EXHIBIT 99.1

Forward-Looking Statements

This exhibit contains statements concerning our expectations, beliefs, plans,
objectives, goals, strategies, future events or performance and underlying
assumptions and other statements that are not historical facts. These statements
are "forward-looking statements" within the meaning of the Private Securities
Litigation Reform Act of 1995. You generally can identify our forward-looking
statements by the words "anticipate," "believe," "budgeted," "continue,"
"could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "scheduled," "should," "will" or
other similar words. These forward-looking statements include, among others,
statements regarding:

o our growth strategies;

o our ability to explore for and develop natural gas and oil resources
successfully and economically;

o anticipated trends in our business;

o our future results of operations;

o our liquidity and our ability to finance our exploration and development
activities;

o future market conditions in the oil and gas industry;

o our ability to make and integrate acquisitions;

o the impact of governmental regulation; and

o future acquisitions.

More specifically, our forward looking statements include:

o our estimates of the timing and number of wells we expect to drill and
other exploration activities; and

o statements regarding our capital expenditure program.

We have based our forward-looking statements on our management's beliefs and
assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.

Some of the factors that could cause actual results to differ from those
expressed or implied in forward-looking statements are described under "Risk
Factors" and in other sections of this exhibit. You should not place undue
reliance on our forward-looking statements. Each forward-looking statement
speaks only as of the date of the particular statement.

Business Strategy

Growth Through the Drillbit

Our objective is to create shareholder value through the execution of a business
strategy designed to capitalize on our strengths. Key elements of our business
strategy include:

o grow primarily through drilling;

o focus on prolific and industry-proven trends;

o aggressively evaluate 3-D seismic data and acquire acreage to maintain a
large drillsite inventory;

o maintain a balanced exploration drilling portfolio;

o manage risk exposure by market testing prospects and optimizing working
interests; and

o retain and incentivize a highly qualified technical staff.

Through the execution of this business strategy, we have achieved the following
results from January 1, 2000 through December 31, 2003:

o we drilled 117 wells in our onshore Gulf Coast area, 107 of which were
classified as exploratory wells, with a 77% success rate; and

o our annual production grew from 4.3 Bcfe in 1999 to 7.5 Bcfe in 2003, a
compound annual growth rate of approximately 15%.

In addition, we have achieved the following results over the three years ended
December 31, 2002:

o our average annual reserve replacement percentage was 222% and;

o our proved reserves grew from 40.6 Bcfe at December 31, 1999 to 63.2
Bcfe at December 31, 2002, a compound annual growth rate of 16%.

Summary Reserve and Production Data

The following table sets forth summary information concerning our estimated
proved natural gas and oil reserves at December 31, 2000, 2001 and 2002 based on
reports prepared by Ryder Scott Company and Fairchild and Wells, Inc.,
Independent Petroleum Engineers. The PV-10 Value and the Standardized Measure
attributable to our proved reserves, shown below, use prices and costs in effect
as of December 31 of the year for which such information is presented.

At December 31,
---------------------------------------
2000 2001 2002
----------- ----------- -----------

Estimated Net Proved Reserves:
Natural gas (MMcf).......................................... 10,992 17,858 12,922
Oil (MBbls)................................................. 6,397 6,857 8,381
Natural gas equivalent (MMcfe)........................... 49,377 59,000 63,208
PV-10 Value (in thousands)(1)............................... $ 88,830 $ 49,582 $ 83,614
Standardized Measure (in thousands)......................... $ 70,106 $ 44,577 $ 65,297
Prices Used in Calculating Estimated Value of Proved
Reserves:
Natural gas (per Mcf)....................................... $ 10.34 $ 2.76 $ 4.70
Oil (per Bbl)............................................... 24.85 17.71 29.16
Other Reserve Data:
Average all-sources finding cost (per Mcfe)(2).............. $ 1.01 $ 1.97 $ 1.89
Average reserve replacement percentage...................... 241% 279% 163%
Proved developed reserves (MMcfe)........................... 16,452 20,702 21,184

Our average all-sources finding cost for the three years ended December 31, 2002
was $1.59 per Mcfe.

The following table sets forth summary information concerning our production
results, sales prices and costs and expenses for the years ended December 31,
2000, 2001 and 2002 and for the nine-month periods ended September 30, 2002 and
2003.

Nine Months Ended
Year Ended September 30,
------------------------------ -------------------
2000 2001 2002 2002 2003
-------- -------- -------- -------- --------

Net Production Volume:
Oil (MBbls)...................... 198 160 401 261 363
Natural gas (MMcf)............... 5,460 4,432 4,801 3,543 3,432
Natural gas equivalent (MMcfe) 6,651 5,390 7,207 5,109 5,607
Average Pre-hedge Sales Prices:
Oil (per Bbl).................... $ 28.64 $ 24.14 $ 25.63 $ 23.95 $ 31.02
Natural gas (per Mcf)............ 4.15 4.58 3.62 3.32 5.87
Average Post-hedge Sales Prices:
Oil (per Bbl).................... $ 27.81 $ 24.28 $ 24.94 $ 23.34 $ 29.08
Natural gas (per Mcf)............ 3.90 5.04 3.50 3.24 5.56
Costs and Expenses (per Mcfe):
Oil and natural gas operating
expenses........................ $ 0.74 $ 0.77 $ 0.68 $ 0.72 $ 0.90
Depreciation, depletion and
amortization.................... 1.08 1.20 1.47 1.44 1.56
General and administrative....... 0.47 0.62 0.57 0.60 0.77

- ----------

(1) The PV-10 Values are pre-tax and were determined by using the year-end sales
prices, which averaged $24.85, $17.71 and $29.16 per Bbl of oil, and $10.34,
$2.76 and $4.70 per Mcf of natural gas in 2000, 2001 and 2002, respectively.

(2) Our all-sources finding cost excludes the coalbed methane unproved property
costs we contributed as a minority investment to Pinnacle Gas Resources,
Inc. in June 2003 and, accordingly, is no longer included in our
consolidated operations. We believe our calculation of finding cost provides
investors with an indication of our relative exploration efficiency. In
addition, our management uses finding cost as a component of our individual
well economic analysis. The table below reconciles our calculation of
finding cost to our costs incurred in the purchase of proved and unproved
properties and in development and exploration activities, excluding
capitalized interest on unproved properties of $3.6 million, $3.2 million
and $3.1 million for the years ended December 31, 2000, 2001 and 2002,
respectively:

Year Ended December 31,
------------------------------------
2000 2001 2002
---------- ---------- ----------
(in thousands, except finding cost)

Acquisition costs:
Unproved properties contributed to Pinnacle....... -- $ 5,239 $ 1,323
Other unproved properties......................... $ 6,641 7,368 5,079
Proved properties................................. 337 800 660
Exploration......................................... 7,843 18,356 14,194
Development......................................... 1,361 3,065 2,351
---------- ---------- ----------
Total costs incurred.............................. $ 16,182 $ 34,828 $ 23,607
========== ========== ==========
Less unproved properties contributed to Pinnacle.... -- $ 5,239 $ 1,323
---------- ---------- ----------
Adjusted costs...................................... $ 16,182 $ 29,589 $ 22,284
========== ========== ==========
Total proved reserves added......................... 16,040 15,018 11,761
---------- ---------- ----------
Average all-sources finding cost (per Mcfe)......... $ 1.01 $ 1.97 $ 1.89
========== ========== ==========

Risk Factors

Natural gas and oil drilling is a speculative activity and involves numerous
risks and substantial and uncertain costs that could adversely affect us.

Our success will be largely dependent upon the success of our drilling program.
Drilling for natural gas and oil involves numerous risks, including the risk
that no commercially productive natural gas or oil reservoirs will be
discovered. The cost of drilling, completing and operating wells is substantial
and uncertain, and drilling operations may be curtailed, delayed or canceled as
a result of a variety of factors beyond our control, including:

o unexpected or adverse drilling conditions;

o elevated pressure or irregularities in geologic formations;

o equipment failures or accidents;

o adverse weather conditions;

o compliance with governmental requirements; and

o shortages or delays in the availability of drilling rigs, crews and
equipment.

Because we identify the areas desirable for drilling from 3-D seismic data
covering large areas, we may not seek to acquire an option or lease rights until
after the seismic data is analyzed or until the drilling locations are also
identified; in those cases, we may not be permitted to lease, drill or produce
natural gas or oil from those locations.

Even if drilled, our completed wells may not produce reserves of natural gas or
oil that are economically viable or that meet our earlier estimates of
economically recoverable reserves. Our overall drilling success rate or our
drilling success rate for activity within a particular project area may decline.
Unsuccessful drilling activities could result in a significant decline in our
production and revenues and materially harm our operations and financial
condition by reducing our available cash and resources. Because of the risks and
uncertainties of our business, our future performance in exploration and
drilling may not be comparable to our historical performance.

We may not adhere to our proposed drilling schedule.

Our final determination of whether to drill any scheduled or budgeted wells will
be dependent on a number of factors, including:

o the results of our exploration efforts and the acquisition, review and
analysis of the seismic data;

o the availability of sufficient capital resources to us and the other
participants for the drilling of the prospects;

o the approval of the prospects by the other participants after additional
data has been compiled;

o economic and industry conditions at the time of drilling, including
prevailing and anticipated prices for natural gas and oil and the
availability and prices of drilling rigs and crews; and

o the availability of leases and permits on reasonable terms for the
prospects.

Although we have identified or budgeted for numerous drilling prospects, we may
not be able to lease or drill those prospects within our expected time frame or
at all. Wells that are currently part of our capital budget may be based on
statistical results of drilling activities in other 3-D project areas that we
believe are geologically similar rather than on analysis of seismic or other
data in the prospect area, in which case actual drilling and results are likely
to vary, possibly materially, from those statistical results. In addition, our
drilling schedule may vary from our expectations because of future
uncertainties.

Our reserve data and estimated discounted future net cash flows are estimates
based on assumptions that may be inaccurate and are based on existing economic
and operating conditions that may change in the future.

There are numerous uncertainties inherent in estimating natural gas and oil
reserves and their estimated value, including many factors beyond the control of
the producer. The reserve data set forth in this exhibit represents only
estimates. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of natural gas and oil that cannot be
measured in an exact manner. The reserve data included in this exhibit
represents estimates that depend on a number of factors and assumptions that may
vary considerably from actual results, including:

o historical production from the area compared with production from other
areas;

o the assumed effects of regulations by governmental agencies;

o assumptions concerning future natural gas and oil prices;

o future operating costs;

o severance and excise taxes;

o development costs; and

o workover and remedial costs.

For these reasons, estimates of the economically recoverable quantities of
natural gas and oil attributable to any particular group of properties,
classifications of those reserves based on risk of recovery and estimates of the
future net cash flows expected from them prepared by different engineers or by
the same engineers but at different times may vary substantially. Accordingly,
reserve estimates may be subject to upward or downward adjustment, and actual
production, revenue and expenditures with respect to our reserves likely will
vary, possibly materially, from estimates.

As of December 31, 2002, approximately 66% of our proved reserves were either
proved undeveloped or proved nonproducing. Moreover, some of the producing wells
included in our reserve reports as of December 31, 2002 had produced for a
relatively short period of time as of that date. Because most of our reserve
estimates are calculated using volumetric analysis, those estimates are less
reliable than estimates based on a lengthy production history. Volumetric
analysis involves estimating the volume of a reservoir based on the net feet of
pay of the structure and an estimation of the area covered by the structure
based on seismic analysis. In addition, realization or recognition of our proved
undeveloped reserves will depend on our development schedule and plans. Lack of
certainty with respect to development plans for proved undeveloped reserves
could cause the discontinuation of the classification of these reserves as
proved. We have from time to time chosen to delay development of our proved
undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing
shorter-term exploration projects with higher potential rates of return, adding
to our lease position in this field and further evaluating additional economic
enhancements for this field's development.

The discounted future net cash flows included in this exhibit are not
necessarily the same as the current market value of our estimated natural gas
and oil reserves. As required by the Securities and Exchange Commission (the
SEC), the estimated discounted future net cash flows from proved reserves are
based on prices and costs as of the date of the estimate. Actual future net cash
flows also will be affected by factors such as:

o the actual prices we receive for natural gas and oil;

o our actual operating costs in producing natural gas and oil;

o the amount and timing of actual production;

o supply and demand for natural gas and oil;

o increases or decreases in consumption of natural gas and oil; and

o changes in governmental regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future
net cash flows for reporting requirements in compliance with the Financial
Accounting Standards Board in Statement of Financial Accounting Standards No. 69
may not be the most appropriate discount factor based on interest rates in
effect from time to time and risks associated with us or the natural gas and oil
industry in general.

We depend on successful exploration, development and acquisitions to maintain
reserves and revenue in the future.

In general, the volume of production from natural gas and oil properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent we conduct successful
exploration and development activities or acquire properties containing proved
reserves, or both, our proved reserves will decline as reserves are produced.
Our future natural gas and oil production is, therefore, highly dependent on our
level of success in finding or acquiring additional reserves. The business of
exploring for, developing or acquiring reserves is capital intensive. Recovery
of our reserves, particularly undeveloped reserves, will require significant
additional capital expenditures and successful drilling operations. To the
extent cash flow from operations is reduced and external sources of capital
become limited or unavailable, our ability to make the necessary capital
investment to maintain or expand our asset base of natural gas and oil reserves
would be impaired. In addition, we are dependent on finding partners for our

exploratory activity. To the extent that others in the industry do not have the
financial resources or choose not to participate in our exploration activities,
we will be adversely affected.

Natural gas and oil prices are highly volatile, and lower prices will negatively
affect our financial results.

Our revenue, profitability, cash flow, future growth and ability to borrow funds
or obtain additional capital, as well as the carrying value of our properties,
are substantially dependent on prevailing prices of natural gas and oil.
Historically, the markets for natural gas and oil prices have been volatile, and
those markets are likely to continue to be volatile in the future. It is
impossible to predict future natural gas and oil price movements with certainty.
Prices for natural gas and oil are subject to wide fluctuation in response to
relatively minor changes in the supply of and demand for natural gas and oil,
market uncertainty and a variety of additional factors beyond our control. These
factors include:

o the level of consumer product demand;

o overall economic conditions;

o weather conditions;

o domestic and foreign governmental relations;

o the price and availability of alternative fuels;

o political conditions;

o the level and price of foreign imports of oil and liquefied natural gas;
and

o the ability of the members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil price controls.

Declines in natural gas and oil prices may materially adversely affect our
financial condition, liquidity and ability to finance planned capital
expenditures and results of operations.

We face strong competition from other natural gas and oil companies.

We encounter competition from other natural gas and oil companies in all areas
of our operations, including the acquisition of exploratory prospects and proven
properties. Our competitors include major integrated natural gas and oil
companies and numerous independent natural gas and oil companies, individuals
and drilling and income programs. Many of our competitors are large,
well-established companies that have been engaged in the natural gas and oil
business much longer than we have and possess substantially larger operating
staffs and greater capital resources than we do. These companies may be able to
pay more for exploratory projects and productive natural gas and oil properties
and may be able to define, evaluate, bid for and purchase a greater number of
properties and prospects than our financial or human resources permit. In
addition, these companies may be able to expend greater resources on the
existing and changing technologies that we believe are and will be increasingly
important to attaining success in the industry. We may not be able to conduct
our operations, evaluate and select suitable properties and consummate
transactions successfully in this highly competitive environment.

We may not be able to keep pace with technological developments in our industry.

The natural gas and oil industry is characterized by rapid and significant
technological advancements and introductions of new products and services using
new technologies. As others use or develop new technologies, we may be placed at
a competitive disadvantage, and competitive pressures may force us to implement
those new technologies at substantial cost. In addition, other natural gas and
oil companies may have greater financial, technical and personnel resources that
allow them to enjoy technological advantages and may in the future allow them to
implement new technologies before we can. We may not be able to respond to these
competitive pressures and implement new technologies on a timely basis or at an
acceptable cost. If one or more of the technologies we use now or in the future
were to become obsolete or if we are unable to use the most advanced
commercially available technology, our business, financial condition and results
of operations could be materially adversely affected.

We are subject to various governmental regulations and environmental risks.

