RANGE RESOURCES CORP - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K
(MARK ONE)

(x) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 2001

( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transaction period from _______ to _______

COMMISSION FILE NUMBER 0-9592

RANGE RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 34-1312571
(State of incorporation) (I.R.S. Employer
Identification No.)

777 MAIN STREET, FORT WORTH, TEXAS 76102
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code:
(817) 870-2601

Securities registered pursuant to Section 12(b) of the Act:
None

COMMON STOCK, $.01 PAR VALUE
(Title of class)

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes x No
--- ---

Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. ( )

The aggregate market value of voting stock of the registrant held by
non-affiliates (excluding voting shares held by officers and directors) was
$237,932,024 on March 1, 2002.

Indicate the number of shares outstanding of each of the registrant's
classes of stock on March 1, 2002: Common Stock $.01 par value: 52,841,766.

DOCUMENTS INCORPORATED BY REFERENCE:
Part III of this report incorporates by reference the Proxy Statement relating
to the Registrant's 2002 Annual Meeting of Stockholders, to be filed on or
about April 18, 2002.

RANGE RESOURCES CORPORATION

ANNUAL REPORT ON FORM 10-K
YEAR ENDED DECEMBER 31, 2001

PART I

ITEM 1. BUSINESS

GENERAL

Range Resources Corporation ("Range") is engaged in development,
acquisition and exploration of oil and gas properties, primarily in the
Southwestern, Gulf Coast and Appalachian regions of the United States. The
Company pursues development drilling and exploitation projects, acquisitions
and, to a lesser extent, exploration of its extensive acreage position. All
Appalachian assets are held through a 50% interest in a joint venture, Great
Lakes Energy Partners L.L.C. ("Great Lakes"). Independent Producer Finance
("IPF"), a wholly owned subsidiary, provides financing to small oil and gas
producers through the purchase of overriding royalty interests. Both Great Lakes
and IPF are independently financed and all of IPF and Range's proportionate
share of Great Lakes' assets and operations are consolidated in the Company's
financial statements. At December 31, 2001, the Company had 513 Bcfe of proved
reserves, having a pre-tax present value, excluding open hedging contracts, of
$399.2 million based on constant prices of $20.38 per barrel and $2.63 per
Mmbtu. The fair value of open hedging contracts at December 31, 2001
approximated a net unrealized pre-tax gain of $52.1 million. The Company's
proved reserves are 76% natural gas by volume, 70.2% developed and 84.4%
operated. At year-end, the Company's properties had a reserve life index of 9.2
years. In addition, the Company owned 558,862 gross (284,028 net) acres of
undeveloped leasehold.

HISTORY

Between 1988 and 1997, the Company actively pursued small acquisitions
as well as the further development of its properties. The Company was
consistently profitable and steadily increased its production and reserves.
Between late 1997 and mid-1998, a series of large acquisitions were consummated
which proved extremely disappointing. Production from the acquired properties
fell more rapidly than anticipated and further development of the principal
fields proved far less attractive than expected. In combination with a steep
decline in energy prices which began in late 1997 and the substantial burden
imposed by debt and fixed income securities taken on in connection with the
purchases, the adverse impact on the Company's operating results, balance sheet
and stock price was severe.

In 1998 and 1999, sharp reductions in staff and capital budgets, sales
of properties and the formation of Great Lakes allowed the Company to materially
reduce debt and stabilize its financial position. However, production and
reserves fell as a result of these actions. In the Great Lakes transaction, the
single most significant step in the debt reduction effort, Range and FirstEnergy
Corp. ("FirstEnergy") contributed their Appalachian oil and gas properties and
associated gas pipeline systems to a joint venture, forming one of the largest
production companies in the region. To achieve equal ownership despite Range's
contribution of a disproportionate share of the proved reserves, the venture
assumed $188.3 million of Range's bank debt and FirstEnergy contributed $2.0
million of cash.

Faced with high leverage and significant concern from its banks, the
Company moved aggressively to hedge its production as the oil and gas markets
began to recover in late 1999. These hedges, which covered roughly 80% of the
Company's anticipated production through the third quarter of 2000, were
designed to assure financial viability while the restructuring was completed.
Given the continuing sharp rise in oil and gas prices throughout 2000, these
hedges substantially limited the benefits to the Company of the price increases.
Because the Company has continued to hedge on a rolling twelve to eighteen month
basis since that time, the rise in prices has permitted a substantial increase
in the average price at which production is hedged, particularly since September
30, 2000. At year-end 2001, the Company had hedges in place on approximately
47.3 bcf of gas and 700,000 barrels of oil at average prices of $4.02 per mcf
and $25.97 per barrel. These hedges cover approximately 55%, 30%, 15% and 5% of
the Company's anticipated production from proved reserves on an mcfe basis for
2002 through 2005, respectively.

In 2000, with the benefit of rising oil and gas prices, the Company
began to gradually increase capital expenditures while keeping spending below
internal cash flow to allow the continued pay down of debt. Through these
repayments and

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exchanges of common stock for fixed income securities, debt was again
substantially reduced. Despite capital constraints, the Company managed to
modestly increase production in the course of the year, primarily by bringing
proved non-producing reserves on stream. While production rose during the year,
it fell 17% from the prior year level primarily due to the impact of the Great
Lakes transaction in late 1999. By mid-year 2000, the progress made in
restructuring began to be recognized and the market for the Company's stock
started to rebound. However, due to the lower capital expenditures the Company
was unable to replace production and proved reserves fell 5.4% during the year.

In 2001, the Company increased its capital spending 84% to roughly
$90.0 million. This generated a modest increase in production. The benefits of
sharply higher energy prices and reduced fixed charges allowed for continued
profitability and a further reduction of debt. By year-end 2001, leverage had
been reduced to a more manageable level and the Company was far better
positioned to pursue profitable long-term growth. The Company did not replace
production in 2001 and proved reserves declined 12.1% during the year. However,
the Company replaced production during the fourth quarter of 2001.

For 2002, the Company has announced a $100.0 million capital budget.
Given the current low product price environment, the Company will monitor its
capital expenditures carefully and may elect not to expend the entire budget.
Any decline in capital spending would have an adverse affect on production and
reserve replacement. Based on the authorized level of capital expenditures, the
Company expects to sustain or slightly increase reserves in 2002. The 2002
budget includes $86 million for drilling and recompletions, $11 million for land
and seismic and $3 million for pipelines and facilities.

During the fourth quarter of 2001, the Company recognized property
impairments of $38.9 million including $5.1 million of acreage and $33.8 million
of proved properties. The Company periodically compares the carrying value of
its acreage to estimated fair value based on a variety of factors including
geological and engineering assessments, other acreage transactions in the area,
assessment of value that could be recovered from sale, farmout or exploitation,
timing of the associated drilling program, and the unique nature of the
property. An impairment evaluation of proved properties includes estimated
future cash flows and a risk assessment which includes historical operations and
recoverability of reserves. At year-end 2001, the Company's impairment analysis
for short reserve life properties included consideration of the current low
price environment. Therefore, for such short reserve life properties, the
unescalated prices of $20.38 per bbl of oil and $2.63 per Mmbtu of gas were
utilized in the calculation of impairment. This resulted in a $33.8 million
impairment. The Company's onshore long-life properties were evaluated using a
10-year price strip which averaged $25.29 per bbl of oil and $3.45 per Mmbtu of
gas. No impairment was required for these properties. (See Management's
Discussion and Analysis - Results of Operations.)

DESCRIPTION OF THE BUSINESS

Strategy

Between 1988 and 1997, assets grew from $7 million to $759 million as
stockholders' equity increased from less than $1 million to $197 million. In
1998 and 1999, the Company incurred almost $200 million of losses as a result of
disappointing results on a series of large acquisitions. These losses led to a
series of impairments, up to and including those recorded in the fourth quarter
of 2001. These losses materially reduced stockholders' equity and increased
leverage. The significant improvement in oil and gas prices since mid-1999
combined with the benefits of reduced costs allowed the Company to return to
profitability in 2000 and 2001. In 2001, production began to increase slightly.
The 2002 capital budget of $100.0 million is expected to increase production 5%
or more and expand the reserve base. The Company's hedge position, which covers
approximately 50% of anticipated 2002 production from proved reserves, is
expected to allow the capital program to be funded with internal cash flow even
in this low price environment. However, in such a low price environment,
management expects little excess cash flow to be available for reduction in
debt. Should prices decline further, it would be unlikely that the Company would
be able to fund its entire capital program with internal cash flow. The Company
intends to monitor its capital expenditures closely and results of operations;
therefore, this current low price environment may negatively affect the amount
of capital spending for the year.

At year-end, the Company had almost 1,900 proven development projects
in inventory. Given current oil and gas prices, the Company's hedge position and
this development inventory, the Company believes it can achieve growth in
reserves, production, cash flow and earnings over the next several years while
further reducing debt. The Company currently anticipates spending $100.0 million
on capital expenditures in 2002, although, the current price environment may
affect the actual level of

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spending. The Company's approximately 558,862 gross (284,028 net) acre
undeveloped leasehold position provides significant long-term exploration and
development potential.

