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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________
FORM 10-K
_________________________
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to _____________
Commission file number: 000-21843
TITAN EXPLORATION, INC.
(Exact name of Registrant as Specified in its Charter)
Delaware 75-2671582
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 West Texas, Suite 500
Midland, Texas 79701
(Address of principal executive offices) (Zip Code)
(915) 498-8600
(Registrant's telephone number,
including area code)
--------------------------------
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
-------------------------------- --------------------------------
None None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
(Title of Class)
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
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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. [ ]
As of March 1, 1999, the Registrant had outstanding 37,934,675 shares of
Common Stock. The aggregate market value of the Common Stock held by non-
affiliates of the Registrant, based upon the closing sale price of the Common
Stock on March 1, 1999, as reported on the Nasdaq National Market, was
approximately $105,000,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1999 Annual
Meeting of Stockholders to be held on or about May 26, 1999, are incorporated by
reference in Part III of this Form 10-K. Such definitive proxy statement will
be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 1998.
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TABLE OF CONTENTS
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PART I
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Item 1. Business............................................................................. 1
Item 2. Properties........................................................................... 10
Item 3. Legal Proceedings.................................................................... 14
Item 4. Submission of Matters to a Vote of Security Holders.................................. 15
Executive Officers of the Registrant................................................. 15
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................ 17
Item 6. Selected Financial Data.............................................................. 18
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 20
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................... 36
Item 8. Financial Statements and Supplementary Data.......................................... 38
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 39
PART III
Item 10. Directors and Executive Officers of the Registrant................................... 40
Item 11. Executive Compensation............................................................... 40
Item 12. Security Ownership of Certain Beneficial Owners and Management....................... 40
Item 13. Certain Relationships and Related Party Transaction.................................. 40
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...................... 41
Glossary of Oil and Gas Terms........................................................ 46
Signatures........................................................................... 49
Index to Consolidated Financial Statements........................................... F-1
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TITAN EXPLORATION, INC.
1998 ANNUAL REPORT ON FORM 10-K
PART I
ITEM 1. BUSINESS
Titan Exploration, Inc. (the "Company") is an independent energy company
engaged in the exploitation, development, exploration and acquisition of oil and
gas properties located in the Permian Basin of West Texas and southeastern New
Mexico, south Texas, Gulf Coast region and Gulf of Mexico. Since our inception
in March 1995, we have increased our reserves, production and cash flow through
(i) the development and exploration of our properties and (ii) the acquisition
of producing properties that provide exploitation, development and exploration
potential.
The Company is incorporated in the State of Delaware, its principal executive
offices are located at 500 West Texas, Suite 500, Midland, Texas 79701, and its
telephone number is (915) 498-8600.
Recent Developments
Asset Divestiture
In the fourth quarter of 1998, the Company approved a plan to dispose of non-
strategic assets, including its Gulf of Mexico, Gulf Coast and certain Permian
Basin assets. The Company's reason to dispose of these assets varied depending
on the portfolio of assets being considered. The disposition will allow the
Company to (a) realize full value for certain assets whose value is not fully
reflected in the public valuation of the Company in the capital markets, (b)
redeploy capital to higher return projects or acquisitions, (c) invest in
projects that will accelerate cash flow to the Company, (d) eliminate certain
administrative costs and (e) reduce the Company's debt obligations. The Company
will not ultimately sell assets for which adequate consideration is not offered.
Subject to adequate consideration, the Company expects to dispose of these
assets by the end of the third quarter of 1999.
Paragon Prospect
The Company has entered into an exploitation joint venture with the Permian
Gas Business Unit of Mobil Exploration & Producing U.S. Inc. ("MEPUS"). The new
venture, named Paragon, will conduct a proprietary 3-D seismic program covering
approximately 600 square miles in two phases of 300 square miles each in
Culberson and Reeves counties in the Permian Basin of West Texas.
The venture has acquired over 350,000 net acres of leasehold interests to
date. The Company owns a 50% working interest in the leasehold acreage and was
substantially carried in the acquisition of the leasehold interest.
Additionally, the Company is substantially carried by MEPUS in the acquisition
of the Phase I seismic program and, if the parties elect to acquire the Phase II
seismic program, MEPUS will pay approximately 75% of the costs to acquire this
additional 300 miles. The Company will pay 25% of the costs of the Phase II
seismic program and will own, along with MEPUS, the proprietary 3-D seismic data
over the entire 600 square miles. Once the Company has recovered its share of
costs paid, MEPUS will share in the Company's revenues until such time as it has
recovered its share of costs. The costs of all wells drilled and subsequent
acreage acquired will be shared equally by MEPUS and the Company. Subsequently,
MEPUS and the Company will share all costs and production equally.
To date, approximately 200 miles of the Phase I seismic program has been
acquired. Based upon the results of the initial phase, the parties may commit
to the Phase II seismic program which will cover the remaining 300 square miles.
It is anticipated that the acquisition of all 600 square miles of seismic data
will be completed by mid-2000. Upon completion, the program should represent
one of the largest proprietary contiguous 3-D seismic acquisition programs
conducted within the onshore lower 48 states. Successful prospect development
is expected to result in drilling activity beginning late in the first half of
1999 and continue as quality prospects are identified.
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Offshore Activities
In the Gulf of Mexico, the Company has drilled the Vermilion Block 253 A-1
well to a depth of 11,270 feet. Mud log shows supported by open hole logs and
sidewall cores indicate potential oil and gas zones from at least 16 pay zones.
Although the Company is enthusiastic about these shows and the potential of this
discovery, production testing and additional drilling is necessary before the
Company can more accurately determine the effect on future cash flows and
reserves. The Company is the operator and has a 50% working interest (38.42%
net revenue interest) in this block. The Company anticipates that it will drill
subsequent wells to test deeper horizons which are highly productive in the
area. This property and the Company's other Gulf of Mexico interests are
included in its asset divestiture plan.
The Company drilled the Vermilion Block 252 F-4 and has completed the well as
a dual flowing well. The gas condensate zone has been completed and the well is
flowing approximately 600 barrels of condensate per day and 500 Mcf of gas per
day. The oil zone is awaiting pipeline construction to an adjacent platform and
oil production is expected to commence during mid-1999. The Company is the
operator of the block and owns a 41.25% working interest (31.49% net revenue
interest).
Onshore Activities
The Eller No. 1 has been completed in the deep, downdip overpressured Austin
Chalk. The well is currently producing 3,800 Mcf of gas per day to the
Company's interest. The Company owns a 33% working interest in this non-
operated well. The Company recently spudded three additional wells (Dierking
No. 1, Titan No. 1 and Rains Trust No. 1) in the area with varying ownership
percentages. Subsequently, the Titan No. 1 was determined to be a dry hole.
The Company's net cost is approximately $1.7 million.
The Habanero No. 1, the Company's first Webb County, Texas well, is currently
flowing at a rate of approximately 155 Mcf of gas per day. The Company has a
50% working interest in the well. The rate and pressure are down from an
initial rate of approximately 2.5 MMcf of gas per day and significantly higher
flowing tubing pressures. The Company is currently considering additional
testing to determine whether stimulation might achieve greater production
levels. While the Company was disappointed in the results of this first well on
its 200,000 acres, the presence of natural gas coupled with good reservoir
quality supported additional drilling activities. In November 1998, the Company
spudded a second well, the Jalapeno No. 1, to further test the acreage. The well
did not discover any economical reserves. Primarily as a result of the drilling
activities the Company has impaired a significant portion of the Webb County
acreage. The Company believes there still is potential in the future but has no
current drilling activity planned.
Other
The Company recently reduced its staff in its Gulf Coast and Gulf of Mexico
regions as part of integrating the December 1997 OEDC and Carrollton
acquisitions, described below, and as part of its plans to divest non-strategic
assets in these regions. The Company will further reduce its administrative
costs in these regions upon completion of the dispositions. However, the full
impact of these cost reductions may not be visible until the third quarter of
1999.
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Overview
The Company's strategy is to grow reserves, production and net income per
share through (i) the exploitation and development of its reserve base, (ii) the
acquisition of producing properties that provide significant development and
exploratory drilling potential, (iii) the exploration for oil and gas reserves,
(iv) capitalization on advanced technology to identify, explore and exploit
projects, (v) financial flexibility, and (vi) a low overhead and operating cost
structure.
As of December 31, 1998, the Company estimated net proved reserves of
approximately 23.0 MMBbls of oil and 332.0 Bcf of natural gas, or an aggregate
of 470.0 Bcfe with a PV-10 of $242.2 million. Approximately 60% of these
reserves were classified as proved developed. The Company acquired, explored
for and developed its reserves for an average reserve replacement cost of
approximately $.77 per Mcfe from inception of the Company through December 31,
1998.
The Company prefers to acquire properties over which it can exercise operating
control. As of December 31, 1998, the Company operated 825 gross productive
wells (740 net productive wells) and these operated properties represented
approximately 84% of its proved developed PV-10 and 83% of the Company's PV-10
attributable to proved reserves as of such date. The Company's emphasis on
controlling the operation of its properties enables the Company to better manage
expenses, capital allocation and other aspects of development and exploration.
The Company's proved oil and gas properties are located in more than 90 fields
in the Permian Basin and in 24 lease blocks in the Gulf of Mexico and, to a
lesser extent, in north and south Louisiana. Approximately 56% of the Company's
PV-10 of total proved reserves is concentrated in 7 principal fields located in
the Permian Basin. The Permian Basin is characterized by complex geology with
numerous known producing horizons and provides significant opportunities to
increase reserves, production and ultimate recoveries through development,
exploratory and horizontal drilling, recompletions, secondary and tertiary
recovery methods, and use of 3-D seismic and other advanced technologies.
The Company was formed in 1996 for the purpose of becoming the holding company
for Titan Resources, L.P. ("TRLP") pursuant to the terms of an exchange
agreement dated September 30, 1996. TRLP was formed in March 1995 and grew
primarily through acquisitions of oil and gas properties and the exploitation of
those properties. Under the exchange agreement, effective September 30, 1996,
(i) the limited partners of TRLP transferred all their limited partnership
interests to the Company in exchange for an aggregate of 19,318,199 shares of
Common Stock, and (ii) the shareholders of Titan Resources I, Inc., a Texas
corporation that is the general partner of TRLP, transferred all the issued and
outstanding stock of that corporation to the Company in exchange for an
aggregate of 231,814 shares of Common Stock. These transactions are referred to
as the "Conversion." As a result of the Conversion, Titan Exploration, Inc.
owns, directly or indirectly, all the partnership interests in TRLP and conducts
its active business operations through TRLP. References to the "Company" are to
Titan Exploration, Inc. and its predecessors and subsidiaries, including TRLP.
Acquisitions
The Company's strategy is to make acquisitions with exploitation potential.
The following four paragraphs outline the Company's significant acquisitions
since the inception of the Company.
In December 1995, the Company acquired a concentrated group of Permian Basin
producing oil and gas properties from a large independent Company for a purchase
price of approximately $41.0 million (the "1995 Acquisition"). On October 31,
1996, the Company acquired additional Permian Basin producing properties from a
major integrated company for a purchase price of approximately $136.0 million
(the "1996 Acquisition").
In December 1997, the Company issued 5,486,734 shares of Common Stock in
connection with its acquisition of all of the issued and outstanding shares of
common stock of Offshore Energy Development Corporation ("OEDC"), an independent
energy company that focuses on the acquisition, exploration, development and
production of natural gas and on natural gas gathering, processing and marketing
activities (the "OEDC
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Acquisition"). OEDC's integrated operations are conducted in the Gulf of Mexico,
where OEDC had an interest in 24 lease blocks, all of which are operated by
OEDC.
In December 1997, the Company issued 899,965 shares of Common Stock in
connection with its acquisition of all of the issued and outstanding units of
membership interests in Carrollton Resources, L.L.C., a small independent energy
company engaged in the exploration, development and acquisition of onshore oil
and gas properties located primarily in the Gulf Coast region (the "Carrollton
Acquisition").
In December 1997, the Company completed the acquisition of certain oil and gas
producing properties from Pioneer Natural Resources USA, Inc., a wholly-owned
subsidiary of Pioneer Natural Resources Company ("Pioneer"), for a purchase
price of approximately $55.8 million (the "Pioneer Acquisition").
The Company regularly pursues and evaluates acquisition opportunities
(including opportunities to acquire oil and gas properties or related assets or
entities owning oil and gas properties or related assets and opportunities to
engage in mergers, consolidations or other business combinations with entities
owning oil and gas properties or related assets) and at any given time may be in
various stages of evaluating these opportunities. These stages may take the
form of internal financial and oil and gas property analysis, preliminary due
diligence, the submission of an indication of interest, preliminary
negotiations, negotiation of a letter of intent, or negotiation of a definitive
agreement. While the Company is currently evaluating a number of potential
acquisition opportunities (some of which would be material in size to the
Company), it has not signed a letter of intent with respect to any material
acquisition and currently has no assurance of completing any particular material
acquisition or of entering into negotiations with respect to any particular
material acquisition.
Oil and Gas Marketing and Major Customers
The revenues generated by the Company's operations are highly dependent upon
the prices of, and demand for, oil and gas. The price received by the Company
for its oil and gas production depends on numerous factors beyond the Company's
control including seasonality; the condition of the United States and world
economy, particularly the manufacturing sector; foreign imports; political and
economic conditions in other oil-producing and gas-producing countries; the
actions of OPEC and domestic government regulation, legislation and policies.
Decreases in the prices of oil and natural gas could have a material adverse
effect on the carrying value of the Company's proved reserves and the Company's
revenues, profitability and cash flow. Although the Company is not currently
experiencing any significant involuntary curtailment of its oil or gas
production, market, economic and regulatory factors may in the future materially
affect the Company's ability to sell its oil or gas production.
During, 1998, sales to Enron Corp., and its subsidiaries and affiliates,
Dynegy Inc. and Western Gas Resources, Inc. were approximately 31%, 13% and 13%
of the Company's oil and gas revenues, respectively.
Due to the availability of other markets and pipeline connections, the Company
does not believe that the loss of any single crude oil or gas customer would
have a material adverse effect on the Company's results of operations.
Competition
The oil and gas industry is highly competitive. The Company encounters
competition from other oil and gas companies in all areas of its operations,
including the acquisition of producing properties. The Company's competitors
include major integrated oil and gas companies and numerous independent oil and
gas companies, individuals and drilling and income programs. Many of its
competitors are large, well established companies with substantially larger
operating staffs and greater capital resources than the Company and which, in
many instances, have been engaged in the energy business for a much longer time
than the Company. Such companies may be able to pay more for productive oil and
gas properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or human resources permit. The Company's ability to acquire
additional properties and to discover reserves in the future will be dependent
upon its ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment.
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Operating Hazards and Uninsured Risks
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil and
gas may involve unprofitable efforts, not only from dry wells, but from wells
that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond the Company's control, including title
problems, weather conditions, mechanical problems, compliance with governmental
requirements and shortages or delays in the delivery of equipment and services.
The Company's future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on the Company's
future results of operations and financial condition.
In addition, the Company's use of 3-D seismic requires greater pre-drilling
expenditures than traditional drilling strategies. Although the Company
believes that its use of 3-D seismic will increase the probability of success of
its exploratory wells and should reduce average finding costs through the
elimination of prospects that might otherwise be drilled solely on the basis of
2-D seismic data and other traditional methods, unsuccessful wells are likely to
occur. There can be no assurance that the Company's drilling program will be
successful or that unsuccessful drilling efforts will not have a material
adverse effect on the Company. Although the Company has identified numerous
potential drilling locations, there can be no assurance that such locations will
ever be drilled upon or that oil or gas will be produced from them.
The Company's operations are subject to hazards and risks inherent in drilling
for and producing and transporting oil and gas such as fires, natural disasters,
explosions, encountering formations with abnormal pressures, blowouts,
cratering, pipeline ruptures and spills. Any of the preceding risks can result
in the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to properties of the Company and others. The Company's offshore
operations are also subject to the additional hazards of marine operations such
as severe weather, capsizing and collision.
The Company expects to drill a number of deep vertical and horizontal wells in
the future. The Company's deep and/or horizontal drilling activities involve
greater risk of mechanical problems than other type drilling operations. These
wells may be significantly more expensive to drill than those drilled to date.
The Company maintains insurance against some, but not all, of the risks
described above. The Company may elect to self-insure in circumstances in which
management believes that the cost of insurance, although available, is excessive
relative to the risks presented. The occurrence of an event that is not
covered, or not fully covered, by insurance could have a material adverse effect
on the Company's financial condition and results of operations.
Employees
As of December 31, 1998, the Company had 94 full-time employees, none of whom
is represented by a labor union. Included in the total were 29 administrative
employees located in the Company's office in Midland, Texas, eight of whom are
involved in the management of the Company. The Company considers its relations
with its employees to be good.
Office Facilities
The Company currently leases approximately 50,937 square feet of office space
in Midland, Texas, where its principal offices are located. This office lease
is with an affiliate of Jack Hightower. The Company's principal offices are
leased through March 15, 2002. The Company currently leases approximately 8,433
and 3,420 square feet of office space in The Woodlands, Texas and Baton Rouge,
Louisiana, respectively, where division offices are located.
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Title to Properties
The Company received title opinions relating to properties representing 80% of
the PV-10 of the 1995 Acquisition, 90% of the PV-10 of the 1996 Acquisition and
54% of the PV-10 of the Pioneer Acquisition. The Company's land department and
contract land professionals have reviewed title records of substantially all its
producing properties. The title investigation performed by the Company prior to
acquiring undeveloped properties is thorough but less rigorous than that
conducted prior to drilling, consistent with industry standards. The Company
believes it has satisfactory title to all of its producing properties in
accordance with standards generally accepted in the oil and gas industry. The
Company's properties are subject to customary royalty interests, liens incident
to operating agreements, liens for current taxes and other burdens which the
Company believes do not materially interfere with the use of or affect the value
of such properties. The Company's Credit Agreement is secured by a first lien
on properties that represented at least 80% of the value of the Company's proved
oil and gas properties (based on PV-10 as of December 31, 1998). Presently, the
Company keeps in force its leaseholds for 21% of its net acreage by virtue of
production on that acreage in paying quantities. The remaining acreage is held
by lease rentals and similar provisions and requires production in paying
quantities prior to expiration of various time periods to avoid lease
termination.
Governmental Regulation
The Company's oil and gas exploration, production and related operations are
subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Although the Company believes it is in substantial compliance with all
applicable laws and regulations, because such rules and regulations are
frequently amended or reinterpreted, the Company is unable to predict the future
cost or impact of complying with such laws. Significant expenditures may be
required to comply with governmental laws and regulations and may have a
material adverse effect on the Company's financial condition and results of
operations.
Such regulation requires permits for drilling operations, drilling bonds and
reports concerning operations and imposes other requirements relating to the
exploration and production of oil and gas. Such state and federal agencies have
statutes or regulations addressing conservation matters, including provisions
for the unitization or pooling of oil and gas properties, the establishment of
maximum rates of production from wells, and the regulation of spacing, plugging
and abandonment of such wells.
The Federal Energy Regulatory Commission ("FERC") regulates interstate natural
gas transportation rates and service conditions, which affect the marketing of
gas produced by the Company, as well as the revenues received by the Company for
sales of such production. Since the mid-1980s, FERC has issued a series of
orders, culminating in Order Nos. 636, 636-A and 636-B ("Order 636"), that have
significantly altered the marketing and transportation of gas. Order 636
mandated a fundamental restructuring of interstate pipeline sales and
transportation service, including the unbundling by interstate pipelines of the
sale, transportation, storage and other components of the city-gate sales
services such pipelines previously performed. One of FERC's purposes in issuing
the orders is to increase competition within all phases of the gas industry.
The United States Court of Appeals for the District of Columbia Circuit largely
upheld Order 636, and the Supreme Court has declined to hear the appeal.
Generally, Order 636 has eliminated or substantially reduced the interstate
pipelines' traditional role as wholesalers of natural gas, and has substantially
increased competition and volatility in natural gas markets.
The price the Company receives from the sale of oil and natural gas liquids is
affected by, among other things, the cost of transporting products to market.
Effective January 1, 1995, FERC implemented regulations establishing an indexing
system for transportation rates for oil pipelines, which, generally, would index
such rates to inflation, subject to certain conditions and limitations. The
Company is not able to predict with certainty the effect, if any, of these
regulations on its operations. However, the regulations may increase
transportation costs or reduce wellhead prices for oil and natural gas liquids.
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Environmental Matters
The Company's operations and properties are subject to extensive and changing
federal, state and local laws and regulations relating to environmental
protection including the generation, storage, handling, emission, transportation
and discharge of materials into the environment, and their relation to safety
and health. The recent trend in environmental legislation and regulation
generally is moving toward stricter standards, and this trend will likely
continue. These laws and regulations may require the acquisition of a permit or
other authorization before construction or drilling commences and for certain
other activities; limit or prohibit construction, drilling and other activities
on certain lands lying within wilderness and other protected areas; and impose
substantial liabilities for pollution resulting from the Company's operations.
The permits required for various operations of the Company are subject to
revocation, modification and renewal by issuing authorities. Governmental
authorities have the power to enforce compliance with their regulations, and
violators are subject to fines or injunction, or both. In the opinion of
management, the Company is in substantial compliance with current applicable
environmental laws and regulations, and the Company has no material commitments
for capital expenditures to comply with existing environmental requirements.
Nevertheless, changes in existing environmental laws and regulations or in
interpretations thereof could have a significant material impact on the Company,
as well as the oil and gas industry in general. The Comprehensive Environmental
Response, Compensation, and Liability Act ("CERCLA") and comparable state
statutes impose strict, joint and several liability on owners and operators of
sites and on persons who disposed of or arranged for the disposal of "hazardous
substances" found at such sites. It is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment.
Resource Conservation and Recovery Act ("RCRA") and comparable state statutes
govern the disposal of "solid waste" and "hazardous waste" and authorize the
imposition of substantial fines and penalties for noncompliance. Although
CERCLA currently excludes petroleum from its definition of "hazardous
substance," state laws affecting the Company's operations impose clean-up
liability relating to petroleum and petroleum related products. In addition,
although RCRA classifies certain oil field wastes as "nonhazardous," such
exploration and production wastes could be reclassified as hazardous wastes
thereby making such wastes subject to more stringent handling and disposal
requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990,
as amended ("OPA"), contains numerous requirements relating to the prevention of
and response to oil spills into waters of the United States. For onshore
facilities that may affect waters of the United States, the OPA requires an
operator to demonstrate $10 million in financial responsibility. In addition,
the OPA currently requires persons responsible for "offshore facilities" to
establish $150 million in financial responsibility to cover environmental
cleanup and restoration costs likely to be incurred in connection with an oil
spill in the waters of the United States. On September 10, 1996, Congress passed
legislation that would lower the financial responsibility requirement under OPA
to $35 million, subject to an increase of $150 million if a formal risk
assessment indicates the increase is warranted. The impact of any legislation is
not expected to be any more burdensome to the Company than it will be to other
similarly situated companies involved in oil and gas exploration and production.