Natural gas and oil operations are subject to various federal, state and local
government regulations that may change from time to time. Matters subject to
regulation include discharge permits for drilling operations, plug and
abandonment bonds, reports concerning operations, the spacing of wells,
unitization and pooling of properties and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting the rate of flow of natural gas and oil wells below actual
production capacity in order to conserve supplies of natural gas and oil. Other
federal, state and local laws and regulations relating primarily to the
protection of human health and the environment apply to the development,
production, handling, storage, transportation and disposal of natural gas and
oil, by-products thereof and other substances and materials produced or used in
connection with natural gas and oil operations. In addition, we may be liable
for environmental damages caused by previous owners of property we purchase or
lease. As a result, we may incur substantial liabilities to third parties or
governmental entities and may be required to incur substantial remediation
costs. Further, we or our affiliates hold certain mineral leases in the State of
Montana that require coalbed methane drilling permits, the issuance of which has
been challenged in pending litigation. We may not be able to obtain new permits
in an optimal time period or at all. We also are subject to changing and
extensive tax laws, the effects of which cannot be predicted. Compliance with
existing, new or modified laws and regulations could have a material adverse
effect on our business, financial condition and results of operations.

We are subject to various operating and other casualty risks that could result
in liability exposure or the loss of production and revenues.

The natural gas and oil business involves operating hazards such as:

o well blowouts;

o mechanical failures;

o explosions;

o uncontrollable flows of oil, natural gas or well fluids;

o fires;

o geologic formations with abnormal pressures;

o pipeline ruptures or spills;

o releases of toxic gases; and

o other environmental hazards and risks.

Any of these hazards and risks can result in the loss of hydrocarbons,
environmental pollution, personal injury claims and other damage to our
properties and the property of others.

We may not have enough insurance to cover all of the risks we face.

In accordance with customary industry practices, we maintain insurance coverage
against some, but not all, potential losses in order to protect against the
risks we face. We do not carry business interruption insurance. We may elect not
to carry insurance if our management believes that the cost of available
insurance is excessive relative to the risks presented. In addition, we cannot
insure fully against pollution and environmental risks. The occurrence of an
event not fully covered by insurance could have a material adverse effect on our
financial condition and results of operations.

We cannot control the activities on properties we do not operate and are unable
to ensure their proper operation and profitability.

We do not operate all of the properties in which we have an interest. As a
result, we have limited ability to exercise influence over, and control the
risks associated with, operations of these properties. The failure of an
operator of our wells to adequately perform operations, an operator's breach of
the applicable agreements or an operator's failure to act in ways that are in
our best interests could

reduce our production and revenues. The success and timing of our drilling and
development activities on properties operated by others therefore depend upon a
number of factors outside of our control, including the operator's

o timing and amount of capital expenditures;

o expertise and financial resources;

o inclusion of other participants in drilling wells; and

o use of technology.

The marketability of our natural gas production depends on facilities that we
typically do not own or control, which could result in a curtailment of
production and revenues.

The marketability of our production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. We generally deliver natural gas through gas gathering
systems and gas pipelines that we do not own under interruptible or short-term
transportation agreements. Under the interruptible transportation agreements,
the transportation of our gas may be interrupted due to capacity constraints on
the applicable system, for maintenance or repair of the system, or for other
reasons as dictated by the particular agreements. Our ability to produce and
market natural gas on a commercial basis could be harmed by any significant
change in the cost or availability of such markets, systems or pipelines.

Our future acquisitions may yield revenues or production that varies
significantly from our projections.

In acquiring producing properties, we assess the recoverable reserves, future
natural gas and oil prices, operating costs, potential liabilities and other
factors relating to the properties. Our assessments are necessarily inexact and
their accuracy is inherently uncertain. Our review of a subject property in
connection with our acquisition assessment will not reveal all existing or
potential problems or permit us to become sufficiently familiar with the
property to assess fully its deficiencies and capabilities. We may not inspect
every well, and we may not be able to observe structural and environmental
problems even when we do inspect a well. If problems are identified, the seller
may be unwilling or unable to provide effective contractual protection against
all or part of those problems. Any acquisition of property interests may not be
economically successful, and unsuccessful acquisitions may have a material
adverse effect on our financial condition and future results of operations.

Our business may suffer if we lose key personnel.

We depend to a large extent on the services of certain key management personnel,
including our executive officers and other key employees, the loss of any of
whom could have a material adverse effect on our operations. We have entered
into employment agreements with each of S.P. Johnson IV, our President and Chief
Executive Officer, Paul F. Boling, our Chief Financial Officer, Jeremy T.
Greene, our Vice President of Exploration Development, Kendell A. Trahan, our
Vice President of Land, and J. Bradley Fisher, our Vice President of Operations.
We do not maintain key-man life insurance with respect to any of our employees.
Our success will be dependent on our ability to continue to employ and retain
skilled technical personnel.

We may experience difficulty in achieving and managing future growth.

We have experienced growth in the past primarily through the expansion of our
drilling program. Future growth may place strains on our resources and cause us
to rely more on project partners and independent contractors, possibly
negatively affecting our financial condition and results of operations. Our
ability to grow will depend on a number of factors, including:

o our ability to obtain leases or options on properties for which we have
3-D seismic data;

o our ability to acquire additional 3-D seismic data;

o our ability to identify and acquire new exploratory prospects;

o our ability to develop existing prospects;

o our ability to continue to retain and attract skilled personnel;

o our ability to maintain or enter into new relationships with project
partners and independent contractors;

o the results of our drilling program;

o hydrocarbon prices; and

o our access to capital.

We may not be successful in upgrading our technical, operations and
administrative resources or in increasing our ability to internally provide
certain of the services currently provided by outside sources, and we may not be
able to maintain or enter into new relationships with project partners and
independent contractors. Our inability to achieve or manage growth may adversely
affect our financial condition and results of operations.

We may continue to hedge the price risks associated with our production. Our
hedge transactions may result in our making cash payments or prevent us from
benefitting to the fullest extent possible from increases in prices for natural
gas and oil.

Because natural gas and oil prices are unstable, we periodically enter into
price-risk-management transactions such as swaps, collars, futures and options
to reduce our exposure to price declines associated with a portion of our
natural gas and oil production and thereby to achieve a more predictable cash
flow. The use of these arrangements limits our ability to benefit from increases
in the prices of natural gas and oil. Our hedging arrangements may apply to only
a portion of our production, thereby providing only partial protection against
declines in natural gas and oil prices. These arrangements may expose us to the
risk of financial loss in certain circumstances, including instances in which
production is less than expected, our customers fail to purchase contracted
quantities of natural gas and oil or a sudden, unexpected event materially
impacts natural gas or oil prices.

We have substantial capital requirements that, if not met, may hinder
operations.

We have experienced and expect to continue to experience substantial capital
needs as a result of our active exploration, development and acquisition
programs. We expect that additional external financing will be required in the
future to fund our growth. We may not be able to obtain additional financing,
and financing under existing or new credit facilities may not be available in
the future. Without additional capital resources, we may be forced to limit or
defer our planned natural gas and oil exploration and development program and
thereby adversely affect the recoverability and ultimate value of our natural
gas and oil properties, in turn negatively affecting our business, financial
condition and results of operations.

Our credit facility contains operating restrictions and financial covenants, and
we may have difficulty obtaining additional credit.

Over the past few years, increases in commodity prices and proved reserve
amounts and the resulting increase in our estimated discounted future net
revenue have allowed us to increase our available borrowing amounts. In the
future, commodity prices may decline, we may increase our borrowings or our
borrowing base may be adjusted downward, thereby reducing our borrowing
capacity. Our credit facility is secured by a pledge of substantially all of our
producing natural gas and oil properties assets, is guaranteed by our subsidiary
and contains covenants that limit additional borrowings, dividends to
nonpreferred shareholders, the incurrence of liens, investments, sales or
pledges of assets, changes in control, repurchases or redemptions for cash of
our common or preferred stock, speculative commodity transactions and other
matters. The credit facility also requires that specified financial ratios be
maintained. We may not be able to refinance our debt or obtain additional
financing, particularly in view of our current credit agreement's restrictions
on our ability to incur debt under our bank credit facility and the fact that
substantially all of our assets are currently pledged to secure obligations
under that facility. The restrictions of our credit facility and our difficulty
in obtaining additional debt financing may have adverse consequences on our
operations and financial results including:

o our ability to obtain financing for working capital, capital
expenditures, our drilling program, purchases of new technology or other
purposes may be impaired;

o the covenants in our credit facilities that limit our ability to borrow
additional funds and dispose of assets may affect our flexibility in
planning for, and reacting to, changes in business conditions;

o because our indebtedness is subject to variable interest rates, we are
vulnerable to increases in interest rates;

o any additional financing we obtain may be on unfavorable terms;

o we may be required to use a substantial portion of our cash flow to make
debt service payments, which will reduce the funds that would otherwise
be available for operations and future business opportunities;

o a substantial decrease in our operating cash flow or an increase in our
expenses could make it difficult for us to meet debt service
requirements and could require us to modify our operations, including by
curtailing portions of our drilling program, selling assets, reducing
our capital expenditures, refinancing all or a portion of our existing
debt or obtaining additional financing; and

o we may become more vulnerable to downturns in our business or the
economy generally.

We may incur additional debt in order to fund our exploration and development
activities. A higher level of indebtedness increases the risk that we may
default on our debt obligations. Our ability to meet our debt obligations and
reduce our level of indebtedness depends on future performance. General economic
conditions, natural gas and oil prices and financial, business and other
factors, many of which are beyond our control, affect our operations and our
future performance. Our senior subordinated notes contain restrictive covenants
similar to those under our credit facility.

In addition, under the terms of our credit facility, our borrowing base is
subject to redeterminations at least semiannually based in part on prevailing
natural gas and oil prices. In the event the amount outstanding exceeds the
redetermined borrowing base, we could be forced to repay a portion of our
borrowings. We may not have sufficient funds to make any required repayment. If
we do not have sufficient funds and are otherwise unable to negotiate renewals
of our borrowings or arrange new financing, we may have to sell a portion of our
assets.

We may record ceiling limitation write-downs that would reduce our shareholders'
equity.

We use the full-cost method of accounting for investments in natural gas and oil
properties. Accordingly, we capitalize all the direct costs of acquiring,
exploring for and developing natural gas and oil properties. Under the full-cost
accounting rules, the net capitalized cost of natural gas and oil properties may
not exceed a "ceiling limit" that is based upon the present value of estimated
future net revenues from proved reserves, discounted at 10%, plus the lower of
the cost or the fair market value of unproved properties. If net capitalized
costs of natural gas and oil properties exceed the ceiling limit, we must charge
the amount of the excess to operations through depreciation, depletion and
amortization expense. This charge is called a "ceiling limitation write-down."
This charge does not impact cash flow from operating activities but does reduce
our shareholders' equity. The risk that we will be required to write down the
carrying value of our natural gas and oil properties increases when natural gas
and oil prices are low or volatile. In addition, write-downs would occur if we
were to experience sufficient downward adjustments to our estimated proved
reserves or the present value of estimated future net revenues, as further
discussed in "Risk Factors--Our reserve data and estimated discount future net
cash flows are estimates based upon assumptions that may be inaccurate and are
based on existing economic and operating conditions that may change in the
future." Once incurred, a write-down of natural gas and oil properties is not
reversible at a later date. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Critical Accounting Policies and
Estimates" for additional information on these matters.

Our affiliates control a majority of our outstanding common stock, which may
affect your vote as a shareholder.

As of December 31, 2003, our officers and directors and their affiliates
beneficially owned approximately 86% of our outstanding common stock (60% after
completion of the offering to which our prospectus dated February 5, 2004
relates). As a result, these shareholders, to the extent they act as a group,
will be able to significantly influence or control the outcome of certain
matters requiring a shareholder vote, including votes concerning the election of
directors, the adoption or amendment of provisions in our certificate of
incorporation or bylaws, and the approval of mergers and other significant
corporate transactions. The existence of these levels of ownership concentrated
in a few persons makes it unlikely that any other holder of common stock will be
able to affect our management or strategic direction. These factors may also
have the effect of delaying, deterring or preventing a change in control and may
adversely affect the voting and other rights of other shareholders.

Our shares that are eligible for future sale may have an adverse effect on the
price of our common stock.

Future sales of substantial amounts of our common stock, or a perception that
such sales could occur, could adversely affect the market price of our common
stock and could impair our ability to raise capital through the sale of our
equity securities. This risk is

compounded by the fact that a substantial portion of our common stock is owned
by a relatively few number of individuals or entities. The major holders of
shares of our common stock have piggyback and demand registration rights that
provide for the registration of the resale of those shares at our expense which
will allow those shares to be sold in the public market without restriction.

The market price of our common stock is volatile.

The trading price of our common stock and the price at which we may sell common
stock in the future are subject to large fluctuations in response to any of the
following:

o limited trading volume in our common stock;

o quarterly variations in operating results;

o our involvement in litigation;

o general financial market conditions;

o the prices of natural gas and oil;

o announcements by us and our competitors;

o our liquidity;

o our ability to raise additional funds;

o changes in government regulations; and

o other events.

We do not anticipate paying dividends on our common stock in the near future.

We have not paid any dividends in the past and do not intend to pay cash
dividends on our common stock in the foreseeable future. We currently intend to
retain any earnings for the future operation and development of our business,
including exploration, development and acquisition activities. Any future
dividend payments will be restricted by the terms of our credit agreement and
our senior subordinated notes.

Certain anti-takeover provisions may affect your rights as a shareholder.

Our articles of incorporation authorize our board of directors to set the terms
of and issue additional preferred stock without shareholder approval. Our board
of directors could use the preferred stock as a means to delay, defer or prevent
a takeover attempt that a shareholder might consider to be in our best interest.
In addition, our outstanding Series B preferred stock, our senior credit
facility and our senior subordinated notes contain terms that may restrict our
ability to enter into change of control transactions, including requirements to
redeem or repay the Series B preferred stock, our credit facility and our senior
subordinated notes upon a change in control. These provisions, along with
specified provisions of the Texas Business Corporation Act and our articles of
incorporation and bylaws, may discourage or impede transactions involving actual
or potential changes in our control, including transactions that otherwise could
involve payment of a premium over prevailing market prices to holders of our
common stock.

Management's Discussion and Analysis of Financial Condition
and Results of Operations

You should read this discussion together with the consolidated financial
statements and other financial information included in our filings with the SEC.
Unless explicitly stated otherwise, or the context otherwise requires, all
references in this section to planned capital expenditures or planned drilling
activities assume the completion of the offering described in our prospectus
dated February 5, 2004.

General Overview

For the year ended December 31, 2002 and for the first nine months of 2003, we
achieved record drilling success rates, levels of production, natural gas and
oil revenues and net income available to shareholders for any twelve- and
nine-month period, respectively, in our history.

In 2002, we produced a record 7.2 Bcfe compared to 5.4 Bcfe in 2001. In the
first nine months of 2003, we produced 5.6 Bcfe, a record for any nine-month
period and an improvement over production of 5.1 Bcfe in the first nine months
of 2002. These increasing production levels in 2003 are due to our drilling
success.

In 2002, we drilled 20 wells (7.1 net) in the onshore Gulf Coast with a success
rate of 85% compared to a success rate of 80% in 2001, in which we drilled 25
wells (7.6 net). During the first nine months of 2003, we drilled 22 wells (8.2
net) with a success rate of 86%. Between January 1, 2001 and September 30, 2003,
93% of our wells drilled were exploratory and 7% were development. In 2003, we
drilled 38 wells, with 32 wells in the onshore Gulf Coast area.

In 2002, both our revenues and our net income increased: our natural gas and oil
revenues reached a record level at $26.8 million, and our net income available
to common shareholders was $4.2 million, or $0.30 and $0.26 per basic and fully
diluted share, respectively. In 2001, our natural gas and oil revenues were
$26.2 million and our net income available to common shareholders was $9.5
million, or $0.68 and $0.57 per basic and fully diluted share, respectively. In
the first nine months of 2003, our natural gas and oil revenues reached a
nine-month record level of $29.6 million, as compared to $17.6 million during
the first nine months of 2002. Our net income available to common shareholders
was $6.3 million in the 2003 nine-month period, or $0.45 and $0.38 per basic and
fully diluted share, respectively, as compared to $2.0 million, or $0.14 and
$0.12 per basic and fully diluted share, respectively, for the first nine months
of 2002. These increases in natural gas and oil revenues and net income were
attributable partly to the high levels of production discussed above and to high
commodity prices.

Our financial results are largely dependent on a number of factors, including
commodity prices. Commodity prices are outside of our control and historically
have been and are expected to remain volatile. Natural gas prices in particular
have remained volatile during the last few years. Commodity prices are affected
by changes in market demands, overall economic activity, weather, pipeline
capacity constraints, inventory storage levels, basis differentials and other
factors. As a result, we cannot accurately predict future natural gas, natural
gas liquids and crude oil prices, and therefore, cannot accurately predict
revenues. Including the effects of hedging activities, our realized natural gas
price was 31% lower and our realized oil price was 3% higher in 2002 than in
2001, and our realized natural gas price was 72% higher and our realized oil
price was 25% higher during the first nine months of 2003 than in the comparable
period in 2002.

