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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, 1999

[ ] 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 200 79701
Midland, Texas (Zip Code)
(Address of principal executive offices)

(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
Participating Preferred Stock Purchase Right
(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 _____
-

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 9, 2000, the Registrant had outstanding 40,189,843 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 9, 2000, as reported on the Nasdaq National Market, was
approximately $153,962,000.

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TABLE OF CONTENTS
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Page
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PART I

Item 1. Business.................................................................................. 2

Item 2. Properties................................................................................ 9

Item 3. Legal Proceedings......................................................................... 12

Item 4. Submission of Matters to a Vote of Security Holders....................................... 13

PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.................... 14

Item 6. Selected Financial Data.................................................................. 15

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.... 17

Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................... 32

Item 8. Financial Statements and Supplementary Data.............................................. 34

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..... 35

PART III

Item 10. Directors and Executive Officers of the Registrant....................................... 36

Item 11. Executive Compensation................................................................... 38

Item 12. Security Ownership of Certain Beneficial Owners and Management........................... 42

Item 13. Certain Relationships and Related Party Transaction...................................... 44

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.......................... 45

Glossary of Oil and Gas Terms............................................................ 49

Signatures............................................................................... 52

Index to Consolidated Financial Statements........................................................... F-1

-1-

TITAN EXPLORATION, INC.

1999 ANNUAL REPORT ON FORM 10-K

PART I

ITEM 1. BUSINESS

Titan Exploration, Inc. (the "Company" or "Titan") 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, Brenham Dome area of south central Texas and the
Central Gulf Coast region of Texas. 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 200, Midland, Texas 79701, and its
telephone number is (915) 498-8600.

Recent Developments

On December 13, 1999, the Company announced its agreement to merge the Company
and the Permian Basin business unit of Unocal Corporation ("Unocal") into a new
company named Pure Resources, Inc. ("Pure Resources"). Pure Resources will be a
publicly traded company. The Permian Basin business unit of Unocal includes oil
and gas exploration and production assets in the Permian Basin of West Texas and
the San Juan Basin in New Mexico and Colorado.

Pure Resources will have approximately 50 million shares of common stock
outstanding upon completion of the merger. Unocal will hold approximately 65%
(32.7 million shares) of Pure Resources. The Unocal merger will cause a change
of control of the Company. Upon approval by the Company stockholders of the
merger, the Company stockholders will receive 0.4302314 shares of Pure
Resources common stock for every share held of the Company's common stock and
will collectively own approximately 35% of the outstanding common stock of Pure
Resources. The Company expects that upon receiving its shareholder approval the
merger would close in April 2000.

For more information about the proposed merger, see definitive proxy materials
relating to the merger, which the Company expects to file with the SEC in late
March 1999.

Management of Pure Resources will include all former officers of the Company
plus the addition of (1) Jack Rathbone as Executive Vice President - Operations
and (2) Gary Dupriest as Vice President - Production. Jack Rathbone was
previously the President of Mobil Producing Texas and New Mexico and has
recently become an officer of the Company. Gary Dupriest is currently the Vice
President of the Permian Basin business unit for Unocal and will join Pure
Resources upon consummation of the merger.

The board of directors of Pure Resources will be Jack D. Hightower, George G.
Staley and Herbert C. Williamson, III, all current directors of the Company,
plus Timothy H. Ling, Darrell Chessum, Graydon H. Laughbaum, Jr. and H.D.
Maxwell, all designees of Unocal.

In November 1999, the Company acquired, for approximately $10 million, proved
properties, prospect acreage and approximately 500 square miles of proprietary
3-D geophysical data in the Central Gulf Coast region of Jackson, Victoria,
Wharton and Colorado counties in Texas. The properties were acquired to allow
the Company exposure to the Expanded Yegua, Frio and Deep Wilcox Trend plays.
Through December 31, 1999 the Company participated in the drilling of four
exploratory wells on its acreage, of which three were successful.

-2-

Overview

The Company's strategy is to grow reserves, production and net income per
share by:

. identifying acquisition opportunities that provide significant
development and exploratory drilling potential,

. exploiting and developing its reserve base,

. pursuing exploration opportunities for oil and gas reserves,

. capitalizing on advanced technology to identify, explore and exploit
projects, and

. emphasizing a low overhead and operating cost structure.

As of December 31, 1999, the Company estimated net proved reserves of
approximately 31.8 MMBbls of oil and 244.7 Bcf of natural gas, or an aggregate
of 435.7 Bcfe with a PV-10 of $412.7 million. Approximately 65% 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 $.74 per Mcfe from inception of the Company through December 31,
1999.

The Company prefers to acquire properties over which it can exercise operating
control. As of December 31, 1999, the Company operated 819 gross productive
wells (718 net productive wells) and these operated properties represented
approximately 71% of its proved developed PV-10 and 76% of the Company's PV-10
attributable to total 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 70
fields/areas in the Permian Basin, Brenham Dome area and Central Gulf Coast
region. Approximately 74% of the Company's PV-10 of total proved reserves is
concentrated in 13 principal fields/areas 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.

Acquisitions

The Company's strategy is to make acquisitions with exploitation potential.
The following paragraphs outline the Company's acquisition practices and its
significant acquisitions since the inception of the Company. The Company
believes the merger with the Permian Basin business unit of Unocal is in keeping
with its growth and acquisition strategy.

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 focused on the acquisition, exploration, development and
production of natural gas and on natural gas gathering, processing and marketing
activities (the "OEDC Acquisition"). OEDC's integrated operations were
conducted in the Gulf of Mexico, where OEDC had an interest in 24 lease blocks,
all of which were 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

-3-

energy company that was engaged in the exploration, development and acquisition
of onshore oil and gas properties that were 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
economies, 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 1999, sales to Enron Corp., and its subsidiaries and affiliates and
Dynegy Inc. were approximately 36% and 16% 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.

-4-

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, 1999, the Company had 76 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, ten 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 on an arms-length basis with an affiliate of Jack Hightower. The Company's
principal offices are leased through March 15, 2002.

-5-

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, 1999). Presently, the
Company keeps in force its leaseholds for 18% 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.

-6-

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.

In addition, the Outer Continental Shelf Lands Act ("OCSLA") authorizes
regulations relating to safety and environmental protection applicable to
lessees and permittees operating in the Outer Continental Shelf ("OCS").

-7-

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 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 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.

-8-

ITEM 2. PROPERTIES

Oil and Natural Gas Reserves

The Company's oil and gas properties are located in the Permian of West Texas
and southeastern New Mexico, the Brenham Dome area of south central Texas and
the Central Gulf Coast region of Texas.

The following table summarizes the estimates of the Company's historical net
proved reserves as of December 31, 1999 and 1998, 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 and the Company's independent
petroleum consultants.

December 31,
--------------------------------
1999 1998
--------------- ---------------
(dollars in thousands)

Estimated proved reserves:

Oil and condensate (MBbls)....................................... 31,830 23,011
Natural gas (MMcf)............................................... 244,705 331,970
MMcfe (6 Mcf per Bbl)............................................ 435,685 470,036

Proved developed reserves as a percentage of proved reserves...... 65% 60%
PV-10 (a)......................................................... $412,694 242,170
Standardized Measure of Discounted Future Net Cash Flows (b)...... $333,363 $236,628

____________
(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, 1999 were $24.48 per Bbl of oil and condensate and $1.73 per Mcf of
natural gas, compared to average realized prices for the Company's reserves as
of December 31, 1998 of $9.49 per Bbl of oil and $1.57 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.

-9-

Estimates based on these methods are generally less reliable than those based on
actual production history. 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, 1999:

Actual
----------------------

Gross Net
---------- ----------

Oil...................................................... 2,001 692
Gas...................................................... 673 260
----- ---
Total Productive Wells................................... 2,674 952
===== ===

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, 1999.

Developed Acres Undeveloped Acres Total Acres
----------------------- ----------------------- ------------------------
Gross Net Gross Net Gross Net
---------- ----------- ---------- ----------- ----------- -----------

Total....... 205,620 75,873 727,024 423,995 932,644 499,868

Drilling Activities

The following table sets forth the drilling activity of the Company on its
properties for the periods presented.

Year Ended December 31,
----------------------------------------------------------------
1999 1998 1997
-------------------- -------------------- --------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------

Exploratory Wells:
Productive.................. 10.0 3.9 8.0 3.6 2.0 1.0

Nonproductive.................. 9.0 4.5 3.0 2.5 2.0 1.8
---- ---- ---- ---- ---- ----
Total....................... 19.0 8.4 11.0 6.1 4.0 2.8
==== ==== ==== ==== ==== ====
Development Wells:
Productive..................... 16.0 12.0 22.0 18.8 48.0 17.2

Nonproductive.................. - - 4.0 3.7 6.0 4.5
---- ---- ---- ---- ---- ----
Total........................ 16.0 12.0 26.0 22.5 54.0 21.7
==== ==== ==== ==== ==== ====

At December 31, 1999, the Company had 5.0 gross wells (2.7 net wells) being
drilled and not included in the above table.

-10-

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 the periods presented.

Year Ended December 31,
------------------------------------------------------
1999 1998 1997
----------------- ----------------- ----------------

Production:
Oil and condensate (MBbls).................................. 2,272 2,492 1,880
Natural gas (MMcf).......................................... 23,190 26,731 22,104
Total (MMcfe)............................................... 36,822 41,683 33,385
Average sales price (a):
Oil and condensate (per Bbl)................................ $ 16.22 $ 12.05 $ 18.67
Natural gas (per Mcf)....................................... $ 1.68 $ 1.60 $ 1.75
Total (per Mcfe)............................................ $ 2.06 $ 1.75 $ 2.21

Production costs, excluding production and other taxes
(per Mcfe).................................................. $ .51 $ .65 $ .48
Production and other taxes (per Mcfe)......................... $ .17 $ .14 $ .17
General and administrative costs (per Mcfe)................... $ .21 $ .22 $ .16
Depletion, depreciation and amortization expenses (per
Mcfe)....................................................... $ .52 $ .65 $ .60

_____________
(a) Reflects results of hedging activities in 1999, 1998 and 1997.

-11-

ITEM 3. LEGAL PROCEEDINGS

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, were 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, Texas, 270/th/ Judicial District and
subsequently removed to federal court in the United States Southern District of
Texas.

OEDC and certain of its officers and directors, as well as NGP, were also
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.

These matters were settled in the fourth quarter of 1999 at an expense to
the Company of approximately $200,000.

The Company is involved in 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.

-12-

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a) Inapplicable.

(b) Inapplicable.

(d) Inapplicable.

-13-

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 presented below.

Common Stock
-----------------------

High Low
---------- -----------

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:
$ 4.375
First Quarter.................................... $ 7.188

Second Quarter................................... 5.938 4.313

Third Quarter.................................... 6.094 4.625

Fourth Quarter................................... 5.438 3.000

2000:

First Quarter (through February 4, 2000)......... $ 5.250 $ 3.500

As of February 4, 2000, the Company estimates that there were more than 143
record holders and more than 3,000 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.

-14-

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."

Period March 31, 1995
(date of inception)
Year Ended December 31, through
--------------------------------------------------------- December 31,
1999(a) 1998(b) 1997(b) 1996 (b) 1995(b)
------------- -------------- -------------- ---------- ---------------------
(in thousands, except per share amounts and operating data)

Consolidated Statement of Operations Data:
Revenues-
Operating revenues........................... $ 75,717 $ 72,876 $ 73,827 $ 23,824 $ 743
Expenses:
Oil and gas production....................... 18,643 27,078 16,298 7,312 265
Production and other taxes................... 6,116 5,725 5,548 1,887 39
General and administrative................... 7,771 9,163 5,372 2,270 1,546
Amortization of stock option awards.......... 5,049 5,055 5,053 1,839 576
Exploration and abandonment.................. 11,049 17,596 3,055 184 490
Depletion, depreciation and amortization..... 19,222 27,090 19,972 5,789 299
Impairment of long-lived assets.............. 31,783 25,666 68,997 -- --
Restructuring costs.......................... -- 625 -- -- --
Interest..................................... 7,320 8,648 1,524 2,965 97
Other........................................ (2,893) (1,172) (258) (503) (1,038)
-------- -------- --------- --------- --------
Total expenses.......................... 104,060 125,474 125,561 21,743 2,274
-------- -------- --------- --------- --------
Income (loss) before income taxes............ (28,343) (52,598) (51,734) 2,081 (1,531)
Income tax (expense) benefit................. 20,069 5,381 18,267 (3,484) --
-------- -------- --------- --------- --------
Net loss..................................... $ (8,274) $(47,217) $ (33,467) $ (1,403) $ (1,531)
======== ======== ========= ========= ========

Net loss per common share.................... $ (.22) $ (1.22) $ (.99) $ (.07) $ (.11)
Net loss per common share -
assuming dilution............................ $ (.22) $ (1.22) $ (.99) $ (.07) $ (.11)
Weighted average common shares
outstanding............................... 38,038 38,808 33,942 19,605 14,066
Consolidated Statement of Cash Flows Data:
Net cash provided by (used in):
Operating activities......................... $ 33,426 $ 18,448 $ 46,563 $ 7,710 $ (1,805)
Investing activities......................... 20,204 (58,413) (114,302) (144,998) (47,522)
Financing activities......................... (52,930) 38,972 63,052 137,365 55,540
Other Consolidated Financial Data:
Capital expenditures............................ $ 45,212 $ 63,235 $ 114,377 $ 150,119 $ 43,770
Consolidated Operating Data:
Production:
Oil and condensate (MBbls)...................... 2,272 2,492 1,880 714 30
Natural gas (MMcf).............................. 23,190 26,731 22,104 5,787 245
Total (MMcfe)................................... 36,822 41,683 33,385 10,071 425
Average Sales Prices Per Unit(c):
Oil and condensate (per Bbl).................... $ 16.22 $ 12.05 $ 18.67 $ 19.16 $ 16.80
Natural gas (per Mcf)........................... 1.68 1.60 1.75 1.75 .97
Total (per Mcfe)................................ 2.06 1.75 2.21 2.37 1.75
Expenses per Mcfe
Production costs, excluding production and
other taxes.................................. $ .51 $ .65 $ .48 $ .72 $ .63
Production and other taxes...................... .17 .14 .17 .19 .09
General and administrative...................... .21 .22 .16 .23 3.64
Depletion, depreciation and amortization........ .52 .65 .60 .57 .70

-15-

December 31,
--------------------------------------------------------------
1999(a) 1998(b) 1997(b) 1996(b) 1995(b)
----------- ----------- ----------- ----------- ----------
(in thousands)

Consolidated Balance Sheet Data:
Cash and cash equivalents..................... $ 1,310 $ 610 $ 1,603 $ 6,290 $ 6,213
Working capital (deficit) (d)................. (3,912) 105,697 28 8,124 11,946
Oil and gas assets, net....................... 230,101 209,177 271,920 190,062 42,861
Total assets.................................. 268,798 341,022 352,583 207,179 57,487
Total debt.................................... 90,000 144,200 85,450 6,500 20,000
Stockholders' equity and predecessor
capital...................................... 160,851 171,354 232,421 187,186 34,585

____________
(a) In May 1999, the Company sold its assets in the Gulf of Mexico for $71.3
million in cash.

(b) Certain reclassifications have been made to the 1998, 1997, 1996 and 1995
amounts to conform to the 1999 presentation.