Development. Development projects include recompletions of existing
wells, infill drilling and the installation of secondary recovery projects. Such
projects are pursued within core areas where the Company has significant
operational and technical experience. At December 31, 2001, the Company had an
inventory of 1,604 proven drilling locations and 274 proven recompletions.
During 2002, the Company plans to drill 161 proven locations and recomplete 41
wells. In addition, the Company also plans to drill an additional 109 not yet
proven projects in 2002. The following table illustrates the activity for
development projects during 2001:

Exploration. Onshore exploration projects cover 268,122 gross (106,810
net) acres. These projects target deeper horizons in existing fields as well as
prospective fields in trend areas. Offshore exploration focuses on the shallow
waters of the Gulf of Mexico where 3D seismic data covering 3.5 million
contiguous acres are held. The Company has offshore leases covering 174,724
gross (49,055 net) acres on which it has to date identified eleven specific
projects. The Company's exploration strategy is based on limiting risk by
allocating no more than 10% to 15% of the capital budget to such projects. At
times, other companies pay all or a disproportionate share of exploration costs
to earn an interest in a project. The Company currently anticipates
participating in up to thirteen exploratory wells in 2002.

Acquisitions. After a two year period during which the Company withdrew
from the acquisition market, it expects to reactivate this effort in 2002. At
least initially, the focus will be on modest purchases of incremental interests
in existing and adjacent properties. To the extent the acquisition effort is
successfully reinitiated and capital constraints are reduced, a more substantial
effort will be considered in the latter part of 2002.

DEVELOPMENT AND EXPLORATION

In 2001, the Company spent $80.6 million on oil and gas related capital
expenditures, an increase of 59% over that expended in 2000. Of this amount,
$35.8 million was expended in the Southwest, $22.2 million in Appalachia and
$22.6 million in the Gulf Coast. These expenditures were primarily focused on
placing proved non-producing reserves on stream. They funded 51 recompletions,
264 development and 8 exploratory wells, minor lease acquisitions and seismic
work. Exploration and development spending brought 26.1 Bcfe of proved
non-producing reserves on stream and added a net 34.4 Bcfe of new reserves. In
the absence of price revisions, net reserves added during the year replaced 71%
of production.

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Development

Development includes recompletions, infill drilling and to a lesser
extent, installation of secondary recovery projects. As described below, the
Company currently has 1,878 proven recompletion opportunities and drilling
locations in inventory. Drilling prospects are geographically diverse and target
a mix of oil and gas, generally at depths of less than 8,000 feet. Approximately
88% of the proved development locations are concentrated in ten fields covering
824,000 gross (446,000 net) acres. The Company believes that such large acreage
blocks and concentration of to be drilled wells provides economies of scale,
access to competitively priced field services and focused operating and
technical expertise. The following table sets forth information pertaining to
the proven development inventory at December 31, 2001.

Exploration

Onshore. The Company currently has 117 onshore exploration projects
covering 268,122 gross (106,810 net) acres. Each project has multiple drilling
prospects, some with several targeted formations. Given the continuing emphasis
on debt reduction, it is expected that only a limited amount of work will be
done on these projects in 2002.

Gulf of Mexico. The Company owns exclusive license to a 3D seismic
database covering 700 contiguous blocks in the shallow water of the Gulf of
Mexico, primarily offshore Louisiana. In February 2001, a joint venture was
formed between the Company, Callon Petroleum Co. ("Callon") and Cheyenne
Petroleum Company ("Cheyenne") to reprocess the data and utilitze it to identify
and capture exploration and exploitation opportunities in a 3.5 million acre
area. Callon has a 50% interest in the joint venture with the Company and
Cheyenne sharing the remainder. The joint venture was awarded two blocks in the
March 2001 OCS lease sale. The Company's current offshore leasehold inventory
totals only 174,724 gross (49,055 net) acres. To more fully exploit the 3D
seismic data base, it will be necessary to lease or farm in significant
additional acreage. To date, the joint venture has identified 24 specific
prospects and leads on acreage not currently controlled. These projects target
Miocene and Pliocene formations at depths of 3,000 to 16,000 feet.

PRODUCTION

Production revenue is generated through the sale of natural gas, crude
oil and natural gas liquids ("NGL") from properties owned directly or through
partnerships and joint ventures. The Company receives additional revenue from
royalties. Production is sold to a limited number of purchasers of which three
accounted for more than 10% of oil and gas revenues. These three purchasers
currently accounted for 50% of oil and gas revenues in 2001. However, the
Company believes that the loss of any individual customer would not have a
material adverse long-term effect on the Company. Proximity to local markets,
availability of competitive fuels and overall supply and demand are factors
affecting the prices at which production can be marketed. Factors outside the
Company's control, such as international political developments, overall energy
supply and demand, weather conditions, economic growth rates and other factors
in the United States and world economies have had, and will continue to have, a
significant effect on energy prices.

On an mcfe basis, 76% of the Company's production for 2001 was natural gas.
Gas is sold to utilities, marketing companies and industrial users. Gas sales
are made pursuant to various contractual arrangements including month-to-month,
one to three-year contracts at fixed or variable prices and fixed prices for the
life of the well. Contracts other than those with fixed prices contain
provisions for price adjustment, termination and other terms customary in the
industry. From the inception of Great Lakes through June 30, 2001, the joint
venture sold 90% of its gas production to FirstEnergy based on closing prices on
the New York Mercantile Exchange ("NYMEX") plus a basis differential. For the
last six months of 2001, Great Lakes sold 34% of its gas to First Energy, with
the remaining 66% being sold to eight other companies. Currently 91% of Great
Lakes gas is sold at prices based on the close of the NYMEX contract each month
plus a basis differential. The remainder is sold at a fixed price. Oil is sold
under contracts that can be terminated on 30 days notice. The price received is

5

generally equal to a posted price set by major purchasers in the area. Oil
purchasers are selected on the basis of price and service. In 2001, gas revenues
totaled $154.9 million or 74% of oil and gas revenues while revenues from oil
and natural gas liquids totaled $54.6 million. Oil and gas revenues in 2001
increased 21% over the prior year due to a slight increase in production and
substantially higher prices.

TRANSPORTATION, PROCESSING AND MARKETING

Transportation, processing and marketing revenues are comprised of fees
for the transportation and processing of gas as well as oil and gas marketing
income. Transportation, processing and marketing revenues decreased 35% in 2001
to $3.4 million primarily as a result of the sale of the Sterling Plant in April
2000 and lower NGL prices.

The Company's gas transportation and processing assets include (i) 50%
ownership in approximately 4,600 miles of gas pipelines in Appalachia held
through Great Lakes and (ii) a number of smaller gathering systems associated
with the Company's producing properties. The Appalachian gathering systems
transport a majority of Great Lakes' gas production as well as third party gas
to major trunklines and directly to end-users. Third parties who transport gas
through the systems are charged a fee based on throughput. In the Southwest and
Gulf Coast regions gas production is transported through a combination of
Company-owned and third party gathering systems. The Company is typically
charged a fee based on throughput to transport its gas through third party
systems.

The Company markets its own gas production and attempts to reduce the
impact of price fluctuations through hedging. Only 2% of gas production is
currently sold pursuant to fixed price contracts at prices ranging from $1.25 to
$4.73 per mcf (averaging $3.80 per mcf). The remaining 98% of gas production is
sold at market (generally index) related prices.

HEDGING ACTIVITIES

The Company regularly enters into hedging agreements to reduce the
impact on its operations of fluctuations in oil and gas prices. All such
contracts are entered into solely to hedge prices and limit volatility. The
Company's current policy is to hedge between 50% and 75% of its production, when
futures prices justify, on a rolling twelve to eighteen month basis. Due to the
exceptional gas prices in 2001, the Company extended their hedging program into
2005. At December 31, 2001, hedges were in place covering 47.3 Bcf at prices
averaging $4.02 per mcf and 700,000 barrels of oil averaging $25.97 per barrel.
Their fair value, excluding hedge contracts with Enron North America Corp.
("Enron"), represented by the estimated amount that would be realized on
termination, approximated a net unrealized pre-tax gain of $52.1 million ($41.9
million gain net of $10.2 million of deferred taxes) at December 31, 2001, which
is presented on the balance sheet as a short-term gain of $37.2 million and a
long-term gain of $14.9 million based on contract expiration. The contracts
expire monthly through December 2005 and cover approximately 55%, 30%, 15% and
5% of anticipated 2002 through 2005 production from proved reserves,
respectively. Gains or losses on both realized and unrealized hedging
transactions are determined as the difference between the contract price and a
reference price, generally NYMEX. Transaction gains and losses are determined
monthly and are included as increases or decreases in oil and gas revenues in
the period the hedged production is sold. Any ineffective portion of such hedges
is recognized in earnings as it occurs. Net pre-tax losses relating to these
derivatives in 1999, 2000 and 2001 were $10.6 million, $43.2 million, and $6.2
million, respectively. Over the last three years, the Company has recorded
cumulative net pre-tax hedging losses of $60.0 million in income, which, when
combined with the $52.1 million unrealized pre-tax gain at year-end 2001, result
in a $7.9 million cumulative net loss. Effective January 1, 2001, the unrealized
gains (losses) on these hedging positions are recorded at an estimate of fair
value which the Company bases on a comparison of the contract price and a
reference price, generally NYMEX, on the Company's balance sheet as Other
comprehensive income (loss)("OCI"), a component of Stockholders' Equity.

The Company had hedge agreements with Enron for 22,700 Mmbtus per day,
at $3.20 per Mmbtu covering the first three months of 2002. Amounts due from
Enron are not included in the open hedges described in the previous paragraph.
Based on its accountants guidance, the Company has recorded an allowance for bad
debts at year-end 2001 of $1.4 million, offset by a $318,000 ineffective gain
included in income and $1.0 million gain included in OCI at year-end 2001
related to these amounts due from Enron. The gain included in OCI at year-end
2001 will be included in income in the first quarter of 2002. The last of the
Enron contracts will expire in March 2002. While an allowance for bad debts for
the entire estimated fair value of these hedge contracts with Enron has been
recorded, the Company is aware of offers to purchase these contracts at
approximately 25% of par.