We have continued to reinvest a substantial portion of our operating cash flows
into funding our drilling program and increasing the amount of 3-D seismic data
available to us. In 2004, we expect capital expenditures to be approximately $40
to $45 million, as compared to $25.3 million in 2003. In the first nine months
of 2003, we incurred $20.4 million in capital and exploration expenditures, as
compared to $20.9 million in the first nine months of 2002.

At September 30, 2003, our debt-to-total capitalization ratio was 31.0%, an
improvement from 36.5% at the end of 2002. This improvement was primarily the
result of the increased shareholders' equity from net income, a decrease in the
outstanding debt on the Hibernia credit facility and a reduction in our
nonrecourse note to Rocky Mountain Gas, Inc., both as described under
"--Liquidity and Capital Resources--Financing Arrangements."

During the second quarter of 2001, we acquired interests in natural gas and oil
leases in Wyoming and Montana in areas prospective for coalbed methane and
subsequently began to drill wells on those leases. During the second quarter of
2003, we contributed our interests in certain of these leases to a newly formed
company, Pinnacle Gas Resources, Inc. (Pinnacle). In exchange for this
contribution, we received 37.5% of the common stock of Pinnacle and options to
purchase additional Pinnacle common stock. We account for our interest in
Pinnacle using the equity method. As a result, our contributed operations and
reserves are no longer directly reflected in our financial statements. We
retained our interests in approximately 189,000 gross acres in the Castle Rock
project area in

Montana and the Oyster Ridge project area in Wyoming. See "Business and
Properties--Pinnacle Transaction" for a description of this transaction. Our
discussion of future drilling and capital expenditures does not reflect
operations conducted through Pinnacle.

Since our initial public offering, we have grown primarily through the
exploration of properties within our project areas although we consider
acquisitions from time to time and may in the future complete acquisitions that
we find attractive.

Recent Developments

Fourth Quarter 2003 Operating Results

During the fourth quarter of 2003, in our core areas in the onshore Gulf Coast
of Texas and Louisiana, we participated in the drilling of 12 gross exploratory
wells, 11 of which were successful. Also during the quarter, in our Barnett
Shale Project we participated in the drilling of two gross (one net) exploratory
wells and two gross (one net) development wells, all of which were successful.
On a combined basis for these two areas, we had a 94% success rate for the
quarter.

Production during the fourth quarter of 2003 was estimated at 1.85 Bcfe,
bringing our 2003 annual production to an estimated record level of 7.5 Bcfe, an
increase of 3.5% over our 2002 production level. Approximately 72% of our
production during the fourth quarter of 2003 and 64% of our production in the
full year 2003 was natural gas. We estimate that fourth quarter 2003 sales
prices, including the effect of hedging activities, averaged approximately $4.78
per Mcf and $29.61 per barrel. Based on our preliminary reserve estimates, we
believe that in 2003 we more than replaced our production with proved reserve
additions from our drilling activities.

Potential Barnett Shale Acquisition

We have entered into negotiations with a private company to purchase working
interests and acreage in certain oil and gas wells located in Denton County,
Texas in the Newark East Field in the Barnett Shale trend. This potential
acquisition, with an expected purchase price of $7.2 million, includes
non-operated working interests ranging from 12.5% to 45% over 3,800 acres. As of
January 1, 2004, the 14 producing wells (5.0 net) that would be included in the
acquisition were producing a net 1.4 MMcf/d with another five wells (1.3 net)
waiting for pipeline hook-up. We expect the undeveloped acreage to contribute
additional drilling locations, 13 of which will target proved undeveloped
reserves and 18 of which will be exploratory.

We expect that we would finance the acquisition with our current revolving
credit facility or, alternatively, with a new project financing facility that we
would seek to obtain. We currently have targeted a closing date of February 16,
2004 for the acquisition. There can be no assurance that the transaction
described above will be completed on the terms or timing described above or at
all. Regardless of whether this transaction is completed, we intend to continue
to pursue growth opportunities in this geologic trend.

Results of Operations

The following table summarizes production volumes, average sales prices and
operating revenues for our natural gas and oil operations for the years ended
December 31, 2000, 2001 and 2002 and for the nine months ended September 30,
2002 and 2003:

Nine Months
% Increase % Increase Ended
Year Ended Year Ended (Decrease) Year Ended (Decrease) September 30,
December 31, December 31, from 2000 December 31, from 2001 ---------------------
2000 2001 to 2001 2002 to 2002 2002 2003
------------ ------------ ---------- ------------ ---------- --------- ---------

Production volumes
Oil and condensate
(MBbls)................ 198 160 (20)% 401 151% 261 363
Natural gas (MMcf)...... 5,460 4,432 (19) 4,801 8 3,543 3,432
Natural gas equivalent
(MMcfe).............. 6,651 5,390 (19) 7,207 34 5,109 5,607
Average sales
prices(1)
Oil and condensate
(MBbls)............... $ 27.81 $ 24.28 (13)% $ 24.94 3% $ 23.34 $ 29.08
Natural gas (MMcf)..... 3.90 5.04 (29) 3.50 (31) 3.24 5.56
Operating revenues (in
thousands)............. $ 26,834 $ 26,226 (2)% $ 26,802 2% $ 17,559 $ 29,615

- ----------

(1) Includes impact of hedging activities.

Nine Months Ended September 30, 2003 Compared to the Nine Months Ended September
30, 2002

Natural gas and oil revenues for the nine months ended September 30, 2003
increased 69% to $29.6 million from $17.6 million for the same period in 2002.
Production volumes for natural gas during the nine months ended September 30,
2003 decreased 3% to 3.4 Bcf from 3.5 Bcf for the same period in 2002. Average
natural gas prices increased 72% to $5.56 per Mcf in the first nine months of
2003 from $3.24 per Mcf in the same period in 2002. Production volumes for oil
in the nine months ended September 30, 2003 increased 39% to 363 MBbls from 261
MBbls for the same period in 2002. Average oil prices increased 25% to $29.08
per barrel in the first nine months of 2003 from $23.34 per barrel in the same
period in 2002. The increase in oil production was due primarily to the
commencement of production at six wells offset by the natural decline in
production from other wells. The decrease in natural gas production was
primarily due to a workover at one well and natural production declines in other
wells offset by the commencement of production at new wells. Natural gas and oil
revenues include the impact of hedging activities as discussed below under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Critical Accounting Policies and Estimates--Derivative Instruments
and Hedging Activities."

Natural gas and oil operating expenses for the nine months ended September 30,
2003 increased 38% to $5.1 million from $3.7 million for the same period in 2002
primarily due to higher severance taxes and other operating costs associated
with the addition of new production. Operating expenses per equivalent unit
increased 25% to $0.90 per Mcfe in the first nine months of 2003 from $0.72 per
Mcfe in the same period in 2002 primarily as a result of the natural decline in
production on older wells and the addition of a relatively higher cost new well.

General and administrative (G&A) expense for the nine months ended September 30,
2003 increased 43% to $4.3 million from $3.0 million for the same period in
2002. The increase in G&A expense was due primarily to employee severance costs
and the addition of contract staff to handle increased drilling and production
activities, higher compensation costs and higher insurance.

Depreciation, depletion and amortization (DD&A) expense for the nine months
ended September 30, 2003 increased 19% to $8.7 million from $7.3 million for the
same period in 2002. This increase was due to increased production and
additional seismic and drilling costs.

Interest income for the nine months ended September 30, 2003 increased to
$50,000 from $44,000 in the first nine months of 2002 primarily as a result of
higher cash balances during the first quarter of 2003. Capitalized interest was
$2.2 million in the first nine months of 2003 and 2002.

Provision for income taxes increased to $4.1 million for the nine months ended
September 30, 2003 from $1.5 million for the same period in 2002 as a result of
higher taxable income based on the factors described above.

We adopted Financial Accounting Standards Board (FASB) Statement of Financial
Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement
Obligations," effective January 1, 2003 and recorded a cumulative effect of
change in accounting principle of $0.1 million in the nine months ended
September 30, 2003.

Income before income taxes for the nine months ended September 30, 2003
increased to $11.1 million from $3.9 million in the same period in 2002. Net
income for the nine months ended September 30, 2003 increased to $6.3 million
from $2.0 million for the same period in 2002 primarily as a result of the
factors described above.

Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001

Our natural gas and oil revenues for 2002 increased 2% to $26.8 million from
$26.2 million in 2001. Production volumes for natural gas in 2002 increased 8%
to 4,801 MMcf from 4,432 MMcf in 2001, due primarily to the commencement of
production at five wells, offset by natural production declines in other wells,
primarily from the initial Matagorda County Project wells. Realized average
natural gas prices decreased 31% to $3.50 per Mcf in 2002 from $5.04 per Mcf in
2001.

Production volumes for oil in 2002 increased 151% to 401 MBbls from 160 MBbls in
2001, due primarily to the commencement of production at four wells, offset by
natural production declines in other older wells. Natural gas and oil revenues
include the impact of hedging activities as discussed below under "--Critical
Accounting Policies and Estimates--Derivative Instruments and Hedging
Activities." Average oil prices increased 3% to $24.94 per Bbl in 2002 from
$24.28 per Bbl in 2001.

Natural gas and oil operating expenses for 2002 increased 19% to $4.9 million
from $4.1 million in 2001, primarily as a result of the addition of new natural
gas and oil wells drilled and completed since December 31, 2001 and higher ad
valorem taxes. Operating expenses per equivalent unit in 2002 decreased to $0.68
per Mcfe from $0.77 per Mcfe in 2001. The per-unit cost decreased primarily as a
result of the addition of higher-production-rate, lower-cost-per-unit wells,
offset by an increase in ad valorem taxes and decreased production of natural
gas as wells naturally declined.

DD&A expense for 2002 increased 63% to $10.6 million from $6.5 million in 2001.
This increase was due primarily to increased production and the additional
seismic and drilling costs added to the proved property cost base.

G&A expense for 2002 increased 24% to $4.1 million from $3.3 million for 2001.
The increase in G&A expense was due primarily to the addition of contract staff
to handle increased drilling and production activities and higher insurance
costs.

Interest income for 2002 decreased to $0.1 million from $0.3 million in 2001
primarily as a result of lower interest rates during 2002. Capitalized interest
decreased to $3.1 million in 2002 from $3.2 million in 2001 primarily due to
lower interest costs during 2002.

Provision for income taxes decreased to $2.8 million in 2002 from $5.3 million
in 2001.

Dividends and accretion of discount on preferred stock increased to $0.6 million
in 2002 from none in 2001 as a result of our sale of preferred stock in the
first quarter of 2002.

Net income for 2002 decreased to $4.8 million from $9.5 million in 2001
primarily as a result of the factors described above.

Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000

Natural gas and oil revenues for 2001 decreased 2% to $26.2 million from $26.8
million in 2000. Production volumes for natural gas in 2001 decreased 19% to
4,432 MMcf from 5,461 MMcf in 2000, due primarily to the sale of a project
during 2000 and the natural decline in production at certain wells, offset by
the commencement of production at other wells. Realized average natural gas
prices increased 29% to $5.04 per Mcf in 2001 from $3.90 per Mcf in 2000.

Production volumes for oil in 2001 decreased 20% to 160 MBbls from 199 MBbls in
2000 due to the natural decline in production at certain wells, offset by the
commencement of production of another well. Natural gas and oil revenues include
the cash effect of hedging activities as discussed below under "Critical
Accounting Policies and Estimates--Derivative Instruments and Hedging
Activities." Average oil prices decreased 13% to $24.28 per Bbl in 2001 from
$27.81 per Bbl in 2000.

Natural gas and oil operating expenses for 2001 decreased 16% to $4.1 million
from $4.9 million in 2000, primarily as a result of the lower production taxes
and the implementation of cost reduction measures in fields with decreased
production. Operating expenses per

equivalent unit in 2001 increased to $0.77 per Mcfe from $0.74 per Mcfe in 2000.
The per-unit cost increased primarily as a result of an increase in severance
taxes and decreased production of natural gas as wells naturally declined.

Depreciation, depletion and amortization expense for 2001 decreased 9% to $6.5
million from $7.2 million in 2000. This decrease was primarily due to the
seismic and drilling costs added to the proved property cost base.

G&A expense for 2001 increased 6% to $3.3 million from $3.1 million for 2000.
The increase in G&A expense was due primarily to the addition of staff to handle
increased drilling and production activities and also to stock option
compensation expense, a noncash charge resulting from a decrease during 2001 and
an increase during the last six months of 2000 in the stock price underlying the
stock options that we repriced in February 2000.

Interest expense, net of amounts capitalized, for 2001 decreased 47% to $6,873
from $13,003 in 2000.

Provision for income taxes increased to $5.3 million in 2001 from $1.0 million
in 2000 as a result of an adjusted noncash valuation allowance during 2000 on
net operating loss carryforwards expected to be realized that resulted in a
deferred income tax benefit adjustment of $3.6 million, which reduced our
effective tax rate to 8% in 2000.

Other income for the year ended December 31, 2001 included a gain on the sale of
an investment in Michael Petroleum Corporation of $3.9 million, offset by:

o a charge and related legal expenses of $1.4 million in respect of the
final settlement of litigation with BNP Petroleum Corporation; and

o a noncash valuation allowance of $0.8 million relating to certain hedge
arrangements with Enron North America Corp.

Net income for 2001 decreased to $9.5 million from $12.0 million in 2000 as a
result of the factors described above.

Liquidity and Capital Resources

We have made and expect to make capital expenditures in excess of our net cash
flows provided by operating activities. We will require additional sources of
financing to fund drilling expenditures on properties we currently own and to
fund leasehold costs and geological and geophysical costs on our exploration
projects.

While we believe that current cash balances and anticipated cash provided by
operating activities for 2004 will provide sufficient capital to carry out our
exploration plans for that time period, our management continues to seek
financing for our capital program from a variety of sources. We may not be able
to obtain additional financing on terms that would be acceptable to us. If we
cannot obtain acceptable financing, we anticipate that we may be required to
limit or defer our planned natural gas and oil exploration and development
program, thereby adversely affecting the recoverability and ultimate value of
our natural gas and oil properties. See "Risk Factors--We have substantial
capital requirements that, if not met, may hinder operations."

Our primary sources of liquidity have included funds generated by operations,
proceeds from the issuance of various securities, including our common stock,
preferred stock and warrants, and borrowings, primarily under revolving credit
facilities and through the issuance of senior subordinated notes.

Cash flows provided by operating activities were $17.1 million, $24.0 million
and $19.9 million for 2000, 2001 and 2002, respectively, and $12.3 million and
$23.5 million for the nine months ended September 30, 2002 and 2003,
respectively. The increase in cash flows provided by operating activities in
2003 as compared to 2002 was due primarily to additional revenue resulting from
higher natural gas and oil prices and higher oil and condensate production,
offset by an increase in our working capital during the first nine months of
2003.

Estimated maturities of long-term debt are $3.9 million in 2004, $8.5 million in
2005 and the remainder in 2007.

Capital Expenditures

We estimate capital expenditures in 2003 to have been approximately $25.3
million, of which we used $4.9 million to fund 3-D seismic surveys and acquire
land and $20.4 million for drilling activities in our project areas. We have
drilled 38 wells (10.2 net) in

2003. In 2004, we expect capital expenditures to be approximately $40 to $45
million (a 58 to 78% increase over our expected 2003 capital expenditures). We
expect to drill 38 wells in 2004 (18.5 net), 30 of which we expect to operate.
The actual number of wells drilled and the amount of capital expended depends on
available financing, cash flow, availability and cost of drilling rigs, land and
partner issues and other factors.

We have continued to reinvest a substantial portion of our cash flows into
increasing our 3-D prospect portfolio, improving our 3-D seismic interpretation
technology and funding our drilling program. Capital expenditures were $20.4
million for the nine months ended September 30, 2003, which included $2.2
million of capitalized interest and general and administrative costs. Our
drilling efforts in the onshore Gulf Coast region resulted in the successful
completion of 17 wells (6.0 net) in 2002 and 19 wells (5.2 net) in the nine
months ended September 30, 2003. Of the 77 coalbed methane wells (29.0 net) we
drilled or acquired in the Rocky Mountain region through September 30, 2003, 24
wells (8.0 net) are currently producing and 53 wells (21.0 net) are in various
stages of evaluation.

Pursuant to an exchange election provided in a letter agreement dated May 1,
2001, with some of the participants in the Carrizo 2001 Seismic and Acreage
Program, we issued to those participants who exercised their election
approximately 168,000 shares of our common stock in exchange for the
participants' interest in that program, including interests in approximately 350
square miles of 3-D seismic data and working interests in specified producing
properties. The exchange transaction was effective on October 10, 2003 and was
valued at approximately $1.2 million using the closing price of our stock on
that date.

