.
23
INTEREST EXPENSE.
Interest expense increased $2,567,000 to $5,149,000 in 1997 compared to
$2,582,000 in 1996. This increase was primarily due to increased borrowings
under the Company's credit facility to finance its on going exploration and
development activities.
IMPAIRMENT OF LONG-LIVED ASSETS.
As previously described, the Company recorded a write-down of $24.1 million
relating to its oil and gas properties due to significant decreases in oil and
natural gas prices as of December 31, 1997.
MERGER EXPENSES.
As previously described in accordance with the pooling-of-interest method of
accounting, the Company expensed $10.0 million of costs associated with the
Cairn Merger.
LITIGATION EXPENSES.
As previously described, the Company incurred a charge of $6.2 million relating
to the Amoco litigation.
YEARS ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
OPERATING REVENUES AND PRODUCTION.
For the fiscal year ended 1996, the Company reported significant increases in
reserves, production and cash flow from oil and natural gas producing
activities. These increases were the result of exploration activities in both
its onshore and offshore properties. During 1996, the Company placed on
production 13 wells. In addition, production levels benefitted from a full year
of production from the Company's 12 wells that began producing in 1995 as well
as from favorable market conditions during 1996 which significantly increased
the prices received for both oil and natural gas over 1995 levels. The following
table summarizes operating revenues, production volumes, and average sales
prices for the Company's oil and natural gas for the years ended December 31,
1996 and 1995.
24
1996/95
YEAR ENDED PERCENTAGE
DECEMBER 31, INCREASE
1996 1995 (DECREASE)
---- ---- ----------
Production
Natural Gas (MMcf) 15,783 14,598 8%
Oil (MBbls) 751 650 16%
MMCFE 20,289 18,498 10%
Average Sales Price:
Natural Gas ($/Mcf) $ 2.44 $ 1.71 43%
Oil ($/Bbl) 21.92 18.04 21%
MCFE ($/Mcf) 2.71 1.99 36%
Gross Revenues (000's):
Natural Gas $38,454 $25,012 54%
Oil 16,462 11,729 40%
Pipeline 207 225 (8%)
---------- ---------- -------------
Total $55,123 $36,966 49%
========== ========== =============
OPERATING EXPENSES.
Oil and natural gas operating expenses increased $961,000 to $4,696,000 in 1996
compared to $3,735,000 in 1995, primarily due to additional wells that were
placed on production during 1996.
SEVERANCE AND AD VALOREM TAXES.
Severance and ad valorem taxes increased by $711,000 to $1,677,000 in 1996,
compared to $966,000 in 1995. This increase was the result of the Company's
increased oil and natural gas production and revenues and were partially offset
by a Louisiana severance tax reduction incentive for new field discoveries and
wells drilled below 15,000 feet.
DEPLETION AND DEPRECIATION.
Depletion and depreciation expense for the Company increased $6,851,000 to
$25,342,000 for 1996, compared to $18,491,000 for 1995. The increases were
primarily the result of increased production and a depletion rate increase
during 1996.
INTEREST AND OTHER INCOME.
Interest and other income increased $346,000 to $1,610,000 during 1996, compared
to $1,264,000 in 1995. This increase resulted from higher cash balances after a
1995 common stock offering and an increase in interest rates during 1996 from
1995.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expense increased $1,109,000 to $5,770,000 in 1996,
compared to $4,661,000 in 1995. This increase was primarily due to increased
employee costs associated with the Company's expanded exploration activities.
25
INTEREST EXPENSE.
Interest expense in 1996 remained relatively unchanged from 1995 levels.
Interest expense was reduced by the retirement of TMRC's bank debt in late 1995
following TMRC's 1995 common stock which was offset by interest on increased
borrowings under Cairn's credit facility.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During the year ending December 31, 1997, the Company's
liquidity needs were met from oil and natural gas production sales, cash
reserves and borrowings under the Company's lines of credit. As of December 31,
1997, the Company had a cash balance of $8.1 million and negative working
capital of $11 million. The decrease in both the cash balance and working
capital reflects capital expenditures related to the Company's increasing
exploration and development activities.
EXISTING CREDIT FACILITY. In November 1997, the Company obtained a $125 million
line of credit ("Existing Credit Facility") with The Chase Manhattan Bank
("Chase"). The Company's obligations under this facility are secured by the
common stock of Texas Meridian Resources Exploration, Inc. ("TMRX"), the
Company's operating subsidiary, and certain other subsidiaries of the Company
and Cairn's oil and natural gas properties. Under the terms of this Existing
Credit Facility, the Company may borrow, on a revolving basis, up to $125
million, subject to a borrowing base as determined from time to time by Chase.
The Existing Credit Facility contains various restrictive covenants including,
among other things, certain minimum financial ratios and restrictions on cash
dividends. Borrowings under the Existing Credit Facility mature on November 5,
2002.
Under the Existing Credit Facility, the Company may secure either an alternate
base rate loan, which bears interest at a rate per annum equal to the greatest
of (i) Chase's prime rate, (ii) a CD-based rate or Federal Funds-based rate, or
a Eurodollar base rate loan, which bears interest, generally, at a rate per
annum equal to the rate at which Chase is offered U. S. dollar deposits in the
interbank Eurodollar market plus 1.0% to 1.75% depending on the Company's ratio
of the aggregate outstanding loans and Letters of Credit to the borrowing base.
The Existing Credit Facility also provides for commitment fees ranging from 0.3%
to 0.5% per annum. The book value of the Company's floating-rate debt is
considered representative of its fair value.
The Company utilized $92 million under the Existing Credit Facility to refinance
Cairn's outstanding indebtedness and the indebtedness under the Company's prior
credit facility as well as to fund expenses relating to the Merger. As a result,
at December 31, 1997, the Company had available borrowings of $18 million under
the Existing Credit Facility following the Merger. As of March 31, 1998, the
Company had borrowed a total of $125 million under the Existing Credit Facility.
NEW CREDIT FACILITY. The Company has received an underwritten commitment which
it has accepted (the "New Credit Facility") which will replace the Existing
Credit Facility and fund ongoing operations and the cash consideration portion
of the Shell Transactions. The commitment provides for a total credit facility
of $250 million, with an initial borrowing base of $150 million which is
available through the closing of the Shell Transactions. A borrowing base
redetermination is scheduled at the earlier of the closing of the Shell
Transactions or six months from the closing date of the New Credit Facility,
which is currently anticipated to increase the borrowing base to at least $185
million. After closing, the New Credit Facility will bear interest at the
lender's base rate plus a margin of 0% to .25%. The New Credit Facility will be
secured in the same manner as the Existing Credit Facility and has similar
covenants and conditions.
26
CAPITAL EXPENDITURES. Capital expenditures during 1997 consisted of $111.9
million for property and equipment additions related to exploration and
development of various prospects, including lease, seismic data acquisitions,
drilling and completion costs. The Company expects that capital expenditures for
property and equipment additions may increase during 1998, as the Company funds
its offshore exploration and development program. The Company currently expects
capital expenditures for 1998 to be approximately $100 million. In addition, if
the Shell Transactions are consummated, the Company expects to expand its
onshore exploration program to take advantage of opportunities associated with
the properties to be acquired. Capital expenditures associated with this
expansion are expected to be as much as $25 million for 1998. These capital
expenditures are expected to be funded through a combination of cash flow from
the acquired properties and borrowings under a proposed expansion of the
Company's credit facility or other debt or equity financings.
In management's opinion, the Company will have sufficient capital resources to
fund its operations. Future requirements, however, will depend upon the success
of the Company's drilling program and the nature and extent of capital
expenditures required for development of discoveries. In that regard, the
Company anticipates that it may obtain additional capital through the issuance
of debt, equity or convertible securities.
NEW ACCOUNTING PRONOUNCEMENTS
REPORTING COMPREHENSIVE INCOME. In June 1997, the Financial Accounting Standards
Board (FASB) issued Statement No. 130 ("SFAS 130"), "Reporting Comprehensive
Income," which establishes standards for reporting and displaying of
comprehensive income in the financial statements. Comprehensive income is the
total of net income and all other non-owner changes in equity. Adoption of this
standard is not expected to have a material effect on the Company's financial
statements.
DISCLOSURES ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION. In June
1997, the FASB issued SFAS No. 131, "Disclosures about Segments of an Enterprise
and Related Information", which is effective for years beginning after December
15, 1997. SFAS No. 131 establishes standards for the way that public business
enterprises report information about operating segments in annual financial
statements and requires that those enterprises report selected information about
operating segments in interim financial reports. It also establishes standards
for related disclosures about products and services, geographic areas and major
customers. SFAS No. 131 is effective for financial statements for fiscal years
beginning after December 15, 1997, and, therefore, the Company will adopt the
new requirements retroactively in 1998. Management has not completed its review
of SFAS No. 131, but does not anticipate that the adoption of this statement
will have a significant effect on the Company's reported operations.
