RANGE RESOURCES CORP - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K
(Mark one)

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
FOR THE FISCAL YEAR-ENDED DECEMBER 31, 2002

or

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.

For the transition period from _______ to _______

COMMISSION FILE NUMBER 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

Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, $.01 par value New York Stock Exchange

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. [ ]

Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act).

Yes [X] No [ ]

The aggregate market value of the voting and non-voting common equity
held by non-affiliates (excluding voting shares held by officers and directors)
as of June 30, 2002 was $307,686,000.

As of March 1, 2003, there were 55,339,077 shares of Common Stock
outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant's Proxy Statement to be furnished to stockholders in
connection with its 2003 Annual Meeting of Stockholders is incorporated by
reference in Part III of this Report.

RANGE RESOURCES CORPORATION

ANNUAL REPORT ON FORM 10-K
YEAR-ENDED DECEMBER 31, 2002

PART I

ITEM 1. BUSINESS

GENERAL

Range Resources Corporation (the "Company") 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 pursues development drilling, exploitation projects, exploration and
acquisitions. The Company's Appalachian assets are held through a 50% interest
in a joint venture, Great Lakes Energy Partners L.L.C. ("Great Lakes"). Range's
interest in Great Lakes' assets and operations is consolidated in its financial
statements. A minor wholly-owned subsidiary, Independent Producer Finance
("IPF"), provides financing to small oil and gas producers through the purchase
of overriding royalty interests. At December 31, 2002, the Company had 578 Bcfe
of proved reserves, having a pre-tax present value of $965.2 million based on
constant prices of $31.17 per barrel and $4.75 per Mmbtu. The fair value of open
hedging contracts at December 31, 2002 approximated a loss of $32.9 million. The
Company's proved reserves are 76% natural gas by volume, 73% developed and 90%
operated. At year-end, the Company had a reserve life index of 10.6 years and
owned 676,530 (328,261 net) acres of undeveloped leasehold.

HISTORY

Until 1997, the Company pursued small acquisitions and the further
development of its properties, was consistently profitable and steadily
increased production and reserves. In 1997 and 1998, several large acquisitions
were consummated which proved unsuccessful. Production from the acquired
properties fell rapidly and further development proved far less attractive than
expected. In combination with the debt burden incurred in the purchases, the
adverse impact on the Company's financial results and balance sheet was severe,
and the stock price declined significantly. In response, sharp reductions in
staff and capital budgets were instituted. Sales of properties and the formation
of Great Lakes allowed the Company to substantially reduce debt, but production
and reserves fell as a result. In the Great Lakes transaction, Range and
FirstEnergy Corp. ("FirstEnergy"), an Ohio-based public utility, contributed
their Appalachian assets to a joint venture, forming one of the largest
production companies in the region, with Range contributing a disproportionate
share of the assets. To achieve equal ownership, the venture assumed $188.3
million of Range's bank debt and FirstEnergy contributed $2.0 million of cash.

To help assure a predictable cash flow, the Company began to
aggressively hedge its production as oil and gas prices recovered in late 1999.
These hedges covered roughly 80% of anticipated production through the third
quarter of 2000. Given the sharp rise in prices during 2000, these hedges
limited the benefits of the price increases. Since that time, the Company has
continued to hedge a significant percentage of its production on a rolling 12 to
24 month basis. At year-end 2002, hedges were in place on approximately 64.6 Bcf
of gas and 1.6 million barrels of oil at average prices of $3.96 per mcf and
$24.45 per barrel. These hedges cover approximately 90%, 75% and 10% of
anticipated production from proved reserves for 2003, 2004 and 2005,
respectively.

With the benefit of rising oil and gas prices and a reduced cost
structure, the Company began to increase capital expenditures in 2000, keeping
spending below internal cash flow to allow continued pay down of debt. Through
debt repayment with cash flow and exchanges of common stock for fixed income
securities, debt was steadily reduced. By 2001, the Company was able to increase
capital spending sharply to roughly $90.0 million. The benefits of higher energy
prices and reduced fixed charges permitted continued profitability and a further
reduction of debt. By 2002, leverage had been substantially reduced and the
Company was in a position to again pursue long-term growth. Capital spending was
increased a further 25% to approximately $112.0 million, including $21.8 million
of acquisitions. However, due to continued production declines in the Gulf of
Mexico, total Company production declined 2%. The Company's other divisions,
Southwest and Appalachia raised production 11% and 4%, respectively, and the
Company remained profitable while continuing to reduce debt. While overall
production declined slightly in 2002, the benefits of growing capital spending
became evident as proved reserves increased 13% and 222% of production was
replaced while debt was reduced a further $24.2 million.

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The Company has announced a $105.0 million 2003 capital budget
excluding acquisitions. The budget includes $89.0 million to drill 326 (173.4
net) wells and 38 (26.9 net) recompletions. A further $12.0 million is budgeted
for lease and seismic acquisition and $4.0 million for pipelines and facilities.
Based on this level of expenditures, the Company expects to increase production
and further expand reserves in the coming year.

DESCRIPTION OF THE BUSINESS

Strategy. Between 1988 and 1997, assets grew one hundred fold to $759.0
million as stockholders' equity increased from less than $1.0 million to $197.0
million. In 1998 and 1999, the Company incurred almost $200.0 million of losses
due to disappointing results on several large acquisitions. A series of property
impairments, up to and including that recorded in the fourth quarter of 2001,
were the primary cause of the losses which materially reduced stockholders'
equity. The significant improvement in oil and gas prices since mid-1999
combined with the benefits of reduced costs has allowed the Company to return to
profitability in the past three years. Current energy prices in combination with
the Company's hedge position, which covers approximately 90% of anticipated 2003
production from proved reserves, is expected to allow the 2003 capital spending
to be funded with approximately 75% of internal cash flow.

