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, 1996 Commission file number: 1-10671
TEXAS MERIDIAN RESOURCES 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 The American Stock Exchange, Inc.
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 February 25, 1997. $206,208,630
Number of shares of common stock outstanding
at February 25, 1997. 14,393,299
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, 1997.
Page 1 of 53
TEXAS MERIDIAN RESOURCES CORPORATION
INDEX TO FORM 10-K
PART I PAGE
----
Item 1. Business 3
Item 2. Properties 11
Item 3. Legal Proceedings 17
Item 4. Submission of Matters to a Vote of Security Holders 17
PART II
Item 5. Market for Registrant's Common Equity and Related
Shareholder Matters 18
Item 6. Selected Financial Data 19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 20
Item 8. Financial Statements and Supplementary Data 26
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 49
PART III
Item 10. Directors and Executive Officers of the Registrant 49
Item 11. Executive Compensation 49
Item 12. Security Ownership of Certain Beneficial Owners
and Management 49
Item 13. Certain Relationships and Related Transactions 49
PART IV
Item 14. Exhibits, Financial Statements, Schedules and
Reports on Form 8-K 50
Signatures 53
2
PART I
ITEM 1. BUSINESS
GENERAL
Texas Meridian Resources Corporation, together with its subsidiaries
(the "Company" or "TMRC") is an independent oil and natural gas company engaged
in the exploration for and development of oil and natural gas properties
utilizing 3-D seismic technology. The Company was one of the first independent
oil and natural gas companies in the industry to incorporate 3-D seismic
technology as an integral component of its exploration strategy and considers
itself to be among the leaders in the use of this technology by independent oil
and natural gas companies. The use of 3-D seismic technology provides the
Company with substantially more accurate and comprehensive geological data for
the evaluation of drilling prospects than 2-D seismic and traditional evaluation
methods. The Company believes that its expertise with and disciplined
application of 3-D seismic technology provides it with a significant competitive
advantage in the areas in which it operates.
The Company's exploration efforts are focused primarily onshore and
offshore in the coastal areas of the Louisiana and Texas Gulf Coast. The Company
generally seeks to identify exploration prospects with potential reserves of oil
or natural gas having a minimum of 50 Bcf of natural gas or more per prospect
and capable of producing the equivalent of 10 MMcf of natural gas per day or
greater. The Company's drilling prospects are located primarily in known
geologically complex trends where there have been discoveries of large oil or
natural gas reserves. Most of the Company's prospects require the drilling of
deep wells (12,000 to 25,000 feet) in geo-pressured downhole environments where
drilling risks are higher, with average drilling costs of greater than $3
million per well. The Company typically retains a working interest of between
50% and 75% in each well. Working interests retained by the Company may vary in
certain prospects depending upon participation structure, assessed risk, capital
availability and other factors.
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 sole
limited and general partner. Prior to its conversion, the Company focused its
efforts on the acquisition of producing properties in an effort to take
advantage of what it believed to be low prices for proved reserves with
development potential in relation to the cost of reserves discovered through
exploration activities. In 1991, the Company made a strategic decision to shift
its emphasis away from the acquisition of producing properties to exploration
for large oil and natural gas reserves utilizing 3-D seismic technology. To
facilitate its exploration strategy, the Company disposed of all of its
producing properties in December 1991 and utilized the proceeds to repay
substantially all of its debt and pursue its initial exploration prospects.
Since the commencement of its technologically-based exploration
strategy, the Company has successfully discovered five new fields and has
completed 14 of 19 wells drilled utilizing 3-D seismic technology. Total
reserves attributable to these discoveries as of December 31, 1996 were 13,324
MBbls of oil and 120.3 Bcf of natural gas, of which a total of 5,308 MBbls of
oil and 70.1 Bcf of natural gas is attributable to the Company's interest. The
Company's estimated proved reserves as of December 31, 1996, were approximately
4,524 MBbls of oil and 25.4 Bcf of natural gas having an estimated Present Value
of Proved Reserves of approximately $146.4 million. On a
3
natural gas equivalent basis, 1996 year end proved reserves of 52.5 BCFE
increased 65% over the Company's 31.8 BCFE of proved reserves at December 31,
1995.
RECENT DEVELOPMENTS
LL&E ALLIANCE. In June of 1996, the Company entered into a definitive agreement
with the Louisiana Land and Exploration Company ("LL&E") to form an exploration
joint venture covering areas of the coastal transition zone of south Louisiana.
Under the terms of the agreement, Texas Meridian and LL&E designated an area of
mutual interest covering approximately 1,500 square miles in which they are
jointly pursuing the evaluation and drilling of new prospects utilizing 3-D
seismic technology. The Company and LL&E each own a 50% working interest in
joint projects within the area of mutual interest. The acquisition of oil and
natural gas leases has already been completed for several projects under this
alliance, and 3-D seismic data has been obtained covering approximately 500
square miles, with plans to conduct additional 3-D surveys in the near future.
Since forming the alliance, the Company and LL&E have already
participated in several joint venture projects in south Louisiana outside the
area of mutual interest previously established. Those projects include one well
that is currently drilling (the Prudeaux Bayou prospect) and three prospect
areas where 3-D seismic surveys are under way (Barataria Bay and East Lake
Arthur) or planned (Halter Island). Working interests for Texas Meridian and
LL&E in projects outside the new area of mutual interest generally vary from 75%
to 37.5%.
While both the Company and LL&E are active in the Louisiana coastal area
and have similar and compatible technical approaches to exploration geology and
geophysics, there is minimal overlap in the prospects identified by each
company. As a consequence, entering into these joint ventures is expected to
benefit the Company by enabling it to increase and diversify its exposure to
exploratory prospects and to increase on a combined basis the technical staff
dedicated to those areas without increasing the overhead expenses of either
company.
GECO-PRAKLA ALLIANCE. The use of 3-D seismic data to confirm prospect potential
is a cornerstone of the Company's exploration strategy. Through 1996, the
Company's increased production and reserve additions have been accomplished with
an inventory of less than 300 square miles of 3-D seismic data. In order to
maintain or increase its growth in production and reserves, the Company must
continually add to its inventory of drillable prospects, which in turn requires
a continually increasing inventory of 3-D seismic data. To ensure the
availability of sufficient quantities of high quality 3-D seismic data, the
Company recently entered into an agreement with GECO-Prakla ("GECO"), a division
of Schlumberger Technology Corporation, to acquire access to substantial amounts
of new 3-D seismic data as a participant in GECO's Transition 2000 3-D seismic
development program for south Louisiana. Under this program, GECO intends to
acquire between 1,000 and 2,000 square miles of 3-D seismic data per year
through the year 2000, including surveys that will be performed at the Company's
request and direction. The Company has approximately 150 prospects in various
stages of development within the area expected to ultimately be covered by the
Transition 2000 program.
4
EXPLORATION STRATEGY
The Company's exploration strategy is focused primarily onshore and
offshore in the coastal areas of Louisiana and southeast Texas where large
accumulations of oil and natural gas have been found and where the Company
believes substantial oil and natural gas reserve additions can be made through
exploratory drilling utilizing 3-D seismic technology. The Company also seeks to
identify and pursue prospects with multiple potential productive zones to
maximize the probability of success. In an effort to mitigate the risk of dry
holes, the Company engages in a rigorous and disciplined review of each prospect
utilizing the latest in technological advances with respect to prospect analysis
and evaluation.
The Company's process of review of exploration prospects begins with a
thorough analysis of the prospect using traditional methods of prospect
development and computer technology to analyze all reasonably available 2-D
seismic data and other geological and geophysical data with respect to the
prospect. If the results of this analysis confirm the prospect potential, the
Company seeks to acquire 3-D seismic data over, and leasehold options and
interests in, the prospect area. The Company then applies state of the art
technology to assimilate and correlate the 2-D and 3-D seismic data on the
prospect with all available well log information and other data to create a
computer model that is designed to identify the location and size of potential
hydrocarbon accumulations in the prospect. If the Company's analysis of the
model continues to confirm the potential for hydrocarbon accumulations within
the Company's prospect objectives, the Company will then seek to identify the
most desirable drilling location to test the prospect and to maximize production
when prospect is successful.
The process of developing, reviewing and analyzing a prospect from the
time it is first identified to the time that it is drilled, is generally a 12 to
24 month process and results in a large number of potential prospects being
rejected at various levels of the review. Although the cost of designing,
acquiring, processing and interpreting 3-D seismic data and acquiring options
and leases on prospects that are not ultimately drilled requires greater up
front costs per prospect than traditional exploration techniques, the Company
believes that the elimination of prospects that are unlikely to be successful
and that might otherwise have been drilled at a substantial cost, results in
significant savings to the Company and a higher than average success rate for
large reserve exploratory wells and thereby lower average finding costs per
MCFE. The Company also believes that its use of 3-D seismic technology minimizes
development costs by allowing for the better placement of initial and, if
necessary, development wells.
The Company attempts to match its exploration risks with expected
results by typically retaining a working interest of between 50% and 75% in each
well. The Company further attempts to manage its economic and exploration risks
by internally generating its prospects through one of the industry's most
experienced exploration staffs among the independent oil and gas companies in
the regions in which the Company operates, and by funding its exploration
activities with internally generated cash from operations and the proceeds of
equity issuances, supplemented by the limited use of debt when appropriate,
primarily for the Company's development activities.
5
3-D SEISMIC TECHNOLOGY
The application and reliance on 3-D seismic technology is an integral
part of the Company's exploration strategy. The Company believes that it has a
competitive advantage over many of its competitors through its application of a
disciplined approach to the use of 3-D seismic technology and its access to a
substantial inventory of 3-D seismic data covering its existing properties and
new potential prospects.
The Company uses 3-D seismic technology as a key exploration and
drilling tool and not merely as means of exploiting development opportunities or
confirming the potential viability of a prospect without engaging in the
detailed process of analyzing and correlating the data with other seismic and
well data to identify the most probable areas for hydrocarbon accumulations. The
Company believes that its application of the technology enables it to develop a
much more accurate definition of the risk profile of an exploratory prospect
than was previously available using traditional exploration techniques. As a
result, the Company believes its use of the technology increases its success
rates and reduces its dry hole costs compared to companies that do not engage in
a similar process.
The Company has also sought to achieve advantages over its competitors
by acquiring substantial 3-D seismic data over its prospects prior to drilling
and by securing access to new data over its existing and new prospect areas. To
assure the availability of 3-D seismic data for its prospects, the Company has
entered into several agreements with seismic firms giving the Company rights to
purchase large volumes of both 2-D and 3-D seismic data in the area of its
exploration focus at attractive prices relative to others in its industry. The
Company considers its recent agreement with GECO as an important step toward
enhancing the company's position as a technological leader in exploration in its
areas of operation. As a participant in GECO's Transition 2000 program, the
Company will be entitled to receive data on terms that it believes should
provide it with a competitive advantage over companies that buy such data in the
open market. In addition to its ability to make volume purchases of non-
proprietary data under these agreements, the Company has also accelerated its
acquisition of proprietary 3-D seismic data, which, although more expensive,
provides the company with a competitive advantage through the exclusive use of
the data. The Company estimates that the inventory of both proprietary and
non-proprietary data that it owns or has rights to acquire has increased from
approximately 300 square miles at year end 1995 to approximately 1,190 square
miles at year end 1996.