27
IMPACT OF YEAR 2000
Some of the Company's computer programs were written using two digits rather
than four to define the applicable year. As a result, those computer programs
have time-sensitive software that recognizes a date using "00" as the year 1900
rather than the year 2000. If not corrected, this could cause a system failure
or miscalculations causing disruptions of operations, including, among other
things, a temporary inability to process transactions, send invoices or engage
in similar normal business activities.
The Company currently is in the process of converting its information systems to
be Year 2000 compliant, the costs of which the Company does not believe will be
material. The system conversion is estimated to be completed no later than
December 31, 1998; however, it is possible that certain efforts will be delayed
into 1999. The greatest Year 2000 compliance risk is that system conversion will
be delayed beyond the anticipated completion date and the severe shortage of
qualified information systems personnel, both internally and externally, could
affect compliance efforts. The Company believes that with conversions to new
software, the Year 2000 issue will not pose significant operational problems for
its computer systems.
The estimated cost and the anticipated date of system implementation are based
on management's best estimates; however, there can be no assurance that these
estimates will be achieved, and actual results could differ materially from
those anticipated.
FORWARD-LOOKING STATEMENTS
From time to time, the Company 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, TMRC's future prospects,
including prospects if the Shell Transactions are consummated, developments, oil
and gas reserves and properties and business strategies for their operations and
synergies that are possible from the Merger and the Shell Transactions, if
consummated, exploration and seismic acquisition plans, anticipated results from
current and future exploration prospects, 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 gas industry
and the exploration and development sector thereof, environmental and other
expenditures and various business trends. These forward-looking statements are
identified by their use of terms and phrases such as "anticipate", "expect",
"estimate", "intend", "project", "believe", and similar terms and phrases.
Forward-looking statements may be made by management orally or in writing
including, but not limited to, the Management's Discussion and Analysis and
Financial Condition Results of Operations section and other sections of the
Company's filings with the Securities and Exchange Commission under the
Securities Act of 1933 and the Securities Exchange Act of 1934.
Although TMRC believes that the expectations described in such forward-looking
statements are reasonable, these statements involve risks and uncertainties that
may cause actual future activities and results of operations to be materially
different from that suggested or described herein.
These risks include changes in market conditions in the oil and natural gas
industry and demand and prices for oil and gas, the ability of TMRC to integrate
and realize anticipated synergies related to the combination of TMRC and Cairn
and from the Shell Transactions, if consummated, consummation of the Shell
Transactions, which are subject to shareholder approval and other customary
closing conditions, dependence on current managements, the ability of TMRC to
achieve and execute internal business plans, the ultimate outcome and results
from the Company's litigation with Amoco relating to its Southwest Holmwood
properties, the impact of any economic downturns and inflation and other market
factors affecting the demand and supply of oil and natural gas, the timing of
drilling new prospects, the ability of TMRC to successfully identify and
complete its current prospects and those acquired in the Shell Transactions, if
consummated, variation in actual production results from that estimated in
existing reserve data, regulatory changes affecting exploration activities and
higher costs associated with drilling. Many of these risks are more specifically
described in this Annual Report on Form 10-K. Should one or more of these risks
or uncertainties materialize, or should underlying assumptions prove incorrect,
actual results may vary materially from those expected, estimated or projected.
28
GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS
The definitions set forth below apply to the indicated terms commonly used in
the oil and natural gas industry and in this Form 10-K. MCFEs are determined
using the ratio of six Mcf of natural gas to one barrel of oil, condensate or
natural gas liquids, which approximates the relative energy content of crude
oil, condensate and natural gas liquids as compared to natural gas. Prices have
historically been substantially higher for crude oil than natural gas on an
energy equivalent basis. Any reference to net wells or net acres was determined
by multiplying gross wells or acres by the Company's working percentage interest
therein.
"Bbl" means barrel and "Bbls" means barrels.
"Bcf" means billion cubic feet.
"BCFE" means billion cubic feet of natural gas equivalent.
"Btu" means British Thermal Unit.
"EPA" means Environmental Protection Agency.
"FERC" means the Federal Energy Regulatory Commission.
"MBbls" means thousand barrels.
"Mcf" means thousand cubic feet.
"MCFE" means thousand cubic feet of natural gas equivalent.
"MMBbls" means million barrels.
"MMBtu" means million Btus.
"MMcf" means million cubic feet.
"MMCFE" means million cubic feet of natural gas equivalent.
"NGPA" means the Natural Gas Policy Act of 1978, as amended.
"Present Value of Future Net Revenues" or "Present Value of Proved
Reserves" means the present value of estimated future revenues to be
generated from the production of proved reserves calculated in
accordance with Commission guidelines, net of estimated production and
future development costs, using prices and costs as of the date of
estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative
expenses, debt service, future income tax expenses and depreciation,
depletion and amortization, and discounted using an annual discount rate
of 10%.
"Tcf" means trillion cubic feet.
29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Report of Independent Auditors 31
Consolidated Statements of Operations
-- For each of the three years in the period ended December 31, 1997 32
Consolidated Balance Sheets--December 31, 1997 and 1996 33
Consolidated Statements of Cash Flows
-- For each of the three years in the period ended December 31, 1997 35
Consolidated Statements of Changes in Stockholders' Equity
-- For each of the three years in the period ended December 31, 1997 36
Notes to Consolidated Financial Statements 37
Consolidated Supplemental Oil and Gas Information (Unaudited) 50
30
REPORT OF INDEPENDENT AUDITORS
Board of Directors and Stockholders
The Meridian Resource Corporation
We have audited the accompanying consolidated balance sheets of The Meridian
Resource Corporation and subsidiaries as of December 31, 1997 and 1996, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the three years in the period ended December 31, 1997. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of The
Meridian Resource Corporation and subsidiaries at December 31, 1997 and 1996,
and the consolidated results of their operations and their cash flows for each
of the three years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles.
ERNST & YOUNG LLP
March 10, 1998, except
for note 7, as to which
the date is March 27, 1998
Houston, Texas
31
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
-----------------------
1997 1996 1995
---- ---- ----
(In thousands, except per share)
REVENUES:
Oil and natural gas $57,640 $55,123 $36,966
Interest and other 693 1,610 1,264
------ ------- -------
58,333 56,733 38,230
------ ------- -------
COSTS AND EXPENSES:
Oil and natural gas operating 5,680 4,696 3,735
Severance and ad valorem taxes 2,165 1,677 966
Depletion and depreciation 26,337 25,342 18,491
General and administrative 7,192 5,770 4,661
Interest 5,149 2,582 2,589
Impairment of long-lived assets 24,141 ----- 300
Merger expenses 9,998 ----- -----
Litigation expenses and loss provision 6,205 ----- -----
------- -------- --------
86,867 40,067 30,742
------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES (28,534) 16,666 7,488
INCOME TAX EXPENSE (BENEFIT) 7 (26) 30
------- -------- --------
NET INCOME (LOSS) ($28,541) $16,692 $7,458
========= ======= =======
NET INCOME (LOSS) PER SHARE:
Basic ($0.85) $0.50 $0.25
======= ===== =====
Diluted ($0.85) $0.47 $0.23
======= ======= =======
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES:
Outstanding 33,383 33,399 30,207
====== ====== ======
Assuming dilution 33,383 35,484 31,984
====== ====== ======
See notes to consolidated financial statements.
32
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-----------
1997 1996
---- ----
(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $8,083 $23,705
Accounts receivable 10,920 12,020
Due from affiliates 3,038 857
Prepaid expenses and other 1,130 587
------- --------
Total current assets 23,171 37,169
------- --------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$51,883,000 [1997] and $54,454,000 [1996] not
subject to depletion) 409,310 298,446
Land 478 478
Equipment 4,618 3,586
-------- --------
414,406 302,510
Less accumulated depletion and depreciation (145,719) (95,246)
-------- --------
268,687 207,264
-------- --------
OTHER ASSETS, NET 700 1,324
-------- --------
$292,558 $245,757
======== ========
See notes to consolidated financial statements.
33
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
DECEMBER 31,
-----------
1997 1996
---- ----
(in thousands)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $7,735 $10,528
Revenues and royalties payable 5,991 5,530
Accrued liabilities 20,330 16,267
Current maturities of long-term debt 110 -----
-------- --------
Total current liabilities 34,166 32,325
-------- --------
LONG-TERM DEBT 107,085 42,000
-------- --------
COMMITMENTS AND CONTINGENCIES ----- -----
LITIGATION LIABILITIES 6,205 -----
-------- --------
STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value (25,000,000 shares
authorized, none issued and outstanding) ----- -----
Common stock, $0.01 par value (100,000,000 shares
authorized, 33,481,261 [1997] and 33,422,556 [1996]
issued) 336 334
Additional paid-in capital 172,023 170,086
Accumulated earnings (deficit) (26,106) 2,435
Unamortized deferred compensation (309) (343)
-------- --------
145,944 172,512
Treasury stock, at cost (46,792 [1997] and 60,000 [1996] shares) (842) (1,080)
-------- --------
Total stockholders' equity 145,102 171,432
-------- --------
$292,558 $245,757
======== ========
See notes to consolidated financial statements.