At year-end, the Company had 2,047 proven development projects in
inventory. Given current oil and gas prices, hedges and its 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's 676,530 gross (328,261 net) acres of undeveloped leasehold provide
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 operational and
technical experience. At December 31, 2002, the Company had an inventory of
1,770 proven drilling locations and 277 proven recompletions. During 2003, the
Company plans to drill 253 proven locations and recomplete 38 wells. In
addition, the Company plans to drill more than 40 unproved projects. The
following table summarizes 2002 development activity and changes in the
inventory of proved development projects:

Exploration. Onshore exploration projects cover 432,483 gross (195,300
net) acres, targeting deeper horizons in existing fields as well as trend areas.
Offshore exploration focuses on the shallow waters of the Gulf of Mexico where
the Company owns a license on 3-D seismic data covering 3.9 million contiguous
acres. The Company has offshore leases covering 132,353 (40,740 net) acres on
which 13 specific projects have been identified to date. The Company's strategy
limits risk by allocating no more than 15% of its capital budget to exploration.
At times, other companies pay all or a disproportionate share of exploration
costs to earn an interest. The Company currently expects to participate in as
many as 26 exploratory wells in 2003.

Acquisitions. After two years during which the Company withdrew from
the market, an acquisition program was reinstated in 2002. The Company will
continue to pursue modest purchases in 2003. In 2002, several small acquisitions
were completed. The focus is on modest purchases of properties in existing and
adjacent fields. To the extent the acquisition effort proves successful, a more
substantial effort may be considered.

DEVELOPMENT AND EXPLORATION

In 2002, the Company spent $111.3 million on oil and gas related
capital expenditures (Costs incurred - See Note 16 to the financial statements),
an increase of 24%, with $56.8 million expended in the Southwest, $34.7 million
in Appalachia and $19.8 million in the Gulf Coast. The spending funded 36 (28.1
net) recompletions, 300 (166.4 net) development and 28 (12.2 net)

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exploratory wells, lease acquisitions and seismic work. Exploration and
development spending brought 25.0 Bcfe of proved non-producing reserves on
stream and added a net 81.2 Bcfe of new reserves (including acquisitions).
Excluding the benefits of price revisions, reserves added during the year
replaced 160% of production.

Development

Development projects include recompletions, infill drilling and to a
lesser extent, installation of secondary recovery projects. Drilling prospects
are geographically diverse and target a mix of oil and gas, generally at depths
of less than 8,000 feet. The following table sets forth the development
inventory at December 31, 2002 by division:

Exploration

Onshore. The Company currently has 239 onshore exploration projects
covering 432,483 (195,300 net) acres. Most of the projects cover multiple
drilling prospects, some with a number of targeted formations. Given the
relatively small percentage of the capital budget dedicated to exploration, work
on these projects in 2003 will be limited.

Gulf of Mexico. The Company owns a license on a 3-D seismic database
covering 780 contiguous blocks in the shallow water of the Gulf of Mexico,
primarily offshore Louisiana. In 2001, a joint venture was formed with Callon
Petroleum Co. ("Callon") and Cheyenne Petroleum Company ("Cheyenne") to
reprocess the data and utilize it to identify and pursue exploration and
exploitation opportunities within a 3.9 million acre area. Callon holds a 50%
interest in the venture with the Company and Cheyenne each holding 25%. The
joint venture was awarded two blocks in the March 2001 OCS lease sale. The
Company's current offshore leasehold inventory includes 132,353 gross (40,740
net) acres. To more fully exploit the seismic data base, it will be necessary to
lease or farm in additional acreage. To date, the joint venture has identified
46 specific prospects and leads on acreage not currently controlled. These
projects generally target Miocene and Pliocene formations at depths ranging from
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 number of purchasers, of which three account
for more than 10% of oil and gas revenues. These three purchasers accounted for
35% of oil and gas revenues in 2002. However, the Company believes that the loss
of any individual customer would not have a long-term material adverse effect.
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 elsewhere have had, and
will continue to have, a significant effect on energy prices.

On an mcfe equivalent basis, 75% of the Company's 2002 production 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, to
a minor degree, 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 mid 2001, the joint venture sold 90% of its gas production to
FirstEnergy. Currently, 92% of Great Lakes gas is sold to a number of parties 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
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 2002, gas revenues
totaled $144.0

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million or 75% of oil and gas revenues while revenues from oil and natural gas
liquids totaled $46.9 million. Oil and gas revenues in 2002 decreased 9% from
the prior year due to slightly lower production and lower oil and gas 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 were $3.5 million in
2002, roughly level with the prior year. Gas transportation and processing
assets include (i) 50% ownership in approximately 4,900 miles of gas pipelines
in Appalachia held through Great Lakes and (ii) a number of smaller gathering
systems associated with producing properties outside of Appalachia. The
Appalachian gathering systems transport a majority of Great Lakes' gas
production as well as third party gas to major trunk lines 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. Approximately 8% of gas production
is currently sold pursuant to fixed price contracts at prices ranging from $1.25
to $5.09 per mcf (averaging $4.35 per mcf). The remaining 92% of gas production
is sold at market (generally index) related prices.