6

INDEPENDENT PRODUCER FINANCE ("IPF")

IPF provides capital to small oil and gas producers to finance
acquisition and development projects in exchange for term overriding royalty
interests. The overrides are dollar-denominated and calculated to provide a
contractual rate of return that typically ranges between 15% and 25%. Almost all
of the advances are for less than $5.0 million and most are for $2.0 million or
less. IPF funds itself through a combination of internal cash flow and bank
borrowings. At December 31, 2001, IPF's portfolio included 44 transactions
having an aggregate book value of $41.4 million (net of $17.3 million of
valuation allowances). The portfolio balance declined 15% in 2001 primarily due
to $19.0 million of repayments received during the year. The reserves underlying
IPF's royalty interests are not included in Range's consolidated reserve
disclosure.

IPF provides valuation allowances against advances which may not be
recoverable. These allowances reduce reported revenues. IPF recorded valuation
allowances of $603,000 against its revenues in early 2000. Because of higher
product prices and the resultant increase in cash receipts, IPF reversed $1.9
million of previously reserved amounts in the second half of 2000. Due to the
continued favorable oil and gas prices, $1.8 million of increases in receivables
were also recorded as additional income in the first nine months of 2001.
However, because of lower product prices, IPF increased its reserve allowance by
$2.0 million in the fourth quarter of 2001. IPF expenses include general and
administrative costs and interest expense, which totaled $4.9 million and $3.6
million, respectively, in 2000 and 2001. At year-end commodity prices, the
Company believes that IPFs valuation allowances were adequate.

IPF has two petroleum engineers with an average of 19 years of
experience who identify and evaluate projects. The staff is responsible for
defining transaction risk, assessing reserve coverage and negotiating terms.
Transactions are structured to minimize risk by focusing on asset coverage and
taking direct title to the royalty interests. As dollar-denominated royalties,
the transactions leave a portion of the commodity price risk with the producer.
However, when extreme price declines occur, as they did in 1998 and 1999, IPF is
exposed to substantial losses.

IPF provides capital to parties who are generally ignored by
traditional financial institutions. These producers are typically denied access
to financing because: (i) they are too small to access the public securities
markets; (ii) private equity and debt financing is too restrictive and
expensive; and (iii) few commercial banks are interested in small energy loans
as consolidation in the banking industry has raised the size threshold for
lending. IPF's portfolio decreased in 2001 as a limited number of fundings were
more than offset by principal repayments. IPF's bank debt is non-recourse to
Range.

IPF investments involve the purchase of a term overriding royalty
interest pursuant to which it receives a specified share of revenues from
specific properties. The producer's obligation is non-recourse unless he fails
to operate prudently, there is title failure and in certain other circumstances.
Consequently, IPF's success is based on its ability to accurately estimate
reserves underlying its royalty, the prices at which the production will be
sold, and the operator's ability to recover the reserves on a timely and cost
efficient basis. Because the override is considered a property interest, if a
producer goes bankrupt, IPF's interest should be beyond the reach of creditors.
If a creditor, the producer as debtor-in-possession or a trustee in a bankruptcy
proceeding were to argue successfully that the transaction should be
characterized as a loan, IPF may have only a creditor's claim for repayment.
IPF's ownership in these production payments is a non-operated interest. While
IPF is unlikely to be exposed to liabilities associated with direct working
interests, such as environmental matters, personal injuries or death and
property damage, such events could result in a loss of IPF's economic interest
in the properties. The producer's obligation to deliver a specified share of
revenues to IPF is subject to the ability of the burdened reserves to produce
such revenues. As a result, IPF bears the risk that revenues will not be
sufficient to amortize its investment or provide an acceptable return.

IPF was acquired in 1998. The following table summarizes IPF's
historical investments:

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INTEREST AND OTHER

The Company earns interest on cash balances and certain receivables.
Interest and other income in 2000 was comprised principally of losses on
property sales. The Company expects to continue to sell non-strategic
properties. In 2001, Interest and other income also includes ineffective hedging
gains or losses. The 2001 period included $2.3 million of the ineffective
hedging gains and a $689,000 gain on asset sales partially offset by a $1.7
million writedown of marketable securities and a $1.4 million bad debt expense
related to the Enron hedges. Interest and other income in 2001 amounted to
$490,000, representing 0.2% of revenues.

COMPETITION

The Company encounters substantial competition in acquiring oil and gas
leases, marketing its production, securing personnel and conducting drilling and
field operations. Competitors in development, exploration, acquisitions and
production include the major oil companies as well as numerous independents,
individual proprietors and others. Many competitors have financial and other
resources substantially exceeding those of the Company. Therefore, competitors
may be able to pay more for desirable leases and to evaluate, bid for and
purchase a greater number of properties or prospects than the financial or
personnel resources of the Company permit. The ability of the Company to replace
and expand its reserve base will depend on its ability to identify and acquire
suitable producing properties and prospects for future drilling.

Acquisitions have generally been financed through the issuance of debt
and equity securities and internally generated cash flow. There is competition
for capital to finance oil and gas projects. The ability of the Company to
obtain financing on satisfactory terms is uncertain and can be affected by
numerous factors beyond its control. The inability of the Company to raise
external capital in the future could have a material adverse effect on its
business.

The Company currently has three issues of debt outstanding in addition
to its bank debt. The 8.75% senior subordinated notes, 6% convertible debentures
and 5.75% trust preferred had a combined book value of $198.4 million at
December 31, 2001. Their combined fair market value, based on market quotes, was
$148.5 million. The Company has in the past and expects to continue in the
future to exchange equity for these debt instruments. Such exchanges could have
a dilutive effect on existing shareholders.

GOVERNMENTAL REGULATION

The Company's operations are affected in varying degrees by federal,
state and local laws and regulations. In particular, oil and gas production and
related operations are or have been subject to price controls, taxes and other
laws and regulations. Failure to comply with such laws and regulations can
result in substantial penalties. The regulatory burden on the industry increases
the Company's cost of doing business and affects its profitability. Although the
Company believes it is in substantial compliance with all applicable laws and
regulations, because such laws and regulations are frequently amended or
reinterpreted, the Company is unable to precisely predict the future cost or
impact of complying.

THE RESTRUCTURING

A series of significant acquisitions financed principally with debt and
convertible securities were completed between late-1997 and mid-1998. Due to the
poor performance of the acquired properties compounded by a decline in oil and
gas prices which began in late 1997, the Company was forced to take a number of
steps. These included a workforce reduction, a significant decrease in capital
expenditures, the sale of assets, the formation of Great Lakes and the exchange
of common stock for fixed income securities. Between year-end 1998 and December
31, 2001, these initiatives reduced parent company bank debt from over $365.0
million to $95.0 million. Total debt, including trust preferred, has been
reduced 46% to $392.2 million. While the Company believes its financial position
has stabilized, management believes debt remains too high. To return to its
historical posture of consistent profitability and growth, the Company believes
it should further reduce debt. The Company expects to utilize excess cash flow
to retire debt and to continue to exchange additional stock for indebtedness.
Stockholders could be materially diluted if a substantial amount of fixed income
securities are exchanged for stock. Since 1998, 8.2 million shares of common
stock have been issued in exchange for debt and 5.4 million shares have been
exchanged for $2.03 preferred stock for a total of 13.6 million shares. The
shares were exchanged for $56.7 million face value of 8.75% senior subordinated
notes, 6% convertible debentures, 5.75% trust preferred securities and $28.7
million of $2.03 preferred

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stock for a total of $85.4 million. The extent of any future dilution will
depend on a number of factors, including the number of shares issued, the price
at which stock is issued or any newly issued securities are convertible into
common stock and the price at which fixed income securities are reacquired.
While such exchanges reduce existing stockholders' proportionate ownership,
management believes they enhance financial flexibility and will ultimately
increase the value of the Company's stock.

The Company believes it has sufficient liquidity and cash flow to meet
its obligations. However, a material decline in oil and gas prices or a
reduction in production and/or reserves would reduce its ability to fund capital
expenditures, meet financial obligations and reduce leverage. In addition, the
Company's high depletion depreciation and amortization ("DD&A") rate may make it
difficult to remain profitable if oil and gas prices decline further.

ENVIRONMENTAL MATTERS

The Company's operations are subject to stringent federal, state and
local laws governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental
departments such as the Environmental Protection Agency ("EPA") issue
regulations to implement and enforce such laws, which are often difficult and
costly to comply with and which carry substantial civil and criminal penalties
for failure to comply. These laws and regulations may require the acquisition of
a permit before drilling commences, restrict the types, quantities and
concentrations of various substances that can be released into the environment
in connection with drilling, production and transporting through pipelines,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands, frontier and other protected areas, require some form of remedial
action to prevent pollution from former operations such as plugging abandoned
wells, and impose substantial liabilities for pollution resulting from
operations. In addition, these laws, rules and regulations may restrict the rate
of production. The regulatory burden on the oil and gas industry increases the
cost of doing business and affects profitability. Changes in environmental laws
and regulations occur frequently, and changes that result in more stringent and
costly waste handling, disposal or clean-up requirements could adversely affect
the Company's operations and financial position, as well as the industry in
general. Management believes the Company is in substantial compliance with
current applicable environmental laws and regulations. The Company has not
experienced any material adverse effect from compliance with environmental
requirements, there is no assurance that this will continue. The Company did not
have any material capital expenditures in connection with environmental matters
in 2001, nor does it anticipate that such expenditures will be material in 2002.

