Back to GetFilings.com
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, 1998 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 18, 1999. $135,401,832
Number of shares of common stock outstanding at March 18, 1999. 45,817,319
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, 1999.
Page 1 of 61
THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K
PART I PAGE
----
Item 1. Business .................................................... 3
Item 2. Properties .................................................. 17
Item 3. Legal Proceedings ........................................... 17
Item 4. Submission of Matters to a Vote of Security Holders ......... 18
PART II
Item 5. Market for Registrant's Common Equity and Related
Shareholder Matters ......................................... 19
Item 6. Selected Financial Data ..................................... 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations ......................... 21
Item 8. Financial Statements and Supplementary Data ................. 31
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure ......................... 56
PART III
Item 10. Directors and Executive Officers of the Registrant .......... 56
Item 11. Executive Compensation ...................................... 56
Item 12. Security Ownership of Certain Beneficial Owners
and Management ..................................... 56
Item 13. Certain Relationships and Related Transactions .............. 56
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K ................................ 57
Signatures .................................................. 61
-2-
PART I
ITEM 1. BUSINESS
GENERAL
The Meridian Resource Corporation is an independent oil and natural gas company
that explores for, acquires and develops oil and natural gas properties using
3-D seismic technology. Our operations are focused in onshore oil and gas
regions in south Louisiana and the Texas Gulf Coast as well as offshore in the
Gulf of Mexico. As of December 31, 1998, (1) we had proved reserves of
approximately 304 Bcfe with a SEC PV10 value of $293 million, and (2)
approximately 56% of our proved reserves were natural gas and approximately 68%
were classified as proved developed. Since December 31, 1998, as a result of our
exploration efforts we have made significant discoveries that we currently
estimate increase our proved reserves by 25 Bcfe as of March 18, 1999.
We believe we are among the leaders in the use of 3-D seismic technology by
independent oil and natural gas companies. We also believe we have a competitive
advantage in the areas where we operate because of our large inventory of
seismic data to which we have rights or access and our expertise with, and
careful application of, 3-D seismic technology.
During 1997, we expanded our operations into the Gulf of Mexico by merging with
Cairn Energy USA, Inc. for shares of our common stock. This acquisition not only
expanded the geographic scope of our operations, but also provided us with a
greater base from which to expand and execute our operations.
Following the merger with Cairn, we acquired substantially all of Shell Oil
Company's and its Affiliates' (collectively, "Shell") onshore south Louisiana
oil and gas property interests in two separate transactions (the "Shell
Transactions"). The Shell Transactions were consummated on June 30, 1998 and
positioned us as one of the leading operators in south Louisiana. We believe we
will be able to improve upon Shell's efforts to develop and explore these
properties due to the larger number of geological and geophysical staff that we
intend to dedicate to these properties. Additionally, the property interests
acquired in the Shell Transactions allow us to focus on more lower risk
development and exploration projects with a lesser dependence on higher risk
exploration drilling. As a result of the Shell Transactions, Shell beneficially
owns 39.9% of our common stock on a fully-diluted basis assuming the exercise of
all outstanding stock options and warrants and conversion of all preferred
stock.
As a result of the merger with Cairn and the Shell Transactions, we believe that
we are strategically positioned to further expand our position as a leading
independent oil and natural gas company operating in south Louisiana and the
Texas Gulf Coast. We currently have interests in over 156,994 gross onshore
acres in Louisiana and Texas and 427,484 gross offshore acres in the Gulf of
Mexico. We also have rights or access to approximately 2,700 square miles of
onshore 3-D seismic data and 1,200 square miles of offshore 3-D seismic data,
which we believe to be one of the largest positions held by a company of our
size operating in our core areas of operation.
The Meridian Resource Corporation was incorporated in Texas in 1990. Our
headquarters are located at 15995 N. Barkers Landing, Suite 300, Houston, Texas
77079.
EXPLORATION STRATEGY
We have focused our exploration strategy on prospects where large accumulations
of oil and natural gas have been found and where we believe substantial oil and
natural gas reserve additions can be achieved through exploratory drilling in
which we use 3-D seismic technology. We also seek to identify prospects with
-3-
multiple potential productive zones to maximize the probability of success. In
an effort to mitigate the risk of dry holes, we engage in a rigorous and
disciplined review of each prospect utilizing the latest in technological
advances with respect to prospect analysis and evaluation.
Our process of review of exploration prospects begins with a thorough analysis
of the prospect using traditional methods of prospect development and computer
technology to analyze all reasonably available 2-D seismic data and other
geological and geophysical data with respect to the prospect. If the results of
this analysis confirm the prospect potential, we seek to acquire 3-D seismic
data over, and leasehold interests in or options to acquire leasehold interests
in, the prospect area. We then apply 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 we design to
identify the location and size of potential hydrocarbon accumulations in the
prospect. If our analysis of the model continues to confirm the potential for
hydrocarbon accumulations within our prospect objectives, we will then seek to
identify the most desirable drilling location to test the prospect and to
maximize production if the prospect is successful.
The process of developing, reviewing and analyzing a prospect from the time we
first identify it to the time that we drill it is generally a 12 to 36 month
process in which we reject many potential prospects at various levels of the
review. Although the cost of designing, acquiring, processing and interpreting
3-D seismic data and acquiring options and leases on prospects that we do not
ultimately drill requires greater up-front costs per prospect than traditional
exploration techniques, we believe that the elimination of prospects that are
unlikely to be successful and that might otherwise have been drilled at a
substantial cost results in significant lower finding cost. We also believe that
our use of 3-D seismic technology minimizes development costs by allowing for
the better placement of initial and, if necessary, development wells.
We attempt to match our exploration risks with expected results by retaining
working interests that historically have been between 50% and 75% in our onshore
wells. Our working interests may vary in certain prospects depending on
participation structure, assessed risk, capital availability and other factors.
In addition, working interests in offshore properties we acquired in the Cairn
acquisition average between 3% and 50% in each well. We intend to increase our
offshore working interests over time as we will operate a greater percentage of
future projects. Our 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.
3-D SEISMIC TECHNOLOGY
An integral part of our exploration strategy is the application and reliance on
3-D seismic technology. We believe that we have a competitive advantage over
many of our competitors because we apply a disciplined approach to our use of
3-D seismic technology and we have rights or access to a substantial inventory
of 3-D seismic data covering our existing properties and new potential
prospects.
We use 3-D seismic technology as a key exploration and drilling tool and not
merely to exploit development opportunities or to confirm 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. We believe that our application of
this technology enables us 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, we believe our use of this
technology increases our success rates and reduces our dry-hole costs compared
to companies that do not engage in a similar process.
We also have sought to achieve advantages over our competitors by acquiring
substantial 3-D seismic data over our prospects prior to drilling and by
securing access to new data over our existing and new prospect areas. We
estimate that the inventory of both proprietary and non-proprietary data that we
own or have rights to acquire has increased from approximately 1,025 square
miles at December 31, 1996 to
-4-
approximately 3,900 square miles at December 31, 1998. In addition, the Shell
transactions provide us with access to substantially all of Shell's existing 2-D
seismic grid covering onshore South Louisiana.
We attempt to maximize the quality and usefulness of our 3-D seismic data by
participating in the original design of the survey whenever practicable. After
the survey is designed, we test the design for the amount and type of energy
source, shot proprietary hole depths and layout, and type and placement of
recording devices to optimize data quality. We also seek to have a
representative on location during the acquisition process and conduct periodic
quality-control checks as a survey progresses.
We can test the survey design in part because we can process the survey field
data using our 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 interpretation
software can use it. We believe that having the capability to process internally
gives us greater control over not only the survey planning but also over the
cost and timing of processing the survey data, and gives us greater flexibility
to control the assumptions used in processing the data.
Once we complete our processing, we then analyze the data using state-of-the-art
interpretation software and techniques, including amplitude variation with
offset, 3-D and 2-D pre-stack depth migration, coherency and inversion
techniques. In the areas where we are active, the 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 us to apply combinations of interpretive techniques and multiple
iterations to yield the best solution. In addition to seismic data, we use all
available subsurface data from wells previously drilled in the surrounding areas
to correlate structural position and to test the validity of hydrocarbon
indicators, where applicable.
-5-
OIL AND GAS PROPERTIES
This following table sets forth as of December 31, 1998, our net proved
reserves, average working interest and the operator of our 10 largest properties
representing 80% of our proved reserves as of December 31, 1998.
NET PROVED RESERVES
GAS OIL TOTAL
FIELD MMCF MBLS (BCFE) OPERATOR
----- ---- ---- ------ --------
ONSHORE(1)
Weeks Island ...................... 24,897 13,980 108.8 TMRC
Lac Blanc ......................... 17,306 178 18.4 TMRC
West Lake Verret .................. 3,100 2,396 17.5 TMRC
Turtle Bayou ...................... 15,859 73 16.3 TMRC
Backridge (Cameron) ............... 2,113 2,077 14.6 TMRC
Chocolate Bayou ................... 8,364 143 9.2 TMRC
Gibson-Humphreys .................. 3,959 97 4.5 TMRC
OFFSHORE
East Cameron Block 331/332 ........ 13,705 703 17.9 Third Party
South Timbalier Block 290/291 ..... 6,883 207 8.1 TMRC
Vermillion Block 203 .............. 3,915 34 4.1 Third Party
(1) Includes properties located in state waters and transition zones.
This table does not include the Company's new field discovery at North Turtle
Bayou which represents 25 BCFE of proved reserves added subsequent to year end.
WEEKS ISLAND FIELD. The Weeks Island is located in Iberia Parish, Louisiana, at
the northeast lobe of Vermillion Bay. We have acquired a 100 square mile 3-D
seismic survey over the dome that is currently being processed. Average daily
gross production during December 1998 was 73.7 Mmcfe (50.1 Mmcfe net) from 13
gross (13 net) wells. During 1998, we drilled 4 gross wells in this field, 4 of
which were commercially productive. We currently plan to drill five development
wells in this field during 1999. At least two offset-development locations are
being permitted. Enron has claimed an ownership interest in certain of our
recently drilled wells in this field. This dispute is currently in arbitration.
See "Legal Proceedings."
LAC BLANC FIELD. The Lac Blanc field is located 25 miles southwest of Abbeville
in Vermillion Parish, Louisiana. The field is in White Lake and is operated by
work boat. We have acquired a 40 square mile 3-D that is currently being
processed. Average daily gross production during December 1998 was 2.7 Mmcfe
(1.0 Mmcfe net) from 5 gross (2.5 net) wells.
-6-
WEST LAKE VERRET . The West Lake Verret field is located 64 miles west of New
Orleans in St. Martins Parish, Louisiana. We acquired a 63 square mile 3-D
seismic survey covering the field that was shot in 1993. Average daily gross
production during December 1998 was 7.9 Mmcfe (6.6 Mmcfe net) from 44 gross (44
net) wells. We currently plan to drill two development wells in this field
during 1999.
TURTLE BAYOU FIELD. The Turtle Bayou field is located 65 miles southwest of New
Orleans in Terrebonne Parish, Louisiana. We acquired a proprietary 3-D seismic
survey covering the field that was shot in 1993. Average daily gross production
during December 1998 was 6.1 Mmcfe (5.4 Mmcfe net) from 13 gross (13 net) wells.
During 1998, we drilled one gross well in this field, which was commercially
productive. We currently plan to drill one development well in this field during
1999.
BACKRIDGE (CAMERON) FIELD. The Backridge (Cameron) field is located one mile
north of the town of Cameron in Cameron Parish, Louisiana. In 1994, we acquired
a 43-square mile proprietary 3-D survey over the area that led to multiple
discoveries. Average daily gross production during December 1998 was 12.5 Mmcfe
(5 Mmcfe net) from 5 gross (2.5 net) wells.
CHOCOLATE BAYOU FIELD . The Chocolate Bayou field is located 35 miles south of
Houston in Brazoria Co., Texas. We acquired 70 square miles of seismic data
covering the field which led to our discovery of this field. The first
production began in January 1993 and we have drilled a total of 8 wells to date.
Average daily gross production during December 1998 was 12.9 Mmcfe (3.6 Mmcfe
net) from 5 gross (2.9 net) wells.
GIBSON-HUMPHREYS FIELD. The Gibson-Humphreys field is located 55 miles southwest
of New Orleans in Terrebonne Parish, Louisiana. Shell licensed to us 13 square
miles of a large non-proprietary 3-D seismic program in 1994 that will be used
for future field development. Average daily gross production during December
1998 was .9 Mmcfe (.4 Mmcfe net) from 3 gross (1.5 net) wells.
EAST CAMERON 331/332 FIELD. The East Cameron 331/332 field is located 98 miles
offshore Louisiana in 240 feet of water. The field's production is processed
through a 21 slot, four-pile manned drilling and production platform with 100
Mmcf/day and 10,000 Bbl/day capacity. We will sidetrack the No. A-7 well to test
a Lentic 5 amplitude anomaly that ties to log shows in the No. A-16 well.
Average daily gross production during December 1998 was 59.2 Mmcfe (11.3 Mmcfe
net) from 12 gross (3.6 net) wells. During 1998, we drilled two gross wells in
this field, one of which was commercially productive.
SOUTH TIMBALIER 290/291 FIELD. The South Timbalier 290/291 field is located 60
miles offshore Louisiana in 395 feet of water. The field's production will be
processed through an eight slot, four-pile manned drilling and production
platform with 50 Mmcf/day and 5,000 Bbl/day capacity. The platform was installed
in the fourth quarter of 1998 and testing of the No. 1 well began immediately
thereafter. A comprehensive development program will commence based on the No. 1
well test results. We currently plan to drill two exploratory wells in this
field during 1999.
VERMILLION 203 FIELD. The Vermillion Block 203 field is located 56 miles
offshore Louisiana in 100 feet of water. The field's production is processed
through a six slot, four-pile unmanned production platform with facilities
capable of processing 50 Mmcf/day and 5,000 Bbl/day. Average daily gross
production during December 1998 was 4.0 Mmcfe (1.5 Mmcfe net) from two gross
(one net) wells.
