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

18

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.

20

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.

22

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.

23

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):

Cash Flow

The Company's principal sources of cash are operating cash flow and
bank borrowings. The Company's cash flow is highly dependent on oil and gas
prices. The Company has entered into hedging agreements covering approximately
55%, 30%, 15%, and 5% of its anticipated production from proved reserves on an
mcfe basis for 2002, 2003, 2004 and 2005, respectively. Decreases in prices and
lower production at certain properties reduced cash flow sharply in 1998 and
early 1999 and resulted in the reduction of the Company's borrowing base.
Simultaneously, the Company sharply reduced its development and exploration
spending. While the $90.1 million of capital expenditures for 2001 were funded
entirely with internal cash flow, the amount expended was not sufficient to
replace production. The 2002 capital budget of $100.0 million is expected to
increase production 5% or more and expand the reserve base by more than
replacing production. The Company's hedge position 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
reduction in long-term debt as excess internal cash flow will be limited. With
any further decrease in product prices, it would be unlikely that the Company
would be able to fund the $100.0 million capital program entirely from internal
cash flow. The Company intends to closely monitor its capital expenditure
program and results of operations in 2002; therefore, this current low price
environment may negatively affect the amount of capital spending for the year.

Net cash provided by operations in 1999, 2000 and 2001 was $50.2
million, $74.1 million and $130.3 million, respectively. Cash flow from
operations increased as higher prices and lower interest expense more than
offset increasing direct operating and general and administrative expenses.

Net cash used in (provided by) investing in 1999, 2000 and 2001 was
$(98.2) million, $5.3 million and $78.9 million, respectively. In 1999, a $98.7
million source of cash from the formation of Great Lakes, $17.5 million in asset
sales and $13.2 million of IPF receipts, more than offset additions to oil and
gas properties and IPF investments. In 2000, $46.8 million of additions to oil
and gas properties, offset by $25.9 million proceeds from sales of assets and
$24.8 million of IPF repayments were included. The 2001 period included $87.7
million of additions to oil and gas properties and $11.6 million of IPF
investments, partially offset by $19.0 million of IPF receipts and $3.8 million
of asset sales.

Net cash used in financing in 1999, 2000 and 2001 was $146.4 million,
$79.3 million and $50.6 million, respectively. Sources of financing have been
primarily bank borrowings and capital raised through equity and debt offerings.
During 2001, recourse debt increased by $5.1 million and total debt (including
Trust Preferred) decreased by $65.9 million. The reduction in debt was the
result of applying excess cash flow, proceeds from asset sales and from
exchanges of common stock. During 2000, recourse debt decreased by $63.9 million
and total debt (including Trust Preferred) decreased by $118.5 million. The
reduction in debt was the result of applying excess cash flow and proceeds from
the sale of assets to debt repayment and exchanges of common stock for fixed
income securities. The amount of Trust Preferred outstanding decreased $2.3
million in 1999, $25.0 million in 2000 and $2.9 million in 2001 due primarily to
exchanges of such securities into common stock.

Capital Requirements

During 2001, $90.1 million of capital was expended, primarily on
development projects. This represented approximately 69% of internal cash flow.
The Company manages its capital budget with the goal of funding it with internal
cash flow. The 2002 capital budget of $100.0 million is expected to increase
production 5% or more and expand the reserve base by more than replacing
production. The Company's hedge position which covers approximately 55% of
anticipated 2002

26

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 reduction in long-term
debt as excess internal cash flow will be limited. With any further decrease in
product prices, it would be unlikely that the Company would be able to fund the
$100.0 million capital program entirely from internal cash flow. The Company
intends to closely monitor the capital expenditure program and results of
operations; therefore, this current low price environment may negatively affect
the amount of capital spending for the year. Development and exploration
activities are highly discretionary, and, for the foreseeable future, management
expects such activities to be maintained at levels equal to or below internal
cash flow. See "Business--Development and Exploration Activities."

Banking

The Company maintains three separate revolving credit facilities: a
$225.0 million facility at the parent company; a $100.0 million facility at IPF
and a $275.0 million facility at Great Lakes. Each facility is secured by
substantially all of the assets of the borrower. The IPF and Great Lakes
facilities are non-recourse to Range. As Great Lakes is 50% owned, half of the
borrowings on its facility are consolidated in Range's financial statements.

Availability under the facilities are subject to borrowing bases set by
banks semi-annually and in certain other circumstances. The borrowing bases are
dependent on a number of factors, primarily the lenders' assessment of future
cash flows. Redeterminations require approval of 75% of the lenders, increases
require unanimous approval.

At March 1, 2002, there was availability under each of the Company's
facilities. At the parent, a $120.0 million borrowing base was in effect of
which $16.5 million was available. At IPF, a $35.0 million borrowing base was in
effect of which 11.7 million was available. At Great Lakes, half of which is
consolidated at Range, a $200.0 million borrowing base was in effect, of which
54.0 million was available.

Hedging
Oil and Gas Prices

The Company regularly enters into hedging agreements to reduce the
impact of fluctuations in oil and gas prices on its operations. The Company's
current policy, when futures prices justify, is to hedge between 50% and 75% of
projected production from existing proved reserves on a rolling twelve to
eighteen month basis. At December 31, 2001, hedges were in place covering 47.3
Bcf of gas 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, based on contract versus NYMEX prices,
approximate 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, respectively. The
contracts expire monthly through December 2005 and cover approximately 55% of
anticipated 2002 production from proceed reserves and 30% of 2003 production
from proved reserves and lesser amounts of 2004 and 2005 production. Gains or
losses on open and closed hedging transactions are determined as the difference
between the contract price and a reference price, generally closing prices on
the NYMEX. Transaction gains and losses are determined monthly and are included
as increases or decreases on 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 cumulative net
loss of $7.9 million. 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 as OCI, a component of Stockholders'
Equity.

The Company had hedge agreements with Enron for 22,700 Mmbtu's per day,
at $3.20 per Mmbtu for 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 2001 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 as of 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 some market offers for purchasing these contracts at
percentages much less than par.

27

Interest Rates

At December 31, 2001, Range had $392.2 million of debt (including Trust
Preferred) outstanding. Of this amount, $198.4 million bears interest at fixed
rates averaging 7.0%. Senior debt and non-recourse debt totaling $193.8 million
bears interest at floating rates, which averaged 4.0% at year-end 2001,
excluding interest rate swaps. At December 31, 2001, Great Lakes had $100.0
million of interest rate swap agreements, of which 50% is consolidated at Range.
Two agreements totaling $45.0 million at rates of 7.1% each expire in May 2004.
Two agreements of $10.0 million each at 6.2% in December 2002 and five
agreements totaling $35.0 million at rates of 4.8%, 4.7%, 4.6%, 4.5%, and 4.5%
expire in June 2003. The agreements expiring in May 2004 may be terminated at
the counter party's option in May 2002. The 30-day LIBOR rate on December 31,
2001 was 1.9%. A 1% increase in short-term interest rates on the floating-rate
debt outstanding at December 31, 2001 would cost the Company approximately $1.4
million in additional annual interest, net of swaps.

Capital Restructuring Program

As described in Note 1 to the Consolidated Financial Statements, the
Company took a number of steps beginning in 1998 to strengthen its financial
position. These steps included the sale of assets and the exchange of common
stock for fixed income securities. These initiatives have helped reduce Parent
company bank debt to $95.0 million and total debt (including Trust Preferred) to
$392.2 million at December 31, 2001. 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 currently believes it has
sufficient liquidity and cash flow to meet its obligations for the next twelve
months; however, a drop in oil and gas prices or a reduction in production or
reserves would reduce the Company's ability to fund capital expenditures and
meet its financial obligations.

INFLATION AND CHANGES IN PRICES

The Company's revenues, the value of its assets, its ability to obtain
bank loans or additional capital on attractive terms have been and will continue
to be affected by changes in oil and gas prices. Oil and gas prices are subject
to significant fluctuations that are beyond the Company's ability to control or
predict. During 2001, the Company received an average of $25.55 per barrel of
oil and $3.66 per Mcf of gas after hedging. Although certain of the Company's
costs and expenses are affected by the general inflation, inflation does not
normally have a significant effect on the Company. However, industry specific
inflationary pressures built up over an 18 month period in 2000 and 2001 due to
favorable conditions in the industry. While product prices have recently
declined, the cost of services in the oil and gas industry have not declined by
the same percentage. Any increases in product prices could cause inflationary
pressures specific to the industry to also increase.

28

RESULTS OF OPERATIONS

The following table identifies certain items included in the Company's
results of operations and is presented to assist in comparison of the last three
years. The table should be read in conjunction with the following discussions of
results of operations.

Comparison of 2001 to 2000

Net income for the twelve months totaled $9.0 million compared to $38.0
million for the comparable period in 2000. The twelve-month period of 2000
included a $17.8 million gain on retirement of securities versus $4.0 million in
2001. The fourth quarter of 2001 included an impairment charge of $38.9 million.
Production increased to 152.7 Mmcfe per day, a 1% increase from the prior year
period. Revenues benefited from a 21% increase in average prices per mcfe to
$3.76. The average prices received for oil increased 10% to $25.55 per barrel
and for gas increased 26% to $3.66 per mcfe. Production expenses increased $6.0
million to $44.5 million as a result of higher production and property taxes,
increased workover costs and slightly higher labor and services and supplies.
Therefore, operating cost per mcfe produced averaged $0.80 in 2001 versus $0.70
in 2000.

Transportation and processing revenues decreased 35% to $3.4 million
due to the impact of the sale of a gas processing plant in June 2000 and lower
NGL prices. IPF's $6.5 million of revenues is a decline of 35% from the same
period of 2000. In 2000, a favorable adjustment of $1.3 million was recorded to
IPF reserves. IPF records income from payments on accounts with no reserve
accrued against them. For accounts with reserves accrued, IPF reduces the
carrying value of the account for payments received and does not record any
income from those collections. Due to declining prices in 2001, less income was
recorded from payments received. In 2001, a favorable adjustment to IPF reserves
of $1.8 million, due to favorable prices at the time, was more than offset by a
year-end increase in reserve for doubtful accounts of $2.0 million. During 2001,
IPF expenses included $1.8 million of administrative costs and $1.8 million of
interest. During 2000, IPF expenses included $1.5 million of administrative
costs and $3.4 million on interest costs.

Exploration expense increased 84% to $5.9 million primarily due to
additional seismic activity and increased personnel expenses. General and
administrative expenses increased 32% due to additional personnel costs ($1.4
million), higher legal and occupancy costs ($1.2 million) and additional costs
($600,000) incurred by having duplicate functions at Great Lakes and Range. The
average number of general and administrative personnel increased 15% from 2000
to 2001. The Company does not expect further increases of this magnitude.

29

Interest and other income increased from a loss of $702,000 in 2000 to
a gain of $490,000 in 2001. The 2001 period included $2.3 million of 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. The 2000 period included $1.1 million loss on asset
sales. Interest expense decreased 23% to $30.7 million primarily as a result of
lower average outstanding balances and falling interest rates. Average
outstandings on the Parent Facility were $124.7 million and $90.5 million for
2000 and 2001, respectively and the average interest rates were 8.8% and 6.4%,
respectively.