(c) Reflects results of hedging activities. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations."

(d) The 1998 amount includes $109.5 million of assets held for sale.

-16-

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

Unocal Merger

On December 13, 1999, the Company announced its agreement to merge the
Company and the Permian Basin business unit of Unocal Corporation ("Unocal")
into a new company named Pure Resources, Inc. ("Pure Resources"). Pure Resources
will be a publicly traded company. The Permian Basin business unit of Unocal
includes oil and gas exploration and production assets in the Permian Basin of
West Texas and the San Juan Basin in New Mexico and Colorado.

For more information about the proposed merger, see definitive proxy
materials relating to the merger, which the Company expects to file with the SEC
in late March 1999.

Management of Pure Resources will include all former officers of the
Company plus the addition of (1) Jack Rathbone as Executive Vice President -
Operations and (2) Gary Dupriest as Vice President - Production. Jack Rathbone
was previously the President of Mobil Producing Texas and New Mexico and has
recently become an officer of the Company. Gary Dupriest is currently the Vice
President of the Permian Basin business unit for Unocal and will join Pure
Resources upon consummation of the merger.

The board of directors of Pure Resources will be Jack D. Hightower, George
G. Staley and Herbert C. Williamson, III, all current directors of the Company,
plus Timothy H. Ling, Darrell Chessum, Graydon H. Laughbaum, Jr. and H.D.
Maxwell, all designees of Unocal.

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 by:

. identifying acquisition opportunities that provide significant
development and exploratory drilling potential,

. exploiting and developing its reserve base,

. pursuing exploration opportunities for oil and gas reserves,

. capitalizing on advanced technology to identify, explore and exploit
projects, and

. emphasizing 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

-17-

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 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.

Impact of Commodity Oil Prices

During 1998 and through the first quarter of 1999, 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 were 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 crude oil
production quotas and a decline in demand in Asian markets. The prices for crude
oil during the second through fourth quarters of 1999 have shown significant
improvement over those of the previous fifteen months.

A return of low prices for crude oil, natural gas or other commodities sold
by the Company could have a material adverse effect on the Company's results of
operations, on the quantities of crude oil and natural gas that can be
economically produced from its fields, and on the quantities and economic values
of its proved reserves and potential resources. Such adverse pricing scenarios
could result in write-downs of the carrying values of the Company's properties
and materially adversely affect the Company's financial condition, as well as
its results of operations.

Year 2000 Issues

The Company has initially incurred no significant problems related to the
Year 2000 issue. However, the Company has not yet fully utilized all functions
and processes of its systems and accordingly cannot be sure that all its systems
will be free of Year 2000 issues. Also, the Company has no assurance that its
"critical business partners," or governmental agencies or other key third
parties, have not incurred Year 2000 issues that may affect the Company.

-18-

Operating Data

The following sets forth the Company's historical operating data:

Year ended December 31,
-------------------------------------------
1999 1998 1997
------------- ------------- -------------

Production:
Oil and condensate (MBbls)............................... 2,272 2,492 1,880
Natural gas (MMcf)....................................... 23,190 26,731 22,104
Total (Mmcfe)............................................ 36,822 41,683 33,385

Average sales price per unit (excluding the effects of
hedging):
Oil and condensate (per Bbl)............................. $ 16.83 $ 11.97 $ 18.38
Natural gas (per Mcf).................................... $ 1.68 $ 1.51 $ 1.75
Total (per Mcfe)......................................... $ 2.10 $ 1.68 $ 2.19

Average sales price per unit (including the effects of
hedging):
Oil and condensate (per Bbl)............................. $ 16.22 $ 12.05 $ 18.67
Natural gas (per Mcf).................................... $ 1.68 $ 1.60 $ 1.75
Total (per Mcfe)......................................... $ 2.06 $ 1.75 $ 2.21

Expenses per Mcfe:
Production costs, excluding production and other taxes... $ .51 $ .65 $ .48
Production and other taxes............................... $ .17 $ .14 $ .17
General and administrative............................... $ .21 $ .22 $ .16
Depletion, depreciation and amortization................. $ .52 $ .65 $ .60

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 OEDC
Acquisition, the Carrollton Acquisition and the Pioneer Acquisition, did not
close until the end of December 1997 and, consequently, did not contribute to
1997 operating results. In May 1999, the Company sold its offshore assets
acquired in the OEDC Acquisition and accordingly only 5 months of those assets'
operations are reflected in the 1999 operating results.

Year ended 1999 as compared to 1998

The Company's revenues from the sale of oil and gas (excluding the effects
of hedging activities) were $38.2 million and $38.9 million in 1999 and $29.8
million and $40.3 million in 1998, respectively. Realized oil and gas prices
increased $4.86 per Bbl and $.17 per Mcf, respectively. Excluding the production
from the two significant dispositions, oil production was 2,448,000 barrels and
2,216,000 barrels and gas production was 22,935 MMcf and 21,961 MMcf in 1999 and
1998, respectively. Oil and gas production decreased 220,000 barrels and 3,541
MMcf, respectively, between years. Excluding the production from the two
significant dispositions in 1999, oil and gas production decreased 232,000
barrels and 974 MMcf, respectively, between years. The decrease in the oil
production is principally due to normal production declines and the Company
deferring some of its 1998 projects and not budgeting significant 1999 projects
due to the uncertainties over crude oil price levels earlier in the year. The
decrease in gas production is partially due to normal production declines and
loss and/or curtailment of production on wells due to mechanical and/or
reservoir problems, offset by increased gas production from the

-19-

Company's recent drilling activities.

The Company's hedging activities in 1999 decreased oil and gas revenues $1.4
million ($.61 per Bbl) and $72,000 ($.003 per Mcf), respectively, as compared to
1998, when hedging activities increased oil and reduced gas revenues $206,000
($.08 per Bbl) and $2.6 million ($.09 per Mcf), respectively. At December 31,
1999, the Company had oil and gas hedges in place for approximately 1.9 million
barrels and 5,475 Mcf of the Company's production through 2000 and early 2001.
The hedges will allow the Company to realize, at a minimum, a price of $16.93
per barrel of oil and $2.37 per Mcf on the volumes hedged. The outstanding
hedges had an estimated cost to settle of approximately $1.6 million at December
31, 1999.

The Company's oil and gas production costs were $18.6 million ($.51 per Mcfe)
and $27.1 million ($.65 per Mcfe) in 1999 and 1998, respectively. Excluding the
production costs from the two significant dispositions in 1999, the Company's
production costs would have been $17.3 million ($.49 per Mcfe) and $22.4 million
($.59 per Mcfe) in 1999 and 1998, respectively. A portion of the decrease is
due to the first half of 1998 rework expenses ($.06 per Mcfe) associated with
the 1997 acquisitions properties. Initially, acquired properties generally
incur significant rework expenses, which are costs incurred to perform required
maintenance, workovers and other remedial activities. Also, the decrease is due
to the sale of properties and the Company performing only routine and necessary
expenditures in certain fields early in 1999 due to depressed commodity prices.

Depletion, depreciation and amortization expense (DD&A) was $19.2 million
($.52 per Mcfe) and $27.1 million ($.65 per Mcfe) in 1999 and 1998,
respectively. The decrease in the absolute and per unit amounts is attributable
to (a) the first three quarters of 1999 not including DD&A for the assets then
classified as assets held for sale, (b) increased proved reserves, in high net
book value fields, resulting from increased commodity prices and recent drilling
activities and (c) the effects from the 1998 impairment.

The Company recognized an impairment of $31.8 million and $25.7 million in
1999 and 1998, respectively. The 1999 impairment was comprised of (a) $25.9
million related to assets held for sale and (b) $5.9 million related to oil and
gas properties. The 1999 impairment on assets held for sale was due to the
write-down of the net cost of the assets held for sale based on the expected net
proceeds from the sale of these assets. The 1999 impairment of oil and gas
properties relates directly to one field in which proved undeveloped reserve
volumes were revised downward based on new information. The 1998 impairment
was comprised of (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 was primarily attributable to loss of proved reserves
associated with below expectation developmental drilling results and downhole
mechanical problems primarily in the Company's Gulf Coast and Gulf of Mexico
regions.

Estimated future cash flows for purposes of determining impairment of oil and
gas properties are determined using the following assumptions:

. Only cash flows from proved oil and gas properties disclosed in Note 22 of
the consolidated financial statements are considered in the analysis.

. The prices used for determining cash flows are determined based on the
near-term (a period exceeding one year, depending on management's current
views of future market conditions) NYMEX futures index adjusted for
property specific qualitative and location differentials. The latest
futures price in the near-term price outlook is then held flat for the
remaining life of the properties. Prices estimated for future periods may
be above or below current pricing levels. For example, futures prices over
the following year are significantly below year-end prices at December 31,
1999.

. If production is subject to hedges, future product prices are further
adjusted to reflect the prices to be realized under these arrangements.

The Company's exploration and abandonment expense was $11.0 million and $17.6
million in 1999 and 1998, respectively. The decrease is due primarily to lower
impairment of unproved properties. In 1998, the Company impaired its Webb
County prospect by over $9 million. Offsetting the 1998 impairment are
increases in the Company's dry hole costs due to increased exploratory well
activity in 1999 and increases in seismic costs primarily due to the Company's
3-D seismic shoot in the Paragon venture.

-20-

The Company's general and administrative expense (G&A) was $7.8 million ($.21
per Mcfe) and $9.2 million ($.22 per Mcfe) in 1999 and 1998, respectively.
Excluding G&A from the two significant dispositions in 1999, the Company's G&A
would have been $7.2 million ($.20 per Mcfe) and $6.9 million ($.18 per Mcfe) in
1999 and 1998, respectively.

In the fourth quarter of 1998, the Company recognized a restructuring charge
of $625,000. This charge related to the severance and related benefits that
were provided to individuals whose positions were eliminated as a result of the
planned disposition of assets in 1999.

The 1999 and 1998 equity in net loss of affiliates is primarily attributable
to the Company's ownership in two partnerships acquired in the OEDC Acquisition
both which were included in the Gulf of Mexico disposition. Included in the
equity loss is approximately $211,000 and $632,000 of amortization of the
Company's cost basis in excess of the underlying historical net assets of one of
the partnerships in 1999 and 1998, respectively.

The Company's interest expense was $7.3 million and $8.6 million in 1999 and
1998, respectively. The decrease is due to the decrease in average debt level
between years, resulting from the sale of the Gulf of Mexico properties in the
second quarter of 1999.

The Company's effective income tax rates were 71% and 10% for 1999 and 1998,
respectively. In 1998 the Company provided a valuation allowance of $14.0
million against its deferred tax asset which was reversed in 1999. In 1998, with
the depressed commodity prices outlook, it appeared more likely than not that
the Company would not be able to utilize all its available loss carryforwards
prior to their ultimate expiration. In light of the improved commodity prices,
it now appears more likely than not that the Company will be able to utilize all
its available loss carryforwards.

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, 1998 oil and gas production was relatively flat compared to 1997.
The increase in production, assuming 1997 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 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,
production costs attributable to the 1997 acquisitions were $11.9 million ($1.32
per Mcfe). Thus, the increase in production costs was 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.

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

-21-

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 acquisitions in 1997 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 commodity price
expectations on which most of the property acquisitions were based. The 1998
impairment was comprised of (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 was primarily attributable to loss of proved reserves
associated with below expectation developmental drilling results and downhole
mechanical problems primarily in 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 was 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. The Company's Webb County prospect was
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 Acquisitions, the remainder of the increase in G&A from 1997 to 1998
was primarily the result of a full year's effect of the increase in staff in
1997 necessitated by the Company's growth.

The 1998 equity in net loss of affiliates is attributable to the Company's
ownership in two partnerships 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 one of the
partnerships.

The Company's interest expense was $8.6 million and $1.5 million in 1998 and
1997, respectively. The increase was 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 was due to the Company's inability in 1998
to recognize the income tax benefit associated with a loss before income taxes
because it was more likely than not that the Company would 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 provided a valuation allowance of approximately $14.0 million against
its deferred tax assets.

-22-

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 was $33.4 million for 1999 and $18.4 million for 1998 and net cash
provided by operating activities, before changes in operating assets and
liabilities, was $35.9 million for 1999, compared to $20.2 million for 1998.
The increase was primarily attributable to a decrease in operating costs with a
slight increase in revenues. The increase in revenues is due to an increase in
commodity prices offset by decrease in production due primarily to the sale of
properties.

Captial Expenditures. For 1999, the Company's adjusted budget was 46.2 million
for capital expenditures, and the Company incurred actual cash expenditures of
$44.2 million. The Company acquired proved and unproved properties in the
Central Gulf Coast region for approximately $10 million, which was not budgeted.

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.