3-D technology has been in existence since the mid 1970's. However, it
was not until recent years, with the development of high capacity data
acquisition equipment and the availability of improved computer technology and
processing software at reasonable costs that the method became economically
available to companies in addition to major oil companies. Since 1992, the
Company has assembled one of the most experienced 3-D seismic based exploration
staffs dedicated to the development of prospects in the Louisiana and Texas Gulf
Coast area.
In general, seismic technology is the analysis of sound reflected from
geologic features in the subsurface. The sound waves are generated by an energy
source at or near the surface and reflected back to recording devices, or
receivers, at the surface. In 2-D seismic applications, the energy source and
receivers are deployed in a straight line on the surface, and all data collected
is assumed to be reflections from strata in the vertical plane of data
collection directly beneath that line, yielding no information on strata
immediately adjacent to, but outside of, the plane. By
6
comparison, 3-D technology involves the acquisition, processing and
interpretation of seismic information in three dimensions. In the 3-D process,
multiple seismic lines are deployed parallel to one another, with rows of energy
sources, or shot points, laid out perpendicular to the lines of the receivers,
forming a grid. As the energy sources are individually fired, the recording
devices receive reflected energy from reflection points in hundreds of different
planes of data collection, generating millions of individual bits of information
that can be correlated and triangulated by modern seismic software to generate
an accurate image of subsurface strata.
The Company attempts to maximize the quality and usefulness of its 3-D
seismic data by participating in the original design of the survey whenever
practicable. After the survey is designed, the Company conducts tests on such
aspects of the design as the amount and type of energy source, shot hole depths
and layout, and type and placement of recording devices to optimize data
quality. The Company also has a representative on location during the
acquisition process and conducts periodic quality control checks as a survey
progresses.
Testing of survey design is made possible in part by the fact that the
Company has the ability to process the survey field data using its own staff, a
capability that is unusual among independent exploration and production
companies. 3-D seismic processing involves extracting data from magnetic tapes
recorded in the field and filtering that information with a variety of software
programs that present the data in a manner that can be utilized by
interpretation software. The Company believes that having the capability to
process internally gives it greater control over not only the survey planning
but also over the cost and timing of processing the survey data, and gives it
greater flexibility in the assumptions used in processing the data.
Once processing is complete, the Company analyzes the data utilizing
state of the art interpretation software and techniques, including amplitude
variation with offset ("AVO"), 3-D and 2-D pre-stack depth migration, coherency
and inversion techniques. In the areas where the Company is active, the
existence of complex geology and variable acoustic velocities of the subsurface
strata make interpretation of the seismic data in imaging a subsurface structure
a highly subjective process, often requiring the application of combinations of
interpretive techniques and multiple iterations to yield the best solution. In
addition to seismic data, the Company also utilizes all available subsurface
data from wells previously drilled in the surrounding areas to correlate
structural position as well as to test the validity of hydrocarbon indicators,
where applicable. The Company routinely performs forward modeling techniques to
compare the hypothetical seismic response of assumed lithology for a target
horizon to the actual response of a lithologically similar interval in a
preexisting well within the survey area, if available. Additionally, the Company
believes it is one of the few exploration companies to consistently utilize
"Fault Seal Analysis" to evaluate the probability of a competent seal for
prospects that rely on subsurface faulting for structural closure.
GEOLOGIC AND GEOPHYSICAL EXPERTISE
The Company currently employs 47 full-time non-union employees. The
Company's exploration staff is made up of 27 persons, representing over half the
Company's total personnel. This staff includes seven full-time geologists and
eight full-time geophysicists, with between 13 and 41 years of experience in
generating prospects in the Louisiana and Texas Gulf Coast regions. The Company
believes that its exploration group represents one of the most experienced
exploration
7
staffs among the independent oil and natural gas companies in the regions in
which the Company operates. The Company's geologists and geophysicists generate
and review all prospects using computer hardware and software owned or licensed
and operated by the Company. This assemblage of geologists and geophysicists
significantly reduces the Company's dependence on outside technical consultants
and enables the Company to internally generate most of its prospects rather than
taking promoted prospects generated by outside geologists.
In the interest of retaining talented technical personnel, the Company
has adopted an incentive compensation system for its senior geologists and
geophysicists that ties each individual's compensation to the individual's
contribution to the success of the Company's exploration activities by providing
compensation based on results of the prospects generated by the geologist or
geophysicist.
MARKETING OF PRODUCTION
The Company's production is marketed to third parties consistent with
industry practices. Typically, oil is sold at the wellhead at field posted
prices and natural gas is sold under contract at a negotiated price based upon
factors normally considered in the industry, such as price regulations, distance
from the well to the pipeline, well pressure, estimated reserves, quality of
natural gas and prevailing supply and demand conditions.
Pursuant to a farmout by Phillips of leases covering approximately 2,000
acres in the Chocolate Bayou Field to the Company, Phillips reserved a call on
the Company's oil and natural gas production from such field. The gas contract
entered into as a result of Phillips exercising its call on production provides
for a contract until December 31, 1998, which will be renegotiated at that time.
Phillips is currently purchasing 100% of the Company's natural gas production
from the Chocolate Bayou Field at a market price equivalent to the monthly
Houston Ship Channel price quotes less $0.01/MMBtu. Effective December 31, 1996,
the price will increase to 100% of the quoted Houston Ship Channel price and
remain until December 31, 1998.
MARKET CONDITIONS
The Company's revenues, profitability and future rate of growth are
substantially dependent upon prevailing prices for natural gas and, to a lesser
extent, oil. Oil and natural gas prices have been extremely volatile in recent
years and are affected by many factors outside the control of the Company. Since
1992, prices for West Texas Intermediate ("WTI") crude have ranged from $23.39
to $13.94 per Bbl and the monthly average of the Gulf Coast spot market natural
gas price at Henry Hub, Louisiana, has ranged from $3.90 to $1.08 per Mcf. In
1996, WTI crude oil prices have ranged between $23.39 to $17.21 per Bbl, and
spot natural gas prices at Henry Hub, Louisiana, have ranged between $3.97 to
$1.68 per Mcf. The volatile nature of the energy markets makes it difficult to
estimate future prices of oil and natural gas.
Because the majority of the Company's production and targeted prospects
are natural gas, the Company is affected more by changes in natural gas prices
than crude oil prices. However, the Company's recent discoveries in Louisiana
produce more revenues from oil production than from natural gas. Accordingly,
any substantial or extended decline in the price of oil or natural gas could
have a material adverse effect on the Company's financial condition and results
of operations,
8
including reduced cash flow and borrowing capacity. In addition, sales of oil
and natural gas have historically been seasonal in nature, which may lead to
substantial differences in cash flow at various times throughout the year. The
marketability of the Company's production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. Federal and state regulation of oil and natural gas
production and transportation, general economic conditions, changes in supply
and changes in demand, all could adversely affect the Company's ability to
produce and market its oil and natural gas. If market factors were to change
dramatically, the financial impact on the Company could be substantial. The
availability of markets and the volatility of product prices are beyond the
control of the Company and thus represent a significant risk.
COMPETITION
The oil and natural gas industry is highly competitive for prospects,
acreage and capital. The Company's competitors include numerous major and
independent oil and natural gas companies, individual proprietors, drilling and
income programs and partnerships. Many of these competitors possess and employ
financial and personnel resources substantially in excess of those available to
the Company and may, therefore, be able to define, evaluate, bid for and
purchase a greater number of oil and natural gas properties than the Company.
However, by utilizing technological advances, such as 3-D seismic technology,
the Company believes it has enhanced its competitive position relative to others
in the industry that do not similarly rely on such technology. There is intense
competition in marketing oil and natural gas production, and there is
competition with other industries to supply the energy and fuel needs of
consumers.
REGULATION
The availability of a ready market for any oil and natural gas
production depends upon numerous factors beyond the Company's control. These
factors include regulation of oil and natural gas production, Federal and state
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit, the amount of oil
and natural gas available for sale, the availability of adequate pipeline and
other transportation and processing facilities and the marketing of competitive
fuels. For example, 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 the Company 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.
REGULATION OF OIL AND NATURAL GAS PRODUCTION. Oil and natural gas
production operations are subject to various types of regulation by state and
Federal agencies. Legislation affecting the oil and natural gas industry is
under constant review for amendment or expansion. In addition, numerous
departments and agencies, both Federal and state, are authorized by statute to
issue rules and regulations binding on the oil and natural gas industry and its
individual members, some of which carry substantial penalties for failure to
comply. The regulatory burden on the oil and natural gas industry increases the
Company's cost of doing business and, consequently, affects its profitability.
9
GAS PRICE CONTROLS. Prior to January 1993, certain natural gas was
subject to regulation by the Federal Energy Regulatory Commission ("FERC") under
the NGPA which prescribed maximum lawful prices for natural gas sales effective
December 1, 1978. Effective January 1, 1993, natural gas prices were completely
deregulated. Consequently, sales of the Company's natural gas after such date
may be made at market prices.
The FERC regulates interstate natural gas pipeline transportation rates
and service conditions which affect the marketing of natural gas produced by the
Company, as well as the revenues received by the Company for sales of such
natural gas. Since the latter part of 1985, the FERC has adopted policies
intended to make natural gas transportation more accessible to gas buyers and
sellers on an open and non-discriminatory basis. The FERC's latest action in
this area, Order No. 636, reflected the FERC's finding that under the then
current regulatory structure, interstate pipelines and other gas merchants,
including producers, did not compete on a "level playing field" in selling gas.
Order No. 636 instituted individual pipeline service restructuring proceedings,
designed specifically to "unbundle" those services (e.g., transportation, sales
and storage) provided by many interstate pipelines so that buyers of natural gas
may secure gas supplies and delivery services from the most economical source,
whether interstate pipelines or other parties. The FERC has issued final orders
in almost all restructuring proceedings.
Although Order No. 636 does not regulate gas producers such as the
Company, 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 the Company and its marketing efforts, although
recent price declines for natural gas may be attributable, in part, to better
gas distribution resulting from Order 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 the Company. The Company
does not believe, however, it will be affected by any action taken with respect
to Order No. 636 any differently than other gas producers and marketers with
which it competes.
The FERC has adopted a policy concerning "spin-downs" and "spin-offs" of
gathering systems operated by jurisdictional pipelines to non-jurisdictional
entities. Because the Company utilizes gathering service for the transportation
of gas from the wellhead to gas transmission pipelines, the Company could be
affected by this policy. In reviewing applications for "spin-downs" and
"spin-offs," the FERC has considered whether existing shippers have satisfactory
contractual arrangements for gathering in place. In instances in which this is
not the case, the gathering company has been required to offer a "default"
contract for gathering services. The impact that this new policy will have on
the gathering rates paid by the Company or the gathering services received by
the Company cannot yet be determined.
Additional proposals and proceedings that might affect the natural gas
industry are pending before the Congress, the FERC and the courts. The natural
gas industry historically has been very heavily regulated; therefore, there is
no assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.
OIL PRICE CONTROLS. Sales of crude oil, condensate and gas liquids by
the Company are not regulated and are made at market prices.