Depletion, depreciation and amortization ("DD&A") increased 8% to $77.8
million as a result of the mix of production between depletion pools. The per
mcfe DD&A rate in 2001 was $1.40, a $0.10 increase from the $1.30 rate in 2000.
The DD&A rate is determined based on ending reserves (valued at prices
management believes appropriate) and the net book value associated with them and
to a lesser extent, depreciation on other assets owned at year-end. The DD&A
rate in the fourth quarter of 2001 was $1.47 per mcfe as the Company's changed
its policy and shortened the depreciable lives of other assets owned. The
Company currently estimates that the consolidated DD&A rate for 2002 will
approximate $1.29 per mcfe, a decrease of $0.11 from 2001.

The Company recorded a provision for impairment on acreage and proved
properties for the year ended 2001. In evaluating possible impairment, the
Company generally evaluates acreage on a separate basis from proved properties.
Due to its unique nature, West Delta 30 was evaluated by considering its proved
reserves and prospective value in combination.

Acreage. Acreage is assessed periodically to determine whether there
has been a decline in value. If a decline is indicated, an impairment is
recognized. The Company compares the carrying value of its properties to the
assessment of value that could be recovered from sale, farm-out or exploitation.
The Company considers other additional information it believes is relevant in
evaluating the properties' fair value, such as geological assessment of the
area, other acreage purchases in the area, timing of the associated drilling
program or the properties' uniqueness. The following acreage was impaired for
the reasons indicated (in thousands):

30

Proved Properties. The impairment evaluation on all proved properties
utilized proved reserves and for West Delta 30 only, also included possible and
probable reserves. Probable reserves are reserves not reasonably certain or
proved, yet "more likely to be recovered than not." Possible reserves are
reasonably possible but "less likely to be recovered than not." Estimated future
cash flows include revenues from anticipated oil and natural gas production,
severance taxes, direct operating expenses and capital costs. In assessing the
risk associated with proved properties, the Company considers historical
operations and the risk associated with recoverability of proved reserves. The
risk assessment for West Delta 30 also included the recoverability of probable
and possible reserves. Properties in the Gulf Coast region have relatively short
reserve lives as production usually declines rapidly. In evaluating the future
cash flows on these properties for impairment, the Company used unescalated
NYMEX based prices for oil of $20.38 per bbl and $2.63 per Mmbtu for gas. Such
prices are consistent with those used in Note 20 to the financial statements,
"Unaudited Supplemental Reserve Information." The following properties were
impaired based upon an analysis of future cash flows (in thousands):

West Delta 30 currently produces primarily oil and has been adversely affected
by the decline in oil prices. Proved undeveloped and probable and possible
reserves are primarily gas and will not be developed until the operator (a major
oil company) completes interpretation of its proprietary seismic. The Company
anticipates significant delays in any drilling schedule. 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.

Comparison of 2000 to 1999

Net income in 2000 totaled $38.0 million, compared to a net loss of
$7.8 million in 1999. Net income excluding the impact of hedging losses and
unusual items would have been $62.1 million in 2000 versus a net loss of $10.3
million in 1999. Production fell to 151,442 mcfe per day, a 17% decrease from
1999. A 4% decrease would have been reported if the effect of the Great Lakes
transaction were eliminated. Revenues benefited from a 43% increase in average
prices per mcfe to $3.12, partially offset by the production decrease. The
average prices received for oil increased 58% to $23.30 per barrel and for gas
increased 36% to $2.90 per Mcf. Production expenses fell 11% to $38.5 million
largely as a result of the Great Lakes transaction and asset sales. Operating
costs per mcfe produced averaged $0.65 in 1999 versus $0.70 in 2000 due to
higher production taxes and workovers.

Transportation, processing and marketing revenues decreased 32% to $5.3
million as benefits of higher NGL prices were more than offset by the impact of
the Sterling gas plant sale in April 2000. IPF's $10.0 million of revenues
consisted of the return portion of its royalties and a $1.3 million net reversal
of valuation allowances previously provided. IPF's income rose 27% over that
reported in 1999. During 2000, IPF expenses included $1.5 million of
administrative costs and $3.4 million of interest.

Exploration expense increased 32% to $3.2 million, primarily due to
higher dry hole costs.

General and administrative expenses increased 29% to $10.3 million. The
increase was primarily due to lower recoupments from third parties for
operations which fell due to the Great Lakes transaction and the expense of
establishing duplicate financial and administrative departments in Fort Worth.

31

Interest and other income decreased $1.1 million primarily due to $1.1
million of losses on sales of assets. Interest expense (excluding IPF) decreased
15% to $40.0 million primarily as a result of the lower outstandings, partially
offset by higher interest rates. The average outstanding balance on the bank
credit facility fell to $125 million from $308 million in the prior year and the
weighted average interest rate rose from 7.1% to 8.8%.

Depletion, depreciation and amortization ("DD&A") decreased 6% as a
result of the mix of production by depletion pool and lower production. The
Company-wide DD&A rate rose to $1.30 per mcfe in 2000 compared to $1.04 in 1999
due to lower reserves at year-end 2000 and the net book value of costs
associated with them. Acreage is assessed periodically to determine whether
there has been an impairment. If an impairment is indicated, a loss is
recognized. The Company compares the carrying value of its acreage to estimated
fair value based on a variety of factors including an assessment of value that
could be recovered from sale, farm-out, or exploitation, a geological and
engineering assessment of the area, other acreage transactions in the vicinity,
timing of the associated drilling program and the property's uniqueness. In the
fourth quarter of 2000, the Company raised its DD&A rate to $1.38 per mcfe to
reflect a decline in proved reserves and the increased book value of properties
subject to amortization. Reserves were revised downward in 2000 due to the
removal of drilling and recompletion locations that, based on perceived risk,
will probably not be drilled. See Note 20 to the financial statements. The DD&A
rate for 2001 was $1.40 per mcfe. The Company's high DD&A rate will make it more
difficult to remain profitable if commodity prices fall sharply.

32

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about Range's potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in oil and gas prices and interest rates. The
disclosures are not meant to be precise indicators of expected future losses,
but rather indicators of reasonably possible losses. This forward-looking
information provides indicators of how Range views and manages its ongoing
market risk exposures. All of Range's market risk sensitive instruments were
entered into for purposes other than trading.

Commodity Price Risk. Range's major market risk is exposure to oil and
gas pricing. Realized pricing is primarily driven by worldwide prices for oil
and spot market prices for North American gas production. Oil and gas prices
have been volatile and unpredictable for many years.

The Company periodically enters hedging arrangements with respect to
oil and gas production of proved reserves. Pursuant to these swaps, Range
receives a fixed price for its production and pays market prices to the contract
counterparty. This hedging is intended to reduce the impact of oil and gas price
fluctuations. Realized gains and losses are generally recognized in oil and gas
revenues when the associated production occurs. Starting in 2001, gains or
losses on open contracts are recorded either in current period income or Other
comprehensive income ("OCI"). The gains and losses realized as a result of
hedging are substantially offset in the cash market when the commodity is
delivered. Range does not hold or issue derivative instruments for trading
purposes.

As of December 31, 2001, Range had oil and gas hedges in place covering
47.3 Bcf of gas and 700,000 barrels of oil. Their fair value, excluding hedge
contracts with Enron, represented by the estimated amount that would be realized
upon termination, based on contract versus NYMEX prices, approximated a net
unrealized pre-tax gain of $52.1 million ($41.9 million net of $10.2 million of
deferred taxes) at December 31, 2001. These contracts expire monthly through
December 2005 and cover approximately 55% of anticipated 2002 production from
proved reserves and 30% of 2003 production from proved reserves and lesser
amounts of 2004 and 2005 production. Gains or losses on open and closed hedging
transactions are determined as the difference between the contract price and a
reference price, generally closing prices on the NYMEX. Transaction gains and
losses are determined monthly and are included as increases or decreases to 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. Effective January 1, 2001, the
unrealized gains (losses) on these hedging positions were recorded at an
estimate of the fair value based on a comparison of the contract price and a
reference price, generally NYMEX, on the Company's balance sheet as OCI, a
component of Stockholders' Equity.

The Company had hedge agreements with Enron for 22,700 Mmbtu's per day,
at $3.20 per Mmbtu for 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 2001 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 as of 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 some market offers for purchasing these
contracts at percentages much less than par.

In 2001, a 10% reduction in oil and gas prices, excluding amounts fixed
through hedging transactions, would have reduced revenue by $4.4 million. If oil
and gas future prices at December 31, 2001 had declined by 10%, the unrealized
hedging gain at that date would have increased by $15.2 million.

At December 31, 2001, Range had $392.2 million of debt (including Trust
Preferred) outstanding. Of this amount, $198.4 million bears interest at fixed
rates averaging 7.0%. Senior debt and non-recourse debt totaling $193.8 million
bears interest at floating rates, excluding interest rate swaps, which averaged
4.0% at that date. At December 31, 2001, Great Lakes had interest rate swap
agreements totaling $100.0 million, 50% of which is consolidated with Range. Two
agreements totaling $45.0 million at rates of 7.1% each expire in May 2004. Two
agreements of $10.0 million each at 6.2% expire in December 2002 and five
agreements totaling $35.0 million at rates of 4.8%, 4.7%, 4.6%, 4.5% and 4.5%
expire in June 2003. The agreements expiring in May 2004 may be terminated at
the counterparty's option in May 2002. On December 31, 2001, the 30-day LIBOR
rate was 1.9%. A 1% increase in short-term interest rates on the floating-rate
debt outstanding (net of

33

amounts fixed through hedging transactions) at December 31, 2001 would cost the
Company approximately $1.4 million in additional annual interest.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reference is made to the Index to Financial Statements on page 40 for a
list of financial statements and notes thereto and supplementary schedules.
Schedules I, III, IV, V, VI, VII, VIII, IX, X, XI, XII and XIII have been
omitted as not required or not applicable, or because the information required
to be presented is included in the financial statements and related notes.

MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS

The financial statements have been prepared by management in conformity
with generally accepted accounting principles. Management is responsible for the
fairness and reliability of the financial statements and other financial data
included in this report. In the preparation of the financial statements, it is
necessary to make informed estimates and judgments based on currently available
information on the effects of certain events and transactions.

The Company maintains accounting and other controls which management
believes provide reasonable assurance that financial records are reliable,
assets are safeguarded and transactions are properly recorded. However,
limitations exist in any system of internal control based upon the recognition
that the cost of the system should not exceed benefits derived.

The Company's independent auditors, Arthur Andersen LLP, are engaged to
audit the financial statements and to express an opinion thereon. Their audit is
conducted in accordance with generally accepted auditing standards to enable
them to report whether the financial statements present fairly, in all material
respects, the financial position and results of operations in accordance with
generally accepted accounting principles.

ITEM 9. CHANGE IN ACCOUNTANTS AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE

None.

34

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY

The officers and directors are listed below with a description of their
experience and certain other information. Each director was elected for a
one-year term at the Company's 2001 annual stockholders' meeting of
stockholders. Officers are appointed by the Board of Directors.