Year Ended December 31,
-------------------------------------------
1999 1998 1997
------------- ------------- -------------

Development costs............................. $12,176 $30,663 $ 44,896
Exploration costs............................. 17,087 21,316 2,856
Acquisition costs:
Unproved properties......................... 8,211 4,994 24,532
Proved properties........................... 7,892 404 100,871
------- ------- --------
Total.................................... $45,366 $57,377 $173,155
======= ======= ========

Excluding the effects of the Unocal merger, for 2000 the Company, currently,
expects to spend approximately $50 million in capital projects, of which
approximately $25 million would be for development projects.

The Company regularly engages in discussions relating to potential
acquisitions of oil and gas properties. The Company, other than the Unocal
merger, 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 may 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 approximately $86 million was available at December 31,
1999.

Credit Agreement. In June 1999, the Company entered into an amended and
restated credit agreement (the "Credit Agreement") with Chase Bank of Texas,
N.A. (the "Bank"), which established a revolving credit facility of $250 million
subject to a borrowing base. The borrowing base, which is $175 million at
December 31, 1999, is subject to redetermination annually each April by the
lenders based on certain proved oil and gas reserves and other assets of the
Company. To the extent 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 Agreement is available for the issuance of up to $15.0 million of

-23-

letters of credit, of which $144,000 was outstanding at December 31, 1999. All
amounts outstanding are due and payable in full on April 1, 2001. At December
31, 1999, the outstanding principal was $89 million and the available capacity
was approximately $86 million.

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 .5% per annum) or the
Eurodollar rate, plus 1% 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 substantially all of the Company's oil and gas properties. The
Company obtained a consent and waiver of certain provisions of the Credit
Agreement as it related to the Company entering into the Merger Agreement with
Unocal. The Company also obtained an extension of the maturity date of the
Credit Agreement from January 1, 2001 to April 1, 2001.

Liquidity and Working Capital. At December 31, 1999, the Company had $1.3
million of cash and cash equivalents as compared to $610,000 at December 31,
1998. The Company's ratio of current assets to current liabilities was .77 at
December 31, 1999, compared to 6.23 at December 31, 1998. The Company's working
capital ratio decreased 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, as compared to a working capital
deficit of $3.9 million at December 31, 1999. The working capital deficits are
due partially to the Company maintaining low cash levels for cash management
purposes. The Company, at December 31, 1999, has availability under its Credit
Agreement to fund any working capital deficit.

Unsecured Credit Agreement. In April 1997, the Company entered into a credit
agreement, as amended (the "Unsecured Credit Agreement"), with the Bank which
establishes a revolving credit facility, up to the maximum of $5 million.
Individual borrowings may be made for up to a three week period. The Unsecured
Credit Agreement has no maturity date and is cancellable at any time by the
Bank. Proceeds of the Unsecured Credit Agreement are utilized to fund short-term
needs (less than thirty days). The Company had $1 million in outstanding
principal under the Unsecured Credit Agreement at December 31, 1999.

The interest rate of amounts outstanding 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
law. Interest rates generally are the Bank's cost of funds plus 1% per annum.

Other Matters

Stock Options and Compensation Expense

In 1996, the Company issued options to purchase 3,631,350 shares of Common
Stock, at an exercise price of $2.08 per share, to certain of its officers and
employees in substitution of previous options held by the officers and
employees. As a result, at the time the Company recorded deferred compensation
related to these options which it amortized over a 39-month period beginning in
October 1996. Noncash compensation expense recorded for the years ended December
31, 1999, 1998 and 1997 was $5,049,000, $5,055,000 and $5,053,000, respectively.

During the years ended December 31, 1999, 1998 and 1997, the Company issued
additional options to purchase aggregates of 486,309, 389,499, and 259,000
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.
There are various counterparties to these agreements, including Enron Capital &
Trade Resources Corp., an affiliate of a significant stockholder of the Company.
Settlement of gains or losses on the hedging transactions are generally based on
the difference between the contract price and a

-24-

formula using New York Mercantile Exchange ("NYMEX") or other major indices
related prices and is reported as a component of oil and gas revenues as the
associated production occurs. At December 31, 1999, the Company had entered into
hedging transactions with respect to approximately 5,475,000 MMBtu of its future
2000 estimated natural gas production and 1,463,000 and 452,500 barrels of its
future 2000 and 2001, respectively, estimated crude oil production. For
additional information, see note 18 of Notes to Consolidated Financial
Statements.

Crude Oil

The Company reports average oil prices per Bbl including the net effect of
oil hedges. In 1999, 1998 and 1997, the Company received (paid) related to its
oil hedges ($1.4million), $206,000 and $551,000, respectively.

Natural Gas

The Company reports average gas prices per Mcf including the net effect of
gas hedges. In 1999, 1998 and 1997, the Company received (paid) related to its
gas hedges ($72,000), $2.6 million and ($62,000), respectively.

Natural Gas Balancing

In the natural gas industry, various working interest partners produce more
or less than their entitled share of natural gas from time to time. The
Company's net underproduced position at December 31, 1999 was approximately
112,000 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 an
asset/liability with respect to the value of the underproduced/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 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 2001.
Early adoption is permitted. The Company has not evaluated the effects of
implementing SFAS No. 133.

-25-

Risk Factors

Our rapid growth placed significant demands upon our resources

Our brief operating history has been characterized by rapid growth which
places significant demands on our financial, operational and administrative
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.

You should not place undue reliance on our reserve data because numerous
uncertainties are inherent in the estimation of the reserve data

There are numerous uncertainties inherent in estimating quantities of oil and
gas reserves and their values, including many factors beyond our control. The
reserve information contained in this filing represents estimates only.
Approximately 35% of our total proved reserves on December 31, 1999 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 the estimates assumes that we will
expend substantial capital to develop these reserves.

The estimates of oil and gas reserves in this filing are based on several
factors, including 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. The
estimates of economically recoverable oil and gas reserves and of future net
cash flows rely on various assumptions, including, for example, historical
production from the area compared with production from other producing areas,
constant oil and gas prices, future operating costs, capital expenditures and
the availability of funds. Therefore, estimates of reserves are inherently
imprecise indications of future net cash flows. Actual future production, cash
flows, taxes, operating expenses, development expenditures and quantities of
recoverable oil and gas reserves may vary substantially from those assumed in
the estimates. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves. Additionally, we may
have to revise our reserve data based upon actual production performance,
results of future development and exploration, prevailing oil and gas prices and
other factors, many of which are beyond our control.

You should not construe the present value of our proved reserves as the
current market value of the estimated proved reserves of oil and gas
attributable to our properties. In accordance with SEC requirements, the
estimated discounted future net cash flows from proved reserves have been based
on prices and costs as of the date of the estimate, whereas actual future prices
and costs may vary significantly.

The amount and timing of actual production and related expenses, supply and
demand for oil and gas, changes in consumption levels, changes in governmental
regulations or taxation and other factors will also affect actual future net
cash flows.

In addition, the calculation of the present value of the future net cash
flows using a 10% discount factor, which the SEC requires 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.

-26-

Maintaining reserves and revenues in the future depends on successful
exploration and development

Our future success will depend upon our ability to find or acquire additional
oil and gas reserves that are economically recoverable. Unless we successfully
explore or develop properties containing proved reserves, our proved reserves
will generally decline as a result of continued production. The decline rate
varies depending upon reservoir characteristics and other factors. Our oil and
gas reserves and production, and, therefore, cash flow and income, will depend
greatly upon our success in exploiting out current reserves and acquiring or
finding additional reserves.

Our exploration and development activities will be subject to significant risks

Our drilling activities will involve a variety of operating risks, including
well blow outs, cratering, uncontrollable flows of oil, natural gas or well
fluids into the environment, 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.

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.

Our use of enhanced oil recovery techniques will involve certain risks,
especially the use of water flooding techniques. Part of our inventory of
development prospects will include waterflood projects. Water flooding involves
significant capital expenditures and uncertainty as to the total amount of
recoverable secondary reserves. 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 degree of success, if any, of any enhanced recovery
program depends on a large number of factors, including the porosity of the
formation, the technique used and the location of injector wells.

We cannot assure you that our planned development and exploration projects
and acquisition activities will result in significant additional reserves or
that we will have 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.

We face the risk of volatility of oil and gas prices

Our revenues, operating results and future rate of growth will depend upon
the price 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 that are beyond our control will affect prices of oil and gas, such as:

. the worldwide and domestic supplies of oil and gas,

. the ability of the members of the Organization of Petroleum Exporting
Countries ("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,

-27-

. 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.

We are unable to predict the long-term effects of these and other conditions
on the prices of oil and gas. 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. Lower oil and gas prices may also require a reduction in the
carrying value of our oil and gas properties. We will 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.

Our hedging activities may not adequately offset risks we face

Our use of hedging contracts to reduce our sensitivity to oil and gas price
volatility will be subject to a number of risks. If we do not produce reserves
at the rates we estimate 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. The terms under which we
will enter into fixed price sales and hedging contracts will be based on
assumptions and estimates of numerous factors, including transportation costs to
delivery points. Substantial variations between the assumptions and estimates
we will use and actual results we will experience could adversely affect our
anticipated profit margins and our ability to manage the risks 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. Hedging contracts are also subject to the risk that the
counter-party may not be able or willing to perform its obligations.

Our acquisitions will involve a high degree of risk

We will evaluate and pursue acquisition opportunities available on terms that
our management considers favorable. Although our management will review and
analyze the properties that we will acquire, such reviews are subject to
uncertainties. The acquisition of producing properties will involve an
assessment of several factors, including recoverable reserves, future oil and
gas prices, operating costs, potential environmental and other liabilities and
other factors beyond our control. These assessments are necessarily inexact,
and it is generally not possible to review in detail every individual property
involved in an acquisition. However, even a detailed review of all properties
may not reveal all existing structural and environmental problems. We will
generally assume preclosing liabilities, including environmental liabilities,
and will generally acquire interests in oil and gas properties on an "as is"
basis. In addition, volatile oil and gas prices will make it difficult for us
to accurately estimate the value of producing properties for acquisition and may
cause disruption in the market for oil and gas producing properties. Price
volatility also makes it difficult to budget for and project the return on
acquisitions and development and exploration projects. We will not be able to
assure you that our acquisitions will achieve desired profitability objectives.

Our business will require substantial capital expenditures

We will make substantial capital expenditures for the exploration,
development, acquisition and production of 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.
If revenues decrease as a result of lower oil or gas prices or for other
reasons, we may not be able to expend the capital necessary to replace our

-28-

reserves or to maintain production levels, resulting in a decrease in production
over time. If our cash flow from operations and availability under our credit
facilities are not sufficient to satisfy our capital expenditure requirements,
we may not be able to obtain additional debt or equity financing to meet these
requirements.

Our use of leverage may limit our operational flexibility

We will have certain debt obligations that may affect our operations, including:

. our need to dedicate a substantial portion of our cash flow from operations
to the payment of interest on our indebtedness which prevents us from using
these funds for other purposes;

. 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

. 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 capitalization may
significantly alter our leverage structure. Our ability to meet our debt service
obligations and to reduce our total indebtedness will depend on 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 may not be able to market our production

The marketability of our production will depend, in part, upon the
availability and capacity of natural gas gathering systems, pipelines and
processing facilities. Most of our natural gas will be delivered through gas
gathering systems and gas pipelines that we do not own. Our ability to produce
and market our oil and gas will be subject to several factors, including Federal
and state regulation of oil and gas production and transportation, tax and
energy policies, changes in supply and demand and general economic conditions.

We will be subject to extensive government regulations

Our business will be subject to federal, state and local laws and regulations
relating to the oil and gas industry as well as regulations relating to safety
matters. Although we believe we will be 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 cannot 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.

We will be subject to substantial environmental regulation

Our operations will be subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities. The implementation of new or modified laws or
regulations could have a material adverse effect on our business. The discharge
of oil, gas or other pollutants into the air, soil or water may lead to
significant liability to the government and third parties and may require us to
incur substantial costs. Moreover, we have agreed to indemnify sellers of
producing properties purchased in each of our substantial acquisitions against
environmental claims associated with these properties. Current environmental
laws or regulations or future laws or regulations may adversely affect our
operations or our financial condition. Furthermore, material indemnity claims
may arise against us.

The competition in our industry is intense, some of our competitors have
significantly greater resources than we, and this competition may adversely
affect our operations

We will 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.

-29-

In seeking to acquire desirable producing properties or new leases for future
exploration and in marketing our oil and gas production, we will 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
that will be available to us. This highly competitive environment could have a
material adverse effect on us.

We depend heavily on certain key personnel, and our failure to retain these
individuals could adversely affect the management of Titan

Our success will be highly dependent on Jack Hightower, our 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 will maintain a $3.0 million key
man life insurance policy on the life of Mr. Hightower, with one-half of the
benefits payable to Titan, but no other senior management personnel. 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.

The Delaware General Corporation Law may inhibit a takeover, which may limit the
price that certain investors might be willing to pay for our common stock.

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.

-30-

FORWARD-LOOKING STATEMENTS

Certain statements contained in or incorporated by reference into this
document, 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.

-31-

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, 1999,
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 and crude oil
commodity prices. See note 18 of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements" for specific information regarding
the terms of the Company's commodity derivative financial instruments that are
sensitive to natural gas and crude oil commodity prices.