Financing Arrangements

Hibernia Credit Facility

On May 24, 2002, we entered into a credit agreement with Hibernia National Bank
that matures on January 31, 2005, and repaid our prior facility with Compass
Bank. The Hibernia credit facility provides a revolving line of credit of up to
$30.0 million. It is secured by substantially all of our producing assets.

The borrowing base will be determined by Hibernia National Bank at least
semi-annually on each October 31 and April 30. The borrowing base as of January
31, 2004 was $16.0 million, of which $7.0 million was drawn as of that date.
Each party to the credit agreement can request one unscheduled borrowing base
determination subsequent to each scheduled determination. The borrowing base
will at all times equal the borrowing base most recently determined by Hibernia
National Bank, less quarterly borrowing base reductions required subsequent to
such determination.

If the outstanding principal balance of the Hibernia credit facility exceeds the
borrowing base at any time, we have the option within 30 days to take any of the
following actions, either individually or in combination: make a lump sum
payment curing the deficiency, pledge additional collateral sufficient in
Hibernia National Bank's opinion to increase the borrowing base and cure the
deficiency or begin making equal monthly principal payments that will cure the
deficiency within the ensuing six-month period. Those payments would be in
addition to any payments that may come due as a result of the quarterly
borrowing base reductions. Otherwise, any unpaid principal or interest will be
due at maturity.

The interest rate applicable to incremental borrowings under this credit
facility will be, at our option, a eurodollar rate or a base rate, in each case
plus an applicable margin based upon borrowing levels.

We are subject to specified covenants under the terms of the Hibernia credit
facility, including but not limited to maintaining a minimum current ratio, a
minimum quarterly debt services coverage ratio and a minimum level of
shareholders' equity. The Hibernia credit facility also places restrictions on
additional indebtedness, dividends to shareholders, liens, investments, mergers,
acquisitions, asset dispositions, asset pledges and mortgages, change of
control, repurchase or redemption for cash of our common or preferred stock,
speculative commodity transactions and other matters.

Rocky Mountain Gas Note

In June 2001, our subsidiary CCBM issued a nonrecourse promissory note in the
amount of $7.5 million to Rocky Mountain Gas, Inc. (RMG) as consideration for
specified interests in natural gas and oil leases held by RMG in Wyoming and
Montana. At September 30, 2003, the outstanding principal balance of this note
was $1.0 million.

Capital Leases

We have entered into capital lease agreements, each secured by specified
production equipment, with payment obligations of $0.4 million in 2004, $0.3
million in 2005 and $0.1 million in 2006.

Senior Subordinated Notes and Related Securities

In December 1999, we sold $22.0 million principal amount of 9% Senior
Subordinated Notes due 2007. The senior subordinated notes were sold at a
discount of $0.7 million, which is being amortized over the life of the notes.
Interest is payable quarterly beginning March 31, 2000. We may elect, until
December 2004, to increase the amount of the senior subordinated notes for up to
60% of the interest rate which would otherwise be payable in cash. As of
December 31, 2002 and September 30, 2003, the outstanding balance of the senior
subordinated notes had been increased by $3.9 million and $5.0 million,
respectively, for such interest paid in kind.

Concurrently with the sale of the senior subordinated notes, we sold 3,636,364
shares of our common stock at a price of $2.20 per share and warrants expiring
in December 2007 to purchase up to 2,760,189 shares of our common stock at an
exercise price of $2.20 per share. For accounting purposes, the warrants were
valued at $0.25 each. We sold the warrants to CB Capital Investors, L.P. (now
JPMorgan), Mellon, Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P.
Hamilton.

We are subject to specified covenants under the terms of the securities purchase
agreement related to the senior subordinated notes, including but not limited to
maintenance of a specified tangible net worth and a debt service coverage ratio
and limits on our ability to incur indebtedness and to engage in certain
transactions and activities.

Series B Preferred Stock

In February 2002, we sold 60,000 shares of our Series B preferred stock and
warrants to purchase 252,632 shares of our common stock for an aggregate
purchase price of $6.0 million. We sold $4.0 million of Series B preferred stock
and 168,422 warrants to Mellon and $2.0 million of Series B preferred stock and
84,210 warrants to Steven A. Webster, our Chairman of the Board. The investors
may convert the Series B preferred stock into common stock at a conversion price
of $5.70 per share, subject to adjustment for transactions including issuance of
common stock or securities convertible into or exercisable for common stock at
less than the conversion price of the Series B preferred stock. The approximate
$5.8 million net proceeds of this financing were used to fund our ongoing
exploration and development program and for general corporate purposes.

Dividends on the Series B preferred stock are payable either in cash at a rate
of 8% per annum or, at our option, by payment in kind of additional shares of
the Series B preferred stock at a rate of 10% per annum. At December 31, 2002
and September 30, 2003, the outstanding balance of the Series B preferred stock
had been increased by $0.5 million (5,294 shares) and $0.9 million (8,559
shares), respectively, for dividends paid in kind. At September 30, 2003, we had
accrued a dividend of $0.2 million that we paid on December 31, 2003. In
addition to the foregoing, if we declare a cash dividend on our common stock,
the holders of shares of Series B preferred stock are entitled to receive for
each share of Series B preferred stock a cash dividend in the amount of the cash
dividend that would be received by a holder of the common stock into which that
share of Series B preferred stock is convertible on the record date for the cash
dividend. Unless all accrued dividends on the Series B preferred stock shall
have been paid and a sum sufficient for the payment thereof set apart, no
distributions may be paid on any Junior Stock (as defined in the Statement of
Resolutions for the Series B preferred stock) (which includes the common stock),
and no redemption of any junior stock shall occur other than subject to
specified exceptions.

We must redeem the Series B preferred stock at any time after the third
anniversary of its initial issuance upon request from any holder at a price per
share equal to Purchase Price/Dividend Preference (as defined below). We may
redeem the Series B preferred stock after the third anniversary of its issuance
at a price per share equal to the Purchase Price/Dividend Preference and, prior
to that time, at varying preferences to the Purchase Price/Dividend Preference.
"Purchase Price/Dividend Preference" is defined to mean, generally, $100 plus
all cumulative and accrued dividends.

In the event of any dissolution, liquidation or winding up or specified mergers
or sales or other disposition by us of all or substantially all of our assets,
the holder of each share of Series B preferred stock then outstanding will be
entitled to be paid per share of Series B preferred stock, prior to the payment
to holders of our common stock and out of our assets available for distribution
to our shareholders, the greater of:

o $100 in cash plus all cumulative and accrued dividends; and

o in specified circumstances, the "as-converted" liquidation distribution,
if any, payable in such liquidation with respect to each share of common
stock.

Upon the occurrence of specified events constituting a "Change of Control" (as
defined in the Statement of Resolutions), we must make an offer to each holder
of Series B preferred stock to repurchase all of that holder's Series B
preferred stock at an offer price per share of Series B preferred stock in cash
equal to 105% of the Change of Control Purchase Price, which is generally
defined to mean $100 plus all cumulative and accrued dividends.

The warrants issued in connection with the Series B preferred stock have a
five-year term, entitle the holders to purchase up to 252,632 shares of our
common stock at a price of $5.94 per share, subject to adjustment, and are
exercisable at any time after issuance. For accounting purposes, the warrants
are valued at $0.06 per warrant.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing natural gas
and oil prices. If the price of natural gas and oil increases (decreases), there
could be a corresponding increase (decrease) in the operating cost we are
required to bear for operations, as well as an increase (decrease) in revenues.
Inflation has had a minimal effect on us.

Critical Accounting Policies and Estimates

The following summarizes several of our critical accounting policies. See a
complete list of significant accounting policies in Note 2 to the Consolidated
Financial Statements.

Use of Estimates

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from these estimates. The use of these estimates
significantly affects natural gas and oil properties through depletion and the
full cost ceiling test, as discussed in more detail below.

Natural Gas and Oil Properties

We account for investments in natural gas and oil properties using the full-cost
method of accounting. All costs directly associated with the acquisition,
exploration and development of natural gas and oil properties are capitalized.
These costs include lease acquisitions, seismic surveys, and drilling and
completion equipment. We proportionally consolidate our interests in natural gas
and oil properties. We capitalized compensation costs for employees working
directly on exploration activities of $0.7 million and $1.1 million for the nine
months ended September 30, 2002 and 2003, respectively. We expense maintenance
and repairs as they are incurred.

We amortize natural gas and oil properties based on the unit-of-production
method using estimates of proved reserve quantities. We do not amortize
investments in unproved properties until proved reserves associated with the
projects can be determined or until these investments are impaired. We
periodically evaluate, on a property-by-property basis, unevaluated properties
for impairment. If the results of an assessment indicate that the properties are
impaired, we add the amount of impairment to the proved natural gas and oil
property costs to be amortized. The amortizable base includes estimated future
development costs. The depletion rate per thousand cubic feet equivalent (Mcfe)
for the nine months ended September 30, 2002 and 2003 was $1.40 and $1.51,
respectively.

We account for dispositions of natural gas and oil properties as adjustments to
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. We have not had any transactions that significantly alter that
relationship.

The net capitalized costs of proved natural gas and oil properties are subject
to a ceiling test, which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net revenues from proved reserves
(the NPV) based on current economic and operating conditions (with reserve
estimates calculated using SEC guidelines). This test is performed after any
impairment of unproved properties are added to the property costs to amortize as
discussed above. We include asset retirement obligation costs, liabilities and
related discounted cash flows in our ceiling test calculations. If net
capitalized costs exceed this limit, we charge the

excess to operations through depreciation, depletion and amortization. No
write-down of our natural gas and oil assets was necessary for the nine months
ended September 30, 2002 or 2003. In concert with this determination, a price
sensitivity study also indicated that a 20% increase in commodity prices at
September 30, 2003 would have increased our NPV by approximately $15.8 million.
Conversely, a 20% decrease in commodity prices at September 30, 2003 would have
reduced our NPV by approximately $18.4 million. This would have caused our
unamortized cost of proved natural gas and oil properties to exceed the cost
pool ceiling by approximately $18.1 million. Our aforementioned price
sensitivity and NPV is as of September 30, 2003 and, accordingly, does not
include any potential changes in reserves due to fourth quarter performance,
such as commodity prices, reserve revisions and drilling results, including
proved reserves associated with our recently discovered Shadyside #1 well. Based
on natural gas and oil prices in effect on December 31, 2001, the unamortized
cost of natural gas and oil properties exceeded the cost center ceiling. As
permitted by full cost accounting rules, improvements in pricing subsequent to
December 31, 2001 removed the necessity to record a write-down. Using prices in
effect on December 31, 2001 the pretax write-down would have been approximately
$0.7 million. Because of the volatility of natural gas and oil prices, we cannot
assure you that we will not experience a write-down in future periods.

Under the full cost method of accounting, the depletion rate is the current
period production as a percentage of the total proved reserves. Total proved
reserves include both proved developed and proved undeveloped reserves. The
depletion rate is applied to the net book value and estimated future development
costs to calculate the depletion expense.

We have a significant amount of proved undeveloped reserves, which are primarily
oil reserves. We had 41.9 Bcfe of proved undeveloped reserves, representing 66%
of our total proved reserves at December 31, 2002. These reserves are primarily
attributable to our Camp Hill properties we acquired in 1994. This ratio of
proved undeveloped reserves to total proved reserves and the producing
properties that have had an average productive life of 2.25 years since our
inception, compared to the average 10 year depletable life for the total proved
reserves, has resulted in a relatively low historical depletion rate and
depreciation expense. This has resulted in a capitalized cost basis associated
with producing properties being depleted over a longer period than the
associated production and revenue stream. It has also resulted in the build-up
of nondepleted capitalized costs associated with properties that have been
completely produced out.

We expect our low historical depletion rate to continue until the high level of
nonproducing reserves to total proved reserves is reduced and the life of our
proved developed reserves is extended through development drilling and/or the
significant addition of new proved producing reserves through acquisition or
exploration. If our level of total proved reserves and current prices were both
to remain constant, this continued build-up of capitalized costs increases the
probability of a ceiling test write-down.

We depreciate other property and equipment using the straight-line method based
on estimated useful lives ranging from five to 10 years.

SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and
Intangible Assets," were issued by the FASB in June 2001 and became effective
for us on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires
all business combinations initiated after June 30, 2001 to be accounted for
using the purchase method. Additionally, SFAS No. 141 requires companies to
disaggregate and report separately from goodwill certain intangible assets. SFAS
No. 142 establishes new guidelines for accounting for goodwill and other
intangible assets. Under SFAS No. 142, goodwill and certain other intangible
assets are not amortized but rather are reviewed annually for impairment.

Natural gas and oil mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves for both
undeveloped and developed leaseholds may have to be classified separately from
natural gas and oil properties as intangible assets on our consolidated balance
sheets. In addition, the disclosures required by SFAS No. 141 and 142 relative
to intangibles would be included in the notes to the consolidated financial
statements. Historically, we, like many other natural gas and oil companies,
have included these rights as part of natural gas and oil properties, even after
SFAS No. 141 and 142 became effective.

As it applies to companies like us that have adopted full cost accounting for
natural gas and oil activities, we understand that this interpretation of SFAS
No. 141 and 142 would only affect our balance sheet classification of proved
natural gas and oil leaseholds acquired after June 30, 2001 and all of our
unproved natural gas and oil leaseholds. We would not be required to reclassify
proved reserve leasehold acquisitions prior to June 30, 2001 because we did not
separately value or account for these costs prior to the adoption date of SFAS
No. 141. Our results of operations and cash flows would not be affected, since
these natural gas and oil mineral rights held under lease and other contractual
arrangements representing the right to extract natural gas and oil reserves
would continue to be amortized in accordance with full cost accounting rules.

As of September 30, 2003, December 31, 2002 and December 31, 2001, we had
leasehold costs incurred of approximately $3.4 million, $1.4 million and $1.4
million, respectively, that would be classified on our consolidated balance
sheet as "intangible leasehold costs" if we applied the interpretation discussed
above.

We will continue to classify our natural gas and oil mineral rights held under
lease and other contractual rights representing the right to extract such
reserves as tangible oil and gas properties until further guidance is provided.

Natural Gas and Oil Reserve Estimates

The reserve data included or incorporated in this exhibit are estimates prepared
by Ryder Scott Company and Fairchild and Wells, Inc., Independent Petroleum
Engineers. Reserve engineering is a subjective process of estimating underground
accumulations of hydrocarbons that cannot be measured in an exact manner. The
process relies on interpretation of available geologic, geophysical, engineering
and production data. The extent, quality and reliability of this data can vary.
The process also requires certain economic assumptions regarding drilling and
operating expense, capital expenditures, taxes and availability of funds. The
SEC mandates some of these assumptions such as natural gas and oil prices and
the present value discount rate.

Proved reserve estimates prepared by others may be substantially higher or lower
than our estimates. Because these estimates depend on many assumptions, all of
which may differ from actual results, reserve quantities actually recovered may
be significantly different than estimated. Material revisions to reserve
estimates may be made depending on the results of drilling, testing and rates of
production.

You should not assume that the present value of future net cash flows is the
current market value of our estimated proved reserves. In accordance with SEC
requirements, we have based our estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate.

Our rate of recording depreciation, depletion and amortization expense for
proved properties is dependent on our estimate of proved reserves. If these
reserve estimates decline, the rate at which we record these expenses will
increase.

Derivative Instruments and Hedging Activities

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement, as amended by SFAS No. 137
and SFAS No. 138, establishes standards of accounting for and disclosures of
derivative instruments and hedging activities. This statement requires all
derivative instruments to be carried on the balance sheet at fair value with
changes in a derivative instrument's fair value recognized currently in earnings
unless specific hedge accounting criteria are met. SFAS No. 133 was effective
for us beginning January 1, 2001 and we adopted it on that date. In accordance
with the current transition provisions of SFAS No. 133, we recorded a cumulative
effect transition adjustment of $2.0 million (net of related tax expense of $1.1
million) in accumulated other comprehensive income to recognize the fair value
of our derivatives designated as cash flow hedging instruments at the date of
adoption.

Upon entering into a derivative contract, we designate the derivative
instruments as a hedge of the variability of cash flow to be received (cash flow
hedge). Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income to the extent that the derivative is effective in
offsetting changes in the fair value of the hedged item. Any ineffectiveness in
the relationship between the cash flow hedge and the hedged item is recognized
currently in income. Gains and losses accumulated in other comprehensive income
associated with the cash flow hedge are recognized in earnings as natural gas
and oil revenues when the forecasted transaction occurs. All of our derivative
instruments at December 31, 2002 and September 30, 2003 were designated and
effective as cash flow hedges except for certain options described below under
"--Qualitative and Quantitative Disclosures About Market Risk--Derivative
Instruments and Hedging Activities."