HEDGING

The Company regularly enters into hedging agreements to reduce the
impact of volatile oil and gas prices. These contracts are entered into solely
to hedge prices. The Company's current policy is to hedge between 50% and 75% of
its anticipated production, when prices justify it, on a rolling 12 to 24 month
basis. Due to the exceptional gas prices in early 2001, the Company extended its
hedging into 2005. At December 31, 2002, hedges were in place covering 64.6 Bcf
at prices averaging $3.96 per mcf and 1.6 million barrels of oil at prices
averaging $24.45 per barrel. Given the significant rise in prices over the past
six months, the hedges' fair value, represented by the estimated amount that
could be realized on termination, approximated a pre-tax loss of $32.9 million
at December 31, 2002. This loss is primarily presented on the balance sheet as a
short-term loss of $24.4 million and a long-term loss of $8.5 million. The
contracts expire monthly through December 2005 and cover approximately 90%, 75%
and 10% of anticipated 2003, 2004 and 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
reference price, generally NYMEX. Hedging 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. Changes in the value of the
ineffective portion of all open hedges is recognized in earnings quarterly.
Pre-tax losses relating to hedging in 2000 and 2001 were $43.2 million and $6.2
million, respectively. A hedging gain of $17.8 million was realized in 2002.
Over the last three years, the Company has recorded a cumulative pre-tax hedging
loss of $31.6 million. When combined with the $32.9 million unrealized pre-tax
loss at year-end 2002, this results in a $64.5 million cumulative loss. Since
2001, unrealized gains or losses on hedging contracts are recorded at an
estimate of fair value based 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.
Through Great Lakes, the Company also has interest rate swap agreements (See
Notes 6 and 7 to the financial statements).

INDEPENDENT PRODUCER FINANCE ("IPF")

IPF is a minor subsidiary which provides capital to small oil and gas
producers in exchange for term overriding royalty interests. The overrides are
dollar-denominated and calculated to provide a contractual rate of return that
typically exceeds 15%. Interest earned on the overrides is reported as revenues.
Almost all of the advances are for less than $5.0 million and most are for less
than $2.0 million. Until December 2002, IPF funded its operations through a
combination of internal cash flow and bank borrowings. In December 2002, IPF's
credit facility was retired with borrowings from the Parent credit facility. At
year-end 2002, IPF's portfolio included 34 transactions having an aggregate book
value of $24.5 million (net of $12.6 million of valuation allowances). The book
value of the portfolio declined 41% in 2002 primarily due to $22.4 million of
repayments received during the year and a $4.2 million valuation allowance. The
oil and gas reserves underlying IPF's royalties are not included in the
Company's reported proved reserves.

IPF provides valuation allowances against advances that may not be
recoverable. Increases and decreases in valuation allowances are reported as
expenses. IPF expenses also include general and administrative costs and
interest

5

expense, which totaled $3.6 million and $2.6 million, respectively, in 2001 and
2002. As dollar-denominated royalties, the transactions leave a portion of the
commodity price risk with the producer. However, when price declines occur, IPF
is exposed to losses. In addition, IPF is fully exposed to the individual
operator's ability to successfully produce and develop the underlying reserves.
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 public markets; (ii) private equity
and debt financing is too restrictive or unavailable to them; and (iii) few
commercial banks are interested in small energy loans. IPF's portfolio declined
in 2002 as fundings on existing transactions were more than offset by principal
repayments. Since 2001, IPF has not entered into any new financing agreements
and does not anticipate entering into any. Therefore, the size of its portfolio
should continue to decline.

OTHER

The Company earns interest on cash balances and certain receivables.
Other income in 2000 was comprised principally of losses on property sales. The
Company expects to continue to sell non-strategic properties. Beginning in 2001,
Other income also included ineffective hedging gains or losses. During 2001,
$2.3 million of ineffective hedging gains and a $689,000 gain on asset sales was
offset by a $1.7 million write-down of marketable securities and a $1.4 million
bad debt expense related to Enron hedges. During 2002, $2.7 million of
ineffective hedging losses, a $1.2 million write-down of marketable securities
and a $715,000 favorable arbitration settlement were recorded. Other income in
2002 amounted to a loss of $2.9 million.

COMPETITION

The Company encounters substantial competition in acquiring oil and gas
leases, marketing 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 depends on its ability to identify and acquire
suitable producing properties and prospects for future drilling.

Historically, 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 fixed income securities
outstanding. The 8.75% senior subordinated notes, 6% convertible debentures and
5.75% trust preferred had a combined book value of $175.7 million at December
31, 2002. Their combined fair market value, based on market quotes at that date,
was $139.8 million. The Company has, and may continue to, exchange equity for
these securities. Such exchanges could have a dilutive effect on shareholders.

GOVERNMENTAL REGULATION

The Company's operations are substantially affected 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
numerous 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 cost of doing business and affects profitability.
Although the Company believes it is in substantial compliance with all
applicable laws and regulations, such laws and regulations are frequently
amended or reinterpreted. Therefore, the Company is unable to predict the future
cost or impact of complying.

SECURITIES EXCHANGES

Since 1998, 9.9 million shares of common stock have been issued in
exchange for debt and 5.4 million shares have been exchanged for preferred
stock, or a total of 15.2 million shares. The shares were exchanged for $67.2
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 stock, or a total of $95.8 million. The extent of any future dilution
from exchanges 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

6

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 sharply.

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. Although 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 2002, nor does it anticipate that such expenditures will be material in 2003.

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. 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. In
addition, 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 under
environmental statutes, common law or both.

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 waters of the United States. 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.

The Resource 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

7

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, can be 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,"
"projects" or "targets" 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, our ability to
implement our business strategy, costs and results of drilling new projects,
mechanical and other inherent risks associated with oil and gas production,
weather, availability of drilling equipment and changes in interest rates. All
such forward-looking statements in this document are expressly qualified in
their entirety by the cautionary statements in this paragraph, and the Company
undertakes no obligation to publicly update or revise any forward-looking
statements.

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.