Fair
2000 2001 Total Value
---- ---- ----- -----
(dollars in thousands, except volumes and prices)

Natural Gas Hedge Derivatives (a):

Collar option contracts (b):
Notional volumes (MMBtu) 5,475,000 -- 5,475,000 $ 1,342,473
Weighted average short call MMBtu strike price (c) $ 2.500 $ -- $ 2.500
Weighted average long put MMBtu strike price (c) $ 2.948 $ -- $ 2.948

Basis differential contracts (d):
Notional volumes (MMBtu) 8,215,000 -- 8,215,000 $ (212,180)
Weighted average MMBtu strike price $ .132 $ -- $ .132

Crude Oil Hedge Derivatives (a):

Collar option contracts (e):
Notional volume (Bbls) 1,463,000 452,500 1,915,500 $(2,755,669)
Weighted average short call strike price per Bbl (c) $ 17.06 $ 16.50 $ 16.93
Weighted average long put strike price per Bbl (c) $ 21.47 $ 20.48 $ 21.24

___________________________________

(a) See note 18 of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements" for additional information related to hedging
activities.
(b) A counterparty has the option to extend a collar option from October 1,
2000 to June 30, 2001 on volumes of 15,000 MMBtu per day at a floor and
ceiling price of $2.60 and $3.08 per MMBtu, respectively. The table does
not include amounts or volumes related to the extension as it is not
probable the counterparty would exercise.
(c) The strike prices are based on the prices traded on the New York Mercantile
("NYMEX").
(d) The basis differential relates to the spread between the NYMEX price and an
El Paso/Permian price or Waha West Texas price.
(e) A counterparty has the option to extend a collar option from July 1, 2000
to June 30, 2001 on volumes of 2,500 barrels per day at a floor and ceiling
price of $16.50 and $20.48 per barrel, respectively. The fair value assumes
the extension is exercised by the counterparty.

-32-

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 1999. See note 5 of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements"
for specific information regarding the terms of the Company's debt obligations
that are sensitive to interest rates.

Fair
2000 2001 Total Value
---- ---- ----- -----
(dollars in thousands, except volumes and prices)

Debt (a)

Variable rate debt:

Chase Bank of Texas, N.A. (Secured) $ - $89,000 $89,000 $89,000
Average interest rate -% 6.55%

Chase Bank of Texas, N.A. (Unsecured) $ - $ 1,000 $ 1,000 $ 1,000
Average interest rate -% 7.02%

__________________________

(a) See note 5 of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements" 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 note 18 of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements" 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 5 of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements" for specific information regarding the terms of
the Company's debt obligations. The Company's policy and strategy, as of
December 31, 1999, 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, 1999, 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, 1998.

-33-

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.

-34-

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

-35-

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following individuals were the directors and executive officers of the
Company as of December 31, 1999:

Jack D. Hightower........... 51 President, Chief Executive Officer and Chairman of the Board
George G. Staley............ 64 Executive Vice President -- Exploration and Director
M. J. "Jack" Rathbone IV.... 47 Executive Vice President -- Operations
Rodney L. Woodard........... 44 Vice President -- Engineering
Thomas H. Moore............. 54 Vice President -- Business Development
Dan P. Colwell.............. 55 Vice President -- Acquisitions, Divestitures and Land
William K. White............ 57 Vice President -- Finance and Chief Financial Officer
John L. Benfatti............ 54 Vice President -- Accounting and Controller
Susan D. Rowland............ 39 Vice President -- Administration and Corporate Secretary
Darin G. Holderness......... 36 Assistant Controller
William J. Vaughn, Jr....... 79 Director
Herbert C. Williamson, III.. 51 Director

Set forth below is a description of the backgrounds of each individual
serving as an executive officer and director of the Company.

Jack D. Hightower has served as President, Chief Executive Officer and
Chairman of the Board of Directors of Titan since the formation of Titan in
March 1995. Prior to forming Titan, from 1986 to January 1996, Mr. Hightower
served as Chairman of the Board and Chief Executive Officer of United Oil
Services, Inc., an 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
Chase Bank of Texas, N.A., Midland.

George G. Staley has served as Executive Vice President, Exploration and
Director of Titan 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.

M. J. "Jack" Rathbone IV has served as Executive Vice President, Operations
since December 1999. Mr. Rathbone served as President of Mobil Producing Texas
and New Mexico and as a director of Mobil Exploration & Producing U.S., Inc.
from September 1995 until December 1999. From 1991 until September 1995, he
served as Planning and Production Manager for Mobil Exploration Norway, Inc.
From 1988 to 1990, he served as Operations Manager for Mobil Oil in California.
From 1985 to 1988, Mr. Rathbone served in headquarters strategic planning and
operations positions with responsibility for Mobil Oil's operations in Europe,
Africa and the Middle East. Prior to 1985, he served in numerous engineering,
planning and operations positions in Mobil Oil's international and domestic
operations. Mr. Rathbone joined Mobil Oil as a Petroleum Engineer in 1977.

Rodney L. Woodard has served as Vice President, Engineering for Titan 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 Titan
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 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.

-36-

Dan P. Colwell has served as Vice President, Land of Titan 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 Titan 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
Titan 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 Titan 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.

Darin G. Holderness has served as Assistant Controller since January 1998.
From January 1996 to December 1997, Mr. Holderness served as Manager of
Financial Reporting for Aquila Gas Pipeline Corporation. From May 1986 to
December 1995, Mr. Holderness served as a senior manager and in other staff
positions with KPMG LLP.

William J. Vaughn, Jr. has served as director of the Company since March
1997. Since 1975, Mr. Vaughn has served as Chairman of the Board and President
of WJV, Inc. and DMV, Inc., which are oil and gas exploration companies. From
1986 and 1996, Mr. Vaughn served as Vice President of United Oil Services, Inc.,
an oil field service company. From 1975 to 1995, Mr. Vaughn was an independent
geologist in association with Mr. Hightower.

Herbert C. Williamson, III has served as a director of Titan since August
1999. Mr. Williamson, since April 1999 to the present, has served as chief
financial officer and since August 1998 to present as director of Merlon
Petroleum Company, a private oil and gas company involved in exploration and
production in Egypt. Mr. Williamson served as Executive Vice President, Chief
Financial Officer and director of Seven Seas Petroleum Inc., a publicly traded
oil and gas exploration company, from September 1997 to April 1999. From 1995
through September 1997, he served as Director in the Investment Banking
Department of Credit Suisse First Boston. Mr. Williamson served as Vice
Chairman and Executive Vice President of Parker & Parsley Petroleum Company, a
publicly traded oil and gas exploration company (now Pioneer Natural Resources
Company) from 1985 through 1995.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the 1934 Act requires directors and officers of the Company,
and persons who own more than 10 percent of the Company's common stock, to file
with the SEC initial reports of ownership and reports of changes in ownership of
the Company's common stock. Directors, officers and more than 10 percent
stockholders are required by the SEC regulations to furnish the Company with
copies of all Section 15(a) forms they file. To the Company's knowledge, based
solely on a review of the copies of such reports furnished to the Company and
written representations that no other reports were required, during the year
ended December 31, 1999, all Section 16(a) filing requirements applicable to its
directors, officers and more than 10 percent beneficial owners were met.

-37-

ITEM 11. EXECUTIVE COMPENSATION

The following table sets forth certain summary information concerning the
compensation paid or awarded to the Chief Executive Officer of the Company and
the other five most highly compensated executive officers of the Company
(collectively, the "named executive officers") for the years indicated.

SUMMARY COMPENSATION TABLE

Long Term
Compensation
Annual Compensation Awards
----------------------------------------------- ---------------
Other Annual Shares
Name and Compensation Underlying All Other
Principal Position Year Salary Bonus (1) Options (#) Compensation
- ------------------------------------- ---- ------------ --------- --- -------------- -------------

Jack D. Hightower 1999 $ 315,162 $100,000 $ -- 74,418 $ 19,338 (2)
President and Chief Executive 1998 246,154 9,231 -- 2,612 19,183
Officer 1997 153,333 48,000 -- -- 12,577

George G. Staley 1999 $ 186,847 $100,000 $ -- 45,317 $ 19,265 (3)
Executive Vice President, 1998 190,154 7,077 -- 2,003 19,183
Exploration 1997 153,333 32,000 -- -- 15,227

William K. White 1999 $ 176,826 $ 60,000 $ -- 15,018 $ 18,893 (4)
Vice President, Finance and 1998 180,192 6,731 -- 116,905(5) 18,980
Chief Financial Officer 1997 129,375 27,000 -- -- 10,560

Thomas H. Moore 1999 $ 155,925 $ 55,000 $ -- 15,049 $ 18,463 (6)
Vice President, Business 1998 160,442 5,971 -- 1,690 18,263
Development 1997 129,375 27,000 -- -- 8,100

Rodney L. Woodard 1999 $ 155,934 $ 55,000 $ -- 14,976 $ 19,041 (7)
Vice President, Engineering 1998 160,442 5,971 13,431 1,690 18,980
1997 129,375 27,000 13,431 -- 10,485

Dan P. Colwell 1999 $ 155,934 $ 55,000 $ -- 14,816 $ 19,077 (8)
Vice President, Land 1998 160,442 5,971 -- 1,690 18,980
1997 129,375 27,000 -- -- 11,440

- ---------------------------------------

/(1)/ Other Annual Compensation does not include prerequisites and other
personal benefits if the aggregate amount of such compensation does not
exceed the lesser of (i) $50,000 of (ii) 10% of individual combined
salary and bonus for the named executive officer in each year.

/(2)/ Consists of premiums paid by the Company under a nondiscriminatory group
insurance program and contributions by the Company under its 401(k)
Retirement Plan of $3,338 and $16,000, respectively, during 1999.

/(3)/ Consists of premiums paid by the Company under a nondiscriminatory group
insurance program and contributions by the Company under its 401(k)
Retirement Plan of $3,265 and $16,000, respectively, during 1999.

/(4)/ Consists of premiums paid by the Company under a nondiscriminatory group
insurance program and contributions by the Company under its 401(k)
Retirement Plan of $2,893 and $16,000, respectively, during 1999.

/(5)/ This amount represents the net effect of the cancellation of 85,000 stock
options granted on October 1, 1996, and 20,000 stock options granted on
January 1, 1998, and the grant of 200,000 stock options on November 19,
1998.

/(6)/ Consists of premiums paid by the Company under a nondiscriminatory group
insurance program and contributions by the Company under its 401(k)
Retirement Plan of $2,463 and $16,000, respectively, during 1999.

/(7)/ Consists of premiums paid by the Company under a nondiscriminatory group
insurance program and contributions by the Company under its 401(k)
Retirement Plan of $3,041 and $16,000, respectively, during 1999.

/(8)/ 1 Consists of premiums paid by the Company under a nondiscriminatory
insurance group program and contributions by the Company under its 401(k)
Retirement Plan of $3,077 and $16,000, respectively, during 1999.

-38-

Option Grants

The following table contains information about stock option grants to the named
executive officers in 1999:

Option/SAR Grants in Last Fiscal Year

Individual Grants
--------------------------------------------------------------------------------------------------
Number of Percent of Potential realizable
securities total options/ value at assumed
underlying SARs granted annual rates of stock
Options/ to employees Exercise of price appreciation for
SARs granted in fiscal Base price Expiration option term
-----------------------
Name # year (1) ($/Sh) date 5% ($) 10% ($)
--------------- ----------- -------------- ------------ ------------- -------- --------

Jack D. Hightower 3,556 0.73% $6.69 1/4/06 $ 2,146 $ 10,513
64,358 13.23% $4.66 6/10/06 $179,623 $347,662
6,504 1.34% $3.69 12/1/06 $ 25,574 $ 44,409
George G. Staley 2,726 0.56% $6.69 1/04/06 $ 1,645 $ 8,059
37,605 7.73% $4.66 6/10/06 $104,956 $203,142
4,986 1.03% $3.69 12/1/06 $ 19,605 $ 34,044
William K. White 2,593 0.53% $6.69 1/04/06 $ 1,565 $ 7,666
7,682 1.58% $4.66 6/10/06 $ 21,440 $ 41,498
4,743 0.98% $3.69 12/1/06 $ 18,649 $ 32,385
Thomas H. Moore 2,300 0.47% $6.69 1/4/06 $ 1,388 $ 6,800
8,542 1.76% $4.66 6/10/06 $ 23,841 $ 46,144
4,207 0.87% $3.69 12/1/06 $ 16,542 $ 28,725
Rodney L. Woodard 2,300 0.47% $6.69 1/4/06 $ 1,388 $ 6,800
8,469 1.74% $4.66 6/10/06 $ 23,637 $ 45,750
4,207 0.87% $3.69 12/1/06 $ 16,542 $ 28,725
Dan P. Colwell 2,300 0.47% $6.69 1/4/06 $ 1,388 $ 6,800
8,309 1.71% $4.66 6/10/06 $ 23,190 $ 44,885
4,207 0.87% $3.69 12/1/06 $ 16,542 $ 28,275

___________________

(1) The total number of options granted to employees in 1999.

-39-

Option Exercises and Year-End Options Values

The following table provides information about the number of shares issued
upon option exercises by the named executive officers during 1999, and the value
realized by the named executive officers. The table also provides information
about the number and value of options that were held by the named executive
officers at December 31, 1999.

Aggregated Option Exercises in Last Fiscal Year
and FY-End Option Values

Number of Securities Value of Unexercised
Underlying Exercised In-the-Money Options
Options at FY-End (#) at FY-End ($)
----------------------------- ----------------------------
Shares
Acquired on Value
Name Exercise (#) Realized ($) Exercisable Unexercisable Exercisable Unexercisable
- -------------------------- ------------ ------------ ----------- ------------- ----------- -------------

Jack D. Hightower 1,705,594 $2,688,016 653 76,377 $ -- $61,633
George G. Staley 872,171 $1,374,541 501 46,819 $ -- $38,085
William K. White -- $ -- 50,477 166,446 $ -- $14,290
Thomas H. Moore 222,641 $ 350,882 423 16,316 $ -- $13,968
Rodney L. Woodard 220,681 $ 347,793 423 16,243 $ -- $13,843
Dan P. Colwell 216,619 $ 341,392 423 16,083 $ -- $14,025

Compensation of Directors

Each director of the Company who is not an employee of the Company will
receive a fee of $15,000 per year for serving as a director. The Company will
also reimburse directors for travel, lodging and related expenses they may incur
in attending the Company's board and committee meetings.