When we discontinue hedge accounting because it is probable that a forecasted
transaction will not occur, we continue to carry the derivative on the balance
sheet at its fair value and immediately recognize in earnings any gains and
losses that were accumulated in other comprehensive income. In all other
situations in which we discontinue hedge accounting, we will carry the
derivative at fair value on our balance sheet and will recognize in future
earnings any future changes in its fair value.

We typically use fixed rate swaps and costless collars to hedge our exposure to
material changes in the price of natural gas and oil. We formally document all
relationships between hedging instruments and hedged items as well as our risk
management objectives and strategy for undertaking various hedge transactions.
This process includes linking all derivatives that are designated cash flow
hedges

to forecasted transactions. We also formally assess, both at the hedge's
inception and on an ongoing basis, whether the derivatives that are used in
hedging transactions are highly effective in offsetting changes in cash flows of
hedged transactions.

Our Board of Directors sets our hedging policy, including volumes, types of
instruments and counterparties, on a quarterly basis. Management implements
these policies through the execution of trades by either the President or Chief
Financial Officer after consultation with and concurrence by the other as well
as the Chairman of the Board. The master contracts with the authorized
counterparties identify the President and Chief Financial Officer as the only
company representatives authorized to execute trades. The Board of Directors
also reviews the status and results of hedging activities quarterly.

Income Taxes

Under SFAS No. 109, "Accounting for Income Taxes," we recognize deferred income
taxes at each year end for the future tax consequences of differences between
the tax bases of assets and liabilities and their financial reporting amounts
based on tax laws and statutory tax rates applicable to the periods in which the
differences are expected to affect taxable income. We establish valuation
allowances when necessary to reduce the deferred tax asset to the amount
expected to be realized.

Contingencies

We recognize liabilities and other contingencies upon our determination that it
is both probable that an asset has been impaired or that a liability has been
incurred and that the amount of such loss is reasonably estimable.

New Accounting Pronouncements

The FASB issued Interpretation 46, "Consolidation of Variable Interest Entities"
(FIN 46), in January 2003. FIN 46 requires the consolidation of specified types
of entities in which a company absorbs a majority of another entity's expected
losses, receives a majority of the other entity's expected residual returns, or
both, as a result of ownership, contractual or other financial interests in the
other entity. These entities are called "variable interest entities." The
provisions of FIN 46 were effective for us in the second quarter for new
transactions or entities formed in 2003 and in the third quarter for
transactions or entities formed prior to 2003.

If an entity is determined to be a "variable interest entity" (VIE), the entity
must be consolidated by the "primary beneficiary." The primary beneficiary is
the holder of the variable interests that absorbs a majority of the variable
interest entity's expected losses or receives a majority of the entity's
residual returns in the event no holder has a majority of the expected losses.
The primary beneficiary is determined based on projected cash flows at the
inception of the variable interests.

We have assessed whether to consolidate Pinnacle under FIN 46. Because Steven A.
Webster, our Chairman, is also a managing director of Credit Suisse First Boston
(whose interest in Pinnacle is described under "Business and
Properties--Pinnacle Transaction") we could be defined as the primary
beneficiary if the projected cash flows analysis indicated losses in excess of
the equity invested. The initial determination of whether an entity is a VIE is
to be reconsidered only when one or more of the following occur:

o the entity's governing documents or the contractual arrangements among
the parties involved change;

o the equity investment of some part thereof is returned to the investors,
and other parties become exposed to expected losses; or

o the entity undertakes additional activities or acquires additional
assets that increase the entity's expected losses.

We have determined that we should not consolidate Pinnacle under FIN 46 because
our current projected cash flow analysis of Pinnacle's operations at inception
indicates that Pinnacle is not a VIE. Accordingly, our investment in Pinnacle
has been recorded using the equity method of accounting.

The reclassification of investments in contributed properties resulting from the
transaction with Pinnacle is reflected on our balance sheet as of September 30,
2003 in accordance with the full cost method of accounting.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our major market risk exposure is the commodity pricing applicable to our
natural gas and oil production. Realized commodity prices received for such
production are primarily driven by the prevailing worldwide price for oil and
spot prices applicable to natural gas. Those prices are and are expected to
continue to be volatile. See "Risk Factors--Natural gas and oil prices are
highly volatile, and lower prices will negatively affect our financial results."
A 10% fluctuation in the price received for natural gas and oil production would
have an approximate $2.7 million and $3.0 million impact on our annual revenues
and operating income for the year ended December 31, 2002 and the nine months
ended September 30, 2003, respectively.

Derivative Instruments and Hedging Activities

To mitigate some of our commodity price risk, we engage periodically in certain
limited hedging activities but only to the extent of buying protection price
floors. We record the costs and any benefits derived from these price floors as
a reduction or increase, as applicable, in natural gas and oil sales revenue;
these reductions and increases were not significant for any of the years 2000,
2001 and 2002. The costs to purchase put options are amortized over the option
period. We do not hold or issue derivative instruments for trading purposes. We
realized losses related to these instruments of $0.4 million and $1.8 million
for the nine months ended September 30, 2002 and 2003, respectively.

As of December 31, 2002 and September 30, 2003, $0.4 million and $67,000, net of
tax of $0.2 million and $36,000, respectively, remained in accumulated other
comprehensive income related to the valuation of our hedging positions.

While the use of hedging arrangements limits the downside risk of adverse price
movements, it may also limit our ability to benefit from increases in the prices
of natural gas and oil. We enter into the majority of our hedging transactions
with two counterparties and have a netting agreement in place with those
counterparties. We do not obtain collateral to support the agreements but
monitor the financial viability of counterparties and believe our credit risk is
minimal on these transactions. Under these arrangements, payments are received
or made based on the differential between a fixed and a variable product price.
These agreements are settled in cash at expiration or exchanged for physical
delivery contracts. In the event of nonperformance, we would be exposed again to
price risk. We have some risk of financial loss because the price received for
the product at the actual physical delivery point may differ from the prevailing
price at the delivery point required for settlement of the hedging transaction.
Moreover, our hedging arrangements generally do not apply to all of our
production and thus provide only partial price protection against declines in
commodity prices. We expect that the amount of our hedges will vary from time to
time.

Our gas derivative transactions are generally settled based upon the average of
the reporting settlement prices on the NYMEX for the last three trading days of
a particular contract month. Our oil derivative transactions are generally
settled based on the average reporting settlement prices on the NYMEX for each
trading day of a particular calendar month. For the month of December 2002 a
$0.10 change in the price per Mcf of gas sold would have changed revenue by
$44,000. A $0.70 change in the price per barrel of oil would have changed
revenue by $41,000.

The table below summarizes our total natural gas production volumes subject to
derivative transactions during 2002 and the weighted average NYMEX reference
price for those volumes.

Natural Gas Swaps
-----------------------------

Volumes (MMBtu).............. 2,131,000
Average price ($/MMBtu)...... $ 3.20
Volumes (MMBtu).............. 183,000
Average price ($/MMBtu)
Floor...................... $ 3.50
Ceiling.................... $ 4.52

The table below summarizes our total crude oil production volumes subject to
derivative transactions during 2002 and the weighted average NYMEX reference
price for those volumes.

Crude Oil Swaps
-------------------------

Volumes (Bbls)........... 131,600
Average price ($/Bbls)... $ 25.52

Total oil purchased and sold under swaps and collars during the three months
ended September 30, 2002 and 2003 were 33,600 Bbls and 24,400 Bbls,
respectively. Total natural gas purchased and sold under swaps and collars
during the three months ended September 30, 2002 and 2003 was 731,000 MMBtu and
828,000 MMBtu, respectively. Total oil purchased and sold under swaps and
collars during the nine months ended September 30, 2002 and 2003 was 79,100 Bbls
and 150,700 Bbls, respectively. Total natural gas purchased and sold under swaps
and collars during the nine months ended September 30, 2002 and 2003 was
3,094,000 MMBtu and 2,187,000 MMBtu, respectively. We realized net losses under
these hedging arrangements of $0.1 million and $0.1 million for the three months
ended September 30, 2002 and 2003, respectively, and $0.4 million and $1.7
million for the nine months ended September 30, 2002 and 2003, respectively.

At December 31, 2002 and September 30, 2003, we had the following outstanding
hedge positions:

December 31, 2002
------------------------------------------------------------------------------------------
Contract Volumes
---------------------
Average Average Average
Quarter Bbls MMBtu Fixed Price Floor Price Ceiling Price
---------------------- -------- ---------- ----------- ----------- -------------

First Quarter 2003.... 27,000 $ 24.85
First Quarter 2003.... 36,000 $ 23.50 $ 26.50
First Quarter 2003.... 540,000 3.40 5.25
Second Quarter 2003... 27,300 24.85
Second Quarter 2003... 36,000 23.50 26.50
Second Quarter 2003... 546,000 3.40 5.25
Third Quarter 2003.... 552,000 3.40 5.25
Fourth Quarter 2003... 552,000 3.40 5.25

September 30, 2003
------------------------------------------------------------------------------------------
Contract Volumes
---------------------
Average Average Average
Quarter Bbls MMBtu Fixed Price Floor Price Ceiling Price
---------------------- -------- ---------- ----------- ----------- -------------

` Fourth Quarter 2003... 30,700 $ 30.22
Fourth Quarter 2003... 552,000 $ 3.40 $ 5.25
First Quarter 2004.... 546,000 4.10 7.00
Second Quarter 2004... 273,000 4.00 5.20
Third Quarter 2004.... 276,000 4.00 5.20
Fourth Quarter 2004... 93,000 4.00 5.20

From October 1, 2003 through January 12, 2004, we entered into swap arrangements
covering 51,500 Bbls of oil for November 2003 through May 2004 production with
an average fixed price of $30.33. We also entered into swap arrangements
covering 180,000 MMBtu of natural gas for January 2004 through February 2004
production with an average fixed price of $6.67 and costless collar arrangements
covering 825,000 MMBtu of natural gas production for April 2004 through December
2004 with a floor of $4.00 and a ceiling of $6.00.

In addition to the hedge positions above, during the second quarter of 2003, we
acquired call options to sell 6,000 MMBtu of natural gas per day for the period
July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for
approximately $119,000. We acquired these options to protect our cash position
against potential margin calls on certain natural gas derivatives due to large
increases in the price of natural gas. We expensed $119,000 related to the
expiration of these options during the nine months ended September 30, 2003.

Interest Rate Risk

Our floating rate debt exposes us to changes in interest rates. With regard to
our revolving credit facility, a 10% fluctuation in short-term interest rates
would have impacted our 2002 cash flow by approximately $32,000.

Financial Instruments and Debt Maturities

Our financial instruments consist of cash and cash equivalents, accounts
receivable, accounts payable, bank borrowing, senior subordinated notes payable
and Series B redeemable preferred stock. The carrying amounts of cash and cash
equivalents, accounts receivable and accounts payable approximate fair value due
to the highly liquid nature of these short-term instruments. The fair values of
the bank and vendor borrowings approximate the carrying amounts as of September
30, 2002 and 2003, and were determined based upon interest rates currently
available to us for borrowings with similar terms. Maturities of the debt are
$1.6 million in 2003, $3.9 million in 2004, $8.5 million in 2005 and the balance
in 2007.

Business and Properties

Unless explicitly stated otherwise, or the context otherwise requires, all
references in this section to planned capital expenditures or planned drilling
activities assume the completion of the offering described in our prospectus
dated February 5, 2004.

General

We are an independent energy company engaged in the exploration, development and
production of natural gas and oil. Our current operations are focused in proven,
producing natural gas and oil geologic trends along the onshore Gulf Coast in
Texas and Louisiana, primarily in the Miocene, Wilcox, Frio and Vicksburg
trends. Our other interests include properties in East Texas, a coalbed methane
investment in the Rocky Mountains and, recently, the Barnett Shale trend in
North Texas. Additionally, in 2003 we obtained licenses to explore in the U.K.
North Sea.

We have grown our production through our 3-D seismic-driven exploratory drilling
program. Our compound production growth rate for the period December 31, 1999
through December 31, 2003 on an annualized basis was 15%. From our inception
through December 31, 2003, we participated in the drilling of 295 wells (89.9
net) with a success rate of approximately 68% in our onshore Gulf Coast core
area. Exploratory wells accounted for 97% of the total wells we drilled. Our
total proved reserves as of December 31, 2002 were an estimated 63.2 Bcfe with a
PV-10 Value of $83.6 million. During 2002, we added 11.4 Bcfe to proved reserves
and produced 7.2 Bcfe.

As a main component of our business strategy, we have acquired licenses for over
8,700 square miles of 3-D seismic data for processing and evaluation. Since
2001, we have been able to increase the size of our 3-D seismic holdings in our
onshore Gulf Coast core area by approximately 75% to over 6,650 square miles, in
large part by taking advantage of very favorable pricing available for
nonproprietary data. One of our primary strengths is the experience of our
management and technical staff in the development, processing and analysis of
this 3-D seismic data to generate and drill natural gas and oil prospects. Our
technical and operating employees have an average of over 20 years of industry
experience, in many cases with major and large independent oil and gas
companies, including Shell Oil, ARCO, Conoco, Vastar Resources, Pennzoil and
Tenneco. Using our 3-D seismic database, our highly qualified technical staff is
continually adding to and refining our substantial inventory of drilling
locations.

We believe that our utilization of large-scale 3-D seismic surveys and related
technology allows us to create and maintain a multiyear inventory of
high-quality exploration prospects. As of September 30, 2003, we had 85,678
gross acres in Texas and Louisiana under lease or lease option, almost all of
which is covered by 3-D seismic data. On this leased acreage, we have identified
over 120 potential exploratory drilling locations, including over 45 additional
extension opportunities, depending on the success of our initial drilling
activities on those locations. The vast majority of our 3-D seismic data covers
productive geological trends in our onshore Gulf Coast core area, where we have
made 192 completions as a result of our utilization and evaluation of this data.

Business Strategy

Growth Through the Drillbit

Our objective is to create shareholder value through the execution of a business
strategy designed to capitalize on our strengths. Key elements of our business
strategy include:

o Grow Primarily Through Drilling. We are pursuing an active
technology-driven exploration drilling program. We generate exploration
prospects through geological and geophysical analysis of 3-D seismic and
other data. Our ability to successfully define and drill exploratory
prospects is demonstrated by our exploratory drilling success rate in
the onshore Gulf Coast core area of 73% over the last three years. We
are drilling or plan to drill approximately 36 wells (16.6 net) in the
onshore Gulf Coast area during 2004. We have budgeted approximately $40
to $45 million for capital expenditures in 2004, $39.4 million of which
we expect to use for drilling activities in the onshore Gulf Coast area.

o Focus on Prolific and Industry-Proven Trends. We focus our activities
primarily in the prolific onshore Gulf Coast area where our management,
our technical staff and our field operations teams have significant
prior experience. Although we have broadened our areas of operations to
include the Rocky Mountains and have purchased interests in the Barnett
Shale trend and the U.K. North Sea, we plan to focus a majority of our
near-term capital expenditures in the onshore Gulf Coast region, where
we believe our accumulated data and knowledge base provide a competitive
advantage.

o Aggressively Evaluate 3-D Seismic Data and Acquire Acreage to Maintain a
Large Drillsite Inventory. We have accumulated and continue to add to a
multiyear inventory of 3-D seismic and geologic data along the prolific
producing trends of our onshore Gulf Coast region. In 2003, we added
approximately 1,050 square miles of newly released 3-D and seismic data.
We believe our utilization of large-scale 3-D seismic surveys and
related technology provides us with the opportunity to maximize our
exploration success. As of September 30, 2003, we had accumulated
licenses for approximately 8,700 square miles of 3-D seismic data and
identified over 210 drilling locations and extension opportunities,
including 123 currently under lease or in the process of being leased.

o Maintain a Balanced Exploration Drilling Portfolio. We seek to balance
our drilling program between projects with relatively lower risk and
moderate potential and drilling prospects that have relatively higher
risk and substantial potential. We will continue to expand our
exploratory drilling portfolio, including possibly through acquisitions
with exploration potential.

o Manage Risk Exposure by Market Testing Prospects and Optimizing Working
Interests. We seek to limit our financial and operating risks by varying
our level of participation in drilling prospects with differing risk
profiles and by seeking additional technical input and economic review
from knowledgeable industry participants regarding our prospects.
Additionally, we rely on advanced technologies, including 3-D seismic
analysis, to better define geologic risks, thereby enhancing the results
of our drilling efforts. We also seek to operate our projects in order
to better control drilling costs and the timing of drilling.

o Retain and Incentivize a Highly Qualified Technical Staff. We employ 18
natural gas and oil professionals, including geophysicists,
petrophysicists, geologists, petroleum engineers and production and
reserve engineers, who have an average of over 20 years of experience.
This level of expertise and experience gives us a unique in-house
ability to apply advanced technologies to our drilling and production
activities. Our technical staff is granted stock options and
participates in an incentive bonus pool based on production resulting
from our exploratory successes.