-7-
PRODUCING PROPERTIES
The following table sets forth reserve and production information by region with
respect to our proved oil and gas reserves as of December 31, 1998. The reserve
volumes were prepared by T.J. Smith & Company, Inc., independent reservoir
engineers.
GULF OF
TEXAS LOUISIANA MEXICO OTHER TOTAL
------------ -------------- ------------- ----------- --------------
RESERVES AS OF DECEMBER 31, 1998
Oil (MBbls) ...................... 143 20,992 1,242 _____ 22,377
Gas (MMcf) ....................... 8,364 123,692 37,831 _____ 169,887
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS ($000)(1) ....... $ 11,401 $237,981 $ 43,995 _____ $293,377
PRODUCTION FOR THE YEAR ENDED
DECEMBER 31, 1998
Oil (MBbls) ...................... 49 1,812 499 5 2,365
Gas (MMcf) ....................... 2,311 7,732 10,429 131 20,603
(1) The Standardized Measure of Discounted Future Net Cash Flows represents
the Present Value of Future Net Revenues after income taxes discounted at
10%. For calculating the Present Value of Future Net Revenues as of
December 31, 1998, we used the prices we received at December 31, 1998,
which were $10.13 per Bbl of oil and $2.14 per Mcf of natural gas.
PRODUCTIVE WELLS
At December 31, 1998, 1997, and 1996, we held interests in the following
productive wells. The majority of our 45 gross (10 net) wells in the Gulf of
Mexico as of December 31, 1998 have multiple completions.
DECEMBER 31,
1998 1997 1996
--------------------------- ---------------------------- ------------------------------
GROSS NET GROSS NET GROSS NET
----------- ----------- ------------ ----------- ------------- ------------
Oil Wells...................... 117 89 16 7 12 4
Gas Wells...................... 94 42 345 94 337 91
Total................. 211 131 361 101 349 95
=========== =========== ============ =========== ============= ============
-8-
OIL AND NATURAL GAS RESERVES
Presented below are our estimated quantities of proved reserves of crude oil and
natural gas, Future Net Cash Flows, Present Value of Future Net Revenues and the
Standardized Measure of Discounted Future Net Cash Flows as of December 31,
1998. Information set forth in the following table is based on reserve reports
we prepared in accordance with the rules and regulations of the Commission. The
reserve volumes were prepared by T. J. Smith & Company, Inc., independent
reservoir engineers, as of December 31, 1998.
PROVED RESERVES AT DECEMBER 31, 1998
--------------------------------------------------------------------------------
DEVELOPED DEVELOPED UNDEVELOPED TOTAL
PRODUCING NON-PRODUCING
------------- ------------------ ------------------ -------------------
(DOLLARS IN THOUSANDS)
Net Proved Reserves:
Oil (MBbls)................................ 11,783 2,809 7,785 22,377
Gas (MMcf)................................. 70,922 49,311 49,654 169,887
Natural Gas Equivalent (Mmcfe)............. 141,620 66,165 96,364 304,149
Future Net Cash Flows(1).............................................................................. $ 407,663
Standardized Measure of Discounted Future Net Cash Flows(1)........................................... $ 293,377
- ---------------
(1) The Standardized Measure of Discounted Future Net Cash Flows we
prepared represents the Present Value of Future Net Revenues after
income taxes discounted at 10%. For calculating the Future Net Cash
Flows, the Present Value and Future Net Revenues and Standard Measure
of Discounted Future Net Cash Flows as of December 31, 1998, we used
the prices we received at December 31, 1998, which were $10.13 per Bbl
of oil and $2.14 per Mcf of natural gas.
You can read additional reserve information in our Consolidated Financial
Statements and the Supplemental Oil and Gas Information (unaudited) included
elsewhere herein. We have not included estimates of total proved reserves,
comparable to those disclosed herein, in any reports filed with federal
authorities other than the Commission.
In general, we base our estimates of economically recoverable oil and natural
gas reserves and of the future net revenues therefrom on a number of variable
factors and assumptions, such as historical production from the subject
properties, the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices and future operating
costs, all of which may vary considerably from actual results. All such
estimates are to some degree speculative, and classifications of reserves 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, and development and operating expenditures
with respect to our reserves likely will vary from such estimates, and such
variances could be material.
Estimates with respect to proved reserves that we may develop and produce in the
future are often based on volumetric calculations and on analogy to similar
types of reserves rather than actual production history. Estimates based on
these methods generally are less reliable than those based on actual production
history, and subsequent evaluation of the same reserves, based on production
history, will result in variations, which may be substantial, in the estimated
reserves.
In accordance with applicable requirements of the Commission, we based the
estimated discounted future net revenues from estimated proved reserves 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
-9-
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 we drilled in 1998, 1997 and 1996.
GROSS WELLS NET WELLS
--------------------------------------- ---------------------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
-------------- -------- --------- -------------- -------- ---------
EXPLORATORY WELLS
Year ended December 31, 1998................... 8 12 20 2.9 6.3 9.2
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
DEVELOPMENT WELLS
Year ended December 31, 1998................... 6 1 7 4.5 .2 4.7
Year ended December 31, 1997................... 3 - 3 0.8 - 0.8
Year ended December 31, 1996................... --- - - - - -
The Company had 4 gross (1.9 net) exploratory wells in progress at December 31,
1998.
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 we held an interest during 1998, 1997 and 1996.
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1998 1997 1996
----------------- ------------------ -----------------
PRODUCTION:
Oil (Mbbls).................................. 2,365 914 751
Natural gas (MMcf)........................... 20,603 14,603 15,783
Natural gas equivalent (MMCFE)............... 34,793 20,087 20,289
AVERAGE PRICES:
Oil ($/Bbl).................................. $ 12.19 $ 19.72 $ 21.92
Natural Gas ($/Mcf).......................... $ 2.16 $ 2.70 $ 2.44
Natural gas equivalent($/MCFE)............... $ 2.11 $ 2.86 $ 2.71
PRODUCTION EXPENSES:
Lease operating expenses
($/MCFE)................................. $ 0.37 $ 0.28 $ 0.23
Severance and ad valorem
taxes ($/MCFE)........................... $ 0.12 $ 0.11 $ 0.08
-10-
ACREAGE
The following table sets forth the developed and undeveloped oil and natural gas
acreage in which we held an interest as of December 31, 1998. Undeveloped
acreage is considered to be those lease acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether or not such acreage
contains proved reserves.
DECEMBER 31, 1998
-------------------------------------------------------------------------
DEVELOPED UNDEVELOPED
---------------------------------- ---------------------------------
REGION GROSS NET GROSS NET
-------------- -------------- ------------- --------------
TEXAS 1,510 1,172 380 225
LOUISIANA 38,160 29,923 116,944 64,763
GULF OF MEXICO 109,746 30,922 317,738 141,490
-------------- -------------- ------------- --------------
TOTAL 149,416 62,017 435,062 206,478
============== ============== ============= ==============
In addition to the above acreage, we currently have options or farm-ins to
acquire leases on approximately 29,704 gross (13,573 net) acres of undeveloped
land located in Texas and Louisiana. Our fee holdings of 5,000 acres have been
included in the undeveloped acreage and have been reduced to reflect the
interest that has been leased to third parties.
GEOLOGIC AND GEOPHYSICAL EXPERTISE
We employ approximately 98 full-time non-union employees. Our exploration staff
consists of 44 persons, representing 45% of our total personnel. Our staff
includes 9 full-time geologists and 11 full-time geophysicists, with between 9
and 43 years of experience in generating onshore and offshore prospects in the
Louisiana, Texas Gulf Coast and in the Gulf of Mexico. Our geologists and
geophysicists generate and review all prospects using computer hardware and
software. This group of professionals reduces our dependence on outside
technical consultants, allowing us to generate most of our prospects rather than
taking promoted prospects generated by outside geologists.
In the interest of retaining talented technical personnel, we have adopted an
incentive compensation plan for our senior geologists, geophysicists,
consultants and executives that relates each individual's compensation to the
success of our exploration activities by providing compensation based on results
of the prospects.
MARKETING OF PRODUCTION
We market our production to third parties consistent with industry practices.
Typically, we sell our onshore oil production at the wellhead at field-posted
prices and we sell our natural gas under contract at a negotiated price based on
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. We typically sell our
onshore gas production under short-term contracts or in the spot market.
We sell our offshore oil production 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. We typically sell our offshore gas production pursuant to short-term
contracts or in the spot market.
-11-
The following table sets forth purchasers of our oil and natural gas that
accounted for more than 10% of total revenues for 1998, 1997 and 1996.
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
CUSTOMER 1998 1997 1996
--------
---------------- ----------------- -----------------
Tauber Oil Company..................................... 32% ----- -----
Equiva Trading Company(1).............................. 22% ----- -----
Coral Energy Resources(1).............................. 15% ----- -----
Phillips Petroleum Company............................. ----- 20% 22%
Coastal Corporation.................................... ----- 15% 21%
Koch Oil Company....................................... ----- 15% 12%
(1) These entities are affiliates of Shell.
We believe that the loss of any of these purchasers would not have a material
adverse effect on our results of operations because other purchasers for its oil
and natural gas are available.
MARKET CONDITIONS
Our revenues, profitability and future rate of growth substantially depend on
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 our control. Since 1992, prices for West Texas Intermediate
crude have ranged from $23.39 to $8.00 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. Prices we received for our oil production have been
significantly depressed since the fourth quarter of 1997. Average natural gas
prices have similarly declined, but on a less dramatic basis. As a result of
these declines, the average price we received during the year ended December 31,
1998 was $2.11 per Mcfe compared to $2.86 per Mcfe during the year ended
December 31, 1997, which negatively impacted our revenues and cash flow during
1998. These declines in prices of oil and natural gas have affected the results
and associated cash flow of our 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 would have a material adverse
effect on our results of operations and financial condition.
The marketability of our production depends in part on the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. Federal and state regulation of oil and natural gas
production and transportation, general economic conditions, changes in supply
and changes in demand could adversely affect our ability to produce and market
our oil and natural gas. If market factors were to change dramatically, the
financial impact on us could be substantial. We do not control the availability
of markets and the volatility of product prices are beyond our control and thus
they represent significant risks.
COMPETITION
The oil and natural gas industry is highly competitive for prospects, acreage
(including offshore in the Gulf of Mexico) and capital. Our competitors include
numerous major and independent oil and natural gas companies, individual
proprietors, drilling and income programs and partnerships. Many of these
competitors possess and employ financial and personnel resources substantially
in excess of those available to us and may, therefore, be able to define,
evaluate, bid for and purchase more oil and natural gas properties than we can.
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.
-12-
At present, we compete with Shell in the Gulf of Mexico for offshore prospects
and we expect that such competition will continue. Shell also retains and may
obtain in the future interests in producing properties and exploration prospects
in Louisiana state waters and adjacent onshore areas where Shell competes with
us. In addition, although Shell currently does not have any significant working
interests in producing properties or exploration prospects onshore in south
Louisiana, and has indicated to us that it does not currently intend to obtain
any such interests, it may do so in the future.
REGULATION
The availability of a ready market for any oil and natural gas production
depends on numerous factors that we do not control. These factors include
regulation of oil and natural gas production, federal and state regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by a well or proration unit, the amount of oil and natural
gas available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or lack of an available natural gas pipeline in the
areas in which we may conduct operations. State and federal regulations
generally are intended to prevent waste of oil and natural gas, protect rights
to produce oil and natural gas between multiple owners in a common reservoir,
control the amount of oil and natural gas produced by assigning allowable rates
of production and control contamination of the environment. Pipelines are
subject to the jurisdiction of various federal, state and local agencies.
Oil and natural gas production operations are subject to various types of
regulation by state and federal agencies. Legislation affecting the oil and
natural gas industry is under constant review for amendment or expansion. In
addition, numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations that bind the oil and
natural gas industry and its individual members, some of which carry substantial
penalties for failure to comply. The regulatory burden on the oil and natural
gas industry increases our cost of doing business and, consequently, affects our
profitability.
All of our federal offshore oil and gas leases are granted by the federal
government and are administered by the Mineral Management Service (the "MMS").
These leases require compliance with detailed federal regulations and orders
that regulate, among other matters, drilling and operations and the calculation
of royalty payments to the federal government. Ownership interests in these
leases generally are restricted to United States citizens and domestic
corporations. The MMS must approve any assignments of these leases or interests
therein.
The federal authorities, as well as many state authorities, require permits for
drilling operations, drilling bonds and reports concerning operations and impose
other requirements relating to the exploration and production of oil and gas.
These states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from oil and gas wells and the
regulation of spacing, plugging and abandonment of such wells. The statutes and
regulations of the federal authorities, as well as many state authorities, limit
the rates at which we can produce oil and gas on our properties.
GAS PRICE CONTROLS
Prior to January 1993, the Federal Energy Regulatory Commission ("FERC") under
the Natural Gas Price Act ("NGPA"), regulated certain natural gas and 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 our natural gas after such date may be made at market
prices.
The FERC regulates interstate natural gas pipeline transportation rates and
service conditions that affect the marketing of natural gas we produce, as well
as the revenues we receive for sales of such natural gas. Since
-13-
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 its 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.
Although Order No. 636 does not regulate gas producers such as us, 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 us
and our 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 us. We do
not believe, however, that we will be affected by any action taken with respect
to Order No. 636 any differently than other gas producers and marketers with
which we compete.
The FERC has adopted a policy concerning "spin-downs" and "spin-offs" of
gathering systems operated by jurisdictional pipelines to non-jurisdictional
entities. Because we use gathering service for the transportation of gas from
the wellhead to gas transmission pipelines, this policy could affect us. 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 we pay or the
gathering services we received 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, we cannot assure you
that the less-stringent regulatory approach recently pursued by the FERC and
Congress will continue.