10
STATE REGULATION OF OIL AND NATURAL GAS PRODUCTION. States in which the
Company conducts its oil and natural gas activities regulate the production and
sale of oil and natural gas, including requirements for obtaining drilling
permits, the method of developing new fields, the spacing and operation of wells
and the prevention of waste of natural gas and resources. In addition, most
states regulate the rate of production and may establish maximum daily
production allowables for wells on a market demand or conservation basis.
ENVIRONMENTAL REGULATION. The Company's operations are subject to
numerous laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict the types, quantities and concentration of various substances that can
be released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from the Company's operations. Moreover, the
recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. For instance, legislation has been proposed in
Congress from time to time that would reclassify certain oil and gas exploration
and production wastes as "hazardous wastes" which would make the reclassified
wastes subject to much more stringent handling, disposal and clean-up
requirements. If such legislation were to be enacted, it could have a
significant impact on the operating costs of the Company, as well as the oil and
natural gas industry in general. Initiatives to further regulate the disposal of
oil and gas wastes are also pending in certain states, and these various
initiatives could have a similar impact on the Company. Management believes that
the Company is in substantial compliance with current applicable environmental
laws and regulations and that continued compliance with existing requirements
will not have a material adverse impact on the Company.
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ITEM 2. PROPERTIES
PRODUCING PROPERTIES
The Company's producing properties are currently located in four fields,
the Chocolate Bayou Field in Texas and the Bayou Lafourche/Lake Boeuf, Southwest
Holmwood and East Cameron Fields in south Louisiana. The following table sets
forth reserve and production information with respect to the Company's interest
in each of these fields as of December 31, 1996.
PRESENT
VALUE OF 1996
FUTURE NET PRODUCTION
OIL GAS REVENUES OIL GAS
PROPERTY (MBBLS) (MMCF) (000) (MBBLS) (MMCF)
-------- ------- ------ ---------- ------- ------
Chocolate Bayou 242 18,609 $ 59,465 57 4,432
Bayou Lafourche/Lake Boeuf 1,141 2,211 26,504 290 714
Southwest Holmwood 184 3,069 15,208 27 377
East Cameron 2,957 1,479 45,227 104 45
-------- -------- ---------- --------- ------
Total 4,524 25,368 $ 146,404 478 5,568
======== ======== ========== ========= ======
Additional information with respect to these fields is set forth below.
Well and reserve information is provided as of December 31, 1996.
CHOCOLATE BAYOU. The Company's Chocolate Bayou Field is located in Brazoria
County, Texas, approximately 35 miles southeast of Houston. In 1992, the Company
farmed-in a prospect near a major field producing from shallower horizons. 3-D
data analyzed by the Company clearly indicated the existence of potential
hydrocarbons, and a discovery well was drilled by the Company to the RA- 4 sand
at approximately 14,000 feet. The field is presently producing approximately 38
MMcf of natural gas and 400 Bbls of oil per day from four wells, with one well
currently drilling and another planned for later in the year. Cumulative
production to date has been 39.8 BCFE and ultimate recovery for the field is
estimated by the Company's independent reservoir engineers to be 103.1 BCFE. The
Company's net revenue interests in the field range from 28% to 49%.
LAKE BOEUF/BAYOU LAFOURCHE. The Lake Boeuf and Bayou Lafourche Fields are
located in Lafourche Parish approximately 30 miles southwest of New Orleans,
Louisiana. These two adjacent fields are covered by a 15 square mile survey
commissioned in 1993. After interpreting the 3-D data, the Company identified
several fault traps and drilled three productive wells. Those three wells are
currently producing at a combined rate of 1,400 barrels of oil and 4.0 MMcf of
natural gas per day. The Company subsequently drilled two additional exploratory
wells in the field, both of which were dry but found the structures as predicted
by 3-D analysis. Both structures had trace amounts of hydrocarbons, indicating
the migration of hydrocarbons through the structures. The Company has since
added a specialist to its staff to perform fault seal analysis, a sophisticated
proprietary technique which estimates the effectiveness of a fault seal. That
analysis is now performed on all prospects that rely on fault trapping
mechanisms whenever requisite data is available.
12
SOUTHWEST HOLMWOOD. The Southwest Holmwood Field is located in Calcasieu Parish,
several miles south of Lake Charles, Louisiana. After reviewing data from a 35
square mile 3-D seismic survey, the Company participated with a major oil
company in 1995 in the discovery well in the field. Based on geologic
information gained from the discovery well and additional interpretation of the
3-D data, the Company drilled a second well in 1996 in the fault block that came
in structurally high to the first well. The two wells are currently producing
approximately 12.3 MMcf and 800 Bbls of oil per day. A third well drilled to
test a different formation in a deeper fault block was unsuccessful.
EAST CAMERON. The East Cameron Field is located in Cameron Parish, Louisiana,
approximately 25 miles south of Lake Charles. In 1994, the Company shot a 43
square mile proprietary 3-D seismic survey to evaluate the prospect. After
drilling the discovery well and a development well in the original fault block,
two additional and separate fault blocks have been drilled extending the field
beyond the original discovery in the field. Three of the four wells are
currently producing at combined rates of 2,000 Bbls of oil and 1.3 MMcf of
natural gas per day, with the fourth well to be tested in March of this year.
The Company currently expects to drill at least three additional wells in the
field. The Company's net revenue interests in the field average 40%.
PRODUCTIVE WELLS
At December 31, 1996, 1995 and 1994, the Company held interests in the
following productive wells, none of which had multiple completions.
DECEMBER 31, 1996 1995(1) 1994
- --------------------------------------------------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Oil Wells .......... 5 2.6 3 1.4 2 1.2
Gas Wells .......... 10 5.6 6 3.4 4 2.1
- ----------
(1)Following December 1, 1994, one well was reclassified from an oil well
to a natural gas well.
CURRENT PROSPECTS
The Company is actively pursuing its exploration and development program
with more than 150 prospects under various stages of review, including prospects
under the LL&E alliance, and has analyzed, acquired or has, or expects to obtain
rights to acquire interests in 3-D seismic data covering approximately 1,850
square miles in south Louisiana and southeast Texas relating to these prospects.
The Company also is currently drilling two wells and expects to drill
approximately 18 wells over the next 12 months. The total cost of the Company's
exploration and development program, including lease and seismic data
acquisition costs, through the end of 1997 is currently estimated to be over $50
million, subject to adjustment depending upon drilling results, timely delivery
and analysis of seismic data, the availability of drilling equipment and other
factors. The Company has recently reaffirmed its exploration strategy and is
implementing a renewed effort at accelerating and increasing its exploration
program for the ensuing twelve months.
13
OIL AND NATURAL GAS RESERVES
Presented below are the estimated quantities of proved undeveloped
reserves of crude oil and natural gas, the Estimated Future Net Revenues (before
income taxes), the Present Value of Future Net Revenues and the Standardized
Measure of Discounted Future Net Cash Flows for the Company as of December 31,
1996. Information set forth in the following table is based upon reserve reports
prepared by Ryder Scott, independent petroleum engineers, in accordance with the
rules and regulations of the Securities and Exchange Commission ("the
Commission").
PROVED RESERVES AT DECEMBER 31, 1996
DEVELOPED DEVELOPED
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL
(dollars in thousands)
Net Proved Reserves:
Oil (MBbls) . . . . . . . . 1,427 1,278 1,819 4,524
Gas (MMcf) . . . . . . . . 18,635 5,823 910 25,368
MMCFE . . . . . . . . . . . 27,197 13,491 11,824 52,512
Estimated Future Net Revenues
(Before Income Taxes). . . . . . . . . . . . . . . . . . . $ 192,305
Present Value of Future Net Revenues . . . . . . . . . . . . . .$ 146,404
Standardized Measure of Discounted
Future Net Cash Flows(1) . . . . . . . . . . . . . . . . .$ 111,010
- ------------
(1)The Standardized Measure of Discounted Future Net Cash Flows prepared by
the Company represents the Present Value of Future Net Revenues after
income taxes discounted at 10%.
Additional reserve information is set forth in the Company's
Consolidated Financial Statements and the Supplemental Oil and Gas Information
(unaudited) included elsewhere herein. The Company has not included estimates of
total proved reserves, comparable to those disclosed herein, in any reports
files with Federal authorities other than the Commission.
In general, estimates of economically recoverable oil and natural gas
reserves and of the future net revenues therefrom are based upon a number of
variable factors and assumptions, such as historical production from the subject
properties, the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices and future operating
costs, all of which may very considerably from actual results. All such
estimates are to some degree speculative, and classifications of reserves are
only attempts to define the degree of speculation involved. For these reasons,
estimates of the economically recoverable oil and natural gas reserves
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery and estimates of the future net revenues
expected therefrom, prepared by different engineers or by the same engineers at
different times, may vary substantially. Therefore, the actual production,
revenues, severance and excise taxes, development and operating expenditures
14
with respect to the Company's reserves will likely vary from such estimates, and
such variances could be material.
Estimates with respect to proved reserves that may be developed and
produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production history, and subsequent evaluation of the same reserves, based
upon production history, will result in variations, which may be substantial, in
the estimated reserves.
In accordance with applicable requirements of the Commission, the
estimated discounted future net revenues from estimated proved reserves are
based on prices and costs as of the date of the estimate unless such prices or
costs are contractually determined at such date. Actual future prices and costs
may be materially higher or lower. Actual future net revenues also will be
affected by factors such as actual production, supply and demand for oil and
natural gas, curtailments or increases in consumption by natural gas purchasers,
changes in governmental regulations or taxation and the impact of inflation on
costs.
OIL AND NATURAL GAS DRILLING ACTIVITIES
The following table sets forth the gross and net number of productive,
dry and total exploratory and development wells that the Company drilled in each
of 1996, 1995 and 1994, all of which are onshore in the Gulf Coast region.
GROSS WELLS NET WELLS
------------------------ ------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- --- -----
Exploratory Wells
Year ended December 31, 1996 4 3 7 2.6 1.7 4.3
Year ended December 31, 1995 3 2(1) 5 1.1 0.9 2.0
Year ended December 31, 1994 3 -- 3 1.9 -- 1.9
Development Wells
Year ended December 31, 1996 -- -- -- -- -- --
Year ended December 31, 1995 1 -- 1 0.8 -- 0.8
Year ended December 31, 1994 1 -- 1 0.6 -- 0.6
- ------------
(1)Due to mechanical difficulties, Amoco, the operator, abandoned one well,
the Ben Todd #1 well, and drilled a substitute well, the Ben Todd #2,
which was subsequently brought on production.
15
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 (all of which are onshore) in which the Company held an
interest during the last three years.
YEAR ENDED DECEMBER 31,
1996 1995 1994
---- ---- ----
Production:
Natural Gas (MMcf) 5,568 4,195 3,176
Oil (MBbls) 478 219 63
MMCFE 8,436 5,509 3,554
Average Sales Price:
Natural Gas ($/Mcf) $ 2.60 $ 1.74 $ 2.03
Oil ($/Bbl) $ 22.19 $ 17.87 $ 16.40
MCFE ($/Mcf) $ 2.98 $ 2.04 $ 2.10
Production Expenses:
Lease operating expenses ($/MCFE) $ 0.12 $ 0.12 $ 0.06
Severance and ad valorem
taxes ($/MCFE) $ 0.20 $ 0.17 $ 0.20
ACREAGE
The following table sets forth the developed and undeveloped oil and
natural gas acreage in which the Company held an interest as of December 31,
1996. 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.