Significant Areas

For the period from January 1, 2000 through December 31, 2002, we completed 61
wells (18.8 net) in 84 attempts for a success rate of 73%. Total exploration,
development and acquisition activities from January 1, 2000 through December 31,
2002 resulted in the addition of approximately 26.4 Bcfe, net to our interest.

We have budgeted approximately $40 to $45 million to drill approximately 36
wells (16.6 net) and to purchase and reprocess 3-D seismic surveys during 2004.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources." The following chart summarizes our
properties by region and focus area as of September 30, 2003 unless otherwise
noted.

Three Months
Ended September
30, 2003 At September 30, 2003
------------------ ------------------------------------------------
Average Productive 3-D Net
Daily Net % Wells Seismic Options/ Drilling Capital Expenditures
Production Nat. --------------------- Data Leased ------------------------------
(MMcfe/d) Gas Gross Net (Sq. Miles) Acres Estimated 2003 Budgeted 2004
---------- ----- --------- --------- ----------- ---------- -------------- -------------
(millions)

Onshore Gulf Coast:
Wilcox.............. 1.6 94 28 8.2 1,793 18,741 $ 5.9 $ 8.0
Frio/Vicksburg...... 8.4 58 137 43.3 2,102 8,615 6.1 11.0
Southeast Texas..... 8.8 78 11 3.8 900 3,729 2.9 11.1
South Louisiana..... 2.4 58 7 1.3 1,864 2,028 4.0 9.3
East Texas............ 0.4 -- 45 5.9 472 2,816 -- 0.5
Rocky Mountain........ -- -- -- -- 473 27,140 0.6 --
Barnett Shale......... -- -- -- -- -- 1,409 0.9 1.2
North Sea............. -- -- -- -- 153 209,613 -- --
Other Areas........... -- -- -- -- 980 -- -- --
---------- ----- --------- --------- ----------- ---------- -------------- -------------
Total................. 21.6 68 228 62.5 8,737 274,091 $ 20.4 $ 41.1
========== ===== ========= ========= =========== ========== ============== =============

Core Project Area--The Onshore Gulf Coast Region

The onshore Gulf Coast region is a prolific proven hydrocarbon trend with
complex structural and stratigraphic targets that are optimally explored through
the use of 3-D seismic data. We believe our approximately 6,650 square miles of
data located in key producing onshore Gulf Coast trends is comparable to the
volume of data some major oil and gas companies hold for this area. Of this
volume, approximately 2,870 square miles of 3-D seismic data was acquired or
reprocessed in the last 18 months. Our exploration

staff, with an average of over 20 years experience, analyzes the data seeking to
provide multiple opportunities which we prioritize and add to our onshore Gulf
Coast exploration prospect portfolio.

Wilcox Trend

We have licenses for approximately 1,800 square miles of 3-D seismic data and
18,741 acres of leasehold in the Wilcox trend in Texas. From January 1, 2000
through December 31, 2003, we drilled and completed 32 wells (9.8 net) on 40
attempts in this area. We invested $5.9 million to drill and complete eight
wells (2.3 net) in the Texas Wilcox area in 2003 and expect to devote
approximately $8.0 million to drill seven wells (3.9 net) in this area in 2004.
Currently, we have identified over 30 exploratory drilling locations, with an
additional 22 potential extension opportunities, in the Wilcox trend over which
we have licenses for 3-D seismic data and leased acreage. Approximately 18 of
the 30 exploratory locations we have identified are relatively lower risk and
generally shallower with the remainder being relatively higher risk and deeper
with greater upside potential.

Greater Cabeza Creek. Since January 1, 2000, our exploration efforts in the
Wilcox area largely have been focused in the greater Cabeza Creek area centered
in Goliad, Lavaca and Dewitt Counties, where we have licenses for over 950
square miles of 3-D seismic data and 5,700 net acres of leasehold. From January
1, 2000 through December 31, 2003, we have drilled 14 wells (7.1 net) with an
86% success rate in this area. Our most notable discovery was the Riverdale
Field in 2001, where we have 68.8% working interest. The Riverdale Field was
delineated with two extension wells. The greater Cabeza Creek area continues to
be a primary focus area in the middle and lower Wilcox intervals which have
relatively higher potential and risk. We have a significant acreage position to
either explore ourselves or sell to third parties while retaining a promoted
interest.

Texas Frio/Vicksburg Trend Area

This combined trend area sometimes overlaps but is generally closer to the Texas
Gulf Coast than the Wilcox areas discussed above. In any particular target or
prospect in this area, the Frio is the shallower formation, above the deeper
Vicksburg and still deeper Yegua formations. We have licenses for a total of
2,100 miles of 3-D seismic data and 8,615 net leasehold acres over this trend.
Since 1999, we have focused primarily in Matagorda County, the location of the
Providence Field, and in Brooks County, the location of the Encinitas Field.

Currently, we have identified over 23 exploratory drilling locations with an
additional 12 potential extension opportunities (depending on the success of our
initial drilling activities on those locations) in the Frio/ Vicksburg trend
area over which we have licenses for 3-D seismic data and leased acreage.
Approximately 15 of the 23 exploratory locations we have identified are
relatively lower risk and generally shallower with the remaining eight being
relatively higher risk and deeper with greater upside potential.

From January 1, 2000 through December 31, 2003, we have drilled and completed 38
wells (10.0 net) in 45 attempts in this trend. We invested $6.1 million to drill
and complete 16 wells (3.4 net) in the Frio/ Vicksburg trend area in 2003 and
expect to devote approximately $11.0 million to drill 12 wells (5.0 net) in this
area in 2004.

Providence Field. We have licenses for over 540 square miles of 3-D data
(including 450 square miles of newly reprocessed data delivered in 2003) in and
surrounding the Providence Field we discovered in 2001. Since the discovery well
commenced production in January 2002, five wells have been drilled and
successfully completed. Four of the wells had average production rates ranging
from 14,309 to 17,669 Mcfe per day per well during the first 90 full days of
production. The field has cumulative production as of September 30, 2003 of 10.2
Bcfe. We have working interests ranging from 35% to 45% in the leases in this
field and operate three of the six wells. We anticipate participating in two
additional extension wells (1.0 net) in the field in first quarter 2004.

Encinitas Field. This field, the site of our first 3-D seismic survey in 1995,
has 24 wells currently producing. Since 1996, we have participated in the
drilling of 24 wells (4.0 net) in this area, 22 (3.5 net) of which were
successfully completed. During 2003, we participated in the drilling of nine
wells, all of which were successfully completed. We expect to drill between four
and eight wells in 2004, with an additional six to 10 well locations to be
drilled thereafter. We will have a 27.5% working interest in those wells.

Southeast Texas Area

The Southeast Texas area contains similar objective levels found in the
Frio/Vicksburg trend area. We separate this as a focus area because of the
geographic concentration of our 3-D seismic data and because reservoirs in this
area can display seismic amplitude anomalies. Seismic amplitude anomalies can be
interpreted as an indicator of hydrocarbons, although these anomalies are not
necessarily reliable as to hydrocarbon presence or productivity. We have
acquired licenses for approximately 900 square miles of 3-D

data (including 400 square miles of newly released data delivered in 2003) over
our Southeast Texas project area which is focused primarily on the Frio, Yegua,
Cook Mountain and Vicksburg formations. The project area is split into the Cedar
Point and Liberty County areas.

Currently, we have identified over 15 exploratory drilling locations with an
additional 10 potential extension locations in the Southeast Texas area over
which we have licenses for 3-D seismic data. Approximately 12 of the 15
exploratory locations we have identified are relatively lower risk and generally
shallower with the remaining three being relatively higher risk and deeper with
greater upside potential.

From January 1, 2000 to December 31, 2003, we participated in the drilling and
completion of 12 wells (4.3 net)in 17 attempts in this area. We invested $2.9
million to drill and complete five wells (1.3 net) in the Southeast Texas area
in 2003 and expect to devote approximately $11.1 million to drill 11 wells (4.8
net) in this area in 2004. The Liberty Project Area and Cedar Point Project Area
have proven to be successful for us, and we expect that the Liberty Project Area
will constitute a significant portion of our drilling program for the remainder
of 2003 and for 2004.

Cedar Point Area. The Cedar Point Project Area is located in Chambers County,
Texas, adjacent to Trinity Bay. The 30-square-mile 3-D survey targets the lower
Frio and Vicksburg formations. Since 1999, five of six wells drilled have been
successful. In 2003, we drilled one well that produced an average of 15,789 Mcfe
per day during the first 90 full days of production. In December 2003, we
completed an extension well that encountered approximately 41 feet of logged
pay. Our working interest in leases in this project area is approximately 28% in
the first well drilled in 2003 and 25% in the extension well.

Liberty County Area. We have identified and leased prospects ranging from the
Frio to the Cook Mountain formations within the 500 square miles of 3-D seismic
data in the Liberty Project Area which, along with 290 square miles of newly
released 3-D seismic data licensed in early 2003, now covers significant areas
of Liberty and Hardin Counties, Texas. Since January 1, 2000, we have been
successful on six of eight wells drilled, including one Yegua well, one Frio
well and five Cook Mountain wells. In 2002, we completed one well that produced
an average of 9,787 Mcfe per day during the first 90 full days of production. We
operate this well and own a 40% working interest. In 2003, we had another
drilling success in this area with a well producing an average of 13,030 Mcfe
per day during the first 90 full days of production. We operate this well and
own a 46.3% working interest.

South Louisiana Area

The South Louisiana area primarily contains objectives in the Middle and Lower
Miocene intervals. We have acquired licenses for approximately 1,850 square
miles of 3-D data (including 1,416 square miles of newly released data delivered
in 2003), and over 2,000 acres of leasehold. The 3-D seismic data sets are
concentrated in one general area including St. Mary, Terrebonne and LaFourche
Parishes.

Currently, we have identified over eight exploratory drilling locations with an
additional three potential extension locations in the South Louisiana area over
which we have licenses for 3-D seismic data. Two of the eight exploratory
locations we have identified are relatively lower risk and generally shallower
with the other six being relatively higher risk and deeper with greater upside
potential. From January 1, 2000 to December 31, 2003, we drilled and completed
seven wells (1.7 net) on 14 attempts in this area. We invested $4.0 million to
drill three wells (0.7 net) in the South Louisiana area in 2003 and expect to
devote approximately $9.3 million to drill five wells (2.5 net) in this area in
2004.

LaRose Area. During 2002, we successfully drilled and completed an offset well
to the discovery well in this area. We operate the two wells and own a 40%
working interest. The discovery well produced at an average of 15,581 Mcfe per
day during the first 90 full days of production. We plan to participate in three
to four additional wells (1.3 to 1.8 net) in the general area during 2004.

Patterson Area. In December 2003, we announced the discovery of Shadyside #1
well in this area, which logged over 77 feet of pay. We operate the well and
have an approximate 35% working interest. We believe there are two potential
extension wells in the Patterson area.

Other Areas of Interest

East Texas Area

The East Texas area encompasses multiple objectives, including the Wilcox and
Cotton Valley intervals. We are focused on the Camp Hill Field, a Wilcox steam
flood project in Anderson County, and the Tortuga Grande Prospect, a Cotton
Valley sand opportunity. We have licenses for over 470 square miles of 3-D
seismic data in the East Texas area and 2,816 net acres under leasehold.

We expect to invest $0.5 million to drill one (0.5 net) well in this region in
2004.

Camp Hill Field. We own interests in eight leases totaling approximately 600
gross acres in the Camp Hill field in Anderson County, Texas. We currently
operate seven of these leases. During the year ended December 31, 2002, the
project produced an average of 58 Bbls/d of 19 API gravity oil. The wells
produce from a depth of 500 feet and utilize a tertiary steam drive as an
enhanced oil recovery process. Although efficient at maximizing oil recovery,
the steam drive process is relatively expensive to operate because natural gas
or produced crude is burned to create the steam injectant. Lifting costs during
the year ended December 31, 2002 averaged $14.99 per barrel ($2.50 per Mcfe). In
response to high fuel gas prices, steam injection was reduced in mid-2000.
Because profitability increases when natural gas prices drop relative to oil
prices, the project is a natural hedge against decreases in natural gas prices
relative to oil prices. The oil produced, although viscous, commands a higher
price (an average premium of $1.00 per Bbl during the year ended December 31,
2002) than West Texas intermediate crude due to its suitability as a lube oil
feedstock. As of December 31, 2002, we had 7.7 MMBbls of proved oil reserves in
this project, with 750 MBbls of oil reserves currently developed. We have from
time to time chosen to delay development of our proved undeveloped reserves in
the Camp Hill Field in East Texas in favor of pursuing shorter-term exploration
projects with potential higher rates of return, adding to our lease position in
this field and further evaluating additional economic enhancements for this
field's development. The proved undeveloped reserves at the Camp Hill Field
constitute 66% of our proved reserves and account for 34% of our present value
of net future revenues from proved reserves as of December 31, 2002. We
anticipate drilling additional wells and increasing steam injection to develop
the proved undeveloped reserves in this project, with the timing and amount of
expenditures dependent on the relative prices of oil and natural gas. We have an
average working interest of approximately 90% in this field and an average net
revenue interest of 74%.

Tortuga Grande Prospect. In November 2003 we finalized an agreement to operate
the re-entry of an abandoned Cotton Valley test well that calculates on logs to
have over 230 feet of sands with possible production. At the time of drilling,
the operator perforated the objective interval and tested gas but in uneconomic
volumes. This well was drilled before newer fracturing technology that can
increase flow rates was developed and when gas prices were significantly lower.
Following successful testing of this re-entry, there are over 10 potential
extension locations on our acreage that may be prospective.

Barnett Shale Trend

We began active participation in the Barnett Shale play in the Fort Worth Basin
on acreage located west of the city of Fort Worth, Texas in mid-2003. Since that
time, we have acquired leases on 2,178 net acres and have transactions pending
on additional acreage. We have invested $0.9 million to drill six wells (2.6
net), two of which are completed and producing and four of which are awaiting
pipeline hookup. Net production from the two wells (0.6 net) drilled to date
that are on-line was a combined 360 Mcf per day and 384 Mcfe per day as of
November 21, 2003. We have received permits for the first proposed well for
which we will act as operator, a horizontal well expected to be drilled in the
first quarter of 2004. We are continuing to expand our leasehold acquisition in
this trend. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Recent Developments--Potential Barnett Shale
Acquisition."

Rocky Mountain Region

As discussed below under "--Pinnacle Transaction," in the second quarter of
2003, we contributed to Pinnacle our interests in leases in the Clearmont,
Kirby, Arvada and Bobcat project areas and natural gas and oil reserves in the
Bobcat project in the Powder River Basin in southwestern Wyoming and Montana. We
also own direct interests in approximately 189,000 gross acres of coalbed
methane properties in the Castle Rock project area in Montana and the Oyster
Ridge project area in Wyoming that were not contributed to Pinnacle, but we
currently have no proved reserves of, and are no longer receiving revenue from,
coalbed methane gas other than through Pinnacle.

As of the closing of the Pinnacle transaction in June 2003, we had participated
in the acquisition and/or drilling of 77 wells (29.0 net); we had invested $0.6
million to drill and complete two wells in the Rocky Mountain region from
January 1, 2003 to that date. All of

the wells encountered coal accumulations and are in various stages of
development and/or stages of production. Coalbed methane wells typically first
produce water in a process called dewatering and then, as the water production
declines, begin producing methane gas at an increasing rate. As the wells
mature, the production peaks and begins declining.

We continue to own a 26.9% interest in Pinnacle on a fully diluted basis. We are
not required to make any further capital contributions to Pinnacle.