Thomas J. Edelman, Chairman and Chairman of the Board of Directors,
joined the Company in 1988. From 1981 to 1997, Mr. Edelman served as a director
and President of Snyder Oil Corporation ("SOCO"), a publicly traded independent
oil and gas company. In 1996, Mr. Edelman became Chairman and Chief Executive
Officer of Patina Oil & Gas Corporation. Prior to 1981, Mr. Edelman was a Vice
President of The First Boston Corporation. From 1975 through 1980, Mr. Edelman
was with Lehman Brothers Kuhn Loeb Incorporated. Mr. Edelman received his
Bachelor of Arts Degree from Princeton University and his Masters Degree in
Finance from Harvard University's Graduate School of Business Administration.
Mr. Edelman serves as a director of Star Gas Partners, L.P., a publicly-traded
master limited partnership, which distributes fuel oil and propane.

John H. Pinkerton, President and a Director, became a director in 1988.
He joined the Company and was appointed President in 1990. Previously, Mr.
Pinkerton was Senior Vice President-Acquisitions of SOCO. Prior to joining SOCO
in 1980, Mr. Pinkerton was with Arthur Andersen & Co. Mr. Pinkerton received his
Bachelor of Arts Degree in Business Administration from Texas Christian
University and his Master of Arts Degree in Business Administration from the
University of Texas. Mr. Pinkerton is a director of Venus Exploration, Inc., a
publicly traded exploration and production company in which Range owned
approximately a 18% interest at December 31, 2001.

Robert E. Aikman, became a Director in 1990. Mr. Aikman has more than
40 years experience in petroleum and natural gas exploration and production
throughout the United States and Canada. From 1984 to 1994 he was Chairman of
the Board of Energy Resources Corporation. From 1979 through 1984, he was the
President and principal shareholder of Aikman Petroleum, Inc. From 1971 to 1977,
he was President of Dorchester Exploration Inc. and from 1971 to 1980, he was a
Director and a member of the Executive Committee of Dorchester Gas Corporation.
Mr. Aikman is also Chairman of Provident Communications, Inc., Vice-Chairman of
Whamtech, Inc., and President of The Hawthorne Company, an entity which
organizes joint ventures and provides advisory services for the acquisition of
oil and gas properties, including the financial restructuring, reorganization
and sale of companies. In addition, Mr. Aikman is a director of the Panhandle
Producers and Royalty Owners Association and a member of the Independent
Petroleum Association of America and American Association of Petroleum Landmen.
Mr. Aikman graduated from the University of Oklahoma in 1952.

Anthony V. Dub became a Director in 1995. Mr. Dub is Chairman of Indigo
Capital, LLC, a financial advisory firm based in New York City. Prior to forming
Indigo Capital in 1997, he served as an officer of Credit Suisse First Boston,
an

35

investment banking firm. Mr. Dub joined Credit Suisse First Boston in 1971 and
was named a Managing Director in 1981. Mr. Dub received his Bachelor of Arts
Degree from Princeton University in 1971.

Allen Finkelson became a Director in 1994. Mr. Finkelson has been a
partner at Cravath, Swaine & Moore since 1977, with the exception of the period
1983 through 1985, when he was a managing director of Lehman Brothers Kuhn Loeb
Incorporated. Mr. Finkelson joined Cravath, Swaine & Moore in 1971. Mr.
Finkelson a Bachelor of Arts Degree from St. Lawrence University and a Doctor of
Laws Degree from Columbia University School of Law.

V. Richard Eales became a Director in 2001. Mr. Eales has over 35 years
of experience in the energy, high technology and financial industries. He is
currently a financial consultant serving energy and information technology
businesses. Mr. Eales was employed by Union Pacific Resources Group Inc. from
1991 to 1999 serving as Executive Vice President from 1995 through 1999. Prior
to 1991, Mr. Eales served in various financial capacities with Butcher & Singer
and Janney Montgomery Scott, investment banking firms, as CFO of Novell, Inc., a
technology company, and in the treasury department of Mobil Oil Corporation. Mr.
Eales received his Bachelor of Chemical Engineering from Cornell University and
his Masters in Business Administration from Stanford University.

Alexander P. Lynch became a Director in 2000. Mr. Lynch currently
serves as Managing Director of J.P. Morgan, a subsidiary of J.P. MorganChase &
Co., and Director of Patina Oil and Gas Corporation. Until its merger into J.P.
MorganChase, Mr. Lynch was a General Partner of The Beacon Group. Previously, he
was Co-President and Chief Executive Officer of The Bridgeford Group, a
financial advisory firm that was acquired by Beacon in 1997. Prior to 1991, Mr.
Lynch served as a Managing Director with Lehman Brothers, a division of Shearson
Lehman Brothers, Inc. Mr. Lynch received a Bachelor of Arts degree from the
University of Pennsylvania and a Master's Degree from the Wharton School of
Business at the University of Pennsylvania.

James E. McCormick became a Director in 2000. Mr. McCormick has more
than 40 years experience in the oil and gas industry. He currently serves as
Director of Lone Star Technologies, TESCO Corporation and Dallas National Bank.
He served as a Director for Santa Fe Snyder Corporation until its merger with
Devon Energy in August 2000. Mr. McCormick served as President and Chief
Operating Officer for Oryx Energy Company from its inception in 1988 until his
retirement in 1992. Prior to his position at Oryx, he served as President and
Chief Executive Officer of Sun Exploration and Production Company. Mr. McCormick
received a Bachelor of Science degree in Geology from Boston University.

Terry W. Carter, Executive Vice President-Exploration and Production,
joined the Company in January 2001. Previously, Mr. Carter provided consulting
services to independent oil and gas companies. From 1976 to 1999, Mr. Carter was
employed by Oryx Energy Company, holding a variety of positions including
Planning Manager, Development Manager and Manager of Drilling. Mr. Carter
received a Bachelor of Science degree in Petroleum Engineering from Tulsa
University.

Eddie M. LeBlanc III, Senior Vice President and Chief Financial
Officer, joined the Company in 2000. Previously Mr. LeBlanc was a founder of
Interstate Natural Gas Company, which merged into Coho Energy in 1994. At Coho
Energy Mr. LeBlanc served as Senior Vice President and Chief Financial Officer.
Mr. LeBlanc's twenty-six years of experience include assignments in the oil and
gas subsidiaries of Celeron Corporation and Goodyear Tire and Rubber. Prior to
his industry experience, Mr. LeBlanc was with a national accounting firm, he is
a certified public accountant, a chartered financial analyst, and received a
Bachelor of Science degree from University of Southwestern Louisiana.

Herbert A. Newhouse, Senior Vice President - Gulf Coast, joined the
Company in 1998. Prior to joining Range, Mr. Newhouse served as Executive Vice
President of Domain Energy Corporation. He was a former Vice President of
Tenneco Ventures Corporation. Mr. Newhouse was an employee of Tenneco for over
17 years and has over 30 years of operational and managerial experience in oil
and gas exploration and production. Mr. Newhouse received a Bachelor of Science
degree in Chemical Engineering from Ohio State University.

Chad L. Stephens, Senior Vice President - Southwest, joined the Company
in 1990. Previously, Mr. Stephens was with Duer Wagner & Co., an independent oil
and gas producer, since 1988. Prior thereto, Mr. Stephens was an independent oil
operator in Midland, Texas for four years. From 1979 to 1984, Mr. Stephens was
with Cities Service Company and HNG Oil Company. Mr. Stephens received a
Bachelor of Arts Degree in Finance and Land Management from the University of
Texas.

36

Rodney L. Waller, Senior Vice President and Corporate Secretary, joined
the Company in 1999. Previously, Mr. Waller had been with Snyder Oil
Corporation, now part of Devon Energy Corporation, since 1977, where he served
as a senior vice president. Before joining Snyder, Mr. Waller was employed by
Arthur Andersen. Mr. Waller received a Bachelor of Arts degree from Harding
University.

The Board has established five committees to assist it in the discharge of
its responsibilities.

Audit Committee. The Audit Committee reviews the professional services
provided by independent public accountants and the independence of such
accountants from management. This Committee also reviews the scope of the audit
coverage, the annual financial statements and such other matters with respect to
the accounting, auditing and financial reporting practices and procedures as it
may find appropriate or as have been brought to its attention. Messrs. Aikman,
Dub, Eales and Lynch are the members of the Audit Committee.

Compensation Committee. The Compensation Committee reviews and approves
officers' salaries and administers the bonus, incentive compensation and stock
option plans. The Committee advises and consults with management regarding
benefits and significant compensation policies and practices. This Committee
also considers nominations of candidates for officer positions. The members of
the Compensation Committee are Messrs. Aikman, Finkelson, Lynch and McCormick.

Dividend Committee. The Dividend Committee is authorized and directed
to approve the payment of dividends. The members of the Dividend Committee are
Messrs. Edelman and Pinkerton.

Executive Committee. The Executive Committee reviews and authorizes
actions required in the management of the business and affairs of Range, which
would otherwise be determined by the Board, where it is not practicable to
convene the full Board. One of the principal responsibilities of the Executive
Committee will be to review and approve smaller acquisitions. The members of the
Executive Committee are Messrs. Edelman, Finkelson and Pinkerton.

Nominating Committee. The Nominating Committee develops and reviews
background information for candidates for the Board of Directors and makes
recommendations to the Board regarding such candidates. The members of the
Nominating Committee are Messrs. Aikman, Finkelson, Lynch and McCormick.

ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS

Information with respect to officers' compensation is incorporated
herein by reference to the Company's 2002 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information with respect to security ownership of certain beneficial
owners and management is incorporated herein by reference to the Company's 2002
Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.
PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K

(a) 1. and 2. Financial Statements and Financial Statement
Schedules

The items listed in the accompanying index to financial
statements are filed as part of this Annual Report on Form
10-K.

37

3. Exhibits.

The items listed on the accompanying index to exhibits are
filed as part of this Annual Report on Form 10-K.

(b) Reports on Form 8-K.

None.

(c) Exhibits required by Item 601 of Regulation S-K

Exhibits required to be filed pursuant to Item 601 of
Regulation S-K are contained in Exhibits listed in response to
Item 14 (a)3, and are incorporated herein by reference.

(d) Financial Statement Schedules Required by Regulation S-X. The
items listed in the accompanying index to financial statements
are filed as part of this Annual Report on Form 10-K.

38

SIGNATURES

PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE COMPANY HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.

Dated: March 5, 2002
RANGE RESOURCES CORPORATION

By: /s/ John H. Pinkerton
---------------------------------
John H. Pinkerton
President

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE PERSONS ON BEHALF OF THE COMPANY AND IN
THE CAPACITIES AND ON THE DATES INDICATED.

/s/ Thomas J. Edelman Thomas J. Edelman, March 5, 2002
- --------------------------------------
Chairman and Chairman of the Board

/s/ John H. Pinkerton John H. Pinkerton, March 5, 2002
- --------------------------------------
President and Director

/s/ Eddie M. LeBlanc III Eddie M. LeBlanc III, March 5, 2002
- --------------------------------------
Chief Financial and Accounting Officer

/s/ Robert E. Aikman Robert E. Aikman, March 5, 2002
- --------------------------------------
Director

/s/ Anthony V. Dub Anthony V. Dub, March 5, 2002
- --------------------------------------
Director

/s/ V. Richard Eales V. Richard Eales, March 5, 2002
- --------------------------------------
Director

/s/ Allen Finkelson Allen Finkelson, March 5, 2002
- --------------------------------------
Director

/s/ Alexander P. Lynch Alexander P. Lynch, March 5, 2002
- --------------------------------------
Director

/s/ James E. McCormick James E. McCormick, March 5, 2002
- --------------------------------------
Director

39

GLOSSARY

The terms defined in this glossary are used throughout this Form 10-K.

bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6
Mcf for each barrel of oil, which reflects the relative energy content.