The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to be responsible for the release of a "hazardous substance"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed of
or arranged for the disposal of the hazardous substances at the site where the
release occurred. Under CERCLA, such persons 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. It is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damages
allegedly caused by the release of hazardous substances or other pollutants into
the environment. Furthermore, although petroleum, including crude oil and
natural gas, is exempt from CERCLA, at least two courts have ruled that certain
wastes associated with the production of crude oil may be classified as
"hazardous substances" under CERCLA and that such wastes may become subject to
liability and regulation under CERCLA. State initiatives to further regulate the
disposal of oil and gas wastes are pending in certain states and these
initiatives could have a significant impact on the Company.

The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of produced waters and other oil and
gas wastes into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters. The FWPCA and analogous state laws
provide for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other hazardous substances in reportable quantities and
may impose substantial potential liability for the costs of removal, remediation
and damages. State water discharge regulations and the federal National
Pollutant Discharge Elimination System general permits applicable to the oil and
gas industry generally prohibit the discharge of produced water, sand and some
other substances into coastal waters. The cost to comply with zero discharges
mandated under federal and state law have not had a material adverse impact on
the Company's financial condition and results of operations. Some oil and gas
exploration and production facilities are required to obtain permits for their
storm water discharges. Costs may be incurred in connection with treatment of
wastewater or developing storm water pollution prevention plans.

9

The Resources Conservation and Recovery Act ("RCRA"), as amended,
generally does not regulate most wastes generated by the exploration and
production of oil and gas. RCRA specifically excludes from the definition of
hazardous waste "drilling fluids, produced waters, and other wastes associated
with the exploration, development, or production of crude oil, natural gas or
geothermal energy." However, these wastes may be regulated by the EPA or state
agencies as solid waste. Moreover, ordinary industrial wastes, such as paint
wastes, waste solvents, laboratory wastes and waste compressor oils, are
regulated as hazardous wastes. Although the costs of managing solid hazardous
waste may be significant, the Company does not expect to experience more
burdensome costs than similarly situated companies.

The U.S. Oil Pollution Act ("OPA") requires owners and operators of
facilities that could be the source of an oil spill into "waters of the United
States" (a term defined to include rivers, creeks, wetlands and coastal waters)
to adopt and implement plans and procedures to prevent any spill of oil into any
waters of the United States. OPA also requires affected facility owners and
operators to demonstrate that they have at least $35 million in financial
resources to pay for the costs of cleaning up an oil spill and compensating any
parties damaged by an oil spill. Substantial civil and criminal fines and
penalties can be imposed for violations of OPA and other environmental statutes.

Stricter standards in environmental legislation may be imposed on the
oil and gas industry in the future. For instance, legislation has been proposed
in Congress from time to time that would reclassify certain oil and gas
exploration and production wastes as "hazardous wastes" and make the waste
subject to more stringent handling, disposal and clean-up restrictions. If such
legislation were enacted, it could have a significant impact on the Company's
operating costs, as well as the industry in general. Compliance with
environmental requirements generally could have a material adverse effect on the
capital expenditures, earnings or competitive position of the Company. Although
the Company has not experienced any material adverse effect from compliance with
environmental requirements, no assurance may be given that this will continue.

RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE SAFE HARBOR PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Certain information included in this report, other materials filed or
to be filed by the Company with the Securities and Exchange Commission ("SEC"),
as well as information included in oral statements or other written statements
made or to be made by the Company contain or incorporate by reference certain
statements (other than statements of historical fact) that constitute
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used
herein, the words "budget," "budgeted," "assumes," "should," "goal,"
"anticipates," "expects," "believes," "seeks," "plans," "estimates," "intends,"
or "projects" and similar expressions that convey the uncertainty of future
events or outcomes are intended to identify forward-looking statements. Where
any forward-looking statement includes a statement of the assumptions or bases
underlying such forward-looking statement, we caution that while we believe
these assumptions or bases to be reasonable and to be made in good faith,
assumed facts or bases almost always vary from actual results and the difference
between assumed facts or bases and the actual results could be material,
depending on the circumstances. It is important to note that our actual results
could differ materially from those projected by such forward-looking statements.
Although we believe that the expectations reflected in such forward-looking
statements are reasonable and such forward-looking statements are based upon the
best data available at the date this report is filed with the SEC, we cannot
assure you that such expectations will prove correct. Factors that could cause
our results to differ materially from the results discussed in such
forward-looking statements include, but are not limited to, the following:
production variance from expectations, volatility of oil and gas prices, hedging
results, the need to develop and replace reserves, the substantial capital
expenditures required to fund operations, exploration risks, environmental
risks, uncertainties about estimates of reserves, competition, litigation,
government regulation, political risks, and our ability to implement our
business strategy. All such forward-looking statements in this document are
expressly qualified in their entirety by the cautionary statements in this
paragraph.

With the previous paragraph in mind, you should consider the following
important factors that could cause actual results to differ materially from
those expressed in any forward-looking statement made by the Company or on its
behalf.

10

Common shareholders will be diluted if additional shares are issued

The Company has filed shelf registration statements which allow it to
issue additional common stock and the Company has exchanged common stock for its
fixed income securities over the past three years. In 1999, 2000 and 2001, the
Company exchanged common stock for 5 3/4% trust convertible preferred
securities, 6% convertible debentures, 8.75% senior subordinated notes and $2.03
convertible preferred stock. The exchanges were made based on the relative
market value of the common stock and the convertible securities at the time of
the exchange, incorporating negotiated terms ranging from a 10% discount to a 4%
premium, in 2001. In 2001, the convertible securities were acquired at discounts
to their face value ranging from 4% to 44%. During 2000, $25.0 million of trust
preferred, $13.8 million of 6% convertible debentures and $23.2 million of $2.03
convertible preferred stock was acquired in exchange for common stock. During
2001, $2.9 million of trust preferred, $5.7 million of 6% convertible
debentures, $5.4 million of $2.03 convertible preferred stock and $3.4 million
of 8.75% senior subordinated notes was acquired in exchange for common stock.
Since 1998, $85.4 million face value of convertible securities have been
exchanged for 13,568,000 shares of common stock. See Notes 6 and 9 to the
financial statements. While the exchanges reduce interest expense, dividends and
future repayment obligations, the larger number of common shares outstanding
have a dilutive effect on existing shareholders. The Company's ability to
repurchase additional convertible securities is limited by the parent credit
facility and the 8.75% senior subordinated notes restricted payment baskets. As
of December 31, 2001, the Company has only $3.0 million available under the most
restrictive basket. The amount of the restrictive baskets limit the Company's
flexibility in repurchasing debt securities at attractive discounts to par, when
they become available. Therefore, the Company may seek changes in these
covenants.

The Company continues to review alternatives to further strengthen its
balance sheet and to retire debt and convertible securities. Several
alternatives involve the issuance of a large number of shares of common stock.
Therefore, such alternatives could materially dilute current shareholders. The
Company expects to continue to exchange common stock or other equity linked
securities for its fixed income securities. While the Company anticipates
reacquiring fixed income securities at a discount to face value, existing
stockholders will be substantially diluted if material portions of the fixed
income securities are exchanged. The extent of dilution will depend on various
factors, including the number of shares issued, the price at which newly issued
securities are convertible into common stock and the price at which fixed income
securities are reacquired. While such exchanges reduce existing stockholders'
proportionate ownership, management believes they enhance financial flexibility
and will ultimately increase the market value of the Company's common stock. The
Company's ability to consummate exchanges and the terms of the exchanges is
dependent on a number of factors beyond its control, such as the level of
various interest rates, the willingness of other parties to engage in
transactions, state and federal regulations covering such transactions and
capital market conditions.

Dividend restrictions

Restrictions on the payment of dividends and other restricted payments
as defined are imposed under the Company's bank credit agreements and the 8.75%
senior subordinated notes. No common dividends may be paid under the current
bank agreement. Partially in response to these restrictions, a new $2.03
Convertible Exchangeable Preferred Stock Series D was authorized in September
2000. The Series D had terms substantially identical to the previously
outstanding Series C except that dividends could be paid in common stock. In
November 2000, 91% of the Series C was exchanged for Series D. In December 2000,
62% of the Series D was exchanged for common stock and the Company elected to
pay fourth quarter 2000 Series D dividends in common stock. Fourth quarter 2000
dividends paid on the Series C amounted to only $10,000. During 2001, all
remaining shares of Series D and all remaining shares of Series C were
repurchased or exchanged for common stock.

The terms of the 8.75% senior subordinated notes limited restricted
payments (including dividends) to the greater of $20.0 million or a formula
based on earnings since the issuance of the notes. Given the Company's losses
over the past few years, the formula provides no availability. Therefore, the
Company must rely on the $20.0 million basket. At December 31, 2001, only $3.0
million of the $20.0 million basket remained available. The covenant limits the
Company's flexibility in continuing to reduce debt. The Company may attempt to
change this basket restriction.

Oil and gas prices are volatile, which can adversely affect cash flow available
for reinvestment

The oil industry is cyclical and prices for oil and gas are volatile.
Historically, the industry has experienced severe downturns characterized by
oversupply and/or weak demand. Many factors affect oil and gas prices including
general economic conditions, consumer preferences, discretionary spending
levels, interest rates and the availability of capital to the

11

industry. In 1998 and early 1999, oil and gas prices fell substantially, which
contributed to the substantial losses reported by the Company in those years. By
early 2001, oil and gas prices reached levels substantially above their
historical norm. Since that time, prices have declined significantly. Decreases
in oil and gas prices from current levels could adversely affect the Company's
revenues, net income, cash flow and proved reserves. Significant and prolonged
price decreases could have a materially adverse effect on the Company's
operations and limit its ability to fund capital expenditures. To help limit
this risk, the Company has entered into hedging agreements covering
approximately 55% and 30% of its anticipated production from proved reserves on
an mcfe basis for 2002 and 2003, respectively and lesser amounts of 2004 and
2005 production. However, if prices rise above the level at which the hedges
were entered into, they would limit the benefit of the rise in prices.