34
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
----------------------
1997 1996 1995
---- ---- ----
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ...................................... ($ 28,541) $ 16,692 $ 7,458
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depletion and depreciation .......................... 26,337 25,342 18,491
Amortization of other assets ........................ 671 519 410
Non-cash compensation ............................... 1,815 719 63
Impairment of long-lived assets ..................... 24,141 -- 300
Litigation expenses and loss provision............... 6,205 -- --
Changes in assets and liabilities:
Accounts receivable ................................. 1,100 (6,605) (2,215)
Due from affiliates ................................. (2,181) 314 (487)
Accounts payable .................................... (2,793) 2,515 3,933
Revenues and royalties payable ...................... 461 2,164 2,667
Accrued liabilities and other ....................... 5,930 (228) (255)
--------- -------- --------
Net cash provided by operating activities ................ 33,145 41,432 30,365
--------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment additions, net .................. (114,311) (83,350) (44,809)
Proceeds from sale of oil and natural gas properties ... -- 502 1,920
--------- -------- --------
Net cash used in investing activities .................... (114,311) (82,848) (42,889)
--------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt ........................... 156,234 26,500 13,800
Reductions in long-term debt ........................... (91,039) -- (21,800)
Common stock offering, net of issuance costs ........... -- -- 53,464
Exercise of stock options .............................. 396 177 254
Payment of deferred loan costs and other financing costs (47) (767) (276)
--------- -------- --------
Net cash provided by financing activities ................ 65,544 25,910 45,442
--------- -------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS .................. (15,622) (15,506) 32,918
CASH AND CASH EQUIVALENTS
AT BEGINNING OF YEAR ................................... 23,705 39,211 6,293
--------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR ................. $ 8,083 $ 23,705 $ 39,211
========= ======== ========
See notes to consolidated financial statements.
35
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1995, 1996 AND 1997
(in thousands)
ADDITIONAL ACCUMULATED UNAMORTIZED
COMMON STOCK PAID-IN EARNINGS DEFERRED TREASURY STOCK
SHARES PAR VALUE CAPITAL (DEFICIT) COMPENSATION SHARES COST TOTAL
------ --------- ------- --------- ------------ ------ ---- -----
Balance, December 31, 1994,
as previously reported 10,593 $106 $ 37,151 ($ 4,899) -- -- -- $ 32,358
Adjustment for pooling-of-interests ........ 17,240 173 77,970 (16,816) -- -- -- 61,327
------ ---- --------- -------- ------- --- ------- ---------
Balance, December 31, 1994, as restated .... 27,833 279 115,121 (21,715) -- -- -- 93,685
Common stock offering,
net of issuance costs ................... 5,482 55 53,409 -- -- -- -- 53,464
Exercise of stock options ................ 64 -- 254 -- -- -- -- 254
Company's 401(k) plan contribution ....... 5 -- 63 -- -- -- -- 63
Net income ............................... -- -- -- 7,458 -- -- -- 7,458
------ ---- --------- -------- ------- --- ------- ---------
Balance, December 31, 1995 ................. 33,384 334 168,847 (14,257) -- -- -- 154,924
Exercise of stock options ................ 25 -- 177 -- -- -- -- 177
Issuance of rights to common stock ....... -- -- 910 -- (910) -- -- --
Compensation expense ..................... -- -- -- -- 567 -- -- 567
Treasury shares acquired ................. -- -- -- -- -- (60) (1,080) (1,080)
Company's 401(k) plan contribution ....... 13 -- 152 -- -- -- -- 152
Net income ............................... -- -- -- 16,692 -- -- -- 16,692
------ ---- --------- -------- ------- --- ------- ---------
Balance, December 31, 1996 ................. 33,422 334 170,086 2,435 (343) (60) (1,080) 171,432
Exercise of stock options ................ 55 1 395 -- -- -- -- 396
Company's 401(k) plan contribution ....... 4 -- (57) -- -- 13 238 181
Issuance of rights to common stock ....... -- 1 1,599 -- (1,600) -- -- --
Compensation expense ..................... -- -- -- -- 1,634 -- -- 1,634
Net loss ................................. -- -- -- (28,541) -- -- -- (28,541)
------ ---- --------- -------- ------- --- ------- ---------
Balance, December 31, 1997 ................. 33,481 $336 $ 172,023 ($26,106) ($ 309) (47) ($ 842) $ 145,102
====== ==== ========= ======== ======= === ======= =========
See notes to consolidated financial statements.
36
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
The Meridian Resource Corporation together with its subsidiaries, (the "Company"
or "TMRC") explores for, develops and produces oil and natural gas reserves,
principally located onshore and offshore Louisiana and southeast Texas. The
Company was initially organized in 1985 as a master limited partnership and
operated as such until 1990 when it converted into a corporation through a
merger with a limited partnership of which the Company was the sole limited and
general partner. On November 5, 1997, Cairn Energy USA, Inc. ("Cairn") merged
with a subsidiary of the Company (see note 6). The merger was accounted for as a
pooling of interests, and accordingly, the accompanying financial statements
have been restated to include the financial position and results of operations
of Cairn for all periods presented.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF CONSOLIDATION
These consolidated financial statements reflect the accounts of TMRC and its
subsidiaries after elimination of all significant intercompany transactions and
balances.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for its investments in
oil and natural gas properties. The Company capitalizes all direct and certain
indirect cost associated with the acquisition, exploration and development costs
of oil and natural gas reserves. Included in capitalized costs are general and
administrative costs that are directly identified with acquisition, exploration
and development activities. Proceeds from sale of oil and natural gas properties
are credited to the full cost pool, unless the sale involves a significant
quantity of reserves, in which case a gain or loss is recognized. Under the
rules of the Securities and Exchange Commission ("SEC") for the full cost method
of accounting, the net carrying value of oil and natural gas properties is
limited to the sum of the present value (10% discount rate) of the estimated
future net cash flows from proved reserves, based on the current prices and
costs, plus the lower of cost or estimated fair market value of unproved
properties.
Capitalized costs of proved oil and natural gas properties are depleted on a
unit of production method using proved oil and natural gas reserves as reviewed
by independent petroleum engineers. Costs depleted include all capitalized cost
(less accumulated depletion); the estimated dismantlement, restoration, and
abandonment costs. Estimated future abandonment, dismantlement and site
restoration costs include costs to dismantle, relocate and dispose of the
Company's offshore production platforms, gathering systems, wells and related
structures. Such costs related to onshore properties, net of estimated salvage
values, are not expected to be significant. Equipment is recorded at cost, and
depreciation is determined using an accelerated depreciation method basis over
the estimated useful lives of the assets.
CASH AND CASH EQUIVALENTS
For purposes of the statements of cash flows, cash equivalents include time
deposits, certificates of deposit and all highly liquid instruments with
original maturities of three months or less.
37
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's receivables are due from oil and natural gas
producing companies located in the United States.
REVENUE RECOGNITION
TMRC recognizes oil and natural gas revenue from its interests in producing
wells as oil and natural gas is produced and sold from those wells. Oil and
natural gas sold is not significantly different from TMRC's share of production.
EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board ("FASB") issued
Statement No. 128, ("SFAS 128") "Earnings per Share," which simplifies the
computation of earnings per share ("EPS"). SFAS 128 is effective for financial
statements issued for periods ending after December 15, 1997, and requires
restatement for all prior periods earnings per share data presentation. Under
SFAS 128, the Company computes two earnings per share amounts - basic EPS and
EPS assuming dilution. Basic EPS (which replaces the current "primary earnings
per share") is calculated based on the weighted average number of shares of
common stock outstanding for the periods. EPS assuming dilution is based on the
weighted average number of shares of common stock outstanding for the periods,
including the dilutive effects of stock options and warrants granted through
December 31, 1997. Dilutive options and warrants that are issued during a period
or that expire or are canceled during a period are reflected in the EPS assuming
dilution 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.
COMPREHENSIVE INCOME
In June 1997, the FASB issued Statement No. 130 ("SFAS 130"), "Reporting
Comprehensive Income," which establishes standards for reporting and displaying
of comprehensive income in the financial statements. Comprehensive income is the
total of net income and all other non-owner changes in equity. Adoption of this
standard is not expected to have a material effect on the Company's financial
statements.