Severance and Retention Bonus Agreements

Each of the executive officers of the Company as of June 10, 1999 is a party to
a Severance and Retention Bonus Agreement dated June 10, 1999 with a Titan
subsidiary. In the following discussion, we refer to the severance and retention
bonus agreements as the severance agreements, to the employees listed in the
previous sentence collectively as the covered employees and to Messrs.
Hightower, Staley, White, Moore, Woodard and Colwell collectively as the Titan
named executive officers. The covered employees are eligible to receive
severance benefits in the event of a qualifying termination of their employment
on or within one year following a change in control of Titan, as such term is
defined in the severance agreements. A qualifying termination of employment
under the severance agreements means (1) a termination by the employer other
than for "cause," as defined in the severance agreements, (2) a termination by
the covered employee for "good reason," as defined in the severance agreements
or (3) the covered employee and the employer shall fail to reach an agreement on
or prior to the change of control as to the terms of the employee's employment
following the change in control, which terms are acceptable to the employee in
his or her sole discretion.

A covered employee who incurs a qualifying termination of employment will:

. be entitled to receive a cash lump sum severance payment equal to his
or her annual base salary and any bonuses or special incentive
payments for the preceding twelve months, multiplied by 3;

. will be provided with life insurance and/or disability benefit plan
coverage until the earlier to occur of 18 months from the date of the
qualifying termination or the covered employee's obtaining other
employment;

. will be reimbursed continuing coverage premiums for hospital
surgical, medical or dental benefit plan coverage until the date on
which the covered employee obtains other employment; and

-40-

. will be entitled to have his or her reasonable legal fees and expenses
paid by the employer as they are incurred by the covered employer in
seeking to obtain or enforce any right or benefit provided by the
severance agreement.

In the event the covered employee does not receive a payment upon a
qualifying termination and the covered employee remains employed by Titan or any
successor of Titan (or an affiliate of Titan or its successor) one year after
the change in control, then the covered employee will be entitled to receive a
cash lump sum retention bonus payment equal to his or her annual base salary
multiplied by 3, and will also be entitled to have his or her reasonable legal
fees and expenses paid by the employer as they are incurred by the covered
employer in seeking to obtain or enforce any right or benefit provided by the
severance agreement.

The severance agreements also provide that in the event of a change of
control, the employer or any successor thereto, or an affiliate of the employer
or any successor thereto, shall take all such action as may be necessary or
appropriate to amend any option to purchase Titan common stock held by the
covered employee to provide that such option will not terminate as a result of
or in connection with the covered employee's termination of employment with the
employer or any successor thereto, or an affiliate of the employer or any
successor thereto, for reasons other than cause, as defined in the severance
agreements, but may continue to be exercised following such termination of
employment until the date on which such options otherwise would terminate or
expire.

Under the severance agreements, the employer is required, if necessary, to
make an additional gross-up payment to any covered employee to offset fully the
effect of any excise tax imposed by Section 4999 of the Internal Revenue Code on
any excess parachute payment, whether made to that employee under the severance
agreement or otherwise. In general, Section 4999 imposes an excise tax on the
recipient of any excess parachute payment equal to 20% of that payment. A
parachute payment is any payment that is contingent on a change in control.
Excess parachute payments consist of the excess of parachute payments over an
individual's average taxable compensation received by him from the employer
during the five taxable years preceding the year in which the change in control
occurs. If the individual has been employed for fewer than five taxable years,
the individual's entire period of employment will be used to calculate the
excess parachute payment.

Compensation Committee Interlocks and Insider Participation

The Company's Compensation Committee is comprised of Messrs. Hightower,
Vaughn and Williamson. Messrs. Hightower and Vaughn and certain of their
affiliates have common ownership interests in wells operated by the Company.
For information relating to the ownership of these interests see "Certain
Relationships and Related Party Transactions" on page 44.

The Company leases its offices are leased from Fasken Center Ltd., which is
an affiliate of Mr. Hightower. For information relating to the terms of the
lease see "Certain Relationships and Related Party Transactions" on page 44.

The Company loaned Mr. Hightower, pursuant to the provisions of the stock
option plan, $4,339,256 to enable him to exercise certain stock options. For
information relating to this and other similar officer and employee loans see
"Certain Relationships and Related Party Transactions" on page 44.

-41-

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The table below sets forth information concerning (i) the only persons known
by the Company, based upon statements filed by such persons pursuant to Section
13(d) or 13(g) of the Securities Exchange Act of 1934 as amended (the "Exchange
Act"), to own beneficially in excess of 5% of the Common Stock as of February
15, 2000 and (ii) the shares of Common Stock beneficially owned, as of February
15, 2000, by each director of the Company, each executive officer listed in the
Summary Compensation Table included elsewhere in this proxy statement, and all
executive officers and directors of the Company as a group. Except as
indicated, each individual has sole voting power and sole investment power over
all shares listed opposite his name.

Shares Beneficially
Owned
--------------------------------------------
Name of Beneficial Owner Number (15) Percent
- ---------------------------------------------------------------------- --------------------- ---------------------

Directors and Named Executive Officers (1):
Jack D. Hightower (2) 4,458,393 11.1%
George G. Staley (3) 1,073,380 2.7%
William K. White (4) 55,985 *
Thomas H. Moore (5) 322,824 *
Rodney L. Woodard (6) 282,061 *
Dan P. Colwell (7) 264,596 *
William J. Vaughn, Jr. (8) 345,041 *
Herbert C. Williamson III -- *

Executive Officers and Directors as a Group (12 persons) (9) 6,968,092 17.3%

Holders of 5% or More Not Named Above
Enron Corp. and Joint Energy Development Investment Limited
Partnership (10) 3,423,194 8.5%
1400 Smith Street
Houston, Texas 77002
State Street Research & Management Company (11) 4,058,423 10.1%
One Financial Center, 30/th/ Floor
Boston, Massachusetts 02111
Schroder Investment Management North America Inc. (12) 2,049,800 5.1%
787 Seventh Ave. 34/th/ Floor
New York, New York 10019
Charles M. Royce (13) 2,458,700 6.1%
1414 Plaza of the Americas
New York, New York 10019
Wellington Management Company, LLP (14) 3,633,900 9.0%
75 State Street
Boston, Massachusetts 02109

___________________

* Less than 1%

(1) The business address of each director and executive officer of Titan is
c/o Titan Exploration, Inc., 500 West Texas, Suite 200, Midland, Texas
79701.

-42-

(2) Includes (i) 4,323,182 shares held by Mr. Hightower, (ii) 133,016 shares
held by Mr. Hightower's children and (iii) 2,195 shares subject to stock
options that are exercisable within 60 days. Based upon information
reported in a Schedule 13D dated December 13, 1999 filed by Unocal
Corporation with the Commission, Unocal purports to having shared voting
power of Mr. Hightower's beneficially owned shares. This shared voting
power is pursuant to a Voting Agreement between Union Oil Company of
California and Jack D. Hightower dated December 13, 1999.
(3) Includes (i) 1,071,696 shares held by Mr. Staley and (ii) 1,684 shares
subject to stock options that are exercisable within 60 days.
(4) Includes (i) 3,000 shares held by Mr. White, (ii) 51,602 shares subject to
stock options that are exercisable within 60 days, and (iii) 1,383 shares
held indirectly through a 401(k) plan.
(5) Includes (i) 321,403 shares held by Mr. Moore and (ii) 1,421 shares subject
to stock options that are exercisable within 60 days.
(6) Includes (i) 267,237 shares held by Mr. Woodard, (ii) 1,421 shares subject
to stock options that are exercisable within 60 days, and (iii) 13,403
shares held indirectly through a 401(k) plan.
(7) Includes (i) 263,175 shares held by Mr. Colwell and (ii) 1,421 shares
subject to stock options that are exercisable within 60 days.
(8) Includes (i) 5,500 shares held by Mr. Vaughn, (ii) 299,287 shares held in
trust for Mr. Vaughn and his spouse, and (iii) 40,254 shares held by
affiliates of Mr. Vaughn.
(9) Includes 67,226 shares that officers and directors as a group have the
right to acquire within 60 days through the exercise of options granted
pursuant to the 1996 incentive plan.
(10) Based upon information reported in a Schedule 13G dated January 20, 1997
filed by Enron Corp. and Joint Energy Development Investments Limited
Partnership ("JEDI") with the Commission. The general partners of JEDI is
Enron Capital Management Limited Partnership, whose general partner is
Enron Capital Corp., an indirect wholly-owned subsidiary of Enron Corp.
(11) Based upon information reported in a Form 13G dated February 7, 2000 filed
by State Street Research & Management Company ("State Street"), State
Street has sole voting power with respect to 3,822,323 of such shares and
has sole dispositive power with respect to 4,058,423 of such shares.
According to the report, State Street is a registered investment advisor
and the reported shares are in fact owned by its clients. No clients of
State Street are identified on the report as beneficially owning more than
5% of Titan's common stock. In the report State Street disclaims beneficial
ownership of the shares.
(12) Based upon information reported in a Schedule 13G dated February 3, 2000
filed by Schroder Investment Management North America Inc. ("Shroder"),
Shroder is a registered investment and has sole voting power with respect
to 1,988,000 of such shares and had sole dispositive power with respect to
2,049,800 of such shares.
(13) Based upon information reported in a Form 13G dated February 9, 2000 filed
by Royce & Associates, Inc. ("R&A"), Royce Management Company ("RMC") and
Charles M. Royce. According to the report, R&A has sole voting and
dispositive power with respect to 2,409,700 of such shares and RMC has sole
voting and dispositive power with respect to 49,000 of such shares.
According to the report, Mr. Royce may be deemed to beneficially own these
shares.
(14) Based upon information reported in a Form 13G dated February 11, 2000 filed
by Wellington Management Company ("WMC"), WMC has shared voting power with
respect to 2,911,100 of such shares and has shared dispositive power with
respect to 3,633,900 of such shares. According to the report, WMC is a
registered investment advisor, the reported shares are owned of record by
its clients and no such client is known to WMC to beneficially own more
than 5% of Titan's common stock.
(15) The number includes only options that are exercisable with 60 days.
However, all options held by an officer and all employees will become
exercisable upon closing of the Unocal merger.

Changes in Control

The Company has agreed to merge the Company and the Permian Basin business
unit of Unocal Corporation into a new company. For more information relating to
the merger see "Recent Developments--Unocal Merger" on page 2.

-43-

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Company has entered into an administrative services contract with
Staley Operating Co. ("Staley Operating"), an affiliate of Mr. Staley. Pursuant
to the agreement, the Company provided certain administrative, accounting and
other office and technical services on behalf of Staley Operating, in its
capacity as the operator of certain producing oil and gas properties, in return
for which the company received the amounts charged by Staley Operating for
providing such services under the applicable operating agreements for such
properties. The total amount refunded by the Company due to past overcharges
under such agreement was approximately $3,300 for the year ended December
31,1999.

Messrs. Hightower, Staley and Vaughn and certain of their affiliates have
common ownership interests in wells operated by the Company and, in accordance
with a standard industry operating agreement, Messrs. Hightower, Staley and
Vaughn and certain of their affiliates make payments to the Company of leasehold
costs and lease operating and supervision charges. These payments aggregated
approximately $9,671 for the year ended December 31, 1999. Revenue received in
connection with these wells was approximately $3,769 for the year ended December
31, 1999. The fees charged by the Company to Messrs. Hightower, Staley and
Vaughn are the same as those charged to unaffiliated third parties that are also
party to the operating agreement.

From time to time, the Company enters into certain hedging arrangements
with Enron Capital & Trade Resources Corp. ("ECTRC"), an affiliate of JEDI.
Pursuant to the terms of such arrangements relating to hedges, during the year
ended December 31, 1999, the Company paid approximately $1,595,000 to ECTRC.

For the year ended December 31, 1999, sales to Enron Corp. (an affiliate of
JEDI), its subsidiaries and affiliates were approximately 36%, of the Company's
oil and gas revenues.

The Company's offices are in Fasken Center located at 500 West Texas, Suite
200, in Midland, Texas and are leased on an arms-length basis from Fasken Center
Ltd., an affiliate of Mr. Hightower. The lease terminates on March 15, 2002 and
requires monthly rent payments of approximately $36,000, subject to increase as
the Company assumes additional space.

On November 11, 1999, the Company entered into loan agreements with the
following executive officers and other employees for the amount set forth below
opposite his or her name to enable these individuals to exercise certain stock
options:

. Jack D. Hightower $4,339,256
. George G. Staley 2,218,918
. Thomas H. Moore 566,428
. Rodney L. Woodard 561,442
. Dan P. Colwell 551,107
. John L. Benfatti 251,373
. Susan D. Rowland 133,190
. Total other employees 52,726

These loans have been secured by a portion of the common stock received by these
individuals upon their exercise of such options. The loans were made pursuant
to the provisions of the stock option plan. The interest rate on the loans is
initially 6.34% and will be adjusted each September 30 to the Company's cost of
funds for the preceding twelve months. The principal and interest associated
with the loans is due in full on November 11, 2002.

-44-

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:

Exhibit
Number Description of Document
- ------
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).

2.4 -- Agreement and Plan of Merger, dated December 13, 1999, among
Union Oil of California, Titan Resources Holdings, Inc., TRH, Inc.
and Titan Exploration, Inc. (filed as Exhibit 2.1 to the Company's
Current Report on Form 8-K filed December 23, 1999 (date of event
December 13, 1999), and 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).

3.2.1 -- Amendment to the Bylaws (filed as Exhibit 3 to the Company's
Current Report on Form 8-K date of report June 10, 1999, and
incorporated herein by reference.

4.1 -- Rights Agreement, dated June 10, 1999, between Titan Exploration,
Inc. and First Union National Bank - Rights Agent (filed as Exhibit
4 to the Company's Current Report on Form 8-K date of Report June
10, 1999, and incorporated herein by reference).

-45-

Exhibit
Number Description of Document
- ------

10.1 -- Agreement of Limited Partnership of Titan Resources, L.P., 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 Statement on Form S-1, Registration No. 333-14029, and
incorporated herein by reference).

10.2 -- 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).

10.3 -- 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).

10.3.1 -- Form of Officer Severance and Retention Bonus Agreement (filed as
Exhibit 10.1 of the Company's Current Report on Form 8-K date of
report June 10, 1999, and incorporated herein by reference).

10.4 -- 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).

10.4.1 -- 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).

10.5 -- 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).

10.5.1 -- 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).

10.5.2 -- 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).