Common shareholders will be diluted if additional shares are issued

The Company has filed shelf registration statements that allow it to
issue common stock, and the Company has exchanged common stock for its fixed
income securities over the past three years. In 2000, 2001 and 2002, the Company
exchanged common stock for 5.75% Trust 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

8

the common stock and the convertible securities at the time of the exchange.
Negotiated terms in 2002 ranged from a 1% discount to none at a premium and the
convertible securities were acquired at discounts to face value ranging from 4%
to 41%. 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
were 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
were acquired in exchange for common stock. During 2002, $2.4 million of Trust
preferred, $7.1 million of 6% Convertible debentures and $875,000 of 8.75%
Senior subordinated notes were acquired in exchange for common stock. Since
1998, $95.8 million face value of convertible securities have been exchanged for
15.2 million shares of common stock. See Notes 6 and 18 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
convertible securities for cash is limited by the Parent credit facility and the
8.75% Senior subordinated note agreement. As of December 31, 2002, and March 1,
2003 the Company had only $803,000 and $567,000, respectively available under
the 8.75% restricted payments basket. As the restricted payments basket limits
the Company's ability to repurchase debt securities at attractive discounts, the
Company may seek to amend this agreement. The Company continues to review
alternatives to further strengthen its balance sheet and to retire debt and
convertible securities.

Dividend restrictions

Restrictions on the payment of dividends and other restricted payments
as defined are imposed under the Company's bank credit agreement and the 8.75%
Senior subordinated notes. Under the Parent credit facility, common dividends
are now permitted. The terms of the 8.75% Senior subordinated notes limit
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 since the issuance of the 8.75% Senior subordinated notes, the formula
provides no availability. Therefore, the Company must rely on the $20.0 million
basket. At December 31, 2002, only $803,000 of the $20.0 million basket remained
available. With transactions occurring subsequent to December 31, 2002, the
basket is $567,000 at March 1, 2003.

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

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 industry. In 1998
and early 1999, oil and gas prices fell substantially, which contributed to the
substantial losses reported in those years. By early 2001, oil and gas prices
reached levels substantially above their historical norm. Prices declined in the
second half of 2001 but have risen substantially since mid-2002. 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 90% and 75% of its anticipated production from proved reserves for
2003 and 2004, respectively, and a lesser amount of 2005 production. If prices
remain above the level at which the hedges were entered into, the hedges will
limit the benefit of the price rise.

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
exposure to adverse price movements, it also 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. At December 31, 2002, hedges were in
place covering 64.6 Bcf and 1.6 million barrels of oil. The hedges' fair value
was a loss of $32.9 million. Due to additional hedging activity and rising
prices, their fair value on March 1, 2003 had risen to a loss of $108.7 million.
If prices continue to rise, the Company could be subject to margin calls.

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,

9

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.

In 1997 and 1998, several 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 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
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. Downward
revisions at year-end 2000 represented 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 was unlike
the previous revisions recorded. Previous revisions were associated with the
disappointing performance of the properties acquired in the late 1990s. The
entire reserve revision in 2001 was associated with the dramatic reduction in
commodity prices during 2001. The impact of the 73% drop in the gas price on the
Company's proved reserves, which are 76% gas by volume, resulted in a
significant revision. Without the decline in commodity prices, the Company would
have experienced a slightly positive performance revision. During 2002, reserves
increased 119 Bcfe, including 34 Bcfe related to higher prices and 6 Bcfe due to
positive performance revisions. While there can be no assurance that future
reserve revisions will not occur, management believes that it has fully assessed
all data available through this date.

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 and 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 in the future be
written down

Accounting rules require that the carrying value of oil and gas
properties be periodically reviewed for possible impairment. "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
in 1997 and 1998 and significantly lower oil and gas prices, impairments of $215
million in 1998 and $29.9 million in 1999 were recorded. In 2000, no impairments
were required. At year-end 2001, an impairment of $31.1 million was recorded due
to year-end prices. No impairments were recorded in 2002. (See Management's
Discussion and Analysis - Results of Operations.) For a further discussion of
accounting policies related to oil and gas properties, see Note 2 to the
Consolidated financial statements.

We could incur substantial environmental liabilities.

The oil 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
"Business-Environmental Matters."

10

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, 2002, a portion of the Company's
borrowings, held through Great Lakes, were subject to interest rate swap
agreements, which are above market, and therefore, increase the Company's
interest expense. See Notes 6 and 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 carries floating interest rates while its
other debt securities pay fixed rates. At December 31, 2002, the face value of
the Company's fixed rate obligations totaled $175.7 million, and the annual
associated interest payments totaled $12.2 million a year. At December 31,
2002, the face value of floating interest rate debt totaled $192.3 million, of
which certain amounts held through Great Lakes are effectively fixed

11

through interest swaps. In addition, these debt obligations have certain
covenants the Company must meet or comply with to avoid the acceleration of
their maturity. 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, limiting 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 IPF 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 estimate reserves and
production rates and the operator's ability to produce and recover the projected
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 84% oil. Declines in oil prices could cause material increases in the IPF
valuation allowance. Many of the existing IPF clients do not have sufficient
equity and liquidity to maintain and/or further develop the underlying reserves.
If such properties are not fully developed and maintained, the potential
reserves applicable to the overriding royalty may not be realizable, requiring
periodic valuation allowances to be recognized by IPF.

Acquisitions are subject to numerous risks

It generally is not feasible to review in detail every individual
property included in an acquisition. 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 1997 and 1998, a series of acquisitions were
consummated which proved 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 financial statements are complex

Due to new accounting rules, our financial statements continue to be
complex, particularly with reference to hedging and the accounting for the
deferred compensation plan. The Company expects such complexity to continue or
even increase.

Our Chairman is affiliated with another oil and gas company that could compete
with us

Our Chairman, Thomas J. Edelman, also serves as the Chairman and Chief
Executive Officer of Patina Oil & Gas Corporation ("Patina"), 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, particularly as Patina has recently become active in
some of the same geographic areas as Range. The Board requires Mr. Edelman,
along with all other officers and directors, to provide notification of any
potential conflicts that arise. All employees of the Company sign a written
acknowledgement that they have read and understand the Company's written
conflict of interest policy. 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

12

The Company's success is highly dependent on its senior management
personnel, of which none are currently subject to an employment contract. The
loss of one or more of these individuals could have a material adverse effect on
the Company.