ESTIMATES IN FINANCIAL STATEMENTS
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
38
CHANGES IN PRESENTATION
Certain items in 1995 and 1996 have been reclassed to conform to 1997
presentation.
3. IMPAIRMENT OF LONG-LIVED ASSETS
The Company recognized a $24.1 million non-cash write-down of its oil and
natural gas properties, under the full cost method of accounting, primarily as a
result of declines in both oil and natural gas prices which significantly
lowered the present value of proved oil and natural gas reserves at December 31,
1997. Prices for these commodities since have declined further and, based on
prices in effect at March 1, 1998, an estimated additional write-down of $40 to
$45 million would have been required had such prices been in effect on December
31, 1997. If oil and natural gas prices do not improve or if there are no other
factors that offset the effect of lower prices, such as significant net
additions to proved oil and gas reserves during the first quarter of 1998, the
Company will recognize an additional property write-down at March 31, 1998.
Because the carrying value of oil and natural gas properties has been reduced
due to the full cost ceiling limitation such that the present value of the
Company's proved oil and gas reserves do not exceed the Company's net oil and
gas properties recorded on its balance sheet, there is an increased risk of
future property write-downs due to factors that negatively affect the present
value of proved oil and gas reserves, including volatile oil and natural gas
prices and downward revisions in estimated proved oil and gas quantities and
unsuccessful exploratory drilling operations.
4. LONG-TERM DEBT
In November 1997, the Company obtained a $125 million line of credit with The
Chase Manhattan Bank ("Chase"). The Company's obligations under this facility
are secured by the stock of The Meridian Resource & Exploration Company
("TMRX"), the Company's operating subsidiary, and certain other subsidiaries of
the Company and Cairn's oil and gas properties. Under the terms of this
facility, the Company may borrow, on a revolving basis, up to $125 million,
subject to a borrowing base as determined from time to time by Chase. The Credit
Agreement contains various restrictive covenants including, among other things,
certain minimum financial ratios and restrictions on cash dividends. Borrowings
under the Credit Agreement mature on November 5, 2002.
Under the Credit Agreement, the Company may secure either an alternate base rate
loan, which bears interest at a rate per annum equal to the greatest of (i)
Chase's prime rate, (ii) a CD-based rate or Federal Funds-based rate, or a
Eurodollar base rate loan, which bears interest, generally, at a rate per annum
equal to the rate at which Chase is offered U. S. dollar deposits in the
interbank Eurodollar market plus 1.0% to 1.75% depending on the Company's ratio
of the aggregate outstanding loans and Letters of Credit to the borrowing base.
The Credit Agreement also provides for commitment fees ranging from 0.3% to 0.5%
per annum. The book value of the Company's floating-rate debt is considered
representative of its fair value.
5. COMMITMENTS AND CONTINGENCIES
LITIGATION
In June 1996, Amoco Production Company ("Amoco") filed suit against the Company
in Louisiana State Court in Calcasieu Parish with respect to a dispute involving
the drilling by the Company of the Company's Ben Todd No. 1 (TMRC) well in the
Southwest Holmwood Field in which the Company ET AL and Amoco each hold a 50%
leasehold interest. The case was removed to the United States District Court for
the Western District of
39
Louisiana in July 1996. The Ben Todd No. 1 (TMRC) well was drilled by the
Company under a participation agreement between the Company and Amoco in which
Amoco had a right to participate in the well. The well was drilled by the
Company after providing notice to Amoco pursuant to the participation agreement
of the Company's intent to drill the well and Amoco's failure to take action to
elect to participate in the well. Prior to the drilling of the well, the Company
had been advised by its advisors that the drilling of the well by the Company
was permitted under the participation agreement by virtue of Amoco's refusal to
reasonably consent to the well following TMRC's request to do so. Amoco also did
not seek to enjoin the drilling of the well and accepted the benefits of the
well following the drilling thereof as well as other benefits under the
participation agreement and lease. Amoco alleged in its suit that the well was
not permitted to be drilled under the agreement and sought to recover all the
revenues from the well or have the production from the well stopped. Amoco
requested that the trial court cancel the participation agreement and the
Company's leasehold interest in the prospect, which includes the Company's 50%
interest in the Ben Todd No. 2 (Amoco) well that was drilled prior to the Ben
Todd No. 1 (TMRC) well on an agreed basis. The Company filed a counterclaim for
breach of contract, unfair practices and other claims.
On December 22, 1997, the Federal District Court entered a judgment against the
Company in this matter and ordered that the Company was not permitted under the
participation agreement to drill the Ben Todd No. 1 (TMRC) well and that the
participation agreement and related lease had been terminated by virtue of the
Company's drilling of the well. The trial court also dismissed the Company's
counterclaims against Amoco. The trial court further ordered a reversion of the
Company's rights with respect to the Ben Todd No. 1 (TMRC) and the Ben Todd No.
2 (Amoco) and directed TMRC to account for all production and monies received by
it from the date of the cancellation of the lease. The Company has calculated
the production and revenues received by it as operator from these properties to
which the trial court has ordered to be returned to Amoco to be approximately
4.0 Bcfe and $10.2 million. The Company recorded a charge of $6.2 million in the
fourth quarter of 1997, representing its estimated portion of the potential
loss, which is net of approximately $4.0 million of amounts that would be
recoverable from third parties with respect to the Amoco lawsuit. Management
does not expect any material additional charges to be made with respect to this
matter. The Company has reported no reserves related to these properties as of
December 31, 1997.
GECO-PRAKLA
In December 1996, the Company entered into an agreement with GECO-Prakla
("GECO"), a division of Schlumberger Technology Corporation. Under this
agreement, GECO intends to acquire between 1,000 and 2,000 square miles of 3-D
seismic data per year through the year 2000, including surveys which will be
performed at the Company's request and direction. This agreement obligated the
Company to acquire 1,100 square miles of 3-D seismic over a three year period.
During 1997, TMRC purchased 605 square miles of seismic data, leaving an
obligation of 495 square miles to be acquired from GECO over the remaining two
years.
6. MERGER
On November 5, 1997, a wholly-owned subsidiary of the Company combined with
Cairn pursuant to a merger agreement in which approximately 19.0 million shares
of the Company's common stock was issued in exchange for all of the outstanding
common stock of Cairn. The Company also reserved approximately 0.8 million
shares for issuance in connection with Cairn's outstanding employee stock
options plans. The transaction has been accounted for as a pooling of interests.
40
Revenues and net income for the separate companies and the combined amounts
presented in the consolidated financial statements follow.
NINE MONTHS YEAR ENDED YEAR ENDED
ENDED SEPT. 30, DEC. 31, DEC. 31,
1997 1996 1995
----------- ---------- ----------
(In thousands)
Revenues:
The Meridian Resource Corporation $21,159 $26,387 $12,267
Cairn Energy USA, Inc. 21,103 30,346 25,963
------- ------- -------
Combined $42,262 $56,733 $38,230
======= ======= =======
Net income:
The Meridian Resource Corporation $3,747 $7,134 $2,153
Cairn Energy USA, Inc. 3,203 6,638 5,235
Merger adjustments 1,586 2,920 70
------- -------- ---------
Combined $8,536 $16,692 $7,458
======= ======= =======
Merger adjustments primarily relate to the recognition of deferred tax benefits
in 1996. Certain amounts from Cairn's prior financial statements have been
reclassified to conform to the Company's presentation.
In connection with the merger, the Company incurred significant financial
advisor, legal, accounting, printing, severance and other costs. Under pooling
of interests accounting, these costs, totaling approximately $10.0 million, were
expensed in the fourth quarter of 1997. Accrued merger costs of approximately
$5.9 million are included in accrued liabilities as of December 31, 1997.
7. PROPOSED ACQUISITION OF OIL AND GAS INTERESTS
On March 27, 1998, the Company and affiliates of Shell Oil Company
(collectively, "Shell") executed a definitive merger agreement which, together
with a separate purchase and sale agreement (collectively referred to as the
"Shell Agreements" and the transactions contemplated by the Shell Agreements are
referred to herein as the "Shell Transactions"), will result in the Company
acquiring all of Shell's producing and exploration properties in South Louisiana
in exchange for shares of common and preferred stock representing 39.9% of the
common stock of the Company as of the closing, assuming exercise of all stock
options, warrants and conversion of the preferred stock, and $42.5 million in
cash.
The terms of the Shell Agreements call for Shell to receive a fixed 39.9% of the
post-transaction common stock of the Company, assuming exercise of all stock
options, warrants and conversion of the preferred stock, comprised of 12.082
million shares of common stock and shares of a new series of preferred stock
(the "Preferred Stock") convertible into approximately 12.827 million shares of
common stock. The Preferred Stock will have a stated value of $135 million, a 4%
annual dividend for a period of five years (with the dividend reducing in amount
by one-third in each year starting at the end of two years so that no
41
dividends will be payable after five years) and a conversion price of
approximately $10.52 per share. The Preferred Stock will convert automatically
into common stock if the market price of the common stock is greater than or
equal to 150% of the conversion price for 75 consecutive trading days. Terms of
the Shell Transactions are not subject to changes in the market price of the
common stock.