OIL PRICE CONTROLS
Our sales of crude oil, condensate and gas liquids are not regulated and are
made at market prices.
STATE REGULATION OF OIL AND NATURAL GAS PRODUCTION
States where we conduct our oil and natural gas activities regulate the
production and sale of oil and natural gas, including requirements for obtaining
drilling permits, the method of developing new fields, the spacing and operation
of wells and the prevention of waste of natural gas and resources. In addition,
most states regulate the rate of production and may establish maximum daily
production allowables for wells on a market demand or conservation basis.
ENVIRONMENTAL REGULATION
Our operations are subject to numerous laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require us to acquire a
permit before we commence drilling, restrict the types, quantities and
concentration of various substances that we can release into the environment in
connection with drilling and production activities,
-14-
limit or prohibit our drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from our operations. Moreover, the 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 enacted, it could have a significant
impact on our operating costs, as well as the oil and natural gas industry in
general. Initiatives to further regulate the disposal of oil and gas wastes also
are pending in certain states, and these various initiatives could have a
similar impact on us. We believe that we substantially comply with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on us.
OPA. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area where an offshore facility is
located. The OPA 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
party caused the spill 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 be able to cover at least some costs if a
spill occurs. On August 25, 1993, the MMS published an advance notice that it
intends 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 also are uncertain.
We cannot predict the final form of the financial responsibility rule that the
MMS will adopt, but such rule could impose on us substantial additional annual
costs or otherwise materially adversely affect us. The impact of the rule should
not be any more adverse to us 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. We have such a plan in place. Failure to comply with ongoing
requirements or inadequate cooperation during a spill may subject a responsible
party to civil or criminal enforcement actions.
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.
-15-
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, we make only a cursory
review of title to undeveloped oil and natural gas leases at the time we acquire
them. However, before drilling commences, we search the title, and remedy any
material defects before we actually begin drilling the well. To the extent title
opinions or other investigations reflect title defects, we (rather than the
seller or lessor of the undeveloped property) typically are obligated to cure
any such title defects at our expense. If we were unable to remedy or cure any
title defect so that it would not be prudent for us to commence drilling
operations on the property, we could suffer a loss of our entire investment in
the property. We believe that we have good title to our oil and natural gas
properties, some of which are subject to immaterial encumbrances, easements and
restrictions. Under the terms of our credit facility, we may not grant liens on
various of our properties and must grant to our lenders a lien on such property
in the event of certain defaults. Our owned oil and natural gas properties also
typically are subject to royalty and other similar noncost-bearing interests
customary in the industry. We currently are in a dispute with respect to our
interest in the Southwest Holmwood field. Enron also has claimed an interest in
wells that we have drilled in the Weeks Island Field. See " - Legal
Proceedings".
We acquired substantial portions of our 3-D seismic data through licenses and
other similar arrangements. Such licenses contain transfer and other
restrictions customary in the industry.
-16-
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 us in
Louisiana State Court in Calcasieu Parish with respect to a dispute involving
our drilling of our Ben Todd No. 1 (TMRC) well in the Southwest Holmwood
Field in which we 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. We drilled the Ben Todd No. 1 (TMRC) well under a
participation agreement between us and Amoco pursuant to which Amoco had a right
to participate in the well. We drilled the well after providing notice to Amoco
pursuant to the participation agreement that we intended to drill the well and
that Amoco had failed to take action to elect to participate in the well. Prior
to drilling the well, our legal advisors informed us that under our Joint
Operating Agreement with Amoco, we had the right to drill the well because Amoco
had refused to consent to drill the well after we requested to do so. Amoco also
did not seek to enjoin the drilling of the well and accepted the benefits (both
working interest and royalty revenues) 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 Participation Agreement did not permit us to
drill the well and sought to recover all the revenues from the well or to stop
us from producing from the well. Amoco requested that the trial court cancel the
Participation Agreement and our leasehold interest in the prospect, which
included our 50% interest in the Ben Todd No. 2 (Amoco) well that Amoco drilled
prior to the Ben Todd No. 1 (TMRC) well on an agreed basis. We filed a
counterclaim for breach of contract, unfair practices and other claims.
On December 22, 1997, the United States District Court for the Western District
of Louisiana entered a judgment against us in this matter and ordered that the
Participation Agreement did not permit us to drill the Ben Todd No. 1 (TMRC)
well and that the Participation Agreement and related lease had been terminated
by virtue of our drilling the well. The trial court also dismissed our
counterclaims against Amoco. The trial court further ordered a reversion of our
rights to the Ben Todd No. 1 (TMRC) well and the Ben Todd No. 2 (Amoco) well and
directed us to account for all production and monies we received from the date
of the cancellation of the lease. We recorded a charge of $6.2 million in the
fourth quarter of 1997, representing our 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. We do not
expect any material additional charges to be made with respect to this matter.
We have reported no reserves related to these properties as of December 31, 1997
or thereafter. We have filed an appeal relating to the decision of the trial
court in this litigation.
In November, 1998 Enron Capital & Trade Resources Corp. ("Enron") filed an
action in the District Court of Harris County, Texas, 11th Judicial District,
Texas which is proceeding against certain Shell affiliates ("Shell") and us. The
pleadings allege causes of action against Shell and us for trespass and tortious
interference with contract and seeking declaratory and injunctive relief. Enron
further asserts that our drilling and operation of certain Louisiana oil and gas
wells has and will trespass upon Enron's Louisiana property interests and
tortiously interfere with a Participation Agreement dated June 12, 1996 between
Enron and Shell (the "Participation Agreement"). Enron asserts that it is being
denied its right to participate in certain drilling projects allegedly included
under the Participation Agreement, including interests in wells drilled in the
Weeks Island Field. The properties in dispute, which we acquired from Shell in
the Shell Transactions on June 30, 1998, are exploration projects identified in
the Participation Agreement. The Participation Agreement includes the Weeks
Island Field only with respect to "deeper pool tests in the lower Miocene
Sands." To date, the only wells we have drilled in the Weeks Island Field under
the Participation Agreement were in the upper Miocene sands and not the lower
Miocene sands. In response to Enron's claims, we filed an action against Enron
in the 31st Judicial District for the Parish of Jefferson Davis,
-17-
Louisiana seeking injunctive relief from Enron's interference with our rights to
operate our wells and properties located in Louisiana that we purchased and
contracted with Shell to own and operate. Additionally, we asserted that the
matter should be addressed and resolved by the Louisiana Commissioner of
Conservation. We subsequently entered into a stipulation with Enron whereby
Enron agreed not to contest us on the wells being drilled at that time, of which
three are currently in operation in the Thornwell Field, that Guidry 21-1,
Guidry 16-1 and Lacassine #33-3.
The properties covered by the Participation Agreement are owned by us, with
record title in our subsidiary, Louisiana Onshore Properties Inc., which we
acquired from Shell in the Shell Transactions. Subject to certain agreed upon
limitations, Enron, Shell and the Company have consented to submit this dispute
to arbitration. Enron has appointed an arbitrator and Shell and the Company have
together appointed a second arbitrator, and a third arbitrator is expected to be
selected by the two appointed arbitrators by the end of the second quarter of
1999. After the arbitrators have been selected, a schedule will be created for
the arbitration of disputes between Enron on one hand and Shell and us on the
other hand.
We are vigorously defending against Enron's claims and have reserved all of our
rights for reimbursement against Shell if Enron's claims are successful. We
believe that we are entitled to operate the referenced Louisiana properties and
that Enron is not entitled to any of our interest in wells that have been
drilled in the Weeks Island Field. However, in the event of an adverse
determination resulting in a monetary judgment or property losses as a result of
Enron's claims, we believe that we are entitled to indemnification or
reimbursement from Shell under the agreements governing the Shell Transactions
and have other rights and actions under common law and state and federal
securities laws, and we have informed Shell that we will pursue all available
courses of action in this regard in the event of an adverse determination.
Absent Shell's failure to timely honor its indemnity obligations, we currently
do not believe the dispute with Enron will have a material adverse effect on our
financial condition or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of our security holders during the fourth
quarter of 1998.
-18-
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Company's 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
---- ---
1998:
First quarter............................. 9 9/16 7 3/16
Second quarter............................ 9 7/16 6 1/8
Third quarter............................. 7 1/4 2 3/4
Fourth quarter ........................... 5 1/2 2
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
The closing sale price of the common stock on March 18, 1999, as reported on the
New York Stock Exchange Composite Tape, was $3.00. As of March 18, 1999, we have
approximately 983 shareholders of record.
We have not paid cash dividends on the common stock and do not intend to pay
cash dividends on the common stock in the foreseeable future. We currently
intend to retain our cash for the continued development of our business,
including exploratory and development drilling activities. We also are currently
restricted under our Chase Manhattan Bank Credit Agreement from expending more
than $2.0 million in the aggregate for cash dividends on the common stock or for
purchase of shares of common stock without the prior consent of the lender.
-19-
ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with our Consolidated Financial
Statements and related notes thereto included elsewhere in this report.
YEAR ENDED DECEMBER 31,
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(In thousands, except per share data)
A. SUMMARY OF OPERATING DATA
Production:
Oil (MBbl) .................... 2,365 914 751 650 163
Natural gas (MMcf) ............ 20,603 14,603 15,783 14,598 7,116
Natural gas equivalent (MMCFE) 34,793 20,087 20,289 18,498 8,094
Average Prices:
Oil ($/Bbl) ................... $ 12.19 $ 19.72 $ 21.92 $ 18.04 $ 15.14
Natural gas ($/Mcf) ........... $ 2.16 $ 2.70 $ 2.44 $ 1.71 $ 2.01
Natural gas equivalent ($/MCFE) $ 2.11 $ 2.86 $ 2.71 $ 1.99 $ 2.07
B. SUMMARY OF OPERATIONS
Total revenues ...................... $ 74,026 $ 58,333 $ 56,733 $ 38,230 $ 17,752
Depletion and depreciation .......... $ 45,390 $ 26,337 $ 25,342 $ 18,491 $ 7,788
Net income (loss)(1) ................ ($230,708) ($ 28,541) $ 16,692 $ 7,458 $ 1,661
Net income (loss) per share:(1)
Basic ......................... ($ 5.80) ($ .85) $ .50 $ .25 $ .07
Diluted ....................... ($ 5.80) ($ .85) $ .47 $ .23 $ .06
Dividends per:
Common share .................. -- -- -- -- --
Preferred share ............... $ 0.68 -- -- -- --
Weighted average common
shares outstanding ............ 39,774 33,383 33,399 30,207 24,485
C. SUMMARY BALANCE SHEET DATA
Total assets ........................ $ 445,175 $ 292,558 $ 245,757 $ 193,134 $ 126,124
Long-term obligations, inclusive
of current maturities ......... $ 240,084 $ 107,195 $ 42,000 $ 15,500 $ 23,500
Stockholders' equity ................ $ 148,808 $ 145,102 $ 171,432 $ 154,924 $ 93,685
(1) Applicable to common stockholders.
-20-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
SHELL TRANSACTIONS. On June 30, 1998, we acquired (the "LOPI Transaction")
Louisiana Onshore Properties Inc. ("LOPI"), an indirect subsidiary of Shell Oil
Company ("Shell"), pursuant to a merger of a wholly-owned subsidiary with LOPI.
The consideration paid in the LOPI Transaction consisted of 12,082,030 shares of
our common stock, $.01 par value ("Common Stock"), and a new issue of
convertible preferred stock (the "Preferred Stock") that is convertible into
12,837,428 shares of Common Stock, which together provided Shell Louisiana
Onshore Properties Inc., an indirect subsidiary of Shell ("SLOPI"), with
beneficial ownership of 39.9% of our common stock on a fully-diluted basis
assuming the exercise of all outstanding stock options and warrants and
conversion of all preferred stock. In a transaction separate from the LOPI
Transaction, we also acquired on June 30, 1998 from Shell Western E&P Inc., an
indirect subsidiary of Shell ("SWEPI"), various other oil and gas property
interests located onshore in south Louisiana for a total cash consideration of
$38.6 million (the "SWEPI Acquisition").
The LOPI Transaction and the SWEPI Acquisition (together, the "Shell
Transactions") were effected to increase our reserves, lease acreage positions
and exploration prospects in Louisiana and are expected to substantially
increase our production and cash flow. The Shell Transactions were accounted for
utilizing the purchase method of accounting. Therefore, operations relating to
the Shell Properties are included in our results of operations beginning with
the third quarter of 1998. Revenues and production from the Shell properties
accounted for 46% of our total revenue and production during the second half of
1998.
CAIRN MERGER. On November 5, 1997, we consummated a merger (the "Cairn Merger")
with Cairn Energy USA, Inc. ("Cairn"). In connection with the Cairn Merger, we
issued approximately 19.0 million shares of Common Stock. The Cairn Merger more
than doubled our then-existing proved reserves and substantially increased our
production and cash flow. The Cairn Merger was accounted for as a pooling of
interests and our historical financial statements and operating results and the
discussion of such results in this Management's Discussion and Analysis of
Financial Condition and Results of Operations have been restated to reflect the
combined operations of the Company and Cairn for the periods presented. We
recorded a one-time charge in the fourth quarter of 1997 of approximately $10
million for costs associated with the Cairn Merger.
INDUSTRY CONDITIONS. Our 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 of our control. In this regard,
average worldwide oil and natural gas prices have decreased substantially from
levels existing during 1997. As a result of these declines, the price received
by us during the year ended December 31, 1998 was $2.11 per Mcfe compared to
$2.86 per Mcfe during the year ended December 31, 1997, which has negatively
impacted our revenues and cash flow during 1998. These industry conditions, and
any continuation thereof, will have several important consequences to us,
including decreasing the level of cash flow received from our producing
properties, delaying the timing of exploration of certain prospects and reducing
our access to capital markets, which could adversely affect our revenues,
profitability and ability to maintain or increase its exploration and
development program.