Credit Facility. The Range Resources Corporation $225 million revolving bank
facility.

Development well. A well drilled within the proved area of an oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing either oil or natural gas in
sufficient quantities to justify completion as an oil or gas well.

Exploratory well. A well drilled to find and produce oil or gas in an unproved
area, to find a new reservoir in a field previously found to be productive of
oil or gas in another reservoir, or to extend a known reservoir.

Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.

Infill well. A well drilled between known producing wells to better exploit the
reservoir.

LIBOR. London Interbank Offer Rate, the rate of interest at which banks offer to
lend to one another in the wholesale money markets in the City of London. This
rate is a yardstick for lenders involved in high value transactions.

Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.

mcf. One thousand cubic feet.

mcf/d. One thousand cubic feet per day.

mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6
mcf for each barrel of oil, which reflects the relative energy content.

Merger. The acquisition via merger of Domain Energy Corporation by Lomak
Petroleum, Inc. in August 1998. Simultaneously, Lomak's name was changed to
Range Resources Corporation.

Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.

Mmbtu. One million British thermal units. One British thermal unit is the heat
required to raise the temperature of a one-pound mass of water from 58.5 to 59.5
degrees Fahrenheit.

Mmcf. One million cubic feet.

Mmcfe. One million cubic feet of natural gas equivalents.

Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.

Net oil and gas sales. Oil and natural gas sales less oil and natural gas
production expenses.

Oil and gas royalty trust. An arrangement whereby typically, the creating
company conveys a net profits interest in certain of its oil and gas properties
to the newly created trust and then distributes ownership units in the trust to
its unitholders. The function of the trust is to serve as agent to distribute
income from the net profits interest to its unitholders.

40

Present Value. The present value, discounted at 10%, of future net cash flows
from estimated proved reserves, using constant prices and costs in effect on the
date of the report (unless such prices or costs are subject to change pursuant
to contractual provisions).

Productive well. A well that is producing oil or gas or that is capable of
production.

Proved developed non-producing reserves. Reserves that consist of (i) proved
reserves from wells which have been completed and tested but are not producing
due to lack of market or minor completion problems which are expected to be
corrected and (ii) proved reserves currently behind the pipe in existing wells
and which are expected to be productive due to both the well log characteristics
and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves. Proved reserves that can be expected to be
recovered from currently producing zones under the continuation of present
operating methods.

Proved developed reserves. Proved reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.

Recompletion. The completion for production of an existing wellbore in another
formation from that in which the well has previously been completed.

Reserve life index. The presentation of proved reserves defined in number of
years of annual production.

Royalty interest. An interest in an oil and gas property entitling the owner to
a share of oil and natural gas production free of costs of production.

Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves after income taxes calculated holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change pursuant to contractual provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.

Term overriding royalty. A royalty interest that is carved out of the operating
or working interest in a well. Its term does not extend to the economic life of
the property and is of shorter duration than the underlying working interest.
The term overriding royalties in which the Company participates through its
Independent Producer Finance subsidiary typically extend until amounts financed
and a designated rate of return have been achieved. At such point in time, the
override interest reverts back to the working interest owner.

Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.

41

RANGE RESOURCES CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES

(ITEM 14[A],[D])

Exhibits

All other schedules have been omitted since the required information is
not present in amounts sufficient to require submission of the schedule, or
because the information required is included in the financial statements or
footnotes.

42

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

TO THE BOARD OF DIRECTORS AND STOCKHOLDERS
RANGE RESOURCES CORPORATION

We have audited the accompanying consolidated balance sheets of Range
Resources Corporation (a Delaware corporation) as of December 31, 2000 and 2001,
and the related consolidated statements of income, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of Range Resources Corporation's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Range Resources
Corporation as of December 31, 2000 and 2001, and the results of its operations
and its cash flows for the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States.

As explained in Note 2 to the financial statements, effective January
1, 2001, the Company changed its method of accounting for derivatives.

ARTHUR ANDERSEN LLP

Dallas, Texas
March 1, 2002

43

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)

SEE ACCOMPANYING NOTES.

44

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)

SEE ACCOMPANYING NOTES.

45

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

SEE ACCOMPANYING NOTES.

46

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)

SEE ACCOMPANYING NOTES.

47

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) ORGANIZATION AND NATURE OF BUSINESS

Range Resources Corporation ("Range") is engaged in the development,
acquisition and exploration of oil and gas properties primarily in the
Southwestern, Gulf Coast and Appalachian regions of the United States. The
Company also provides financing to smaller oil and gas producers through a
wholly-owned subsidiary, Independent Producer Finance ("IPF"). The Company seeks
to increase its reserves and production primarily through development drilling
and acquisitions. In 1999, Range and FirstEnergy Corp. ("FirstEnergy")
contributed their Appalachian oil and gas properties to an equally owned joint
venture, Great Lakes Energy Partners L.L.C. ("Great Lakes").

After ten years of rapid growth and uninterrupted profitability, Range
concluded a series of disastrous acquisitions in 1997 and 1998. Due to the poor
performance of the acquired properties, the Company was forced to retrench.
Staff was sharply reduced, capital expenditures cut, assets sold, and a program
of exchanging common stock for fixed income securities initiated. Since year-end
1998, parent company bank debt has been reduced 74% to $95.0 million. Total
debt, including Trust Preferred, has been reduced 46% to $392.2 million. As a
result, the Company's financial position has stabilized. The Company expects to
continue to retire debt with internal cash flow and may exchange additional
common stock or other equity-linked securities for indebtedness. Stockholders
could be materially diluted if a substantial amount of the fixed income
securities are exchanged for stock. The extent of dilution will depend on a
number of factors, including the number of shares issued, the price at which
stock is issued or 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 such
exchanges enhance the Company's financial flexibility and should increase the
market value of its common stock.

With its financial strength largely restored, the Company has refocused
on increasing production and reserves. As part of this effort, the Company's
exploration and production effort was placed under the control of a newly hired
Executive Vice President in early 2001. Due to reserve revisions and asset
sales, reserves and production fell in 1999 and 2000. In 2001, there was a
slight increase in production and reserves decreased as the Company's capital
program did not replace production. In 2002, the Company has announced a capital
budget of $100.0 million. Due to the current low product price environment, the
Company will monitor its capital expenditure program carefully and may elect not
to spend the entire amount.

The Company currently believes it has sufficient liquidity and cash
flow to meet its obligations. However, a material drop in oil and gas prices or
a reduction in production and reserves would reduce its ability to fund capital
expenditures, reduce debt and meet its financial obligations. In addition, the
Company's high depletion, depreciation and amortization rate may make it
difficult to remain profitable if oil and gas prices decline further. The
Company operates in an environment with numerous financial and operating risks,
including, but not limited to, the ability to acquire reserves on an attractive
basis, the inherent risks of the search for, development and production of oil
and gas, the ability to sell production at prices which provide an attractive
return and the highly competitive nature of the industry. The Company's ability
to expand its reserve base is, in part, dependent on obtaining sufficient
capital through internal cash flow, borrowings or the issuance of debt or equity
securities.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION

The accompanying consolidated financial statements include the accounts
of the Company, all majority-owned subsidiaries and a pro rata share of the
assets, liabilities, income and expenses of Great Lakes. Liquid investments with
maturities of ninety days or less are considered cash equivalents. The Company
has no other assets or liabilities other than those reported in the consolidated
financial statements.

REVENUE RECOGNITION

The Company recognizes revenues from the sale of products and services
in the period delivered. Revenues at IPF are recognized as received. Although
receivables are concentrated in the oil and gas industry, the Company does not
view

48

this as an unusual credit risk. The Company had allowances for doubtful accounts
relating to its exploration and production business of $1.7 million and $2.2
million at December 31, 2000 and 2001, respectively. At the same dates, IPF had
valuation allowances of $15.3 million and $17.3 million, respectively. A further
decrease in oil prices could cause an increase in IPF's valuation allowances and
a corresponding decrease in income.

MARKETABLE SECURITIES

The Company has adopted Statement of Financial Accounting Standards
("SFAS") No. 115, "Accounting for Certain Investments." Pursuant to SFAS 115,
the Company's holdings of equity securities qualify as available-for-sale and
are recorded at fair value. Unrealized gains and losses are reflected in
Stockholders' equity as a component of Other comprehensive income. A decline in
the market value of a security below cost deemed other than temporary is charged
to earnings. Realized gains and losses are reflected in income. In 1998, certain
securities classified as available for sale were written down by $10.3 million
to their estimated realizable value, because in the opinion of management, the
decline in market value was considered to be other than temporary. During 2001,
the Company determined that the decline in the market value of an equity
security it holds was other than temporary and losses of $1.7 million were
recorded as reductions to Interest and other revenues.

GREAT LAKES

The Company contributed its Appalachian assets to Great Lakes in 1999,
retaining a 50% interest in the venture. Great Lakes' proved reserves, 86% of
which are natural gas, were 423.1 Bcfe at December 31, 2001. In addition, the
joint venture owns 4,600 miles of gas gathering and transportation lines and a
leasehold position of approximately 1,064,144 gross (496,981 net) acres. Great
Lakes has over 1,400 proved drilling locations within its existing fields. At
year-end, Great Lakes has a reserve life index of 17 years.

INDEPENDENT PRODUCER FINANCE

IPF acquires dollar denominated royalties in oil and gas properties
from smaller producers. These royalties are accounted for as receivables because
the investment is recovered from an agreed-upon share of revenues until a
specified rate of return is received. The portion of payments received relating
to the return is recognized as income; remaining receipts are considered a
return of capital and reduce receivables. Receivables classified as current
represent the return of capital expected to be received within twelve months.
All receivables are evaluated quarterly and provisions for uncollectible amounts
are established. At December 31, 2001, the valuation allowance totaled $17.3
million. On certain receivables, income is recorded at rates of return below
those specified due to an assessment of risk. Due to favorable oil and gas
prices during the last nine months of 2000 and the first six months of 2001,
certain of these receivables began to generate all or a greater than anticipated
percentage of contract returns. As a result, $1.8 million of increases in
receivables were recorded as additional income in the first nine months of 2001.
However, because of lower prices, IPF increased its reserve allowance by $2.0
million in the fourth quarter of 2001. During 2000 and 2001, IPF expenses were
comprised of $1.5 million and $1.8 million of general and administrative costs
and $3.4 million and $1.8 million of interest, respectively. IPF recorded
valuation allowances of $603,000 against its revenues in early 2000. However,
because of higher product prices and the resultant increase in cash receipts,
IPF reversed $1.9 million of previously reserved amounts over the remaining
quarters of 2000. The valuation allowance at December 31, 2000 and 2001 was
$15.3 million and $17.3 million, respectively.

49

OIL AND GAS PROPERTIES

The Company follows the successful efforts method of accounting.
Exploratory drilling costs are capitalized pending determination of whether a
well is successful. Costs resulting in discoveries and development costs are
capitalized. Geological and geophysical costs, delay rentals and costs to drill
unsuccessful exploratory wells are expensed. Depletion is provided on the
unit-of-production method. Oil is converted to mcfe at the rate of six mcf per
barrel. The depletion, depreciation and amortization ("DD&A") rates were $1.04,
$1.30 and $1.40 per mcfe in 1999, 2000 and 2001, respectively. Unproved
properties had a net book value of $61.8 million, $49.5 million and $25.7
million at December 31, 1999, 2000 and 2001, respectively.