To insure the Company's ability to function as an independent oil and gas
company, Shell has agreed to restrict its discretionary voting rights on
non-extraordinary corporate issues requiring a shareholder vote to 23% of the
outstanding voting shares, with the remainder of its holdings to be voted in the
same ratio as the shares voted by other shareholders and Shell's unrestricted
shares. Shell also has agreed to restrictions on its ability to sell shares and
will be provided with certain rights to purchase additional shares to the extent
necessary to maintain at least a 21% beneficial ownership interest in the
Company. Shell will be entitled to one seat on the Company's board of directors.
The consummation of the Shell Transactions is subject to approval of the
shareholders of the Company and certain other customary conditions. The Company
currently anticipates that a closing of the Shell Transactions will occur either
late in the second quarter or early in the third quarter of 1998.
8. INCOME TAXES
Components of the provision (benefit) for Federal and State income taxes are as
follows:
1997 1996 1995
---- ---- ----
(in thousands)
Current ....................... $ 7 ($26) $30
Deferred ...................... -- -- --
---- ---- ----
$ 7 ($26) $30
==== ==== ====
Income tax expense as reported is reconciled to the federal statutory rate (35%)
as follows:
1997 1996 1995
---- ---- ----
(in thousands)
Income tax provision (benefit) computed at statutory rate ($9,987) $5,833 $2,621
Nondeductible merger costs 2,355 ----- -----
Nondeductible items - other 111 95 35
Non-statutory options ----- ----- (51)
Decrease (increase) in percentage depletion carryover 18 (263) (302)
Change in valuation allowance 7,597 (5,658) (2,283)
Other (87) (33) 10
------- -------- --------
$7 ($26) $30
======= ======= =======
42
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:
1997 1996
---- ----
(in thousands)
Deferred tax assets:
Net operating tax loss carryforward $39,933 $22,731
Statutory depletion carryforward 950 968
Basis differential in equipment 108 108
Other 3,094 -----
Less valuation allowance (8,754) (1,157)
------- ------
Total deferred tax assets 35,331 22,650
------- ------
Deferred tax liabilities:
Exploration and development expenditures
expensed for tax and capitalized for books 35,261 22,580
Basis differential in long-term investments 70 70
-------- ------
Total deferred tax liabilities $35,331 $22,650
-------- -------
Net deferred tax asset (liability) ----- -----
======== =======
As of December 31, 1997, the Company has approximately $114 million of net
operating loss carryforwards which begin to expire in 2005. Some of the net
operating loss carryforwards are subject to change in ownership and separate
return limitations. The net operating loss carryforwards assume that certain
items, primarily intangible drilling costs have been written off in the current
year. However, the Company has not made a final determination if an election
will be made to capitalize all or part of these items for tax purposes.
9. STOCKHOLDERS' EQUITY
COMMON STOCK
In July 1995, the Company completed a public offering of 3,795,000 shares of
common stock at a price of $10.50 per share. The total proceeds of the offering,
net of issuance costs, received by the Company were approximately $36.9 million.
The Company used a portion of these funds to retire $2.8 million in long-term
debt and the remainder of the proceeds is being used for additional drilling and
other exploration and development activities and for other general corporate
purposes.
A public offering of 1,687,500 shares of Cairn's common stock at an offering
price of $10.42 per share was closed on September 18, 1995. The total net
proceeds of the offering totaling approximately $16.6 million after issuance
costs, were used to reduce Cairn's borrowings.
TREASURY STOCK
On December 9, 1996, the Board of Directors authorized the acceptance of 60,000
shares of the Company's common stock, based on the closing price of $18.00 per
share, in satisfaction of certain obligations owed by
43
affiliates of Messrs. Reeves and Mayell (See Note 13). The acquired stock will
be used to fund the Company's future contributions to the employees' 401(k)
plan. During 1997, the Company issued 13,208 shares of the Company's treasury
stock to the employees' 401(k) plan.
WARRANTS
The Company had the following warrants to purchase TMRC common stock outstanding
at December 31, 1997:
NUMBER OF
SHARES UNDER EXERCISE
WARRANTS WARRANT PRICE EXPIRATION DATE
-------- ------- ----- ---------------
Executive Officers 1,428,000 $5.85 *
General Partner 677,180 $0.28 December 31, 2015
* A date one year following the date on which the respective warrant holder
ceases to be an employee of the Company.
On June 7, 1994, the shareholders of the Company approved a conversion of Class
"B" Warrants held by Joseph A. Reeves, Jr. and Michael J. Mayell, which entitled
each of them to purchase an aggregate of 714,000 shares of common stock, to
Executive Officer Warrants. The Warrants expire one year following the date on
which the respective officer ceases to be an employee of the Company. The
Warrants further provide that in the event the officer's employment with the
Company is terminated by the Company without "cause" or by the officer for "good
reason," the officer will have the option to require the Company to purchase
some or all of the Warrants held by the officer for an amount per Warrant equal
to the difference between the exercise price, $5.85 per share, and the then
prevailing market price of the common stock. The Company may satisfy this
obligation with shares of its common stock.
44
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, 1997, 1996 and 1995, 851,024, 913,221 and 808,491 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, 1994 1,085,050 $6.24
Granted 522,950 11.01
Exercised (63,539) 4.02
Canceled (14,311) 8.05
----------- -----
Outstanding at December 31, 1995 1,530,150 7.94
Granted 480,550 9.64
Exercised (24,710) 7.15
Canceled (34,110) 10.40
----------- -----
Outstanding at December 31, 1996 1,951,880 8.30
Granted 332,926 11.79
Exercised (55,327) 7.17
Canceled (157,292) 9.26
---------- ----
Outstanding at December 31, 1997 2,072,187 $8.81
========== =====
Shares exercisable:
December 31, 1997 1,621,025 $8.95
December 31, 1996 1,233,380 $7.45
December 31, 1995 751,899 $6.56
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
WEIGHTED WEIGHTED
RANGE OF OUTSTANDING AT AVERAGE EXERCISABLE AT AVERAGE
EXERCISABLE PRICES DECEMBER 31, 1997 EXERCISE PRICE DECEMBER 31, 1997 EXERCISE PRICE
------------------ ----------------- -------------- ----------------- --------------
$1.13 - $4.98 388,500 $4.72 388,500 $4.87
$5.56 - $10.00 915,132 $8.44 806,757 $8.52
$10.38 - $16.38 768,555 $11.33 425,768 $11.19
--------- ------ ---------- ------
2,072,187 $8.81 1,621,025 $8.95
========= ======= ========= =======
The weighted average remaining contractual life of options outstanding at
December 31, 1997 was approximately seven years.
45
Pro forma information is required by SFAS No. 123 to reflect the estimated
effect on net income and net income per share as if the Company had accounted
for the stock options and other awards granted using the fair value method
described in that Statement. The fair value was estimated at the date of grant
using the Black-Scholes option pricing model with the following weighted average
assumptions: risk-free interest rate of 5.6% and 6.2%; dividend yield of 0%;
volatility factors of the expected market price of the Company's common stock of
0.31 and 0.35 for 1997 and 1996, respectively; and a weighted-average expected
life of five years. These assumptions resulted in a weighted average grant date
fair value of $3.90 and $2.61 for options granted in 1997 and 1996,
respectively. For purposes of the pro forma disclosures, the estimated fair
value is amortized to expense over the awards' vesting period. Reflecting the
amortization of this hypothetical expense for 1997 and 1996 results in pro forma
net income (loss) of ($29.6) million and $15.7 million, respectively, and pro
forma basic net income (loss) per share of ($0.89) and $0.47, respectively.
The Black-Scholes option valuation model was developed for use in estimating the
fair value of traded options which have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions including the expected stock price volatility. Because
the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its employee stock options. In addition, because
SFAS 123 is applicable only to options granted subsequent to December 31, 1994,
the pro forma information does not reflect the pro forma effect of all previous
stock option grants of the Company, and thus the pro forma information is not
necessarily indicative of future amounts until SFAS 123 is applied to all
outstanding stock options.
DEFERRED COMPENSATION
In July 1996, the Company through the Compensation Committee of the Board of
Directors granted to Messrs. Reeves and Mayell (the Company's Chief Executive
Officer and President, respectively) rights to the Company's common stock in
lieu of cash compensation pursuant to the Company's Long-Term Incentive Plan.