CEILING WRITE-DOWN. A significant decline in oil and natural gas prices
primarily caused us to recognize $245.0 million of non-cash write-downs of our
oil and natural gas properties under the full cost method of accounting during
1998, including $48.9 million during the fourth quarter. Due to the substantial
recent
-21-
volatility in oil and gas prices and their effect on the carrying value of our
proved oil and gas reserves, there can be no assurance that future write-downs
will not be required as a result of factors that may negatively affect the
present value of proved oil and natural gas reserves and the carrying value of
oil and natural gas properties, including volatile oil and natural gas prices,
downward revisions in estimated proved oil and natural gas reserve quantities
and unsuccessful drilling activities.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
OPERATING REVENUES AND PRODUCTION.
During 1998 production increased 73% on a natural gas equivalent basis.
Increased production was a direct result of the addition of the Shell properties
at June 30, 1998, as well as, offshore platforms and new wells brought online in
1998. The following table summarizes our operating revenues, production volumes
and average sales prices for the years ended December 31, 1998 and 1997.
Year Ended Percentage
December 31, Increase
1998 1997 (DECREASE)
---- ---- ----------
Production
Natural Gas (MMcf) ..................... 20,603 14,603 41%
Oil (MBbls) ............................ 2,365 914 159%
MMCFE .................................. 34,793 20,087 73%
Average Sales Price:
Natural Gas ($/Mcf) .................... $ 2.16 $ 2.70 (20%)
Oil ($/Bbl) ............................ $ 12.19 $ 19.72 (38%)
MCFE ($/Mcf) ........................... $ 2.11 $ 2.86 (26%)
Gross Revenues (000's)
Natural Gas ............................ $44,425 $39,398 13%
Oil .................................... 28,827 18,021 60%
Pipeline ............................... 84 221 (62%)
------- ------- -------
Total: ..... $73,336 $57,640 27%
======= ======= =======
OPERATING EXPENSES.
Oil and natural gas operating expenses increased $7.1 million to $12.8 million
in 1998, compared to $5.7 million in 1997. The increase was primarily due to
added operating expenses related to the inclusion of costs and expenses from the
Shell properties as well as new wells brought on production in the last twelve
months. On a MCFE basis lease operating expenses increased 32% in 1998 to $.37
from $.28 in 1997. This increase was primarily attributable to the fact that
operating costs for the more mature fields acquired from Shell are higher than
those of our existing properties with higher per well flow rates. The Company
continues to implement plans to reduce the operating costs associated with the
Shell properties.
SEVERANCE AND AD VALOREM TAXES.
Severance and ad valorem taxes increased $1.9 million to $4.1 million in 1998,
compared to $2.2 million in 1997. This increase is largely attributed to the
additional production as a result of the purchase of the Shell properties, which
are located entirely onshore south Louisiana and subject to state severance
taxes.
-22-
DEPLETION AND DEPRECIATION.
Depletion and depreciation expenses increased $19.1 million to $45.4 million in
1998, compared to $26.3 million in 1997. The increase is primarily due to the
significant production increase of 73% over 1997.
INTEREST AND OTHER INCOME.
Interest and other income remained flat at $.7 million for 1998 as compared to
$.7 million for 1997.
GENERAL AND ADMINISTRATIVE EXPENSE.
General and administrative expenses increased $2.4 million to $9.6 million in
1998, compared to $7.2 million in 1997. This increase was primarily a result of
increases in salaries and wages and related employee costs associated with our
expanded exploration and production activities associated with the Shell and
Cairn transactions.
INTEREST EXPENSE.
Interest expense increased $8.1 million to $13.2 million in 1998 compared to
$5.1 million in 1997. The increase is a combination of borrowings of
approximately $37 million utilized to fund the purchase of certain properties in
the Shell Transactions and continued borrowings to fund our exploration and
development program during 1998.
IMPAIRMENT OF LONG-LIVED ASSETS.
As previously described, we recorded write-downs of $245 million relating to our
oil and gas properties due to significant decreases in oil and natural gas
prices during 1998.
INCOME TAX EXPENSE
The Company recognized a $28.1 million deferred income tax benefit in 1998
associated with the reduction in the difference between book and income tax
bases, principally due to the previously described oil and gas property
write-downs.
-23-
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
OPERATING REVENUES AND PRODUCTION.
During 1997, production remained relatively flat compared to 1996. Although we
experienced production increases during 1997 attributable to the continuing
increase in exploration and development activities by us and the addition of 10
new producing wells, those increases were offset by normal declines in oil and
natural gas production from older wells as well as a significant decline in
production from wells in the Southwest Holmwood Field in Louisiana during the
third quarter of 1997 due to poor production performance from the wells in this
field as well as the elimination of production from these wells during the
fourth quarter of 1997 as a result of the Amoco litigation. In addition, during
the fourth quarter of 1997, production from certain offshore wells was
temporarily interrupted due to a ruptured pipeline. The following table
summarizes our operating revenues, production volumes and average sales prices
for the years ended December 31, 1997 and 1996.
Year Ended Percentage
December 31, Increase
1997 1996 (DECREASE)
---- ---- ----------
Production
Natural Gas (MMcf) ............... 14,603 15,783 (7%)
Oil (MBbls) ...................... 914 751 22%
MMCFE ............................ 20,087 20,289 (1%)
Average Sales Price:
Natural Gas ($/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 $1.0 million to $5.7 million in
1997, compared to $4.7 million 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 us 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 $.5 million to $2.2 million in 1997,
compared to $1.7 million 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.
-24-
DEPLETION AND DEPRECIATION.
Depletion and depreciation expense increased $1.0 million to $26.3 million in
1997, compared to $25.3 million 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 $.9 million to $.7 million for 1997 as
compared to $1.6 million for 1996. The decrease was due primarily to decreases
in cash balances.
GENERAL AND ADMINISTRATIVE EXPENSE.
General and administrative expenses increased $1.4 million to $7.2 million in
1997, compared to $5.8 million in 1996. This increase was primarily due to
increases in salaries and wages and related employee costs associated with our
expanded exploration and overall growth activities.
INTEREST EXPENSE.
Interest expense increased $2.5 million to $5.1 million in 1997 compared to $2.6
million in 1996. This increase was primarily due to increased borrowings under
our credit facility to finance our on-going exploration and development
activities.
IMPAIRMENT OF LONG-LIVED ASSETS.
We recorded a write-down of $24.1 million relating to our oil and gas properties
due to significant decreases in oil and natural gas prices during the fourth
quarter of 1997.
MERGER EXPENSES.
As previously described, we recorded a one-time charge of $10.0 million for
costs associated with the Cairn Merger.
LITIGATION EXPENSES.
As previously described, we recorded a charge of $6.2 million relating to the
Amoco litigation. See "Legal Proceedings."
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL. During 1998, our liquidity needs were met from cash from
operations and borrowings under our credit facilities. As of December 31, 1998,
we had a cash balance of $9.5 million and negative working capital of $2.1
million. The increase in both the cash balance and working capital from levels
existing at December 31, 1997, reflects refinancing of the Credit Facility to
the $250.0 million borrowing base supported by reserve additions from the
Company's exploration activities coupled with our increased operating cash flows
resulting from the Shell Transactions.
AMENDED CREDIT FACILITY. In May 1998, we amended and restated our credit
facility with The Chase Manhattan Bank as Administrative Agent (the "Credit
Facility") to provide for maximum borrowings, subject to borrowing base
limitations, of up to $250 million. In November 1998, we amended the Credit
Facility to increase the then-existing borrowing base from $200 million to $250
million. The borrowing base currently set at $250 million is scheduled to be
redetermined on March 31, 1999. In addition to regularly scheduled semi-annual
borrowing base redeterminations, the lenders under the Credit Facility have the
right to redetermine the borrowing base at any time once during each calendar
year and we have the right to obtain a redetermination by the banks of the
borrowing base once during each calendar year. Borrowings under the
-25-
Credit Facility are secured by pledges of the outstanding capital stock of our
material subsidiaries and a mortgage of all of the Company's offshore oil and
natural gas properties and several onshore oil and natural gas properties. In
the event of a default, we are obligated to pledge additional properties
representing, in the aggregate, at least 75% of our present value of proved
properties. The Credit Facility contains various restrictive covenants,
including, among other things, maintenance of certain financial ratios and
restrictions on cash dividends on the Common Stock. Borrowings under the Credit
Facility mature on May 22, 2003.
Under the Credit Facility, as amended, we may secure either (i) an alternative
base rate loan that bears interest at a rate per annum equal to the greatest of
the administrative agent's prime rate, a certificate of deposit based rate or
federal funds based rate plus 0% to 1.5% or (ii) a Eurodollar base rate loan
that bears interest, generally, at a rate per annum equal to the London
interbank offered rate plus 1.0% to 2.5%, depending on our ratio of the
aggregate outstanding loans and letters of credit to the borrowing base. The
Credit Facility also provides for commitment fees ranging from .3% to .5% per
annum, a 2.5% one time drawdown fee on first time borrowings in excess of $200
million, and certain closing fees aggregating $2.5 million paid in November 1998
in connection with the increase in the borrowing base. At March 18, 1999, we had
outstanding borrowings of $250 million under the Credit Facility. Based upon the
fact that drilling results have resulted in significant increases in proved
reserves and the fact that oil and gas prices have remained relatively flat, we
currently do not believe that our borrowing base under the Credit Facility will
be reduced from its current $250 million level as a result of the
redetermination that will take place effective as of March 31, 1999. However,
the lenders under the Credit Facility have not yet completed their review of the
borrowing base and have made no formal determination as to the borrowing base
level, and there can be no assurance that a reduction will not occur. Any
reduction in the borrowing base by the lenders could cause us to delay planned
capital expenditures and drilling projects or possibly result in us being
required to repay borrowed amounts exceeding the borrowing base.
CAPITAL EXPENDITURES. Capital expenditures (excluding the Shell Transactions)
during 1998 consisted of $107.5 million for property and equipment additions
related to exploration and development of various prospects (including leases),
seismic data acquisitions, and drilling and completion costs. We currently
expect capital expenditures for 1999 to be approximately $60 million and
anticipate that such capital expenditures will be funded from cash flows from
our producing properties and borrowings under the Credit Facility. Availability
of capital to fund our 1999 exploration and development program will depend upon
the success of our drilling program and the nature and extent of capital
expenditures required for development of discoveries. In this regard, we
anticipate that based on our current product price and production forecast,
internal cash flow and borrowings permitted under the Credit Facility should
fully fund our 1999 capital expenditure program as currently anticipated.
DIVIDENDS. It is our policy to retain existing cash for reinvestment in our
business, and therefore, we do not anticipate that we will pay dividends with
respect to the Common Stock in the foreseeable future. The Preferred Stock
issued upon closing of the LOPI Transaction accrues a quarterly cash dividend of
4% of its stated value with the dividend ceasing to accrue incrementally on
one-third of the shares of Preferred Stock on June 30, 2001, 2002 and 2003 so
that no dividends will accrue on any shares of Preferred Stock after June 30,
2003. Dividends on the Preferred Stock aggregating $2.7 million were accrued or
paid during 1998.
STOCK RIGHTS AND RESTRICTIONS AGREEMENT. In light of the large ownership
position issued to SLOPI in the LOPI Transaction and in recognition of both our
and SLOPI's desire that the Company function as an independent oil and gas
company, we entered into a Stock Rights and Restrictions Agreement with SLOPI
that defines and limits SLOPI's and our respective rights and obligations. These
agreements limit SLOPI's and its affiliates' control while protecting their
interests in the context of certain extraordinary transactions by (i) allowing
SLOPI to maintain representation on our Board of Directors, (ii) restricting
SLOPI's and its affiliates' ability to effect certain business combinations with
us or to propose certain business combinations with us, (iii) restricting the
ability of SLOPI and its affiliates to sell certain portions of their shares of
Common Stock and Preferred Stock, subject to certain exceptions designed to
permit them to sell such shares over time and to sell such shares in the event
of certain business combinations involving us, (iv) limiting SLOPI's and its
affiliates' discretionary voting rights to 23% of the total voting shares,
except with respect
-26-
to certain extraordinary events and in situations in which the price of the
Common Stock for a period of time has been less than $5.50 per share or we are
in material breach of our obligations under the agreements governing the LOPI
Transaction, (v) permitting SLOPI and its affiliates to purchase additional of
our securities in order to maintain a 21% beneficial ownership interest of the
Common Stock if we propose to issue additional shares of Common Stock or
securities convertible into Common Stock, (vi) extending certain statutory and
corporate restrictions on business combinations applicable to SLOPI and its
affiliates and (vii) obligating us, at our option, to issue a currently
indeterminable number of additional shares of Common Stock in the future, or pay
cash, in satisfaction of a make-whole provision contained in the Stock Rights
and Restrictions Agreement in the event SLOPI receives less than approximately
$10.52 per share on the sale of any Common Stock that is issuable upon
conversion of the Preferred Stock. SLOPI currently is restricted from selling
shares of Common Stock owned by it until June 30, 2000. Beginning on June 30,
2000, SLOPI may sell 25% of the Common Stock owned by it and may sell an
incremental 25% of the Common Stock owned by it each year until June 30, 2003,
at which time it is free to sell all Common Stock owned by it. In the event
SLOPI sold all Common Stock issued on conversion of the Preferred Stock at the
market prices existing on March 18, 1999, our make-whole obligation would be
approximately $96.5 million, which we may satisfy at our option in cash or
Common Stock, which could significantly dilute all holders of our Common Stock
other than Shell, or significantly reduce our ability to raise additional funds
for exploration and development.
YEAR 2000
We are currently conducting a company-wide Year 2000 readiness program ("Y2K
Program"). The Y2K Program is addressing the issue of computer programs and
embedded computer chips being unable to distinguish between the year 1900 and
the year 2000. Therefore, some computer hardware and software will need to be
modified prior to the year 2000 to remain functional. We anticipate that our
Year 2000 compliance will be substantially complete by May 1999.