DEVELOPED UNDEVELOPED
GROSS NET GROSS NET
Texas 1,480 1,089 153 99
Louisiana 1,032 548 31,531 15,979
------- ------- ------- -------
Total 2,512 1,637 31,684 16,078
======= ======= ======= =======
In addition to the above acreage, the Company currently has options or
farm-ins to acquire leases on 64,781 gross (54,253 net) acres of undeveloped
land located in Texas and Louisiana. The Company's fee holdings of 4,915 acres
has been included in the undeveloped acreage and has been reduced to reflect the
interest which has been leased to third parties.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, the Company makes
only a cursory review of title to undeveloped oil and natural gas leases at the
time they are acquired by the Company. However, before drilling commences, the
Company causes a thorough title search to be
16
conducted, and any material defects in title are remedied prior to the time
actual drilling of a well on the lease begins. To the extent title opinions or
other investigations reflect title defects, the Company, rather than the seller
or lessor of the undeveloped property, is typically obligated to cure any such
title defects at its expense. If the Company were unable to remedy or cure any
title defect of a nature such that it would not be prudent to commence drilling
operations on the property, the Company could suffer a loss of its entire
investment in the property. The Company believes that it has good title to its
oil and natural gas properties, some of which are subject to immaterial
encumbrances, easements and restrictions. Under the terms of its Credit
Agreement, the Company is prohibited from granting liens on various of its
properties and is required to grant to its bank a lien on such property in the
event of certain defaults. The oil and natural gas properties owned by the
Company are also typically subject to royalty and other similar non-cost bearing
interests customary in the industry.
Substantial portions of the Company's 3-D seismic data has been acquired
through licenses and other similar arrangements. Such licenses contain transfer
and other restrictions customary in the industry.
ITEM 3. LEGAL PROCEEDINGS
In June 1996, Amoco Production Company ("Amoco") filed suit against the
Company in Louisiana State Court in Calcasieu Parish with respect to a dispute
involving the drilling by the Company of a well in the Southwest Holmwood Field
in which the Company and Amoco each hold a 50% leasehold interest. The case was
removed to the United State District Court for the Western District of Louisiana
in July 1996. The well in question was drilled by the Company under a
participation agreement between the Company and Amoco in which Amoco had a right
to participate in the well. The well was drilled by the Company after providing
notice to Amoco pursuant to the participation agreement of the Company's intent
to drill the well and Amoco's election not to participate in the well. Amoco has
alleged in its suit that the well was not permitted to be drilled under the
agreement and is seeking to recover the revenues from the well or have the
production from the well stopped. Amoco is also requesting a cancellation of the
Company's leasehold interest. The Company has filed a counterclaim for breach of
contract, unfair trade practices and other claims. The Company believes that
Amoco's suit is without merit and intends to vigorously defend the suit. The
Company does not believe that the outcome of this suit will have a material
impact on the Company or its financial condition.
There are no other material legal proceedings, except for that mentioned
above, to which the Company or any of its subsidiaries or partnerships is a
party or by which any of its property is subject, other than ordinary and
routine litigation incidental to the business of producing and exploring for oil
and natural gas.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's security holders
during the fourth quarter of the year ended December 31, 1996.
17
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The common stock is traded on the American Stock Exchange under the
symbol "TMR." The following table sets forth, for the periods indicated, the
high and low sale prices per share for the common stock as reported on the
American Stock Exchange Composite Tape:
HIGH LOW
1996:
First quarter................. 14 10 3/4
Second quarter................ 13 9
Third quarter................. 15 1/8 9 5/16
Fourth quarter................ 18 1/2 14 5/8
1995:
First quarter................. 11 5/8 9 1/8
Second quarter................ 13 9 7/8
Third quarter................. 12 5/8 10 1/4
Fourth quarter ............... 14 10 3/8
The closing sale price of the common stock on February 25, 1997, as
reported on the American Stock Exchange Composite Tape, was $15.00. As of
February 25, 1997, the Company had approximately 754 shareholders of record.
The Company has not paid cash dividends on the common stock and does not
intend to pay cash dividends on the common stock in the foreseeable future. The
Company currently intends to retain its cash for the continued development of
its business, including exploratory and development drilling activities. The
Company is also currently restricted under its Credit Agreement from expending
more than $500,000 in the aggregate for cash dividends on the common stock or
for purchases of shares of common stock without the prior consent of the lender.
18
ITEM 6. SELECTED FINANCIAL DATA
All financial data should be read in conjunction with the Consolidated
Financial Statements of TMRC and related notes thereto included elsewhere in
this report.
YEAR ENDED DECEMBER 31,
1996 1995 1994 1993 1992
----- ---- ---- ---- ----
(in thousands, except per share data)
A. SUMMARY OF OPERATIONS
Total revenues $ 26,387 $ 12,267 $ 7,860 $ 5,000 $ 2,868
Depletion, depreciation and
amortization $ 9,014 $ 4,999 $ 3,069 $ 1,759 $ 74
Net income (loss) $ 7,134 $ 2,153 $ 1,398 $ (3,373) $ (951)
Net income (loss) per common
and common equivalent share $ 0.45 $ 0.16 $ 0.12 $ (0.51) $ (0.21)
Dividends per common share $ -- $ -- $ -- $ -- $ --
Weighted average common
shares outstanding (1) 15,720 13,580 11,769 6,654 4,608
B. SUMMARY BALANCE SHEET DATA
Total assets $ 103,262 $ 86,726 $ 37,415 $32,520 $ 10,521
Long-term obligations, inclusive
of current maturities $ -- $ -- $ -- $ -- $ 4,300
(1) The weighted average common shares outstanding for the Company have been
adjusted for the effect of common stock equivalents for the years ended
December 31, 1996, 1995 and 1994.
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
GENERAL
For the fiscal years of 1996, 1995 and 1994, the Company reported
significant increases in reserves, production and cash flow from oil and natural
gas producing activities. These increases were primarily the result of the
Company's activities in its Chocolate Bayou, East Cameron, Lake Bouef/Bayou
Lafourche and Southwest Holmwood Fields. Chocolate Bayou continues to be the
Company's most significant property in terms of natural gas production, and the
Company has drilled at least one well in that area in each of the last three
years. Oil reserves and production have increased significantly with the East
Cameron discovery. During 1996, the Company completed two wells in the East
Cameron prospect and two other extension wells were in progress at year end.
Additional wells will be drilled in both the East Cameron and Chocolate Bayou
Fields in 1997. During the last three years, the Company has also drilled two
producing wells in its Southwest Holmwood Field and three in its Lake
Bouef/Bayou Lafourche Field area. See Item II, "Properties Producing
Properties."
Production results for 1997 are expected to grow over 1996 as TMRC sees
a full year's production from its six wells that were placed on production
during 1996 and from the Company's recently announced extension well in the East
Cameron Field. The full future results for 1997 will be affected by pricing
trends for oil and natural gas, which continue to be volatile and therefore
difficult to determine. Future results of the Company will also be materially
dependent upon the Company's ability to fund and complete, as well as the
success of, the Company's 3-D exploratory drilling and development program. Due
to the nature of the Company's business activities and the general risks
relating to exploratory drilling for oil and natural gas, there can be no
assurance as to the success of these efforts.
20
RESULTS OF OPERATIONS
REVENUES AND PRODUCTION. The following table summarizes operating revenues,
production volumes, and average sales prices for the Company's oil and natural
gas for the years ended December 31, 1996, 1995 and 1994.
1996/95 1995/94
PERCENTAGE PERCENTAGE
YEAR ENDED DECEMBER 31, INCREASE INCREASE
1996 1995 1994 (DECREASE) (DECREASE)
---- ---- ---- ---------- ----------
Production:
Natural Gas (MMcf) 5,568 4,195 3,176 33% 32%
Oil (MBbls) 478 219 63 118% 248%
MMCFE 8,436 5,509 3,554 53% 55%
Average Sales Price:
Natural Gas ($/Mcf) $ 2.60 $ 1.74 $ 2.03 49% (14%)
Oil ($/Bbl) $ 22.19 $ 17.87 $ 16.40 24% 9%
MCFE ($/Mcf) $ 2.97 $ 2.04 $ 2.10 46% (3%)
Gross Revenues (000's):
Natural Gas $ 14,499 $ 7,311 $ 6,440 98% 14%
Oil 10,608 3,913 1,026 171% 281%
--------- --------- --------- --------- -------
Total $ 25,107 $ 11,224 $ 7,466 124% 50%
========= ========= ========= ========= =======
Oil production volumes were up in 1996 over 1995 as a result of six
additional wells being placed on production during 1996. During 1995, three
additional wells were placed on production increasing that year's volumes over
that of 1994. Market conditions during 1996 and 1995 caused oil price increases
in both years over prior years, however, natural gas prices were lower in 1995
than 1994, but rebounded sharply in 1996.
OPERATING EXPENSES. 1996 lease operating expenses increased to $1 million from
$0.7 million during the prior year, primarily related to six additional wells
that were placed on production during 1996. Operating expenses increased $0.5
million during 1995 over 1994 levels. This increase related to three additional
wells being placed on production during 1995 and an increase in the number of
water drive wells and associated salt water production. Several salt water
disposal wells were drilled in 1995 to lower the water disposal costs.
SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes increased by $0.7
million and $0.2 million for the years 1996 and 1995, respectively. These
increases are a result of the Company's increased oil and natural gas production
and revenues and were partially offset by a Louisiana severance tax reduction
incentive for new field discoveries and wells drilled below 15,000 feet.
INTEREST AND OTHER INCOME. Interest and other income increased 30%, or $0.3
million, to $1.3 million in 1996 as compared to $1 million in 1995. This
increase resulted from higher cash balances and interest rates during 1996. 1995
interest and other income increased $0.6 million over 1994 levels due to a
significant increase in the Company's cash balances following its July 1995
common stock offering.
21
INTEREST EXPENSE. During 1996, interest expense decreased by $30,000 reflecting
the retirement of the Company's bank debt in late 1995 following the Company's
common stock offering. Interest expense in 1995 increased by $33,000 over 1994,
reflecting borrowings prior to the stock offering.
DEPLETION, DEPRECIATION AND AMORTIZATION. Depletion, depreciation and
amortization expense for the Company increased to $9 million for 1996 compared
to $5 million for 1995 and $3.1 million for 1994. The increases were primarily
the result of increased production during each of the years. Depletion expense
related to oil and natural gas properties, per equivalent Mcf of gas, for 1996,
1995 and 1994 was $1.01, $0.86 and $0.81, respectively. Fixed asset depreciation
and other asset amortization was $491,000, $276,000 and $179,000 for 1996, 1995
and 1994, respectively.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased
for 1996 and 1995 by $1.1 million and $0.7 million, respectively. These
increases were primarily due to increased employee costs associated with the
Company's expanded exploration activities. Although the general and
administrative expenses have increased in the aggregate, as percentages of oil
and natural gas revenues, they decreased from 28% in 1995 to 17% in 1996.