Under such grants, Messrs. Reeves and Mayell each elected to defer $180,000 and
$400,000 of their compensation for 1996 and 1997, respectively. The Company also
granted to each officer a 100% matching deferral, which is subject to a one-year
vesting. Under the terms of the grants, the employee and matching deferrals are
allocated to a common stock account in which units are credited to the accounts
of the officer based on the number of shares that could be purchased at the
market price of the common stock at June 28, 1996, for deferrals in 1996 and at
December 31, 1996, for deferrals in 1997. At December 31, 1997, the plan had
reserved 250,000 shares of common stock for future issuance and 173,435 rights
have been granted. No actual shares of common stock are issued and the officer
has no rights with respect to any shares unless and until there is a
distribution. Distributions are to be made upon the death, retirement or
termination of employment of the officer.
The obligations of the Company with respect to the deferrals are unsecured
obligations. The shares of common stock that may be issuable upon distribution
of deferrals have been treated as a common stock equivalent in the financial
statements of the Company. The compensation expense of $1,634,000 and $567,000
for 1997 and 1996, respectively, relating to these grants is reflected in
general and administrative expense for the years ended December 31, 1997 and
1996, respectively.
10. PROFIT SHARING AND SAVINGS PLAN
The Company has a 401(k) profit sharing and savings plan (the "Plan") that
covers substantially all employees and entitles them to contribute up to 15% of
their annual compensation, subject to maximum limitations
46
imposed by the Internal Revenue Code. TMRC matches 25% of each employee's
contribution up to 10% of annual compensation subject to certain limitations as
outlined in the Plan. In addition, TMRC may make discretionary contributions
which are allocable to participants in accordance with the Plan.
11. OIL AND GAS HEDGING ACTIVITIES
During the years ended December 31, 1995 and 1996, Cairn's oil and gas revenues
were increased by $323,000 and reduced by $2,449,000 respectively, as a result
of hedging transactions. As of December 31,1997 the Company has no open hedging
agreements.
12. MAJOR CUSTOMERS
Major customers for TMRC for the years ended December 31, 1997, 1996 and 1995
were as follows (based on purchases of oil and natural gas as a percent of total
oil and natural gas sales):
YEAR ENDED DECEMBER 31,
-----------------------------------
CUSTOMER 1997 1996 1995
- -------- ---- ---- ----
Phillips Petroleum Company 20% 22% 19%
Coastal Corporation 15% 21% 15%
Koch Oil Company 15% 12% 7%
Phillips Petroleum Company ("Phillips") is the sole purchaser of TMRC's natural
gas production from the Chocolate Bayou Field under a natural gas contract
entered into pursuant to a farmout agreement with Phillips.
13. RELATED PARTY TRANSACTIONS
Texas Oil Distribution and Development, Inc. ("TODD") and Sydson Energy, Inc.
("Sydson"), entities controlled by Joseph A. Reeves, Jr. and Michael J. Mayell,
respectively, collectively invested approximately $2,315,000, $1,660,000, and
$625,000 for the years ended December 31, 1997, 1996 and 1995, respectively, in
oil and natural gas drilling activities for which the Company was the operator.
Collective amounts due from such entities for such activities were approximately
$2,500,000 and $83,000 as of December 31, 1997 and 1996, respectively, which
have been netted by amounts owed to them from the Company (See Note 9 regarding
stock purchase from Messrs. Reeves and Mayell). The Company has executed note
agreements with TODD and Sydson dated December 31, 1997 for $1,510,699 each
related to certain amounts due, which mature on December 30, 1998 and accrue
interest at variable market rates. TODD and Sydson participated under the same
terms negotiated with unaffiliated working interest owners.
Mr. Joe Kares, a Director of TMRC, is a partner in the public accounting firm of
Kares & Cihlar, which provided TMRC and its affiliates with accounting services
for the years ended December 31, 1997, 1996 and 1995 and received fees of
approximately $27,000, $56,000 and $68,000, respectively. Such fees exceeded 5%
of the gross revenues of Kares & Cihlar for those respective years. Management
believes that such fees were equivalent to fees that would have been paid to
similar firms providing such services in arm's length transactions.
Mr. Gary A. Messersmith, a Director of The Meridian Resource Corporation, is a
partner in the law firm of Fouts & Moore, L.L.P. in Houston, Texas, which
periodically provides legal services for the Company. In addition, the Company
has Mr. Messersmith on personal retainer of $8,333.33 per month relating to
services provided to the Company personally by Mr. Messersmith.
47
In the interest of retaining talented technical personnel, the Company has
adopted an incentive compensation system for its senior geologist, geophysicists
and executives that relates each individual's compensation to the success of the
Company's exploration activities by providing compensation based on results of
the prospects.
14. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings per
share:
YEAR ENDED DECEMBER 31,
----------------------
1997 1996 1995
---- ---- ----
(in thousands, except per share)
Numerator:
Net income (loss) ($28,541) $16,692 $7,458
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding 33,383 33,399 30,207
Effect of potentially dilutive common shares:
Employee and director stock options N/A 650 442
Warrants N/A 1,435 1,335
------ ------
Denominator for diluted earnings per
share - weighted-average shares
outstanding and assumed conversions 33,383 35,484 31,984
======== ====== ======
Basic (loss) earnings per share ($0.85) $0.50 $0.25
======== ======= =======
Diluted (loss) earnings per share ($0.85) $0.47 $0.23
======== ======= =======
15. SUPPLEMENTAL CASH FLOWS INFORMATION
YEAR ENDED DECEMBER 31,
----------------------------
1997 1996 1995
---- ---- ----
(in thousands)
Cash Payments:
Interest $3,866 $2,166 $2,239
Income taxes $7 ($26) $37
Non-Cash Operating and Financing Activities:
Accounts receivable ----- ($1,080) -----
Treasury stock (See Note 9) ----- $1,080 -----
48
16. RESTATED QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following is a summary of the unaudited quarterly results of operations for
the years ended December 31, 1997 and 1996.
QUARTER ENDED
--------------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31(2) TOTAL
-------- ------- -------- ---------- -----
(in thousands, except per share amounts)
1997
----
Revenues $16,660 $13,239 $12,363 $16,071 $58,333
======= ======= ======= ======== =======
Results of operations from
exploration and production
activities(1) $8,563 $4,606 $3,986 ($16,924) $81
====== ====== ====== ========= ============
Net income (loss) $5,644 $2,016 $876 ($37,077) ($28,541)
====== ====== ======= ========= =========
Net income (loss) per common share:
Basic $0.17 $0.06 $0.03 ($1.11) ($0.85)
===== ===== ===== ======= =======
Diluted $0.16 $0.06 $0.02 ($1.11) ($0.85)
===== ===== ===== ======= =======
1996
----
Revenues $12,366 $13,144 $14,410 $16,813 $56,733
======= ======= ======= ======== =======
Results of operations from
exploration and production
activities(1) $5,563 $4,861 $5,314 $8,253 $23,991
====== ====== ====== ======= =======
Net income $4,207 $3,223 $3,471 $5,791 $16,692
====== ====== ====== ======= =======
Net income (loss) per common share:
Basic $0.13 $0.10 $0.10 $0.17 $0.50
===== ===== ===== ====== =====
Diluted $0.12 $0.09 $0.10 $0.16 $0.47
===== ===== ===== ====== =====
(1) Results of operations from exploration and production activities, which
approximate gross profit, are computed as operating revenues less lease
operating expenses, severance and ad valorem taxes, depletion and impairment
of oil and natural gas properties.
(2) Fourth quarter 1997 results include impairment of $24.1 million related to
oil and natural gas properties, merger expenses of $10.0 million and a
provision of $6.2 million related to litigation.
49
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION
(UNAUDITED)
The following information is being provided as supplemental information in
accordance with certain provisions of SFAS No. 69, "Disclosures about Oil and
Gas Producing Activities." Expenditures for oil and natural gas properties
attributable to TMRC for the years ended December 31, 1997, 1996 and 1995 were
primarily to acquire, explore and develop oil and natural gas properties.
COSTS INCURRED IN OIL AND NATURAL GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES ARE SUMMARIZED BELOW:
YEAR ENDED DECEMBER 31,
-----------------------
1997 1996 1995
-------- --------- --------
(in thousands)
Costs incurred during the year:(1)
Property acquisition costs(2) $11,610 $10,923 $329(3)
Exploration 73,441 67,093 35,752
Development 25,813 9,184 16,062
-------- --------- --------
$110,864 $87,200 $52,143
======== ======= =======
(1) Costs incurred during the years ended December 31, 1997, 1996 and 1995
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of
third party reimbursements, of $3,958,000, $3,102,000 and, $2,697,000,
respectively.
(2) All property acquisition costs are related to unproved property.