Hedging activities expose us to certain risks

We enter into hedging arrangements covering a portion of our future
production to limit volatility and increase the predictability of cash flow.
Hedging instruments are generally fixed price swaps but have at times included
or may include collars, puts and options on futures. While hedging limits our
exposure to adverse price movements, hedging limits the benefit of price
increases and is subject to a number of risks, including the risk the
counterparty to the hedge may not perform.

Estimates of oil and gas reserves may change; we may not replace production

The information on proved oil and gas reserves included in this
document are simply estimates. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment, assumptions used regarding quantities of oil and
gas in place, recovery rates and future prices for oil and gas. Actual prices,
production, development expenditures, operating expenses and quantities of
recoverable oil and gas reserves will vary from those assumed in our estimates,
and such variances may be significant. If the assumptions used to estimate
reserves later prove incorrect, the actual quantity of reserves and future net
cash flow could be materially different from the estimates used herein. In
addition, results of drilling, testing and production along with changes in oil
and gas prices may result in substantial upward or downward revisions.

Without success in exploration, development or acquisitions, our
reserves, production and revenues from the sale of oil and gas will decline over
time. Exploration, the continuing development of our properties and acquisitions
all require significant expenditures as well as expertise. If cash flow from
operations proves insufficient for any reason, we may be unable to fund
exploration, development and acquisitions at levels we deem advisable.

Our oil and gas properties' carrying value have been and may continue to be
written down

Accounting rules require that the carrying value of oil and gas
properties be periodically reviewed for possible impairment. An "impairment" is
recognized when the book value of a proven property is greater than the expected
undiscounted future cash flows from that property and on acreage when the
assessment of fair value is less than the book value. We may be required to
write down the carrying value of a property based on oil and gas prices at the
time of the impairment review, as well as a continuing evaluation of development
results, production data, economics and other factors. While an impairment
charge does not impact cash or cash flow from operating activities, it reduces
earnings, increases leverage ratios and reflects the long-term ability to
recover a prior investment.

Based primarily on the poor performance of certain properties acquired
between late-1997 and mid-1998 and significantly decreased oil and gas prices,
we recorded impairments of $197 million in 1998 and $27 million in 1999. In
2000, no impairments were required. At year-end 2001, an impairment of $38.9
million was recorded. (See Management's Discussion and Analysis - Results of
Operations.) For a further discussion of our accounting policies with respect to
oil and gas properties, see Note 2 to the Consolidated Financial Statements.

We could incur substantial environmental liabilities

Our industry is subject to numerous federal, state and local laws and
regulations relating to the environment. We may incur significant costs and
liabilities in complying with existing or future environmental laws and
regulations. It is possible that increasingly strict environmental laws,
regulations and enforcement policies or claims for damages to property,
employees, other persons and the environment resulting from current or
discontinued operations, could result in substantial costs and liabilities in
the future. For additional information concerning environmental matters, see the
"Business-Environmental Matters."

12

Our activities involve operating hazards and uninsured risks

While we maintain insurance against certain of the risks associated
with our operations, including, but not limited to, explosion, pollution and
fires, an event against which we are not fully insured could have a significant
negative effect on our business. Such occurrences could include title defects on
properties, lost equipment in drilling operations when the drilling contractor
is not responsible for such loss, costs to redrill wells due to down hole
equipment and casing failures, and property damage caused over a period of time
not covered by standard industry insurance policies.

We maintain insurance in amounts and areas of coverage normal for a
company of our size and industry. These include, but are not limited to,
workers' compensation, employers' liability, automotive liability and general
liability. In addition, umbrella liability and operator's extra expense policies
are maintained. All such insurance is subject to normal deductible levels. We do
not insure against all risks associated with our business either because
insurance is unavailable or because we elect not to insure due to cost or other
considerations.

Individuals or companies who feel the Company or those acting on its
behalf damaged them physically or financially, have the right under the law to
seek recovery in court. In today's legal climate, the likelihood of suits
continues to increase. As verdicts or judgments are so uncertain, the Company
may elect to settle claims. Settlements may not be covered by insurance and
costs might have to be borne solely by the Company. Even when the Company elects
to contest a claim, it may be held liable by the courts. Often, the cost of
defending oneself or one's rights cannot be recovered from the other parties
even if you prove successful and the costs must be borne solely by the Company.
Such costs and settlements could have a material adverse effect on the Company's
financial position. See Item 3 "Legal Proceedings" included in this report and
Note 8 to Consolidated Financial Statements as to certain proceedings and
contingencies.

We are subject to financing and interest rate exposure risks

Our business and operating results can be harmed by factors such as the
availability and cost of capital, increases in interest rates, changes in the
tax rates, market perceptions of the oil and gas industry or the Company, or a
reduction in credit rating. These changes could cause our cost of doing business
to increase, limit our ability to pursue opportunities and place us at a
competitive disadvantage. At December 31, 2001, the Company had a portion of its
borrowings subject to interest rate swap agreements. See Note 7 to the financial
statements.

We face considerable competition

We face competition in every aspect of our business, including, but not
limited to, acquiring reserves, leases, obtaining goods, services, and employees
needed to operate and manage the Company, and marketing oil and gas. Competitors
include multinational oil companies, independent production companies and
individual producers and operators. Many of our competitors have greater
financial and other resources than we do.

The oil industry is subject to extensive regulation

The oil industry is subject to various types of regulations in the
United States by local, state and federal agencies. Legislation affecting the
industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Numerous departments and agencies, both state
and federal, are authorized by statute to issue rules and regulations binding on
the industry and participants in it. Compliance with such rules and regulations
is often difficult and costly and may carry substantial penalties for
non-compliance. As the regulatory burden on the industry increases, the cost of
complying affects profitability. Generally these burdens do not appear to affect
the Company to any greater or lesser extent than other companies in the industry
with similar types and quantities of properties in the same areas of the
country.

Our high fixed charge burden could impact our liquidity, profitability and cash
flow

The Company pays significant interest charges associated with its bank
debt, 8.75% senior subordinated notes, 6% convertible debentures and 5.75% trust
preferred. The Company's bank debt is at floating interest rates and the other
debt securities are at fixed interest rates. At December 31, 2001, the face
value of the Company's fixed rate obligations totaled $198.4 million and the
annual associated interest payments, based on rates in effect at that date
totaled $13.9 million a year.

13

In addition, these obligations have certain requirements that the Company must
meet to avoid the acceleration of the maturity of these instruments. See Note 6
to the Consolidated Financial Statements for their stated maturities. The
acceleration of the maturity of one or more of such obligations could have a
material adverse effect on the Company.

The Company's significant debt burden could have other important
consequences such as, but not limited to, requiring the sale of assets at
unfavorable prices, the impact of an increase in interest rates which would
increase financing costs and limit capital available for developing and
acquiring new properties, limit the ability to raise capital in the equity
and/or debt markets, preclude financing options available to less leveraged
companies, and make the Company more vulnerable to losses during periods of low
oil and gas prices.

Risks associated with IPF

IPF purchases term overriding royalty interests through which it
receives an agreed upon share of revenues from certain properties. The
producer's obligation to deliver revenues to us is non-recourse. Consequently,
IPF can only recover its investment and a return through revenues from those
properties. These revenues are subject to our ability to accurately estimate
reserves and production rates and the operator's ability to produce and recover
these reserves. In summary, IPF bears the risk that future revenues it receives
will be insufficient to amortize the price paid for its overrides or to provide
an acceptable return. IPF's production, on a net equivalent barrel basis, is
more than 80% oil. Any further decline in oil prices, may cause additional
increases in the IPF valuation allowance.

Acquisitions are subject to numerous risks

It generally is not feasible to review in detail every individual
property acquired. Ordinarily, a review is focused on higher-valued properties.
However, even a detailed review of all properties and records may not reveal
existing or potential problems, nor will it permit us to become sufficiently
familiar with the properties to assess fully their deficiencies and
capabilities. We do not always inspect every well we acquire, and environmental
problems, such as groundwater contamination, are not necessarily observable even
when an inspection is performed. In late 1997 and 1998, a series of acquisitions
were consummated which proved extremely unsuccessful. Ongoing results showed the
potential of the properties was far less than our engineering and geological
review, as well as a review by one of our independent petroleum engineering
firms, had suggested.

Our Chairman has an interest in another oil and gas company that could compete
with us

Our Chairman also serves as the Chairman and Chief Executive Officer of
Patina Oil & Gas Corporation, a publicly traded oil and gas company in which he
is a significant investor. He is also an officer, director and/or significant
investor in several other public and private companies engaged in various
aspects of the energy industry. We currently have no business relationship with
any of these companies, none of them owns our securities nor do we hold any of
theirs. Historically, no material conflict has arisen with regard to these
companies. However, conflicts of interests may arise. Board policies are in
place that require Mr. Edelman, along with all other officers and directors, to
give us notification of any potential conflicts that arise. However, we cannot
assure you that we will not compete with one or more of these companies,
particularly for acquisitions, or encounter other conflicts of interest in the
future.

Success depends on key members of our management

The Company's success is highly dependent on its senior management
personnel, of which only one is currently subject to an employment contract. The
loss of one or more of these individuals could have a material adverse effect on
the Company.

EMPLOYEES

As of January 1, 2002, the Company had 141 full time employees, 54 of
whom were field personnel. None are covered by a collective bargaining
agreement. Management believes its relationship with employees is good.