Our Y2K Program is divided into three major categories: (i) internal information
and accounting ("IT") systems, (ii) non-"IT" equipment and systems and (iii)
third-party suppliers and customers. The general stages of review with respect
to each of the categories are (a) identifying and assessing items or systems
that are not Year 2000 compliant, (b) assessing costs and expenses associated
with the various alternatives for remedying items and systems that are not Year
2000 compliant and (c) repairing or replacing items that are determined not to
be Year 2000 compliant.
We are in varying stages of review with respect to each category within our Y2K
Program. We have completed our review of our IT equipment and systems and
currently believe that our internal information and accounting systems are Year
2000 compliant, except for certain field software that we currently do not
believe are material to our operations. We currently are reviewing various
alternatives for making such field software Year 2000 compliant, and believe the
costs associated therewith will not be material.
We currently are in the process of reviewing our non-IT equipment and systems.
We do not believe such equipment and systems will present any material Year 2000
issues. At present, we have not identified any non-IT equipment and systems that
are not Year 2000 compliant that cannot be remedied or replaced at minimal cost
to us.
We have begun our assessment of third party Year 2000 issues during the first
quarter of 1999. Our third party review initially consists of written inquiries
to third party suppliers, subcontractors and customers requesting information
and representations from such third parties as to their readiness for the Year
2000. We are in the process of circulating these responses and, based upon such
responses, will determine the necessity for requesting additional information as
appropriate. We expect our initial review of third parties to be substantially
complete during the second quarter of 1999. We believe we have alternative
suppliers and product customers to mitigate material exposure if certain of our
current suppliers and customers are determined not to be Year 2000 ready.
-27-
Management believes that it has taken reasonable steps in developing its Y2K
Program. Notwithstanding these actions, there can be no assurance that all of
our Year 2000 issues or those of our key suppliers, subcontractors or customers
will be resolved or addressed satisfactorily before the Year 2000 commences. If
our key suppliers, subcontractors, customers and other third parties fail to
address their Year 2000 issues, and there are no alternatives available to us,
then our usual channels of supply and distribution could be disrupted, in which
event we could experience a material adverse impact on its business, results of
operations or financial position. In addition, although we believe our internal
planning efforts are adequate to address our internal Year 2000 concerns, there
can be no assurances that we will not experience unanticipated negative
consequences and material costs caused by undetected errors or defects in the
technology used in its internal systems, which could have material adverse
effect on our business, results of operations or financial condition. We
currently are unable to estimate the most reasonably likely worst-case effects
of the arrival of the year 2000 and currently do not have a contingency plan in
place for any such unanticipated negative effects. We intend to analyze
reasonably likely worst-case scenarios and the need for such contingency
planning once our review of third-party preparedness described above has been
completed, and we expect to complete this analysis by September 30, 1999.
It is anticipated that the total costs related to the Year 2000 issue will not
exceed $250,000. The majority of which will be incurred by us in 1999. To date,
there have been no material deferments of other IT projects resulting from the
work taking place on our Y2K Program.
FORWARD-LOOKING INFORMATION
From time to time, we may make certain statements that contain "forward-looking"
information as defined in the Private Securities Litigation Reform Act of 1995
and that involves risk and uncertainty. These forward-looking statements may
include, but are not limited to, exploration and seismic acquisition plans,
anticipated results from current and future exploration prospects, the
anticipated results of wells based on logging data and production tests, future
sales of production, earnings, margins, production levels and costs, market
trends in the oil and natural gas industry and the exploration and development
sector thereof, environmental and other expenditures and various business
trends. Forward-looking statements may be made by management orally or in
writing including, but not limited to, the Management's Discussion and Analysis
of Financial Condition and Results of Operations section and other sections of
our filings with the Securities and Exchange Commission under the Securities Act
of 1933, as amended, and the Securities Exchange Act of 1934, as amended.
Actual results and trends in the future may differ materially depending on a
variety of factors including, but not limited to, the success of our exploration
and development program; changes in the price of oil and natural gas, which
could cause us to delay or suspend planned drilling operations or reduce
production levels; risks relating to the availability of capital to fund
drilling operations and our current estimates of our need for additional
capital, which can be adversely affected by adverse drilling results, production
declines, declines in oil and gas prices and declines in the overall economy;
world-wide political stability and economic growth; our successful execution of
internal exploration, development and operating plans; risks inherent in the
drilling of oil and natural gas wells, including risks of fire, explosion,
blowout, pipe failure, casing collapse, unusual or unexpected formation
pressures, unusual or unexpected weather conditions; litigation and disputes in
the ordinary course of business; environmental hazards and other operating and
production risks, which may temporarily or permanently reduce production or
cause initial production or test results to not be indicative of future well
performance or delay in timing of sales or completion of drilling operations;
environmental regulation and costs; regulatory uncertainties and legal
proceedings. The risks related to the year 2000, and the dates on which we
believe our Y2K Program will be completed, are based on management's best
estimates, which were derived utilizing numerous assumptions of future events,
including the continued availability of certain resources, third-party
modification plans and other factors. However, there can be no guarantee that
these estimates will be achieved, or that there will not be a delay in, or
increased costs associated with, the implementation of our Y2K Program. Specific
factors that might cause differences between the estimates and actual results
include, but are not limited to, the availability and cost of personnel trained
in these areas, the ability to locate and correct all relevant computer codes,
timely
-28-
responses to and corrections by third parties and suppliers, the ability to
implement interfaces between the new systems and the systems not being replaced,
and similar uncertainties. Due to the general uncertainty inherent in the Year
2000 problem, resulting in part from the uncertainty of the Year 2000 readiness
of third parties and the interconnection of global businesses, we cannot ensure
our ability to timely and cost effectively resolve problems associated with the
Year 2000 issue that may affect our operations and business or expose us to
third-party liability.
-29-
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.
-30-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
-----------------------------
PAGE
----
Report of Independent Auditors........................................... 32
Consolidated Statements of Operations
-- For each of the three years in the period ended December 31, 1998... 33
Consolidated Balance Sheets--December 31, 1998 and 1997.................. 34
Consolidated Statements of Cash Flows
-- For each of the three years in the period ended December 31, 1998... 36
Consolidated Statements of Changes in Stockholders' Equity
-- For each of the three years in the period ended December 31, 1998... 37
Notes to Consolidated Financial Statements............................... 38
Consolidated Supplemental Oil and Natural Gas Information (Unaudited).... 51
-31-
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, 1998 and 1997, and the
related consolidated statements of operations, stockholders' equity, and cash
flows for each of the three years in the period ended December 31, 1998. 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, 1998 and 1997,
and the consolidated results of their operations and their cash flows for each
of the three years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles.
ERNST & YOUNG LLP
March 17, 1999
Houston, Texas
-32-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
1998 1997 1996
--------- --------- ---------
(in thousands, except per share)
REVENUES:
Oil and natural gas .................. $ 73,336 $ 57,640 $ 55,123
Interest and other ................... 690 693 1,610
--------- --------- ---------
74,026 58,333 56,733
--------- --------- ---------
COSTS AND EXPENSES:
Oil and natural gas operating ........ 12,841 5,680 4,696
Severance and ad valorem taxes ....... 4,069 2,165 1,677
Depletion and depreciation ........... 45,390 26,337 25,342
General and administrative ........... 9,564 7,192 5,770
Interest ............................. 13,211 5,149 2,582
Impairment of long-lived assets ...... 245,011 24,141 --
Merger expenses ...................... -- 9,998 --
Litigation expenses and loss provision -- 6,205 --
--------- --------- ---------
330,086 86,867 40,067
--------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES .......... (256,060) (28,534) 16,666
INCOME TAX EXPENSE (BENEFIT) ............... (28,052) 7 (26)
--------- --------- ---------
NET INCOME (LOSS) .......................... ($228,008) ($ 28,541) $ 16,692
--------- --------- ---------
DIVIDEND REQUIREMENT ON PREFERRED STOCK .... ($ 2,700) -- --
========= ========= =========
NET INCOME (LOSS) APPLICABLE
TO COMMON STOCKHOLDERS ............... ($230,708) ($ 28,541) $ 16,692
========= ========= =========
NET INCOME (LOSS) PER SHARE:
Basic ................................ ($ 5.80) ($ 0.85) $ 0.50
========= ========= =========
Diluted .............................. ($ 5.80) ($ 0.85) $ 0.47
========= ========= =========
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES:
Outstanding .......................... 39,774 33,383 33,399
========= ========= =========
Assuming dilution .................... 39,774 33,383 35,484
========= ========= =========
See notes to consolidated financial statements.
-33-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
------------
1998 1997
--------- ---------
(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ................................. $ 9,478 $ 8,083
Accounts receivable ....................................... 32,558 10,920
Due from affiliates ....................................... 4,848 3,038
Prepaid expenses and other ................................ 1,394 1,130
--------- ---------
Total current assets ................................ 48,278 23,171
--------- ---------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including
$94,077,000 [1998] and $51,883,000 [1997] not
subject to depletion) ............................... 820,322 409,310
Land ...................................................... 478 478
Equipment ................................................. 6,775 4,618
--------- ---------
827,575 414,406
Accumulated depletion and depreciation .................... (436,120) (145,719)
--------- ---------
391,455 268,687
OTHER ASSETS, NET ......................................... 5,442 700
--------- ---------
$ 445,175 $ 292,558
========= =========
See notes to consolidated financial statements.
-34-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
DECEMBER 31,
------------
1998 1997
--------- ---------
(in thousands)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable .............................................................. $ 19,138 $ 7,735
Revenues and royalties payable ................................................ 6,500 5,991
Accrued liabilities ........................................................... 24,440 20,330
Current maturities of long-term debt .......................................... 84 110
--------- ---------
Total current liabilities ................................................ 50,162 34,166
--------- ---------
LONG-TERM DEBT ................................................................ 240,000 107,085
--------- ---------
COMMITMENTS AND CONTINGENCIES ................................................. -- --
LITIGATION LIABILITIES ........................................................ 6,205 6,205
--------- ---------
STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value (25,000,000 shares authorized 3,982,906 [1998]
and none [1997] shares of Series A
Cumulative Convertible Preferred Stock issued at stated value) ........... 135,000 --
Common stock, $0.01 par value (200,000,000 shares
authorized, 45,817,319 [1998] and 33,481,261 [1997]
issued) .................................................................. 461 336
Additional paid-in capital .................................................... 270,477 172,023
Accumulated deficit ........................................................... (256,814) (26,106)
Unamortized deferred compensation ............................................. (293) (309)
--------- ---------
148,831 145,944
Treasury stock, at cost (1,275 [1998] and 46,792 [1997] shares) ............... (23) (842)
--------- ---------
Total stockholders' equity ............................................... 148,808 145,102
--------- ---------
$ 445,175 $ 292,558
========= =========
See notes to consolidated financial statements.
-35-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997 1996
--------- --------- ---------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) .................................. ($228,008) ($ 28,541) $ 16,692
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depletion and depreciation ..................... 45,390 26,337 25,342
Amortization of other assets ................... 345 671 519
Non-cash compensation .......................... 1,948 1,815 719
Impairment of long-lived assets ................ 245,011 24,141 --
Deferred income taxes .......................... (28,052) -- --
Litigation expenses and loss provision ......... -- 6,205 --
Changes in assets and liabilities:
Accounts receivable ............................ (21,638) 1,100 (6,605)
Due from affiliates ............................ (1,810) (2,181) 314
Accounts payable ............................... 11,403 (2,793) 2,515
Revenues and royalties payable ................. 509 461 2,164
Accrued liabilities and other .................. (7,524) 5,930 (228)
--------- --------- ---------
Net cash provided by operating activities ............ 17,574 33,145 41,432
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment ................ (108,947) (114,311) (83,350)
Acquisition of oil and natural gas properties ...... (37,078) -- --
Proceeds from sale of oil and natural gas properties 2,045 -- 502
--------- --------- ---------
Net cash used in investing activities ................ (143,980) (114,311) (82,848)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt ....................... 143,000 156,234 26,500
Reductions in long-term debt ....................... (10,111) (91,039) --
Preferred dividends ................................ (1,350) -- --
Exercise of stock options .......................... 1,293 396 177
Additions to deferred loan costs ................... (5,031) (47) (767)
--------- --------- ---------
Net cash provided by financing activities ............ 127,801 65,544 25,910
--------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS .............. 1,395 (15,622) (15,506)
CASH AND CASH EQUIVALENTS
AT BEGINNING OF YEAR ............................... 8,083 23,705 39,211
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF YEAR ............. $ 9,478 $ 8,083 $ 23,705
========= ========= =========
See notes to consolidated financial statements.