WEBSITE

The Company has a website under the name "rangeresources.com". The
Company makes available, free of charge, on its website, the annual report on
Form 10K, quarterly reports on Form 10Q, current reports on Form 8K and
amendments to those reports as soon as practicable after they are electronically
filed with or furnished to the SEC.

EMPLOYEES

As of January 1, 2003, the Company had 145 full-time employees, 52 of
whom were field personnel. None are covered by a collective bargaining
agreement. Management believes its relationship with employees is good.

ITEM 2. PROPERTIES

On December 31, 2002, the Company held working interests in 10,671
gross (5,394 net) productive wells and royalty interests in an additional 238
wells. Including its 50% share of Great Lakes' reserves, its properties
contained, net to its interest, estimated proved reserves of 440 Bcf of gas and
23 million barrels of oil and NGLs or a total of 578 Bcfe.

PROVED RESERVES

The following table sets forth estimated proved reserves at the end of
each of the past five years:

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

At year-end 2002, the following independent petroleum consultants
evaluated the Company's reserves: H.J. Gruy and Associates, Inc. (Southwest),
DeGolyer and MacNaughton (Southwest and Gulf Coast), and Wright and Company,
Inc. (Appalachia). These engineers were selected for their geographic expertise
and their history in engineering certain properties. At December 31, 2002, these
consultants collectively evaluated approximately 84% of the proved reserves. The
remaining reserves were evaluated by 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 prices used in projecting them over the past five years
(in millions except prices):

13

Future net revenues represent projected revenues from the sale of
proved reserves net of production and development costs (including production
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, 2002. Average product prices at
December 31, 2002 were $27.52 per barrel of oil, $18.72 per barrel for natural
gas liquids, and $4.76 per mcf of gas using benchmark NYMEX prices of $31.17 per
barrel and $4.75 per Mmbtu. There can be no assurance that the proved reserves
will be produced within the periods indicated and prices and costs will not
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 operations are divided into three geographical areas or
divisions known as, Southwest, Gulf Coast and Appalachia. The Appalachian
division represents the 50% ownership in Great Lakes. At year-end, the Company's
properties included working interests in 10,671 (5,394 net) productive oil and
gas wells, royalty interests in an additional 238 wells, and 676,530 (328,261
net) undeveloped acres. The following table sets forth summary information by
division with respect to estimated proved reserves at December 31, 2002.

SOUTHWEST DIVISION

The Southwest Division has production and field operations in the
Permian Basin of West Texas and the East Texas Basin as well as in the Texas
Panhandle and the Anadarko Basin of western Oklahoma. This region represents 43%
of the Company's total reserves by value and 41% by volume. Proved reserves in
the Southwest Division totaled 239.7 Bcfe, of which 61% was gas. Reserves
increased 33.9 Bcfe, up 16% from 2001 due to additions, higher commodity prices
and favorable performance revisions. The region's daily production totaled 71.5
Mmcfe per day, representing 48% of total production. On an annual basis,
production increased 11% from 2001. At year-end, the Southwest Division had an
inventory of 162 proven recompletions and 92 proven drilling locations. Acreage
owned in the region at that date included 198,554 (149,448 net) developed acres
and 160,749 (120,442 net) undeveloped acres. During 2002, 72 (64.9 net)
development wells were drilled in the region, of which 69 (62.3 net) were
productive and 6 exploratory wells (6.0 net) were drilled, of which 3 (3.0 net)
were productive. During the year, the region achieved a 92% drilling success
rate.

In East Texas, 4 (3.3 net) successful wells were drilled at the Laura
LaVelle field in Houston County, Texas. Net production from the field currently
approximates 2.9 Mmcfe a day. In other East Texas drilling, one (1.0 net) well
was drilled in the James Lime formation, a fractured carbonate. The well was
successfully completed at an initial rate of 4 (3.2 net) Mmcfe per day but
declined rapidly to 0.5 Mmcfe per day. Also in East Texas, the Company
successfully drilled two Travis Peak wells (the Linder #2 & #3) in Henderson
County, Texas. These wells were completed at depths ranging from 9,491 to 9,550
feet. In West Texas, 15 (13.8 net) infill and field extension wells were
successfully

14

drilled in 2002 in the Sterling Field of Sterling County, Texas. Net production
from this field currently approximates 14.1 Mmcfe per day. In the Val Verde
field of Edwards and Sutton Counties, Texas, 5 (2.8 net) infill and field
extension wells were drilled and completed. There were also 8 (8.0 net) Val
Verde field wells recompleted in 2002. At year-end the net production from this
field approximates a net 8.3 Mmcfe per day.

In West Texas, 16 (15.6 net) wells were drilled in the Fuhrman - Mascho
field complex. Of the 16 wells, four were water injection wells in a waterflood
development pilot. At year-end, the Fuhrman Mascho field area was producing
approximately 5.6 mcfe per day. The Company expects to continue the drilling
program in 2003. In West Texas, three wells were also successfully drilled at
Powell Ranch in Glasscock, County. At year-end, production from that field
totaled 11.1 net Mmcfe per day.

In the Texas Panhandle, the Morrow play continues to provide growth
opportunities. Characterized by multiple sands and depositional environments
within a single formation, the Upper, Middle and Lower Morrow Sands produce at
depths of 7,000 to 12,000 feet with average expected reserves of 1.5 Bcf and
individual wells ranging from 1 to 5 Bcfe. Range currently holds more than
62,000 (49,500 net) acres in the play. Traditionally, the Morrow has been a
statistical play. With the aid of 307 square miles of 3-D seismic and regional
subsurface mapping, the Company believes its geoscientists are now able to
identify promising opportunities and increase the predictability of drilling. In
2002, Range drilled a total of 11 (10.1 net) Morrow wells with a 73% success
rate. The 8 (7.7 net) successful wells drilled in 2002 are currently producing
at a rate of 8.8 (6.5 net) Mmcfe per day. Each new well has enhanced the ability
to interpret key seismic reflectors. Significant wells drilled in the area in
2002 were the Pioneer #2, the Intrepid #1-107, and the Courson Ranch #1-140. The
Pioneer #2 in the Ben Hill area of northeast Roberts County tested over 8.3 (6.6
net) Mmcfe per day from the targeted Lower Morrow Sand and after 11 months of
production is currently delivering in excess of 3.1 (2.5 net) Mmcfe per day. The
Courson Ranch #1-140 in northwest Roberts County was initially tested at rates
exceeding 1,000 (546 net) bbls of oil per day in the Upper Morrow Sand. The well
is currently producing at the full allowable rates of 340 (186 net) bbls of oil
per day and 0.3 (0.2) Mmcf per day. Since first sales in late October 2002, the
well has produced 25,000 bbls of oil and 22 Mmcf of gas.