14

ITEM 2. PROPERTIES

On December 31, 2001, the Company held working interests in 9,719 gross
(4,743 net) productive wells and royalty interests in an additional 215 wells.
Including its 50% share of Great Lakes' reserves, its properties contained, net
to its interest, estimated proved reserves of 389 Bcf of gas and 21 million
barrels of oil and NGL or a total of 513 Bcfe.

PROVED RESERVES

The following table sets forth estimated proved reserves over the past
five years.

(a) Oil and NGL are converted to mcfe at a rate of 6 (m)cf per barrel.

At year-end 2001, the Company engaged the following independent
petroleum consultants to evaluate its reserves: H.J. Gruy and Associates, Inc.
(Southwest), DeGolyer and MacNaughton (Southwest and Gulf Coast), and Wright and
Company, Inc. (Appalachia). These engineers were employed primarily based on
their geographic expertise as well as their history in engineering certain
properties. At December 31, 2001, these consultants collectively evaluated
approximately 82% of the proved reserves set forth above. The remainder were
evaluated by the internal engineering staff. All estimates of oil and gas
reserves are subject to significant uncertainty.

The following table sets forth the estimated future net revenues,
excluding open hedging contracts, from proved reserves, the Present Value of
those revenues and the realized prices over the past five years (in millions).

Future net revenues represent future revenues from the sale of proved
reserves net of production and development costs (including production and ad
valorem taxes and operating expenses). Such calculations, prepared in accordance
with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," are
based on costs and prices in effect at December 31, 2001. Average product prices
(average of the last three days NYMEX) at December 31, 2001 were $17.59 per
barrel of oil, $12.38 per barrel for natural gas liquids, and $2.70 per mcf of
gas using benchmark NYMEX prices of $20.38 per barrel and $2.63 per Mmbtu. There
can be no assurance that the proved reserves will be produced within the periods
indicated or that

15

prices and costs will remain constant. There are numerous uncertainties inherent
in estimating reserves and related information and different reservoir engineers
often arrive at different estimates for the same properties. No estimates of
reserves have been filed with or included in reports to another federal
authority or agency since year-end.

SIGNIFICANT PROPERTIES

The Company's proved reserves at December 31, 2001 were concentrated in
three regions, Southwest, Gulf Coast and Appalachia. The Southwest is divided
into the Permian and Midcontinent divisions. The Appalachian properties
represent the Company's 50% ownership in Great Lakes. At year-end, the Company's
properties included working interests in 9,719 gross (4,743 net) productive oil
and gas wells and royalty interests in 215 additional wells. The Company also
held interests in 558,862 gross (284,028 net) undeveloped acres. The following
table sets forth summary information with respect to estimated proved reserves
at December 31, 2001.

SOUTHWEST REGION

The Southwest region has production and field operations located in the
Permian Basin of West Texas and the East Texas Basin (the Permian division) as
well as in the Texas Panhandle and the Anadarko Basin of western Oklahoma (the
Midcontinent division.) This region represents 41% of total reserve value and
40% of its total reserve volume. Proved reserves totaled 206 Bcfe, of which 60%
was gas. The Southwest's daily production volume of 64.6 Mmcfe per day
represents approximately 42% of total daily production.

At December 2001, the Southwest region properties had a development
inventory of 176 proven recompletions and 120 proven drilling locations. Acreage
owned by the Southwest region at December 31, 2001 included 269,242 gross
(191,813 net) developed acres and 128,372 gross (107,821 net) undeveloped acres.
During 2001, 42 development wells (27.4 net) were drilled, of which 38 (24.2
net) were productive. One exploratory well (one net) was drilled which was
productive.

Permian. The Permian division's total proved reserves at December 31,
2001 contained 147 Bcfe, down 16% compared to year-end 2000. This change was due
90% to lower commodity prices year-over-year and 10% to poor well performance.
These reserves represented 29% by volume and 28% by value of total proved
reserves and were 53% oil and NGL. In the fourth quarter of 2001, net production
averaged 3,612 barrels of oil and NGLs and 23.9 Mmcf of gas per day, or 45.6
Mmcfe per day in total. On an annual basis, production increased 1% to 47.6
Mmcfe per day. Producing wells total 1,347 (1,046 net), of which the Company
operates approximately 90%. At December 31, 2001, the Permian division had a
development inventory of 148 proven recompletions and 108 proven drilling
locations. Acreage owned by the Permian division at December 31, 2001 included
68,922 gross (64,673 net) developed acres and 113,561 gross (96,890 net)
undeveloped acres. In 2001, $24.9 million of capital funded the drilling of 21
development wells (14.4 net), 18 (12.2 net) were productive and one exploratory
well (one net) which was productive. During the year, the division achieved an
86% drilling success rate.

In East Texas, the Permian division participated in the drilling of two
gross (0.4 net) horizontal wells in the James Lime formation, a fractured
carbonate. Both wells were successfully completed for combined initial rates of
13 (3.5 net) Mmcfe per day. Also in East Texas, the Company drilled its first
Bossier sand test (the Linder #1). The well was unsuccessful in the Bossier
formation at depths ranging from 11,500 to 12,500 feet. However, the Linder #1
was successfully

16

recompleted uphole in the Travis Peak formation yielding rates of 3.0 (2.5 net)
Mmcfe per day. To date, Range has accumulated an acreage position in East Texas
totaling 34,600 (11,000 net) acres in the horizontal James Lime play and 31, 600
(21,400 net) acres in the Bossier sand play. Further Bossier drilling has been
deferred, pending the results of a thorough technical review; however the
Company plans to continue drilling in the Travis Peak formation. At year-end
2001, acreage in East Texas was impaired by $825,000 to reflect the lack of
success in the Bossier sand. (See Management's Discussion and Analysis - Results
of Operations.)

In West Texas, the Permian division had disappointing drilling results
in 2001 at the Powell Ranch in Glasscock County, Texas. Between 1997, when Range
acquired the property, and year-end 2000, Range drilled 11 seismically
identified locations with six successes for a 55% success rate. Of the five
wells drilled at Powell Ranch in 2001, three were dry and two were productive.
Current total net production from the field is 9.5 Mmcfe per day.

In other West Texas drilling, 5 gross (5 net) wells successfully
drilled in 2001 in the Sterling Field of West Texas. Three of these wells
expanded the productive limits of this field on its eastern edge. Current total
net production from this field approximates 11.0 Mmcfe per day.

Midcontinent. In the Midcontinent division, total proved reserves at
December 31, 2001 were 58.8 Bcfe, about the same as a year earlier. In 2001,
production climbed 14% to an average of 17.0 Mmcfe per day. December 2001
production reached 19.9 Mmcfe per day as the result of successful drilling,
recompletion and workover activities. During 2001, $17.8 million of capital was
spent to drill 21 (13.0 net) development wells and to recomplete 10 (6.9 net)
wells. Twenty (12.0 net) of the development wells proved successful, resulting
in a 92% success rate.

In the Texas Panhandle, 6 (5.9 net) wells were drilled. As of December
2001, four of the wells were producing 4.5 Mmcfe per day net to Range, one of
the wells was being completed and one was abandoned as a dry hole. The most
significant completion in the Texas Panhandle was the Pioneer #1, which targeted
the Upper Morrow sands, and is producing 4 (3.2 net) Mmcfe per day. The
offsetting Pioneer #2 is currently being completed in the Upper and Lower Morrow
sands. The Saturn #1, which was the only dry hole in the area, was abandoned due
to lack of reservoir quality sand in the Upper Morrow.

In four trends in the Anadarko Basin, including the Sooner, Watonga
Chickasha, Granite Wash and Northwest Shelf, 15 (7.8 net) wells were drilled in
2001. The only dry hole in the area was the Dalton #1, which was abandoned due
to a pipe failure but later successfully redrilled. Notable in this area was the
Gemini #1, which was completed in the Granite Wash and is producing in excess of
1.5 Mmcfe (1.1 net) per day. The division plans to drill at least two offsets to
the Gemini #1 in 2002. In addition, a significant workover was performed on the
Greene #1, which increased production to 1.8 Mmcfe per day (1.4 net). An offset
to the Greene #1 is currently being drilled. The 340 (199 net) producing wells
in the Midcontinent are 92% operated.

GULF COAST REGION

The Gulf Coast region represents 24% of total reserve value and 19% of
total reserve volumes of the Company. Proved reserves totaled 95.7 Bcfe, down
13% from 110 Bcfe at year-end 2000. In 2001, the region only partially replaced
the reserves lost through property dispositions of 2.6 Bcfe and the production
of 20 Bcfe. Gulf Coast reserves are 88% natural gas. Properties are located in
the shallow waters of the Gulf of Mexico and onshore in Texas, Louisiana and
Mississippi. The region's wells are characterized by high initial rates and
relatively short reserve lives. Production by the region represented 36% of the
Company's total average daily production. Major onshore fields include Alta Mesa
in Brooks County, Texas, which produces from depths of 6,000 to 7,000 in the
Frio and Vicksburg formations, and Oakvale, in Jefferson Davis County,
Mississippi, which produces at depths ranging from 15,000 to 16,500 feet in the
Sligo and Hosston formations. Offshore properties include interests in 50
platforms in water depths ranging from 20 to 210 feet, none of which are
operated. The Gulf Coast's development inventory includes 47 recompletions and
16 drilling locations on 155,020 gross (43,277 net) developed acres and 93,388
gross (22,245 net) undeveloped acres. At year-end 2001, the Company impaired
acreage by $4.3 million and proved properties by $33.8 million in the Gulf Coast
region. (See Management's Discussion and Analysis - Results of Operations.)