Of the approximately 318,740 gross and 90,250 net mineral acres held by us and
Pinnacle, respectively, as of September 30, 2003, approximately 193,250 and
20,970 net mineral acres, respectively, are located in the State of Montana. The
issuance of new coalbed methane drilling permits in Montana was halted
temporarily pending the Federal Bureau of Land Management's approval of a final
record of decision on Montana's Resource Management Plan environmental impact
statement and the Montana Department of Environmental Quality's approval of a
statewide oil and gas environmental impact statement. These two program
approvals were obtained in April and August of 2003, respectively. Accordingly,
the Montana Board of Oil and Gas Conservation has begun accepting new coalbed
methane drilling permit applications. Environmental groups have initiated two
lawsuits, each challenging one of these program approvals. We believe that the
decisions by the Federal Bureau of Land Management and the State of Montana
ultimately will be upheld and new coalbed methane development will continue to
be authorized in Montana. Pinnacle holds approximately 56 grandfathered drilling
permits in Montana that were contributed by our joint venture partner RMG at the
time of Pinnacle's formation, and RMG holds approximately 56 grandfathered
drilling permits in Montana for acreage in which CCBM also has an interest.
There can be no assurance that any new permits will be obtained in a given time
period or at all.

U.K. North Sea Region

We have been awarded seven acreage blocks, consisting of one "Traditional" and
three "Promote" licenses, in the United Kingdom's 21st Round of Licensing. The
awarded blocks, to explore for natural gas and oil totaling approximately
209,000 acres, are located within mature producing areas of the Central and
Southern North Sea in water depths of 30 to 350 feet. The Promote licenses do
not have drilling commitments and have two-year terms. The Traditional license
will be canceled after four years if we or our assignee elects not to commit to
drilling a well. We believe our U.K. North Sea interest is a natural extension
to our technical analyses, portfolio and business plan. The U.K. North Sea
includes proven hydrocarbon trends with established technological expertise,
available large 3-D seismic datasets and significant exploration potential. We
plan to promote our interests to other parties experienced in drilling and
operating in this region. Geological and geophysical costs will be incurred in
an attempt to maximize the value of our retained interest. Our estimated project
commitments from commencement through mid-2005 are $0.9 million, comprised of
$0.2 million for seismic data, $0.2 million for leasehold costs and $0.2 million
for data processing in 2003 and $0.3 million for seismic data processing in
2004.

Working Interest and Drilling in Project Areas

The actual working interest we ultimately will own in a well will vary based
upon several factors, including the depth, cost and risk of each well relative
to our strategic goals, activity levels and budget availability. From time to
time, some fraction of these wells may be sold to industry partners either on a
prospect-by-prospect basis or on a program basis. In addition, we may also
contribute acreage to larger drilling units, thereby reducing prospect working
interest. We have, in the past, retained less than 100% working interest in our
drilling prospects. References to our interests are not intended to imply that
we have or will maintain any particular level of working interest.

Our success will be materially dependent upon the success of our exploratory
drilling program. In addition, although we currently are pursuing prospects
within the project areas described above, there can be no assurance that these
prospects will be drilled at all or within the expected time frame. See "Risk
Factors--Natural gas and oil drilling is a speculative activity and involves
numerous risks and substantial and uncertain costs that could adversely affect
us" and "Risk Factors--We may not adhere to our proposed drilling schedule."

Natural Gas and Oil Reserves

The following table sets forth our estimated net proved natural gas and oil
reserves and the PV-10 Value of such reserves as of December 31, 2002. The
reserve data and the present value as of December 31, 2002 were prepared by
Ryder Scott Company and Fairchild and Wells, Inc., Independent Petroleum
Engineers. The PV-10 Value was prepared using constant prices as of the
calculation date, discounted at 10% per annum on a pretax basis, and is not
intended to represent the current market value of the estimated natural gas and
oil reserves we own. For further information concerning the present value of
future net revenue from these proved reserves,

see Note 13 of the notes to our consolidated financial statements for the year
ended December 31, 2002, which are included in our annual report on Form 10-K
for the year ended December 31, 2002.

Proved Reserves
---------------------------------------
Developed Undeveloped Total
----------- ----------- -----------

Natural gas (MMcf)................... 12,826 96 12,922
Oil and condensate (MBbls)........... 1,393 6,988 8,381
Natural gas equivalent (MMcfe)..... 21,184 42,024 63,208
PV-10 Value (in thousands)(1)........ $ 55,235 $ 28,379 $ 83,614

- ----------

(1) The PV-10 Value as of December 31, 2002 is pretax and was determined by
using the December 31, 2002 sales prices, which averaged $29.16 per Bbl of
oil, $4.70 per Mcf of natural gas.

No estimates of proved reserves comparable to those included herein have been
included in reports to any federal agency other than the SEC.

For a discussion of the uncertainties inherent in estimating natural gas and oil
reserves and their estimated values, see "Risk Factors--Our reserve data and
estimated discounted future net cash flows are estimates based on assumptions
that may be inaccurate and on existing economic and operating conditions that
may differ from future conditions."

Volumes, Prices and Natural Gas & Oil Operating Expense

The following table sets forth certain information regarding the production
volumes of, average sales prices received for and average production costs
associated with our sales of natural gas and oil for the periods indicated. The
table includes the cash impact of hedging activities and the effect of certain
hedge positions with an affiliate of Enron Corp. reclassified as derivatives
during November 2001.

Year Ended December 31,
------------------------------------
2000 2001 2002
---------- ---------- ----------

Production volumes:
Natural gas (MMcf).......................................... 5,460 4,432 4,801
Oil (MBbls)................................................. 198 160 401
Natural gas equivalent (MMcfe)........................... 6,651 5,390 7,207
Average sales prices:(1)
Natural gas (per Mcf)....................................... 3.90 5.04 3.50
Oil (per Bbl)............................................... $ 27.81 $ 24.28 $ 24.94
Natural gas and oil operating expenses (per Mcfe):(2)
Operating expenses in all areas excluding Camp Hill......... $ 0.59 $ 0.43 $ 0.44
Operating expenses in Camp Hill............................. 3.08 2.14 2.50
Total operating expenses................................. $ 0.74 $ 0.77 $ 0.68

- ----------

(1) Includes impact of hedging activities.

(2) Includes direct operating costs (labor, repairs and maintenance, materials
and supplies), workover costs and the administrative costs of production
offices, insurance and property and severance taxes.

Development, Exploration and Acquisition Capital Expenditures

The following table sets forth certain information regarding the gross costs
incurred in the purchase of proved and unproved properties and in development
and exploration activities.

Year Ended December 31,
---------------------------------------
2000 2001 2002
----------- ----------- -----------
(in thousands)

Acquisition costs:
Unproved properties(1)...... $ 6,641 $ 12,607 $ 6,402
Proved properties........... 337 800 660
Exploration................... 7,843 18,356 14,194
Development................... 1,361 3,065 2,351
----------- ----------- -----------
Total costs incurred(2).. $ 16,182 $ 34,828 $ 23,607
=========== =========== ===========

- ----------

(1) Includes unproved property costs of $9.0 million in 2001 and $2.2 million in
2002 in the coalbed methane properties we contributed as a minority interest
to Pinnacle in June 2003.

(2) Excludes capitalized interest on unproved properties of $3.6 million, $3.2
million and $3.1 million for the years ended December 31, 2000, 2001 and
2002, respectively.

Drilling Activity

The following table sets forth our drilling activity for the years ended
December 31, 2000, 2001 and 2002. In the table, "gross" refers to the total
wells in which we have a working interest and "net" refers to gross wells
multiplied by our working interest therein. Our drilling activity from January
1, 1996 to December 31, 2002 has resulted in a commercial success rate of
approximately 66%.

Year Ended December 31,
---------------------------------------------
2000 2001 2002
------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----

Exploratory wells:
Productive...... 19 4.7 18 5.9 16 5.6
Nonproductive... 15 3.4 5 1.4 3 1.1
----- ----- ----- ----- ----- -----
Total........ 34 8.1 23 7.3 19 6.7
===== ===== ===== ===== ===== =====
Development wells:
Productive...... 5 1.9 2 0.3 1 0.4
Nonproductive... -- -- -- -- -- --
----- ----- ----- ----- ----- -----
Total........ 5 1.9 2 0.3 1 0.4
===== ===== ===== ===== ===== =====

The above table excludes 75 gross (28 net) wells drilled or acquired by CCBM
through 2002. At December 31, 2002, we have ownership in 11 gross (2.7 net)
wells with dual completion in single bore holes.

Productive Wells

The following table sets forth the number of productive natural gas and oil
wells in which we owned an interest as of December 31, 2002.

Company
Operated Other Total
------------- ------------- -------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----

Oil........ 49 46 18 6 67 52
Natural Gas 36 19 59 15 95 34
----- ----- ----- ----- ----- -----
Total...... 85 65 77 21 162 86
===== ===== ===== ===== ===== =====

Acreage Data

The following table sets forth certain information regarding our developed and
undeveloped lease acreage as of September 30, 2003. Developed acres refers to
acreage within producing units and undeveloped acres refers to acreage that has
not been placed in producing units. Leases covering substantially all of the
undeveloped acreage in the following table will expire within the next three
years. In general, our leases will continue past their primary terms if natural
gas or oil in commercial quantities is being produced from a well on such
leases.

Developed Acreage Undeveloped Acreage Total
--------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------

Onshore Gulf Coast.... 40,449 14,767 44,182 18,675 84,631 33,442
East Texas............ 360 220 687 342 1,047 562
Rocky Mountain........ -- -- 145,376 16,710 145,376 16,710
U.K. North Sea........ -- -- 209,613 209,613 209,613 209,613
--------- --------- --------- --------- --------- ---------
Total............... 40,809 14,987 399,858 245,340 440,667 260,327
========= ========= ========= ========= ========= =========

The table does not include 7,422 gross acres (3,334 net) that we had a right to
acquire in Texas pursuant to various seismic options or agreements at September
30, 2003. Under the terms of our option agreements, we typically have the right
for a period of one year, subject to extensions, to exercise our option to lease
the acreage at predetermined terms. Our lease agreements generally terminate if
producing wells have not been drilled on the acreage within a period of three
years. Further, the table does not include 28,511 gross and 10,403 net acres in
Wyoming that we have the right to earn pursuant to specified drilling
obligations and other predetermined terms.

Marketing

Our production is marketed to third parties consistent with industry practices.
Typically, oil is sold at the wellhead at field-posted prices plus a bonus and
natural gas is sold under contract at a negotiated price based upon factors
normally considered in the industry, such as distance from the well to the
pipeline, well pressure, estimated reserves, quality of natural gas and
prevailing supply and demand conditions.

Our marketing objective is to receive the highest possible wellhead price for
our product. We are aided by the presence of multiple outlets near our
production in the Texas and Louisiana onshore Gulf Coast. We take an active role
in determining the available pipeline alternatives for each property based on
historical pricing, capacity, pressure, market relationships, seasonal variances
and long-term viability.

There are a variety of factors that affect the market for natural gas and oil,
including:

o the extent of domestic production and imports of natural gas and oil;

o the proximity and capacity of natural gas pipelines and other
transportation facilities;

o demand for natural gas and oil;

o the marketing of competitive fuels; and

o the effects of state and federal regulations on natural gas and oil
production and sales.

See "Risk Factors--Natural gas and oil prices are highly volatile, and lower
prices will negatively affect our financial results," "Risk Factors--We are
subject to various governmental regulations and environmental risks" and "Risk
Factors--The marketability of our natural gas production depends on facilities
that we typically do not own or control, which could result in a curtailment of
production and revenues."

We from time to time market our own production where feasible with a combination
of market-sensitive pricing and forward-fixed pricing. We utilize forward
pricing to take advantage of anomalies in the futures market and to hedge a
portion of our production deliverability at prices exceeding forecast. All of
these hedging transactions provide for financial rather than physical
settlement. For a discussion of these matters, our hedging policy and recent
hedging positions, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Critical Accounting Policies and
Estimates--Derivative Instruments and Hedging Activities" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Qualitative and Quantitative Disclosures About Market
Risk--Derivative Instruments and Hedging Activities."

Competition and Technological Changes

We encounter competition from other natural gas and oil companies in all areas
of our operations, including the acquisition of exploratory prospects and proven
properties. Many of our competitors are large, well-established companies that
have been engaged in

the natural gas and oil business for much longer than we have and possess
substantially larger operating staffs and greater capital resources than we do.
We may not be able to conduct our operations, evaluate and select suitable
properties and consummate transactions successfully in this highly competitive
environment. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations," "Risk Factors--We face strong competition from
larger natural gas and oil companies" and "Risk Factors--We have substantial
capital requirements that, if not met, may hinder operations."

The natural gas and oil industry is characterized by rapid and significant
technological advancements and introductions of new products and services using
new technologies. If one or more of the technologies we use now or in the future
were to become obsolete or if we are unable to use the most advanced
commercially available technology, our business, financial condition and results
of operations could be materially adversely affected. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations," "Risk
Factors--We may not be able to keep pace with technological developments in our
industry," "Risk Factors--We may experience difficulty in achieving and managing
future growth" and "Risk Factors--We have substantial capital requirements that,
if not met, may hinder operations."

Regulation

Natural gas and oil operations are subject to various federal, state and local
environmental regulations that may change from time to time, including
regulations governing natural gas and oil production, federal and state
regulations governing environmental quality and pollution control and state
limits on allowable rates of production by well or proration unit. These
regulations may affect the amount of natural gas and oil available for sale, the
availability of adequate pipeline and other regulated transportation and
processing facilities and the marketing of competitive fuels. For example, a
productive natural gas well may be "shut-in" because of an oversupply of natural
gas or lack of an available natural gas pipeline in the areas in which we may
conduct operations. State and federal regulations generally are intended to
prevent waste of natural gas and oil, protect rights to produce natural gas and
oil between owners in a common reservoir, control the amount of natural gas and
oil produced by assigning allowable rates of production and control
contamination of the environment. Pipelines are subject to the jurisdiction of
various federal, state and local agencies. We are also subject to changing and
extensive tax laws, the effects of which cannot be predicted.

The following discussion summarizes the regulation of the United States oil and
gas industry. We believe we are in substantial compliance with the various
statutes, rules, regulations and governmental orders to which our operations may
be subject, although we cannot assure you that this is or will remain the case.
Moreover, those statutes, rules, regulations and government orders may be
changed or reinterpreted from time to time in response to economic or political
conditions, and any such changes or reinterpretations could materially adversely
affect our results of operations and financial condition. The following
discussion is not intended to constitute a complete discussion of the various
statutes, rules, regulations and governmental orders to which our operations may
be subject.

Regulation of Natural Gas and Oil Exploration and Production

Our operations are subject to various types of regulation at the federal, state
and local levels that:

o require permits for the drilling of wells;

o mandate that we maintain bonding requirements in order to drill or
operate wells; and

o regulate the location of wells, the method of drilling and casing wells,
the surface use and restoration of properties upon which wells are
drilled, the plugging and abandoning of wells and the disposal of fluids
used in connection with operations.

Our operations are also subject to various conservation laws and regulations.
These regulations govern the size of drilling and spacing units or proration
units, the density of wells that may be drilled in natural gas and oil
properties and the unitization or pooling of natural gas and oil properties. In
this regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units and therefore more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from natural gas and oil
wells, generally prohibit the venting or flaring of natural gas and impose
specified requirements regarding the ratability of production. The effect of
these regulations may limit the amount of natural gas and oil we can produce
from our wells and may limit the number of wells or the locations at which we
can drill. The regulatory burden on the natural gas and oil industry increases
our costs of doing business and, consequently, affects our

profitability. Because these laws and regulations are frequently expanded,
amended and reinterpreted, we are unable to predict the future cost or impact of
complying with such regulations.

Regulation of Sales and Transportation of Natural Gas

Federal legislation and regulatory controls have historically affected the price
of natural gas we produce and the manner in which our production is transported
and marketed. Under the Natural Gas Act of 1938 (NGA), the Federal Energy
Regulatory Commission (FERC) regulates the interstate transportation and the
sale in interstate commerce for resale of natural gas. Effective January 1,
1993, the Natural Gas Wellhead Decontrol Act (the Decontrol Act) deregulated
natural gas prices for all "first sales" of natural gas, including all of our
sales of our own production. As a result, all of our domestically produced
natural gas may now be sold at market prices, subject to the terms of any
private contracts that may be in effect. The FERC's jurisdiction over interstate
natural gas transportation, however, was not affected by the Decontrol Act.

Under the NGA, facilities used in the production or gathering of natural gas are
exempt from the FERC's jurisdiction. We own certain natural gas pipelines that
we believe satisfy the FERC's criteria for establishing that these are all
gathering facilities not subject to FERC jurisdiction under the NGA. State
regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, nondiscriminatory take requirements
but does not generally entail rate regulation.