10.5.3 -- 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) .

10.5.4 -- 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).

-46-

10.6 -- 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) .

10.6.1 -- 1999 Stock Option Plan of Titan Exploration, Inc. (filed as
Exhibit 10.2 of the Company's Current Report on Form 8-K date of
report June 10, 1999, and incorporated herein by reference).

10.7 -- Amended and Restated Credit Agreement, dated June 24, 1999, among
Titan Exploration, Inc., Chase Bank of Texas, N.A., as
Administrative Agent, and Financial Institutions now or thereafter
parties thereto (filed as Exhibit 10.10 to the Company's Form 10-Q
for the quarterly period ended June 30, 1999, and incorporated
herein by reference).

10.7.1 -- Consent and Waiver Agreement, dated December 20, 1999, among
Titan Exploration, Inc., Chase Bank of Texas, N.A., and Financial
Institutions now and thereafter parties thereto.

10.8 -- Master Promissory Note, dated July 1, 1999, between Titan
Exploration, Inc. and Chase Bank of Texas, N.A. (filed as Exhibit
10.11 to the Company's Form 10-Q for the quarterly period ended
June 30, 1999, and incorporated herein by reference).

10.9 -- Purchase and Sale Agreement, dated April 28, 1999 by and among
OEDC Exploration & Production, L.P., a Texas limited partnership
("Seller"), and Coastal Oil & Gas USA, L.P., a Delaware limited
partnership ("Buyer") (filed as Exhibit 10.10 of the Company's
Current Report on Form 8-K date of report May 20, 1999, and
incorporated herein by reference).

10.10 -- 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).

10.11 -- 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).

10.12 -- 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).

10.13 -- 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).

10.14 -- 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).

10.15 -- 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).

10.16 -- Letter Agreement, dated November 6, 1997, among Titan
Exploration, Inc. and certain stockholders of Titan Exploration,
Inc. (filed as Exhibit 10.27 to the Company's Registration
Statement on S-4, Registration No. 333-40215, and incorporated
herein by reference).

10.17 -- 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) .

10.18 -- 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.

-47-

(b) During the fourth quarter of 1999 the Company filed a Form 8-K on December
23, 1999 (date of event December 13, 1999), reporting under Item 5. Other
Events. The filing reported the merger agreement between the Company and
Unocal.

-48-

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.

-49-

"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.

-50-

"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.

-51-

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 February 29,
2000.

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 February 29, 2000, 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/ HERBERT C. WILLIAMSON
- ---------------------------------------------
Herbert C. Williamson, III
Director

/s/ WILLIAM J. VAUGHN, JR.
- ---------------------------------------------
William J. Vaughn, Jr.
Director

-52-

Index To Consolidated Financial Statements

Page
----

Consolidated Financial Statements of Titan Exploration, Inc.

Independent Auditors' Report F-2

Consolidated Balance Sheets as of December 31, 1999 and 1998 F-3

Consolidated Statements of Operations for the years ended December 31, 1999, 1998 and 1997 F-4

Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1999, 1998 and 1997 F-5

Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997 F-6

Notes to Consolidated Financial Statements F-7

All schedules are omitted, as the required information is inapplicable or the
information is presented in the financial statements or related notes.

F-1

INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
Titan Exploration, Inc.

We have audited the consolidated financial statements of Titan Exploration, Inc.
and subsidiaries (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 audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Titan Exploration,
Inc. and subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the years in the three year period
ended December 31, 1999, in conformity with generally accepted accounting
principles.

KPMG LLP

Midland, Texas
February 1, 2000

F-2

TITAN EXPLORATION, INC.

Consolidated Balance Sheets
(in thousands, except share data)

December 31,
----------------------
ASSETS 1999 1998
---- ----

Current assets:
Cash and cash equivalents $ 1,310 $ 610
Accounts receivable:
Oil and gas 10,365 13,497
Other 252 761
Inventories 732 1,276
Assets held for sale -- 109,452
Prepaid expenses and other current assets 549 316
--------- ---------

Total current assets 13,208 125,912
--------- ---------

Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 358,787 306,111
Accumulated depletion, depreciation and amortization (128,686) (96,934)
--------- ---------

230,101 209,177
--------- ---------

Other property and equipment, net 4,188 5,179
Deferred income taxes 20,612 --
Other assets, net of accumulated amortization of $921 in 1999 and $639 in 1998 689 754
--------- ---------

$ 268,798 $ 341,022
========= =========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable and accrued liabilities:
Trade $ 7,858 $ 14,097
Accrued interest 959 466
Other (Note 20) 8,303 5,652
--------- ---------

Total current liabilities 17,120 20,215
--------- ---------

Long-term debt 90,000 144,200
Other liabilities (Note 20) 827 5,253

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; 43,993,843 and
40,534,675 shares issued and outstanding at December 31, 1999 and 1998,
respectively 440 405
Additional paid-in capital 285,265 278,109
Notes receivable - officers and employees (8,729) --
Treasury stock, at cost; 3,804,000 and 2,600,000 shares at December 31, 1999
and 1998, respectively (25,764) (20,020)
Deferred compensation -- (5,053)
Accumulated deficit (90,361) (82,087)
--------- ---------

Total stockholders' equity 160,851 171,354
--------- ---------

Commitments and contingencies (Note 8)
$ 268,798 $ 341,022
========= =========

See accompanying notes to consolidated financial statements.

F-3

TITAN EXPLORATION, INC.

Consolidated Statements of Operations
(in thousands, except per share data)

Year ended December 31,
-----------------------------------------
1999 1998 1997
---- ---- ----

Revenues:
Gas sales $ 38,866 $ 42,844 $ 38,715
Oil sales 36,851 30,032 35,112
-------- --------- ---------

Total revenues 75,717 72,876 73,827
-------- --------- ---------

Expenses:
Oil and gas production 18,643 27,078 16,298
Production and other taxes 6,116 5,725 5,548
General and administrative 7,771 9,163 5,372
Amortization of stock option awards 5,049 5,055 5,053
Exploration and abandonment (Note 21) 11,049 17,596 3,055
Depletion, depreciation and amortization 19,222 27,090 19,972
Impairment of long-lived assets 31,783 25,666 68,997
Restructuring costs -- 625 --
-------- --------- ---------

Total expenses 99,633 117,998 124,295
-------- --------- ---------

Operating loss (23,916) (45,122) (50,468)
-------- --------- ---------

Other income (expense):
Interest income 102 125 190
Interest expense (7,320) (8,648) (1,524)
Gain on sale of assets 1,344 923 58
Management fees - affiliate 3 8 10
Equity in net loss of affiliates (182) (458) --
Other 1,626 574 --
-------- --------- ---------

Loss before income taxes (28,343) (52,598) (51,734)
-------- --------- ---------

Income tax benefit 20,069 5,381 18,267
-------- --------- ---------

Net loss $ (8,274) $ (47,217) $ (33,467)
======== ========= =========

Net loss per common share $ (.22) $ (1.22) $ (.99)
======== ========= =========

Net loss per common share - assuming dilution $ (.22) $ (1.22) $ (.99)
======== ========= =========

See accompanying notes to consolidated financial statements.

F-4

TITAN EXPLORATION, INC.

Consolidated Statements of Stockholders' Equity
(in thousands)

Notes
Additional Receivable- Total
Common Paid-in Officers and Treasury Deferred Accumulated Stockholders'
Stock Capital Employees Stock Compensation Deficit Equity
----- ------- --------- ----- ------------ ------- ------

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
Stock options exercised 35 7,160 (8,654) -- -- -- (1,459)
Stock options cancelled -- (4) -- -- 4 -- --
Accrued interest on notes receivable -- -- (75) -- -- -- (75)
Purchase of treasury stock -- -- -- (5,744) -- -- (5,744)
Deferred compensation -- -- -- -- 5,049 -- 5,049
Net loss -- -- -- -- -- (8,274) (8,274)
----- --------- ------- -------- --------- --------- ---------
Balance, December 31, 1999 $ 440 $ 285,265 $(8,729) $(25,764) $ -- $ (90,361) $ 160,851
===== ========= ======= ======== ========= ========= =========

See accompanying notes to consolidated financial statements.

F-5

TITAN EXPLORATION, INC.

Consolidated Statements of Cash Flows
(in thousands)

Year ended December 31,
-----------------------------------
1999 1998 1997
---- ---- ----

Cash flows from operating activities:
Net loss $ (8,274) $ (47,217) $ (33,467)
Adjustments to reconcile net loss to net cash provided by operating
activities:
Depletion, depreciation and amortization 19,222 27,090 19,972
Impairment of long-lived assets 31,783 25,666 68,997
Amortization of stock option awards 5,049 5,055 5,053
Dry holes and abandonments 9,272 14,118 1,053
Gain on sale of assets (1,344) (923) (58)
Equity in net loss of affiliates 182 458 --
Deferred income taxes (20,612) (5,381) (18,267)
Restructuring costs -- 625 --
Other items 599 672 --
Changes in assets and liabilities, excluding acquisitions:
Accounts receivable 2,755 1,279 (1,595)
Prepaid expenses and other current assets (97) (445) (463)
Other assets (231) 36 (96)
Accounts payable and accrued liabilities (4,878) (2,585) 5,434
--------- --------- ---------

Total adjustments 41,700 65,665 80,030
--------- --------- ---------

Net cash provided by operating activities 33,426 18,448 46,563
--------- --------- ---------

Cash flows from investing activities:
Redemption of short-term investment -- 2,331 --
Investing in oil and gas properties (44,179) (57,432) (112,301)
Payments for acquisitions, net of cash acquired -- -- (715)
Additions to other property and equipment (292) (3,919) (1,361)
Contributions in equity investments of affiliates (741) (1,884) --
Proceeds from sale of assets 74,070 2,491 75
Issuance of notes receivable - officers and employees (8,654) -- --
--------- --------- ---------

Net cash provided by (used in) investing activities 20,204 (58,413) (114,302)
--------- --------- ---------
Cash flows from financing activities:
Proceeds (payments) from revolving debt, net (54,200) 60,100 63,588
Payments of debt -- (1,350) --
Exercise of stock options 7,195 548 9
Purchase of treasury stock (5,744) (19,516) (504)
Other financing activities (181) (810) (41)
--------- --------- ---------

Net cash provided by (used in) financing activites (52,930) 38,972 63,052
--------- --------- ---------

Net increase (decrease) in cash and cash
equivalents 700 (993) (4,687)

Cash and cash equivalents, beginning of year 610 1,603 6,290
--------- --------- ---------
Cash and cash equivalents, end of year $ 1,310 $ 610 $ 1,603
========= ========= =========

See accompanying notes to consolidated financial statements.

F-6

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(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 of two entities under common control with the Company. The
Company is an independent energy company engaged primarily in the exploration,
development and acquisition of oil and gas properties. Since operations began in
March 1995, the Company and its predecessors have 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.

(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 influence 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. If, after the passage of
one year, the existence of proved reserves cannot be conclusively established,
any deferred 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

(Continued)

F-7

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

impairment is determined. The Company capitalizes interest on expenditures for
significant development projects until such time as significant operations
commence.

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. 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.

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

(Continued)

F-8

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

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.

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 $56,000 and $225,000 at December 31, 1999 and December 31,
1998, 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.

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

(Continued)

F-9

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

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,
1999, the Company was not subject to any interest rate swap agreements.

Reclassifications

Certain reclassifications have been made to the 1998 and 1997 amounts to
conform to the 1999 presentation.

(3) Unocal Merger Agreement

On December 13, 1999, the Company, Union Oil Company of California, a
California corporation and wholly-owned subsidiary of Unocal Corporation ("Union
Oil"), Pure Resources, Inc., a Delaware corporation and a wholly-owned
subsidiary of Union Oil ("Pure"), and TRH, Inc., a Delaware corporation and a
wholly-owned subsidiary of Pure ("Merger Sub") entered into an Agreement and
Plan of Merger (the "Merger Agreement"). The Merger Agreement provides that, on
the Closing Date immediately following the Closing (as such terms are defined in
the Merger Agreement), Merger Sub will merge with and into the Company, and the
Company will become a wholly-owned subsidiary of Pure (such events constituting
the "Merger"). Once the Merger is consummated, Merger Sub will cease to exist
as a corporation and all of the business, assets, liabilities and obligations of
Merger Sub will be merged into the Company, with the Company remaining as the
surviving corporation (the "Surviving Corporation") and a wholly-owned
subsidiary of Pure.

As a result of the Merger, each outstanding share of the Common Stock, par
value $0.01 per share (the "Company Common Stock"), other than shares owned by
the Company or any wholly-owned subsidiary of the Company, will be converted
into the right to receive .4302314 of a share (the "Exchange Ratio") of Common
Stock, par value $0.01 per share, of Pure ("Pure Common Stock"). At the
effective time of the Merger, each outstanding option to purchase the Company
Common Stock under the Company's stock option plans (each a "Company Common
Stock Option") will be assumed by Pure (each an "Assumed Option") and will
become an option to purchase that number of shares of Pure Common Stock equal
(subject to rounding) to the number of shares of Company Common Stock that was
subject to such option immediately prior to the Merger, multiplied by the
Exchange Ratio. The exercise price of each Assumed Option will be equal to the
quotient determined by dividing the exercise price per share of the Company
Common Stock at which the Company Common Stock Option was exercisable
immediately prior to the effective time of the Merger by the Exchange Ratio,
rounded up to the nearest whole cent.

(Continued)

F-10

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

On the Closing Date, Union Oil will transfer to Pure substantially all of
its oil and gas exploration and production assets in the Permian Basin and San
Juan Basin areas of Texas, New Mexico and Colorado in return for Pure Common
Stock. Upon consummation of the Merger immediately following the Closing, Union
Oil will own approximately 32 million shares of Pure Common Stock, representing
approximately 65% of the outstanding Pure Common Stock, and the former
stockholders of the Company will own the remaining shares representing
approximately 35% of the outstanding Pure Common Stock.