(3) Includes a $3.9 million favorable purchase price adjustment in
connection with an acquisition of properties in 1994.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES:
DECEMBER 31,
------------
1997 1996
--------- --------
(in thousands)
Capitalized costs $409,310 $298,446
Accumulated depletion(1) (143,510) (93,796)
--------- --------
Net capitalized costs $265,800 $204,650
========= ========
The leasehold costs which are excluded from the depletion base consist primarily
of acreage acquisition costs and related geological and geophysical costs. For
the years ended December 31, 1997 and 1996, costs of $51,883,000 and
$54,454,000, respectively, were excluded from the depletion base. These costs
are expected to be evaluated within the next three years.
(1) Accumulated depletion includes a $24.1 million oil and natural gas
property impairment taken in 1997.
50
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES:
YEAR ENDED DECEMBER 31,
-----------------------------
1997 1996 1995
---- ---- ----
(in thousands)
Oil and natural gas revenues $57,640 $55,123 $36,966
Less:
Oil and natural gas operating costs 5,680 4,696 3,735
Production and ad valorem taxes 2,165 1,677 966
Depletion 25,573 24,759 18,143
Impairment of oil and natural gas properties 24,141 ----- -----
------ ------- ---------
57,559 31,132 22,844
------ ------ ------
Results of operations from oil and
natural gas producing activities $81 $23,991 $14,122
====== ======= =======
Depletion expense per MCFE $1.27 $1.22 $0.98
===== ======= ========
51
PROVED RESERVES
The following table sets forth the net proved reserves of TMRC as of December
31, 1997, 1996 and 1995, and the changes therein during the years then ended.
The reserve information was reviewed by Ryder Scott Company Petroleum Engineers.
All of TMRC's oil and natural gas producing activities are located in the United
States.
OIL GAS
--- ---
PROVED RESERVES: (MBBLS) (MMCF)
BALANCE AT DECEMBER 31, 1994 2,907 77,218
Production (650) (14,598)
Sale of reserves in place (111) (2,060)
Revisions (125) 5,742
Discoveries and extensions 1,542 24,691
------ --------
BALANCE AT DECEMBER 31, 1995 3,563 90,993
Production (751) (15,783)
Revisions 648 (4,418)
Discoveries and extensions 5,956 36,614
------ --------
BALANCE AT DECEMBER 31, 1996 9,416 107,406
Production (914) (14,603)
Revisions (761) (13,862)
Discoveries and extensions 1,990 31,844
------ --------
BALANCE AT DECEMBER 31, 1997 9,731 110,785
====== =======
OIL GAS
--- ---
PROVED DEVELOPED RESERVES: (MBBLS) (MMCF)
Balance at December 31, 1997 5,305 81,500
Balance at December 31, 1996 4,361 81,192
Balance at December 31, 1995 2,569 76,944
Balance at December 31, 1994 2,396 60,573
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS RELATING TO PROVED OIL AND GAS RESERVES
The information that follows has been developed pursuant to procedures
prescribed by SFAS No. 69 and utilizes reserve and production data reviewed by
independent petroleum consultants. Reserve estimates are inherently imprecise
and estimates of new discoveries are more imprecise than those of producing oil
and natural gas properties. Accordingly, these estimates are expected to change
as future information becomes available.
52
The estimated discounted future net cash flows from estimated proved reserves
are based on prices and costs as of the date of the estimate unless such prices
or costs are contractually determined at such date. Actual future prices and
costs may be materially higher or lower. Actual future net revenues also will be
affected by factors such as actual production, supply and demand for oil and
natural gas, curtailments or increases in consumption by natural gas purchasers,
changes in governmental regulations or taxation and the impact of inflation on
costs. At December 31, 1997, the Company has no future income taxes as the
deductible tax basis and available net operating loss carryforwards exceeds
future net cash flows. Future income tax expense has been reduced for the effect
of available net operating loss carryforwards.
AT DECEMBER 31,
--------------
1997 1996
---- ----
(in thousands)
Future cash flows $451,157 $671,123
Future production costs (76,635) (69,332)
Future development costs (32,746) (41,827)
Future income tax expense ----- (121,347)
--------- ---------
Future net cash flows 341,776 438,617
Discount to present value at 10 percent annual rate (127,859) (124,994)
--------- --------
Standardized measure of discounted future net cash flows $213,917 $313,623
========= ========
The average price for natural gas in the above computations was $2.53 and $4.10
at December 31, 1997 and 1996, respectively. The average price used for crude
oil in the above computations was $17.31 and $24.36 at December 31, 1997 and
1996, respectively.
53
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, 1997, 1996 and 1995.
YEAR ENDED DECEMBER 31,
----------------------
1997 1996 1995
---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD .......................... $ 313,623 $ 149,863 $ 100,782
Sale of oil and gas, net of production costs ......... (49,796) (48,750) (32,265)
Changes in prices, and production costs .............. (165,406) 104,249 20,316
Revisions of previous quantity estimates ............. (28,574) (756) 9,839
Sales of reserves in place ........................... -- -- (3,262)
Current year discoveries, extensions
and improved recovery .............................. 50,274 167,080 56,603
Changes in estimated future
development costs .................................. (3,564) (7,597) (20,751)
Development cost incurred during the period .......... 27,666 11,723 19,242
Accretion of discount ................................... 39,451 16,182 10,485
Net change in income taxes .............................. 80,884 (63,476) (13,199)
Change in production rates (timing) and other(1) ........ (50,641) (14,895) 2,073
--------- --------- ---------
Net change .............................................. (99,706) 163,760 49,081
--------- --------- ---------
BALANCE AT END OF PERIOD ................................ $ 213,917 $ 313,623 $ 149,863
========= ========= =========
(1) Approximately $29 million of this change relates in 1997 to production rates
(timing).
54
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
The information required in Items 10, 11, 12 and 13 is incorporated by reference
to the Company's definitive Proxy Statement to be filed with the Securities and
Exchange Commission on or before April 30, 1998.
55
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Independent Auditor's Report
(ii) Consolidated Balance Sheets as of December 31, 1996 and 1995
(iii) Consolidated Statements of Operations for each of the three years in the period ended
December 31, 1996
(iv) Consolidated Statements of Changes in Stockholders' Equity
for each of the three years in the period ended December
31, 1996
(v) Consolidated Statements of Cash Flows for each of the three years in the period ended
December 31, 1996
(vi) Notes to Consolidated Financial Statements
(vii) Consolidated Supplemental Oil and Gas Information (Unaudited)
2. Financial Statement Schedule:
(i) All schedules are omitted as they are not applicable, not
required or the required information is included in the
consolidated financial statements or notes thereto.
3. Exhibits:
2.1 Agreement and Plan of Merger dated March 27, 1998, between
the Company, LOPI Acquisition Corp., Shell Louisiana
Onshore Properties, Inc. and Louisiana Onshore Properties,
Inc. (Pursuant to S-K Item 601(b)(2), the Company has not
included in the filing Exhibit D (LOPI financial
statements); Exhibit 1 (preliminary TMR financial
statements) or Schedule I or II (which relate to the
representations and warranties of the parties). The
Company agrees to furnish supplementally any omitted
schedule to the Commission upon request.
2.2 Agreement and Plan of Merger dated July 3, 1997, among the
Company, C Acquisition Corp. And Cairn Energy USA, Inc.
(incorporated by reference from the Company's current
Report on Form 8-K dated July 3, 1997). Pursuant to Item
601(b)(2) of Regulation S-K, certain schedules and similar
attachments to the Agreement and Plan of Merger have not
been filed with this exhibit. Such schedules and
attachments contain various items relating to the
representation and warranties made by the parties to the
Agreement and Plan of Merger. The Company agrees to
furnish supplementally any omitted schedule to the
Commission upon request.
3.1 Second Amended and Restated Articles of Incorporation of
the Company (incorporated by reference to Exhibit 3 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).
56
3.2 Bylaws of the Company, as amended (incorporated by
reference to Exhibit 3 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 on March 4, 1993).
3.3 Amendment to the Second Amended and Restated Articles of
Incorporation of the Registrant (incorporated by reference
to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1997).
3.4 Amendment to the Company's Bylaws Dated March 6, 1998.
4.1 Specimen Common Stock Certificate (incorporated by
reference to Exhibit 4.1 of the Company's Registration
Statement on Form S-1, as amended (Reg. No. 33-65504)).
4.2 Common Stock Purchase Warrant of the Company dated October
16, 1990, issued to Joseph A. Reeves, Jr. (incorporated by
reference to Exhibit 10.8 of the Company's Annual Report
on Form 10-K for the year ended December 31, 1991, as
amended by the Company's Form 8 filed March 4, 1993).
4.3 Common Stock Purchase Warrant of the Company dated October
16, 1990, issued to Michael J. Mayell (incorporated by
reference to Exhibit 10.9 of the Company's Annual Report
on Form 10-K for the year ended December 31, 1991, as
amended by the Company's Form 8 filed March 4, 1993).