OPA imposes a variety of additional requirements on "responsible parties" for
vessels or oil and gas facilities related to the prevention of oil spills and
liability for damages resulting from such spills in waters of the United States.
The "responsible parties" include the owner or operator of an onshore facility,
pipeline, or vessel or the lessee or permittee of the area in which an offshore
facility is located. OPA assigns liability to each responsible party for oil
spill removal costs and a variety of public and private damages from oil spills.
While liability limits apply in some circumstances, a party cannot take
advantage of liability limits if the spill is caused by gross negligence or
willful misconduct or resulted from violation of a federal safety, construction
or operating regulation. If a party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply. OPA establishes a
liability limit for offshore facilities (including pipelines) of all removal
costs plus $75 million. Few defenses exist to the liability for oil spills
imposed by OPA. OPA also imposes other requirements on facility operators, such
as the preparation of an oil spill contingency plan. Failure to comply with
ongoing requirements or inadequate cooperation in a spill event may subject a
responsible party to civil or criminal enforcement actions.
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In addition, the Outer Continental Shelf Lands Act ("OSCLA") authorizes
regulations relating to safety and environmental protection applicable to
lessees and permittees operating in the Outer Continental Shelf ("OCS").
Specific design and operational standards may apply to OCS vessels, rigs,
platforms, pipelines, vehicles and structures. Violations of lease conditions or
regulations issued pursuant to OCSLA can result in substantial civil and
criminal penalties, as well as potential court injunctions curtailing operations
and the cancellation of leases. Such enforcement liabilities can result from
either governmental or private prosecution.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and
strict controls regarding the discharge of produced waters and other oil and gas
wastes into navigable waters. Permits must be obtained to discharge pollutants
into state and federal waters. The FWPCA and analogous state laws provide for
civil, criminal and administrative penalties for any unauthorized discharges of
oil and other hazardous substances in reportable quantities and, along with the
OPA, may impose substantial potential liability for the costs of removal,
remediation and damages. State water discharge regulations and the federal
National Pollutant Discharge Elimination System ("NPDES") permits prohibit or
are expected to prohibit within the next year the discharge of produced water
and sand, and some other substances related to the oil and gas industry, into
coastal waters. Although the costs to comply with zero discharge mandates under
federal or state law may be significant, the entire industry will experience
similar costs and the Company believes that these costs will not have a material
adverse impact on the Company's financial conditions and operations. Some oil
and gas exploration and production facilities are required to obtain permits for
their storm water discharges. Costs may be incurred in connection with treatment
of wastewater or developing storm water pollution prevention plans.
Regulations are currently being developed under federal and state laws
concerning oil pollution prevention and other matters that may impose additional
regulatory burdens on the Company. In addition, the Clean Water Act and
analogous state laws require permits to be obtained to authorize discharge into
surface waters or to construct facilities in wetland areas. With respect to
certain of its operations, the Company is required to maintain such permits or
meet general permit requirements. The Environmental Protection Agency ("EPA")
recently adopted regulations concerning discharges of storm water runoff. This
program requires covered facilities to obtain individual permits, participate in
a group or seek coverage under an EPA general permit. The Company believes that
it will be able to obtain, or be included under, such permits, where necessary,
and to make minor modifications to existing facilities and operations that would
not have a material effect on the Company.
The implementation of new, or the modification of existing, laws or
regulations could have a material adverse effect on the Company. The discharge
of oil, gas or other pollutants into the air, soil or water may give rise to
significant liabilities on the part of the Company to the government and third
parties and may require the Company to incur substantial costs of remediation.
Moreover, the Company has agreed to indemnify sellers of producing properties
purchased in each of its substantial acquisitions against environmental claims
associated with such properties. No assurance can be given that existing
environmental laws or regulations, as currently interpreted or reinterpreted in
the future, or future laws or regulations will not materially adversely affect
the Company's results of operations and financial condition or that material
indemnity claims will not arise against the Company with respect to properties
acquired by the Company.
The Company has acquired leasehold interests in numerous properties that for
many years have produced oil and gas. Although the previous owners of these
interests may have used operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed of
or released on or under the properties. In addition, some of the Company's
properties are operated by third parties over whom the Company has no control.
Notwithstanding the Company's lack of control over properties operated by
others, the failure of the operator to comply with applicable environmental
regulations may, in certain circumstances, materially adversely impact the
Company.
Abandonment Costs
The Company is responsible for payment of plugging and abandonment costs on
the oil and gas properties pro rata to its working interest. Based on its
experience, with the exception of its offshore oil and gas properties, the
Company anticipates that the ultimate aggregate salvage value of lease and well
equipment located on its properties will exceed the costs of abandoning such
properties. There can be no assurance, however, that the
- 8 -
<PAGE>
Company will be successful in avoiding additional expenses in connection with
the abandonment of any of its properties. In addition, abandonment costs and
their timing may change due to many factors including actual production results,
inflation rates and changes in environmental laws and regulations.
The Company establishes reserves, exclusive of salvage value, to provide for
the eventual abandonment of its offshore wells and platforms. Historically, the
actual cost to the Company of physically abandoning its wells has been largely
offset by the proceeds from the sale of the salvaged equipment. There can be no
assurance that an active secondary market in used equipment will continue to
exist at the time that properties are abandoned, or that the regulatory and
other costs of abandoning offshore properties will not increase. See Note 2 of
Notes to Consolidated Financial Statements.
The Company carries a $3 million area-wide abandonment bond with the Mineral
Management Service ("MMS"). The MMS is empowered to require supplemental
abandonment bonds under appropriate circumstances. While the cost to the
Company of these supplemental bonds to date has not been material, no assurance
may be given that the amounts will not increase, or that the availability
thereof will not be restricted.
- 9 -
<PAGE>
ITEM 2. PROPERTIES
Oil and Natural Gas Reserves
The following table summarizes the estimates of the Company's historical net
proved reserves as of December 31, 1998 and 1997, and the present values
attributable to these reserves at such dates. The reserve and present value
data of the Company were prepared by the Company's independent petroleum
consultants.
<TABLE>
<CAPTION>
December 31,
------------------------------
1998 1997
------------ ------------
(dollars in thousands)
<S> <C> <C>
Estimated proved reserves:
Oil (MBbls).................................................... 23,011 30,275
Gas (MMcf)..................................................... 331,970 345,372
MMcfe (6 Mcf per Bbl).......................................... 470,036 527,022
Proved developed reserves as a percentage of proved reserves....... 60% 68%
PV-10 (a).......................................................... $242,170 $435,127
Standardized Measure of Discounted Future Net Cash Flows (b)....... $236,628 $349,050
</TABLE>
____________
(a) The present value of future net revenue attributable to the Company's
reserves was prepared using prices and costs in effect at the end of the
respective periods presented, discounted at 10% per annum on a pre-tax
basis. These amounts reflect the effects of the Company's hedging
activities.
(b) 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%. These amounts reflect the effects of the Company's
hedging activities.
In accordance with applicable requirements of the Securities and Exchange
Commission ("SEC"), estimates of the Company's proved reserves and future net
revenues are made using sales prices and costs estimated to be in effect as of
the date of such reserve estimates and are held constant throughout the life of
the properties (except to the extent a contract specifically provides for
escalation). The average realized prices for the Company's reserves as of
December 31, 1998 were $9.49 per Bbl of oil and $1.57 per Mcf of natural gas,
compared to average realized prices for the Company's reserves as of December
31, 1997 of $16.11 per Bbl of oil and $1.83 per Mcf of natural gas.
Estimated quantities of proved reserves and future net revenues therefrom are
affected by crude oil and natural gas prices, which have fluctuated widely in
recent years. There are numerous uncertainties inherent in estimating oil and
gas reserves and their estimated values including many factors beyond the
control of the producer. The reserve data set forth in this report represents
only estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
As a result, estimates of different engineers, including those used by the
Company, may vary. In addition, estimates of reserves are subject to revision
based upon actual production, results of future development and exploration
activities, prevailing oil and gas prices, operating costs and other factors,
which revisions may be material. Accordingly, reserve estimates are often
different from the quantities of oil and gas that are ultimately recovered and
are highly dependent upon the accuracy of the assumptions upon which they are
based. The Company's estimated proved reserves have not been filed with or
included in reports to any federal agency.
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.
- 10 -
<PAGE>
Subsequent evaluation of the same reserves based upon production history will
result in variations, which may be substantial, in the estimated reserves.
Productive Wells and Acreage
Productive Wells
The following table sets forth the Company's productive wells as of December
31, 1998:
<TABLE>
<CAPTION>
Actual
----------
Gross Net
---------- ----------
<S> <C> <C>
Oil....................................................... 2,109 720
Gas....................................................... 643 251
----- ----
Total Productive Wells.................................... 2,752 971
===== ====
</TABLE>
Productive wells consist of producing wells and wells capable of production,
including gas wells awaiting pipeline connections. Wells that are completed in
more than one producing horizon are counted as one well.
Acreage Data
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned. A net
acre is deemed to exist when the sum of fractional ownership interests in gross
acres equals one. The number of net acres is the sum of the fractional
interests owned in gross acres expressed as whole numbers and fractions thereof.
The following table sets forth the approximate developed and undeveloped acreage
in which the Company held a leasehold mineral or other interest as of December
31, 1998.
<TABLE>
<CAPTION>
Developed Acres Undeveloped Acres Total Acres
--------------- ----------------- -----------
Gross Net Gross Net Gross Net
--------- --------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Total......... 290,012 130,544 757,777 476,064 1,047,789 606,608
</TABLE>
Drilling Activities
The following table sets forth the drilling activity of the Company on its
properties for 1998, 1997 and 1996.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------------------
1998 1997 1996
--------------------- -------------------- ----------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive....................... 8.0 3.6 2.0 1.0 - -
Nonproductive.................... 3.0 2.5 2.0 1.8 1.0 0.2
--- --- --- --- --- ---
Total.......................... 11.0 6.1 4.0 2.8 1.0 0.2
==== === === === === ===
Development Wells:
Productive....................... 22.0 18.8 48.0 17.2 7.0 3.9
Nonproductive.................... 4.0 3.7 6.0 4.5 1.0 0.2
--- --- --- --- --- ---
Total.......................... 26.0 22.5 54.0 21.7 8.0 4.1
==== ==== ==== ==== === ===
</TABLE>
- 11 -
<PAGE>
Net Production, Unit Prices and Costs
The following table presents certain information with respect to oil and gas
production, prices and costs attributable to all oil and gas property interests
owned by the Company for 1998, 1997 and 1996.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------
1998 1997 1996
----------------- ----------------- ----------------
<S> <C> <C> <C>
Production
Oil (MBbls).................................................. 2,492 1,880 714
Gas (MMcf)................................................... 26,731 22,104 5,787
Total (MMcfe)................................................ 41,683 33,385 10,071
Average sales price (a):
Oil (per Bbl)................................................ $ 12.05 $ 18.67 $ 19.16
Gas (per Mcf)................................................ $ 1.60 $ 1.75 $ 1.75
Total (per Mcfe)............................................. $ 1.75 $ 2.21 $ 2.37
Production costs, excluding production and other taxes (per
Mcfe)......................................................... $ .65 $ .48 $ .72
Production and other taxes (per Mcfe).......................... $ .14 $ .17 $ .19
General and administrative costs (per Mcfe).................... $ .22 $ .16 $ .23
Depletion, depreciation and amortization expenses (per Mcfe)... $ .65 $ .60 $ .57
</TABLE>
_____________
(a) Reflects results of hedging activities in 1998, 1997 and 1996.
Transportation, Gathering and Processing Assets (All included in asset
divestiture plan)
Dauphin Island Gathering Partners
The Company owns a 1% interest in Dauphin Island Gathering Partners ("DIGP"),
which owns the Dauphin Island Gathering System (DIGS). DIGS consists of a FERC
regulated offshore transmission system and non-regulated offshore gathering
system which delivers gas to two market outlets. One market outlet is via
delivery of gas to Texas Eastern ("TETCO") at Main Pass Block No. (MP) 164, and
the other outlet is the delivery of gas to a location near Coden in Mobile
County, Alabama where deliveries can be made to each of three pipelines,
(Transco, Florida Gas Transmission, and Koch). DIGS system consists primarily
of 24 inch and 20 inch pipelines. Once the Mobile Bay Processing Plant,
discussed herein, is in service, the transmission system will have the dual
purpose of delivering rich and lean gas streams onshore Alabama. The gathering
system consists primarily of 12 inch pipeline. DIGS has a current throughput
capacity of up to approximately 1,200 MMcf per day, depending on where gas
enters the system, which could be expanded with looping and onshore compression.
At December 1998, DIGS was transporting approximately 500 MMcf per day.
The Company's interest can increase from 1% up to 11.15% when the other
partners of DIGP receives the return of their investment in DIGP plus a moderate
rate of return. The back-in is subject to a reduction from 10.15% to 8.15% if
the Company does not exercise the option to increase its interest in MBPP.
Mobile Bay Processing Partners
The Company owns an .86% interest in Mobile Bay Processing Partners ("MBPP"),
which is constructing the natural gas processing plant. The Company has an
option from certain of the partners of MBPP to purchase an additional 27.9%
interest in MBPP for a 3-year period beginning with the plant start-up, which
would increase its interest to 28.8%. The Mobile Bay Processing Plant is
currently near completion. The plant is scheduled to start up during the first
quarter 1999. At start-up, the plant is expected to process approximately 550
MMcf per day.
- 12 -
<PAGE>
Gulf Coast NGL Pipeline
The Company owns an .86% interest in Gulf Coast NGL Pipeline L.L.C. ("Gulf
Coast") (as a result of its ownership in MBPP), which owns a 16.67% interest in
Tri-States NGL Pipeline, L.L.C. ("Tri-States"), the entity that is constructing
a natural gas liquids pipeline. The Company has an option to purchase an
additional 27.9% interest in Gulf Coast for a 3-year period beginning with the
liquids pipeline start-up, which would bring its total partnership interest to
28.8%. The initial pipeline design capacity for the Tri-States is 80,000 Bbls
per day. This capacity is expandable to 150,000 Bbls per day.
- 13 -
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
The following is a brief description of certain litigation to which the
Company is subject, as a result of assuming the obligations of Offshore Energy
Development Corporation ("OEDC"). The Company believes it has meritorious
defenses to the claims and intends to vigorously defend against such claims.
The Company does not believe that it has a probable and estimable loss with
respect to any such litigation in excess of currently provided reserves, if any.
If such loss becomes probable and estimable, the amount of any recorded
liability could have a material adverse effect on the Company's (i) results of
operations for the period in which such liability is recorded, (ii) consolidated
financial position as a whole and (iii) liquidity and capital resources.
However, the Company does not expect that any such liability will have a
material adverse effect on its consolidated financial position as a whole or on
its liquidity or capital resources. Due to the uncertainties inherent in
litigation, no assurance can be given to the ultimate outcome of these matters.
OEDC and certain of its officers and directors, as well as Natural Gas
Partners, L.P. ("NGP"), the managing underwriters of OEDC's initial public
offering and an analyst from each of the managing underwriters, have been named
as defendants in a suit styled Eric Baron and Edward C. Allen, on behalf of
Themselves and all Others Similarly Situated, v. David B. Strassner, Douglas H.
Kiesewetter, David R. Albin, Natural Gas Partners, L.P., David Garcia, John J.
Myers, Offshore Energy Development Corporation, Morgan Keegan & Company, Inc.
and Principal Securities Inc., which was filed October 20, 1997, in the Texas
State District Court of Harris County, Southern District of Texas. Plaintiffs
motion to have the case remanded to the state court was granted by the federal
judge in April 1998. The suit seeks class certification on behalf of certain
holders of common stock of denied class certification at this time, in deference
to a parallel federal court action, which is described below. The suit alleges
generally that the defendants wrongfully made false or misleading statements or
omissions relating to OEDC's business and prospects in the course of OEDC's
initial public offering and subsequent thereto. The state court suit seeks
rescission of sales of common stock of OEDC and unspecified monetary damages,
including punitive damages.
OEDC and certain of its officers and directors, as well as NGP, have also
been named defendants in a suit styled John W. Robertson, et al. v. David B.
Strassner, Douglas H. Kiesewetter, David R. Albin, Natural Gas Partners, L.P.
and Offshore Energy Development Corporation, which was filed February 6, 1998,
in the United States Southern District of Texas, Houston Division. This suit
mirrors the allegations of the foregoing matter, but adds request for relief
under federal securities laws. It, too, seeks certification of a class of
certain purchasers of common stock OEDC. The suit seeks compensatory damages,
including rescissory damages, where applicable.
Discovery on the two previously discussed cases has commenced. A mediation
hearing, of all parties, has been set for April 20, 1999.
The Company is involved in other various claims and legal actions arising in
the ordinary course of business. In the opinion of management, the ultimate
disposition of these matters will not have a material adverse effect on the
Company's financial position, results of operations or liquidity.
- 14 -
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) Inapplicable.
(b) Inapplicable.
(c) Inapplicable.
(d) Inapplicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General
Instruction G(3) to Form 10-K, the following information is included in Part I
of this report.
The following table sets forth certain information concerning the executive
officers of the Company as of December 31, 1998:
<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<S> <C> <C>
Jack D. Hightower.................. 50 President and Chief Executive Officer
George G. Staley................... 64 Executive Vice President, Exploration
Rodney L. Woodard.................. 43 Vice President, Engineering
Thomas H. Moore.................... 54 Vice President, Business Development
Dan P. Colwell..................... 54 Vice President, Land
William K. White................... 56 Vice President, Finance and Chief Financial Officer
John L. Benfatti................... 53 Vice President, Accounting and Controller
Susan D. Rowland................... 38 Vice President, Administration and Corporate Secretary
</TABLE>
Set forth below is a description of the backgrounds of each executive officer
of the Company, including employment history for at least the last five years.
Jack D. Hightower has served as President, Chief Executive Officer and Chairman
of the Board of Directors of the Company since he founded the Company in March
1995. Prior to founding the Company, from 1986 to January 1996, Mr. Hightower
served as Chairman of the Board and Chief Executive Officer of United Oil
Services, Inc., a complete oil field service Company serving customers in the
Permian Basin. From 1978 to 1995, Mr. Hightower served as Chairman of the Board
and President of Amber Energy, Inc., a Company formed to identify oil and gas
exploration prospects. From 1991 to 1994, Mr. Hightower served as Chairman of
the Board, Chief Executive Officer and President of Enertex, Inc., which served
as the operator of record for several oil and gas properties involving Mr.
Hightower and other nonoperators, including Selma International Investment
Limited. Since 1990, Mr. Hightower has served on the Board of Directors of
Texas Commerce Bank, N.A., Midland.
George G. Staley has served as Executive Vice President, Exploration and
Director of the Company since its formation. From 1975 until 1995, Mr. Staley
served as President and Chief Executive Officer of Staley Gas Co., Inc. and
Staley Operating Co., which are oil and gas exploration and operating companies.
Rodney L. Woodard has served as Vice President, Engineering for the Company
since its formation. From 1985 to 1995, Mr. Woodard served as Vice President of
Selma International Investment Limited.
Thomas H. Moore has served as Vice President, Business Development of the
Company since its formation. From 1992 to 1995, Mr. Moore served as Managing
Partner of Magnum Energy Corporation, L.L.C. From 1991 until 1992, Mr. Moore
served as Executive Vice President -- Exploration and Production, Chief
Operating Officer and
- 15 -
<PAGE>
Director of Clayton Williams Energy, Inc. From 1985 to 1991, Mr. Moore served as
President, Chief Operating Officer and Director of Clayton W. Williams, Jr. Inc.
Dan P. Colwell has served as Vice President, Land for the Company since its
formation. From 1993 to 1995, Mr. Colwell served as Vice President of Land for
Enertex, Inc. Mr. Colwell was employed by ARCO as Director of Business
Development from 1991 to 1993 and Area Land Manager from 1987 to 1991.
William K. White has served as Vice President, Finance and Chief Financial
Officer of the Company since September 1996. From 1994 to September 1996, Mr.
White was Senior Vice President of the Energy Investment Group of Trust Company
of The West. From 1991 to 1994, Mr. White was President of the Odessa
Associates, a private firm engaged in the practice of providing financial
consulting services to the oil and gas industry.
John L. Benfatti has served as Vice President, Accounting and Controller of the
Company since its formation. From 1980 to 1995, Mr. Benfatti served as
Controller and Treasurer of Staley Gas Co., Inc.
Susan D. Rowland has served as Vice President, Administration and Corporate
Secretary of the Company since its formation. From 1986 to 1996, Ms. Rowland
served as a corporate officer and administrative manager of a number of
companies, including Amber Energy, Inc., Enertex, Inc., Haley Properties, Inc.
and United Oil Services, Inc.
- 16 -
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock has been publicly traded on the Nasdaq National
Market under the symbol "TEXP" since the Company's initial public offering
effective December 16, 1996. The following table summarizes the high and low
reported sales prices on Nasdaq for each quarterly period since the Company's
initial public offering:
<TABLE>
<CAPTION>
Common Stock
----------------------
High Low
---------- ----------
<S> <C> <C>
1997:
First Quarter..................................... $14.750 $8.125
Second Quarter.................................... 12.125 6.750
Third Quarter..................................... 13.000 9.500
Fourth Quarter.................................... 13.875 8.875
1998:
First Quarter..................................... $ 9.625 $6.688
Second Quarter.................................... 9.500 7.500
Third Quarter..................................... 9.125 5.500
Fourth Quarter.................................... 8.938 5.375
1999:
First Quarter (through March 1, 1999)............. $ 7.188 $4.625
</TABLE>
As of March 1, 1999, the Company estimates that there were more than 150
record holders and more than 3,400 beneficial holders of the Company's Common
Stock.
No dividends have been declared or paid on the Company's Common Stock to
date. Currently, the Company plans to retain all future earnings for the
development of its business.
- 17 -
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data should be read in
conjunction with "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's consolidated financial
statements and related notes included in "Item 8. Consolidated Financial
Statements and Supplementary Data."