In the Anadarko Basin, 8 (5.4 net) wells were drilled in the Sooner,
Watonga-Chickasha, Granite Wash and Northwest Shelf trends during 2002. The
notable success in the Watonga-Chickasha was the Endeavour #1-28, which
completed in the Morrow/Springer sands and tested in excess of 1.2 (0.9 net)
Mmcfe per day. The Watonga-Chickasha area was also the location of certain minor
property purchases, in 2002, with 14 (8.0 net) wells being acquired in the area.
Production associated with the acquired properties approximated 2.3 Mmcfe per
day. Included in the transactions were 8,000 (5,252 net) acres of leasehold
which provide new drilling opportunities.

GULF COAST DIVISION

The Gulf Coast Division represents 20% of reserves by value and 15% by
volume. Proved reserves totaled 85.8 Bcfe, down 10% in 2002. During the year,
the region only partially replaced production, which totaled 16.3 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
Division's wells are characterized by high initial rates and relatively short
reserve lives. Production by Gulf Coast represented 30% of the Company total.
Major onshore fields produce from Hartburg formations at depths of 10,000 to
11,000 feet in the Upper Texas Gulf Coast to the Upper Oligocene in South
Louisiana at depths of 10,000 to 12,000 feet to the Sligo and Hosston formations
at depths of 15,000 to 16,500 feet in the Oakvale field in Mississippi. Offshore
properties include interests in 40 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 13 drilling locations on 139,026 (45,480 net)
developed acres and 75,439 (16,826 net) undeveloped acres.

In 2002, the region spent $19.0 million to drill 8 (2.3 net) wells,
recomplete 7 (2.2 net) others and to upgrade facilities. In the fourth quarter
of 2002, net production averaged 674 barrels of oil and 36,349 Mmcf of gas per
day or 40,396 Mmcfe per day in total. Production during the year declined 20% to
44.7 Mmcfe per day due to the natural decline on mature properties. During 2002,
four development wells (1.2 net) were drilled, all of which were productive.
Four exploratory wells (1.1 net) were drilled, all of which were productive.

Offshore, the joint venture formed between Range, Callon and Cheyenne
continued to explore the central shelf of the Gulf of Mexico, successfully
drilling its first exploratory well, the Ship Shoal 28 #40. The well was drilled
to a measured depth of 15,327 feet, encountering 140 feet of net gas pay. Range
has a 26.8% WI (NRI varies by zone from 19.6% to 21.8%). The well tested at
rates as high as 12 (2.4 net) Mmcf per day and is scheduled to go on production
in

15

May. To date, the joint venture has spent $2.1 million on additional seismic
data. The joint venture increased its total 3-D seismic data coverage from 5,500
square miles to 6,100 square miles in 2002 and the joint technical team
continued working the data, identifying 22 new leads and bringing the total
number of identified prospects to 46.

Outside of the joint venture, Range used its offshore seismic database
to identify two prospects on existing acreage and caused wells to be drilled on
them in 2002. The most notable was the West Cameron 45 #20 well, which was
drilled to 16,444 feet encountering 59 feet of net gas pay sand. The well was
turned on in mid-December and is currently producing in excess of 30 Mmcf (6.0
net) per day. In August 2002, Range participated in a well on Vermilion Block
332. This shallow test, in which Range owns a 16.5% WI (11.6% NRI), was drilled
to a depth of 3,184 feet and encountered gas in two horizons. Plans are to
produce the bottom zone first. The combined test rate for both zones was 12.3
Mmcf per day (1.4 net). First sales are anticipated in March. Range is
continuing to work the data covering existing fields to generate additional
prospects.

Onshore, Range participated in the drilling of four wells in 2002. The
most significant was the Arceneaux #1 well in Vermilion Parish, Louisiana. This
Range-operated 11,939-foot test of the Upper Oligocene Marg howei sand began
producing in late August. The well has already produced more than 1.0 Bcf and is
flowing in excess of 6.3 Mmcf (2.0 net) per day. A nearby test well, the Faulk
#1, is expected to be spud before the end of the first quarter. Range also
drilled two wells in the shallow water of Galveston Bay to produce attic oil and
gas accumulations. The ST 127 #1 encountered 95 net feet of Upper Frio oil and
gas pay. The well began producing in late March 2002 and is currently flowing
2.3 Mmcf (0.4 net) and 157 barrels (25 net) per day. The ST 127 #2 was drilled
to a different fault block and then sidetracked to a more advantageous position.
After three months of production, the well developed a mechanical problems and
Range elected not to participate in attempts to restore production.

APPALACHIAN DIVISION

Through its 50% interest in Great Lakes, the Appalachian Division
represents 252.5 Bcfe of proved reserves, or 44% by volume and 37% by value of
total proved reserves. The region has an interest in 9,047 gross (3,914 net)
wells and 4,900 miles of gas gathering lines. Great Lakes sells its gas on a
negotiated basis to a number of companies. At December 31, 2002, Great Lakes had
an inventory of 68 proven recompletions and 1,665 proven drilling locations.