The Company has adopted SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets", which establishes accounting standards for the impairment of
long-lived assets, certain identifiable intangibles and goodwill. SFAS No. 121
requires a review for impairment whenever circumstances indicate that the
carrying amount of an asset may not be recoverable.

Acreage is assessed periodically to determine whether there has been a
decline in value. If such decline is indicated, a loss is recognized. The
Company compares the carrying value of its acreage to their estimated fair
value, using information such as an assessment of value that could be recovered
from sale, farm-out or exploitation, a geological assessment of the acreage,
other acreage purchases in the area, timing of the associated drilling program
or the property's unique nature. During 1999 and 2001, the Company recorded $6.1
million and $5.1 million, respectively, for impairment of acreage. The amount of
impairment was calculated by determining fair value at year-end using
management's best estimate of the value of these properties.

50

The following acreage was impaired for the reasons indicated (in
thousands):

Impairment on proved properties is generally based on the difference
between the carrying amount of the assets and the present value of the estimated
future cash flows from proved reserves discounted at 10%. Impairment is
recognized only if the carrying amount of a property is greater than its
expected undiscounted future cash flows. For West Delta 30, the proved, probable
and possible reserves were combined for impairment evaluation. (See Management's
Discussion and Analysis - Results of Operations).

Following are the proved property values impaired during 2001 due to
the analysis of estimated future cash flows (in thousands):

51

TRANSPORTATION, PROCESSING AND FIELD ASSETS

The Company's gas gathering systems are located in proximity to certain
of its principal fields. Depreciation on these systems is provided on the
straight-line method based on estimated useful lives of four to fifteen years.
The Company sold its only remaining gas processing facility in June 2000. In
connection with the sale of the gas processing plant, an impairment loss of
$21.0 million was recorded in 1999. See Note 5.

The Company receives fees for providing certain field services which
are recognized as earned. Depreciation on the associated assets is calculated on
the straight-line method based on estimated useful lives ranging from three to
seven years. Buildings are depreciated over ten years.

SECURITY ISSUANCE COSTS

Expenses associated with the issuance of debt are capitalized and
included in Other assets on the balance sheet. These costs are generally
amortized over the expected life of the related securities. When a security is
retired prior to maturity, related unamortized costs are expensed. At December
31, 2001, such capitalized costs totaled $3.0 million.

GAS IMBALANCES

The Company uses the sales method to account for gas imbalances,
recognizing revenue based on cash received rather than gas produced. At December
31, 2000 and December 31, 2001, gas imbalance liabilities of $318,000 and
$114,000 were included in Accrued liabilities, respectively.

52

COMPREHENSIVE INCOME

The Company follows SFAS No. 130, "Reporting Comprehensive Income,"
defined as changes in Stockholders' equity from nonowner sources. The following
is a calculation of comprehensive income for each of the three years ended
December 31, 2001 (in thousands).

* Includes $1,000 gain related to amounts due from Enron. On adopting
SFAS 133 on January 1, 2001, the Company recorded $72.1 million of unrealized
pre-tax hedging loss on its balance sheet and an offsetting deficit in
Comprehensive income.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported assets, liabilities, revenues and expenses
as well as disclosure of contingent assets and liabilities. Actual results could
differ from those estimates. Estimates which may significantly impact the
Company's financial statements include reserve estimates, analysis of impairment
of oil and gas properties, reserve requirement for IPF receivables and fair
value estimates of derivatives.

53

RECENT ACCOUNTING PRONOUNCEMENTS

In June 2001, the Financial Accounting Standards Board (FASB) issued
Statements of Financial Accounting Standards No. 143 "Accounting for Asset
Retirement Obligations" (SFAS No. 143). SFAS No. 143 establishes a new
accounting model for the recognition and measurement of retirement obligations
associated with tangible long-lived assets. SFAS No. 143 requires that an asset
retirement cost should be capitalized as part of the cost of the related
long-lived asset and subsequently allocated to expense using a systematic and
rational method. The Company will adopt the Statement effective January 1, 2003.
The transition adjustment resulting from the adoption of SFAS No. 143 will be
reported as a cumulative effect of a change in accounting principle. At this
time, the Company cannot reasonably estimate the effect of the adoption of this
Statement on either its financial position or results of operations.

In August 2001, the FASB issued SFAS No. 144, "Accounting for
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). This Statement
establishes a single accounting model for long-lived assets to be disposed of by
sale and provides additional implementation guidance for assets to be held and
used and assets to be disposed of other than by sale. There will be no financial
implication related to the adoption of SFAS No. 144, and the guidance will be
applied on a prospective basis. The Company adopted the Statement effective
January 1, 2002.

Beginning in 2001, SFAS No. 133, "Accounting for Derivatives," required
that derivatives be recorded on the balance sheet as assets or liabilities at
fair value. Changes in the fair value of all derivatives are recognized
immediately in earnings unless the derivative qualifies as a hedge of future
cash flows. For derivatives qualifying as hedges of future cash flows, the
effective portion of any changes in fair value is recognized in a component of
stockholders' equity called OCI and then reclassified to earnings when the
underlying anticipated transaction is consummated. Any ineffective portion of
such hedges is recognized in earnings as it occurs. On adopting SFAS No. 133 on
January 1, 2001, the Company recorded $72.1 million of unrealized pre-tax
hedging loss on its balance sheet and an offsetting deficit in OCI. Due to the
decline in oil and gas prices since January 1, 2001, this loss had become a net
$52.1 million unrealized pre-tax gain by December 31, 2001. SFAS No. 133 tends
to increase earnings volatility in independent oil companies.

The Company had hedge agreements with Enron North America Corp.
("Enron") for 22,700 Mmbtu per day, at $3.20 per Mmbtu for 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 2001 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 as of
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
some market offers for purchasing these contracts at percentages much less than
par.

The Company enters into contracts to reduce the effect of fluctuations
in oil and gas prices. These contracts qualify as cash flow hedges. Prior to
2001, gains and losses were determined monthly and included in oil and gas
revenues in the period the hedged production was sold. Starting in 2001, gains
or losses on open contracts are recorded either in current period income or in
OCI. The Company also enters into swap agreements to reduce the risk of changing
interest rates. These agreements qualify as fair value hedges and related income
or expense is recorded as an adjustment to interest expense in the period
covered.

Interest and other revenues in the Consolidated Statements of Income
was increased for ineffective hedging gains of $2.3 million in the twelve months
ended December 31, 2001. Unrealized hedging gains (excluding Enron), including
interest rate swaps, of $49.5 million and OCI of $37.0 million, net of taxes,
were recorded on the balance sheet at December 31, 2001. See Note 7.

RECLASSIFICATIONS

Certain reclassifications have been made to the presentation of prior
periods to conform with current classifications.

54

(3) ACQUISITIONS

All acquisitions have been accounted for as purchases. Purchase prices
were allocated to acquired assets based on their estimated fair value at
acquisition. Acquisitions have been funded with internal cash flow, bank
borrowings and the issuance of debt and equity securities. The Company purchased
various other properties for consideration of $846,000, $4.7 million and $9.5
million during the years ended December 31, 1999, 2000 and 2001, respectively.

(4) IPF RECEIVABLES

At December 31, 2000 and 2001, IPF had net receivables of $48.9 million
and $41.4 million, respectively. The receivables represent overriding royalty
interests payable from an agreed-upon share of revenues until a specified return
is achieved. The royalties constitute property interests that serve as security
for the receivables. On certain IPF receivables, income has been recorded at
rates below those specified in the contract based on assessment of risk. Due to
favorable oil and gas prices during the last nine months of 2000 and the first
half of 2001, some of these receivables began to generate a greater proportion
of their contractual return. In the first nine months of 2001, the book value of
the affected receivables was increased and approximately $1.8 million was
recorded as additional income. However, because of lower prices, IPF increased
its reserve allowance by $2.0 million in the fourth quarter of 2001. The Company
estimates that $7.0 million of receivables at December 31, 2001 will be repaid
in the next twelve months and has classified them as current. IPF receivables
reflected valuation allowances of $15.3 million and $17.3 million at December
31, 2000 and 2001, respectively. A further decline in the price of oil could
cause an increase in IPF's valuation allowances and a corresponding decrease in
income.

(5) DISPOSITIONS

In June 2000, the Company sold a gas plant for $19.7 million and
recorded a $716,000 loss.

The following table presents unaudited pro forma operating results as
if the sale of the gas plant had occurred on January 1, 2000 (in thousands,
except per share data).

The pro forma results have been prepared for comparative purposes only.
They do not purport to present actual results that would have been achieved or
to be indicative of future results.

55

(6) INDEBTEDNESS

The Company had the following debt and Trust preferred outstanding as
of the dates shown. Interest rates, excluding the impact of interest rate swaps,
at December 31, 2001 are shown parenthetically (in thousands):

Subsequent to December 31, 2001, the Company exchanged an additional
$0.9 million face amount of the 8.75% Notes. Interest paid in cash during the
years ended December 31, 2000 and 2001 totaled $42.2 million and $31.2 million,
respectively. The Company does not capitalize interest expense.

SENIOR DEBT

The Company maintains a $225 million secured revolving bank facility
(the "Parent Facility"). The Parent Facility provides for a borrowing base which
is subject to semi-annual redeterminations in April and October. On March 1,
2002, the borrowing base on the Parent Facility was $120.0 million of which
$16.5 million was available. Redeterminations are based on a variety of factors,
including banks' projection of future cash flows. Redeterminations require
approval by 75% of the lenders, redeterminations which result in an increase
require 100% approval. Interest is payable the earlier of quarterly or as LIBOR
notes mature. The loan matures in February 2003. A commitment fee is paid
quarterly on the undrawn balance at a rate of 0.25% to 0.50%. The interest rate
on the Parent Facility is LIBOR plus 1.50% to 2.25%, depending on outstandings.
At December 31, 2001, the commitment fee was 0.50% and the interest rate margin
was 0.75%. The weighted average interest rates on the Parent Facility was 8.8%
and 6.4% for the years ended December 31, 2000 and 2001, respectively. As of
March 1, 2002, the interest rate was 3.3%.

NON-RECOURSE DEBT

The Company consolidates its proportionate share of borrowings on Great
Lakes' $275.0 million secured revolving bank facility (the "Great Lakes
Facility"). The Great Lakes Facility is non-recourse to Range and provides for a
borrowing base, which is subject to semi-annual redeterminations in April and
October. On March 1, 2002, the borrowing base was $200.0 million of which $54.0
million was available. Interest is payable the earlier of quarterly or as LIBOR
notes mature. The loan matures in September 2003. The interest rate on the
facility is LIBOR plus 1.50% to 2.00%, depending on outstandings. A

56

commitment fee is paid quarterly on the undrawn balance at an annual rate of
0.25% to 0.50%. At December 31, 2001, the commitment fee was 0.50% and the
interest rate margin was 0.625%. The weighted average interest rates on these
borrowings, excluding interest rate hedges, were 8.5% and 6.4% for the years
ended December 31, 2000 and 2001, respectively. After hedging, the rate was 8.6%
and 7.6% for the twelve months ended December 30, 2000 and 2001, respectively.
At March 1, 2002, the interest rate was 3.6%, excluding interest rate hedges and
6.5% including interest rate hedges.