<TABLE>
<CAPTION>
Year Ended December 31, Period March 31, 1995
-------------------------------------------------- (date of inception)
through
1998 1997(a) 1996 (a) December 31, 1995(a)
-------------- -------------- -------------- ------------------------
(in thousands, except per share amounts and operating data)
<S> <C> <C> <C> <C>
Consolidated Statement of Operations Data:
Revenues-
Operating revenues............................ $ 72,876 $ 73,827 $ 23,824 $ 743
Expenses:
Oil and gas production........................ 27,078 16,298 7,312 265
Production and other taxes.................... 5,725 5,548 1,887 39
General and administrative.................... 9,163 5,372 2,270 1,546
Amortization of stock option awards........... 5,055 5,053 1,839 576
Exploration and abandonment................... 17,596 3,055 184 490
Depletion, depreciation and amortization...... 27,090 19,972 5,789 299
Impairment of long-lived assets............... 25,666 68,997 -- --
Restructuring costs........................... 625 -- -- --
Interest...................................... 8,648 1,524 2,965 97
Other......................................... (1,172) (258) (503) (1,038)
-------- --------- --------- --------
Total expenses............................. 125,474 125,561 21,743 2,274
-------- --------- --------- --------
Income (loss) before income taxes............. (52,598) (51,734) 2,081 (1,531)
Income tax expense (benefit).................. (5,381) (18,267) 3,484 --
-------- --------- --------- --------
Net loss...................................... $(47,217) $ (33,467) $ (1,403) $ (1,531)
======== ========= ========= ========
Net loss per common share..................... $ (1.22) $ (.99) $ (.07) $ (.11)
Net loss per common share -
assuming dilution............................. $ (1.22) $ (.99) $ (.07) $ (.11)
Weighted average common shares outstanding....
38,808 33,942 19,605 14,066
Consolidated Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities.......................... $ 18,448 $ 46,563 $ 7,710 $ (1,805)
Investing activities.......................... (58,413) (114,302) (144,998) (47,522)
Financing activities.......................... 38,972 63,052 137,365 55,540
Other Consolidated Financial Data:
Capital expenditures............................ $ 63,235 $ 114,377 $ 150,119 $ 43,770
Consolidated Operating Data:
Production:
Oil (MBbls)..................................... 2,492 1,880 714 30
Gas (MMcf)...................................... 26,731 22,104 5,787 245
Total (MMcfe)................................... 41,683 33,385 10,071 425
Average Sales Prices Per Unit(b):
Oil (per Bbl)................................... $ 12.05 $ 18.67 $ 19.16 $ 16.80
Gas (per Mcf)................................... 1.60 1.75 1.75 .97
Total (per Mcfe)................................ 1.75 2.21 2.37 1.75
Expenses per Mcfe:
Production costs, excluding production and......
other taxes.................................... $ .65 $ .48 $ .72 $ .63
Production and other taxes...................... .14 .17 .19 .09
General and administrative...................... .22 .16 .23 3.64
Depletion, depreciation and amortization........ .65 .60 .57 .70
</TABLE>
- 18 -
<PAGE>
<TABLE>
<CAPTION>
December 31,
-------------------------------------------------
1998 1997(a) 1996(a) 1995(a)
-------- ----------- ----------- ----------
(in thousands)
<S> <C> <C> <C> <C>
Consolidated Balance Sheet Data:
Cash and cash equivalents................. $ 610 $ 1,603 $ 6,290 $ 6,213
Working capital (c)....................... 105,697 28 8,124 11,946
Oil and gas assets, net................... 209,177 271,920 190,062 42,861
Total assets.............................. 341,022 352,583 207,179 57,487
Total debt................................ 144,200 85,450 6,500 20,000
Stockholders' equity and predecessor
capital.................................. 171,354 232,421 187,186 34,585
</TABLE>
____________
(a) Certain reclassifications have been made to the 1997, 1996 and 1995 amounts
to conform to the 1998 presentation.
(b) Reflects results of hedging activities. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations."
(c) The 1998 amount includes $109.5 million of assets held for sale.
- 19 -
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
General
The Company is an independent energy company engaged in the exploitation,
development, exploration and acquisition of oil and gas properties. The
Company's strategy is to grow reserves, production and net income per share
through (i) the exploitation and development of its reserve base, (ii) the
acquisition of producing properties that provide significant development and
exploratory drilling potential, (iii) the exploration for oil and gas reserves,
(iv) capitalization on advanced technology to identify, explore and exploit
projects, (v) financial flexibility, and (vi) a low overhead and operating cost
structure. The Company has grown rapidly through the acquisition and
exploitation of oil and gas properties, consummating the 1995 Acquisition for a
purchase price of approximately $41.0 million, the 1996 Acquisition for
approximately $136.0 million and the Pioneer Acquisition, in 1997, for
approximately $55.8 million. In addition, the Company issued, in 1997,
5,486,734 shares and 899,965 shares of the Company's common stock in connection
with the OEDC Acquisition and the Carrollton Acquisition, respectively.
The Company's growth from acquisitions has impacted its financial results in
a number of ways. Acquired properties may not have received focused attention
prior to sale. After acquisition, certain of these properties required
extensive maintenance, workovers, recompletions and other remedial activity that
while not constituting capital expenditures may initially increase lease
operating expenses. The Company may dispose of certain of the properties it
determines are outside the Company's strategic focus. The increased production
and revenue resulting from the rapid growth of the Company has required it to
recruit and develop operating, accounting and administrative personnel
compatible with its increased size. As a result, the Company has incurred
increases in its general and administrative expense levels. The Company
believes that with its current inventory of drilling locations and the
additional staff it will be well positioned to follow a more balanced program of
exploration and exploitation activities to complement its acquisition efforts.
The Company uses the successful efforts method of accounting for its oil and
gas producing activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that result in proved reserves,
and to drill and equip development wells are capitalized. Costs to drill
exploratory wells that do not result in proved reserves, and geological and
geophysical costs are expensed. Costs of significant nonproducing properties,
wells in the process of being drilled and significant development projects are
excluded from depletion until such time as the related project is developed and
proved reserves are established or impairment is determined.
The Company's predecessor was classified as a partnership for federal income
tax purposes. Therefore, no income taxes were paid by the Company prior to the
Conversion. Future tax amounts, if any, will be dependent upon several factors,
including, but not limited to, the Company's results of operations.
Impact of Crude Oil Prices
During 1998, the posted price of West Texas intermediate crude oil (the "West
Texas Crude Oil Price") ranged from $15.75 to $8.00 per barrel. These low
prices are thought to be caused primarily by an oversupply of crude oil
inventory created, in part, by an unusually warm winter in the United States and
Europe, the apparent unwillingness of Organization of Petroleum Exporting
Countries ("OPEC") to abide by their respective crude oil production quotas and
a decline in demand in certain Asian markets.
If the West Texas Crude Oil Price worsens or persists for a protracted
period, it will adversely affect the Company's revenues, net income and cash
flows from operations. Also, if these prices maintain their present level for
an extended time period or decline further, the Company may delay or postpone
certain of its capital projects.
If the posted West Texas Crude Oil Price continues to decline, the Company
would expect that it may be required to record an impairment to its oil and gas
properties in 1999. The extent of an impairment, if any, cannot be determined.
- 20 -
<PAGE>
It is the Company's expectation that it will not have positive earnings in
1999 or the near term future unless oil and gas commodity prices improve above
their current levels, especially the price of crude oil.
Year 2000 Issues
Many computer software systems, as well as certain hardware and equipment
using date-sensitive data, were structured to use a two-digit date field meaning
that they may not be able to properly recognize dates in the year 2000. The
Company is addressing this issue through a process that entails evaluation of
the Company's critical software and, to the extent possible, its hardware and
equipment to identify and assess Year 2000 issues and to remediate, replace or
establish alternative procedures addressing non-Year 2000 complaint systems,
hardware and equipment.
The Company has substantially completed an inventory of its systems and
equipment including computer systems and business applications. Based upon this
review, the Company currently believes that all of its critical software and
computer hardware systems are either Year 2000 compliant or will be within the
next six months. The Company continues to inventory its equipment and
facilities to determine if they contain embedded date-sensitive technology. If
problems are discovered, remediation, replacement or alternative procedures for
non-compliant equipment and facilities will be undertaken on a business priority
basis. This process will continue and, depending upon the equipment and
facilities, is scheduled for completion during the first three quarters of 1999.
As of December 31, 1998, the Company had not incurred any material amount of
expense related to its Year 2000 compliance efforts. These costs are currently
being expensed as they are incurred. However, in certain instances the Company
may determine that replacing existing equipment may be more efficient,
particularly where additional functionality is available. These replacements
may be capitalized and therefore would reduce the estimated 1999 expenses
associated with the Year 2000 issue. The Company currently expects total out-
of-pocket costs to become Year 2000 compliant to be less than $100,000. The
Company currently expects that such costs will not have a material adverse
effect on the Company's financial condition, operations or liquidity.
The foregoing timetable and assessment of costs to become Year 2000 compliant
reflect management's current best estimates. These estimates are based on many
assumptions, including assumptions about the cost, availability and ability of
resources to locate, remediate and modify affected systems, equipment and
facilities. Based upon its activities to date, the Company does not currently
believe that these factors will cause results to differ significantly from those
estimated. However, the Company cannot reasonably estimate the potential impact
on its financial condition and operations if key third parties including, among
others, suppliers, contractors, joint venture partners, financial institutions,
customers and governments do not become Year 2000 compliant on a timely basis.
The Company is contacting many of these third parties to determine whether they
will be able to resolve in a timely fashion their Year 2000 issues as they may
affect the Company.
In the event that the Company is unable to complete the remediation or
replacement of its critical systems, facilities and equipment, establish
alternative procedures in a timely manner, or if those with whom the Company
conducts business are unsuccessful in implementing timely solutions, Year 2000
issues could have a material adverse effect on the Company's liquidity and
results of operations. At this time, the potential effect in the event the
Company and/or third parties are unable to timely resolve their Year 2000
problems is not determinable; however, the Company currently believes that it
will be able to resolve its own Year 2000 issues in a timely manner.
The disclosure set forth in this section is provided pursuant to Securities
Act Release No. 33-7558. As such it is protected as a forward-looking statement
under the Private Securities Litigation Reform Act of 1995. See "Forward-
Looking Statements." This disclosure is also subject to protection under the
Year 2000 Information and Readiness Disclosure Act of 1998, Public Law 105-271,
as a "Year 2000 Statement" and "Year 2000 Readiness Disclosure" as defined
therein.
- 21 -
<PAGE>
Operating Data
The following sets forth the Company's historical operating data:
<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------------
1998 1997 1996
------------ ------------- -------------
Production:
<S> <C> <C> <C>
Oil (MBbls).................................... 2,492 1,880 714
Gas (MMcf)..................................... 26,731 22,104 5,787
Total (MMcfe).................................. 41,683 33,385 10,071
Average sales price per unit (excluding the
effects of hedging):
Oil (per Bbl).................................. $11.97 $18.38 $21.26
Gas (per Mcf).................................. $ 1.51 $ 1.75 $ 1.92
Total (per Mcfe)............................... $ 1.68 $ 2.19 $ 2.61
Average sales price per unit (including the
effects of hedging):
Oil (per Bbl).................................. $12.05 $18.67 $19.16
Gas (per Mcf).................................. $ 1.60 $ 1.75 $ 1.75
Total (per Mcfe)............................... $ 1.75 $ 2.21 $ 2.37
Expenses per Mcfe:
Production costs, excluding production and
other taxes................................... $ .65 $ .48 $ .72
Production and other taxes..................... $ .14 $ .17 $ .19
General and administrative..................... $ .22 $ .16 $ .23
Depletion, depreciation and amortization....... $ .65 $ .60 $ .57
</TABLE>
Results of Operations
The Company began operations on March 31, 1995. As a result of the Company's
limited operating history and rapid growth, its financial statements are not
readily comparable and may not be indicative of future results. The 1996
Acquisition, which closed on October 31, 1996, did not contribute fully to the
Company's 1996 operating results. The OEDC Acquisition, the Carrollton
Acquisition and the Pioneer Acquisition, did not close until the end of December
1997 which did not contribute to the 1997 operating results.
Year ended 1998 as compared to 1997
The Company's revenues from the sale of oil and gas (excluding the effects of
hedging activities) were $29.8 million and $40.3 million in 1998 and $34.6
million and $38.7 million in 1997, respectively. Realized oil and gas prices
decreased $6.41 per Bbl and $.24 per Mcf, respectively. In 1998, the 1997
Acquisitions contributed oil sales of $8.0 million and gas sales of $9.7 million
with associated production of approximately 649 Mbls of oil and 5,038 Mmcf of
gas, respectively. The decrease in oil revenues due to price was offset by an
increase in production primarily attributable to the 1997 Acquisitions. Gas
revenues increased as a result of increased production, primarily the result of
the 1997 Acquisitions, despite a decrease in gas prices. Excluding the 1997
Acquisitions, the 1998 oil and gas production was relatively flat compared to
1997. The increase in production, assuming 1997
- 22 -
<PAGE>
prices, would have resulted in additional revenues to the Company of $18.2
million while the decrease in prices reduced revenues by $21.4 million.
The Company's hedging activities in 1998 increased both oil and gas revenues
$206,000 ($.08 per Bbl) and $2.6 million ($.09 per Mcf), respectively, as
compared to 1997, when hedging activities increased oil and reduced gas revenues
$551,000 ($.29 per Bbl) and $62,000 ($.003 per Mcf), respectively. At December
31, 1998 the Company had no oil hedges in place, however, gas hedges for 12,499
Mmcf of the Company's production through early 2000 were outstanding. The
hedges will allow the Company to realize, at a minimum, a price of $1.81 per Mcf
on the volumes hedged. The outstanding gas hedges had a fair value of
approximately $1.7 million at December 31, 1998.
The Company's oil and gas production costs were $27.1 million ($.65 per Mcfe)
and $16.3 million ($.48 per Mcfe) in 1998 and 1997, respectively. In 1998,
productions costs attributable to the 1997 Acquisitions were $11.9 million
($1.32 per Mcfe). Thus, the increase in production costs is primarily related
to the 1997 Acquisitions. Excluding the 1997 Acquisitions, the Company's
production costs would have decreased slightly on an absolute and Mcfe basis.
Initially, acquired properties generally incur significant rework expenses,
which are costs incurred to perform required maintenance, workovers and other
remedial activities. The properties acquired in the Pioneer Acquisition were
primarily oil in nature and generally have a higher per unit production cost as
compared to gas properties. The Company expects that going forward, with its
existing asset base, the per unit production costs should decrease below 1998
levels.
Depletion, depreciation and amortization expense (DD&A) was $27.1 million
($.65 Mcfe) and $20.0 million ($.60 per Mcfe) in 1998 and 1997, respectively.
In 1998 and 1997, DD&A included $.03 per Mcfe and $.01 per Mcfe, respectively,
of depreciation and amortization of other property and equipment and other
assets. In the fourth quarter of 1997 the Company recorded an impairment of
$69.0 million which acted to reduce the DD&A rate going forward. This effect
was offset by the higher finding costs for the properties acquired in the 1997
Acquisitions as compared to previous acquisitions. Through the first three
quarters of 1998, the Company's DD&A rate was slightly below the rates for the
prior comparable quarters. In the fourth quarter of 1998, the Company lost
proved reserves due to the decrease primarily in oil prices, which had an
adverse effect on the fourth quarter DD&A rate. The fourth quarter DD&A rate
caused the annual DD&A rate for 1998 to slightly exceed that of 1997.
The Company recognized an impairment of $25.7 million and $69.0 million in
1998 and 1997, respectively. The 1997 impairment was primarily related to
significantly depressed commodity prices as compared to the expected commodity
prices on which most of the properties were acquired. The 1998 impairment was
comprised of three components (a) $22.2 million related to oil and gas
properties, (b) $2.2 million related to impairment of an investment in a
partnership and (c) $1.3 million related to assets held for sale. The 1998
impairment related to the oil and gas properties is primarily attributable to
loss of proved reserves associated with below expectation developmental drilling
results and downhole mechanical problems primarily from the Company's Gulf Coast
and Gulf of Mexico regions.
The Company's exploration and abandonment expense was $17.6 million and $3.1
million in 1998 and 1997, respectively. The increase is due primarily to (a)
increased geological and geophysical staff, (b) impairment of unproved
properties, (c) uneconomical exploratory wells and (d) delay rentals. Increase
in the geological and geophysical staff was due to the Company's exploratory
efforts primarily associated with the OEDC and Carrollton acquisitions in the
Gulf Coast and Gulf of Mexico regions. With the Company's planned divestitures
in these regions, there should be a reduction in the 1999 geological and
geophysical staff costs. The Company's Webb County prospect, previously
discussed, is the significant contributing factor to the increase due to (a)
$1.1 million uneconomical exploratory well, (b) $9.1 million impairment of the
unproved acreage and (c) approximately $1.3 million in delay rentals paid in
1998 to hold leases.
The Company's general and administrative expense (G&A) was $9.2 million ($.22
per Mcfe) and $5.4 million ($.16 per Mcfe) in 1998 and 1997, respectively. G&A
attributable to the OEDC and Carrollton acquisitions was over $2.2 million (over
$.54 per Mcfe) in 1998. Excluding the OEDC and Carrollton acquisitions, G&A
would have been approximately $.19 per Mcfe. After excluding the OEDC and
Carrollton
- 23 -
<PAGE>
acquisitions, the remainder of the increase in G&A from 1997 to 1998 is
primarily the result of a full year's effect of the increase in staff in 1997
necessitated by the Company's growth. With the planned disposition of assets in
1999, and other cost cutting measures taken, the Company expects a decrease in
its 1999 G&A on both an absolute and per Mcfe basis.
In the fourth quarter of 1998, the Company recognized a restructuring charge
of $625,000. This charge relates to the severance and related benefits that
will be provided to individuals whose positions are being eliminated as a result
of the planned disposition of assets in 1999.
The 1998 equity in net loss of affiliates is attributable to the Company's
ownership in DIGP and MBPP acquired in the OEDC acquisition. Included in the
equity loss is approximately $632,000 of amortization of the Company's cost
basis in excess of the underlying historical net assets of DIGP. The
amortization of the Company's cost basis in excess of the underlying historical
net assets of MBPP will commence being recorded when the underlying assets
commence operations, which is expected to be the first quarter of 1999.
The Company's interest expense was $8.6 million and $1.5 million in 1998 and
1997, respectively. The increase is primarily due to the increase in debt
levels between years. In 1997, the average debt outstanding was lower as a
result of the December 1996 initial public common stock offering. In 1998, the
average outstanding debt obligation increased primarily due to (a) the Pioneer
acquisition in December 1997, (b) the purchase of treasury stock, (c) the
assumption of $15.8 million in debt from the OEDC and Carrollton acquisitions,
(d) the Company's capital expenditure program and (e) the reduction in operating
cash flow due to significantly depressed commodity prices.
The Company's effective income tax rates were 10% and 35% for 1998 and 1997,
respectively. The decrease in rate is due to the Company's inability in 1998 to
recognize the income tax benefit associated with a loss before income taxes
because it is more likely than not that the Company will not be able to utilize
all its available loss carryforwards prior to their ultimate expiration. Due to
the Company's inability to potentially use its loss carryforwards, the Company
has provided a valuation allowance of approximately $14.0 million against its
deferred tax assets. In 1999 and in future years, the Company will not be able
to recognize an income tax benefit until the Company begins to generate an
adequate level of earnings before income taxes.
Year Ended December 31, 1996
For the year ended December 31, 1996, the Company's revenues from the sale of
oil and gas (excluding the effects of hedging activities) were $15.1 million and
$11.1 million, respectively. Of total gross oil and gas revenues, $16.2 million
and $9.5 million are attributable to the 1995 Acquisition and the 1996
Acquisition, respectively. During the year, the Company produced 714 MBbls of
oil (514 MBbls attributable to the 1995 Acquisition and 186 MBbls attributable
to the 1996 Acquisition) and 5,787 MMcf of gas (3,401 MMcf attributable to the
1995 Acquisition and 2,124 MMcf attributable to the 1996 Acquisition), with
total oil and gas production of 10,071 MMcfe. The revenues and production are
primarily attributable to the 1995 Acquisition since the 1996 Acquisition did
not close until October 31, 1996.
As a result of hedging activities in the year ended December 31, 1996, oil
revenues were reduced $1.5 million ($2.10 per Bbl) and gas revenues were reduced
$995,000 ($.17 per Mcf) for a total reduction of $2,495,000.
Oil and gas production costs, including production taxes, were $9.2 million
($.91 per Mcfe) for the year ended December 31, 1996. These costs included $2.2
million ($.22 per Mcfe) of rework expenses of which $945,000 were attributable
to the 1995 Acquisition and $1.2 million were attributable to the 1996
Acquisition.
Exploration and abandonment costs were $184,000 for the year ended December
31, 1996.
General and administrative expenses were $2.3 million ($.23 per Mcfe) for the
year ended December 31, 1996.
- 24 -
<PAGE>
For the year ended December 31, 1996, depletion, depreciation and
amortization expense was $5.8 million ($.57 per Mcfe). This represents a full
year of depletion, depreciation and amortization relating to production for the
1995 Acquisition and two months of depletion, depreciation and amortization
relating to production for the 1996 Acquisition.
Interest expense was $2,965,000 for the year ended December 31, 1996. The
interest expense was attributable to bank financing incurred primarily to fund
the 1995 Acquisition and the 1996 Acquisition.
Liquidity and Capital Resources
The Company's primary sources of capital have been its initial
capitalization, private equity sales, bank financing, cash flow from operations
and the Company's initial public offering. The 1996 Acquisition was principally
funded with bank financing, which was repaid with the proceeds from the
Company's initial public offering. The OEDC Acquisition and the Carrollton
Acquisition were completed by issuing common stock in exchange for the equity
interest in each entity. The Pioneer Acquisition was funded with bank
financing.
Net Cash Provided by Operating Activities. Net cash provided by operating
activities, before changes in operating assets and liabilities, was $20.2
million for the year ended December 31, 1998, compared to $43.3 million for the
year ended December 31, 1997. The decrease was primarily attributable to an
increase in operating and interest costs with a slight decrease in revenues.
Revenues were significantly below expectation due to depressed commodity prices.
Capital Expenditures. In 1998, the Company budgeted $83.8 million for capital
expenditures and had actual cash expenditures of $63.2 million. The Company did
not spend all of its 1998 budget primarily as a result of deferring some of its
exploration and production projects (mainly oil) and the $16 million pipeline
and processing project investments due to uncertainties over future commodity
price levels.
Cash expenditures for investing in oil gas properties were $57.4 million for
the year ended December 31, 1998. This includes $5.4 million for the
acquisition of oil and gas leases and $52.0 million for development and
exploratory drilling.
The Company requires capital primarily for the exploration, development and
acquisition of oil and gas properties, the repayment of indebtedness and general
working capital needs.
The following table sets forth costs incurred by the Company in its
exploration, development and acquisition activities.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Development costs..............................
$30,663 $44,896 $12,468
Exploration costs..............................
21,316 2,856 129
Acquisition costs:
Unproved properties...........................
4,994 24,532 802
Proved properties.............................
404 100,871 139,110
------- ------- -------
Total.....................................