In 2001, the region spent $23.1 million to drill 13 (4.2 net) wells,
recomplete 10 (4.1 net) others and to upgrade facilities. In addition, the
division participated in the abandonment of one platform and reduced its overall
plugging and abandonment exposure through assignment of its Chandeleur 37
facility and a property trade at West Delta 30. In the fourth

17

quarter of 2001, net production averaged 782 barrels of oil and 48.6 Mmcf of gas
per day or 53.3 Mmcfe per day in total. On an annual basis, production declined
4% to 55.5 Mmcfe per day due to the natural decline of mature properties. In
total, the onshore properties include 56 wells (40 net), of which 77% are
operated. These operated onshore properties represent 8.5% of the Company's
pre-tax present value of the Gulf Coast properties at December 31, 2001. During
2001, 13 development wells (4.2 net) were drilled, of which 11 (2.7 net) were
productive. Two exploratory wells (0.3 net) were drilled, of which both were
productive.

A total of $5.1 million was spent at the Matagorda Island 519 offshore
gas field, which is operated by BP Amoco. The Company has a 17% working interest
in the field's seven wells, which produce from as deep as 16,800 feet in the
lower Miocene sands. While the field is non-operated, the Company assigns
technical and operational staff to study and monitor it given its significance.
The field contributed 6% (3.3 Bcfe) of the Company's production in 2001. In
2000, the 519 L-3 well was drilled and turned to sales in December. In 2001, the
519 L-4 well was drilled and turned to sales in September. The initial flow
rates from both wells were disappointing. To address this problem, an additional
interval was opened to production in the L-3 well in September of 2001,
increasing the well's rate from 5.0 to 35.0 Mmcfe per day, for a net increase to
Range of 3.8 Mmcfe per day. A similar operation is currently in progress in the
L-4 well. No additional drilling activity is forecast for Matagorda Island 519
in 2002. The operator has historically significantly overspent its authorized
expenditures for capital projects and has consistently encountered numerous
delays in completion of those projects. Largely as a result, the Company
impaired Matagorda Island 519 by $8.1 million at year-end 2001. (See
Management's Discussion - Results of Operations.) Other offshore activity
included drilling one well each at West Cameron 206, West Cameron 192, East
Cameron 33 and Mobile 864. The four wells are currently producing at a combined
rate of 28.1 (5.3 net) Mmcfe per day.

Onshore, Range was active in the Hartburg play in Orange County, Texas
and Calcasieu Parish, Louisiana, where five wells were drilled and one is in
progress. These wells targeted Frio sands at depths of approximately 9,000 feet.
The Stephenson #1, #2 and #3 as well as the Stark #2 are all online producing at
a combined rate of 20.2 (2.0 net) Mmcfe per day. The one disappointment was the
Lawton #1, which was abandoned after the target sands proved wet. Currently the
Stephenson #4 is completing. In the Oakvale field in Mississippi, Range
completed the Polk 36-3 #1 and drilled and completed the 31-7 #1 in 2001. Both
wells have been fracture stimulated and are online at a combined rate of 5.5
(3.4 net) Mmcfe per day.

APPALACHIAN REGION

Through its 50% interest in Great Lakes Energy Partners L.L.C., the
Company's Appalachian region represents 212 Bcfe of proved reserves, or 41% by
volume and 35% by value of total proved reserves. The Appalachian Region has an
interest in 8,128 gross (3,567 net) wells and 4,600 miles of gas gathering
lines. Great Lakes sells its gas on a negotiated basis. Effective July 1, 2001,
Great Lakes began selling its gas to several different companies, including
First Energy. At December 31, 2001, Great Lakes had a development inventory of
51 proven recompletions and 1,468 proven drilling locations.

Acreage owned by the Appalachian region at December 31, 2001 included
730,142 gross (343,019 net) developed acres and 334,102 gross (153,962 net)
undeveloped acres. During 2001, 209 development wells (86.8 net) were drilled,
of which 207 (86.0 net) were productive. Five exploratory wells (1.5 net) were
drilled, of which three (0.6 net) were productive. At December 31, 2001, Great
Lakes operated 99% of the wells. The reserves are 86% gas and produce
principally from the upper-Devonian, Medina, Clinton, Knox and Oriskany
formations at depths ranging from 2,500 to 7,000 feet. In the fourth quarter of
2001, net daily production averaged 28,915 Mmcf of gas and 869 barrels of oil
per day or a total of 34,128 mcfe per day. The region's properties, with 1,468
(663 net) proven projects at year-end, are located in the Appalachian and, to a
minor degree, the Michigan

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Basins of the northeastern United States. After initial flush production, these
properties are characterized by gradual decline rates, on average, producing
from 10-35 years.

In 2001, $22 million in capital expenditures funded the drilling of
193.0 (84.8 net) shallow development wells, 16 (5.7 net) medium depth wells, and
five (2.5 net) deep exploitation wells. In addition, capital was expended on 11
(4.2 net) recompletions as well as the purchase of 1,021 miles of 2-D and 3-D
seismic data and 48,750 acres of leasehold. Out of 209 development wells
drilled, 207 were successful. Three of the five exploration wells were also
successful, indicating an overall 98% success rate. Production during the year
averaged 32.6 Mmcfe/day net, a 4% increase. Year-end proved reserves decreased
approximately 12% to 211.6 Bcfe primarily as a result of lower pricing.

During 2001 exploration prospects at Great Lakes consisted of activity
in the Knox Unconformity, Huntersville-Oriskany, and Trenton Black River plays.
The largest effort (14 gross/12.1 net) was directed to the Knox play in Ohio.
Great Lakes significantly increased its use of 3D seismic for the Knox
Unconformity play in Ohio shooting or acquiring over 30 square miles of data in
three separate project areas. Each of these 3D shoots yielded new discovery
wells with additional drilling opportunities. Great Lakes shot a moderate amount
of 2D seismic and drilled 3 gross (2 net) wells in the Huntersville/Oriskany
play in Pennsylvania. While all three wells were completed, initial production
rates are below expectations. In the Trenton Black River play, Great Lakes
acquired leases on over 125,000 gross acres in four major prospect areas, and
has plans for seismic and drilling in 2002. While Great Lakes successfully
established land positions in this play, our initial drilling results were
unsuccessful on all three gross (0.6 net) wells drilled in 2001.

Five major geologic plays comprise Great Lakes' exploration and
development portfolio. The two major development plays, consisting primarily of
shallow low-risk, lower impact wells include the Clinton Medina and Upper
Devonian Sandstone plays. Production from these shallower blanket-type,
tight-sand formations is characteristically long-lived with estimated ultimate
production anywhere from 150-750 Mmcf per well. The three exploration plays,
consisting of medium to deep wells with higher-risk and higher potential impact,
include the Knox Unconformity play, the Huntersville/Oriskany Sandstone play and
the Trenton Black River play. Wells drilled in the Knox Unconformity are
characterized by a relatively short well life of 10 years or less and have
reserves in the 250 Mmcf to 1 Bcf range. Production from the deeper and more
structurally complex formations such as the Oriskany is in the 500 Mmcf to 3 Bcf
range with a 15-25 year well life or greater. Recent discoveries in the
fault-related Trenton Black River play indicate per well recoveries in the 500
Mmcf to 5 Bcf range, particularly in the deeper structures of the play.

Management of Great Lakes is directed by a committee comprised of three
representatives from each of the Company and FirstEnergy. Disagreements that
cannot be resolved by the committee may be resolved through arbitration.

19

PRODUCTION

The following table sets forth total company production information for
the preceding five years (in thousands, except average sales price and operating
cost data).

(a) Oil and NGL are converted to mcfe at a rate of 6 mcf per barrel.

(b) Includes severance and production taxes.

(c) Average sales prices are net of hedging, which increased average oil prices
in 2001 by $2.21 and decreased average gas prices by $0.25, respectively.
In 2000, average sales prices are net of hedging, which reduced average oil
and gas prices in 2000 by $4.85 and $0.81, respectively.

(d) Average mcfe prices excluding hedging were $2.34, $3.90, and $3.87, in
1999, 2000 and 2001, respectively.

PRODUCING WELLS

The following table sets forth information relating to productive wells
at December 31, 2001. The Company owns royalty interests in an additional 215
wells. Wells are classified as oil or gas according to their predominant
production stream.

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ACREAGE

The following table sets forth total acreage held by the Company at
December 31, 2001.

The following table sets forth, for the preceding three years, the book
value of acreage where the Company has not yet identified proved reserves (in
thousands):

DRILLING RESULTS

The following table summarizes drilling activities for the past three
years.

REAL PROPERTY

The Company leases approximately 59,000 square feet of office space in
Texas and Oklahoma under standard office lease arrangements that expire at
various dates through March 2006. All facilities are believed adequate to meet
the Company's current needs and existing space could be expanded or additional
space could be leased if required.

In March 2000, a tornado struck the Company's headquarters in Fort
Worth. The Company temporarily relocated to 801 Cherry Street in Fort Worth. In
January 2001, the Company entered into a five-year lease for approximately
26,000 square feet of office space located at 777 Main Street in Fort Worth, and
moved in April 2001. The annual lease payments on this office space will average
$500,000 for the term of the lease.

The Company owns various vehicles and other equipment that is used in
its field operations. Such equipment is believed to be in good repair and, while
such equipment is important to its operations, it can be readily replaced as
necessary.

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ITEM 3. LEGAL PROCEEDINGS

The Company is involved in various legal actions and claims arising in
the ordinary course of business. During 2001, the Company incurred approximately
$480,000 of litigation costs for such matters. In the opinion of management,
such litigation and claims are likely to be resolved without material adverse
effect on its financial position or results of operations.