IPF has a $100.0 million secured revolving credit facility (the "IPF
Facility"). The IPF Facility is non-recourse to Range and matures in January
2004. The borrowing base under the IPF Facility is subject to semi-annual
redeterminations in April and October. On March 1, 2002, the borrowing base on
the IPF Facility was $35.0 million of which $11.7 million was available. The IPF
Facility bears interest at LIBOR plus 1.75% to 2.25% depending on outstandings.
Interest expense in the IPF Facility is included in IPF expenses in the
Consolidated Statements of Income and amounted to $3.4 million and $1.8 million
for the years ended December 31, 2000 and 2001, respectively. A commitment fee
is paid quarterly on the undrawn balance at a rate of 0.375% to 0.50%. The
weighted average interest rate on these borrowings was 8.5% and 6.4% for the
years ended December 31, 2000 and 2001, respectively. As of March 1, 2002, the
interest rate was 4.3%.

SUBORDINATED NOTES

The 8.75% Senior Subordinated Notes due 2007 (the "8.75% Notes") become
redeemable beginning on January 15, 2002, in whole or in part, at 104.375% of
principal, declining 1.46% each January 15 to par in 2005. The 8.75% Notes are
unsecured general obligations subordinated to all senior debt (as defined). The
8.75% Notes are guaranteed on a senior subordinated basis by the Company's
subsidiaries. Interest is payable semi-annually in January and July. During the
twelve months ended December 31, 2001, the Company repurchased $42.5 million
face amount of the 8.75% Notes at a discount. The Company also exchanged $3.4
million of the 8.75% Notes for common stock. Exchanges are not reflected on the
cash flow statement. The cash flow reflects a $41.2 million Repayment of debt
relating to these repurchases. The gain on these repurchases is included as a
Gain on retirement of securities on the Consolidated Statements of Income. The
repurchased notes are held in treasury and may be reissued. Subsequent to
December 31, 2001, the Company exchanged for common stock an additional $0.9
million face amount of the 8.75% Notes. As of March 1, 2002, $78.2 million of
the 8.75% Notes remained outstanding.

The 6% Convertible Subordinated Debentures Due 2007 (the "6%
Debentures") are convertible into common stock at the option of the holder at
any time at a price of $19.25 per share. Interest is payable semi-annually in
February and August. The 6% Debentures mature in 2007 and are currently
redeemable at 103.5% of principal, declining 0.5% each February through 2007.
The 6% Debentures are unsecured general obligations subordinated to all senior
indebtedness (as defined), including the 8.75% Notes. During 2000 and 2001,
$13.8 million and $5.7 million of 6% Debentures were retired at a discount in
exchange for 2.5 million and 0.7 million shares of common stock, respectively.
In addition, $2.3 million were repurchased in 2001. Exchanges are not reflected
on the cash flow statement. Extraordinary gains of $4.3 million and $1.9 million
were recorded in 2000 and 2001, respectively. As of March 1, 2002, $29.6 million
of the 6% Debentures remained outstanding.

TRUST PREFERRED

In 1997, a special purpose affiliate, (the "Trust") issued $120 million
of 5 3/4% Trust Convertible Preferred Securities (the "Trust Preferred"),
represented by 2,400,000 shares of Trust Preferred priced at $50 a share. The
Trust Preferred is convertible into common stock at a price of $23.50 per share.
The Trust invested the proceeds in 5 3/4% convertible junior subordinated
debentures issued by the Company (the "Junior Debentures"), its sole asset. The
Junior Debentures and the Trust Preferred mature in November 2027. At December
31, 2001, the Junior Debentures and the related Trust Preferred are redeemable
in whole or in part at 103.450% of principal declining 0.58% each November to
par in 2007.

The Company guarantees payments on the Trust Preferred only to the
extent the Trust has funds available. Such guarantee, taken together with other
obligations provides a full subordinated guarantee of the Trust Preferred. The
Company has the right, at its sole discretion, to suspend payment of all
distributions on the Trust Preferred for five years without triggering a
default. The accounts of the Trust are included in Range's consolidated
financial statements after eliminations. Distributions recorded as interest
expense are deductible for tax purposes, and are subject to limitations in the
Parent Facility as described below. In the twelve months ended December 31,
2001, $2.9 million of Trust Preferred was reacquired at a discount in exchange
for 291,000 shares of common stock. In addition, $50,000 of Trust Preferred were
repurchased. An

57

extraordinary gain of $1.2 million was recorded in 2001. The exchange
transactions are not reflected on the cash flow statement because no cash was
involved. As of March 1, 2002, $89.7 million of the Trust Preferred remained
outstanding.

The debt agreements contain various covenants relating to net worth,
working capital maintenance, restrictions on dividends and financial ratio. If
certain ratio requirements are not met, payments of interest on the Trust
Preferred would be restricted. The Parent Facility prohibits the payment of
dividends on common stock. The Company was in compliance with all such covenants
at December 31, 2001. Under the most restrictive covenant, $3.0 million of
dividends or other restricted payments could be paid at December 31, 2001. Under
the Parent Facility, common dividends are prohibited and dividends may not be
paid on the Trust Preferred unless certain ratio requirements are met.

(7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

The Company's financial instruments include cash and equivalents,
accounts receivable, accounts payable, debt obligations and commodity and
interest rate hedges. The book value of cash and equivalents and accounts
receivable and payable are considered to be representative of fair value because
of their short maturity. The book values of borrowings under the Parent
Facility, the Great Lakes Facility, and IPF Facility are believed to approximate
fair value because of their floating rate structure.

A portion of the Company's future oil and gas sales is periodically
hedged through the use of option or swap contracts. Realized gains and losses on
these instruments are reflected in the contract month being hedged as an
adjustment to oil and gas revenue. At times, the Company seeks to manage
interest rate risk on its credit facilities through the use of swaps. Gains and
losses on these swaps are included as an adjustment to interest expense in the
relevant periods.

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The following table sets forth the book and estimated fair values of financial
instruments (in thousands):

* Excluding Enron

At December 31, 2001, the Company had open hedging contracts (excluding
contracts with Enron) covering 47.3 Bcf of gas at prices averaging $4.02 per mcf
and 700,000 barrels of oil at prices averaging $25.97 barrel. Their fair value,
represented by the estimated amount that would be realized upon termination,
based on contract versus New York Mercantile Exchange ("NYMEX") price,
approximated a net unrealized pre-tax gain of $52.1 million at December 31,
2001. These contracts expire monthly through December 2005. Gains or losses on
open and closed hedging transactions are determined as the difference between
the contract price and the reference price, generally closing prices on NYMEX.
Transaction gains and losses are determined monthly and are included as
increases or decreases to oil and gas revenues in the period the hedged
production is sold. Net pre-tax losses incurred relating to these derivatives
for the years ended December 31, 1999, 2000 and 2001 were $10.6 million, $43.2
million, and $6.2 million, respectively. These hedging positions are recorded on
the Company's balance sheet at an estimate of fair value based on a comparison
of the contract price and a reference price, generally NYMEX.

The Company had hedge agreements with Enron for 22,700 Mmbtu per day,
at $3.20 per Mmbtu for 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 2001 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 as of 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 some market offers for purchasing these
contracts at percentages much less than par.

59

The following schedule shows the effect of the Company's hedge position
for the four quarters ended December 31, 2001 and the projected impact of open
contracts (excluding contracts with Enron) as of that date.

Interest rate swap agreements are accounted for on the accrual basis.
Income or expense resulting from these agreements is recorded as an adjustment
to interest expense in the period covered. At December 31, 2001, Great Lakes had
interest rate swap agreements totaling $100.0 million, 50% of which is
consolidated at Range. Two agreements totaling $45.0 million at rates of 7.1%
each expire in May 2004. Two agreements of $10.0 million each at 6.2% which
expire in December 2002. Five agreements totaling $35.0 million at rates of
4.8%, 4.7%, 4.6%, 4.5% and 4.5% which expire in June of 2003. Range's share of
the fair value of the swaps at December 31, 2001, was a net loss of $2.6 million
based on current quotes. The agreements expiring in May 2004 may be terminated
at the counterparty's option in May 2002. On December 31, 2001, the 30-day LIBOR
rate was 1.9%. The value of these swap agreements is marked to market each
quarter. For 2001, GLEP incurred additional interest expense of $1.1 million due
to interest swaps.

The combined fair value of oil and gas hedging contracts and interest
rate swaps, totaling $49.5 million appear as an Unrealized hedging gain on the
balance sheet. Hedging activities are conducted with major financial or
commodities trading institutions which management believes are acceptable credit
risks. At times, such risks may be concentrated with certain counterparties. The
credit worthiness of these counterparties is subject to continuing review.

(8) COMMITMENTS AND CONTINGENCIES

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

60

In 2000, a royalty owner filed a suit asking for a class action
certification against Great Lakes and the Company in New York, alleging that gas
was sold to affiliates and gas marketers at low prices, inappropriate post
production expenses reduced proceeds to the royalty owners, and that Great Lakes
improperly accounted for the royalty owners' share of gas. The action sought a
proper accounting for all gas sold, 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 state court in New York. While the outcome of this
suit is uncertain, the Company believes it will be resolved without material
adverse effect on its financial position or results of operations.

The Company leases certain office space and equipment under cancelable
and non-cancelable leases, most of which expire within three years and may be
renewed by the Company. Rent expense under such arrangements totaled $1.1
million, $1.0 million and $1.1 million in 1999, 2000 and 2001, respectively.
Future minimum rental commitments under non-cancelable leases are as follows (in
thousands):

2002 $ 820
2003 546
2004 513
2005 501
2006 126
2007 and thereafter --
---------
$ 2,506
=========

(9) STOCKHOLDERS' EQUITY

In 1995, the Company issued 1,150,000 shares of $2.03 Convertible
Exchangeable Preferred Stock (the "$2.03 Preferred") for $28.8 million. The
$2.03 Preferred was convertible into 2.632 shares of common stock representing a
conversion price of $9.50 per common share. Through December 31, 2000, $23.2
million of the $2.03 Preferred had been exchanged for 4.6 million of common
stock. For the twelve months ended December 31, 2001, the majority of the
outstanding $2.03 Preferred was exchanged for 767,000 shares of common stock and
the remaining shares were repurchased for cash. Gains on exchanges of $2.03
Preferred are not included in net income but they are included in income
available to common shareholders. Exchange transactions are not reflected on the
cash flow statement because no cash was involved. The elimination of the $2.03
Convertible Preferred stock has reduced the annual dividend requirement by $2.3
million.

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The following is a schedule of changes in outstanding common shares:

Supplemental disclosures of non-cash investing and financing activities

(10) STOCK OPTION AND PURCHASE PLANS

The Company has four stock option plans, of which two are active, and a
stock purchase plan. Under these plans, incentive and non-qualified options and
stock purchase rights are issued to directors, officers, and employees pursuant
to decisions of the Compensation Committee of the Board. Information with
respect to the stock option plans is summarized below:

Two years ago, shareholders approved the 1999 Stock Option Plan (the
"1999 Plan") providing for the issuance of options on 1.4 million common shares.
In May 2001, shareholders approved an increase in the number of options issuable
to 3.4 million shares. All options issued under the 1999 Plan vest 25% per year
beginning a year after grant and expire in 10 years. During the year-ended
December 31, 2001, 774,350 options were granted under the 1999 Plan at exercise
prices of $4.17 to $6.67 a share. At December 31, 2001, 1.3 million options were
outstanding under the 1999 Plan at exercise prices of $1.94 to $6.67.