INVESTMENT CARRYING VALUE ADJUSTMENT. In 1995, management reevaluated the
Company's investment in Jefferson Gas Systems, Inc. in light of available
financial and business information and recognized a $300,000 charge to reflect a
reduction in the estimated realizable value of the investment.
INCOME TAXES. In 1995 and 1994, the Company benefited from the utilization of
prior years' tax loss carryforwards for tax and accounting purposes. These loss
carryforwards, however, have been fully utilized for accounting purposes and in
1996, the prior year's losses were extinguished and TMRC was required to record
$3.4 million deferred tax expense. In 1995 and 1994, the Company recorded a
provision for current income taxes of $30,000 and $22,000, respectively, which
related solely to state income taxes.
LIQUIDITY AND CAPITAL RESOURCES
The Company's operations for 1996 were primarily funded by cash on had
at the beginning of the year and cash generated by oil and natural gas
operations. As of December 31, 1996, the Company had a cash balance of $17.3
million and a positive working capital of $3.8 million. The decrease in both the
cash balance and working capital reflects capital expenditures related to the
Company's exploration activities.
To provide the Company with additional funds to finance its future
exploration and development program and to satisfy working capital needs, the
Company's operating subsidiary, Texas Meridian Resources Exploration, Inc.
("TMRX"), maintains a line of credit with Chase Manhattan Bank. TMRX's
obligations under this facility are guaranteed by the Company and secured by the
stock of TMRX and certain other subsidiaries of the Company. Under this
facility, the Company may borrow, on a revolving basis, up to $20 million,
subject to satisfaction of a borrowing base as determined from time to time by
Chase Manhattan Bank. The initial borrowing base under the facility was
established at $7.5 million. Since that time, maximum borrowings under the
facility have been $2.8 million. In order to minimize commitment fees, the
Company has elected not to request an increase in either the line of credit or
the borrowing base. Borrowings under the
22
Credit Agreement mature on December 31, 1999.
Under the Credit Agreement, the Company may secure either an alternate
base rate loan, which bears interest at a rate per annum equal to the greatest
of (i) Chase Manhattan Bank's prime rate, (ii) a CD-based rate, and (iii) the
average Federal funds rate, or a Eurodollar loan, which bears interest,
generally, at a rate per annum equal to the rate at which Chase Manhattan Bank
is offered U.S. dollar deposits in the interbank Eurodollar market plus 0.5% to
1.5% depending on the Company's Ratio of Consolidated Total Indebtedness to
Consolidated Earnings Before Interest, Taxes, Depreciation and Amortization. The
Credit Agreement also provides for a commitment fee of 0.4% per annum on the
unused portion of the borrowing base, and a supplemental commitment fee of
0.0625% per annum on the amount by which $20 million exceeds the borrowing base.
The Credit Agreement contains certain restrictive and financial
covenants, including a requirement to maintain a minimum amount of Consolidated
Tangible Net Worth (as defined in the Credit Agreement) and to maintain certain
financial ratios. There are also restrictions on the amount of debt or liens the
Company may incur or create, and on mergers, sales of assets or investments that
can be made by the Company. The Company is prohibited from paying cash dividends
or purchasing common stock in excess of an aggregate of $500,000 and from
entering into any agreement that would restrict its ability to create any lien
on its property. It is also an event of default under the Credit Agreement (i)
if any person or group acquires beneficial ownership of 35% of the outstanding
common stock or has the power to elect a majority of the Company's directors, or
if the existing directors (or successors nominated by a majority of the existing
directors (or their successors so nominated)) do not continue to constitute a
majority of the Company's Board of Directors or (ii) if Joseph A. Reeves, Jr.
and Michael J. Mayell (or any successor approved by the lenders) cease to be
actively involved as Chief Executive Officer or President, respectively, of the
Company.
Capital expenditures during 1996, consisted of $38.3 million for oil and
natural gas property additions compared to $22.9 million in 1995. Drilling and
completion expenditures in 1996 were approximately $18 million relating to the
drilling of nine wells and the completion of five wells. Three of the nine wells
remained in progress after the end of the year. The remaining capital
expenditures of $20.3 million was primarily in the development of additional
prospects located in south Louisiana and the Texas Gulf Coast, including lease
and seismic data acquisitions. Capital expenditures for 1997 are currently
estimated at over $50 million, related to the drilling of the Company's
exploration and development prospects in Texas and Louisiana as well as costs
associated with additional acquisition of leases, seismic data and interpretive
work.
Future cash requirements are expected to be provided from existing cash,
cash generated by current properties and newly-drilled properties developed on
the Company's properties and borrowings to the extent necessary. In management's
opinion, the Company has sufficient funding available for its 1997 exploration
and development program.
FORWARD-LOOKING INFORMATION
From time-to-time, the Company may make certain statements that contain
"forwardlooking" information as defined in the Private Securities Litigation
Reform Act of 1995) and that involve risk and uncertainty. These forward-looking
statements may include, but are not limited to, exploration and seismic
acquisition plans, anticipated results from current and future exploration
23
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 the Company's filings with the Securities and Exchange Commission
under the Securities Act of 1933 and the Securities and Exchange Act of 1934.
Actual results and trends in the future may differ materially depending
on a variety of factors including, but not limited to, the success of the
Company's exploration and development program, changes in the price of oil and
natural gas, world-wide political stability and economic growth, the Company's
successful execution of internal exploration, development and operating plans,
environmental regulation and costs, regulatory uncertainties and legal
proceedings.
24
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.
25
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
Report of Independent Auditors 27
Consolidated Statements of Income
--For each of the three years in the period ended December 31, 1996 28
Consolidated Balance Sheets--December 31, 1996 and 1995 29
Consolidated Statements of Cash Flows
--For each of the three years in the period ended December 31, 1996 31
Consolidated Statements of Changes in Stockholders' Equity
--For each of the three years in the period ended December 31, 1996 32
Notes to Consolidated Financial Statements 33
Consolidated Supplemental Oil and Gas Information (Unaudited) 45
26
REPORT OF INDEPENDENT AUDITORS
Board of Directors and Stockholders
Texas Meridian Resources Corporation and Subsidiaries
We have audited the accompanying consolidated balance sheets of Texas Meridian
Resources Corporation and subsidiaries as of December 31, 1996 and 1995, and the
related consolidated statements of income, stockholders' equity, and cash flows
for each of the three years in the period ended December 31, 1996. Our audits
also included the financial statement schedule listed in the Index at Item
14(a). These financial statements and schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule 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 Texas
Meridian Resources Corporation and subsidiaries at December 31, 1996 and 1995,
and the consolidated results of their operations and their cash flows for each
of the three years in the period ended December 31, 1996, in conformity with
generally accepted accounting principles. Also, in our opinion, the related
financial statement schedule when considered in relation to the basic financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
ERNST & YOUNG LLP
February 4, 1997
Houston, Texas
27
TEXAS MERIDIAN RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
1996 1995 1994
---- ---- ----
(in thousands, except per
share information)
REVENUES:
Oil and natural gas .......................... $25,107 $11,224 $ 7,466
Interest and other ........................... 1,280 1,043 394
------- ------- -------
26,387 12,267 7,860
------- ------- -------
COSTS AND EXPENSES:
Oil and natural gas operating ................ 981 683 227
Severance and ad valorem taxes ............... 1,661 917 694
Depletion, depreciation and amortization ..... 9,014 4,999 3,069
General and administrative ................... 4,223 3,135 2,433
Interest ..................................... 20 50 17
Investment carrying value adjustment ......... -- 300 --
------- ------- -------
15,899 10,084 6,440
------- ------- -------
INCOME BEFORE INCOME TAXES ....................... 10,488 2,183 1,420
INCOME TAX EXPENSE ............................... 3,354 30 22
------- ------- -------
NET INCOME ....................................... $ 7,134 $ 2,153 $ 1,398
======= ======= =======
NET INCOME PER COMMON AND
COMMON EQUIVALENT SHARE ...................... $ 0.45 $ 0.16 $ 0.12
======= ======= =======
Weighted average number of common and
common equivalent shares outstanding ......... 15,720 13,580 11,769
======= ======= =======
See notes to consolidated financial statements.
28
TEXAS MERIDIAN RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
1996 1995
---- ----
(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ....................... $ 17,267 $ 35,658
Accounts receivable (less allowance
for doubtful receivables of $121,000) ....... 7,116 2,155
Due from affiliates ............................. 857 1,171
Prepaid expenses and other ...................... 105 141
--------- --------
Total current assets ........................ 25,345 39,125
--------- --------
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method
(including $29,718,000 [1996] and $16,950,000
[1995] not subject to depletion) ............ 92,902 54,649
Land ............................................ 478 887
Equipment ....................................... 2,628 1,521
--------- --------
96,008 57,057
Less accumulated depletion and depreciation ..... (18,506) (9,833)
--------- --------
77,502 47,224
OTHER ASSETS, NET ................................... 415 377
--------- --------
$ 103,262 $ 86,726
========= ========
See notes to consolidated financial statements.
29
TEXAS MERIDIAN RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
DECEMBER 31,
1996 1995
---- ----
(in thousands)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable ...................... $ 4,225 $ 6,348
Revenues and royalties payable ........ 5,530 3,366
Accrued liabilities ................... 11,752 5,473
--------- --------
Total current liabilities ......... 21,507 15,187
--------- --------
DEFERRED INCOME TAXES ..................... 3,380 --
--------- --------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value
(25,000,000 shares authorized, none
issued and outstanding) ........... -- --
Common stock, $0.01 par value
(100,000,000 shares authorized,
14,453,298 [1996] and 14,430,176
[1995] issued) .................... 145 144
Additional paid-in capital ............ 75,265 74,141
Accumulated earnings (deficit) ........ 4,388 (2,746)
Unamortized deferred compensation ..... (343) --
--------- --------
79,455 71,539
Treasury stock, at cost (60,000 shares) (1,080) --
--------- --------
Total stockholders' equity ........ 78,375 71,539
--------- --------
$ 103,262 $ 86,726
========= ========
See notes to consolidated financial statements.
30
TEXAS MERIDIAN RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
1996 1995 1994
---- ---- ----
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .............................................. $ 7,134 $ 2,153 $ 1,398
Adjustments to reconcile net income to net
cash provided by operating activities:
Depletion and depreciation .......................... 8,909 4,944 3,069
Amortization of other assets ........................ 105 55 --
Deferred income taxes ............................... 3,380 -- --
Non-cash compensation ............................... 647 -- --
Investment carrying value adjustment ................ -- 300 --
Changes in assets and liabilities:
(Increase) decrease in accounts receivable .......... (6,041) 94 (838)
(Increase) decrease in due from affiliates .......... 314 (487) (311)
(Increase) decrease in prepaid expenses and other ... 36 (96) 11
Increase (decrease) in accounts payable ............. (2,123) 4,673 (258)
Increase (decrease) in revenues and royalties payable 2,164 2,667 (197)
Increase (decrease) in accrued liabilities .......... (116) 217 10
Decrease in income taxes payable .................... -- -- (90)
-------- -------- --------
Net cash provided by operating activities ................... 14,409 14,520 2,794
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment additions, net ................... (32,792) (19,814) (15,772)
Other, net .............................................. (134) 5 --
-------- -------- --------
Net cash used in investing activities ....................... (32,926) (19,809) (15,772)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term borrowings .......... -- 2,800 --
Reductions in long-term debt ............................ -- (2,800) --
Common stock offering, net of issuance costs ............ -- 36,876 --
Exercise of warrants, net of stock issuance costs ....... -- -- 1,870
Exercise of stock options ............................... 135 152 --
Payment of deferred loan costs .......................... (9) (192) --
-------- -------- --------
Net cash provided by financing activities ................... 126 36,836 1,870
-------- -------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS ..................... (18,391) 31,547 (11,108)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR .............. 35,658 4,111 15,219
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR .................... $ 17,267 $ 35,658 $ 4,111
======== ======== ========
See notes to consolidated financial statements.