-36-
THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
(in thousands)
Additional Accumulated
PREFERRED STOCK COMMON STOCK Paid-In Earnings
----------------------- ------------------
SHARES PAR VALUE SHARES PAR VALUE CAPITAL (DEFICIT)
------ --------- ------ --------- ------- ---------
Balance, December 31, 1995 ....................... -- -- 33,384 $ 334 $ 168,847 ($ 14,257)
Exercise of stock options ............... -- -- 25 -- 177 --
Issuance of rights to common stock ...... -- -- -- -- 910 --
Compensation expense .................... -- -- -- -- -- --
Treasury shares acquired ................ -- -- -- -- -- --
Company's 401(k) plan contribution ...... -- -- 13 -- 152 --
Net income .............................. -- -- -- -- -- 16,692
--------- --------- --------- --------- --------- ---------
Balance, December 31, 1996 ....................... -- -- 33,422 334 170,086 2,435
Exercise of stock options ............... -- -- 55 1 395 --
Company's 401(k) plan contribution ...... -- -- 4 -- (57) --
Issuance of rights to common stock ...... -- -- -- 1 1,599 --
Compensation expense .................... -- -- -- -- -- --
Net loss ................................ -- -- -- -- -- (28,541)
--------- --------- --------- ---------
Balance, December 31, 1997 ....................... -- -- 33,481 336 172,023 (26,106)
Exercise of stock options ............... -- -- 254 3 1,290 --
Company's 401(k) plan contribution ...... -- -- -- -- (487) --
Issuance of rights to common stock ...... -- -- -- 1 1,599 --
Compensation expense .................... -- -- -- -- -- --
Issuance of Shares for Shell Transaction:
Preferred Stock ...................... 3,983 $ 135,000 -- -- -- --
Common Stock ......................... -- -- 12,082 121 96,052 --
Preferred dividends ..................... -- -- -- -- -- (2,700)
Net loss ................................ -- -- -- -- -- (228,008)
--------- --------- --------- --------- --------- ---------
Balance, December 31, 1998 ....................... 3,983 $ 135,000 45,817 $ 461 $ 270,477 ($256,814)
========= ========= ========= ========= ========= =========
Unamortized
Deferred TREASURY STOCK
COMPENSATION SHARES COST TOTAL
------------ ------ ---- -----
Balance, December 31, 1995 ....................... -- -- -- $ 154,924
Exercise of stock options ............... -- -- -- 177
Issuance of rights to common stock ...... (910) -- -- --
Compensation expense .................... 567 -- -- 567
Treasury shares acquired ................ -- 60 (1,080) (1,080)
Company's 401(k) plan contribution ...... -- -- -- 152
Net income .............................. -- -- -- 16,692
--------- --------- --------- ---------
Balance, December 31, 1996 ....................... (343) 60 (1,080) 171,432
Exercise of stock options ............... -- -- -- 396
Company's 401(k) plan contribution ...... -- (13) 238 181
Issuance of rights to common stock ...... (1,600) -- -- --
Compensation expense .................... 1,634 -- -- 1,634
Net loss ................................ -- -- -- (28,541)
--------- --------- --------- ---------
Balance, December 31, 1997 ....................... (309) 47 (842) 145,102
Exercise of stock options ............... -- -- -- 1,293
Company's 401(k) plan contribution ...... -- (46) 819 332
Issuance of rights to common stock ...... (1,600) -- -- --
Compensation expense .................... 1,616 -- -- 1,616
Issuance of Shares for Shell Transaction:
Preferred Stock ...................... -- -- -- 135,000
Common Stock ......................... -- -- -- 96,173
Preferred dividends ..................... -- -- -- (2,700)
Net loss ................................ -- -- -- (228,008)
--------- --------- --------- ---------
Balance, December 31, 1998 ....................... ($ 293) 1 ($ 23) $ 148,808
========= ========= ========= =========
See notes to consolidated financial statements.
-37-
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. 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. The Company acquired in two separate transactions
certain Louisiana onshore properties from Shell Oil Company ("Shell") as
described in note 6 below. The Shell Transactions were accounted for as
purchases for financial accounting purposes.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF CONSOLIDATION
The consolidated financial statements reflect the accounts of the Company 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 costs associated with the acquisition, exploration and development of
oil and natural gas properties. 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. Costs
depleted include net capitalized costs subject to depletion and estimated future
dismantlement, restoration, and abandonment costs. Estimated future abandonment,
dismantlement and site restoration costs include costs to dismantle, relocate
and dispose of the Company's offshore production platforms, gathering systems,
wells and related structures. Such costs related to onshore properties, net of
estimated salvage values, are not expected to be significant. Equipment 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.
-38-
CONCENTRATIONS 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
The Company computes two earnings per share amounts - basic EPS and EPS assuming
dilution. Basic EPS 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.
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.
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.
3. IMPAIRMENT OF LONG-LIVED ASSETS
A significant decline in oil and natural gas prices during 1998 and 1997
primarily has caused the Company to recognize non-cash write-downs totaling
$245.0 million and $24.1 million, respectively, of its oil and natural gas
properties under the full cost method of accounting.
Due to the substantial recent volatility in oil and gas prices and their effect
on the carrying value of the Company's proved oil and gas reserves, there can be
no assurance that future write-downs will not be required as a result of factors
that may negatively affect the present value of proved oil and natural gas
reserves and the carrying value of oil and natural gas properties, including
volatile oil and natural gas prices, downward revisions in estimated proved oil
and natural gas reserve quantities and unsuccessful drilling activities.
-39-
4. LONG-TERM DEBT
In May 1998, we amended and restated our credit facility with The Chase
Manhattan Bank as Administrative Agent (the "Credit Facility") to provide for
maximum borrowings, subject to borrowing base limitations, of up to $250
million. In November 1998, we amended the Credit Facility to increase the
then-existing borrowing base from $200 million to $250 million. The borrowing
base currently set at $250 million is scheduled to be redetermined on March 31,
1999. In addition to the regularly scheduled semi-annual borrowing base
redeterminations, the lenders under the Credit Facility have the right to
redetermine the borrowing base at any time once during each calendar year and
the Company has the right to obtain a redetermination by the banks of the
borrowing base once during each calendar year. Borrowings under the Credit
Facility are secured by pledges of the outstanding capital stock of the
Company's material subsidiaries and a mortgage of all of the Company's offshore
oil and natural gas properties and several onshore oil and natural gas
properties. In the event of a default, the Company is obligated to pledge
additional properties representing, in the aggregate, at least 75% of the
Company's present value of proved properties. The Credit Facility contains
various restrictive covenants, including, among other things, maintenance of
certain financial ratios and restrictions on cash dividends on the Common Stock.
Borrowings under the Credit Facility mature on May 22, 2003.
Under the Credit Facility, as amended, the Company may secure either (i) an
alternative base rate loan that bears interest at a rate per annum equal to the
greatest of the administrative agent's prime rate, a certificate of deposit
based rate or federal funds based rate plus 0% to 1.5% or (ii) a Eurodollar base
rate loan that bears interest, generally, at a rate per annum equal to the
London interbank offered rate plus 1.0% to 2.5%, depending on the Company's
ratio of the aggregate outstanding loans and letters of credit to the borrowing
base. The Credit Facility also provides for commitment fees ranging from .3% to
.5% per annum, a 2.5% one time drawdown fee on first time borrowings in excess
of $200 million, and certain closing fees aggregating $2.5 million paid in
November 1998 in connection with the increase in the borrowing base. At December
31, 1998, the Company had outstanding borrowings of $240 million under the
Credit Facility.
5. COMMITMENTS AND CONTINGENCIES
LITIGATION
In June 1996, Amoco Production Company ("Amoco") filed suit against us in
Louisiana State Court in Calcasieu Parish with respect to a dispute involving
our drilling of the our Ben Todd No. 1 (TMRC) well in the Southwest Holmwood
Field in which we 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. We drilled the Ben Todd No. 1 (TMRC) well under a
participation agreement between us and Amoco pursuant to which Amoco had a right
to participate in the well. We drilled the well after providing notice to Amoco
pursuant to the participation agreement that we intended to drill the well and
that Amoco had failed to take action to elect to participate in the well. Prior
to drilling the well, our advisors informed us that the participation agreement
permitted us to drill the well because Amoco had refused to consent to drill the
well after we requested 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 participation agreement did not permit us to drill
the well and sought to recover all the revenues from the well or to stop us from
producing from the well. Amoco requested that the trial court cancel the
participation agreement and our leasehold interest in the prospect, which
included our 50% interest in the Ben Todd No. 2 (Amoco) well that Amoco drilled
prior to the Ben Todd No. 1 (TMRC) well on an agreed basis. We filed a
counterclaim for breach of contract, unfair practices and other claims.
On December 22, 1997, the United States District Court for the Western District
of Louisiana entered a judgment against us in this matter and ordered that the
participation agreement did not permit us to drill the
-40-
Ben Todd No. 1 (TMRC) well and that the participation agreement and related
lease had been terminated by virtue of our drilling the well. The trial court
also dismissed our counterclaims against Amoco. The trial court further ordered
a reversion of our rights to the Ben Todd No. 1 (TMRC) and the Ben Todd No. 2
(Amoco) and directed us to account for all production and monies we received
from the date of the cancellation of the lease. We recorded a charge of $6.2
million in the fourth quarter of 1997, representing our 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. We do not
expect any material additional charges to be made with respect to this matter.
We have reported no reserves related to these properties as of December 31, 1997
or thereafter. We have filed an appeal relating to the decision of the trial
court in this litigation.
In November 1998, Enron Capital & Trade Resources Corp. ("Enron") filed an
action in the District Court of Harris County, Texas, 11th Judicial District,
Texas against us and certain Shell affiliates alleging causes of action against
us and Shell for trespass and tortious interference with contract and seeking
declaratory and injunctive relief. Enron asserts that our drilling and operation
of certain Louisiana oil and gas wells has and will trespass upon Enron's
Louisiana property interests and tortiously interfere with a Participation
Agreement dated June 12, 1996 between Enron and Shell (the "Participation
Agreement"). Enron asserts further that it is being denied its right to
participate in certain drilling projects allegedly included under the
Participation Agreement, including interests in wells drilled in the Weeks
Island Field. In response to Enron's claims, we filed an action against Enron in
the 31st Judicial District for the Parish of Jefferson Davis, Louisiana seeking
injunctive relief against Enron for interfering with our rights to operate and
asserting that the matter should be addressed and resolved by the Louisiana
Commissioner of Conservation. We subsequently entered into a stipulation with
Enron whereby Enron agreed not to contest us on three wells drilled two of which
are currently in operation in the Thornwell Field, the Guidry 21-1, Guidry 16-1
and Lacassine #33-3.
The properties covered by the Participation Agreement are owned by us, with
record title in our subsidiary, Louisiana Onshore Properties Inc., which was
acquired from Shell in the Shell Transactions. Subject to certain agreed upon
limitations, Enron, Shell and the Company have consented to submit this dispute
to arbitration. Enron has appointed an arbitrator and Shell and the Company have
together appointed a second arbitrator, and a third arbitrator is expected to be
selected by the two appointed arbitrators by the end of the second quarter of
1999. After the arbitrators have been selected, a schedule will be created for
the arbitration of disputes between Enron on one hand and Shell and us on the
other hand.
We intend to vigorously defend against Enron's claims. We believe that we are
entitled to operate the referenced Louisiana properties and that Enron is not
entitled to any of our interest in wells that have been drilled in the Weeks
Island Field. However, in the event of an adverse determination resulting in a
monetary judgment or property losses as a result of Enron's claims, we believe
that we are entitled to indemnification or reimbursement from Shell under the
agreements governing the Shell Transactions as well as under common law and
state and federal securities laws, and we have informed Shell that we will
pursue all available courses of action in this regard in the event of an adverse
determination. Absent Shell's failure to timely honor its indemnity obligations,
we currently do not believe the dispute with Enron will have a material adverse
effect on our financial condition or results of operations.
6. SHELL TRANSACTIONS
On June 30, 1998, the Company acquired (the "LOPI Transaction") Louisiana
Onshore Properties Inc. ("LOPI"), an indirect subsidiary of Shell Oil Company
("Shell"), pursuant to a merger of a wholly-owned subsidiary of the Company with
LOPI. The consideration paid in the LOPI Transaction consisted of 12,082,030
shares of the Company's common stock, $.01 par value ("Common Stock"), and a new
issue of convertible preferred stock of the Company (the "Preferred Stock") that
is convertible into 12,837,428 shares of Common Stock, which together provided
Shell Louisiana Onshore Properties Inc., an indirect subsidiary of Shell
("SLOPI"), with beneficial ownership of 39.9% of the outstanding shares of
Common Stock as of the closing of the LOPI Transaction, assuming exercise of all
outstanding options and warrants and the conversion of the Preferred Stock. In a
transaction separate from the LOPI Transaction, the Company also acquired on
June 30, 1998 from Shell Western E&P, Inc., an indirect subsidiary
-41-
of Shell, various other oil and gas property interests located
onshore in south Louisiana for a total cash consideration of $38.6 million
(together with the LOPI Transaction, the "Shell Transactions"). The combined
purchase price of $303.5 million, including related deferred tax liability of
$28 million, was allocated to oil and gas properties, including $37 million of
unevaluated costs.
The following summarized unaudited proforma financial information assumes the
Shell Transactions occurred on January 1 of each year:
PROFORMA INFORMATION YEAR ENDED DECEMBER 31,
1998 1997
(in thousands, except per share data)
Revenues ............................. $ 105,703 $ 159,361
Net loss ............................. ($211,683) ($ 50,618)
Net loss per share ................... ($ 4.63) ($ 1.23)
The pro forma results do not necessarily represent results that would have
occurred if the transaction had taken place on the basis assumed above, nor are
they indicative of the results of future combined operations.
7. INCOME TAXES
Components of the provision (benefit) for Federal and State income taxes are as
follows:
YEAR ENDED DECEMBER 31,
--------------------------------------------
1998 1997 1996
-------- -------- --------
(in thousands)
Current .................. -- $ 7 ($ 26)
Deferred ................. (28,052) -- --
-------- -------- --------
($28,052) $ 7 ($ 26)
======== ======== ========
-42-
Income tax expense as reported is reconciled to the federal statutory rate (35%)
as follows:
YEAR ENDED DECEMBER 31,
1998 1997 1996
-------- -------- --------
(in thousands)
Income tax provision (benefit) computed at statutory rate ($89,621) ($ 9,987) $ 5,833
Nondeductible costs ..................................... 3,265 2,355 --
Decrease (increase) in percentage depletion carryover ... -- 18 (263)
Net operating loss carryforwards not benefited
in the income tax provision ....................... 39,836 -- --
Change in valuation allowance ........................... 18,328 7,597 (5,658)
Other ................................................... 140 24 62
-------- -------- --------
($28,052) $ 7 ($ 26)
======== ======== ========
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:
DECEMBER 31,
1998 1997
-------- --------
(in thousands)
Deferred tax assets:
Net operating tax loss carryforward ................. $ 55,430 $ 39,933
Statutory depletion carryforward .................... 950 950
Other ............................................... 3,596 3,202
Valuation allowance ................................. (27,082) (8,754)
-------- --------
Total deferred tax assets .............................. 32,894 35,331
-------- --------
Deferred tax liabilities:
Book in excess of tax basis in oil and gas properties 32,824 35,261
Basis differential in long-term investments ......... 70 70
-------- --------
Total deferred tax liabilities ......................... 32,894 35,331
-------- --------
Net deferred tax asset (liability) ..................... -- --
======== ========
As of December 31, 1998, the Company has approximately $158.4 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.