Acreage owned in the Appalachian region at December 31, 2002 included
689,895 (327,111 net) developed acres and 440,342 (190,993 net) undeveloped
acres. During 2002, 224 (100.3 net) development wells were drilled, of which 221
(98.8 net) were productive. Eighteen (5.1 net) exploratory wells were drilled,
of which 10 (2.8 net) were productive. At December 31, 2002, Great Lakes
operated 99% of its 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 2002, net production
averaged 28.9 Mmcf of gas and 845 barrels of oil, or a total of 34.0 Mmcfe per
day. The Division's properties, with 1,733 proven projects at year-end, are
located in the Appalachian and, to a minor degree, the Michigan Basins of the
northeastern United States. After initial flush production, these properties are
characterized by gradual decline rates, producing on average for 10 to 35 years.

In 2002, $20.8 million in capital funded the drilling of 217 (97.3 net)
shallow development wells and 25 (8.1 net) medium depth wells. In addition,
capital was expended on 5 (2.2 net) recompletions as well as the purchase of 825
miles of 2-D and 3-D seismic data and 167,012 (70,315 net) acres of leasehold.
Of the 224 development wells drilled, 221 were successful. Ten of the 18
exploration wells were also successful, indicating an overall 96% success rate.
Production during the year averaged 33.9 Mmcfe per day net, a 4% increase.
Year-end proved reserves increased approximately 19% to 252.5 Bcfe primarily as
a result of higher commodity prices, acquisitions and additions.

16

During 2002, exploration prospects at Great Lakes included targets in
the Knox Unconformity, Huntersville-Oriskany and Trenton Black River plays. The
largest effort (20 (6.2 net)) was directed to the Knox play in Ohio. Great Lakes
significantly increased its use of 3-D seismic in the Knox play, shooting or
acquiring over 30 square miles of data in three separate areas. Each of these
shoots yielded discovery wells with additional drilling opportunities. Great
Lakes also shot a moderate amount of 2-D seismic and drilled 2 (1.0 net) wells
in the Huntersville/Oriskany play in Pennsylvania. While both wells were
successfully completed, initial production rates have been below expectations.
In the Trenton Black River play, leases on over 125,000 gross acres in four
major prospect areas were acquired, and seismic and drilling work is planned for
2003. All 3 (0.6 net) wells drilled in 2001 to the Trenton Black River were
unsuccessful.

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. Production from these shallower blanket-type, tight-sand
formations is characteristically long-lived with estimated ultimate production
of from 150 to 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, the Huntersville/Oriskany Sandstone and the Trenton Black
River. Wells drilled in the Knox Unconformity are characterized by a shorter
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 by other operators 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.

Management of Great Lakes is overseen by a management committee
comprised of three representatives from the Company and three from FirstEnergy.

PRODUCTION

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

17

(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 a barrel and reduced average oil prices by $1.09 a barrel
in 2002. Hedging decreased average gas prices by $0.25 per mcf and increased
average gas prices by $0.48 per mcf in 2001 and 2002, respectively. Average
NYMEX gas prices were $2.51 and $3.24 in 2001 and 2002, respectively.
Average NYMEX oil prices were $19.40 and $26.08 in those same time periods.

(d) Average prices realized excluding hedging were $3.90, $3.86 and $3.16 per
mcfe, in 2000, 2001 and 2002, respectively.

PRODUCING WELLS

The following table sets forth information (including the Company's 50%
share of Great Lakes) relating to productive wells at December 31, 2002. The
Company owns royalty interests in an additional 238 wells. Wells are classified
as oil or gas according to their predominant production stream.

18

ACREAGE

The following table sets forth acreage held at December 31, 2002.

The following table sets forth, for the preceding three years, the book
value of unproved acreage by division (in thousands).

DRILLING RESULTS

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

19

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 September 2007. 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. The Company owns various vehicles
and other equipment that are used in its field operations. Such equipment is
believed to be in good repair and can be readily replaced if necessary.

ITEM 3. LEGAL PROCEEDINGS

The Company is involved in various legal actions and claims arising in
the ordinary course of business, which includes a royalty owner suit filed in
2000 asking for class action certification against Great Lakes and the Company.
During 2002, approximately $250,000 of costs were expensed in defense of
litigation and $385,000 reduced an accrued liability related to the period prior
to the formation of Great Lakes. The Company received a $715,000 arbitration
recovery, net of $72,000 of legal expenses. In the opinion of management, such
litigation and claims are likely to be resolved without a material adverse
effect on the Company's financial position or results of operations.

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

No matters were submitted to a vote of security holders during the
fourth quarter of 2002.

PART II

ITEM 5. MARKET FOR COMMON STOCK AND RELATED MATTERS

The Company's common stock is listed on New York Stock Exchange
("NYSE") under the symbol "RRC." During 2002, trading volume averaged 142,554
shares per day. On March 1, 2003, the closing price of the common stock was
$5.93. The following table sets forth the quarterly high and low sales prices
and volumes as reported on the NYSE composite tape for the past two years.

Between January 1, 2003 and March 1, 2003, the common stock traded at
prices between $5.20 and $6.20 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.

20

At various times in 2002, the Company issued common stock in exchange
for fixed income securities. Shares of common stock issued in such exchanges
were exempt from registration under Section 3(a) (9) of the Securities Act of
1933. The following table summarizes those exchanges in 2000, 2001 and 2002:

HOLDERS OF RECORD

At March 1, 2003, there were approximately 2,308 holders of record of
the common stock.

DIVIDENDS

Quarterly common stock dividends were initiated in 1995. In connection
with the Company's need to reduce leverage, the dividend was reduced in the
first quarter and eliminated in the fourth quarter of 1999. The Parent bank
facility and the 8.75% Senior subordinated notes contain restrictions on the
payment of dividends. Since January 1, 2003, the Parent bank facility has
permitted dividends. Under 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 its losses since 1997, the Company cannot make payments
under the formula and must rely on the $20.0 million basket. At December 31,
2002, only $803,000 remained available under the basket. The Company may seek to
amend this covenant.