$57,377 $173,155 $152,509
======= ======== ========
</TABLE>
For 1999, the Company, currently, expects to spend (i) approximately $15.4
million on developmental projects, (ii) approximately $28.4 million on
exploratory and probable projects, of which $11.0 million relates to contingent
projects following successful exploratory and probable projects, (iii)
approximately $6.4 million to acquire additional acreage and seismic data and
(iv) $.7 million on other items. The final
- 25 -
<PAGE>
determination with respect to the drilling of any well, including those
currently budgeted, will depend on a number of factors, including (i) the
results of exploration efforts and the review and analysis of the seismic data,
(ii) the availability of sufficient capital resources by the Company and other
participants for drilling prospects, (iii) economic and industry conditions at
the time of drilling, including prevailing and anticipated prices for natural
gas and oil and the availability and costs of drilling rigs and crews, (iv) the
financial resources and results of the Company, and (v) the availability of
leases on reasonable terms and permitting for the potential drilling location.
There can be no assurance that the budgeted wells will encounter, if drilled,
recompleted or worked over, reservoirs of commercial quantities of natural gas
or oil.
While the Company regularly engages in discussions relating to potential
acquisitions of oil and gas properties, the Company has no present agreement,
commitment or understanding with respect to any such acquisition, other than the
acquisition of oil and gas properties and interests in its normal course
business. Any future acquisitions may require additional financing and will be
dependent upon financing which may be required in the future to fund the
Company's acquisition and drilling programs.
Capital Resources. The Company's primary capital resources are net cash
provided by operating activities and the availability under the Credit
Agreement, of which $60 million was available at December 31, 1998.
Credit Agreement. The Credit Agreement established a four year revolving credit
facility, up to a maximum amount of $250 million, subject to a borrowing base to
be redetermined semi-annually by the lenders based on certain proved oil and gas
reserves and other assets of the Company. The borrowing base at December 31,
1998 was $200 million. To the extent that the borrowing base is less than the
aggregate principal amount of all outstanding loans and letters of credit under
the Credit Agreement, such deficiency must be cured by the Company ratably
within 180 days, by either prepaying a portion of the outstanding amounts under
the Credit Agreement or pledging additional collateral to the lenders. A
portion of the credit facility is available for the issuance of up to $15.0
million of letters of credit, of which $144,000 was outstanding at December 31,
1998. All outstanding amounts under the Credit Agreement are due and payable in
full on January 1, 2001. The Company's outstanding debt under the Credit
Agreement was $140 million on December 31, 1998.
The Company will undergo a borrowing base review in April 1999. In light of
the depressed commodity prices and the related effect on the Company's oil and
gas reserves, the Company cannot be reasonably assured that it will be able to
maintain its current $200 million borrowing base.
At the Company's option, borrowings under the Credit Agreement bear interest
at either the "Base Rate" (i.e., the higher of the applicable prime commercial
lending rate, or the federal funds rate plus .50% per annum) or the Eurodollar
rate, plus 1.00% to 1.50% per annum, depending on the level of the Company's
aggregate outstanding borrowings. In addition, the Company is committed to pay
quarterly in arrears a fee of .300% to .375% of the unused borrowing base.
The Credit Agreement contains certain covenants and restrictions that are
customary in the oil and gas industry. In addition, the line of credit is
secured by a majority of the Company's proved oil and gas properties.
At December 31, 1998, the Company was not in compliance with a coverage test
required by the Credit Agreement. The Company has requested and received
written consents from its banks to amend this coverage test of the Credit
Agreement, and the Company believes this amendment will be fully documented on
or before April 30, 1999. The Company believes it will be able to comply with
the amended covenants of the Credit Agreement for the foreseeable future.
Liquidity and Working Capital. At December 31, 1998, the Company had $610,000
of cash and cash equivalents as compared to $1.6 million at December 31, 1997.
The Company's ratio of current assets to current liabilities was 6.23 at
December 31, 1998, compared to 1.00 at December 31, 1997. The Company's working
capital ratio increased due to $109.5 million of assets held for sale at
December 31, 1998. Excluding the assets held for sale the Company would have a
working capital deficit of $3.8 million. The working capital deficit is due
partially to the Company maintaining low cash levels for cash management
purposes. The Company, at December 31, 1998, has availability under its Credit
Agreement to fund any working capital deficit.
- 26 -
<PAGE>
Unsecured Credit Agreement. In April 1997, the Company entered into a credit
agreement (the "Unsecured Credit Agreement") with Texas Commerce Bank National
Association (the "Bank"), which establishes a revolving credit facility, up to
the maximum of $5 million. All outstanding amounts pursuant to the Unsecured
Credit Agreement are due and payable in full on or before December 31, 1999.
Proceeds of the Unsecured Credit Agreement are utilized to fund short-term needs
(less than thirty days). The Company had $4.2 million outstanding principal
under the Unsecured Credit Agreement at December 31, 1998.
The interest payable on amounts outstanding under the Unsecured Credit
Agreement is at a rate determined by agreement between the Company and the Bank.
The rate may not exceed the maximum interest rate permitted under applicable
laws. Interest rates generally are the bank's cost of funds plus 1% per annum.
Other Matters
Stock Options and Compensation Expense
In connection with the Conversion, the Company issued options to purchase
3,631,350 shares of Common Stock to certain of its officers and employees in
substitution for options issued by Titan Resources, L.P. Of the options issued
by the partnership approximately 93% were issued on March 31, 1995, the date of
inception, and approximately 7% were issued as of September 30, 1996. The
options issued by the Company have an exercise price of $2.08 per share.
Options to purchase 3,032,717 shares of Common Stock are currently vested and an
additional 426,451 shares will vest on March 31, 1999. Based in part on selling
prices of interests in the partnership in December 1995 and September 1996, the
Company expected to record a noncash compensation expense of approximately
$421,000 per month for a period of 39 months beginning in October 1996 to
reflect the estimated value of the revised option plan on September 30, 1996.
Noncash compensation expense recorded for the years ended December 31, 1998,
1997 and 1996 was $5,055,000, $5,053,000 and $1,839,000, respectively. During
the years ended December 31, 1998, 1997 and 1996, the Company issued additional
options for aggregates of 389,499, 259,000 and 85,000 shares, respectively, for
which no deferred compensation was recorded as these options had no implicit
value when issued.
Hedging Activities
The Company uses swap agreements and other financial instruments in an
attempt to reduce the risk of fluctuating oil and gas prices and interest rates.
The Company is party to various agreements with numerous counterparties for
purposes of utilizing financial instruments, of which the Company assesses the
creditworthiness of its counterparties. Among other counterparties, the Company
has utilized Enron Capital & Trade Resources Corp. (an affiliate of a
significant stockholder of the Company) as a counterparty. Settlement of gains
or losses on the hedging transactions was generally based on the difference
between the contract price and a formula using New York Mercantile Exchange
("NYMEX") or other major indices related prices and was reported as a component
of oil and gas revenues as the associated production occurs. The Company, at
December 31, 1998, had entered into hedging transactions with respect to
approximately 11,134 and 1,365 MMcfe of its 1999 and 2000 estimated production.
See "Risk Factors-Risk of Hedging Activities."
Crude Oil
The Company reports average oil prices per Bbl including the net effect of
oil hedges. In 1998, 1997 and 1996, the Company received (paid) related to its
oil hedges $206,000 ($.08 per Bbl), $551,000 ($.29 per Bbl) and ($1.5 million)
($2.10 per Bbl), respectively.
Natural Gas
The Company reports average gas prices per Mcf including the net effect of
gas hedges. In 1998, 1997 and 1996, the Company received (paid) related to its
gas hedges $2.6 million ($.09 per Mcf), ($62,000) ($.003 per Mcf) and ($995,000)
($.17 per Mcf), respectively.
- 27 -
<PAGE>
Natural Gas Balancing
In the natural gas industry, various working interest partners produce more
or less than their entitlement share of natural gas from time to time. The
Company's net underproduced position at December 31, 1998 was approximately
81,000 Mcf. Under terms of typical natural gas balancing agreements, the
underproduced party can take a certain percentage, typically 25% to 50% of the
overproduced party's entitled share of gas sales in future months, to eliminate
such imbalances. During the make-up period, the overproduced party's cash flow
will be adversely affected. The Company recognizes revenue and imbalance
obligations under the entitlements method of accounting, which means that the
Company recognizes the revenue to which it is entitled and records a liability
with respect to the value of the overproduced gas.
Environmental and Other Laws and Regulations
The Company's business is subject to certain federal, state and local laws
and regulations relating to the exploration for and the development, production
and transportation of oil and gas, as well as environmental and safety matters.
Many of these laws and regulations have become more stringent in recent years,
often imposing greater liability on a larger number of potentially responsible
parties. Although the Company believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by such laws and
regulations are frequently changed and subject to interpretation, and the
Company is unable to predict the ultimate cost of compliance with these
requirements or their effect on its operations. The Company has no material
commitments for capital expenditures to comply with existing environmental
requirements.
Nevertheless, changes in existing environmental laws or in interpretations
thereof could have a significant adverse impact on the operating costs of the
Company, as well as the oil and gas industry in general. See "Risk Factors-
Compliance with Environmental Regulations," "Business and Environmental Matters"
and "Business and Abandonment Costs."
Recently Issued Accounting Standards
In June 1997, the Financial Accounting Standards Board (the "FASB") issued
SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" which establishes standards for reporting information about
operating segments in annual financial statements and requires selected
information about operating segments in interim financial reports issued to
shareholders. It also establishes standards for related disclosures about
products and services, geographic areas and major customers. SFAS No. 131 is
effective for financial statements for periods beginning after December 15,
1997, but the statement need not be applied to interim financial statements in
the initial year of application. SFAS No. 131 did not materially affect the
Company's reporting practices.
In June 1998, the FASB issued SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" which establishes standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires that an entity recognize all
derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. It establishes conditions
under which a derivative may be designated as a hedge and establishes standards
for reporting changes in the fair value of a derivative. SFAS No. 133 is
required to be implemented for the first quarter of the fiscal year ended 2000.
Early adoption is permitted. The Company has not evaluated the effects of
implementing SFAS No. 133.
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<PAGE>
Risk Factors
Volatility of Oil and Gas Prices; Marketability of Production
Our revenues, operating results and future rate of growth are highly
dependent upon the prices we receive for our oil and gas. Historically, the
markets for oil and gas have been volatile and may continue to be volatile in
the future. Various factors which are beyond our control such as the worldwide
and domestic supplies of oil and gas, the ability of the members of the OPEC to
agree to and maintain oil price and production controls, political instability
or armed conflict in oil-producing regions, the price and level of foreign
imports, the level of consumer demand, the price and availability of alternative
fuels, the availability of pipeline capacity, weather conditions, domestic and
foreign governmental regulations and taxes and the overall economic environment
will affect prices of oil and gas. We are unable to predict the long-term
effects of these and other conditions on the prices of oil. Lower oil and gas
prices may reduce the amount of oil and gas we produce economically which may
adversely affect our revenues and operating income and may require a reduction
in the carrying value of our oil and gas properties. We make substantially all
of our sales of oil and gas in the spot market or pursuant to contracts based on
spot market prices and not pursuant to long-term fixed price contracts. We try
to reduce price risk by entering into hedging transactions with respect to a
portion of our expected future production. We cannot assure you, however, that
such hedging transactions will reduce risk or mitigate the effect of any
substantial or extended decline in oil or natural gas prices.
The marketability of our production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. Most of our natural gas is delivered through gas
gathering systems and gas pipelines that we do not own. Federal and state
regulation of oil and gas production and transportation, tax and energy
policies, changes in supply and demand and general economic conditions all could
adversely affect our ability to produce and market our oil and gas. Any
dramatic change in market factors could have a material adverse effect on our
business, financial condition and results of operations.
Substantial Capital Requirements
We make, and will continue to make, substantial capital expenditures for the
exploration, development, acquisition and production of our oil and gas
reserves. We intend to finance these capital expenditures primarily with funds
provided by operations, the incurrence of debt, the issuance of equity and the
sale of non-core assets. Our direct capital expenditures for oil and gas
producing activities were $52.0 million, $47.8 million and $12.6 million for the
years ended December 31, 1998, 1997 and 1996, respectively, and $2.0 million for
the nine months ended December 31, 1995. If revenues decrease as a result of
lower oil or gas prices or otherwise, we may have limited ability to expend the
capital necessary to replace our reserves or to maintain production at current
levels, resulting in a decrease in production over time. If our cash flow from
operations and availability under our credit agreement are not sufficient to
satisfy our capital expenditure requirements, we cannot assure you that we will
be able to obtain additional debt or equity financing to meet these
requirements.
Uncertainty of Reserve Information and Future Net Revenue Estimates
There are numerous uncertainties inherent in estimating quantities of proved
reserves and their values, including many factors beyond our control. The
reserve information contained in our filings with the SEC represents estimates
only. Although we believe such estimates are reasonable, reserve estimates are
imprecise and you should expect them to change as additional information becomes
available.
Estimates of oil and gas reserves, by necessity, are projections based on the
evaluation of available geological, geophysical, economic and engineering data,
and there are uncertainties inherent in the interpretation of such data as well
as the projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that are difficult to measure. The
accuracy of any reserve estimate is a function of the quality of available data,
engineering and geological interpretation and judgment. Estimates of
economically recoverable oil and gas reserves and of future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other
producing areas, the assumed effects of regulations
- 29 -
<PAGE>
by governmental agencies and assumptions concerning future oil and gas prices,
future operating costs, severance and excise taxes, development costs and
workover and remedial costs, all of which may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and gas attributable to any particular group of properties,
classifications of such reserves based on risk of recovery and estimates of the
future net cash flows expected therefrom may vary substantially from those
estimated in our filings with the SEC. Moreover, we cannot assure you that our
reserves will ultimately be produced or that our proved undeveloped reserves,
the recovery of which requires significant capital expenditures and successful
drilling operations, will be developed within the periods anticipated. Any
significant variance in the assumptions could materially affect the estimated
quantity and value of our reserves. Actual production, revenues and expenditures
with respect to our reserves will likely vary from estimates, and such variances
may be material.
Approximately 40% of our total proved reserves on December 31, 1998 were
undeveloped, which are by their nature less certain. Recovery of these reserves
will require significant capital expenditures and successful drilling
operations. The reserve data set forth in our estimates assumes that we will
expend substantial capital to develop these reserves. Although we have prepared
our cost and reserve estimates attributable to our oil and gas reserves in
accordance with industry standards, we cannot assure you that the estimated
costs are accurate, that development will occur as scheduled or that the results
will be as estimated.
In addition, you should not construe the PV-10 referred to in this report to
be the current market value of the estimated oil and gas reserves attributable
to our properties. In accordance with applicable requirements, we generally
base the estimated discounted future net cash flows from proved reserves on
prices and costs as of the date of the estimate, whereas actual future prices
and costs may be materially higher or lower. The amount and timing of actual
production, supply and demand for oil and gas, curtailments or increases in
consumption by gas purchasers, changes in governmental regulations or taxation
and other factors will also affect actual future net cash flows. The timing of
both the production and the incurrence of expenses in connection with
development and production of oil and gas properties will affect the timing of
actual future net cash flows from proved reserves, and thus also affect their
actual present value. In addition, the 10% discount factor, which the SEC
requires us to use in our calculation of the discounted future net cash flows
for reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with us
or the oil and gas industry in general.
Reserve Replacement Risk
Our future success depends upon our ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Our proved
reserves will generally decline as a result of continued production, except to
the extent that we conduct successful exploration or development activities or
acquire properties containing proved reserves, or both. In order to increase
reserves and production, we must continue our development and exploration
drilling and recompletion programs or undertake other replacement activities.
Exploratory drilling and, to a lesser extent, development drilling involve a
high degree of risk that we will not obtain commercial production or that our
production will be insufficient to recover drilling and completion costs. We
cannot state the costs of drilling, completing and operating wells with
certainty. Numerous factors, including title problems, weather conditions,
compliance with governmental requirements and shortages or delays in the
delivery of equipment may curtail, delay or cancel our drilling operations.
Furthermore, there is no guarantee that we will recognize a profit on the
investment or that we will recover our drilling, completion and operations cost
upon the completion of a well.
There are certain risks associated with secondary recovery operations,
especially the use of waterflooding techniques. Part of our inventory of
development prospects consists of waterflood projects. Waterflooding involves
significant capital expenditures and uncertainty as to the total amount of
secondary reserves that we can recover. In waterflood operations, there is
generally a delay between the initiation of water injection into a formation
containing hydrocarbons and any resulting increase in production. The operating
cost per unit of production of waterflood projects is generally higher during
the initial phases of such projects due to the purchase of injection water and
related costs, as well as during the later stages of the life of the project as
production declines. The
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<PAGE>
degree of success, if any, of any secondary recovery program depends on a large
number of factors, including the porosity of the formation, the technique used
and the location of injector wells.
Our current strategy includes increasing our reserve base through
acquisitions of producing properties, continued exploitation of our existing
properties and exploration of new and existing properties. We cannot assure
you, however, that our planned development and exploration projects and
acquisition activities will result in significant additional reserves or that we
will have continuing success drilling productive wells at low finding and
development costs. Furthermore, while our revenues may increase if prevailing
oil and gas prices increase significantly, our finding costs for additional
reserves could also increase.
Acquisition Risks
We expect to continue to evaluate and pursue acquisition opportunities
available on terms that our management considers favorable to us. The
successful acquisition of producing properties involves an assessment of
recoverable reserves, future oil and gas prices, operating costs, potential
environmental and other liabilities and other factors beyond our control. This
assessment is necessarily inexact and its accuracy is inherently uncertain. In
connection with such an assessment of the subject properties, we perform a
review that we believe is generally consistent with industry practices. This
review, however, will not reveal all existing or potential problems, nor will it
permit a buyer to become sufficiently familiar with the properties to assess
fully their deficiencies and capabilities. Inspections may not be performed on
every well, and structural and environmental problems are not necessarily
observable even upon inspection. We generally assume preclosing liabilities,
including environmental liabilities, and generally acquire interests in the
properties on an "as is" basis. With respect to our acquisitions to date, we
have no material commitments for capital expenditures to comply with existing
environmental requirements. In addition, volatile oil and gas prices make it
difficult to estimate the value of producing properties for acquisition and
often cause disruption in the market for oil and gas producing properties, as
buyers and sellers have difficulty agreeing on such value. Price volatility
also makes it difficult to budget for and project the return on acquisitions and
development and exploration projects. We cannot assure you that our
acquisitions will be successful. Any unsuccessful acquisition could have a
material adverse effect on us.
Limited Operating History; Rapid Growth
We began operations in March 1995, and our brief operating history includes
three years of net losses and rapid growth. As a result, our historical results
are not readily comparable to and may not be indicative of future results. We
cannot assure you that we will continue to experience growth in, or maintain our
current level of, revenues, oil and gas reserves or production. Future tax
amounts, if any, will depend on several factors, including, but not limited to,
our results of operations.
Our rapid growth has placed significant demands on our administrative,
operational and financial resources. Any future growth of our oil and gas
reserves, production and operations would place significant further demands on
our financial, operational and administrative resources. Our future performance
and profitability will depend in part on our ability to successfully integrate
the administrative and financial functions of acquired properties and companies
into our operations, to hire additional personnel and to implement necessary
enhancements to our management systems to respond to changes in our business.
We cannot assure you that we will be successful in these efforts. Our inability
to integrate acquired properties and companies, to hire additional personnel or
to enhance our management systems could have a material adverse effect on our
results of operations.
Effects of Leverage
We have certain debt obligations that may affect our operations, including
(i) our need to dedicate a substantial portion of our cash flow from operations
to the payment of interest on our indebtedness which prevents these funds from
being available for other purposes; (ii) the covenants contained in our credit
facility limit our ability to borrow additional funds or to dispose of assets
and may affect our flexibility in planning for, and reacting to, changes in
business conditions; and (iii) our potential inability to obtain additional
financing in the future for working capital, capital expenditures, acquisitions,
general corporate purposes or other purposes. Moreover, future acquisition or
development activities may require us to alter our capitalization significantly.
These changes in
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<PAGE>
capitalization may significantly alter our leverage structure. Our ability to
meet our debt service obligations and to reduce our total indebtedness will
depend on our future performance, which will be subject to general economic
conditions and to financial, business and other factors affecting our
operations, many of which are beyond our control. We cannot assure you that
economic conditions and financial, business and other factors will not adversely
affect our future performance.
Drilling and Operating Risks; Uninsured Risks
Drilling activities are subject to many risks, including well blow outs,
cratering, uncontrollable flows of oil, natural gas or well fluids, fires,
formations with abnormal pressures, pollution, releases of toxic gases and other
environmental hazards and risks, any of which could result in substantial losses
to us. Our offshore operations are also subject to the additional hazards of
marine operations such as severe weather, capsizing and collision. In addition,
we incur the risk that we will not encounter any commercially productive
reservoirs through our drilling operations. We cannot assure you that the new
wells we drill will be productive or that we will recover all or any portion of
our investment in wells drilled. Drilling for oil and gas may involve
unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce net reserves to return a profit after drilling,
operating and other costs. The cost of drilling, completing and operating wells
is often uncertain. Numerous factors, many of which are beyond our control,
including economic conditions, mechanical problems, title problems, weather
conditions, compliance with governmental requirements and shortages and delays
in the delivery of equipment and services may curtail, delay or cancel our
drilling operations. In accordance with industry practices, we maintain
insurance against some, but not all, of these risks. We cannot assure you that
any of our insurance will be adequate to cover losses or liabilities.
Risk of Hedging Activities
Our use of energy swap arrangements and financial futures to reduce our
sensitivity to oil and gas price volatility is subject to a number of risks. If
we do not produce reserves at the rates we estimated due to inaccuracies in the
reserve estimation process, operational difficulties or regulatory limitations,
we would be required to satisfy obligations we may have under fixed price sales
and hedging contracts on potentially unfavorable terms without the ability to
hedge that risk through sales of comparable quantities of our own production.
Further, the terms under which we enter into fixed price sales and hedging
contracts are based on assumptions and estimates of numerous factors such as
cost of production and pipeline and other transportation costs to delivery
points. Substantial variations between the assumptions and estimates we used
and actual results we experience could materially adversely affect our
anticipated profit margins and our ability to manage the risk associated with
fluctuations in oil and gas prices. Additionally, fixed price sales and hedging
contracts limit the benefits we will realize if actual prices rise above the
contract prices. In addition, fixed price sales and hedging contracts are
subject to the risk that the counter-party may prove unable or unwilling to
perform its obligations under such contracts. Any significant nonperformance
could have a material adverse financial effect on us. As of December 31, 1998,
11,134 and 1,365 MMcfe of our 1999 and 2000 production, respectively, were
subject to hedging contracts.
Gas Gathering, Processing and Marketing
Our gas gathering, processing and marketing operations, which are currently
not significant to the Company, depend in large part on our ability to contract
with third party producers to acquire their gas, to obtain sufficient volumes of
committed natural gas reserves, to maintain throughput in our processing plant
at optimal levels, to replace production from declining wells, to assess and
respond to changing market conditions in negotiating gas purchase and sale
agreements and to obtain satisfactory margins between the purchase price of our
natural gas supply and the sales price for such residual gas volumes and the
natural gas liquids processed. In addition, our operations are subject to
changes in regulations relating to gathering and marketing of oil and gas. Our
inability to attract new sources of third party natural gas or to promptly
respond to changing market conditions or regulations in connection with our
gathering, processing and marketing operations could materially adversely affect
our business, financial condition and results of operations.