(4) 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):

December 31,
-----------------------------------------------------------------
1999 1998
---------------------------- ----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------ ----- ------ -----

Financial assets:
Cash and cash equivalents $ 1,310 $ 1,310 $ 610 $ 610
Notes receivable - officers and employees 8,729 8,729 - -

Financial liabilities:
Debt:
Line of credit 89,000 89,000 140,000 140,000
Unsecured line of credit 1,000 1,000 4,200 4,200

Off-balance sheet financial instruments
(see Note 18):
Commodity price hedges - (1,625) - 1,673

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.

Notes receivable - officers and employees. The carrying amounts approximate
fair value due to the comparability of the interest rate to the Company's
borrowing rate.

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-11

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(5) Debt

Debt consists of the following (in thousands):

December 31,
----------------------
1999 1998
---- ----

Line of credit $89,000 $140,000
Unsecured line of credit 1,000 4,200
------- --------
$90,000 $144,200
======= ========

Line of Credit

In June 1999, the Company entered into an amended and restated credit
agreement (the "Credit Agreement") with Chase Bank of Texas, N.A. (the "Bank"),
which established a revolving credit facility of $250 million subject to a
borrowing base. All amounts outstanding are due and payable in full on April 1,
2001. The borrowing base, which is $175 million at December 31, 1999, is
subject to redetermination annually each April by the lenders based on certain
proved oil and gas reserves and other assets of the Company.

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 weighted average interest rate at
December 31, 1999 was 6.54%.

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.

The Company obtained a consent and waiver of certain provisions of the
Credit Agreement as it related to the Company entering into the Merger Agreement
with Unocal. The Company also obtained an extension of the maturity date of the
Credit Agreement from January 1, 2001 to April 1, 2001.

The Company is in the process of negotiating a new credit facility, which
will replace the Credit Agreement, for Pure Resources, the new parent of the
Company after the merger.

Unsecured Credit Agreement

In April 1997, the Company entered into a credit agreement, as amended (the
"Unsecured Credit Agreement"), with the Bank which establishes a revolving
credit facility, up to the maximum of $5 million. Individual borrowings

(Continued)

F-12

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

may be made for up to a three week period. The Unsecured Credit Agreement has no
maturity date and is cancellable at anytime by the Bank. The interest 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 law. Interest rates generally are at the Bank's
cost of funds plus 1% per annum. At December 31, 1999, there was $1 million of
outstanding principal balance under the Unsecured Credit Agreement.

Maturities of debt are as follows (in thousands):

2000 $ --
2001 90,000
Thereafter --

(6) 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:

OEDC Carrollton
-------- ----------
(in thousands)

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
======== ========

The liabilities assumed include amounts recorded for preacquisition
contingencies and bank debt of OEDC and Carrollton.

(Continued)

F-13

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:

Recorded amount of assets acquired, including receivables
of $2,589,817 $55,794,243
Liabilities assumed (1,061,330)
-----------

Cash paid $54,732,913
===========

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.

(7) Rights Agreement

On June 10, 1999, the board of directors of the Company authorized and
declared a dividend to the holders of record on July 1, 1999 of one Right (a
"Right") for each outstanding share of the Company's common stock. When
exercisable, each Right will entitle the holder to purchase one one-hundredth of
a share of a Series A Junior Participating Preferred Stock, par value $.01 per
share, of the Company (the "Preferred Shares") at an exercise price of $30.00
per Right. The rights are not currently exercisable and will become exercisable
only if a person or group acquires beneficial ownership of 15% or more of the
Company's outstanding common stock or announces a tender offer or exchange offer
the consummation of which would result in attaining the triggering percentage.
The Rights are subject to redemption by the Company for $.01 per Right at any
time prior to the tenth day after the first public announcement of a triggering
acquisition.

If the Company is acquired in a merger or other business combination
transaction after a person has acquired beneficial ownership of 15% or more of
the Company's common stock, each Right will entitle its holder to purchase, at
the Right's then current exercise price, a number of the acquiring company
shares of common stock having a market value of two times such price. In
addition, if a person or group acquires beneficial ownership of 15% or more of
the Company's common stock, each Right will entitle its holder (other than the
acquiring person or group) to purchase, at the Right's then current price, a
number of the Company's shares of common stock having a market value of two
times the exercise price.

Subsequent to the acquisition by a person or group of beneficial ownership
of 15% or more of the Company's common stock and prior to the acquisition of
beneficial ownership of 50% or more of the Company's common stock, the board of
directors of the Company may exchange the Rights (other than Rights owned by
such acquiring person or group, which will be null and void and
nontransferable), in whole or in part, at an exchange ratio of one share of the
Company's common stock (or one one-hundredth of a Preferred Share) per Right.

The Rights were issued on July 1, 1999, to shareholders of record at the
close of business on that date. The Rights will expire on June 9, 2009.

(Continued)

F-14

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(8) Commitments and Contingencies

Operating Leases

The Company has non-cancelable operating leases for office facilities. 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, 1999 are as
follows (in thousands):

Total Affiliate
----- -----------

2000 $433 $433
2001 433 433
2002 90 90
Thereafter -- --

Lease expense during 1999, 1998 and 1997 was $713,762, $962,986 and $200,474,
respectively. In 1999 and 1998, $193,065 and $412,056, respectively, of the
lease expense was associated with compressors and recorded as production costs.
Lease expense incurred with an affiliate during 1999, 1998 and 1997 was
$432,965, $419,704 and $200,474, respectively.

Litigation

These matters were settled in the fourth quarter of 1999 at an expense to
the Company of approximately $200,000.

Severance Agreements

On June 10, 1999, the board of directors of the Company approved the form
of an Officer Severance and Retention Bonus Agreement (the "Severance
Agreement") to be entered into with each of the officers of the

(Continued)

F-15

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

Company. The triggering event of the Severance Agreement would involve "change
of control" of the Company as defined in the Severance Agreement.

Upon a termination event as defined in the Severance Agreement, each
officer will be entitled to receive, among other benefits, (a) three times such
officer's base salary plus bonus received in the preceding 12 month period, (b)
continuation of life insurance for an eighteen month period, (c) payment of all
medical and dental insurance premiums until the officer obtains other employment
and (d) reimbursement of all reasonable legal fees and other expenses incurred
in seeking to obtain or enforce any right or benefit provided by the Severance
Agreement. If the payments under the Severance Agreement and other benefit plans
from a termination event cause the officer to be subject to federal excise tax,
the officer will receive a grossed-up amount to pay the officer's federal excise
taxes. At December 31, 1999, the Company's estimated obligation pursuant to the
Severance Agreements was $8.3 million.

Letters of Credit

At December 31, 1999, the Company had outstanding letters of credit of
$144,000, which are issued through the Credit Agreement.

(9) Statements of Cash Flows

Interest expense of $6,828,000, $8,489,000 and $1,525,000 was paid in 1999,
1998 and 1997, respectively.

Income taxes of $561,000 were paid in 1999. No income taxes were paid in
1998 and 1997.

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.

(10) Common Stock

In May 1997, the Company originally announced a plan to repurchase up to
$25 million, which in August 1999 the Company's board of directors increased to
$35 million, of the Company's common stock. The repurchases 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, 1999 and December 31, 1998, the Company had purchased, pursuant to
the repurchase plan, 3,751,000 and 2,547,000 shares of its common stock for
approximately $25.3 million and $19.6 million, respectively.

(Continued)

F-16

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(11) Income Taxes

Total income tax expense was allocated as follows:

Year ended December 31,
------------------------------------------------
1999 1998 1997
---- ---- ----

Income (loss) from continuing operations $(20,069) $(5,381) $(18,267)
Stockholders' equity for compensation expense for tax
purposes in excess of amounts recognized for financial
reporting purposes -- (63) (6)
-------- ------- --------
$(20,069) $(5,444) $(18,273)
======== ======= ========

Income tax expense (benefit) attributable to income (loss) for continuing
operations consists of the following:

Year ended December 31,
----------------------------------
1999 1998 1997
---- ---- ----
(in thousands)

Current:
Federal $ 522 $ -- $ --
State 21 -- --
-------- ------- --------

543 -- --
-------- ------- --------
Deferred:
Federal (20,565) (5,320) (18,274)
State (47) (61) 7
-------- ------- --------
(20,612) (5,381) (18,267)
-------- ------- --------

Total $(20,069) $(5,381) $(18,267)
======== ======= ========

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 benefit is as follows:

Year ended December 31,
--------------------------------------------------
1999 1998 1997
---- ---- ----
(in thousands)

Loss at statutory rate $ (9,920) $(18,409) $(18,107)
Change in the deferred tax asset valuation allowance (14,001) 14,001 -
Non-deductible deferred compensation 3,954 - -
State income taxes, net of federal benefit (47) (373) (167)
Other (55) (600) 7
-------- -------- --------

Income tax benefit $(20,069) $ (5,381) $(18,267)
======== ======== ========

(Continued)

F-17

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities are as follows:

December 31,
---------------------------
1999 1998
---- ----
(in thousands)

Deferred tax assets (liabilities):
Net operating loss $18,176 $ 30,353
Compensation, principally due to accrual for financial
reporting purposes -- 3,883
Property, plant and equipment, principally due to differences
in basis upon acquisition, depletion, impairment, and the
deduction of intangible drilling costs for tax purposes 1,023 (4,249)

Investments in affiliates -- (18,027)
Other 1,413 2,041
------- --------

Net deferred tax asset (liability) 20,612 14,001

Valuation allowance of deferred tax assets -- (14,001)
------- --------
Net deferred tax asset (liability), net of valuation
allowance $20,612 $ -
======= ========

A valuation allowance is provided when it is more likely than not that some
portion of the deferred tax assets will not be realized. Based on expectations
for the future and the availability of certain tax planning strategies that
would generate taxable income to realize the net tax benefits, if implemented,
management has determined that taxable income of the Company will more likely
than not be sufficient to fully utilize available carryforwards prior to their
ultimate expiration.

At December 31, 1999, the Company had net operating loss carryforwards
("NOLs") for U.S. federal income tax purposes of approximately $51.6 million,
which are available to offset future regular taxable income, if any. The
carryforwards begin to expire in 2011.

(12) Related Party Transactions

During 1998 and 1997, the Company received $7,536 and $9,656, respectively,
for administrative services from a related party. During 1999, the Company
reimbursed the related party $3,303 for past overcharges for administrative
services.

Director's fees of $36,250, $45,000 and $45,000 were incurred during 1999,
1998 and 1997, respectively.

Certain properties that were owned or controlled by certain shareholders
were acquired by the Company for $100,000 in 1997, which approximates the
predecessor cost of the properties.

During 1999, 1998 and 1997, the Company received (paid) approximately
($1,595,000), $2,232,000 and $551,000 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.

(Continued)

F-18

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

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 and $3,371 for the years ended December 31, 1998 and
1997, 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 $9,671, $43,019 and $88,473 in 1999, 1998 and 1997, respectively.
Revenue received in connection with these oil and gas properties was $3,769,
$12,350 and $16,098 in 1999, 1998 and 1997, 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 1999 and 1998, the Company received fees of approximately $445,800
and $275,000, respectively, for managing the commercial and construction
operations of DIGP.

(13) Notes Receivable - Officers and Employees

On November 11, 1999, certain officers and employees of the Company entered
into promissory notes with the Company for the purpose of receiving funds to
exercise stock options and pay tax obligations related to the option exercises.
The option agreements of these officers and employees provided for the use of
the promissory notes to exercise the options. The promissory notes and related
interest are recourse to the officers and employees. The promissory notes are
primarily secured by the Company's common stock issued pursuant to the option
exercises.

The interest rate on the promissory notes is initially 6.34% and will be
adjusted each September 30 to the Company's cost of funds for the preceding
twelve months. The principal and interest associated with the promissory notes
is due in full on November 11, 2002.

(14) Company Option Plans

Stock Option Plan

In 1996, the Company issued options to purchase 3,631,350 shares of Common
Stock, at an exercise price of $2.08 per share in exchange for partnership unit
options previously held by certain officers and employees in the Company's
predecessor partnership. Deferred compensation was recorded based on the value
of the Company's common stock on September 30, 1996, and was amortized to
expense over a 39 month period. Deferred compensation of approximately
$17,576,000 (before reduction by amounts previously amortized to expense) was
recorded at September 30, 1996. On June 10, 1999, the board of directors of the
Company extended the expiration date of all the options outstanding at June 9,
1999, under the Company's original stock option plan, to December 31, 2003.
There were no other changes to the terms of the related options. The new
measurement required by the extension of expiration date resulted in a lower
amount of total compensation than originally measured. Consequently, neither
the amount nor the amortization of compensation originally determined were
adjusted. At December 31, 1999, all options under the Stock Plan were
exercised.

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

(Continued)

F-19

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

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.

On June 10, 1999 the board of directors of the Company extended the
expiration date two years for all the options outstanding at June 9, 1999, under
the 1996 Incentive Plan. As the exercise price exceeded the current market price
for the stock in all cases, no compensation expense was recorded. There were no
other changes to the terms of the related options.

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.

1999 Option Plan

The Board of Directors adopted the Company's 1999 Stock Option Plan (the
"1999 Option Plan") on June 10, 1999. The purpose of the 1999 Option Plan is to
retain and attract certain employees (non-officers) of the Company to encourage
the sense of proprietorship of such employees and to stimulate the active
interest of the employees in the development and financial success of the
Company.

Participants in the 1999 Option Plan are selected by the Board of Directors
or such committee of the Board as is designated by the Board to administer the
1996 Option 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

(Continued)

F-20

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

judgment of the Compensation Committee, can have a significant effect on the
success of the Company. An aggregate of 200,000 shares of Common Stock have been
authorized and reserved for issuance pursuant to the 1999 Option Plan. These
options vest ratably on each of the first through fourth anniversaries of the
grant date.

Subject to the provisions of the 1999 Option Plan, the Compensation
Committee will be authorized to determine the terms, conditions and limitations
applicable to each award. In addition, the Compensation Committee will have the
exclusive power to interpret the 1999 Option Plan and to adopt such rules and
regulations as it may deem necessary or appropriate in keeping with the
objectives of the 1999 Option Plan. 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.