62

The Company also maintains the 1989 Stock Option Plan (the "1989 Plan")
which authorized the issuance of options on 3.0 million common shares. No
options have been granted under this plan since the 1999 Plan was adopted.
Options issued under the 1989 Plan vest 30% after one year, 60% after two years
and 100% after three years and expire in 5 years. At December 31, 2001, 542,700
options remained outstanding under the 1989 Plan at exercise prices of $2.63 to
$17.75.

In 1994, shareholders approved the Outside Directors' Stock Option Plan
(the "Directors' Plan"). In 2000, shareholders approved an increase in the
number of options issuable under the Directors' Plan to 300,000, extended the
term of the options to ten years and set the vesting period at 25% per year
beginning a year after grant. During the twelve months ended December 31, 2001,
56,000 options were granted under the Directors' Plan at exercise prices of
$5.52 to $6.00 a share. At December 31, 2001, 120,000 options were outstanding
under the Directors' Plan at exercise prices of $2.81 to $6.00.

The Domain stock option plan was adopted when Domain was acquired, with
existing Domain options becoming exercisable into Range common stock. Since
August 1998, no further options have been granted under the Plan. At December
31, 2001, 137,484 options remained outstanding under the Plan at a price of
$3.46 a share.

In total, 2.1 million options are outstanding at December 31, 2001 at
exercise prices ranging from $1.94 to $17.75 as follows:

In 1997, shareholders approved a Stock Purchase Plan (the "Stock
Purchase Plan") authorizing the sale of 900,000 shares of common stock to
officers, directors, key employees and consultants. Under the Stock Purchase
Plan, the right to purchase shares at prices ranging from 50% to 85% of market
value may be granted and there is a one year hold requirement. To date, all
purchase rights have been granted at 75% of market. In May 2001, shareholders
approved an increase in the number of shares authorized under the Plan to
1,750,000. Through December 31, 2001, 1,121,319 shares have been sold under the
Plan, for $4.7 million. At December 31, 2001, rights to purchase 203,000 shares
were outstanding.

The Company has adopted the disclosure-only provisions of SFAS No.
123, "Accounting for Stock-Based Compensation." Accordingly, no compensation
cost has been recognized for the stock option plans. Had compensation cost been
determined based on the fair value at the grant date for awards in 1999, 2000
and 2001 consistent with the provisions of SFAS No. 123, the Company's net
income and earnings per share would have been reduced to the pro forma amounts
indicated below:

The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following weighted-average
assumptions used for 1999, 2000 and 2001, respectively: fair value of $1.37,
$2.14 and

63

$6.50 per share; dividend yields of $0.03, $0 and $0 per share; expected
volatility factors of 3.55, 64.89 and 69.80; risk-free interest rates of 5.10%,
5.51% and 4.98%, and an average expected life of six years.

(11) BENEFIT PLAN

The Company maintains a 401(k) Plan for its employees. The Plan permits
employees to contribute up to 15% of their salary on a pre-tax basis. The
Company makes discretionary contributions to the 401(k) Plan annually which are
fully vested after four years of service. In 1999, 2000 and 2001, the Company
contributed $854,000, $483,000 and $554,000 of common stock (valued at market)
to the 401(k) Plan. Employees have a variety of investment options available in
the 401K Plan and are encouraged to maintain diversity in accordance with their
personal investment strategy.

(12) INCOME TAXES

The Company's federal income tax provision (benefit) for the years
ended December 31, 1999, 2000 and 2001 was $388,000, $0 and $14,505,
respectively. The current portion of income tax provision for 1999 represented
state income tax payable. A reconciliation between the statutory federal income
tax rate and the Company's effective federal income tax rate is as follows:

The Company follows SFAS Statement No. 109, "Accounting for Income
Taxes," pursuant to which the liability method is used. Under this method,
deferred tax assets and liabilities are determined based on differences between
financial reporting and tax bases of assets and liabilities and are measured
using the enacted tax rates and regulations that will be in effect when the
differences are expected to reverse.

Significant components of the Company's deferred tax liabilities and
assets are as follows (in thousands):

64

A valuation allowance on the net deferred tax asset was originally
established due to the uncertainty of whether future taxable income would be
sufficient to utilize the net deferred tax asset. Increased oil and gas prices
in early 2001 allowed the reversal of the valuation allowance during the first
half of 2001. Therefore, income taxes were recorded at a statutory rate for
financial reporting in the second and third quarters of 2001. Due to the
Company's tax loss carryover, percentage depletion carryover and AMT credits,
such statutory taxes were deferred. However, due to the property impairments
recorded in the fourth quarter of 2001, taxes recorded earlier in the year were
reversed and no statutory provision for taxes was required in 2001. A deferred
tax liability of $9.7 million is recorded on the balance sheet at year-end 2001.
Without considering Other comprehensive income (loss), deferred tax assets
exceed deferred tax liabilities by $7.0 million. The inclusion of OCI causes the
deferred tax liabilities to exceed deferred tax assets by the amount recorded on
the balance sheet. 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 hedge 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.

At December 31, 2001, the Company had regular net operating loss
("NOL") carryovers of $174.3 million including alternative minimum tax ("AMT")
NOL carryovers of $155.9 million that expire between 2012 and 2020. AMT NOLs
generally offset taxable income and to such extent, no income tax payments are
required. Regular NOLs utilized in amounts in excess of AMT NOLs generate an
alternative minimum tax payment, which can be offset by AMT credits. NOLs
generated prior to a change of control are subject to limitations. The Company
experienced several change of control events between 1994 and 1998 due to
acquisitions. Consequently the use of $34.1 million of NOLs is limited to $10.2
million per year. Remaining NOLs are not limited. At December 31, 2001, the
Company had a statutory depletion carryover of $6.6 million and an AMT credit
carryovers of $660,000 which are not subject to limitation or expiration.

The following table sets forth the year of expiration of NOL (pretax)
carryovers which generate the largest component of the deferred tax assets
listed above:

(13) RESTRUCTURING COSTS

In late 1998, the Company initiated a restructuring plan to reduce
costs. The restructuring plan included closing field office, eliminating certain
geological and exploration positions, canceling certain exploration and drilling
obligations and consolidating administrative functions at the remaining
locations. The plan was completed in 1999.

65

(14) EARNINGS PER COMMON SHARE

The following table sets forth the computation of basic and diluted
earnings per common share (in thousands except per share amounts):

During 1999, 2000 and 2001, 505,000, 358,000 and 423,000 stock options
were included in the computation of diluted earnings per share. All remaining
stock options, the 6% Debentures, Trust Preferred and the $2.03 Preferred were
not included in the computation because their inclusion would have been
antidilutive.

The Company has and will continue to consider exchanging common stock
or other equity-linked securities for fixed income securities. Existing common
stockholders may be materially diluted if substantial exchanges are consummated.
The extent of dilution will depend on the number of shares and price at which
common stock is issued, the price at which newly issued securities are
convertible into common stock, and the price at which fixed income securities
are reacquired.

(15) MAJOR CUSTOMERS

The Company markets its production on a competitive basis. Gas is sold
under various types of contracts ranging from life-of-the-well to short-term
contracts that are cancelable within 30 days. Oil purchasers may be changed on
30 days notice. The price for oil is generally equal to a posted price set by
major purchasers in the area. The Company sells to oil purchasers on the basis
of price and service. For the year ended December 31, 2001, three customers
accounted for 10% or more of total oil and gas revenues and the combined sales
to those three customers accounted for 50% of total oil and gas revenues.
Management believes that the loss of any one customer would not have a material
long-term adverse effect on the Company.

From the inception of the Great Lakes joint venture through June 30,
2001, Great Lakes sold approximately 90% of its gas production to FirstEnergy,
at prices based on the close of NYMEX each month plus a basis differential.
Effective July 1, 2001, Great Lakes began selling its gas to several different
companies, including FirstEnergy. Over the next twelve months, Great Lakes
expects to sell roughly 33% of its gas to FirstEnergy with the remaining 67%
being sold to eight companies. Currently 91% of Great Lakes gas is sold at
prices based on the close of NYMEX contracts each month plus a basis
differential. The remainder is sold at a fixed price.

66

(16) OIL AND GAS ACTIVITIES

The following summarizes selected information with respect to producing
activities:

Acquisition costs in 1999 do not reflect $68 million of value
associated with the Company receiving a 50% interest in the reserves contributed
by FirstEnergy to Great Lakes. The Company's share of such reserves was 81.6
Bcfe. Exploration costs include capitalized as well as expensed outlays.

(17) INVESTMENT IN GREAT LAKES

The Company owns 50% of Great Lakes and consolidates its proportionate
interest in the joint venture's assets, liabilities, revenues and expenses. The
following table summarizes the interest in Great Lakes' audited financial
statements as of or for the year ended December 31, 2001.

67

(18) GAIN ON FORMATION OF GREAT LAKES

In September 1999, Range transferred all of its Appalachian oil and gas
properties and associated gas gathering and transportation systems to Great
Lakes in exchange for a 50% ownership interest. Additionally, the Company
contributed $188.3 million of indebtedness to Great Lakes. The Great Lakes
partners have no commitment to support the operations or obligations of Great
Lakes. Great Lakes recorded the assets contributed at fair market value. Range
recognized a gain of $39.8 million, which was attributable to the portion of the
net assets associated with the 50% interest of the Company's joint venture
partner. The gain was calculated by comparing the estimate of the fair market
value of the assets and liabilities conveyed to their net book value. The Great
Lakes DD&A rate for the Company's proportionate share of production is higher
than the Company's DD&A rate for such production due to the lower cost basis
attributed to the investment in Great Lakes versus the Company's proportionate
share of Great Lakes assets. DD&A is reduced in consolidation to reflect the
Company's investment.

(19) EXTRAORDINARY ITEMS

During 1999, 699,000 shares of common stock were exchanged for $2.3
million of Trust Preferred and $3.6 million of 6% Debentures. During 2000, 5.7
million shares of common stock were exchanged for $25.0 million of Trust
Preferred and $13.8 million of 6% Debentures. During 2001, 1.8 million shares of
common stock were exchanged for $2.9 million of Trust Preferred, $5.7 million of
6% Debentures and $3.4 million of 8.75% Senior Subordinated Notes. In addition,
$50,000 of Trust Preferred, $2.3 million of 6% Debentures and $42.5 million of
8.75% Senior Subordinated Notes were repurchased. Since 1998, there have been
13.6 million shares of common stock exchanged for convertible debt and
securities in the amount of $85.4 million. In connection with these exchanges,
an extraordinary gain net of costs of $2.4 million, $17.8 million and $4.0
million was recorded in 1999, 2000 and 2001, respectively, because the
securities were retired at a discount. In addition, 4.6 million and 767,000
shares of common stock were exchanged for $23.2 million and $5.4 million of the
$2.03 Preferred during 2000 and 2001, respectively. In 2001, the remaining of
$2.03 Preferred were repurchased for $74,000.