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<PAGE>
Compliance with Government Regulations
Our business is subject to federal, state and local laws and regulations
relating to the exploration for, and the development, production and
transportation of, oil and gas, as well as safety matters that change from time
to time in response to economic or political conditions. Although we believe we
are in substantial compliance with all applicable laws and regulations, the
requirements imposed by such laws and regulations change frequently, and these
laws and regulations are subject to interpretation. Consequently, we are unable
to predict the ultimate cost of compliance with these requirements or their
effect on our operations. We may have to expend a significant amount of
resources to comply with government laws and regulations, and these expenditures
may have a material adverse effect on our business, financial condition and
results of operations.
Compliance with Environmental Regulations
Our operations are subject to complex and constantly changing environmental
laws and regulations adopted by federal, state and local governmental
authorities. The implementation of new, or the modification of existing, laws
or regulations could have a material adverse effect on our business, financial
condition and results of operations. The discharge of oil, gas or other
pollutants into the air, soil or water may give rise to significant liability on
our part to the government and third parties and may require us to incur
substantial costs of remediation. Moreover, we have agreed to indemnify sellers
of producing properties purchased in each of our substantial acquisitions
against environmental claims associated with these properties. We cannot assure
you that existing environmental laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations will not materially
adversely affect the results of our operations or our financial condition or
that material indemnity claims will not arise against us with respect to
properties we acquired.
Competition
We operate in the highly competitive areas of oil and gas exploration,
development, acquisition and production with other companies, many of which have
substantially larger financial resources, staffs and facilities. In seeking to
acquire desirable producing properties or new leases for future exploration and
in marketing our oil and gas production, we face intense competition from both
major and independent oil and gas companies. Many of these competitors have
financial and other resources substantially in excess of those available to us.
This highly competitive environment could have a material adverse effect on us.
Dependence on Key Personnel
Our success has been and will continue to be highly dependent on Jack
Hightower, our Chairman of the Board and Chief Executive Officer, and a limited
number of other senior management personnel. Loss of the services of Mr.
Hightower or any of those other individuals could have a material adverse effect
on our operations. We maintain a $3.0 million key man life insurance policy on
the life of Mr. Hightower, but no other senior management personnel. In
addition, as a result of our acquisitions, we have increased our number of
employees and employed 94 employees at December 31, 1998. We cannot assure you
that we will be successful in retaining key personnel. Our failure to hire
additional personnel, if necessary, or retain our key personnel could have a
material adverse effect on our business, financial condition and results of
operations.
Control by Existing Stockholders
Our directors, executive officers and principal stockholders, and certain of
our affiliates, beneficially own approximately 57.7% of our outstanding common
stock on a fully-diluted basis at March 1, 1999. Accordingly, these
stockholders, as a group, are able to control the outcome of stockholder votes,
including votes concerning the election of directors, the adoption or amendment
of provisions in our Amended Certificate of Incorporation or Bylaws and the
approval of mergers and other significant corporate transactions. The existence
of these levels of ownership concentrated in a few persons makes it unlikely
that any other holder of common stock will be able to affect our management or
direction. These factors may also have the effect of delaying or preventing a
change in our management or voting control.
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<PAGE>
Anti-Takeover Provisions
Delaware law includes a number of provisions that may have the effect of
delaying or deterring a change in the control of our management and encouraging
persons considering unsolicited tender offers or other unilateral takeover
proposals to negotiate with our Board of Directors rather than pursue non-
negotiated takeover attempts. These provisions may make it more difficult for
our stockholders to benefit from certain transactions which are opposed by the
incumbent Board of Directors.
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<PAGE>
FORWARD-LOOKING STATEMENTS
Certain statements contained in or incorporated by reference into this
prospectus, including, but not limited to, those regarding our financial
position, business strategy and other plans and objectives for future operations
and any other statements which are not historical facts constitute "forward-
looking statements" within the meaning of the Private Securities Litigation
Reform Act of 1995. Such forward-looking statements involve known and unknown
risks, uncertainties and other important factors that could cause our actual
results, performance or achievements, or industry results, to differ materially
from any future results, performance or achievements expressed or implied by
such forward-looking statements. Although we believe that the expectations
reflected in these forward-looking statements are reasonable, we cannot assure
you that the actual results or developments we anticipate will be realized or,
even if substantially realized, that they will have the expected effects on our
business or operations. Among the factors that could cause actual results to
differ materially from our expectations are inherent uncertainties in
interpreting engineering and reserve data, operating hazards, delays or
cancellations of drilling operations for a variety of reasons, competition,
fluctuations and volatility in oil and gas prices, our ability to successfully
integrate the business and operations of acquired companies, compliance with
government and environmental regulations, increases in our cost of borrowing or
inability or unavailability of capital resources to fund capital expenditures,
dependence on key personnel, changes in general economic conditions and/or in
the markets in which we compete or may, from time to time, compete and other
factors including but not limited to those set forth in "Risk Factors" or in
"Item 1" in this report. These factors expressly qualify all subsequent oral
and written forward-looking statements attributable to us or persons acting on
our behalf. We assume no obligation to update any of these statements.
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<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about
financial instruments to which the Company is a party as of December 31, 1998,
and from which the Company may incur future earnings gains or losses from
changes in market interest rates and commodity prices. The Company does not
enter into derivative or other financial instruments for trading purposes.
Quantitative Disclosures
Commodity Price Sensitivity:
The following table provides information about the Company's derivative
financial instruments that are sensitive to changes in natural gas commodity
prices. See notes 2, 3 and 17 of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
description of the accounting procedures followed by the Company for commodity
derivative financial instruments and for specific information regarding the
terms of the Company's commodity derivative financial instruments that are
sensitive to natural gas commodity prices.
<TABLE>
Fair
1999 2000 Total Value
---- ---- ----- -----
(dollars in thousands, except volumes and prices)
<S> <C> <C> <C> <C>
Natural Gas Hedge Derivatives (a)
Collar option contracts:
Notional volumes (MMBtu) 11,134 1,365 12,499 $ 2,729
Weighted average short call MMBtu strike price (b) $ 2.111 $2.200
Weighted average long put MMBtu strike price (b) $ 2.724 $2.550
Basis differential contracts (c):
Notional volumes (MMBtu) 10,839 1,365 12,204 $(1,056)
Weighted average MMBtu strike price $ 0.227 $0.218
</TABLE>
___________________________________
(a) See notes 3 and 17 of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional
information related to hedging activities.
(b) The strike prices are based on the prices traded on the New York Mercantile
("NYMEX").
(c) The basis differential relates to the spread between the NYMEX price and an
El Paso/Permian price.
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<PAGE>
Interest Rate Sensitivity:
The following table provides information about the Company's financial
instruments that are sensitive to interest rates. The debt obligations are
presented in the table at their contractual maturity dates together with the
weighted average interest rates expected to be paid on the debt. The weighted
average interest rates for the variable debt represents the weighted average
interest paid and/or accrued in December 1998. See notes 3 and 4 of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for specific information regarding the terms of the
Company's debt obligations that are sensitive to interest rates.
<TABLE>
Fair
1999 2000 2001 Total Value
---- ---- ---- ----- -----
(in thousands, except interest rates)
<S> <C> <C> <C> <C> <C>
Debt (a)
Variable rate debt:
Chase Manhattan Bank, N.A. (Secured) $140,000 $140,000 $140,000
Average interest rate 7.08% 7.08% 7.08%
Chase Bank of Texas, N.A. (Unsecured) $ 4,200 $ 4,200 $ 4,200
Average interest rate 6.42% 6.42% 6.42%
</TABLE>
- --------------------------
(a) See notes 3 and 4 of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional
information related to debt.
Qualitative Disclosures
The Company, from time to time, enters into interest rate and commodity price
derivative contracts as hedges against interest rate and commodity price risk.
See notes 2, 3 and 17 of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for discussions relative
to the Company's objectives and general strategies associated with it hedging
instruments. The Company is a borrower under variable rate debt instruments
that give rise to interest rate risk. See note 4 of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for specific information regarding the terms of the
Company's debt obligations. The Company's policy and strategy, as of December
31, 1998, is to only enter into interest rate and commodity price derivative
instruments that qualify as hedges of its existing interest rate or commodity
price risks.
As of December 31, 1998, the Company's primary risk exposures associated with
financial instruments to which it is a party include natural gas price
volatility and interest rate volatility. The Company's primary risk exposures
associated with financial instruments have not changed significantly since
December 31, 1997.
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<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's Consolidated Financial Statements required by this item are
included on the pages immediately following the Index to Consolidated Financial
Statements appearing on page F-1.
38
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
39
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference to
information under the caption "Proposal 1 - Election of Directors" and to the
information under the caption "Compliance with Section 16(a) of the Securities
Exchange Act of 1934" in the Company's definitive Proxy Statement (the "1999
Proxy Statement") for its annual meeting of stockholders to be held on or about
May 26, 1999. The 1999 Proxy Statement will be filed with the Securities and
Exchange Commission (the "Commission") not later than 120 days subsequent to
December 31, 1998.
Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to executive officers of the Company is set forth in Part I of
this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference to
the 1999 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 1998.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference to
the 1999 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 1998.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTION
The information required by this item is incorporated herein by reference to
the 1999 Proxy Statement, which will be filed with the Commission not later than
120 days subsequent to December 31, 1998.
40
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements:
See Index to Consolidated Financial Statements on page F-1.
2. Financial Statement Schedules:
See Index to Consolidated Financial Statements on page F-1.
3. Exhibits: The following documents are filed as exhibits to this report:
<TABLE>
<CAPTION>
Exhibit
Number
- --------- Description of Document
<S> <C>
2.1 -- Exchange Agreement and Plan of Reorganization (filed as Exhibit 2.1 to the
Company's Registration Statement on Form S-1, Registration No. 333-14029, and
incorporated herein by reference).
2.2 -- Amended and Restated Agreement and Plan of Merger, dated as of November 6,
1997, among Titan Exploration, Inc., Titan Offshore, Inc. and Offshore Energy
Development Corporation (included as Appendix I to the Joint Proxy
Statement/Prospectus forming a part of the Company's Registration Statement on
S-4, Registration No. 333-40215, and incorporated herein by reference).
2.3 -- Agreement and Plan of Merger, dated as of November 4, 1997, among Titan
Exploration, Inc., Titan Bayou Bengal Holdings, Inc. and Carrollton Resources,
L.L.C. (filed as Exhibit 2.3 to the Company's Registration Statement on S-4
Registration No. 333-40215 incorporated herein by reference).
3.1 -- Certificate of Incorporation (filed as Exhibit 3.1 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
3.1.1 -- Certificate of Amendment of Certificate of Incorporation (filed as Exhibit
3.1.1 to the Company's Registration Statement on Form S-1, Registration No.
333-14029, and incorporated herein by reference).
3.2 -- Bylaws (filed as Exhibit 3.2 to the Company's Registration Statement on Form
S-1, Registration No. 333-14029, and incorporated herein by reference).
10.1 -- Agreement of Limited Partnership, dated March 31, 1995, between Titan
Resources I, Inc., as general partner, and Natural Gas Partners, L.P., Natural Gas
Partners II, L.P. and Jack Hightower, as limited partners (filed as Exhibit 10.1
to the Company's Registration Statement on Form S-1, Registration No. 333-14029,
and incorporated herein by reference).
10.1.1 -- Amendment No. 1 to the Agreement of Limited Partnership of Titan Resources,
L.P., dated December 11, 1995, by and among Titan Resources I, Inc., as the
general partner, and a Majority Interest of the Limited Partners (filed as Exhibit
10.1.1 to the Company's Registration Statement on Form S-1, Registration No.
333-14029, and incorporated herein by reference).
10.1.2 -- Amendment No. 2 to the Agreement of Limited Partnership of Titan Resources,
L.P., dated September 27, 1996, by and among Titan Resources I, Inc., as the
general partner, and a Majority Interest of the Limited Partners (filed as Exhibit
10.1.2 to the Company's Registration Statement on Form S-1, Registration No.
333-14029, and incorporated herein by reference).
10.1.3 -- Amendment No. 3 to the Agreement of Limited Partnership of Titan Resources,
L.P., dated September 30, 1996, by and among Titan Resources I, Inc., as the
general partner, and a Majority Interest of the Limited Partners (filed as Exhibit
10.1.3 to the Company's Registration
</TABLE>
41
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number
- --------- Description of Document
<S> <C>
Statement on Form S-1, Registration No. 333-14029, and incorporated herein by
reference).
10.2 -- Amended and Restated Voting and Shareholders Agreement, dated December 11,
1995, by and among Titan Resources I, Inc., Jack Hightower, Natural Gas Partners,
L.P., Natural Gas Partners II, L.P., Joint Energy Development Investments Limited
Partnership and First Union Corporation (filed as Exhibit 10.2 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.3 -- Amended and Restated Registration Rights Agreement, dated September 30, 1996,
by and among Titan Exploration, Inc., Jack Hightower, Natural Gas Partners, L.P.,
Natural Gas Partners II, L.P., Joint Energy Development Investments Limited
Partnership, First Union Corporation and Selma International Investment Limited
(filed as Exhibit 10.3 to the Company's Registration Statement on Form S-1,
Registration No. 333-14029, and incorporated herein by reference).
10.4 -- Financial Advisory Services Contract, dated March 31, 1995, by and between
Titan Resources, L.P. and Natural Gas Partners, L.P. and Natural Gas Partners II,
L.P. (filed as Exhibit 10.4 to the Company's Registration Statement on Form S-1,
Registration No. 333-14029, and incorporated herein by reference).
10.4.1 -- First Amendment to Financial Advisory Services Contract, dated December 11,
1995, between Titan Resources, L.P., Natural Gas Partners, L.P. and Natural Gas
Partners II, L.P. (filed as Exhibit 10.4.1 to the Company's Registration Statement
on Form S-1, Registration No. 333-14029, and incorporated herein by reference).
10.5 -- Employment Agreement, dated September 30, 1996, by and between Titan
Exploration, Inc., Titan Resources I, Inc. and Jack Hightower (filed as Exhibit
10.5 to the Company's Registration Statement on Form S-1, Registration No.
333-14029, and incorporated herein by reference).
10.6.1 -- Form of Confidentiality and Non-compete Agreement among Titan Resources, L.P.,
Titan Resources I, Inc. and certain of the Registrant's executive officers (filed
as Exhibit 10.6.1 to the Company's Registration Statement on Form S-1,
Registration No. 333-14029, and incorporated herein by reference).
10.6.2 -- Form of Confidentiality and Non-compete Agreement among the Registrant, Titan
Resources I, Inc. and certain of the Registrant's executive officers (filed as
Exhibit 10.6.2 to the Company's Registration Statement on Form S-1, Registration
No. 333-14029, and incorporated herein by reference).
10.7 -- Titan Resources, L.P. Option Plan (filed as Exhibit 10.7 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.7.1 -- Form of Option Agreement (A Option) (filed as Exhibit 10.7.1 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.7.2 -- Form of Option Agreement (B Option) (filed as Exhibit 10.7.2 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.7.3 -- Form of Option Agreement (C Option) (filed as Exhibit 10.7.3 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.7.4 -- Form of Option Agreement (D Option) (filed as Exhibit 10.7.4 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.8 -- Titan Exploration, Inc., Option Plan (filed as Exhibit 10.8 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
</TABLE>
42
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number
- --------- Description of Document
<S> <C>
10.8.1 -- Form of Option Agreement (A Option) (filed as Exhibit 10.8.1 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.8.2 -- Form of Option Agreement (B Option) (filed as Exhibit 10.8.2 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.8.3 -- Form of Option Agreement (C Option) (filed as Exhibit 10.8.3 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.8.4 -- Form of Option Agreement (D Option) (filed as Exhibit 10.8.4 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.9 -- 1996 Incentive Plan (filed as Exhibit 10.9 to the Company's Registration
Statement on Form S-1, Registration No. 333-14029, and incorporated herein by
reference).
10.10 -- Stock and Unit Purchase Agreement, dated December 11, 1995, by and among Joint
Energy Development Investments Limited Partnership, Titan Resources I, Inc. and
Titan Resources, L.P. (filed as Exhibit 10.10 to the Company's Registration
Statement on Form S-1, Registration No. 333-14029, and incorporated herein by
reference).
10.10.1 -- Designation Agreement, dated December 11, 1995, by and between Titan
Resources, L.P. and Joint Energy Development Investments Limited Partnership
(filed as Exhibit 10.10.1 to the Company's Registration Statement on Form S-1,
Registration No. 333-14029, and incorporated herein by reference).
10.11 -- Stock and Unit Purchase Agreement, dated December 11, 1995, by and among First
Union Corporation, Titan Resources I, Inc. and Titan Resources, L.P. (filed as
Exhibit 10.11 to the Company's Registration Statement on Form S-1, Registration
No. 333-14029, and incorporated herein by reference).
10.11.1 -- Designation Agreement, dated December 11, 1995, by and between Titan
Resources, L.P. and First Union Corporation (filed as Exhibit 10.11.1 to the
Company's Registration Statement on Form S-1, Registration No. 333-14029, and
incorporated herein by reference).
10.12 -- Advisory Services Contract, dated December 11, 1995, between Titan Resources,
L.P. and ECT Securities Corp. (filed as Exhibit 10.12 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.13 -- Amended and Restated Credit Agreement, dated October 31, 1996, among Titan
Resources, L.P. and Texas Commerce Bank National Association, as Agent, and
Financial Institutions now or hereafter parties hereto (filed as Exhibit 10.13 to
the Company's Registration Statement on Form S-1, Registration No. 333-14029, and
incorporated herein by reference).
10.14 -- First Amendment to Amended and Restated Credit Agreement, dated May 12, 1997,
among Titan Resources, L.P., The Chase Manhattan Bank, as Administrative Agent,
and Financial Institutions now or thereafter parties thereto (filed as Exhibit
10.13.1 to the Company's Form 10-Q for the quarterly period ended June 30, 1997
and incorporated herein by reference).
10.15 -- Form of Guaranty Agreement among The Chase Manhattan Bank, as Administrative
Agent, Financial Institutions now or thereafter parties thereto and Titan
Exploration, Inc., Titan Resources I, Inc. and Titan Resources Holdings, Inc.
(filed as Exhibit 10.13.2 to the Company's Form 10-Q for the quarterly period
ended June 30, 1997 and incorporated herein by reference).
10.16 -- Second Amendment to Amended and Restated Credit Agreement, dated May 12, 1997,
effective as of April 1, 1997, by and among Titan Resources, L.P., The Chase
Manhattan Bank, as Administrative Agent, and Financial Institutions now or
thereafter parties thereto (filed as Exhibit 10.13.3 to the Company's Form 10-Q
for the quarterly period ended September 30,
</TABLE>
43
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number
- --------- Description of Document
<S> <C>
1997 and incorporated herein by reference).
10.17 -- Third Amendment to the Amended and Restated Credit Agreement, dated December
12, 1997, among Titan Resources, L.P., the Chase Manhattan Bank, as Administrative
Agent and Financial Institutions now or thereafter parties thereto (filed as
Exhibit 10 to the Company's Form 10-Q for the quarterly period ended June 30, 1998
and incorporated herein by reference.
10.18 -- Agreement of Sale and Purchase, dated April 19, 1995, between Enertex, Inc.
and Titan Resources, L.P. (filed as Exhibit 10.14 to the Company's Registration
Statement on Form S-1, Registration No. 333-14029, and incorporated herein by
reference).
10.19 -- Agreement of Sale and Purchase, dated April 19, 1995, between Staley Gas Co.,
Inc. and Titan Resources, L.P. (filed as Exhibit 10.15 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.20 -- Administrative Services Contract, dated March 31, 1995, between Staley
Operating Co. and Titan Resources, L.P. (filed as Exhibit 10.16 to the Company's
Registration Statement on Form S-1, Registration No. 333-14029, and incorporated
herein by reference).
10.21 -- Services Agreement, dated April 1, 1995, between Titan Resources I, Inc. and
Titan Resources, L.P. (filed as Exhibit 10.17 to the Company's Registration
Statement on Form S-1, Registration No. 333-14029, and incorporated herein by
reference).
10.22 -- Office Lease, dated April 10, 1997, between Fasken Center, Ltd. and Titan
Exploration, Inc. (filed as Exhibit 10.17 to the Company's Registration Statement
on Form S-4, Registration No. 333-40215 incorporated herein by reference).
10.23 -- Lease Amendment to the Lease Agreement dated April 4, 1997 between Fasken
Center, LTD. and Titan Exploration, Inc. (filed as Exhibit 10.1 to the Company's
Form 10-Q for the quarterly period ended September 30, 1998 and incorporated
herein by reference).
10.24 -- Purchase and Sale Agreement, dated October 12, 1995, by and between Anadarko
Petroleum Corporation and Titan Resources, L.P. (filed as Exhibit 10.19 to the
Company's Registration Statement on Form S-1, Registration No. 333-14029, and
incorporated herein by reference).
10.25 -- Amendment No. 1 to Purchase and Sale Agreement, dated December 11, 1995, by
and between Anadarko Petroleum Corporation and Titan Resources, L.P. (filed as
Exhibit 10.20 to the Company's Registration Statement on Form S-1, Registration
No. 333-14029, and incorporated herein by reference).
10.26 -- Purchase and Sale Agreement, dated July 12, 1996, by and between Mobil
Producing Texas & New Mexico Inc. and Titan Resources, L.P. (filed as Exhibit
10.21 to the Company's Registration Statement on Form S-1, Registration No.
333-14029, and incorporated herein by reference).
10.27 -- Unit Purchase and Exchange Agreement, dated September 27, 1996, by and between
Selma International Investment Limited and Titan Resources, L.P. (filed as Exhibit
10.22 to the Company's Registration Statement on Form S-1, Registration No.
333-14029, and incorporated herein by reference).
10.28 -- Form of Indemnity Agreement between the Registrant and each of its executive
officers (filed as Exhibit 10.23 to the Company's Registration Statement on Form
S-1, Registration No. 333-14029, and incorporated herein by reference).
10.29 -- Advisory Director Agreement, dated September 30, 1996, by and between Titan
Exploration, Inc. and Joint Energy Development Investments Limited Partnership
(filed as Exhibit 10.24 to the Company's Registration Statement on Form S-1,
Registration No. 333-14029, and incorporated herein by reference).
10.30 -- Form of Stockholders Voting Agreement, dated November 6, 1997, between Titan
</TABLE>
44
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number
- --------- Description of Document
<S> <C>
Exploration, Inc. and the executive officers and directors of Offshore Energy
Development Corporation (filed as Exhibit 10.24 to the Company's Registration
Statement on S-4, Registration No. 333-40215, and incorporated herein by
reference).