Although we therefore do not own or operate any pipelines or facilities that are
directly regulated by the FERC, its regulations of third-party pipelines and
facilities could indirectly affect our ability to market our production.
Beginning in the 1980s the FERC initiated a series of major restructuring orders
that required pipelines, among other things, to perform open access
transportation, "unbundle" their sales and transportation functions, and allow
shippers to release their pipeline capacity to other shippers. As a result of
these changes, sellers and buyers of natural gas have gained direct access to
the particular pipeline services they need and are better able to conduct
business with a larger number of counterparties. We believe these changes
generally have improved our access to markets while, at the same time,
substantially increasing competition in the natural gas marketplace. It remains
to be seen, however, what effect the FERC's other activities will have on access
to markets, the fostering of competition and the cost of doing business. We
cannot predict what new or different regulations the FERC and other regulatory
agencies may adopt, or what effect subsequent regulations may have on our
activities.

In the past, Congress has been very active in the area of natural gas
regulation. However, the more recent trend has been in favor of deregulation or
"lighter handed" regulation and the promotion of competition in the gas
industry. There regularly are other legislative proposals pending in the federal
and state legislatures which, if enacted, would significantly affect the
petroleum industry. At the present time, it is impossible to predict what
proposals, if any, might actually be enacted by Congress or the various state
legislatures and what effect, if any, such proposals might have on us.
Similarly, and despite the trend toward federal deregulation of the natural gas
industry, whether or to what extent that trend will continue, or what the
ultimate effect will be on our sales of gas, cannot be predicted.

Oil Price Controls and Transportation Rates

Our sales of oil, condensate and natural gas liquids are not currently regulated
and are made at market prices. The price we receive from the sale of these
products may be affected by the cost of transporting the products to market.
Much of that transportation is through interstate common carrier pipelines.
Effective as of January 1, 1995, the FERC implemented regulations generally
grandfathering all previously approved interstate transportation rates and
establishing an indexing system for those rates by which adjustments are made
annually based on the rate of inflation, subject to specified conditions and
limitations. These regulations may tend to increase the cost of transporting
natural gas and oil liquids by interstate pipeline, although the annual
adjustments may result in decreased rates in a given year. These regulations
generally have been approved on judicial review. Every five years, the FERC must
examine the relationship between the annual change in the applicable index and
the actual cost changes experienced in the oil pipeline industry. The first such
review was completed in 2000 and on December 14, 2000, the FERC reaffirmed the
current index. Following a successful court challenge of these orders by an
association of oil pipelines, on February 24, 2003 the FERC increased the index
slightly for the current five-year period, effective July 2001. We are not able
at this time to predict the effects, if any, of these regulations on the
transportation costs associated with oil production from our oil-producing
operations.

Environmental Regulations

Our operations are subject to numerous federal, state and local laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the

environment in connection with drilling and production activities, limit or
prohibit drilling activities on specified lands within wilderness, wetlands and
other protected areas, require remedial measures to mitigate pollution from
former operations, such as pit closure and plugging abandoned wells, and impose
substantial liabilities for pollution resulting from production and drilling
operations. The failure to comply with these laws and regulations may result in
the assessment of administrative, civil and criminal penalties, imposition of
investigatory or remedial obligations or the issuance of injunctions prohibiting
or limiting the extent of our operations. Public interest in the protection of
the environment has increased dramatically in recent years. The trend of
applying more expansive and stricter environmental legislation and regulations
to the natural gas and oil industry could continue, resulting in increased costs
of doing business and consequently affecting our profitability. To the extent
laws are enacted or other governmental action is taken that restricts drilling
or imposes more stringent and costly waste handling, disposal and cleanup
requirements, our business and prospects could be adversely affected.

We generate wastes that may be subject to the federal Resource Conservation and
Recovery Act (RCRA) and comparable state statutes. The U.S. Environmental
Protection Agency (EPA) and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes. Furthermore,
certain wastes generated by our natural gas and oil operations that are
currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes" and therefore become subject to more rigorous
and costly operating and disposal requirements.

We currently own or lease numerous properties that for many years have been used
for the exploration and production of natural gas and oil. Although we believe
that we have implemented appropriate operating and waste disposal practices,
prior owners and operators of these properties may not have used similar
practices, and hydrocarbons or other wastes may have been disposed of or
released on or under the properties we own or lease or on or under locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties whose treatment and disposal or
release of hydrocarbons or other wastes was not under our control. These
properties and the wastes disposed thereon may be subject to the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA), RCRA and
analogous state laws as well as state laws governing the management of natural
gas and oil wastes. Under these laws, we could be required to remove or
remediate previously disposed wastes (including wastes disposed of or released
by prior owners or operators) or property contamination (including groundwater
contamination) or to perform remedial plugging operations to prevent future
contamination. See "Risk Factors--We are subject to various governmental
regulations and environmental risks."

CERCLA, also known as the "Superfund" law, and analogous state laws impose
liability, without regard to fault or the legality of the original conduct, on
specified classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These classes of
persons include the owner or operator of the disposal site or sites where the
release occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies, and 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.

Our operations may be subject to the Clean Air Act (CAA) and comparable state
and local requirements. In 1990 Congress adopted amendments to the CAA
containing provisions that have resulted in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. The EPA and states have developed and continue to develop
regulations to implement these requirements. We may be required to incur certain
capital expenditures in the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals addressing other air emission-related issues. However, we do not
believe our operations will be materially adversely affected by any such
requirements.

Federal regulations require certain owners or operators of facilities that store
or otherwise handle oil, such as us, to prepare and implement spill prevention,
control, countermeasure (SPCC) and response plans relating to the possible
discharge of oil into surface waters. The Oil Pollution Act of 1990 (OPA)
contains numerous requirements relating to the prevention of and response to oil
spills into waters of the United States. The OPA subjects owners of facilities
to strict joint and several liability for all containment and cleanup costs and
certain other damages arising from a spill, including, but not limited to, the
costs of responding to a release of oil to surface waters. The OPA also requires
owners and operators of offshore facilities that could be the source of an oil
spill into federal or state waters, including wetlands, to post a bond, letter
of credit or other form of financial assurance in amounts ranging from $10
million in specified state waters to $35 million in federal outer continental
shelf waters to cover costs that could be incurred by governmental authorities
in responding to an oil spill. These financial assurances may be increased by as
much as $150 million if a formal risk assessment indicates that the increase is
warranted. Noncompliance with OPA may result in varying civil and criminal
penalties and liabilities. Our operations are also subject to the federal Clean
Water Act (CWA) and analogous state laws. In

accordance with the CWA, the State of Louisiana issued regulations prohibiting
discharges of produced water in state coastal waters effective July 1, 1997.
Pursuant to other requirements of the CWA, the EPA has adopted regulations
concerning discharges of storm water runoff. This program requires covered
facilities to obtain individual permits or seek coverage under an EPA general
permit. Like OPA, the CWA and analogous state laws relating to the control of
water pollution provide varying civil and criminal penalties and liabilities for
releases of petroleum or its derivatives into surface waters or into the ground.

We also are subject to a variety of federal, state and local permitting and
registration requirements relating to protection of the environment. We believe
we are in substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse effect on us.

As further described in "--Significant Areas--Other Areas of Interest--Rocky
Mountain Region," the issuance of new coalbed methane drilling permits and the
continued viability of existing permits in Montana have been challenged in
lawsuits filed in state and federal court.

Operating Hazards and Insurance

The natural gas and oil business involves a variety of operating hazards and
risks that could result in substantial losses to us from, among other things,
injury or loss of life, severe damage to or destruction of property, natural
resources and equipment, pollution or other environmental damage, cleanup
responsibilities, regulatory investigation and penalties and suspension of
operations. See "Risk Factors--We are subject to various operating and other
casualty risks that could result in liability exposure or the loss of production
and revenues."

In addition, we may be liable for environmental damages caused by previous
owners of property we purchase and lease. As a result, we may incur substantial
liabilities to third parties or governmental entities, the payment of which
could reduce or eliminate the funds available for exploration, development or
acquisitions or result in the loss of our properties. See "Risk Factors--We are
subject to various governmental regulations and environmental risks."

In accordance with customary industry practices, we maintain insurance against
some, but not all, potential losses. We do not carry business interruption
insurance or protect against loss of revenues. We cannot assure you that any
insurance we obtain will be adequate to cover any losses or liabilities. We
cannot predict the continued availability of insurance or the availability of
insurance at premium levels that justify its purchase. We may elect to
self-insure if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable. The occurrence of an event not fully covered
by insurance could have a material adverse effect on our financial condition and
results of operations. See "Risk Factors--We may not have enough insurance to
cover all of the risks we face."

We participate in a substantial percentage of our wells on a nonoperated basis,
and may be accordingly limited in our ability to control the risks associated
with natural gas and oil operations. See "Risk Factors-- We cannot control the
activities on properties we do not operate and are unable to ensure their proper
operation and profitability."

Title to Properties; Acquisition Risks

We believe we have satisfactory title to all of our producing properties in
accordance with standards generally accepted in the natural gas and oil
industry. Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens
which we believe do not materially interfere with the use of or affect the value
of these properties. As is customary in the industry in the case of undeveloped
properties, we make little investigation of record title at the time of
acquisition (other than a preliminary review of local records). Investigations,
including a title opinion of local counsel, are generally made before
commencement of drilling operations. Our revolving credit facility is secured by
substantially all of our natural gas and oil properties.

material adverse effect on our financial condition and future results of
operations See "Risk Factors -- Our future acquisitions may yield revenues or
production that varies significantly from our projections."

Employees

At September 30, 2003, we had 37 full-time employees, including six
geoscientists and six engineers. We believe that our relationships with our
employees are good.

In order to optimize prospect generation and development, we utilize the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of 3-D seismic data mapping,
acquisition of leases and lease options, construction, design, well site
surveillance, permitting and environmental assessment. Independent contractors
generally provide field and on-site production operation services, such as
pumping, maintenance, dispatching, inspection and testings. We believe that this
use of third-party service providers has enhanced our ability to contain general
and administrative expenses.

We depend to a large extent on the services of certain key management personnel,
the loss of, any of which could have a material adverse effect on our
operations. We do not maintain key-man life insurance with respect to any of our
employees. See "Risk Factors--Our business may suffer if we lose key personnel."

Pinnacle Transaction

Formation and Operations

During the second quarter of 2003, we and Rocky Mountain Gas, Inc. (RMG) each
contributed our interests in certain natural gas and oil leases in Wyoming and
Montana in areas prospective for coalbed methane to a newly formed joint
venture, Pinnacle Gas Resources, Inc. In exchange for the contribution of these
assets, we received 37.5% of the common stock of Pinnacle and options to
purchase additional Pinnacle common stock. We retained our interests in
approximately 189,000 gross acres in the Castle Rock project area in Montana and
the Oyster Ridge project area in Wyoming. We no longer have a drilling
obligation in connection with the oil and natural gas leases contributed to
Pinnacle.

Simultaneously with the contribution of these assets, affiliates and related
parties of CSFB Private Equity (CSFB) contributed approximately $17.6 million of
cash to Pinnacle in return for redeemable preferred stock of Pinnacle, 25% of
Pinnacle's common stock as of the closing date and warrants to purchase Pinnacle
common stock. The CSFB parties also agreed to contribute additional cash, under
specified circumstances, of up to approximately $11.8 million to Pinnacle to
fund future drilling, development and acquisitions. The CSFB parties currently
have greater than 50% of the voting power of the Pinnacle capital stock through
their ownership of Pinnacle common and preferred stock.

Currently, on a fully diluted basis, assuming that all parties exercised their
Pinnacle warrants and options, the CSFB parties would have an ownership interest
in Pinnacle of 46.2%, and we and RMG each would own 26.9%. On a fully diluted
basis, assuming the additional $11.8 million of cash were contributed by the
CSFB parties and all warrants and options were exercised by all parties, the
CSFB parties would own 54.6% of Pinnacle and RMG and we each would own 22.7% of
Pinnacle.

Immediately following its formation, Pinnacle acquired an approximate 50%
working interest in existing leases and approximately 36,529 gross acres
prospective for coalbed methane development in the Powder River Basin of Wyoming
from an unaffiliated party for $6.2 million. The leases include 95 producing
coalbed methane wells currently in the early stages of dewatering, a process
that occurs prior to achieving stabilized production. At the time of the
Pinnacle transaction, these wells were producing at a combined gross rate of
approximately 2.5 MMcfd, or an estimated 1 MMcfd net to Pinnacle. Pinnacle also
agreed to fund up to $14.9 million of future drilling and development costs on
these properties on behalf of the third party prior to December 31, 2005. The
drilling and development work will be done under the terms of an earn-in joint
venture agreement between Pinnacle and Gastar. As of September 30, 2003,
Pinnacle owned interests in approximately 131,000 gross acres in the Powder
River Basin.

Certain Relationships and Agreements

Our Chairman, Steven A. Webster, is also Chairman of Global Energy Partners,
Ltd., an affiliate of CSFB Private Equity and could be deemed a related party
with respect to the Pinnacle transaction.

We provide specified accounting, treasury, tax, insurance and financial
reporting functions to Pinnacle through the end of 2003 under a transition
services agreement for a monthly fee equal to our actual cost to provide these
services. After December 31, 2003, the agreement will automatically renew on a
quarterly basis unless one of the parties gives notice of its intent to
terminate the agreement.

We have mutually agreed with RMG, its majority shareholder and the CSFB parties
to provide Pinnacle the right until June 23, 2008 to acquire at cost any
interest in natural gas and oil leases or mineral interests in the Powder River
Basin in Wyoming and Montana, but excluding most of Powder River County,
Montana, that such parties may have acquired in the covered area, subject to
specified exceptions.

We, the CSFB parties, RMG, RMG's parent company, Peter G. Schoonmaker, Gary W.
Uhland and Pinnacle also entered into a securityholders' agreement providing for
an initial eight person board of directors, which initially includes four
directors nominated by the CSFB parties and two nominated by each of us and RMG,
subject to change as their respective ownership percentages change. Each party
to the securityholders' agreement also granted to the others a right of first
offer and co-sale rights. If the CSFB parties propose to sell all of their
Pinnacle shares to a third party, under specified circumstances the CSFB parties
may require the other securityholders to include all of their Pinnacle shares in
that sale. In event of such a sale, the Pinnacle preferred stock will have a
preferred right to receive an amount equal to its liquidation value (as defined
below) per share plus accrued and unpaid dividends prior to distributions to the
holders of shares of Pinnacle common stock and common stock equivalents.
Pinnacle also granted the securityholders pre-emptive rights to purchase
additional securities in order to maintain their proportionate ownership of
Pinnacle. The securityholders' agreement also provides generally for multiple
demand registration rights with respect to the Pinnacle common stock in favor of
the CSFB parties and certain piggyback registration rights for us and RMG
subject to the satisfaction of specified conditions.

Pinnacle Preferred Stock and Warrants Held by the CSFB Parties

The Pinnacle redeemable preferred stock issued to the CSFB parties generally has
the right to vote together with the Pinnacle common stock and has a class vote
on specified matters, including specified extraordinary transactions. In the
event of any dissolution, liquidation, or winding up by Pinnacle, the holder of
each share of Pinnacle preferred stock will be entitled to be paid a liquidation
value of $100 per share out of the assets of Pinnacle available for distribution
to its shareholders.

Dividends on the Pinnacle preferred stock are payable either in cash at a rate
of 10.5% per annum through June 23, 2011 and 12.5% thereafter or, at Pinnacle's
option, by payment in kind of additional shares of the Pinnacle preferred stock.
For each additional share of Pinnacle preferred stock distributed to a holder as
an in-kind dividend, Pinnacle will also deliver to that holder one Pinnacle
warrant, which will have an exercise price equal to the exercise price of the
outstanding Pinnacle warrants on the date of such distribution. On or after July
1, 2005, Pinnacle may redeem all or any portion of the Pinnacle preferred stock,
provided that if any Pinnacle warrants are still outstanding, Pinnacle may
redeem all but a single share; if the redemption occurs at any time before July
1, 2009, the redemption price will be at a premium to the liquidation value of
the shares.

Pinnacle is required to redeem its preferred stock upon:

o specified changes of control, at a price per share equal to 101% of its
liquidation value; or

o specified events of default, at a price per share equal to 110% of the
liquidation value prior to June 30, 2005 and, thereafter, equal to an
optional redemption price that decreases over time.

The Pinnacle warrants entitle the holders to purchase up to 130,000 shares of
Pinnacle common stock at a price of $100 per share and are exercisable at any
time until June 30, 2013. The Pinnacle warrants can be exercised in cash, by
tender of the Pinnacle preferred stock and on a cashless net exercise basis. The
Pinnacle warrants are subject to adjustments, including, in specified cases, an
adjustment of the exercise price to equal the lowest price at which Pinnacle
common stock is sold if such shares are sold below the then-current exercise
price.