-43-
8. STOCKHOLDERS' EQUITY
PREFERRED STOCK
On June 30, 1998, the Company issued to Shell Louisiana Onshore Properties, Inc.
("SLOPI") 3,982,906 shares of the Company's Series A Preferred Stock, $1.00 par
value ("Preferred Stock"). The Preferred Stock has an aggregate stated value of
$135 million and ranks prior to the Common Stock as to distribution of assets
and payment of dividends. The Preferred Stock is entitled to receive, when and
as declared by the Board of Directors, a cash dividend at the rate of 4% per
annum on the stated value per share; provided, however, dividends shall cease to
accrue on an incremental one-third of the shares of Preferred Stock on the
third, fourth and fifth anniversaries of the LOPI Transaction so that no
dividends will accrue on any shares of Preferred Stock after June 30, 2003.
Each share of Preferred Stock is entitled to one vote on matters submitted to
the Company's shareholders for their approval. Until the earlier of (i) the
termination of a Stock Rights and Restrictions Agreement between SLOPI and the
Company (the "Stock Rights and Restrictions Agreement") and (ii) SLOPI and its
affiliates beneficially own less than 21% of the outstanding Common Stock, the
holders of the Preferred Stock may elect at least one member of the Company's
Board of Directors and additional members in the event the number of Board seats
is increased to ten or more so that SLOPI is able to nominate that number of
directors that equals the product (rounded downward to the nearest whole number,
but in no event less than one) of the total number of directors following such
election multiplied by 20%.
The Preferred Stock may be converted into an aggregate of 12,837,428 shares of
Common Stock at any time by the holder thereof. In addition, on or after June
30, 2001, the Preferred Stock will automatically convert into Common Stock in
the event the mean Per Share Market Value (as defined in the Certificate of
Designation) exceeds 150% of the conversion price, which is approximately $10.52
per share (the "Conversion Price"), for 75 consecutive trading days. In
addition, pursuant to the Stock Rights and Restrictions Agreement, SLOPI is
prohibited, subject to certain exceptions, from selling shares of Common Stock
issued upon conversion of Preferred Stock until June 30, 2000, at which time
SLOPI is permitted to sell approximately 25% of the Common Stock owned by it,
and an incremental 25% each year until June 30, 2003, at which time it will be
able to sell all shares of Common Stock owned by it.
Pursuant to the Stock Rights and Restrictions Agreement, when SLOPI sells shares
of Common Stock acquired upon conversion of the Preferred Stock at a share price
less than approximately $10.52, the Conversion Price, the Company has agreed to
pay to SLOPI the difference between the sale price and the Conversion Price,
which payment may be in cash or shares of Common Stock, at the option of the
Company.
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 affiliates of Messrs.
Reeves and Mayell. The acquired stock has been used to fund the Company's
contributions to the employees' 401(k) plan.
-44-
WARRANTS
The Company had the following warrants outstanding at December 31, 1998:
NUMBER OF EXERCISE
WARRANTS SHARES PRICE EXPIRATION DATE
-------- ------ ----- ---------------
Executive Officers ............ 1,428,000 $ 5.85 *
General Partner ............... 928,032 $ 0.20 December 31, 2015
* A date one year following the date on which the respective officer ceases
to be an employee of the Company.
On June 7, 1994, the shareholders of the Company approved a conversion of Class
"B" Warrants held by Joseph A. Reeves, Jr. and Michael J. Mayell, which entitled
each of them to purchase an aggregate of 714,000 shares of common stock, to
Executive Officer Warrants. The Warrants expire one year following the date on
which the respective officer ceases to be an employee of the Company. The
Warrants further provide that in the event the officer's employment with the
Company is terminated by the Company without "cause" or by the officer for "good
reason," the officer will have the option to require the Company to purchase
some or all of the Warrants held by the officer for an amount per Warrant equal
to the difference between the exercise price, $5.85 per share, and the then
prevailing market price of the common stock. The Company may satisfy this
obligation with shares of common stock.
-45-
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, 1998, 1997 and 1996, 74,425, 851,024 and 913,221 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, 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
Granted .............................. 3,229,550 3.37
Exercised ............................ (256,804) 5.04
Canceled ............................. (143,940) 11.40
--------- ------
Outstanding at December 31, 1998 ........ 4,900,993 $ 5.35
========= ======
Shares exercisable:
December 31, 1998 .................... 2,262,085 $ 6.97
December 31, 1997 .................... 1,621,025 $ 8.95
December 31, 1996 .................... 1,233,380 $ 7.45
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------------------- ----------------------------------------
WEIGHTED WEIGHTED
RANGE OF OUTSTANDING AT AVERAGE EXERCISABLE AT AVERAGE
EXERCISABLE PRICES DECEMBER 31, 1998 EXERCISE PRICE DECEMBER 31, 1998 EXERCISE PRICE
------------------ ----------------- -------------- ----------------- --------------
$1.13 - $4.88 3,387,050 $ 3.42 949,882 $ 3.54
$5.56 - $10.00 885,325 8.51 828,885 8.46
$10.38 - $16.38 628,618 11.30 483,318 11.14
----------- ----- ---------- -----
4,900,993 $ 5.35 2,262,085 $ 6.97
========= ======= ========= =======
The weighted average remaining contractual life of options outstanding at
December 31, 1998 was approximately eight years.
-46-
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 5.8%, 5.6% and 6.2%; dividend yield of
0%; volatility factors of the expected market price of the Company's common
stock of 0.59, 0.31 and 0.35 for 1998, 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 $1.89, $3.90 and $2.61 for options
granted in 1998, 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
1998, 1997 and 1996 income results in pro forma net income (loss) of ($232.5)
million, ($29.6) million and $15.7 million, respectively, and pro forma basic
net income (loss) per share of ($5.85), ($0.89) and $.47 ($.44 diluted),
respectively.
The Black-Scholes option valuation model was developed for use in estimating the
fair value of traded options which have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions including the expected stock price volatility. Because
the Company's employee stock options have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in management's
opinion, the existing models do not necessarily provide a reliable single
measure of the fair value of its employee stock options.
DEFERRED COMPENSATION
In July 1996, the Company through the Compensation Committee of the Board of
Directors 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,
$400,000 and $400,000 of their compensation for 1996, 1997 and 1998,
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, at December 31, 1996, for deferrals in 1997, at
December 31, 1997, for deferrals during the first half of 1998, and at June 30
1998 for deferrals during the second half of 1998. At December 31, 1998, the
plan had reserved 1,050,000 shares of common stock for future issuance and
371,034 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 $1,616,000, $1,634,000
and $567,000 for 1998, 1997 and 1996, respectively, relating to these grants is
reflected in general and administrative expense for the years ended December 31,
1998, 1997 and 1996, respectively.
9. PROFIT SHARING AND SAVINGS PLAN
The Company has a 401(k) profit sharing and savings plan (the "Plan") that
covers substantially all employees and entitles them to contribute up to 15% of
their annual compensation, subject to maximum limitations imposed by the
Internal Revenue Code. The Company matches 100% of each employee's contribution
up to 6.5% of annual compensation subject to certain limitations as outlined in
the Plan. In addition, the Company may make discretionary contributions which
are allocable to participants in accordance with the Plan.
-47-
10. OIL AND GAS HEDGING ACTIVITIES
During the year ended December 31, 1996, Cairn's oil and gas revenues were
reduced by $2,449,000 as a result of hedging transactions. As of December 31,
1998 and 1997, the Company had no material open hedging agreements.
11. MAJOR CUSTOMERS
Major customers for the years ended December 31, 1998, 1997 and 1996 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 1998 1997 1996
-------- ---------------- ----------------- -----------------
Tauber Oil Company..................................... 32% ----- -----
Equiva Trading Company(1).............................. 22% ----- -----
Coral Energy Resources(1).............................. 15% ----- -----
Phillips Petroleum Company............................. ----- 20% 22%
Coastal Corporation.................................... ----- 15% 21%
Koch Oil Company....................................... ----- 15% 12%
(1) Equiva Trading Company and Coral Energy Resources are both affiliates
of Shell Oil Company.
12. 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 $2,126,000, $2,315,000 and
$1,660,000 for the years ended December 31, 1998, 1997 and 1996, 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 $4,450,000 and $2,500,000 as of December 31, 1998 and 1997,
respectively, net of amounts owed to them from the Company. The Company has
executed extensions of the note agreements with TODD and Sydson dated December
31, 1997 related to the amounts due which mature on January 1, 2000 and accrue
interest at 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, 1998, 1997 and 1996 and received fees of
approximately $57,000, $27,000 and $56,000, 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 per month relating to
services provided to the Company personally by Mr. Messersmith. Mr. Messersmith
also participates in the plan described below pursuant to which he was paid
$22,600 during 1998.
-48-
In the interest of retaining talented technical personnel, the Company has
adopted an incentive compensation plan for its senior geologists, geophysicists,
consultants 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.
13. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings per
share:
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
---- ---- ----
(in thousands, except per share)
Numerator:
Net income (loss) applicable to common stockholders ($230,708) ($ 28,541) $ 16,692
Denominator:
Denominator for basic earnings per
share - weighted-average shares outstanding .... 39,774 33,383 33,399
Effect of potentially dilutive common shares:
Employee and director stock options ............... N/A N/A 650
Warrants .......................................... N/A N/A 1,435
Denominator for diluted earnings per
share - weighted-average shares
outstanding and assumed conversions ............ 39,774 33,383 35,484
========= ========= =========
Basic (loss) earnings per share ...................... ($ 5.80) ($ 0.85) $ 0.50
========= ========= =========
Diluted (loss) earnings per share .................... ($ 5.80) ($ 0.85) $ 0.47
========= ========= =========
14. SUPPLEMENTAL CASH FLOWS INFORMATION
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997 1996
---- ---- ----
(in thousands)
Cash Payments:
Interest .................................. $12,286 $ 3,866 $ 2,166
Income taxes .............................. -- $ 7 ($ 26)
Non-Cash Operating and Financing Activities:
Accounts receivable ....................... -- -- ($1,080)
Treasury stock (See Note 8) ............... -- -- $ 1,080
-49-
15. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following is a summary of the unaudited quarterly results of operations for
the years ended December 31, 1998 and 1997.
QUARTER ENDED
-------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31(2) TOTAL
---------- ---------- ---------- ---------- ---------
(in thousands, except per share amounts)
1998
----
Revenues ...................... $ 11,897 $ 11,742 $ 23,238 $ 27,149 $ 74,026
========== ========== ========== ========== =========
Results of operations from
exploration and production
activities(1) .............. ($ 36,529) ($ 130,567) $ 1,165 ($ 38,949) ($204,880)
========== ========== ========== ========== =========
Net income (loss)(3) .......... ($ 40,927) ($ 135,400) ($ 6,521) ($ 47,860) ($230,708)
========== ========== ========== ========== =========
Net income (loss) per share:(3)
Basic ...................... ($ 1.22) ($ 4.01) ($ 0.14) ($ 1.04) ($ 5.80)
========== ========== ========== ========== =========
Diluted .................... ($ 1.22) ($ 4.01) ($ 0.14) ($ 1.04) ($ 5.80)
========== ========== ========== ========== =========
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)(3) .......... $ 5,644 $ 2,016 $ 876 ($ 37,077) ($ 28,541)
========== ========== ========== ========== =========
Net income (loss) per share:(3)
Basic ...................... $ 0.17 $ 0.06 $ 0.03 ($ 1.11) ($ 0.85)
========== ========== ========== ========== =========
Diluted .................... $ 0.16 $ 0.06 $ 0.02 ($ 1.11) ($ 0.85)
========== ========== ========== ========== =========
(1) Results of operations from exploration and production activities, which
approximates gross profit, are computed as operating revenues less
lease operating expenses, severance and ad valorem taxes, depletion and
impairment of oil and natural gas properties (after tax).
(2) Fourth quarter 1998 results include impairment of $48.9 million related
to oil and natural gas properties. 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.
(3) Applicable to common stockholders.
-50-
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 the provisions of SFAS No. 69, "Disclosures about Oil and Gas
Producing Activities."
COSTS INCURRED IN OIL AND NATURAL GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997 1996
---- ---- ----
(in thousands)
Costs incurred during the year:(1)
Property acquisition costs
Unproved .......................... $ 16,545 $ 11,610 $ 10,923
Proved ............................ 259,502 -- --
Exploration .......................... 83,156 73,441 67,093
Development .......................... 51,809 25,813 9,184
-------- -------- --------
$411,012 $110,864 $ 87,200
======== ======== ========
(1) Costs incurred during the years ended December 31, 1998, 1997 and 1996
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of
third party reimbursements, of $6,651,000, $3,958,000 and $3,102,000,
respectively.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES
DECEMBER 31,
------------
1998 1997
---- ----
(in thousands)
Capitalized costs ...................... $ 820,322 $ 409,310
Accumulated depletion .................. (432,868) (143,510)
--------- ---------
Net capitalized costs .................. $ 387,454 $ 265,800
========= =========
At December 31, 1998 and 1997, costs of $94,077,000 and $51,883,000,
respectively, were excluded from the depletion base. These costs are expected to
be evaluated within the next three years. These costs consist primarily of
acreage acquisition costs and related geological and geophysical costs.