10.31 -- Stockholders Voting Agreement, dated November 6, 1997, between Titan
Exploration, Inc. and Natural Gas Partners, L.P. (filed as Exhibit 10.25 to the
Company's Registration Statement on S-4, Registration No. 333-40215, and
incorporated herein by reference).
10.32 -- Master Promissory Note, dated March 6, 1997, between Titan Resources, L.P. and
Chase Bank of Texas, National Association (filed as Exhibit 10 to the Company's
Form 10-Q for the quarterly period ended March 31, 1998 and incorporated herein by
reference).
10.33 -- Letter Agreement, dated November 6, 1997, among Titan Exploration, Inc. and
certain stockholders of Titan Exploration, Inc. (filed as Exhibit 10.29 to the
Company's Registration Statement on S-4, Registration No. 333-40215, and
incorporated herein by reference).
10.34 -- Titan Matching Plan, effective as of September 1, 1998 (filed as Exhibit 10.2
to the Company's Form 10-Q for the quarterly period ended September 30, 1998 and
incorporated herein by reference).
10.35 -- Amended and Restated Titan 401(k) Plan, effective as of September 1,1998.
(filed as Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 333-62115, and incorporated herein by reference).
21 -- Subsidiaries of the Registrant.
23 -- Consent of independent auditors.
27 -- Financial Data Schedule.
</TABLE>
(b) No reports on Form 8-K were filed by the Company during the last quarter of
the period covered by this Annual Report on Form 10-K:
45
<PAGE>
GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of terms commonly used in the
oil and gas industry and this report. Unless otherwise indicated in this
report, natural gas volumes are stated at the legal pressure base of the state
or area in which the reserves are located and at 60 degrees Fahrenheit and in
most instances are rounded to the nearest major multiple. BOEs are determined
using the ratio of six Mcf of natural gas to one Bbl of oil.
"Bbl" means a barrel of 42 U.S. gallons of oil.
"Bcf" means billion cubic feet of natural gas.
"Bcfe" means billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
"BOE" means barrels of oil equivalent.
"Completion" means the installation of permanent equipment for the production of
oil or gas.
"Development well" means a well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
"Exploratory well" means a well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
"Gross," when used with respect to acres or wells, refers to the total acres or
wells in which the Company has a working interest.
"Horizontal drilling" means a drilling technique that permits the operator to
contact and intersect a larger portion of the producing horizon than
conventional vertical drilling techniques and can result in both increased
production rates and greater ultimate recoveries of hydrocarbons.
"MBbls" means thousands of barrels of oil.
"Mcf" means thousand cubic feet of natural gas.
"Mcfe" means 1,000 cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
"MMBbls" means millions of barrels of oil.
"MMBOE" means millions of barrels of oil equivalent on a 6:1 basis.
"MMcf" means million cubic feet of natural gas.
"MMcfe" means million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
"Net," when used with respect to acres or wells, refers to gross acres of wells
multiplied, in each case, by the percentage working interest owned by the
Company.
"Net production" means production that is owned by the Company less royalties
and production due others.
"Oil" means crude oil or condensate.
46
<PAGE>
"Operator" means the individual or company responsible for the exploration,
development, and production of an oil or gas well or lease.
"Present Value of Future Revenues" or "PV-10" means the pretax present value of
estimated future revenues to be generated from the production of proved reserves
calculated in accordance with SEC 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 and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
"Proved developed reserves" means reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery will be included as "proved developed
reserves" only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
"Proved reserves" means the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
i. Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (A) that portion delineated by drilling and
defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
ii. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
iii. Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids that may be
recovered from oil shales, coal, gilsonite and other such sources.
"Proved undeveloped reserves" means reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.
"Recompletion" means the completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
"Reserves" means proved reserves.
47
<PAGE>
"Royalty" means an interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
"3-D seismic" means seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
"Tertiary recovery" means enhanced recovery methods for the production of oil or
gas. Enhanced recovery of crude oil requires a means for displacing oil from
the reservoir rock, modifying the properties of the fluids in the reservoir
and/or the reservoir rock to cause movement of oil in an efficient manner, and
providing the energy and drive mechanism to force its flow to a production well.
The Company injects chemicals or energy as required for displacement and for the
control of flow rate and flow pattern in the reservoir, and a fluid drive is
provided to force the oil toward a production well.
"Working interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties. For example, the owner of a 100% working
interest in a lease burdened only by a landowner's royalty of 12.5% would be
required to pay 100% of the costs of a well but would be entitled to retain
87.5% of the production.
"Workover" means operations on a producing well to restore or increase
production.
48
<PAGE>
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, hereunder duly authorized, as of March 30, 1999.
TITAN EXPLORATION, INC.
Registrant
By: /s/ Jack Hightower
-----------------------------------------
Jack Hightower
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below as of March 30, 1999, by the following persons on behalf
of the Registrant and in the capacity indicated.
/s/ Jack Hightower
- -------------------------------
Jack Hightower
President of Directors, Chief Executive Officer and Chairman of the Board
/s/ George G. Staley
- -------------------------------
George G. Staley
Executive Vice President, Exploration and Director
/s/ William K. White
- -------------------------------
William K. White
Vice President, Finance and Chief Financial Officer
/s/ David R. Albin
- -------------------------------
David R. Albin
Director
/s/ Kenneth A. Hersh
- -------------------------------
Kenneth A. Hersh
Director
/s/ William J. Vaughn, Jr.
- -------------------------------
William J. Vaughn, Jr.
Director
49
<PAGE>
Index To Consolidated Financial Statements
<TABLE>
<CAPTION>
Page
----
<S> <C>
Consolidated Financial Statements of Titan Exploration, Inc.
Independent Auditors' Report F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997 F-3
Consolidated Statements of Operations for the years ended December 31, 1998, 1997 and 1996 F-4
Consolidated Statements of Stockholders' Equity and Predecessor Capital for the
years ended December 31, 1998, 1997 and 1996 F-5
Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996 F-6
Notes to Consolidated Financial Statements F-7
</TABLE>
All schedules are omitted, as the required information is inapplicable or the
information is presented in the financial statements or related notes.
F-1
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Titan Exploration, Inc.
We have audited the consolidated financial statements of Titan Exploration, Inc.
(the "Company") as listed in the accompanying index. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Titan Exploration,
Inc. as of December 31, 1998 and 1997, and the results of their operations and
their cash flows for each of the years in the three year period ended December
31, 1998, in conformity with generally accepted accounting principles.
KPMG LLP
Midland, Texas
March 5, 1999
F-2
<PAGE>
TITAN EXPLORATION, INC.
Consolidated Balance Sheets
(in thousands, except share data)
<TABLE>
<CAPTION>
December 31,
------------------------
ASSETS 1998 1997
---------- -----------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 610 $ 1,603
Restricted investment - 2,331
Accounts receivable:
Oil and gas 13,497 13,663
Other 761 2,900
Inventories 1,276 624
Assets held for sale 109,452 -
Prepaid expenses and other current assets 316 531
-------- --------
Total current assets 125,912 21,652
-------- --------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 306,111 366,105
Other property and equipment 6,340 2,421
Accumulated depletion, depreciation and amortization (98,095) (94,387)
-------- --------
214,356 274,139
Investments in affiliates and others - 55,900
Other assets, net of accumulated amortization of $639 in 1998 and $413 in 1997 754 892
-------- --------
$341,022 $352,583
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Trade $ 14,097 $ 16,421
Accrued interest 466 307
Other (Note 19) 5,652 4,896
-------- --------
Total current liabilities 20,215 21,624
-------- --------
Long-term debt 144,200 85,450
Other liabilities (Note 19) 5,253 2,720
Deferred income tax payable - 10,368
Stockholders' equity:
Preferred Stock, $.01 par value, 10,000,000 shares authorized; none issued and outstanding - -
Common Stock, $.01 par value, 60,000,000 shares authorized; 40,534,675 and 40,332,497
shares issued and outstanding at December 31, 1998 and 1997, respectively
405 403
Additional paid-in capital 278,109 277,500
Treasury stock, at cost; 2,600,000 and 55,000 shares at December 31, 1998 and 1997,
respectively (20,020) (504)
Deferred compensation (5,053) (10,108)
Accumulated deficit (82,087) (34,870)
-------- --------
Total stockholders' equity 171,354 232,421
-------- --------
Commitments and contingencies (Note 7)
$341,022 $352,583
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
F-3
<PAGE>
TITAN EXPLORATION, INC.
Consolidated Statements of Operations
(in thousands, except share and per share data)
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------------------
1998 1997 1996
---------- ---------- ---------
<S> <C> <C> <C>
Revenues:
Gas sales $ 42,844 $ 38,715 $10,138
Oil sales 30,032 35,112 13,686
-------- -------- -------
Total revenues 72,876 73,827 23,824
-------- -------- -------
Expenses:
Oil and gas production 27,078 16,298 7,312
Production and other taxes 5,725 5,548 1,887
General and administrative 9,163 5,372 2,270
Amortization of stock option awards 5,055 5,053 1,839
Exploration and abandonment (Note 20) 17,596 3,055 184
Depletion, depreciation and amortization 27,090 19,972 5,789
Impairment of long-lived assets 25,666 68,997 -
Restructuring costs 625 - -
-------- -------- -------
Total expenses 117,998 124,295 19,281
-------- -------- -------
Operating income (loss) (45,122) (50,468) 4,543
-------- -------- -------
Other income (expense):
Interest income 125 190 424
Interest expense (8,648) (1,524) (2,965)
Gain (loss) on sale of assets 923 58 (65)
Management fees - affiliate 8 10 144
Equity in net loss of affiliates (458) - -
Other 574 - -
-------- -------- -------
Income (loss) before income taxes (52,598) (51,734) 2,081
-------- -------- -------
Income tax expense (benefit) (5,381) (18,267) 3,484
-------- -------- -------
Net loss $(47,217) $(33,467) $(1,403)
======== ======== =======
Net loss per common share $ (1.22) $ (.99) $ (.07)
======== ======== =======
Net loss per common share - assuming dilution $ (1.22) $ (.99) $ (.07)
======== ======== =======
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
TITAN EXPLORATION, INC.
Consolidated Statements of Stockholders' Equity and Predecessor Capital
(in thousands)
<TABLE>
<CAPTION>
Additional Total
Predecessor Common Paid-in Treasury Deferred Accumulated Stockholders'
Capital Stock Capital Stock Compensation Deficit Equity
------- ------ ------- ------ ------------ ------- ------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995 $ 37,081 $ - $ - $ - $ (2,496) $ - $ 34,585
Sale of interest in predecessor 5,000 - - - - - 5,000
September 30, 1996 stock plan - - 14,504 - (14,504) - -
Common stock issued - 144 147,021 - - - 147,165
Deferred compensation - - - - 1,839 - 1,839
Net loss - - - - - (1,403) (1,403)
Transfer of predecessor capital
and issuance of common stock
pursuant to the Offering (42,081) 195 41,886 - - - -
-------- ----- --------- ---------- --------- --------- ---------
Balance, December 31,1996 - 339 203,411 - (15,161) (1,403) 187,186
Stock options exercised - - 9 - - - 9
Tax benefit of stock options
exercised - - 6 - - - 6
Common stock issued - - (41) - - - (41)
Acquisitions for common stock - 64 74,115 - - - 74,179
Purchase of treasury stock - - - (504) - - (504)
Deferred compensation - - - - 5,053 - 5,053
Net loss - - - - - (33,467) (33,467)
-------- ----- --------- ---------- --------- --------- ---------
Balance, December 31, 1997 - 403 277,500 (504) (10,108) (34,870) 232,421
Stock options exercised - 2 546 - - - 548
Tax benefit of stock options
exercised - - 63 - - - 63
Purchase of treasury stock - - - (19,516) - - (19,516)
Deferred compensation - - - - 5,055 - 5,055
Net loss - - - - - (47,217) (47,217)
-------- ----- --------- ---------- --------- --------- ---------
Balance, December 31, 1998 $ - $ 405 $ 278,109 $ (20,020) $ (5,053) $ (82,087) $ 171,354
======== ===== ========= ========= ========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE>
TITAN EXPLORATION, INC.
Consolidated Statements of Cash Flows
(in thousands)
<TABLE>
<CAPTION>
Year ended December 31,
------------------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss $ (47,217) $ (33,467) $ (1,403)
Adjustments to reconcile net loss to net cash provided by operating
activities:
Depletion, depreciation and amortization 27,090 19,972 5,789
Impairment of long-lived assets 25,666 68,997 -
Amortization of stock option awards 5,055 5,053 1,839
Dry holes and abandonments 14,118 1,053 21
(Gain) loss on sale of assets (923) (58) 65
Equity in net loss of affiliates 458 - -
Deferred income taxes (5,381) (18,267) 3,484
Restructuring costs 625 - -
Other items 672 - -
Changes in assets and liabilities, excluding acquisitions:
Decrease (increase) in accounts receivable 1,279 (1,595) (7,311)
Increase in prepaid expenses and other current assets (445) (463) (145)
Decrease (increase) in other assets 36 (96) (516)
Increase (decrease) in accounts payable and accrued liabilities (2,585) 5,434 5,887
--------- --------- ---------
Total adjustments 65,665 80,030 9,113
--------- --------- ---------
Net cash provided by operating activities 18,448 46,563 7,710
--------- --------- ---------
Cash flows from investing activities:
Redemption of short-term investment 2,331 - 5,000
Investing in oil and gas properties (57,432) (112,301) (149,901)
Payments for acquisitions, net of cash acquired (715)
Additions to other property and equipment (3,919) (1,361) (218)
Contributions in equity investments of affiliates (1,884) - -
Proceeds from sale of assets 2,491 75 121
--------- --------- ---------
Net cash used in investing activities (58,413) (114,302) (144,998)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from debt 60,100 63,588 -
Payments of debt (1,350) - (13,500)
Capital contributions - - 3,700
Proceeds from initial common stock offering - - 148,376
Direct costs of initial common stock offering - (41) (1,211)
Exercise of stock options 548 9 -
Purchase of treasury stock (19,516) (504) -
Other financing activities (810) - -
--------- --------- ---------
Net cash provided by financing activities 38,972 63,052 137,365
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents
(993) (4,687) 77
Cash and cash equivalents, beginning of year 1,603 6,290 6,213
--------- --------- ---------
Cash and cash equivalents, end of year $ 610 $ 1,603 $ 6,290
========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
December 31, 1998, 1997 and 1996
(1) Organization and Nature of Operations
Titan Exploration, Inc. (the "Company") a Delaware corporation, was
organized on September 27, 1996 and began operations on September 30, 1996 with
the combination, pursuant to the terms of an Exchange Agreement and Plan of
Reorganization (the "Exchange Agreement"), of Titan Resources I, Inc. (the
"General Partner"), a Texas corporation, and Titan Resources, L.P. (the
"Partnership"). Under the exchange agreement, the limited partners of the
Partnership transferred all of their limited partnership interests to the
Company in exchange for 19,318,199 shares of common stock, and the shareholders
of the General Partner transferred all of the issued and outstanding stock of
that corporation to the Company in exchange for an aggregate of 231,814 shares
of common stock. These transactions are referred to as the "Conversion."
Prior to the Conversion, the Company had no issued or outstanding shares of
common stock and there was no public market for the General Partner's common
stock. All shares of the Company issued in the Conversion were issued to the
shareholders of the General Partner or to the limited partners of the
Partnership. The combination of the Company, the General Partner and the
Partnership is treated as a combination of entities under common control because
of the 100% commonality of control between the Company subsequent to the
Conversion and the Partnership prior to the Conversion. All partners of the
Partnership were party to the exchange of shares in the Conversion.
Consequently, the accompanying consolidated financial statements have given
effect to the Conversion as if it were a pooling of interests. Revenues and
costs arising from transactions between the two predecessor entities (the
General Partner and the Partnership) have been eliminated. The following table
sets forth revenues and net income with respect to the two predecessor entities
(in thousands):
<TABLE>
<CAPTION>
Year ended
December 31,
1996
----
<S> <C>
Revenues:
General Partner $ -
Partnership 23,968
Intercompany eliminations -
--------
$ 23,968
========
Net income (loss):
General Partner $ (66)
Partnership 1,502
The Company (2,839)
--------
$ (1,403)
========
</TABLE>
(Continued)
F-7
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
The Company is an independent energy company engaged primarily in the
exploration, development and acquisition of oil and gas properties. Since its
inception in March 1995, the Company has experienced significant growth,
primarily through the acquisition of companies and oil and gas properties and
the exploitation of these properties in the Permian Basin region of west Texas
and southeastern New Mexico, Gulf Coast region and the Gulf of Mexico.
(2) Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries. Investments in corporate joint ventures and
partnerships where the Company has ownership interest of 50% or less are
accounted for on the equity method. All investments with an ownership interest
of less than 20% and no significant control are accounted for on the cost
method. All material intercompany accounts and transactions have been eliminated
in the consolidation.
Use of Estimates in the Preparation of Financial Statements
Preparation of the accompanying consolidated 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 consolidated financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
Cash and Cash Equivalents
For purposes of the statements of cash flows, the Company considers all
demand deposits, money market accounts and certificates of deposit purchased
with an original maturity of three months or less to be cash equivalents.
Inventories
Inventories consist of lease and well equipment not currently being used in
production and are accounted for at the lower of cost (first-in, first-out) or
market.
Oil and Gas Properties
The Company utilizes the successful efforts method of accounting for its
oil and gas properties. Under this method of accounting, all costs associated
with productive wells and nonproductive development wells are capitalized.
Exploration costs are capitalized pending determination of whether proved
reserves have been found. If no proved reserves are found, previously
capitalized exploration costs are charged to expense.
Costs of significant nonproducing properties, wells in the process of being
drilled and development projects are excluded from depletion until such time as
the related project is developed and proved reserves are established or
impairment is determined. The Company capitalizes interest on expenditures for
significant development projects until such time as significant operations
commence.
(Continued)
F-8
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
Capitalized costs of individual properties abandoned or retired are charged
to accumulated depletion, depreciation and amortization. Sales proceeds from
sales of individual properties are credited to property costs. No gain or loss
is recognized until the entire amortization base is sold or abandoned.
Other property and equipment are recorded at cost. Major renewals and
betterments are capitalized while the costs of repairs and maintenance are
charged to operating expenses in the period incurred. With respect to
dispositions of assets other than oil and gas properties, the cost of assets
retired or otherwise disposed of, and the applicable accumulated depreciation
are removed from the accounts, and the resulting gains or losses, if any, are
reflected in operations.
Depletion, Depreciation and Amortization
Provision for depletion of oil and gas properties is calculated using the
unit-of-production method on the basis of an aggregation of properties with a
common geologic structural feature or stratigraphic condition, typically a field
or reservoir. In addition, estimated costs of future dismantlement, restoration
and abandonment, if any, are accrued as a part of depletion, depreciation and
amortization expense on a unit of production basis; actual costs are charged to
the accrual. Other property and equipment is depreciated using the straight-
line method over the estimated useful lives of the assets. Organization costs
are amortized over five years, while loan costs are amortized over the life of
the related loan.
Impairment of Long-Lived Assets
The Company follows the provisions of Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of" ("FAS 121"). Consequently, the Company
reviews its long-lived assets to be held and used, including oil and gas
properties accounted for under the successful efforts method of accounting and
other identifiable intangible assets, whenever events or circumstances indicate
that the carrying value of those assets may not be recoverable. An impairment
loss is indicated if the sum of the expected future cash flows, on a depletable
unit basis, is less than the carrying amount of such assets. In this
circumstance, the Company recognizes an impairment loss for the amount by which
the carrying amount of the asset exceeds the fair value of the asset.
The Company accounts for long-lived assets to be disposed of at the lower of
their carrying amount or fair value less cost to sell once management has
committed to a plan to dispose of the assets.
Net Income (Loss) per Common Share
In 1997, the Financial Accounting Standards Board issued Statement No. 128,
"Earnings per Share" ("FAS 128"). FAS 128 replaced the calculation of primary
and fully diluted earnings per share with basic and diluted earnings per share.
Unlike primary earnings per share, basic earnings per share excludes any
dilutive effects of options, warrants and convertible securities. Diluted
earnings per share is very similar to the previously reported fully diluted
earnings per share. All earnings per share amounts for all periods have been
presented, and when appropriate, restated to conform to the FAS 128
requirements. For the periods prior to the Offering, the weighted average
shares outstanding attributable to predecessor capital are the shares issued to
the predecessor members upon Conversion.
(Continued)
F-9
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
Income Taxes
The Company follows the provisions of Financial Accounting Standards No. 109,
"Accounting for Income Taxes" ("FAS 109"). Under the asset and liability method
of FAS 109, deferred tax assets and liabilities are recognized for the future
tax consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Under FAS 109, the effect
on deferred tax assets and liabilities of a change in tax rate is recognized in
income in the period that includes the enactment date.
Upon Conversion, the Company recorded the tax effect of the differences
between the book and tax basis of its assets and liabilities as a deferred tax
liability and a corresponding charge to deferred income tax expense.
Environmental
The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which are constantly changing, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities for
expenditures of a noncapital nature are recorded when environmental assessment
and/or remediation is probable, and the costs can be reasonably estimated.
Revenue Recognition
The Company uses the sales method of accounting for crude oil revenues.
Under this method, revenues are recognized based on actual volumes of oil sold
to purchasers.
The Company uses the entitlements method of accounting for natural gas
revenues. Under this method, revenues are recognized based on the Company's
proportionate share of actual sales of natural gas. Natural gas revenues would
not have been significantly altered in any period had the sales method of
recognizing natural gas revenues been utilized. The Company has a net liability
of approximately $225,000 and a net asset of approximately $318,000 at December
31, 1998 and December 31, 1997, respectively, associated with gas balancing
recorded.
The Company recognizes marketing revenue net of the cost of gas and third-
party delivery fees as service is provided.
Stock-based Compensation
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APB 25"). Accordingly, the Company
has only adopted the disclosure provisions of Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"). See
Note 13 for the pro forma disclosures of compensation expense determined under
the fair-value provisions of FAS 123.
(Continued)
F-10
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
Treasury Stock
Treasury stock purchases are recorded at cost. Upon reissuance, the cost of
treasury shares held is reduced by the average purchase price per share of the
aggregate treasury shares held.
Commodity Hedging
The financial instruments that the Company accounts for as hedging contracts
must meet the following criteria: the underlying asset or liability must expose
the Company to price or interest rate risk that is not offset in another asset
or liability, the hedging contract must reduce that price or interest rate risk
at the inception of the contract and throughout the contract period, and the
instrument must be designated as a hedge. In order to qualify as a hedge, there
must be clear correlation between changes in the fair value of the financial
instrument and the fair value of the underlying asset or liability such that
changes in the market value of the financial instrument will be offset by the
effect of price or interest rate changes on the exposed items.