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:

For the year ended
December 31,
----------------------------------------
1999 1998 1997
---- ---- ----
(in thousands, except per share amounts)

Net loss $(5,981) $(46,314) $(39,676)
Net loss per common share (.16) (1.19) (1.17)
Net loss per share - assuming dilution (.16) (1.19) (1.17)

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. Pro forma adjustments in future years will include compensation
expense associated with the options granted in 1999, 1998 and 1997 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 1999, 1998 and 1997.

The total fair value of stock options granted in 1999, 1998 and 1997 was
approximately $1,323,000, $1,273,000 and $3,349,000, respectively. 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:

1999 1998 1997
---- ---- ----

Risk-free interest rate 5.32% 4.50% 5.25%
Expected life 4.0 4.0 7.0
Expected volatility 49% 48% 46%
Expected dividend yield - - -

(Continued)

F-21

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

A summary of the Company's stock option plans as of December 31, 1999, 1998
and 1997, and changes during the periods ended on those dates is presented
below:

Year ended December 31,
--------------------------------------------------------------------
1999 1998 1997
---------------------- --------------------- ---------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
---------- -------- --------- -------- --------- --------

Stock options:
Outstanding at beginning of year 4,260,147 $ 3.64 4,429,440 $ 4.15 3,716,350 $ 2.28
Options canceled/forfeited (219,545) $15.29 (356,614) $15.51 - -
OEDC options assumed - - - - 458,375 $15.61
Options exercised (3,459,168) $ 2.08 (202,178) $ 2.71 (4,285) $ 2.08
Options granted 486,309 $ 4.79 389,499 $ 8.19 259,000 $10.95
----------- ---------- ----------

Outstanding at end of year 1,067,743 $ 6.74 4,260,147 $ 3.64 4,429,440 $ 4.15
=========== ========== ==========

Exercisable at end of year 295,351 $ 8.42 3,339,117 $ 3.09 2,470,133 $ 4.72
=========== ========== ==========

Weighted average fair value of
options granted during the year $ 4.79 $ 11.33 $ 10.95
=========== ========== ==========

The following table summarizes information about the stock options
outstanding at December 31, 1999:

Options Outstanding Options Exercisable
--------------------------------------------- ----------------------------
Number of Weighted- Weighted Number of Weighted-
Shares Average Average Shares Average
Outstanding at Remaining Exercise Exercisable at Exercise
Range of Exercise Prices December 31, 1999 Contractual Life Price December 31, 1999 Price
------------------------ ----------------- ---------------- -------- ----------------- --------

$3.69 - $5.73 482,066 $6.82 $ 4.61 83,175 $ 5.73
$6.25 - $8.79 322,535 $5.72 $ 6.66 73,500 $ 6.83
$9.375 - $12.75 263,142 $4.39 $10.76 138,676 $10.88

(Continued)

F-22

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(15) Net Loss per Common Share

The following table sets forth the computation of basic and diluted net
loss per common share:

Year ended December 31,
----------------------------------------------
1999 1998 1997
---- ---- ----
(in thousands)

Numerator:
Net loss and numerator for basic and diluted net
loss per common share - income available to
common stockholders $(8,274) $(47,217) $(33,467)
======= ======== ========
Denominator:
Denominator for basic net loss per common share -
weighted average common shares 38,038 38,808 33,942

Effect of dilutive securities - employee stock
options - - -
------- -------- --------

Denominator for diluted net loss per common share
- adjusted weighted average common shares and
assumed conversions 38,038 38,808 33,942
======= ======== ========

Basic net loss per common share $ (.22) $ (1.22) $ (.99)
======= ======== ========

Diluted net loss per common share $ (.22) $ (1.22) $ (.99)
======= ======== ========

Employee stock options to purchase 1,067,743, 4,260,147 and 4,429,440
shares of common stock were outstanding during 1999, 1998 and 1997,
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.

(16) 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
$493,927, $632,883 and $110,981 in 1999, 1998 and 1997, respectively.

(Continued)

F-23

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(17) Major Customers

The following purchasers accounted for 10% or more of the Company's oil and
gas sales:

1999 1998 1997
---- ---- ----

Purchaser A (a) 36% 31% 36%
Purchaser B 16% 13% 12%
Purchaser C 7% 13% 9%

________________

(a) Purchaser A is an affiliate of Enron Corp., a significant stockholder of
the Company.

(18) Derivative Financial Instruments

The Company utilizes various option and swap contracts and other financial
instruments to hedge the effect of price changes on future oil and gas
production. The index price for the natural gas collars settles based on NYMEX
Henry Hub, while the oil collar settles based on the prices for West Texas
Intermediate on NYMEX. The basis swaps lock in the basis differential between
NYMEX Henry Hub and the El Paso/Permian delivery point or the Waha West Texas
delivery point.

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
option and swap contracts and other financial instruments outstanding at
December 31, 1999:

2000 2001
---- ----

Gas related derivatives:
Collar options:
Volume (MMBtu) 5,475,000 --
Index price per MMBtu (floor - ceiling prices) $ 2.50 - $2.95 $ --

Basis swaps:
Volume (MMBtu) 8,215,000 --
Index Price per MMBtu $ .132 $ --

Oil related derivatives:
Collar options (a):
Volume (Bbls) 1,463,000 452,500
Index price per Bbl (floor - ceiling prices) $17.06 - $21.47 $16.50 - $20.48

________________

(a) Includes amounts in which a counterparty has the option to extend the
collar option from July 1, 2000 to June 30, 2001, on volumes of 2,500 Bbls per
day at a floor and ceiling price of $16.50 and $20.48 per barrel, respectively.

(Continued)

F-24

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(19) 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 net 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 net cash flows at a
discount rate commensurate with the risks involved in the industry. As a result
of this process, the Company recognized an impairment of approximately $5.9
million, $22.2 million and $69.0 million related to its oil and gas properties
during 1999, 1998 and 1997, respectively.

Estimated future cash flows for purposes of determining impairment of oil
and gas properties are determined using the following assumptions:

. Only cash flows from proved oil and gas properties disclosed in Note
22 are considered in the analysis.

. The prices used for determining cash flows are determined based on the
near-term (a period exceeding one year, depending on management's
current views of future market conditions) NYMEX futures index
adjusted for property specific qualitative and location differentials.
The latest futures price in the near-term price outlook is then held
flat for the remaining life of the properties. Prices estimated for
future periods may be above or below current pricing levels. For
example, futures prices over the following year are significantly
below year-end prices at December 31, 1999.

. If production is subject to hedges, future product prices are further
adjusted to reflect the prices to be realized under these
arrangements.

In 1998, the Company recognized an impairment of approximately $2.2 million
on its investment in a limited partnership. This impairment was due to a
significant decrease in the fair value of publicly traded securities held by the
limited partnership.

Assets Held for Sale

In the first quarter of 1999, the Company recognized an impairment of $25.9
million on the assets held for sale. The impairment was the result of comparing
the revised estimated sales proceeds, less costs to sell, to the underlying net
cost basis of each specific portfolio of assets.

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.

(Continued)

F-25

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

The following are the results of operations of the assets held for sale and
other assets sold (in thousands):

1999 1998 1997
---- ---- ----

Oil and gas sales $ 3,106 $ 9,646 $ 1,980
Oil and gas production costs (1,566) (6,134) (986)
Production and other taxes (59) (188) (79)
General and administrative expenses (745) (2,215) -
Exploration and abandonment costs (383) (2,111) -
Depletion, depreciation and amortization (1,570) (6,259) -
Impairment of long-lived assets (25,900) (16,463) (14,651)
Equity loss in net loss of affiliates (115) (458) -
Other 541 579 -
-------- -------- --------

$(26,691) $(23,603) $(13,736)
======== ======== ========

The Company suspends depreciation, depletion and amortization expense on
assets once they are classified as assets held for sale. In 1999, the suspended
depreciation, depletion and amortization expense was approximately $1.9 million.

(20) Other Liabilities

The other current and noncurrent liabilities consist of the following (in
thousands):

December 31,
---------------------------------
1999 1998
---- ----

Other current liabilities:
Capital costs and operating expenses $6,079 $2,220
Gas processing obligation - 564
Restructuring costs - 625
Oil and gas payable 1,108 1,106
Other 1,116 1,137
------ ------
$8,303 $5,652
====== ======

Other noncurrent liabilities:
Gas processing obligation $ - $1,130
Environmental reserve 804 824
Plugging and abandonment reserve - 2,483
Gas and pipeline imbalances - 225
Other 23 591
------ ------

$ 827 $5,253
====== ======

(Continued)

F-26

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(21) Exploration and Abandonments

Exploration and abandonments expense consist of the following (in
thousands):

1999 1998 1997
---- ---- ----

Geological and geophysical staff $ 770 $ 1,283 $ -
Uneconomical exploratory wells 4,948 2,593 723
Impaired unproved properties 775 9,870 331
Seismic costs 3,416 1,130 1,436
Delay rentals 276 1,685 205
Plugging and abandonment reserve 134 525 -
Other 730 510 360
------- ------- ------
$11,049 $17,596 $3,055
======= ======= ======

(Continued)

F-27

TITAN EXPLORATION, INC.

Notes to Consolidated Financial Statements

(22) Unaudited Supplementary Information

Capitalized Costs

December 31,
---------------------------
1999 1998
---- ----
(in thousands)

Oil and gas properties:
Proved oil and gas properties $ 345,349 $299,412
Unproved properties 13,438 6,699
--------- --------
358,787 306,111
Accumulated depletion (128,686) (96,934)
--------- --------

Net capitalized costs for oil and gas properties $ 230,101 $209,177
========= ========

Costs Incurred

Year ended December 31,
-----------------------------------------------
1999 1998 1997
---- ---- ----
(in thousands)

Property acquisition costs:
Proved $ 7,892 $ 404 $100,871
Unproved 8,211 4,994 24,532
Exploration 17,087 21,316 2,856
Development 12,176 30,663 44,896
------- ------- --------

$45,366 $57,377 $173,155
======= ======= ========

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, 1999, 1998 and 1997. 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 $24.48, $9.49 and $16.11 per Bbl and a gas price of $1.73, $1.57 and
$1.83 per Mcf as of December 31, 1999, 1998 and 1997, 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 oil and gas properties. Accordingly, these estimates are
expected to change as additional information becomes available in the future.

(Continued)

F-28

TITAN EXPLORATION, INC.

Notes of Consolidated Financial Statements

Oil And Gas Producing Activities

Oil and Natural
Condensate (MBbl) Gas (MMcf)
----------------- ----------

Total Proved Reserves:

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
Purchase of minerals-in-place 962 7,364
Sales of minerals-in-place (2,729) (59,911)
Extensions and discoveries 1,631 35,641
Revision of previous estimates - price 11,425 6,969
Revision of previous estimates - other (198) (54,138)
Production (2,272) (23,190)
------ -------

Balance, December 31, 1999 31,830 244,705
====== =======

Proved Developed Reserves:
December 31, 1996 16,024 180,161
December 31, 1997 23,604 219,307
December 31, 1998 13,233 202,203
December 31, 1999 22,374 149,908

_____________

(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-29

TITAN EXPLORATION, INC.

Notes of 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.

Year ended December 31,
-------------------------------------------------------------
1999 1998 1997
------------------- ------------------- -------------------
(in thousands)

Future:
Cash inflows $1,203,070 $ 738,683 $1,121,526
Production costs (424,660) (241,570) (345,598)
Development costs (63,657) (59,976) (46,877)
Future income taxes (150,689) (34,387) (153,100)
---------- --------- ----------
Future net cash flows 564,064 402,750 575,951
10% annual discount for estimated timing
of cash flows
(230,701) (166,122) (226,901)
---------- --------- ----------
Standardized measure of discounted net
of cash flows $ 333,363 $ 236,628 (a) $ 349,050
========== ========= ==========

_______________

(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-30

TITAN EXPLORATION, INC.

Notes of Consolidated Financial Statements

Standardized Measure Of Discounted Future Net Cash Flows

Changes in Standardized Measure of Discounted Future Net Cash Flows

Year ended December 31,
----------------------------------------------------------
1999 1998 1997
------------------ ------------------ ------------------

(in thousands)

Standardized measure, beginning of period $236,628 $ 349,050 $ 387,863
Extensions and discoveries and improved
recovery, net of future production and
development costs 34,054 15,155 36,439
Accretion of discount 23,663 34,905 38,786
Net change in sales prices, net of production
costs 169,586 (106,032) (180,281)
Net change in income taxes (73,789) 80,444 40,115
Purchase of minerals-in-place 16,907 11,338 72,241
Sales of minerals-in-place (54,847) (235) -
Revision of quantity estimates and revenues
added by development drilling 18,530 (33,892) 11,615
Sales, net of production costs (50,959) (40,073) (51,846)
Changes in estimated future development costs (32,601) (23,040) (7,904)
Changes in production rates and other 46,191 (50,992) 2,022
-------- --------- ---------
Standardized measure, end of period $333,363 $ 236,628 $ 349,050
======== ========= =========

(Continued)

F-31

TITAN EXPLORATION, INC.

Notes to Consoliadated Financial Statements

(23) Selected Quarterly Financial Results (Unaudited)

Quarter
----------------------------------------------------------------------
First Second Third Fourth
---------------- ---------------- ---------------- ----------------

(in thousands, except per share data)

1999:
Total revenues $ 14,780 $17,441 $21,225 $ 22,271
Total expenses (a) 44,783 19,216 17,351 2,641
Net income (loss) (30,003) (1,775) 3,874 19,630
Net income (loss) per common share (.79) (.05) .10 .51
Net income (loss) per common share -
assuming dilution (.79) (.05) .10 .50

1998:
Total revenues $ 22,107 $18,361 $16,671 $ 15,737
Total expenses (b) 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)

______________________

(a) Total expenses in the first and fourth quarter of 1999 includes impairment
of long-lived assets of approximately $25.9 million and $5.9 million,
respectively. The fourth quarter of 1999 includes a deferred tax benefit of
approximately $23.5 million related to the reduction in the deferred tax
assets valuation allowance.
(b) 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.

F-32