-51-
RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
--------- --------- ---------
(in thousands)
Oil and natural gas revenues .............. $ 73,336 $ 57,640 $ 55,123
Less:
Oil and natural gas operating costs .... 12,841 5,680 4,696
Severance and ad valorem taxes ......... 4,069 2,165 1,677
Depletion .............................. 44,347 25,573 24,759
Impairment of long-lived assets ........ 245,011 24,141 --
Income tax benefit ..................... (28,052) -- --
--------- --------- ---------
278,216 57,559 31,132
--------- --------- ---------
Results of operations from oil and
natural gas producing activities ....... ($204,880) $ 81 $ 23,991
========= ========= =========
Depletion expense per MCFE ................ $ 1.27 $ 1.27 $ 1.22
========= ========= =========
-52-
PROVED RESERVES
The following table sets forth the net proved reserves of the Company as of
December 31, 1998, 1997 and 1996, and the changes therein during the years then
ended. The reserve information was reviewed by Ryder Scott Company Petroleum
Engineers for the years 1997 and 1996. T.J. Smith & Company, Inc. prepared the
reserve information for 1998. All of the Company's oil and natural gas producing
activities are located in the United States.
OIL GAS
PROVED RESERVES: (MBBLS) (MMCF)
-------- --------
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
Production ............................ (2,365) (20,603)
Revisions ............................. (3,088) (33,574)
Sale of reserves-in-place ............. (1,059) (8,047)
Discoveries and extensions ............ 6,556 37,854
Purchase of reserves-in-place ......... 12,602 83,472
-------- --------
BALANCE AT DECEMBER 31, 1998 ................... 22,377 169,887
======== ========
PROVED DEVELOPED RESERVES:
Balance at December 31, 1998 .......... 14,592 120,233
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
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The information that follows has been developed pursuant to SFAS No. 69 and
utilizes reserve and production data prepared or reviewed by independent
petroleum consultants. Reserve estimates are inherently imprecise and estimates
of new discoveries are more imprecise than those of producing oil and natural
gas properties. Accordingly, these estimates are expected to change as future
information becomes available.
-53-
The estimated discounted future net cash flows from estimated proved reserves
are based on prices and costs as of the date of the estimate unless such prices
or costs are contractually determined at such date. Actual future prices and
costs may be materially higher or lower. Actual future net revenues also will be
affected by factors such as actual production, supply and demand for oil and
natural gas, curtailments or increases in consumption by natural gas purchasers,
changes in governmental regulations or taxation and the impact of inflation on
costs. At December 31, 1998 and 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,
1998 1997
--------- ---------
(in thousands)
Future cash flows ...................................... $ 592,114 $ 451,157
Future production costs ................................ (133,558) (76,635)
Future development costs ............................... (50,893) (32,746)
--------- ---------
Future net cash flows .................................. 407,663 341,776
Discount to present value at 10 percent per annum ...... (114,286) (127,859)
--------- ---------
Standardized measure of discounted future net cash flows $ 293,377 $ 213,917
========= =========
The average price for natural gas in the above computations was $2.14 and $2.53
at December 31, 1998 and 1997, respectively. The average price used for crude
oil in the above computations was $10.13 and $17.31 at December 31, 1998 and
1997, respectively.
-54-
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following table sets forth the changes in standardized measure of discounted
future net cash flows for the years ended December 31, 1998, 1997 and 1996.
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997 1996
--------- --------- ---------
(in thousands)
BALANCE AT BEGINNING OF PERIOD .............. $ 213,917 $ 313,623 $ 149,863
Sales of oil and gas, net of production costs (56,426) (49,796) (48,750)
Changes in prices, and production costs ..... (90,882) (165,406) 104,249
Revisions of previous quantity estimates .... (33,938) (28,574) (756)
Sales of reserves-in-place .................. (24,219) -- --
Current year discoveries, extensions
and improved recovery .................... 63,292 50,274 167,080
Purchase of reserves-in-place ............... 185,119 -- --
Changes in estimated future
development costs ........................ (18,139) (3,564) (7,597)
Development costs incurred during the period 51,809 27,666 11,723
Accretion of discount ....................... 21,392 39,451 16,182
Net change in income taxes .................. -- 80,884 (63,476)
Change in production rates (timing) and other (18,548) (50,641) (14,895)
--------- --------- ---------
Net change .................................. 79,460 (99,706) 163,760
--------- --------- ---------
BALANCE AT END OF PERIOD .................... $ 293,377 $ 213,917 $ 313,623
========= ========= =========
-55-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
The information required in Items 10, 11, 12 and 13 is incorporated by reference
to the Company's definitive Proxy Statement to be filed with the Securities and
Exchange Commission on or before April 30, 1998.
-56-
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Independent Auditor's Report
(ii) Consolidated Balance Sheets as of December 31, 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 Purchase and Sale Agreement dated effective October 1, 1997,
by and between The Meridian Resource Corporation and Shell
Western E&P Inc. (incorporated by reference from the Company's
Current Report on Form 8-K dated June 30, 1998).
3.1 Third Amended and Restated Articles of Incorporation of the
Company (incorporated by reference to the Company's Quarterly
Report on Form 10- Q for the three months ended September 30,
1998).
3.2 Amended and Restated Bylaws of the Company (incorporated by
reference to the Company's Quarterly Report on Form 10-Q for
the three months ended September 30, 1998).
3.3 Certificate of Designation for Preferred Stock dated June 30,
1998 (incorporated by reference from the Company's Current
Report on Form 8-K dated June 30, 1998).
4.1 Specimen Common Stock Certificate (incorporated by reference
to Exhibit 4.1 of
-57-
the Company's Registration Statement on Form S-1, as amended
(Reg. No. 33-65504)).
4.2 Common Stock Purchase Warrant of the Company dated October 16,
1990, issued to Joseph A. Reeves, Jr. (incorporated by
reference to Exhibit 10.8 of the Company's Annual Report on
Form 10-K for the year ended December 31, 1991, as amended by
the Company's Form 8 filed March 4, 1993).
4.3 Common Stock Purchase Warrant of the Company dated October 16,
1990, issued to Michael J. Mayell (incorporated by reference
to Exhibit 10.9 of the Company's Annual Report on Form 10-K
for the year ended December 31, 1991, as amended by the
Company's Form 8 filed March 4, 1993).
*4.4 Registration Rights Agreement dated October 16, 1990,
among the Company, Joseph A. Reeves, Jr. and Michael J. Mayell
(incorporated by reference to Exhibit 10.7 of the Company's
Registration Statement on Form S-4, as amended (Reg. No. 33-
37488)).
*4.5 Warrant Agreement dated June 7, 1994, between the Company
and Joseph A. Reeves, Jr. (incorporated by reference to
Exhibit 4.1 of the Company's Quarterly Report on Form 10-Q for
the quarter ended June 30, 1994.)
*4.6 Warrant Agreement dated June 7, 1994, between the Company
and Michael J. Mayell (incorporated by reference to Exhibit
4.1 of the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1994.)
4.7 Amended and Restated Credit Agreement dated May 22, 1998,
among the Company, the several banks and financial
institutions and other entities from time to time parties
thereto (the "Lenders"), The Chase Manhattan Bank, as
administrative agent for the Lenders, Bankers Trust Company,
as syndication agent, Chase Securities Inc., as advisor to the
Company, Chase Securities Inc., B. T. Alex. Brown
Incorporated, Toronto Dominion (Texas), Inc. and Credit
Lyonnais New York Branch as co-arrangers, and Toronto Dominion
(Texas), Inc. and Credit Lyonnais New York Branch, as
co-documentation agents. (incorporated by reference from the
Company's current report on Form 8-K dated June 30, 1998).
4.8 Second Amended and Restated Guarantee dated June 30, 1998,
between the Guarantors signatory thereto and The Chase
Manhattan Bank, as Administrative Agent for the Lenders.
(incorporated by reference from the Company's current report
on Form 8-K dated June 30, 1998).
4.9 Amended and Restated Pledge Agreement, dated May 22, 1998,
between the Company and The Chase Manhattan Bank, as
Administrative Agent. (incorporated by reference from the
Company's current report on Form 8-K dated June 30, 1998).
4.10 First Amendment to Amended and Restated Pledge Agreement dated
June 30, 1998. (incorporated by reference from the Company's
current report on Form 8-K dated June 30, 1998).
4.11 Amendment No. 2 dated November 13, 1998 to Amended and
Restated Credit Agreement dated May 22, 1998, by and among the
Company, The Chase Manhattan
-58-
Bank as administrative agent, and the various lenders party
thereto (incorporated by reference from the Company's
Quarterly Report on Form 10-Q for the three months ended
September 30, 1998).
*4.12 The Meridian Resource Corporation Directors' Stock Option Plan
(incorporated by reference to Exhibit 10.5 of the Company's
Annual Report on Form 10-K for the year ended December 31,
1991, as amended by the Company's Form 8 filed March 4, 1993).
4.13 Stock Rights and Restrictions Agreement dated as of June 30,
1998, by and between The Meridian Resource Corporation and
Shell Louisiana Onshore Properties Inc. (incorporated by
reference from the Company's Current Report on Form 8-K dated
June 30, 1998).
4.14 Registration Rights Agreement dated June 30, 1998, by and
between The Meridian Resource Corporation and Shell Louisiana
Onshore Properties Inc. (incorporated by reference from the
Company's Current Report on Form 8-K dated June 30, 1998).
10.1 See exhibits 4.2 through 4.14 for additional material
contracts.
*10.2 The Meridian Resource Corporation 1990 Stock Option Plan
(incorporated by reference to Exhibit 10.6 of the Company's
Annual Report on Form 10-K for the year ended December 31,
1991, as amended by the Company's Form 8 filed March 4, 1993).
*10.3 Employment Agreement dated August 18, 1993, between the
Company and Joseph A. Reeves, Jr. (incorporated by reference
from the Company's Annual Report on Form 10-K for the year
ended December 31, 1995).
*10.4 Employment Agreement dated August 18, 1993, between the
Company and Michael J. Mayell (incorporated by reference from
the Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
*10.5 Form of Indemnification Agreement between the Company and its
executive officers and directors (incorporated by reference to
Exhibit 10.6 of the Company's Annual Report on Form 10-K for
the year ended December 31, 1994).
*10.6 Deferred Compensation agreement dated July 31, 1996, between
the Company and Joseph A. Reeves, Jr.(incorporated by
reference to Exhibit 10.1 of the Company's Quarterly Report on
Form 10-Q for the quarter ended September 30, 1996).
*10.7 Deferred Compensation agreement dated July 31, 1996, between
the Company and Michael J. Mayell (incorporated by reference
to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q
for the quarter ended September 30, 1996).
*10.8 Texas Meridian Resources Corporation 1995 Long-Term Incentive
Plan (incorporated by reference to the Company's Annual Report
on Form 10-K for the year-ended December 31, 1996)
*10.9 Texas Meridian Resources Corporation 1997 Long-Term Incentive
Plan (incorporated by reference from the Company's Quarterly
Report on Form 10-Q for the three months ended June 30, 1997).
-59-
*10.10 Cairn Energy USA, Inc. 1993 Stock Option Plan, as amended
(incorporated by reference to Cairn Energy USA, Inc.'s Annual
Report on Form 10-K for the year ended December 31, 1993).
*10.11 Cairn Energy USA, Inc. 1993 Directors Stock Option Plan, as
amended (incorporated by reference to Cairn Energy USA, Inc.'s
Registration Statement on Form S-1 (Reg. No.33-64646).
10.12 Notes Receivable dated December 31, 1997 to the Company from
affiliates of Michael J. Mayell (incorporated by reference
from the Company's Annual Report on Form 10-K for the year
ended December 31, 1997).
10.13 Notes Receivable dated December 31, 1997 to the Company from
affiliates of Joseph A. Reeves, Jr. (incorporated by reference
from the Company's Annual Report on Form 10-K for the year
ended December 31, 1997).
* 10.14 Employment Agreement with Lloyd V. DeLano effective November
5, 1997 (incorporated by reference from the Company's
Quarterly Report on Form 10-Q for the three months ended
September 30, 1998).
* 10.15 Employment Agreement with P. Richard Gessinger effective
December 1, 1997 (incorporated by reference from the Company's
Quarterly Report on Form 10-Q for the three months ended
September 30, 1998).
** 10.16 The Meridian Resource Corporation TMR Employee Trust
Well Bonus Plan.
** 10.17 The Meridian Resource Corporation Management Well Bonus Plan.
** 10.18 The Meridian Resource Corporation Geoscientist Well Bonus
Plan.
** 10.19 Modification Agreement effective January 2, 1999, by and among
the Company and affiliates of Joseph A. Reeves, Jr.
** 10.20 Modification Agreement effective January 2, 1999, by and among
the Company and affiliates of Michael J. Mayell.
** 21.1 Subsidiaries of the Company.
** 23.1 Consent of Ernst & Young LLP.
** 23.2 Consent of T. J. Smith & Company.
** 23.3 Consent of Ryder Scott Company
** 27.1 Financial Data Schedule
* Management contract or compensation plan.
** Filed herewith.
(b) Reports on Form 8-K.
None.
-60-
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 22, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
NAME TITLE DATE
---- ----- ----
BY: /s/ JOSEPH A. REEVES, JR. Chief Executive Officer March 22, 1999
Joseph A. Reeves, Jr. (Principal Executive Officer)
Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director March 22, 1999
Michael J. Mayell
BY: /s/ P. RICHARD GESSINGER Chief Financial Officer March 22, 1999
P. Richard Gessinger
BY: /s/ LLOYD V. DELANO Chief Accounting Officer March 22, 1999
Lloyd V. DeLano
BY: /s/ JAMES T. BOND Director March 22, 1999
James T. Bond
BY: /s/ JOE E. KARES Director March 22, 1999
Joe E. Kares
BY: /s/ GARY A. MESSERSMITH Director March 22, 1999
Gary A. Messersmith
-61-