The Company periodically enters into commodity derivative contracts in order
to hedge the effect of price changes on commodities the Company produces and
sells. Gains and losses on contracts that are designed to hedge commodities are
included in income recognized from the sale of those commodities. Gains and
losses on derivative contracts which do not qualify as hedges are recognized in
each period based on the market value of the related instrument.
Interest Rate Swap Agreements
The Company enters into interest rate swap agreements to effectively convert
a portion of its floating-rate borrowings into fixed rate obligations. The
interest rate differential to be received or paid is recognized over the lives
of the agreements as an adjustment to interest expense. At December 31, 1998,
the Company was not subject to any interest rate swap agreements.
Reclassifications
Certain reclassifications have been made to the 1997 and 1996 amounts to
conform to the 1998 presentation.
(Continued)
F-11
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(3) Disclosures About Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments (in thousands):
<TABLE>
<CAPTION>
December 31,
---------------------------------------------------------------------
1998 1997
------------------------------ ------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------ ----- ------ -----
<S> <C> <C> <C> <C>
Financial assets:
Cash and cash equivalents $ 610 $ 610 $ 1,603 $ 1,603
Restricted investments - - 2,331 2,331
Financial liabilities:
Debt:
Line of credit 140,000 140,000 84,100 84,100
Unsecured line of credit 4,200 4,200 - -
Other - - 1,350 1,350
Off-balance sheet financial instruments
(see Note 17):
Commodity price hedges - 1,673 - 1,683
</TABLE>
Cash and cash equivalents, restricted cash, accounts receivable, other
current assets, accounts payable and other current liabilities. The carrying
amounts approximate fair value due to the short maturity of these instruments.
Restricted investments. The fair value of noncurrent investments is based on
quoted market prices.
Debt. The carrying amount of long-term debt approximates fair value because
the Company's current borrowing rate does not materially differ from market
rates for similar bank borrowings.
Commodity price hedges. The fair market values of commodity derivative
instruments are estimated based upon the current market price of the respective
commodities at the date of valuation. It represents the amount which the
Company would be required to pay or able to receive based upon the differential
between a fixed and a variable commodity price as specified in the hedge
contracts.
(Continued)
F-12
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(4) Debt
Debt consists of the following (in thousands):
<TABLE>
<CAPTION>
December 31,
-------------------------------
1998 1997
---- ----
<S> <C> <C>
Line of credit $ 140,000 $ 84,100
Unsecured line of credit 4,200 -
Other - 1,350
--------- --------
$ 144,200 $ 85,450
========= ========
</TABLE>
Line of Credit
On October 31, 1996, the Company entered into a credit agreement, as
amended, (the "Credit Agreement") with Chase Manhattan Bank, N.A. which
establishes a four year revolving credit facility, up to the maximum amount of
$250 million subject to a borrowing base. All amounts outstanding are due and
payable in full by January 1, 2001. The borrowing base, which was $200 million
at December 31, 1998, is subject to redetermination semiannually by the lenders
based on certain proved oil and gas reserves and other assets of the Company
with the next redetermination date scheduled for April 1, 1999.
The Credit Agreement, which is secured by a majority of the Company's
proved oil and gas reserves, is subject to mandatory prepayments. To the extent
that the borrowing base is less than the aggregate principal amount of all
outstanding loans and letters of credit under the Credit Agreement, such
deficiency must be cured by the Company within 180 days, by either prepaying a
portion of the outstanding amounts or pledging additional collateral. Commitment
fees are due quarterly and range from .300% to .375% per annum on the difference
between the commitment and the average daily amount outstanding.
At the Company's option, borrowings under the Credit Agreement bear
interest at either (i) the "Base Rate" (i.e. the higher of the agent's prime
commercial lending rate, or the federal funds rate plus .50% per annum), or (ii)
the Eurodollar rate plus a margin ranging from 1.00% to 1.50% per annum, which
margin increases as the level of the Company's aggregate outstanding borrowings
under the Credit Agreement increases. The interest rates in effect at December
31, 1998 ranged from 7.063% to 7.750%.
The credit agreement contains various restrictive covenants and compliance
requirements, which include (1) limiting the incurrence of additional
indebtedness, (2) restrictions as to merger, sale or transfer of assets and
transactions with affiliates without the lenders' consent, and (3) prohibition
of any return of capital payments or distributions to any of its partners other
than for taxes due as a result of their partnership interest.
At December 31, 1998, the Company was not in compliance with a coverage
test required by the Credit Agreement. The Company has requested and received
written consents from its banks to amend this coverage test of the Credit
Agreement, and the Company believes this amendment will be fully documented on
or before April 30, 1999. The Company believes it will be able to comply with
the amended covenants of the Credit Agreement for the foreseeable future.
(Continued)
F-13
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
Unsecured Credit Agreement
In April 1997, the Company entered into a credit agreement, as amended,
(the "Unsecured Credit Agreement") with Chase Bank of Texas, N.A. (the "Bank"),
an affiliate of Chase Manhattan Bank, N.A., which establishes a revolving credit
facility, up to the maximum of $5 million. All outstanding amounts pursuant to
the Unsecured Credit Agreement are due and payable in full on or before December
31, 1999. The interest rate of each loan under the Unsecured Credit Agreement is
at a rate determined by agreement between the Company and the Bank. The rate
shall not exceed the maximum interest rate permitted under applicable laws.
Interest rates generally are at the bank's cost of funds plus 1% per annum.
Maturities of debt are as follows (in thousands):
<TABLE>
<CAPTION>
<S> <C>
1998 $ -
1999 -
2000 -
2001 144,200
2002 -
</TABLE>
(5) Acquisitions
On December 12, 1997, the Company completed the acquisitions of all the
outstanding stock of Offshore Energy Development Corporation ("OEDC") and
Carrollton Resources, L.L.C. ("Carrollton"). The acquisitions were made by the
issuance of 5,486,734 and 899,965 shares of the Company's common stock to the
stockholders of OEDC and Carrollton, respectively. The results of operations of
OEDC and Carrollton from the closing date are not included in the Company's 1997
results of operations as the acquisitions closed in late December 1997, and the
amounts are not material.
The acquisitions, accounted for on the purchase method, resulted in the
following noncash investing activities:
<TABLE>
<CAPTION>
OEDC Carrollton
---- ----------
(in thousands)
<S> <C> <C>
Recorded amount of assets acquired $ 104,312 $ 19,820
Liabilities assumed (27,102) (2,243)
Deferred income tax liability (13,815) (6,078)
Common stock issued (62,849) (11,330)
--------- ---------
Cash costs, net of cash acquired $ 546 $ 169
========= =========
</TABLE>
The liabilities assumed include amounts recorded for preacquisition
contingencies and bank debt of OEDC and Carrollton.
(Continued)
F-14
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
On December 16, 1997, the Company completed the acquisition of certain oil
and gas properties from Pioneer Natural Resources Company (the "Pioneer
Acquisition"). The Company funded the acquisition from its debt facilities.
The results of operations from the Pioneer Acquisition from the closing date are
not included in the Company's 1997 results of operations as the amounts are not
material. The acquisition of these oil and gas properties, accounted for using
the purchase method, resulted in the following noncash investing activities:
<TABLE>
<S> <C>
Recorded amount of assets acquired, including
receivables of $2,589,817 $ 55,794,243
Liabilities assumed (1,061,330)
------------
Cash paid $ 54,732,913
============
</TABLE>
Included in assets recorded is a $53,919 long-term receivable recorded as a
purchase price adjustment related to the Pioneer Acquisition for a gas imbalance
receivable.
On October 31, 1996, the Company completed the acquisition of certain oil and
gas properties from a major integrated company (the "1996 Acquisition"). The
Company funded the acquisition from its debt facilities. The acquisition of
these oil and gas properties, accounted for using the purchase method, resulted
in the following noncash investing activities:
<TABLE>
<S> <C>
Recorded amount of assets acquired, including
receivables of $300,187 $ 135,983,556
Liabilities assumed (1,570,490)
-------------
Cash paid $ 134,413,066
=============
</TABLE>
Included in receivables assumed is a $300,187 long-term receivable recorded
as a purchase price adjustment related to the 1996 Acquisition for a gas
imbalance. It is shown net of other gas imbalance liabilities in the
consolidated financial statements. Liabilities assumed are amounts recorded as
purchase price adjustments related to the 1996 Acquisition for potential
environmental remediation.
On December 11, 1995, the Company completed the acquisition of certain oil
and gas properties from a large independent oil and gas company (the "1995
Acquisition"). The Company funded the acquisition from its debt facilities.
The total consideration paid for the properties was $39,881,094. The
acquisition of these oil and gas properties, accounted for using the purchase
method, resulted in the following noncash investing activities:
<TABLE>
<S> <C>
Recorded amount of assets acquired, including receivables of $396,719 $ 40,992,065
Liabilities assumed (1,110,971)
------------
Cash paid $ 39,881,094
============
</TABLE>
Included in liabilities assumed is a $963,898 long-term liability recorded as
a purchase price adjustment related to the 1995 Acquisition for a gas imbalance
liability.
Pro Forma Results of Operations (Unaudited)
The following table reflects the pro forma results of operations for the
years ended December 31, 1997 and 1996 as though the 1996 Acquisition, the
Pioneer Acquisition and the OEDC and Carrollton acquisitions had
(Continued)
F-15
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
occurred as of January 1, 1996 and as if the Conversion had taken place on
January 1, 1996. The pro forma amounts are not necessarily indicative of the
results that may be reported in the future (in thousands).
<TABLE>
<CAPTION>
Year ended
December 31,
---------------------------------
1997 1996
---- ----
<S> <C> <C>
Revenues $ 105,016 $ 102,975
Net income (loss) (40,897) 17,125
Net income (loss) per common share (1.01) .43
Net income (loss) per common share - assuming dilution (1.01) .41
</TABLE>
(6) Investments
Dauphin Island Gathering Partners
The Company has a one percent investment in Dauphin Island Gathering
Partners ("DIGP"), which owns a natural gas gathering system in the Gulf of
Mexico, that is accounted for using the equity method. The Company's investment
in DIGP is the result of the acquisition of OEDC. The Company has been
delegated, by the operator of DIGP, to manage the commercial development and
construction activities of DIGP through November 1999, and the Company will be
paid $22,910 per month plus .5% of all construction costs of DIGP.
The Company's interest in DIGP will increase up to a maximum of 11.15% when
its DIGP partners receive the return of their investment plus a 10% rate of
return, subject to certain other conditions.
The Company's cost basis in DIGP exceeds the underlying historical net
assets of DIGP by approximately $18,333,000 at December 31, 1998. The excess
basis will be amortized over 30 years and included in the equity loss in net
loss from DIGP. The Company received distributions from DIGP of $275,433 in
1998.
Mobile Bay Processing Partners
The Company owns a .86% general partnership interest in Mobile Bay
Processing Partners ("MBPP") which was formed for the purpose of constructing,
owning and operating, or providing financing for one or more natural gas
processing facilities onshore in Mobile County, Alabama. The Company's
investment in MBPP is the result of the acquisition of OEDC. The Company
accounts for its investment in MBPP on the equity method. According to estimates
of the managing partner of MBPP the operations of the plant is expected to
commence in the first quarter of 1999. The Company has an option to buy up to an
additional 27.9% interest in MBPP, exercisable until the third anniversary of
the commencement of commercial operations at MBPP's initial processing facility.
The costs of the additional partnership interest will be equal to the historical
book value of the plant reduced for depreciation on the date the option is
exercised and increased by 12% per year.
The Company's cost basis in MBPP exceeds the underlying historical net
assets of MBPP by approximately $32,591,000 at December 31, 1998. The excess
basis will be amortized over 25 years, upon commencement of the first operations
of MBPP, and included in the equity loss in net loss from MBPP.
(Continued)
F-16
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
Other
The Company has a 13.33% limited partnership interest in Asia-Pacific
Refinery Investment, L.P. ("APRI"), which is carried at cost. APRI is involved
in the construction and operation of a refinery unit. The Company has no
responsibility to provide additional funds to APRI. In 1998, the Company
impaired its investment in APRI, see Note 18.
(7) Commitments and Contingencies
Operating Leases
The Company has non-cancelable operating leases for office facilities and
certain major production equipment. The Company's non-cancellable operating
lease for its Midland, Texas offices is with an entity controlled by an officer
of the Company. Future minimum lease commitments under non-cancellable
operating leases at December 31, 1998 are as follows (in thousands):
<TABLE>
<CAPTION>
Total Affiliate
------ ---------
<S> <C> <C>
1999 $ 933 $ 433
2000 433 433
2001 433 433
2002 90 90
2003 - -
</TABLE>
Lease expense during 1998, 1997 and 1996 was $962,986, $200,474 and $110,625,
respectively. In 1998, $412,056 of the lease expense was associated with
compressors and recorded as production costs. Lease expense incurred with an
affiliate during 1998, 1997 and 1996 was $419,704, $200,474 and $110,625,
respectively.
Litigation
The following is a brief description of certain litigation to which the
Company is subject, as a result of assuming the obligations of Offshore Energy
Development Corporation ("OEDC"). The Company believes it has meritorious
defenses to the claims and intends to vigorously defend against such claims.
The Company does not believe that it has a probable and estimable loss with
respect to any such litigation in excess of currently provided reserves, if any.
If such loss becomes probable and estimable, the amount of any recorded
liability could have a material adverse effect on the Company's (i) results of
operations for the period in which such liability is recorded, (ii) consolidated
financial position as a whole and (iii) liquidity and capital resources.
However, the Company does not expect that any such liability will have a
material adverse effect on its consolidated financial position as a whole or on
its liquidity or capital resources. Due to the uncertainties inherent in
litigation, no assurance can be given to the ultimate outcome of these matters.
OEDC and certain of its officers and directors, as well as Natural Gas
Partners, L.P. ("NGP"), the managing underwriters of OEDC's initial public
offering and an analyst from each of the managing underwriters, have been named
as defendants in a suit styled Eric Baron and Edward C. Allen, on behalf of
Themselves and all Others Similarly Situated, v. David B. Strassner, Douglas H.
Kiesewetter, David R. Albin, Natural Gas Partners, L.P., David Garcia, John J.
Myers, Offshore Energy Development Corporation, Morgan Keegan & Company, Inc.
and Principal Securities Inc., which was filed October 20, 1997, in the Texas
State District Court of Harris County,
(Continued)
F-17
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
Southern District of Texas. Plaintiffs motion to have the case remanded to the
state court was granted by the federal judge in April 1998. The suit seeks class
certification on behalf of certain holders of common stock of denied class
certification at this time, in deference to a parallel federal court action,
which is described below. The suit alleges generally that the defendants
wrongfully made false or misleading statements or omissions relating to OEDC's
business and prospects in the course of OEDC's initial public offering and
subsequent thereto. The state court suit seeks rescission of sales of common
stock of OEDC and unspecified monetary damages, including punitive damages.
OEDC and certain of its officers and directors, as well as NGP, have also
been named defendants in a suit styled John W. Robertson, et al. v. David B.
Strassner, Douglas H. Kiesewetter, David R. Albin, Natural Gas Partners, L.P.
and Offshore Energy Development Corporation, which was filed February 6, 1998,
in the United States Southern District of Texas, Houston Division. This suit
mirrors the allegations of the foregoing matter, but adds request for relief
under federal securities laws. It, too, seeks certification of a class of
certain purchasers of common stock OEDC. The suit seeks compensatory damages,
including rescissory damages, where applicable.
Discovery on the two previously discussed cases has commenced. A mediation
hearing, of all parties, has been set for April 20, 1999.
The Company is involved in other various claims and legal actions arising
in the ordinary course of business. In the opinion of management, the ultimate
disposition of these matters will not have a material adverse effect on the
Company's financial position, results of operations or liquidity.
Letters of Credit
At December 31, 1998, the Company had outstanding letters of credit of
$144,000, which are issued through the Credit Agreement.
(8) Statements of Cash Flows
Interest expense of $8,489,059, $1,524,576 and $3,062,656 was paid in 1998,
1997 and 1996, respectively.
In 1998, the Company acquired oil and gas properties by assuming the
underlying plugging obligations. The salvage value of the equipment and
platforms exceeded the estimated plugging obligations. The Company recorded no
basis in the oil and gas properties associated with this transaction.
In 1998, the Company executed a like-kind exchange of oil and gas
properties of which the Company's net basis in the property exchange was
approximately $6,042,000.
During 1996, a $1,300,000 noncash contribution of interests in oil and gas
properties was made in exchange for interest in the Company. Also at December
31, 1996, a $341,250 noncash property addition was recorded as a purchase price
adjustment related to the Conversion.
(Continued)
F-18
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(9) Restricted Investments
The Company carries a $3.0 million Gulf of Mexico area-wide abandonment
bond with the Minerals Management Service, which is secured by cash balances
currently invested in certificates of deposit at a commercial bank. The sum on
deposit related to this area-wide abandonment bond was approximately $2.3
million at December 31, 1997. The deposit was released to the Company in 1998.
(10) Common Stock
On December 16, 1996, the Company completed an initial public offering (the
"Offering") of 14,391,500 shares of common stock at a price of $11.00 per share.
Proceeds received, net of related expenses, were approximately $148,376,365.
In May 1997, the Company announced a plan to repurchase up to $25 million
of the Company's common stock. The repurchase will be made periodically,
depending on market conditions, and will be funded with cash flow from
operations and, as necessary, borrowings under the Credit Agreement. At December
31, 1998, the Company had purchased 2,600,000 shares of its common stock for
approximately $20 million.
(11) Income Taxes
Upon Conversion, the Company became a tax paying entity for U.S. federal
income tax purposes. At the date of Conversion, the book basis of the Company's
assets and liabilities exceeded the tax basis by approximately $8,566,000,
resulting in a deferred tax liability of approximately $2,998,000.
Total income tax expense was allocated as follows:
<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------------------
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Income (loss) from continuing operations $ (5,381) $ (18,267) $ 3,484
Stockholders' equity for compensation expense for tax
purposes in excess of amounts recognized for
financial reporting purposes (63) (6) -
-------- --------- -------
$ (5,444) $ (18,273) $ 3,484
======== ========= =======
</TABLE>
(Continued)
F-19
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
The reconciliation between the tax expense computed by multiplying pretax
income (loss) by the U.S. federal statutory rate and the reporting amounts of
income tax expense (benefit) is as follows:
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Income (loss) at statutory rate $ (18,409) $ (18,107) $ 728
Change in the deferred tax assets valuation allowance
14,001 - -
Operations of related partnerships taxable to the
respective partners, prior to the Conversion - - (242)
Deferred income tax expense to record difference
between book and tax basis of net assets upon
Conversion - - 2,998
State income taxes, net of federal benefit (373) (167) -
Other (600) 7 -
--------- --------- -------
Income tax expense (benefit) $ (5,381) $ (18,267) $ 3,484
========= ========= =======
</TABLE>
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities are as follows:
<TABLE>
<CAPTION>
December 31,
-------------------------------
1998 1997
---- ----
<S> <C> <C>
(in thousands)
Deferred tax assets (liabilities):
Net operating loss $ 30,353 $ 12,953
Compensation, principally due to accrual for financial reporting
purposes 3,883 2,405
Property, plant and equipment, principally due to differences in
basis upon acquisition, depletion, impairment, and the
deduction of intangible drilling costs for tax purposes
(4,249) (6,548)
Investments in affiliates (18,027) (19,178)
Other 2,041 -
-------- ---------
Net deferred tax asset (liability) 14,001 (10,368)
Valuation allowance of deferred tax assets (14,001) -
-------- ---------
Net deferred tax asset (liability), net of valuation
allowance $ - $(10,368)
======== =========
</TABLE>
A valuation allowance is provided when it is more likely than not that some
portion of the deferred tax assets will not be realized. Due to uncertainties
arising from a lack of earnings history and based on management's intention to
continue its drilling program (generating intangible drilling costs which are
projected to create future
(Continued)
F-20
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
losses for tax purposes), it does not appear more likely than not that the
Company will be able to utilize all the available carryforwards prior to their
ultimate expiration.
At December 31, 1998, the Company had net operating loss carryforwards
("NOLs") for U.S. federal income tax purposes of approximately $86,400,000,
which are available to offset future regular taxable income, if any. Of the
Company's NOLs, approximately $15,100,000 related to pre-acquisition NOLs which
are subject to annual limitations on their utilization. The carryforwards begin
to expire in 2011.
(12) Related Party Transactions
During 1998, 1997 and 1996, the Company received $7,536, $9,656 and
$144,167, respectively, for administrative services from a related party.
Financial advisory service fees of $185,854 were paid to two shareholders
during 1996. For the period March 31, 1995 (date of inception) through December
31, 1996, $428,958 were paid to two shareholders and two affiliates of
shareholders. The contracts underlying the financial advisory service fees were
terminated on December 16, 1996 pursuant to the contracts.
Director's fees of $45,000, $45,000 and $10,000 were incurred during 1998,
1997 and 1996, respectively.
Certain properties that were owned or controlled by certain shareholders
were acquired by the Company for $100,000 and $21,708 in 1997 and 1996,
respectively, which approximates the predecessor cost of the properties.
During 1998, 1997 and 1996, the Company received (paid) approximately
$2,232,000, $551,000 and ($635,000) from (to) Enron Capital and Trade Corp., an
affiliate of a significant stockholder of the Company relating to financial
instruments associated, primarily, with the Company's hedging activities.
The Company uses certain aircraft and receives services from an entity
owned by an affiliate. The Company is billed for use of such aircraft and
related services by the Company. Payments made for the use of such aircraft and
related services were $279, $3,371 and $17,348 for the years ended December 31,
1998, 1997 and 1996, respectively.
The President, Chief Executive Officer and Chairman of the Board of the
Company, and certain of his affiliates have a common ownership interest in oil
and gas properties that are operated by the Company and, in accordance with a
standard industry operating agreement, make payments to the Company of leasehold
costs and lease operating and supervision charges. These payments were
approximately $43,019, $88,473 and $229,332 in 1998, 1997 and 1996,
respectively. Revenue received in connection with these oil and gas properties
was $12,350, $16,098 and $6,868 in 1998, 1997 and 1996, respectively. These
interests were owned by the Chief Executive Officer and his affiliates prior to
the formation of the Company on March 31, 1995.
During 1998, the Company received fees of $275,000 for managing the
commercial and construction operations of DIGP.