*4.4 Registration Rights Agreement dated October 16, 1990,
among 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 Form of 1993 Non-Employee Director Stock Option Agreement
(incorporated by reference to Exhibit 4.9 of the Company's
Registration Statement on Form S-8 (Reg. No. 33-86788)).
4.8 Credit Agreement dated as of November 5, 1997, among The
Meridian Resource Corporation, the several Lenders from
time to time a party thereto and The Chase Manhattan Bank,
as administrative Agent (incorporated by reference from
Exhibit 4.16 to the Company's Registration Statement on
Form S-8 (File No. 333-40009).
4.10 Pledge Agreement dated as of November 5, 1997, by Cairn
Energy USA, Inc., Texas Meridian Resources Exploration,
Inc., Texas Meridian Production Corporation and Texas
Meridian Finance Corporation, in favor of The Chase
Manhattan Bank (incorporated by reference from Exhibit
4.16 to the Company's Registration Statement on Form S-8
(File No. 333-40009).
57
4.11 Guaranteed dated November 5, 1997, by Cairn Energy USA,
Inc., Texas Meridian Resources Exploration, Inc., Texas
Meridian Production Corporation and Texas Meridian Finance
Corporation, in favor of The Chase Manhattan Bank
(incorporated by reference from Exhibit 4.16 to the
Company's Registration Statement on Form S- 8 (File No.
333-40009).
*10.1 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).
*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.
*10.4 Employment Agreement dated August 18, 1993, between the
Company and Michael J. Mayell.
*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 The Meridian Resource Corporation 1995 Long-Term Incentive
Plan.
*10.7 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).
*10.8 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).
*10.9 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)
*10.10 Texas Meridian Resources Corporation 1997 Long-Term
Incentive Plan (incorporated by reference to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1997).
*10.11 Cairn Energy USA, Inc. 1993 Stock Option Plan, as amended
(incorporated by reference to Cairn Energy USA, Inc.'s
Annual Report on Form 10-K for the year ended December 31,
1993).
58
*10.12 Cairn Energy USA, Inc. 1993 Directors Stock Option Plan,
as amended (incorporated by reference to Cairn Energy USA,
Inc.'s Registration Statement on Form S-1 (Reg. No.
33-64646).
*10.13 Notes Receivable dated December 31, 1997 to the Company
from affiliates of Michael J. Mayell.
*10.14 Notes Receivable dated December 31, 1997 to the Company
from affiliates of Joseph A. Reeves, Jr.
21. Subsidiaries of the Company.
23.1 Consent of Ernst & Young LLP.
23.2 Consent of Ryder Scott Company.
27.1 Financial Data Schedule
* Management contract or compensation plan.
(b) Reports on Form 8-K.
On November 14, 1997, the Company filed its Current Report on Form 8-K
dated November 5, 1997, reporting the merger of a subsidiary of the Company
with and into Cairn Energy USA, Inc. The report included financial
statements of Cairn as of and for the six months ended June 30, 1997 and
the years ended December 31, 1996 and 1995 as well as pro forma financial
statements of the Company as of and for the six months ended June 30, 1997
and the year ended December 31, 1996.
On December 23, 1997, the Company filed its Current Report on Form 8-K
dated December 19, 1997 reporting that it had executed a Letter of Intent
relating to the Shell Transactions.
59
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 31, 1998
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 Office March 31, 1998
Joseph A. Reeves, Jr. (Principal Executive Officer)
Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director March 31, 1998
Michael J. Mayell
BY: /s/ P. RICHARD GESSINGER Chief Financial Officer March 31, 1998
P. Richard Gessinger
BY: /s/ LLOYD V. DELANO Chief Accounting Officer March 31, 1998
Lloyd V. DeLano
BY: /s/ JOE E. KARES Director March 31, 1998
Joe E. Kares
BY: /s/ GARY A. MESSERSMITH Director March 31, 1998
Gary A. Messersmith
60
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------ -----------
2.1 Agreement and Plan of Merger dated March 27, 1998, between
the Company, LOPI Acquisition Corp., Shell Louisiana
Onshore Properties, Inc. and Louisiana Onshore Properties,
Inc. (Pursuant to S-K Item 601(b)(2), the Company has not
included in the filing Exhibit D (LOPI financial
statements); Exhibit 1 (preliminary TMR financial
statements) or Schedule I or II (which relate to the
representations and warranties of the parties). The
Company agrees to furnish supplementally any omitted
schedule to the Commission upon request.
2.2 Agreement and Plan of Merger dated July 3, 1997, among the
Company, C Acquisition Corp. And Cairn Energy USA, Inc.
(incorporated by reference from the Company's current
Report on Form 8-K dated July 3, 1997). Pursuant to Item
601(b)(2) of Regulation S-K, certain schedules and similar
attachments to the Agreement and Plan of Merger have not
been filed with this exhibit. Such schedules and
attachments contain various items relating to the
representation and warranties made by the parties to the
Agreement and Plan of Merger. The Company agrees to
furnish supplementally any omitted schedule to the
Commission upon request.
3.1 Second Amended and Restated Articles of Incorporation of
the Company (incorporated by reference to Exhibit 3 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).
3.2 Bylaws of the Company, as amended (incorporated by
reference to Exhibit 3 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 on March 4, 1993).
3.3 Amendment to the Second Amended and Restated Articles of
Incorporation of the Registrant (incorporated by reference
to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1997).
3.4 Amendment to the Company's Bylaws Dated March 6, 1998.
4.1 Specimen Common Stock Certificate (incorporated by
reference to Exhibit 4.1 of the Company's Registration
Statement on Form S-1, as amended (Reg. No. 33-65504)).
4.2 Common Stock Purchase Warrant of the Company dated October
16, 1990, issued to Joseph A. Reeves, Jr. (incorporated by
reference to Exhibit 10.8 of the Company's Annual Report
on Form 10-K for the year ended December 31, 1991, as
amended by the Company's Form 8 filed March 4, 1993).
4.3 Common Stock Purchase Warrant of the Company dated October
16, 1990, issued to Michael J. Mayell (incorporated by
reference to Exhibit 10.9 of the Company's Annual Report
on Form 10-K for the year ended December 31, 1991, as
amended by the Company's Form 8 filed March 4, 1993).
*4.4 Registration Rights Agreement dated October 16, 1990,
among 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 Form of 1993 Non-Employee Director Stock Option Agreement
(incorporated by reference to Exhibit 4.9 of the Company's
Registration Statement on Form S-8 (Reg. No. 33-86788)).
4.8 Credit Agreement dated as of November 5, 1997, among The
Meridian Resource Corporation, the several Lenders from
time to time a party thereto and The Chase Manhattan Bank,
as administrative Agent (incorporated by reference from
Exhibit 4.16 to the Company's Registration Statement on
Form S-8 (File No. 333-40009).
4.10 Pledge Agreement dated as of November 5, 1997, by Cairn
Energy USA, Inc., Texas Meridian Resources Exploration,
Inc., Texas Meridian Production Corporation and Texas
Meridian Finance Corporation, in favor of The Chase
Manhattan Bank (incorporated by reference from Exhibit
4.16 to the Company's Registration Statement on Form S-8
(File No. 333-40009).
4.11 Guaranteed dated November 5, 1997, by Cairn Energy USA,
Inc., Texas Meridian Resources Exploration, Inc., Texas
Meridian Production Corporation and Texas Meridian Finance
Corporation, in favor of The Chase Manhattan Bank
(incorporated by reference from Exhibit 4.16 to the
Company's Registration Statement on Form S- 8 (File No.
333-40009).
*10.1 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).
*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.
*10.4 Employment Agreement dated August 18, 1993, between the
Company and Michael J. Mayell.
*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 The Meridian Resource Corporation 1995 Long-Term Incentive
Plan.
*10.7 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).
*10.8 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).
*10.9 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)
*10.10 Texas Meridian Resources Corporation 1997 Long-Term
Incentive Plan (incorporated by reference to the Company's
Quarterly Report on Form 10-Q for the quarter ended June
30, 1997).
*10.11 Cairn Energy USA, Inc. 1993 Stock Option Plan, as amended
(incorporated by reference to Cairn Energy USA, Inc.'s
Annual Report on Form 10-K for the year ended December 31,
1993).
*10.12 Cairn Energy USA, Inc. 1993 Directors Stock Option Plan,
as amended (incorporated by reference to Cairn Energy USA,
Inc.'s Registration Statement on Form S-1 (Reg. No.
33-64646).
*10.13 Notes Receivable dated December 31, 1997 to the Company
from affiliates of Michael J. Mayell.
*10.14 Notes Receivable dated December 31, 1997 to the Company
from affiliates of Joseph A. Reeves, Jr.
21. Subsidiaries of the Company.
23.1 Consent of Ernst & Young LLP.
23.2 Consent of Ryder Scott Company.
27.1 Financial Data Schedule
* Management contract or compensation plan.