31
TEXAS MERIDIAN RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
(in thousands)
ACCUMU-
ADDITIONAL LATED UNAMORTIZED
COMMON STOCK PAID-IN EARNINGS DEFERRED TREASURY STOCK
SHARES PAR VALUE CAPITAL (DEFICIT) COMPENSATION SHARES COST TOTAL
------ --------- ---------- --------- ------------ ------ ---- -----
Balance, December 31, 1993 .............. 9,641 $ 96 $35,291 $(6,297) -- -- -- $ 29,090
Exercise of warrants, net
of stock issuance costs .......... 952 10 1,860 -- -- -- -- 1,870
Net income .......................... -- -- -- 1,398 -- -- -- 1,398
------ ---- ------- ------- ----- --- ------- --------
Balance, December 31, 1994 .............. 10,593 106 37,151 (4,899) -- -- -- 32,358
Common Stock offering,
net of issuance costs ............ 3,795 38 36,838 -- -- -- -- 36,876
Exercise of stock options ........... 42 -- 152 -- -- -- -- 152
Net income .......................... -- -- -- 2,153 -- -- -- 2,153
------ ---- ------- ------- ----- --- ------- --------
Balance, December 31, 1995 .............. 14,430 144 74,141 (2,746) -- -- -- 71,539
Exercise of stock options ........... 17 -- 135 -- -- -- -- 135
Company's 401(k) Plan contribution .. 6 -- 80 -- -- -- -- 80
Issuance of rights to Common Stock -- 1 909 -- (910) -- -- --
Compensation expense ................ -- -- -- -- 567 -- -- 567
Treasury shares acquired ............ -- -- -- -- -- (60) (1,080) (1,080)
Net income .......................... -- -- -- 7,134 -- -- -- 7,134
------ ---- ------- ------- ----- --- ------- --------
Balance, December 31, 1996 .............. 14,453 $145 $75,265 $ 4,388 $(343) (60) $(1,080) $ 78,375
====== ==== ======= ======= ===== === ======= ========
See notes to consolidated financial statements.
32
TEXAS MERIDIAN RESOURCES CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Texas Meridian Resources Corporation together with its subsidiaries,
(the "Company" or "TMRC") was initially organized in 1985 as a master limited
partnership and operated as such until 1990 when it converted into a corporation
through a merger with a limited partnership of which the Company was the sole
limited and general partner.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF CONSOLIDATION
These consolidated financial statements reflect the accounts of TMRC and
its subsidiaries after elimination of all significant intercompany transactions
and balances.
PROPERTY AND EQUIPMENT
TMRC accounts for its oil and natural gas properties using the full cost
method. All direct and certain indirect costs associated with the acquisition,
exploration and development of oil and natural gas properties are capitalized.
Included in capitalized costs are general and administrative costs that are
directly identified with the acquisition, exploration and development
activities. Depletion of oil and natural gas properties is provided on a
composite unit of production method based on estimates of proved oil and natural
gas reserves prepared by independent petroleum consultants.
Proceeds from the sale of proved oil and natural gas reserves 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. Unproved leasehold
acreage costs and costs for exploratory wells in process are excluded from the
depletion base until the results of drilling have been evaluated, at which time
such costs are transferred to the depletion base with the related proved
reserves, if any.
Under the Securities and Exchange Commission's rules 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 estimated
future net cash flows from proved reserves based on periodend prices and costs,
plus the lower of cost or estimated fair value of unproved properties.
Equipment is recorded at cost, and depreciation is determined using an
accelerated depreciation method basis over the estimated useful lives of the
assets. Future well abandonment costs net of salvaged equipment are not expected
to be significant and, accordingly, no provision has been recorded in the
financial statements.
33
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.
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's receivables are due from oil and
natural gas producing companies located in the United States.
REVENUE RECOGNITION
TMRC recognizes oil and natural gas revenue from its interests in
producing wells as oil and natural gas is produced and sold from those wells.
Oil and natural gas sold is not significantly different from TMRC's share of
production.
NET INCOME PER SHARE
Net income per share is calculated by dividing net income by the
weighted average common shares and (in periods in which they have a dilutive
effect) common share equivalents outstanding during the period, excluding shares
held in treasury. Shares of common stock issuable under stock options, warrants
and stock rights are treated as common share equivalents when dilutive.
For the years presented, there is no difference between primary and
fully diluted net income per share.
STOCK OPTIONS
As permitted by SFAS No. 123, the Company will continue to follow the
existing accounting requirements for stock options and stock-based awards
contained in Accounting Principles Board Opinion ("APB") 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.
CHANGES IN PRESENTATION
Certain items in 1994 and 1995 have been reclassed to conform to 1996
presentation.
34
3. ACCOUNTS RECEIVABLE AND ACCRUED LIABILITIES
Accounts receivable consisted of the following:
DECEMBER 31,
1996 1995
(in thousands)
Trade receivables .................. $ 7,073 $ 2,009
Employee receivables ............... 104 79
Other receivables .................. 60 188
------- -------
7,237 2,276
Less allowance for doubtful accounts (121) (121)
------- -------
$ 7,116 $ 2,155
======= =======
Accrued liabilities consisted of the following:
DECEMBER 31,
1996 1995
(in thousands)
Accrued oil and gas property costs ..... $11,267 $4,828
Accrued general and administrative costs 485 520
Other accrued expenses ................. -- 125
------- ------
$11,752 $5,473
======= ======
4. LONG-TERM DEBT
In May 1995, the Company's operating subsidiary, Texas Meridian
Resources Exploration, Inc. ("TMRX"), obtained a line of credit with Chase
Manhattan Bank. TMRX's obligations under this facility are guaranteed by the
Company and secured by the stock of TMRX and certain other subsidiaries of the
Company. Under the terms of this facility, TMRX may borrow, on a revolving
basis, up to $20 million, subject to a borrowing base as determined from time to
time by Chase Manhattan Bank. The initial borrowing base under the facility,
based solely on TMRX's wells producing at the date of the Credit Agreement, is
$7.5 million. Borrowings under this Credit Agreement contains various
restrictive covenants including, among other things, certain minimum financial
ratios and restrictions on cash dividends. Borrowings under the Credit Agreement
mature on December 31, 1999.
Under the Credit Agreement, TMRX may secure either an alternate base
rate loan, which bears interest at a rate per annum equal to the greatest of (i)
Chase Manhattan Bank's prime rate, (ii) a CD-based rate, and (iii) the average
Federal funds rate, or a Eurodollar loan, which bears interest, generally, at a
rate per annum equal to the rate at which Chase Manhattan Bank is offered U. S.
dollar deposits in the interbank Eurodollar market plus 0.5% to 1.5% depending
on the Company's Ratio of Consolidated Total Indebtedness to Consolidated
Earnings Before Interest, Taxes, Depreciation and Amortization. The Credit
Agreement also provides for a commitment fee of 0.4% per annum on the amount of
funds made available (determined quarterly), and a supplemental commitment fee
of 0.625% per annum on the amount by which $20 million exceeds the available
funds.
35
5. COMMITMENTS AND CONTINGENCIES
LITIGATION
The Company is in litigation with a third party in connection with a
dispute related to the third party's election not to participate in the drilling
of a well which was subsequently drilled, completed and is currently producing.
Although the Company is unable to determine the potential exposure associated
with this matter, Management does not expect that the outcome of this litigation
will result in a material impact to the financial statements. In addition, the
Company is involved from time to time in various claims and lawsuits incidental
to its business. In the opinion of Management, the ultimate liability
thereunder, if any, will not have a material effect on the financial condition
of the Company.
LEASE OBLIGATIONS
TMRC has a five-year operating lease with a primary term ending in
September 1999.
Rental expense was approximately $312,000, $274,000 and $197,000 for the
years ended December 31, 1996, 1995 and 1994, respectively.
TMRC also has operating leases for equipment with various terms, none
exceeding three years.
Future minimum lease payments under all non-cancelable operating leases
having initial terms of one year or more are as follows:
1997 $ 401,000
1998 355,000
1999 218,000
----------
Total future minimum lease payments $ 974,000
===========
GECO-PRAKLA
In December 1996, the Company entered into an agreement with GECO-Prakla
("GECO"), a division of Schlumberger Technology Corporation. Under this program
GECO intends to acquire between 1,000 and 2,000 square miles of 3-D seismic data
per year through the year 2000, including surveys which will be performed at the
Company's request and direction. The Company has obligated itself to acquire
1,100 square miles over the next three years.
36
6. INCOME TAXES
Components of the provision (benefit) for Federal and State income taxes
are as follows:
1996 1995 1994
---- ---- ----
Current $ (26,000) $30,000 $22,000
Deferred 3,380,000 -- --
----------- ------- -------
$ 3,354,000 $30,000 $22,000
=========== ======= =======
Income tax expense as reported is reconciled to the statutory rate (35%)
as follows:
1996 1995 1994
---- ---- ----
Income tax computed at statutory rate $ 3,671,000 $ 764,000 $ 497,000
Nondeductible items ................. 95,000 35,000 21,000
Non-statutory options ............... -- (51,000) --
Increase in percentage depletion
carryover ........................ (263,000) (302,000) (244,000)
Basis differential in investment .... -- -- (192,000)
Change in valuation allowance ....... (116,000) (426,000) (107,000)
Other ............................... (33,000) 10,000 47,000
----------- --------- ---------
$ 3,354,000 $ 30,000 $ 22,000
=========== ========= =========
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:
1996 1995
---- ----
Deferred tax assets:
Net operating tax loss carryforward ......... $ 6,055,000 $ 6,282,000
Statutory depletion carryforward ............ 968,000 556,000
Basis differential in equipment ............. 108,000 --
Basis differential in long-term investments . -- 297,000
Less valuation allowance .................... (1,017,000) (1,133,000)
----------- -----------
Total deferred tax assets ...................... 6,114,000 6,002,000
----------- -----------
Deferred tax liabilities:
Exploration and development expenditures
expensed for tax and capitalized for books 9,424,000 6,002,000
Basis differential in long-term investments . 70,000 --
Total deferred tax liabilities ................. 9,494,000 6,002,000
----------- -----------
Net deferred tax liability ..................... $ 3,380,000 $ --
=========== ===========
The valuation allowance is primarily related to net operating loss
carryforwards for a
37
consolidated subsidiary which may not be realized due to certain limitations.