(20) UNAUDITED SUPPLEMENTAL RESERVE INFORMATION

The Company's proved oil and gas reserves are located in the United
States. Proved reserves are those quantities of crude oil and natural gas which,
based upon analysis of geological and engineering data, can with reasonable
certainty be recovered in the future from known oil and gas reservoirs. Proved
developed reserves are those proved reserves, which can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped oil and gas reserves are proved reserves that are expected to
be recovered from new wells on undrilled acreage.

68

QUANTITIES OF PROVED 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 results
were far less attractive than projected in the acquisition engineering. The
steep decline in energy prices, which began in late 1997, combined with the less
than expected performance caused certain downward reserve revisions in 1998. In
1999, a series of exhaustive field performance studies were conducted and the
properties were re-engineered. The studies included a complete review of 1997
and 1998 capital expenditures and development results, a re-examination of
estimates of reservoir thickness, oil and gas in place, ultimate recoverable
reserves and the relationship of pressures and production declines to these
estimates. Reserve reductions were recorded in 1999, based primarily on
performance and a reassessment of the size of the reservoirs offset to a minor
degree by upward revisions due to price increases. The 1999 development program
in these fields was in part designed to confirm revised engineering forecasts.
The downward revisions at year-end 2000 represented what is believed to be the
final integration of the field studies, 1999 and 2000 development results,
pressure data and production declines. Adjustments at year-end 2000 involved
removing from proved reserves drilling and recompletion locations that, based on
perceived risk, will probably not be drilled. The downward revision that
occurred at year-end 2001 is unlike the previous revisions the Company has
experienced. Previous revisions were associated with the disappointing
performance of the properties that were acquired during the late 1990's. The
entire reserve revision in 2001 is associated with the dramatic reduction in
commodity prices between year-end 2000 and year-end 2001. The approximate 73%
reduction in gas price on the Company's proved reserves, which are 76% gas by
reserve volume, resulted in a significant revision. If there had been no change
in commodity prices, the Company would have experienced a slightly positive
revision. While there can be no

69

assurance that future reserve revisions will not occur, management believes that
it has fully assessed all data available through this date. That assumption is
supported by the fact that performance in the fields appears to have stabilized.

The average prices used at December 31, 2001 to estimate the reserve
information were $17.59 per barrel for oil, $12.38 per barrel for natural gas
liquids and $2.70 per Mcf for gas using the benchmark NYMEX prices of $20.38 per
barrel and $2.63 per Mmbtu. The average prices at December 31, 2000 were $24.46
per barrel for oil, $14.91 per barrel for natural gas liquids and $9.57 per Mcf
for gas using the benchmark NYMEX prices of $26.80 per barrel and $9.77 per
Mmbtu. The average prices at December 31, 1999 were $23.48 per barrel for oil,
$15.69 per barrel for natural gas liquids and $2.34 per mcfe for gas using the
benchmark NYMEX prices of $25.60 per barrel and $2.44 per Mmbtu.

The "Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves" ("Standardized Measure") is a disclosure
requirement of SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." The Standardized Measure does not purport to present the fair
market value of proved oil and gas reserves. This would require consideration of
expected future economic and operating conditions, which are not taken into
account in calculating the Standardized Measure.

Future cash inflows were estimated by applying year-end prices to the
estimated future production less estimated future production costs based on
year-end costs. Future net cash inflows were discounted using a 10% annual
discount rate to arrive at the Standardized Measure.

STANDARDIZED MEASURE

70

CHANGES IN STANDARDIZED MEASURE

71

RANGE RESOURCES CORPORATION

INDEX TO EXHIBITS

(Item 14[a 3])

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4.9 Form of Trust Indenture relating to the Senior Subordinated
Notes due 2007 between Lomak Petroleum, Inc., and Fleet
National Bank as trustee (incorporated on the Company's
Registration Statement (No. 333-20257)).

4.10 Credit Agreement, dated as of June 7, 1996, between Domain
Finance Corporation and Compass Bank --Houston (including the
First and the Second Amendment thereto) (incorporated by
reference to Exhibit 10.3 of Domain Energy Corporation's
Registration Statement on Form S-1 filed with the Commission
on April 4, 1997 and Exhibit 10.3 of Amendment No. 1 to Domain
Energy Corporation's Registration Statement on Form S-1 filed
with the Commission on May 21, 1997) (File No. 333-24641).

4.11 Corrected Certificate of Designations of Preferred Stock of
Range Resources Corporation Designated As $2.03 Convertible
Exchangeable Preferred Stock, Series D (incorporated by
reference to the Company's Form 10-Q dated November 6, 2000).

10.1 Incentive and Non-Qualified Stock Option Plan dated March 13,
1989 (incorporated by reference to the Company's Registration
Statement (No. 33-31558)).

10.2 Advisory Agreement dated September 29, 1988 between Lomak and
SOCO (incorporated by reference to the Company's Registration
Statement (No. 33-31558)).

10.3.1 1989 Stock Purchase Plan (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).

10.3.2 Amendment to the Lomak Petroleum, Inc., 1989 Stock Purchase
Plan, as amended (incorporated by reference to the Company's
Registration Statement (No. 333-44821)).

10.4 Form of Directors Indemnification Agreement (incorporated by
reference to the Company's Registration Statement (No.
333-47544)).

10.5.1 1994 Outside Directors Stock Option Plan (incorporated by
reference to the Company's Registration Statement (No.
333-47544)).

10.5.2 1994 Outside Directors Stock Option Plan - Amendment No. 1
(incorporated by reference to the Company's Registration
Statement No. 333-40380)

10.5.3 1994 Outside Directors Stock Option Plan - Amendment No. 2
(incorporated by reference to the Company's Registration
Statement No. 333-40380)

10.5.4 1994 Outside Directors Stock Option Plan - Amendment No. 3
(incorporated by reference to the Company's Registration
Statement No. 333-40380)

10.5.5 1994 Outside Directors Stock Option Plan - Amendment No. 4
(incorporated by reference to the Company's Registration
Statement No. 333-40380)

10.6 1994 Stock Option Plan (incorporated by reference to the
Company's Registration Statement (No. 33-47544)).

10.7 Registration Rights Agreement dated October 22, 1997, by and
among Lomak Petroleum, Inc., Lomak Financing Trust, Morgan
Stanley & Co. Incorporated, Credit Suisse First Boston, Forum
Capital Markets L.P. and McDonald Company Securities, Inc.,
(incorporated by reference to the Company's Registration
Statement (No. 333-43823)).

10.8.1 1997 Stock Purchase Plan dated June 19, 1997 (incorporated by
reference to the Company's Registration Statement (No.
333-44821)).

10.8.2 1997 Stock Purchase Plan, as amended (incorporated by
reference to the Company's Registration Statement (No.
333-44821)).

10.8.3 1997 Stock Purchase Plan - Amendment No. 1 dated May 26, 1999
(incorporated by reference to the Company's Registration
Statement No. 333-40380)

10.8.4 1997 Stock Purchase Plan - Amendment No. 2 dated September 28,
1999 (incorporated by reference to the Company's Registration
Statement No. 333-40380)

10.8.5 1997 Stock Purchase Plan - Amendment No. 3 dated May 24, 2000
(incorporated by reference to the Company's Registration
Statement No. 333-40380)

10.8.6* 1997 Stock Purchase Plan - Amendment No. 4 dated May 24, 2001.

10.9 Second Amended and Restated 1996 Stock Purchase and Option
Plan for Key Employees of Domain Energy Corporation and
Affiliates (incorporated by reference to the Company's
Registration Statement (No. 333-62439)).

10.10 Domain Energy Corporation 1997 Stock Option Plan for
Nonemployee Directors (incorporated by reference to the
Company's Registration Statement (No. 333-62439)).

10.11 $100,000,000 Credit Agreement between Range Energy Finance
Corporation, as Borrower, and Credit Lyonnais New York Branch,
as Administrative Agent and Certain Lenders dated December 14,
1999 (incorporated by reference to the Company's 1999 10K
dated March 20, 2000.)

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10.11.1 $100,000,000 Second Amendment to Credit Agreement between
Range Energy Finance Corporation, as Borrower, and Credit
Lyonnais New York Branch, as Administrative Agent and Certain
Lenders dated December 14, 1999 (incorporated by reference to
the Company's 1999 10K dated March 20, 2000.)

10.12 Purchase and Sale Agreement - Dated April 20, 2000 between
Range Pipeline Systems, L.P. as Seller and Conoco Inc., as
Buyer (incorporated by reference to the Company's 10-Q dated
August 8, 2000).

10.13 Gas Purchase Contract - Dated July 1, 2000 between Range
Production I, L.P. as Seller and Conoco Inc., as Buyer
(incorporated by reference to the Company's 10-Q dated August
8, 2000).

10.14 Application Service Provider and Outsourcing Agreement - Dated
June 1, 2000 between Range Resources and Applied Terravision
Systems Inc. (incorporated by reference to the Company's 10-Q
dated August 8, 2000).

10.15.1 $225,000,000 Amended and Restated Credit Agreement among Range
Resources Corporation, as Borrower, The Lenders from Time to
Time Parties Hereto, as Lenders, Bank One, Texas, N.A., as
Administrative Agent, Chase Bank of Texas, N.A., as
Syndication Agent, and Bank of America, N.A., as Documentation
Agent dated September 30, 1999 incorporated by reference to
the Company's 10Q dated November 10, 1999.

10.15.2 $225,000,000 First Amendment to Credit Agreement among Range
Resources Corporation, as Borrower, certain parties, as
Lenders, Bank One, Texas, N.A., as Administrative Agent, Chase
Bank of Texas, N.A., as Syndication Agent, and Bank of
America, N.A., as Documentation Agent dated September 30, 1999

10.15.3 $225,000,000 Second Amendment to Credit Agreement among Range
Resources Corporation, as Borrower, certain parties, as
Lenders, Bank One, Texas, N.A., as Administrative Agent, Chase
Bank of Texas, N.A., as Syndication Agent, and Bank of
America, N.A., as Documentation Agent dated September 30, 1999
(incorporated by reference to the Company's 10-Q dated August
8, 2000.

10.15.4 $225,000,000 Third Amendment to Credit Agreement among Range
Resources Corporation, as Borrower, certain parties as
Lenders, Bank One, Texas, N.A., as Administrative Agent, Chase
Bank of Texas, N.A., as Syndication Agent, and Bank of
America, N.A., as Documentation Agent dated September 30, 1999
(incorporated by reference to the Company's 10-Q dated August
8, 2000).

10.16 1999 Stock Option Plan (incorporated by reference to the
Company's Registration Statement No. 333-40380)).

10.16.1 1999 Stock Option Plan -- Amended and restated dated April 5,
2001 (incorporated by reference to the Company's Proxy
Statement on Schedule 14A dated April 20, 2001)

10.16.2* 1999 Stock Option Plan -- Amendment No. 1 dated May 24, 2001.

10.19 The Amended and Restated Deferred Compensation Plan for
Directors and Selected Employees, effective September 1, 2000.

21.1* Subsidiaries of Registrant.

23.1* Consent of Independent Public Accountants.

23.2* Consent of H.J. Gruy and Associates, Inc., independent
consulting petroleum engineers.

23.3* Consent of DeGolyer and MacNaughton, independent consulting
petroleum engineers.

23.4* Consent of Wright and Company, independent consulting
engineers.

* Filed herewith.

74