(Continued)
F-21
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(13) Company Option Plans
Stock Option Plan
Prior to the consolidation of Titan Exploration, Inc., Titan Resources,
L.P. established a unit option plan (the "Plan") for certain officers and key
employees of the Partnership and the General Partner. On September 30, 1996,
upon the consolidation of Titan Exploration, Inc., the Plan was replaced by a
new stock option plan the ("Stock Plan"). The Stock Plan provides for the
issuance of 3,631,350 options to acquire common stock of the Company, in four
separate series with a fixed exercise price of $2.08. Option A series, covering
2,410,728 shares of common stock, was to vest at a rate of one-third of the
options at each of the dates of March 31, 1996, 1997 and 1998; Option B, C, and
D series cover 387,265, 406,390, and 426,967 shares of common stock,
respectively. Options B, C and D series each vest on March 31, 1997, 1998 and
1999, respectively. Deferred compensation was recorded based on the value of the
Company's common stock on September 30, 1996, and will be amortized to expense
over a 39 month period. Deferred compensation of approximately $17,576,000
(before reduction by amounts previously amortized to expense under the Plan, as
described above) was recorded at September 30, 1996. At December 31, 1998,
unamortized deferred compensation was $5,053,467.
1996 Incentive Plan
The Board of Directors and the stockholders of the Company approved the
adoption of the Company's 1996 Incentive Plan (the "1996 Incentive Plan") as of
October 1, 1996. The purpose of the 1996 Incentive Plan is to reward selected
officers and key employees of the Company and others who have been or may be in
a position to benefit the Company, compensate them for making significant
contributions to the success of the Company and provide them with a proprietary
interest in the growth and performance of the Company.
Participants in the 1996 Incentive Plan are selected by the Board of
Directors or such committee of the Board as is designated by the Board to
administer the 1996 Incentive Plan (the Compensation Committee of the Board of
Directors) from among those who hold positions of responsibility with the
Company and whose performance, in the judgment of the Compensation Committee,
can have a significant effect on the success of the Company. An aggregate of
850,000 shares of Common Stock have been authorized and reserved for issuance
pursuant to the 1996 Incentive Plan. These options vest ratably on each of the
first through fourth anniversaries of the grant date.
In November 1998, 105,000 stock options of an officer, with a weighted
average exercise price of $11.12 per share, were cancelled. The officer
received 200,000 new stock options at an exercise price of $6.25 per share. The
vesting of the new options is ratable over a four-year period from date of
grant.
Subject to the provisions of the 1996 Incentive Plan, the Compensation
Committee will be authorized to determine the type or types of awards made to
each participant and the terms, conditions and limitations applicable to each
award. In addition, the Compensation Committee will have the exclusive power to
interpret the 1996 Incentive Plan and to adopt such rules and regulations as it
may deem necessary or appropriate in keeping with the objectives of the 1996
Incentive Plan.
Pursuant to the 1996 Incentive Plan, participants will be eligible to
receive awards consisting of (i) stock options, (ii) stock appreciation rights,
(iii) stock, (iv) restricted stock, (v) cash or (vi) any combination of the
foregoing. Stock options may be either incentive stock options within the
meaning of Section 422 of the Internal Revenue Code of 1986, as amended, or
nonqualified stock options.
(Continued)
F-22
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
OEDC Stock Awards Plan
Pursuant to the OEDC merger agreement, the Company converted the outstanding
stock options of OEDC to stock options of the Company at the agreed common stock
exchange rate. At the date of the OEDC merger, there were 118,175 and 340,200
options to purchase shares of the Company common stock at $5.73 and $19.05 per
share, respectively, and all options were exercisable.
The Company applies APB 25 and related interpretations in accounting for its
stock option plans. If compensation expense for the stock option plans had been
determined in a manner consistent with Statement of Financial Accounting
Standards 123, "Accounting for Stock-Based Compensation ("FAS 123"), the
Company's net loss and net loss per share would have been adjusted to the pro
forma amounts indicated below:
<TABLE>
<CAPTION>
For the year ended
December 31,
----------------------------------------------------------
1998 1997 1996
---- ---- ----
(in thousands, except per share amounts)
<S> <C> <C> <C>
Net loss $ (46,314) $ (39,676) $ (2,959)
Net loss per common share (1.19) (1.17) (.15)
Net loss per share - assuming dilution (1.19) (1.17) (.15)
</TABLE>
The pro forma net loss and pro forma net loss per share amounts noted above
are not likely to be representative of the pro forma amounts to be reported in
future years. The pro forma amounts for 1996 reflect the initial phase-in of
FAS 123. Pro forma adjustments in future years will include compensation
expense associated with the options granted in 1998, 1997 and 1996 plus
compensation expense associated with any options awarded in future years. As a
result, such pro forma compensation expense is likely to be higher than the
levels experienced in 1998, 1997 and 1996.
Under FAS 123, the fair value of each stock option grant is estimated on the
date of grant using the Black-Scholes option pricing model with the following
weighted average assumptions used for grants in 1998, 1997 and 1996:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Risk-free interest rate 4.50% 5.25% 6.15%
Expected life 4.0 7.0 3.0
Expected volatility 48% 46% 52%
Expected dividend yield - - -
</TABLE>
(Continued)
F-23
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
A summary of the Company's stock option plans as of December 31, 1998, 1997
and 1996, and changes during the periods ended on those dates is presented
below:
<TABLE>
<CAPTION>
Year ended Year ended Year ended
December 31, 1998 December 31, 1997 December 31, 1996
----------------------- ---------------------- -----------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
------------ -------- ------------ -------- ------------- --------
<S> <C> <C> <C> <C> <C> <C>
Stock options:
Outstanding at beginning of year 4,429,440 $ 4.15 3,716,350 $ 2.28 3,387,674 $ 1.50
Options granted - initial plan - - - - 243,676 $ 1.50
Options canceled/forfeited (356,614) $ 15.51 - - (3,631,350) $ 1.50
OEDC options assumed - - 458,375 $ 15.61 - -
Options exercised (202,178) $ 2.71 (4,285) $ 2.08 - -
Options granted 389,499 $ 8.19 259,000 $ 10.95 3,716,350 $ 2.28
----------- ----------- ------------
Outstanding at end of year 4,260,147 $ 3.64 4,429,440 $ 4.15 3,716,350 $ 2.28
=========== =========== ============
Exercisable at end of year 3,339,117 $ 3.09 2,470,133 $ 4.72 803,576 $ 2.08
=========== =========== ============
Weighted average fair value of
options granted during the year $ 11.33 $ 10.95 $ 5.27
=========== =========== ============
</TABLE>
Options outstanding as of December 31, 1998 have expected lives ranging from
2 to 9 years with exercise prices ranging from $2.08 to $19.05 per share.
(Continued)
F-24
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(14) Net Loss per Common Share
The following table sets forth the computation of basic and diluted net
loss per common share:
<TABLE>
<CAPTION>
Year ended December 31,
------------------------------------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Numerator:
Net loss and numerator for basic and diluted
net loss per common share - income
available to common stockholders
$ (47,217) $ (33,467) $ (1,403)
========= ========= ========
Denominator:
Denominator for basic net loss per common
share - weighted average common shares 38,808 33,942 19,605
Effect of dilutive securities - employee
stock options - - -
--------- --------- --------
Denominator for diluted net loss per common
share - adjusted weighted average common
shares and assumed conversions 38,808 33,942 19,605
========= ========= ========
Basic net loss per common share $ (1.22) $ (.99) $ (.07)
========= ========= ========
Diluted net loss per common share $ (1.22) $ (.99) $ (.07)
========= ========= ========
</TABLE>
Employee stock options to purchase 4,260,147, 4,429,440 and 3,716,350
shares of common stock were outstanding during 1998, 1997 and 1996,
respectively, but were not included in the computation of diluted net loss per
common share because either (i) the employee stock options' exercise price was
greater than the average market price of the common stock of the Company or (ii)
the Company had a loss from continuing operations; and, therefore, the effect
would be antidilutive.
(Continued)
F-25
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(15) 401(k) Plan
The Company has established a qualified cash or deferred arrangement under
IRS code section 401(k) covering substantially all employees. Under the plan,
the employees have an option to make elective contributions of a portion of
their eligible compensation, not to exceed specified annual limitations, to the
plan and the Company has an option to match a portion of the employee's
contribution. The Company has made matching contributions to the plan totaling
$632,883, $110,981 and $23,034 in 1998, 1997 and 1996, respectively.
(16) Major Customers
The following purchasers accounted for 10% or more of the Company's oil
and gas sales:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Purchaser A (a) 31% 36% 43%
Purchaser B 13% 12% 7%
Purchaser C 13% 9% -%
</TABLE>
- --------------------------------
(a) Purchaser A is an affiliate of Enron Corp., a significant stockholder of
the Company.
(17) Derivative Financial Instruments
The Company utilizes various swap contracts and other financial
instruments to hedge the effect of price changes on future gas production. The
following table sets forth the future volumes hedged by year and the range of
prices to be received based upon the fixed price of the individual swap
contracts and other financial instruments outstanding at December 31, 1998:
<TABLE>
<CAPTION>
Gas
Volume Price per
Year (MMcf) Mcf
---- ------ ---
<S> <C> <C>
Gas commodity price collars:
1999:
Onshore 10,839 $1.81 to $1.98
Offshore 295 $2.05
2000 - Onshore 1,365 $1.98
</TABLE>
(18) Impairment of Long-Lived Assets
Assets Held for Use
The Company, in accordance with FAS 121, estimated expected future cash
flows of its oil and gas properties by amortization unit and compared the
amounts determined to the carrying amount of its oil and gas properties to
determine if the carrying amount was recoverable. For those oil and gas
properties for which the carrying amount exceeded the estimated future cash
flows, an impairment was determined to exist; therefore, the Company adjusted
the carrying amount of those oil and gas properties to their estimated fair
value as determined by discounting their expected future cash flows at a
discount rate commensurate with the risks involved in the industry. As a result
of
(Continued)
F-26
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
this process, the Company recognized an impairment of approximately $22.2 and
$69.0 million related to its oil and gas properties during 1998 and 1997,
respectively. No impairment was determined to exist in 1996.
In 1998, the Company recognized an impairment of approximately $2.2 million
on its investment in APRI. This impairment was due to a significant decrease in
the fair value of publicly traded securities held by APRI.
Assets Held for Sale
In the fourth quarter of 1998, the Company approved a plan to dispose of its
Gulf of Mexico, Gulf Coast and non-strategic Permian Basin assets. The
Company's reason to dispose of these assets varied depending on the portfolio of
assets being considered. The disposition would allow the Company to (a) realize
full value for certain assets whose value is not fully reflected in the public
valuation of the Company in the capital markets, (b) redeploy capital to higher
return projects or acquisitions, (c) invest in projects that will accelerate
cash flow to the Company, (d) eliminate certain administrative costs and (e)
reduce the Company's debt obligations.
The Company's basis in these assets (net of any impairment) at December 31,
1998 was approximately $110 million. The Company expects to complete the
disposition of all these assets by the third quarter of 1999.
In 1998, the Company recognized an impairment of approximately $1.3 million
on the assets held for sale. The impairment was the result of comparing the
estimated sales proceeds, less costs to sell, to the underlying net cost basis
of each specific portfolio of assets.
The following are the results of operations of the assets held for sale:
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Oil and gas sales $ 12,428 $ 2,666 $ 2,316
Oil and gas production costs (6,626) (974) (893)
Production and other taxes (469) (225) (180)
Equity loss in net loss of affiliates (458) - -
-------- ------- -------
$ 4,875 $ 1,467 $ 1,243
======== ======= =======
</TABLE>
(Continued)
F-27
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(19) Other Liabilities
The other current and noncurrent liabilities consist of the following (in
thousands):
<TABLE>
<CAPTION>
December 31,
----------------------------------
1998 1997
---- ----
<S> <C> <C>
Other current liabilities:
Capital costs and operating expenses $ 2,220 $ 3,472
Gas processing obligation 564 -
Restructuring costs 625 -
Oil and gas payable 1,106 563
Environmental reserve 248
Other 1,137 613
------- -------
$ 5,652 $ 4,896
======= =======
Other noncurrent liabilities:
Gas processing obligation $ 1,130 $ -
Environmental reserve 824 1,223
Plugging and abandonment reserve 2,483 497
Gas and pipeline imbalances 225 -
Other 591 1,000
------- -------
$ 5,253 $ 2,720
======= =======
</TABLE>
(20) Exploration and Abandonments
Exploration and abandonments expense consist of the following (in
thousands):
<TABLE>
<CAPTION>
1998 1997 1996
------- ---- ----
<S> <C> <C> <C>
Geological and geophysical staff $ 1,283 $ - $ -
Uneconomical exploratory wells 2,593 723 -
Impaired unproved properties 9,870 331 -
Seismic costs 1,130 1,436 148
Delay rentals 1,685 205 14
Plugging and abandonment reserve 525 - -
Other 510 360 22
-------- ------- ------
$ 17,596 $ 3,055 $ 184
======= ======= ======
</TABLE>
(Continued)
F-28
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(21) Unaudited Supplementary Information
Capitalized Costs
<TABLE>
<CAPTION>
December 31,
---------------------------------
1998 1997
---- ----
(in thousands)
<S> <C> <C>
Oil and gas properties:
Proved oil and gas properties $ 299,412 $ 341,072
Unproved properties 6,699 25,033
--------- ---------
306,111 366,105
Accumulated depletion (96,934) (94,185)
--------- ---------
Net capitalized costs for oil and gas properties $ 209,177 $ 271,920
========= =========
Costs Incurred
<CAPTION>
Year ended December 31,
------------------------------------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Property acquisition costs:
Proved $ 404 $ 100,871 $ 139,110
Unproved 4,994 24,532 802
Exploration 21,316 2,856 129
Development 30,663 44,896 12,468
-------- --------- ---------
$ 57,377 $ 173,155 $ 152,509
======== ========= =========
</TABLE>
Reserve Quantity Information
The estimates of proved oil and gas reserves, which are located principally
in the United States and offshore Gulf of Mexico, were prepared and/or audited
(audits are of significant value properties) by independent petroleum
consultants as of December 31, 1998, 1997 and 1996. Reserves were estimated in
accordance with guidelines established by the SEC and FASB which require that
reserve estimates be prepared under existing economic and operating conditions
with no provision for price and cost escalations except by contractual
arrangements. The Company has presented the reserve estimates utilizing an oil
price of $9.49, $16.11 and $25.09 per Bbl and a gas price of $1.57, $1.83 and
$2.70 per Mcf as of December 31, 1998, 1997 and 1996, respectively.
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either an
upward or downward revision of previous estimates. Further, the volumes
considered to be commercially recoverable fluctuate with changes in prices and
operating costs. The Company emphasizes that reserve estimates are inherently
imprecise and that estimates of new discoveries are more imprecise than those of
currently producing
(Continued)
F-29
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
oil and gas properties. Accordingly, these estimates are expected to change as
additional information becomes available in the future.
Oil And Gas Producing Activities
<TABLE>
<CAPTION>
Oil and Natural
Condensate (MBbl) Gas (MMcf)
----------------- ----------
<S> <C> <C>
Total Proved Reserves:
Balance, December 31, 1995 6,146 134,995
Purchases of minerals-in-place 704 264
Revision of previous estimates 101 47,031
Production (388) (2,725)
------ -------
Balance, September 30, 1996 6,563 179,565
Purchases of minerals-in-place 12,510 109,381
Revision of previous estimates 709 15,494
Production (326) (3,062)
------ -------
Balance, December 31, 1996 19,456 301,378
Purchases of minerals-in-place 7,128 43,501
Extensions and discoveries 20 40,633
Revision of previous estimates 5,551 (18,036)
Production (1,880) (22,104)
------ -------
Balance, December 31, 1997 30,275 345,372
Purchase of minerals-in-place 1,540 11,175
Sales of minerals-in-place (77) -
Extensions and discoveries 2,127 12,742
Revision of previous estimates - price (7,877) (16,029)
Revision of previous estimates - other (485) 5,441
Production (2,492) (26,731)
------ -------
Balance, December 31, 1998 (a) 23,011 331,970
====== =======
Proved Developed Reserves:
December 31, 1995 5,945 45,470
September 30, 1996 6,252 54,119
December 31, 1996 16,024 180,161
December 31, 1997 23,604 219,307
December 31, 1998 13,233 202,203
</TABLE>
_____________
(a) At December 31, 1998, total proved reserves included 2,735 MBbl and
42,945 MMcf of oil and natural gas, respectively, which are associated
with oil and gas properties classified as assets held for sale in the
consolidated balance sheets.
(Continued)
F-30
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
Standardized Measure Of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves, less estimated future expenditures
(based on period-end costs) to be incurred in developing and producing the
proved reserves, less estimated future income tax expenses (based on period-end
statutory tax rates, with consideration of future tax rates already legislated)
to be incurred on pretax net cash flows less tax basis of the properties and
available credits, and assuming continuation of existing economic conditions.
The estimated future net cash flows are then discounted using a rate of 10% per
year to reflect the estimated timing of the future cash flows.
Discounted future cash flow estimates like those shown below are not intended
to represent estimates of the fair value of oil and gas properties. Estimates
of fair value should also consider probable reserves, anticipated future oil and
gas prices, interest rates, changes in development and production costs and
risks associated with future production. Because of these and other
considerations, any estimate of fair value is necessarily subjective and
imprecise.
<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Future:
Cash inflows $ 738,683 $ 1,121,526 $ 1,300,863
Production costs (241,570) (345,598) (324,551)
Development costs (59,976) (46,877) (24,154)
Future income taxes (34,387) (153,100) (264,904)
---------- ----------- -----------
Future net cash flows 402,750 575,951 687,254
10% annual discount for estimated timing of
cash flows (166,122) (226,901) (299,391)
---------- ----------- -----------
Standardized measure of discounted net cash
flows $ 236,628 (a) $ 349,050 $ 387,863
========== =========== ===========
</TABLE>
_____________
(a) At December 31, 1998, the standardized measure of discounted net cash
flows included approximately $39.2 million which are associated with oil
and gas properties classified as assets held for sale in the consolidated
balance sheets.
(Continued)
F-31
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------------------------
1998 1997 1996
---- ---- ----
(in thousands)
<S> <C> <C> <C>
Standardized measure, beginning of period $ 349,050 $ 387,863 $ 66,352
Extensions and discoveries and improved recovery,
net of future production and development costs 15,155 36,439 -
Accretion of discount 34,905 38,786 6,635
Net change in sales prices, net of production,
costs (106,032) (180,281) 83,823
Net change in income taxes 80,444 40,115 (126,102)
Purchase of minerals-in-place 11,338 72,241 298,867
Sales of minerals-in-place (235) - -
Revision of quantity estimates and revenues added
by development drilling (33,892) 11,615 70,755
Sales, net of production costs (40,073) (51,846) (14,625)
Changes in estimated future development costs (23,040) (7,904)
Changes in production rates and other (50,992) 2,022 2,158
---------- ---------- ----------
Standardized measure, end of period $ 236,628 $ 349,050 $ 387,863
========== ========== ==========
</TABLE>
(Continued)
F-32
<PAGE>
TITAN EXPLORATION, INC.
Notes to Consolidated Financial Statements
(22) Selected Quarterly Financial Results (Unaudited)
<TABLE>
<CAPTION>
Quarter
--------------------------------------------------------------
First Second Third Fourth
----- ------ ----- ------
(in thousands, except per share data)
<S> <C> <C> <C> <C>
1998:
Total revenues $ 22,107 $ 18,361 $ 16,671 $ 15,737
Total expenses (a) 23,432 26,260 23,103 47,298
Net loss (1,325) (7,899) (6,432) (31,561)
Net loss per common share (.03) (.20) (.17) (.83)
Net loss per common share - assuming
dilution (.03) (.20) (.17) (.83)
1997:
Total revenues $ 18,032 $ 16,166 $ 17,932 $ 21,697
Total expenses (b) 15,755 14,441 15,372 61,726
Net income (loss) 2,277 1,725 2,560 (40,029)
Net income (loss) per common share .07 .05 .08 (1.18)
Net income (loss) per common share -
assuming dilution .06 .05 .07 (1.18)
</TABLE>
______________________
(a) Total expenses in the second, third and fourth quarter of 1998 includes
impairment of long-lived assets of approximately $8.0 million, $5.1 million
and $12.6 million, respectively.
(b) The total expenses in the fourth quarter of 1997 include an impairment of
long-lived assets of approximately $69.0 million.
F-33
<PAGE>
EXHIBIT 21
----------
Titan Exploration, Inc.
Subsidiaries
<TABLE>
<CAPTION>
Name State of Organization Ownership
---- --------------------- ---------
<S> <C> <C>
Titan Resources Holdings, Inc. Nevada corporation 100%
Titan Resources, L.P. Texas limited partnership 100%
Titan Resources I, Inc. Delaware corporation 100%
Titan Offshore, Inc. Delaware corporation 100%
OEDC, Inc. Delaware corporation 100%
OEDC Processing, L.P. Texas limited partnership 100%
Dauphin Island Gathering Company, L.P. Texas limited partnership 100%
Beacon Natural Gas Company, L.P. Texas limited partnership 100%
OEDC Exploration & Production, L.P. Texas limited partnership 100%
Carrollton Resources, L.L.C. Louisiana limited liability company 100%
Carrollton Resources Corporation Louisiana corporation 100%
Dauphin Island Gathering Partners Texas general partnership 1%
South Dauphin Partners II Limited Texas limited partnership 15%
Mobile Bay Processing Partners Delaware general partnership .86%
Asia Pacific Refinery Investment, L. P. Delaware limited partnership 13 1/3%
</TABLE>
<PAGE>
EXHIBIT 23
The Board of Directors
Titan Exploration, Inc.
We consent to incorporation by reference in the registration statements (No's.
333-62115, 333-30063, and 333-30061) on Form S-8 and No. 333-62,113 on Form S-3
of Titan Exploration, Inc. of our report dated March 5, 1999, relating to the
consolidated balance sheets of Titan Exploration, Inc. and subsidiaries as of
December 31, 1998 and 1997, and the related consolidated statements of earnings,
retained earnings, and cash flows for each of the years in the three-year period
ended December 31, 1998, which report appears in the December 31, 1998, annual
report on Form 10-K of Titan Exploration, Inc.
KPMG LLP
Midland, Texas
March 30, 1999
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENT OF THE COMPANY
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-01-1998
<CASH> 610
<SECURITIES> 0
<RECEIVABLES> 14,258
<ALLOWANCES> 0
<INVENTORY> 1,276
<CURRENT-ASSETS> 125,912
<PP&E> 312,451
<DEPRECIATION> 98,095
<TOTAL-ASSETS> 341,022
<CURRENT-LIABILITIES> 20,215
<BONDS> 0
0
0
<COMMON> 405
<OTHER-SE> 170,949
<TOTAL-LIABILITY-AND-EQUITY> 341,022
<SALES> 72,876
<TOTAL-REVENUES> 72,876
<CGS> 0
<TOTAL-COSTS> 117,998
<OTHER-EXPENSES> (1,172)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,648
<INCOME-PRETAX> (52,598)
<INCOME-TAX> (5,381)
<INCOME-CONTINUING> (47,217)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (47,217)
<EPS-PRIMARY> (1.22)
<EPS-DILUTED> (1.22)
</TABLE>