As of December 31, 1996, the Company has approximately $17.3 million of
net operating loss carryforwards which begin to expire in 2006. The net
operating loss carryforward assumes that certain items, primarily intangible
drilling costs and delay rentals, 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.
7. STOCKHOLDERS' EQUITY
COMMON STOCK
In July 1995, the Company completed a public offering of 3,795,000
shares of common stock at a price of $10.50 per share. The total proceeds of the
offering, net of issuance costs, received by the Company were approximately
$36,876,000. The Company used a portion of these funds to retire $2,800,000 in
long-term debt and the remainder of the proceeds is being used for additional
drilling and other exploration and development activities and for other general
corporate purposes.
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 (See Note 10). The acquired stock will be used to fund
the Company's future contributions to the employees' 401(k) plan.
WARRANTS
The Company had the following warrants to purchase TMRC common stock
outstanding at December 31, 1996:
NUMBER OF
SHARES UNDER EXERCISE
WARRANTS WARRANT PRICE EXPIRATION DATE
Executive Officers 1,428,000 $5.85 *
General Partner 291,522 $0.65 December 31, 2015
* A date one year following the date on which the respective warrant holder
ceases to be an employee of the Company.
38
During 1994, the following warrants were exercised for which TMRC
received $1,870,000, net of stock issuance costs:
NUMBER OF
SHARES UNDER EXERCISE
WARRANT HOLDER WARRANTS WARRANT PRICE
- -------------- -------- ------------ --------
Kayne Anderson Group Kayne Anderson 750,000 $ 1.00
Martin Lacoff Class B 150,000 $ 5.85
John Walker Class B 52,088 $ 5.85
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 new Warrants expire one year following
the date on which the respective officer ceases to be an employee of the
Company. The new Warrants further provide that in the event the officer's
employment with the Company is terminated by the Company without "cause" or by
the officer for "good reason," the officer will have the option to require the
Company to purchase some or all of the Warrants held by the officer for an
amount per Warrant equal to the difference between the exercise price, $5.85 per
share, and the then prevailing market price of the common stock. The Company may
satisfy this obligation with shares of its common stock.
39
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, 1996 and 1995, 465,561 and 691,311 shares,
respectively, were available for grant under the plans. A summary of option
transactions follows:
WEIGHTED
NUMBER OF AVERAGE
SHARES EXERCISE PRICE
Outstanding at December 31, 1993 574,750 $ 6.72
Granted 15,000 $ 13.13
Exercised -- --
Canceled (1,500) $ 8.38
--------- -------
Outstanding at December 31, 1994 588,250 $ 6.88
Granted 209,750 $ 10.64
Exercised (41,939) $ 3.64
Canceled (14,311) $ 8.05
--------- -------
Outstanding at December 31, 1995 741,750 $ 8.10
Granted 199,750 $ 9.49
Exercised (17,150) $ 7.86
Canceled (29,250) $ 10.33
--------- ------
Outstanding at December 31, 1996 895,100 $ 8.34
========= =======
Range of exercise prices for option
outstanding at December 31, 1996:
$ 1.13 - $ 5.63 188,000 $ 4.53
$ 8.13 - $ 10.38 602,100 $ 8.92
$ 11.00 - $ 15.63 105,000 $ 11.86
--------- ------
Outstanding at December 31, 1996 895,100 $ 8.34
========= =======
Shares exercisable:
December 31, 1996 598,159 $ 7.55
December 31, 1995 401,439 $ 7.12
December 31, 1994 287,875 $ 6.24
The weighted average remaining contractual life of options outstanding
at December 31, 1996 was seven years.
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 6.5%; dividend yield of 0%;
volatility factors of the expected market price of the Company's common stock of
0.30 and 0.35 for 1996 and
40
1995, respectively; and a weighted-average expected life of five years. These
assumptions resulted in a weighted average grant date fair value of $3.49 and
$4.34 for options granted in 1996 and 1995, 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 1996 and 1995 results in pro forma net income of $6,685,000 and $1,991,000,
respectively, and pro forma net income per share of $0.43 and $0.15,
respectively.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options. In addition,
because SFAS 123 is applicable only to options granted subsequent to December
31, 1994, the pro forma information does not reflect the pro forma effect of all
previous stock option grants of the Company, and thus the pro forma information
is not necessarily indicative of future amounts until SFAS 123 is applied to all
outstanding stock options.
DEFERRED COMPENSATION
In July 1996, the Company through the Compensation Committee of the
Board of Directors granted to Messrs. Reeves and Mayell (the Company's Chief
Executive Officer and President, respectively) rights to the Company's common
stock in lieu of cash compensation pursuant to the Company's Long-Term Incentive
Plan. Under such grants, Messrs. Reeves and Mayell each elected to defer
$180,000 and $400,000 of their compensation for 1996 and 1997, respectively. The
Company also granted to each officer a 100% matching deferral, which is subject
to a one-year vesting. Under the terms of the grants, the employee and matching
deferrals are allocated to a common stock account in which units are credited to
the accounts of the officer based on the number of shares that could be
purchased at the market price of the common stock at June 28, 1996, for the
deferrals of 1996 and at December 31, 1996, for the deferrals of 1997. At
December 31, 1996, the plan had reserved 250,000 shares of common stock for
future issuance and 80,004 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 $647,000
relating to these grants is reflected as a general and administrative expense.
8. 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.
41
TMRC matches 25% of each employee's contribution up to 10% of annual
compensation subject to certain limitations as outlined in the Plan. In
addition, TMRC may make discretionary contributions which are allocable to
participants in accordance with the Plan. Contributions by TMRC into the Plan
for 1996, 1995 and 1994 were approximately $118,000, $107,000 and $90,000,
respectively.
9. MAJOR CUSTOMERS
Major customers for TMRC for the years ended December 31, 1996, 1995 and
1994 were as follows (based on purchases of oil and gas as a percent of total
oil and gas sales):
YEAR ENDED DECEMBER 31,
CUSTOMER 1996 1995 1994
-------- ---- ---- ----
Phillips Petroleum Company 49% 63% 96%
Koch Oil Company 26% 23% --
Tauber Oil Company 13% 9% --
Plains Marketing and Transportation 11% 5% --
Phillips Petroleum Company ("Phillips") is the sole purchaser of TMRC's
natural gas production from the Chocolate Bayou Field under a natural gas
contract entered into pursuant to a farmout agreement with Phillips.
10. RELATED PARTY TRANSACTIONS
Texas Oil Distribution and Development, Inc. and Sydson Energy, Inc.,
entities controlled by Joseph A. Reeves, Jr. and Michael J. Mayell,
respectively, collectively invested approximately $1,660,000, $625,000 and
$900,000 for the years ended December 31, 1996, 1995 and 1994, 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
$83,000 and $803,000 as of December 31, 1996 and 1995, respectively, which have
been netted by amounts owed to them from the Company (See Note 7 regarding stock
purchase from Messrs. Reeves and Mayell). Texas Oil Distribution and
Development, Inc. and Sydson Energy, Inc. 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, 1996, 1995 and 1994 and received fees
of approximately $56,000, $68,000 and $121,000, 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.
In the interest of retaining talented technical personnel, the Company
has adopted an incentive compensation system for its senior geologists,
geophysicists and executives that relates each individual's compensation to the
success of the Company's exploration activities by providing compensation based
on results of the prospects.
42
11. SUPPLEMENTAL CASH FLOWS INFORMATION
FOR THE YEAR ENDED DECEMBER 31, 1996 1995 1994
------------------------------------------------------------------------------
(in thousands)
Cash Payments:
Interest $ 3 $ 96 $ 1
Income taxes $ (26) $ 37 $ 78
Non-Cash Operating and Financing Activities:
Accounts receivable $(1,080) -- --
Treasury stock (See Note 7) $ 1,080 -- --
43
12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The following is a summary of the unaudited quarterly results of
operations for the years ended December 31, 1996 and 1995.
QUARTER ENDED
MAR. 31 JUNE 30 SEPT. 30 DEC. 31 TOTAL
------- ------- -------- ------- -----
(in thousands, except per share amounts)
1996
Revenues ................... $5,079 $ 5,628 $ 6,856 $ 8,824 $26,387
====== ======= ========= ======= =======
Results of operations from
exploration and production
activities (1) ........... $2,186 $ 3,015 $ 3,550 $ 5,191 $13,942
====== ======= ========= ======= =======
Net income ................. $1,375 $ 1,531 $ 1,771 $ 2,457 $ 7,134
====== ======= ========= ======= =======
Net income per
common and common
equivalent share ......... $ 0.09 $ 0.10 $ 0.11 $ 0.15 $ 0.45
====== ======= ========= ======= =======
1995
Revenues ................... $1,917 $ 2,771 $ 3,093 $ 4,486 $12,267
====== ======= ========= ======= =======
Results of operations from
exploration and production
activities (1) ........... $ 885 $ 1,206 $ 1,026 $ 1,784 $ 4,901
====== ======= ========= ======= =======
Net income ................. $ 92 $ 231 $ 622 $ 1,208 $ 2,153
====== ======= ========= ======= =======
Net income per
common and common
equivalent share ......... $ 0.01 $ 0 .02 $ 0.04 $0 .08 $ 0.16
====== ======= ========= ======= =======
(1) Results of operations from exploration and production activities, which
approximate gross profit, are computed as operating revenues less lease
operating expenses, severance taxes and depletion.
44
TEXAS MERIDIAN RESOURCES CORPORATION AND SUBSIDIARIES
CONSOLIDATED SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION
(UNAUDITED)
The following information is being provided as supplemental information
in accordance with certain provisions of SFAS No. 69, "Disclosures about Oil and
Gas Producing Activities." Expenditures for oil and natural gas properties
attributable to TMRC for the years ended December 31, 1996, 1995 and 1994 were
primarily to acquire, explore and develop oil and natural gas properties.
COSTS INCURRED IN OIL AND NATURAL GAS PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES ARE SUMMARIZED BELOW:
YEAR ENDED DECEMBER 31,
1996 1995 1994
(in thousands)
Costs incurred during the year: (1)
Property acquisition costs (2) $ 3,726 $ 1,701 $ 1,212
Exploration .................. 34,527 19,223 13,004
Development .................. -- 1,957 2,423
------- ------- -------
$38,253 $22,881 $16,639
======= ======= =======
(1) Costs incurred during the years ended December 31, 1996, 1995 and 1994
include general and administrative costs related to acquisition,
exploration and development of oil and natural gas properties, net of
third party reimbursements, of $1,602,000, $1,497,000 and, $1,160,000,
respectively.
(2) All property acquisition costs are related to unproved property.
CAPITALIZED COSTS RELATING TO OIL AND NATURAL GAS PRODUCING ACTIVITIES:
DECEMBER 31,
1996 1995
(in thousands)
Capitalized costs ... $ 92,902 $ 54,649
Accumulated depletion (17,654) (9,132)
-------- --------
Net capitalized costs $ 75,248 $ 45,517
======== ========
The leasehold costs which are excluded from the depletion base consist
primarily of acreage acquisition costs and related geological and geophysical
costs. For the years ended December 31, 1996 and 1995, costs of $29,718,000 and
$16,950,000, respectively, were excluded from the depletion base. These costs
are expected to be evaluated within the next three years.