In February 2000, a royalty owner filed a suit asking for a class
action certification against Great Lakes Energy Partners, LLC in the New York
Supreme Court, alleging that gas was sold to affiliates and gas marketers at low
prices, that inappropriate post production expenses reduced proceeds to the
royalty owners, and that the royalty owners' share of gas was improperly
accounted for. The action sought a proper accounting, an amount equal to the
difference in prices paid and the highest obtainable prices, punitive damages
and attorneys' fees. The case has been remanded to the state court in New York.
While the outcome is still uncertain, Great Lakes believes it will be resolved
without material adverse effect on its financial position or result of
operations.

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

There were no matters submitted to a vote of security holders during
the fourth quarter of 2001.

PART II

ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED MATTERS

The Company's common stock is listed on New York Stock Exchange
("NYSE") under the symbol "RRC." Prior to August 1998, the stock was listed
under the symbol "LOM." During 2001, trading volume averaged 339,141 shares per
day. On March 1, 2002, the closing price of the common stock was $4.78. The
following table sets forth the high and low sales prices as reported on the NYSE
composite tape over the past two years.

From January 1, 2002 to March 1, 2002 the common stock has traded at
prices between $4.03 and $5.09 per share. The Company's 5.75% trust preferred,
6% convertible debentures and 8.75% senior subordinated notes are not listed on
an exchange but trade over the counter. The fair value of these securities,
quoted from certain market makers, was $148.5 million or 75% of the par value of
$198.4 million.

At various times during 2001, the Company issued common stock in
exchange for fixed income securities. The shares of common stock issued in such
exchanges were exempt from registration under Section 3(a)(9) of the Securities
Act of 1933. During the fourth quarter of 2001, a total of $3.4 million face
value amount of 8.75% Subordinated Notes was exchanged for 753,601 shares of
common stock and a total of $0.5 million face value of Trust Preferred was
exchanged for 60,503 shares of common stock.

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HOLDERS OF RECORD

At March 1, 2002 there were approximately 2,368 holders of record of
the common stock.

DIVIDENDS

Common stock dividends were initiated in 1995 and paid quarterly
through the third quarter of 1999. In the first quarter of 1999, the dividend
was reduced and in the fourth quarter of 1999 it was eliminated in connection
with continuing losses.

In September 2000, the Company authorized a $2.03 Convertible
Exchangeable Preferred Stock Series D, having terms substantially identical to
the outstanding Series C Preferred, with the exception that dividends could be
paid in common stock. In November 2000, 523,140 shares of Series C were
exchanged for Series D on a one-for-one basis. In December 2000, 323,140 shares
of Series D were exchanged for common stock. The Company elected to pay fourth
quarter 2000 Series D dividends in common stock. During 2001, all remaining
shares of Series D and all remaining shares of Series C were exchanged for
common stock or repurchased for cash. The elimination of the $2.03 Convertible
Exchangeable Preferred Stock reduced the Company's annual dividend requirement
by $2.3 million.

The payment of dividends is subject to declaration by the Board of
Directors and depends on earnings, capital expenditures and various other
factors. The bank credit facility and the 8.75% senior subordinated notes
contain restrictions on the ability to pay dividends. The bank credit facility
currently prohibits common stock dividends. Under the terms of the 8.75% senior
subordinated notes, the Company may pay restrictive payments, including
dividends, equal to the greater of: i) $20.0 million or ii) a formula which
includes earnings and losses since the issuance of the notes. Given the
Company's losses since 1997, the Company cannot make payments under the formula
and must rely on the $20.0 million basket. At December 31, 2001, $3.0 million
remained available under the basket. The Company may seek to amend this basket
covenant.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected financial information covering
the last five years.

(a) Stockholders equity includes other comprehensive income/(loss) of $370,
$292, $(7), $(907) and $38,041 in 1997, 1998, 1999, 2000 and 2001,
respectively.

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The following table sets forth summary unaudited financial information
on a quarterly basis for the past two years (in thousands, except per share
data).

(a) Includes extraordinary gains on retirement of securities of $432 in the
first quarter. These gains, net of income taxes, were $895 and $319 in the
second and third quarters, respectively. In the fourth quarter of 2001, the
gain on retirement of securities was $2,305 which included $886 reversal of
previously recorded deferred income taxes. The $38,945 impairment recorded
at year-end 2001 brought the Company's earnings below the amount required
for the Company to record income taxes, at a statutory rate, on income.

The total of the earnings per share for each quarter does not equal the
earnings per share for the full year, either because the calculations are based
on the weighted average shares outstanding during each of the individual periods
or rounding. During the fourth quarter of 2001, the Company recorded $38.9
million of impairments. (See Management's Discussion and Analysis - Results of
Operations.)

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CAPITALIZED TERMS HEREIN ARE DEFINED IN THE
FOOTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTAINED HEREIN.)

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Company's discussion and analysis of its financial condition and
results of operation are based upon consolidated financial statements, which
have been prepared in accordance with accounting principles generally adopted in
the United States. The preparation of these financial statements requires the
Company to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses. The Company analyzes its estimates,
including those related to oil and gas revenues, bad debts, oil and gas
properties, marketable securities, income taxes and contingencies and
litigation. The Company bases its estimates on historical experience and various
other assumptions that are believed to be reasonable under the circumstances.
Actual results may differ from these estimates under different assumptions or
conditions. The Company believes the following critical accounting policies
affect its more significant judgments and estimates used in the preparation of
its consolidated financial statements. The Company recognizes revenues from the
sale of products and services in the period delivered. Revenues at IPF are
recognized as received. We provide an allowance for doubtful accounts for
specific receivables we judge unlikely to be collected. At IPF, all receivables
are evaluated quarterly and provisions for uncollectible amounts are
established. Oil and gas properties are accounted for under the successful
efforts method of accounting and are periodically evaluated for possible
impairment. The Company records a write down of marketable securities when the
decline in market value is considered to be other than temporary. Impairments
are recorded when

24

management believes that a property's net book value is not recoverable based on
current estimates of expected future cash flows. The Company's deferred tax
assets exceed deferred tax liabilities at year-end 2001, before considering the
effects of Other comprehensive income ("OCI"). In determining deferred tax
liabilities, accounting rules require OCI to be considered, even though such
income (loss) has not yet been earned. The inclusion of OCI causes the deferred
tax liabilities to exceed the deferred tax assets by $9.7 million, therefore,
such amount is recorded as deferred tax liability at year-end 2001 and is
included on the balance sheet of the Company. No statutory taxes are included on
the income statement as the Company has not yet earned income sufficient to
cause the deferred tax liabilities to exceed the deferred tax assets. The
Company needs to earn approximately $20.0 million of pre-tax income from the
unrealized hedges included in OCI at year-end before statutory taxes will be
recorded on the income statement. Due to the complexity of the accounting rules
regarding statutory taxes, the timing of when the Company will record statutory
taxes, which will be deferred, is uncertain.

FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY

LIQUIDITY AND CAPITAL RESOURCES

During 2001, the Company spent $90.1 million on development,
exploration and acquisitions. Debt including Trust Preferred and $2.03 Preferred
were reduced by a total of $65.9 million. At December 31, 2001, the Company had
$3.3 million in cash, total assets of $691.6 million and a debt (including Trust
Preferred) to capitalization (including debt, deferred taxes and stockholders
equity) ratio of 61%. Available borrowing capacity on the Company's bank lines
at December 31, 2001 was $25.0 million on the Parent Facility, $25.0 million on
the Great Lakes Facility and $11.2 million on the IPF Facility. Long-term debt
(including Trust Preferred) at December 31, 2001 totaled $392.2 million and
included $95.0 million of borrowings under the Parent Facility, $75.0 million
under the non-recourse Great Lakes Facility, $23.8 million under the
non-recourse IPF Facility, $79.1 million of 8.75% Senior Subordinated Notes,
$29.6 million of 6% Convertible Subordinated Debentures and $89.7 million of
Trust Preferred.

During 2001, 1.8 million shares of common stock were exchanged for $2.9
million of Trust Preferred, $3.4 million of 8.75% Senior Subordinated Notes and
$5.7 million of 6% Debentures. In addition, $2.3 million of 6% Debentures, $42.5
million of 8.75% Senior Subordinated Notes and $50,000 of 5.75% Trust Preferred
were repurchased. A $4.0 million extraordinary gain net of costs was recorded as
the securities were retired at a discount. In addition, 767,000 shares of common
stock were exchanged for $5.4 million of the $2.03 Preferred and the remaining
were repurchased for $74,000. Since 1998, there have been 13.6 million shares of
common stock exchanged for $85.4 million face value of debt and convertible
preferred stock.

The Company believes its capital resources are adequate to meet its
requirements for at least the next twelve months. However, future cash flows are
subject to a number of variables including the level of production and prices as
well as various economic conditions that have historically affected the oil and
gas business. There can be no assurance that internal cash flow and other
capital sources will provide sufficient funds to maintain planned capital
expenditures.

The following summarizes the Company's contractual obligations at
December 31, 2001 and the effect such obligations are expected to have on its
liquidity and cash flow in future periods (in thousands):

* Due at termination dates in each of the Company's credit facilities, which the
Company expects to renew, but there is no assurance that can be accomplished.

25

Total long-term debt (including Trust Preferred) at December 31, 2001,
was $392.2 million. Long-term debt of $193.8 million was at floating interest
rates. Included in long-term debt was $198.4 million of debt securities which
have fixed interest charges. The table below describes the Company's required
annual fixed interest payments on these debt instruments (in thousands):