45
RESULTS OF OPERATIONS FOR OIL AND NATURAL GAS PRODUCING ACTIVITIES:
YEAR ENDED DECEMBER 31,
1996 1995 1994
(in thousands)
Oil and natural gas sales ................... $ 25,107 $ 11,224 $ 7,466
Oil and natural gas operating costs ......... (981) (683) (227)
Production and ad valorem taxes ............. (1,661) (917) (694)
Depletion ................................... (8,523) (4,723) (2,890)
-------- -------- -------
13,942 4,901 3,655
Income tax expense .......................... (3,380) -- --
-------- -------- -------
Income from oil and natural gas producing
activities (excluding interest expense and
general and administrative expenses) ..... $ 10,562 $ 4,901 $ 3,655
======== ======== =======
Depletion expense per MCFE .................. $ 1.01 $ 0.86 $ 0.81
======== ======== =======
PROVED RESERVES
The following table sets forth the net proved reserves of TMRC as of
December 31, 1996, 1995 and 1994, and the changes therein during the years then
ended. The reserve information was provided by Ryder Scott Company Petroleum
Engineers. All of TMRC's oil and natural gas producing activities are located in
the United States.
PROVED RESERVES: ................... OIL (BBLS) GAS (MCF)
BALANCE AT DECEMBER 31, 1993 ....... 186,015 12,512,000
Production ................. (62,574) (3,176,000)
Revisions .................. 8,102 1,166,000
Discoveries and extensions . 464,272 5,833,000
---------- -----------
BALANCE AT DECEMBER 31, 1994 ....... 595,815 16,335,000
Production ................. (219,421) (4,195,136)
Revisions .................. 152,272 10,338,134
Discoveries and extensions . 751,813 1,612,002
---------- -----------
BALANCE AT DECEMBER 31, 1995 ....... 1,280,479 24,090,000
Production ................. (477,824) (5,567,506)
Revisions .................. 421,202 (1,641,694)
Discoveries and extensions . 3,300,353 8,487,200
---------- -----------
BALANCE AT DECEMBER 31, 1996 ....... 4,524,210 25,368,000
========== ===========
PROVED DEVELOPED RESERVES: ......... OIL (BBLS) GAS (MCF)
Balance at December 31, 1996 2,704,799 24,458,000
Balance at December 31, 1995 1,276,936 23,948,000
Balance at December 31, 1994 582,722 15,680,000
Balance at December 31, 1993 143,492 10,738,000
46
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS RELATING TO PROVED OIL AND GAS RESERVES
The information that follows has been developed pursuant to procedures
prescribed by SFAS No. 69 and utilizes reserve and production data estimated by
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.
The estimated discounted future net cash flows from estimated proved
reserves are based on prices and costs as of the date of the estimate unless
such prices or costs are contractually determined at such date. Actual future
prices and costs may be materially higher or lower. Actual future net revenues
also will be affected by factors such as actual production, supply and demand
for oil and natural gas, curtailments or increases in consumption by natural gas
purchasers, changes in governmental regulations or taxation and the impact of
inflation on costs. Future income tax expense has been reduced for the effect of
available net operating loss carryforwards.
AT DECEMBER 31,
1996 1995 1994
---- ---- ----
(in thousands)
Future cash flows ..................... $ 226,425 $ 79,847 $ 39,892
Future production and development costs (34,120) (11,823) (6,688)
Future income tax expense ............. (51,209) (10,222) (2,111)
--------- -------- --------
Future net cash flows ................. 141,096 57,802 31,093
Discount to present value at
10 percent annual rate ............. (30,086) (11,501) (4,946)
--------- -------- --------
Standardized measure of discounted
future net cash flows .............. $ 111,010 $ 46,301 $ 26,147
========= ======== ========
47
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, 1996, 1995 and
1994.
1996 1995 1994
(in thousands)
BALANCE AT BEGINNING OF PERIOD ...................... $ 46,301 $ 26,147 $ 23,311
--------- -------- --------
SALES OF OIL AND GAS,
NET OF PRODUCTION COSTS ......................... (22,465) (9,624) (6,545)
REVISIONS TO RESERVES PROVED
IN PRIOR YEARS:
Changes in prices, and production costs .......... 36,690 5,238 (7,640)
Revisions of previous quantity estimates ......... 2,708 18,642 1,628
ADDITIONS TO PROVED RESERVES:
Current year discoveries, extensions
and improved recovery ........................ 67,079 10,352 11,263
Changes in estimated future
development costs ............................. (1,304) (4,032) (1,537)
Development cost incurred during
the period that reduce future development costs 2,539 5,137 --
Accretion of discount ............................ 4,630 2,615 2,331
Net change in income taxes ....................... (30,826) (4,569) 2,029
Change in production rates (timing) and other .... 5,658 (3,605) 1,307
--------- -------- --------
Net increase ........................................ 64,709 20,154 2,836
--------- -------- --------
BALANCE AT END OF PERIOD ............................ $ 111,010 $ 46,301 $ 26,147
========= ======== ========
48
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, 1997.
49
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) Schedule VIII - Valuation and Qualifying Accounts and
Reserves
All other schedules are omitted as they are not
applicable, not required or the required information is
included in the consolidated financial statements or
notes thereto.
3. Exhibits:
3.1 Second Amended and Restated Articles of Incorporation of
the Company (incorporated by reference to Exhibit 3 of
the Company's Annual Report on Form 10-K for the year
ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
3.2 Bylaws of the Company, as amended (incorporated by
reference to Exhibit 3 of the Company's Annual Report on
Form 10-K for the year ended December 31, 1991, as
amended by the Company's Form 8 filed on March 4, 1993).
4.1 Specimen Common Stock Certificate (incorporated by
reference to Exhibit 4.1 of the Company's Registration
Statement on Form S-1, as amended (Reg. No. 33-65504)).
4.2 Common Stock Purchase Warrant of the Company dated
October 16, 1990, issued to Joseph A. Reeves, Jr.
(incorporated by reference to Exhibit 10.8 of the
Company's Annual Report on Form 10-K for the year ended
December 31, 1991, as amended by the Company's Form 8
filed March 4, 1993).
4.3 Common Stock Purchase Warrant of the Company dated
October 16,
50
1990, issued to Michael J. Mayell (incorporated by
reference to Exhibit 10.9 of the Company's Annual Report
on Form 10-K for the year ended December 31, 1991, as
amended by the Company's Form 8 filed March 4, 1993).
*4.4 Registration Rights Agreement dated October 16,
1990, among the Company, Joseph A. Reeves, Jr. and
Michael J. Mayell (incorporated by reference to Exhibit
10.7 of the Company's Registration Statement on Form
S-4, as amended (Reg. No. 33-37488)).
*4.5 Warrant Agreement dated June 7, 1994, between the
Company and Joseph A. Reeves, Jr. (incorporated by
reference to Exhibit 4.1 of the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30,
1994.)
*4.6 Warrant Agreement dated June 7, 1994, between the
Company and Michael J. Mayell (incorporated by reference
to Exhibit 4.1 of the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1994.)
*4.7 Form of 1993 Non-Employee Director Stock Option
Agreement (incorporated by reference to Exhibit 4.9 of
the Company's Registration Statement on Form S-8 (Reg.
No. 33-86788)).
4.8 Credit Agreement dated as of May 16, 1995, by and among
Texas Meridian Resources Exploration, Inc., the Company
and Chemical Bank, as lender and agent (incorporated by
reference to Exhibit 4.8 of the Company's Registration
Statement on Form S-3, as amended (Reg. No. 33-92584)).
4.9 First Amendment dated as of January 19, 1996, to the
Credit Agreement dated as of May 16, 1995, by and among
Texas Meridian Resources Exploration, Inc., the Company
and Chemical Bank, as lender and agent (incorporated by
reference to Exhibit 4.8 of the Company's Annual Report
on Form 10-K for the year-ended December 31, 1995).
*10.1 Texas Meridian Resources Corporation Directors'
Stock Option Plan (incorporated by reference to Exhibit
10.5 of the Company's Annual Report on Form 10-K for the
year ended December 31, 1991, as amended by the
Company's Form 8 filed March 4, 1993).
*10.2 Texas Meridian Resources Corporation 1990 Stock
Option Plan (incorporated by reference to Exhibit 10.6
of the Company's Annual Report on Form 10-K for the year
ended December 31, 1991, as amended by the Company's
Form 8 filed March 4, 1993).
*10.3 Employment Agreement dated August 18, 1993, between
the Company and Joseph A. Reeves, Jr.
*10.4 Employment Agreement dated August 18, 1993, between
the Company and Michael J. Mayell.
*10.5 Form of Indemnification Agreement between the
Company and its executive officers and directors
(incorporated by reference to Exhibit
51
10.6 of the Company's Annual Report on Form 10-K for the
year ended December 31, 1994).
*10.6 Texas Meridian Resources Corporation 1995 Long-Term
Incentive Plan.
*10.7 Deferred Compensation agreement dated July 31,
1996, between the Company and Joseph A. Reeves, Jr.
(incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1996).
*10.8 Deferred Compensation agreement dated July 31,
1996, between the Company and Michael J. Mayell
(incorporated by reference to Exhibit 10.1 of the
Company's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1996).
21. Subsidiaries of the Company.
22.1 Consent of Ernst & Young LLP.
22.2 Consent of Ryder Scott Company.
27.1 Financial Data Schedule
* Management contract or compensation plan.
(b) Reports on Form 8-K.
No reports on Form 8-K have been filed by the Registrant during
the fourth quarter of the year ended December 31, 1996.
52
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.
TEXAS MERIDIAN RESOURCES CORPORATION
BY: /s/ JOSEPH A. REEVES, JR.
Chief Executive Officer
(Principal Executive Officer)
Director and Chairman of the Board
Date: March 5, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
NAME TITLE DATE
BY: /s/ JOSEPH A. REEVES, JR. Chief Executive Office March 5, 1997
Joseph A. Reeves, Jr. (Principal Executive Officer)
Director and Chairman
of the Board
BY: /s/ MICHAEL J. MAYELL President and Director March 5, 1997
Michael J. Mayell
BY: /s/ LLOYD V. DE LANO Vice President - March 5, 1997
Lloyd V. DeLano Director of Accounting
(Chief Financial and Accounting Officer)
BY: /s/ JOE E. KARES Director March 5, 1997
Joe E. Kares
53
TEXAS MERIDIAN RESOURCES CORPORATION AND SUBSIDIARIES
SCHEDULE VIII
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(in thousands)
BALANCE AT CHARGED TO CHARGED BALANCE
BEGINNING COSTS AND TO AT END
DESCRIPTION OF YEAR EXPENSES OTHER DEDUCTIONS OF YEAR
Allowance for doubtful receivables:
Year Ended:
December 31, 1996 $ 121 $ -- $ -- $ -- $ 121
========= ========= ========= ========= ========
December 31, 1995 $ 121 $ -- $ -- $ -- $ 121
========= ========= ========= ========= ========
December 31, 1994 $ 121 $ -- $ -- $ -- $ 121
========= ========= ========= ========= ========