The following table summarizes securities issuable and authorized by
the stockholders under certain equity compensation plans (a):

(a) Although the Company does not maintain a formal plan, common stock is
issued to officers and key employees in lieu of cash for bonuses and
company matches under the Company's deferred compensation arrangements. All
such issuances are approved by the Compensation Committee, which is
composed of three independent directors. Issuances to Named Employees are
disclosed in the Company's proxy statements.

(b) Includes 167,000 shares related to the stock purchase plan for which there
is no prescribed price.

21

ITEM 6. SELECTED FINANCIAL DATA

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

a) Refer to Company's detailed balance sheet for hedging amounts included
herein.

b) Stockholders' equity includes other comprehensive income (loss) of
$292,000, $189,000, $(639,000), $45.5 million and $(21.2 million) in 1998,
1999, 2000, 2001 and 2002, respectively.

22

The following table sets forth summary unaudited financial information
on a quarterly basis for the two years ended December 31, 2002 (in thousands,
except per share data).

(a) Includes extraordinary gains on retirement of securities of $432,000 in the
first quarter. These gains were $895,000 and $319,000 in the second and
third quarters (net of taxes), respectively. In the fourth quarter of 2001,
the gain on retirement of securities was $2.3 million (net of taxes). The
fourth quarter includes an impairment charge of $31.1 million.

(b) Includes extraordinary gains (net of taxes) of $770,000, $545,000, $687,000
and $12,000 in the first, second, third and fourth quarters, respectively.

The total of quarterly earnings per share does not necessarily equal
the earnings per share for the year, either because the calculations are based
on the weighted average shares outstanding or rounding. During the fourth
quarter of 2001, the Company recorded $31.1 million of impairments. (See
Management's Discussion and Analysis - Results of Operations.)

23

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.)

RESTATEMENT

For many years, Arthur Andersen LLP served as the Company's auditor. In
July 2002, the Company selected KPMG LLP as its new independent auditor.
Simultaneously, the Company asked KPMG to reaudit its consolidated financial
statements for the three years ended December 31, 2001, even though a reaudit
was not required. The reaudit was intended to provide additional assurance to
shareholders, ensure the Company's ongoing access to the capital markets and to
avoid any possible impediment to future transactions. As a result of the
reaudit, the financial statements were restated. For the three years ended
December 31, 2001, the cumulative impact of the restatements reduced net income
by $8.4 million, of which $7.8 million related to the reduction of the gain
associated with the formation of Great Lakes in 1999. The restatement increased
the 1999 net loss by $15.7 million, reduced 2000 net income by $1.4 million,
increased 2001 net income by $8.7 million and reduced first half of 2002 net
income by $2.3 million.

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. Application of certain of the
Company's accounting policies, including those related to oil and gas revenues,
bad debts, the fair value of derivatives, oil and gas properties, marketable
securities, income taxes and contingencies and litigation require significant
estimates. The Company bases its estimates on historical experience and various
assumptions that are believed reasonable under the circumstances. Actual results
may differ from these estimates. The Company believes the following critical
accounting policies affect its more significant judgments and estimates used in
the preparation of its financial statements.

Proved reserves - Proved reserves are defined by the U.S. Securities
and Exchange Commission ("SEC") as those volumes of crude oil, condensate,
natural gas liquids and natural gas that geological and engineering data
demonstrate with reasonable certainty are recoverable from known reservoirs
under existing economic and operating conditions. Proved developed reserves are
volumes expected to be recovered through existing wells with existing equipment
and operating methods. Although the Company's engineers are knowledgeable of and
follow the guidelines for reserves established by the SEC, the estimation of
reserves requires engineers to make a significant number of assumptions based on
professional judgment. Reserves estimates are updated at least annually and
consider recent production levels and other technical information about each
well. Estimated reserves are often subject to future revision, which could be
substantial, based on the availability of additional information, including:
reservoir performance, new geological and geophysical data, additional drilling,
technological advancements, price changes and other economic factors. Changes in
oil and gas prices can lead to a decision to start-up or shut-in production,
which can lead to revisions to reserve quantities. Reserve revisions in turn
cause adjustments in the depletion rates utilized by the Company. The Company
cannot predict what reserve revisions may be required in future periods.

Depletion rates are determined based on reserve quantity estimates and
the capitalized costs of producing properties. As the estimated reserves are
adjusted, the depletion expense for a property will change, assuming no change
in production volumes or the costs capitalized. Estimated reserves are used as
the basis for calculating the expected future cash flows from a property, which
are used to determine whether that property may be impaired. Reserves are also
used to estimate the supplemental disclosure of the standardized measure of
discounted future net cash flows relating to its oil and gas producing
activities and reserve quantities disclosure in Footnote 19 to the consolidated
financial statements. Changes in the estimated reserves are considered changes
in estimates for accounting purposes and are reflected on a prospective basis.

Successful efforts accounting - The Company utilizes the successful
efforts method to account for exploration and development expenditures.
Unsuccessful exploration wells are expensed and can have a significant effect on
operating results. Successful exploration drilling costs and all development
costs are capitalized and systematically charged to expense using the units of
production method based on proved developed oil and gas reserves as estimated by
the Company's engineers. The Company also uses proved developed reserves as the
divisor to accrue the expense of estimated future dismantlement and abandonment
costs. At year-end, the Company had a liability totaling $32.1 million for
plugging and abandonment costs on its balance sheet. This liability is shown
netted against oil and gas properties on the balance

24

sheet. Currently, the Company's estimates it will spend $13.2 million over the
next three years on plugging and abandonment costs. The Company will adopt SFAS
143 on January 1, 2003 which changes the accounting treatment for these types of
costs. See Note 2 to the Consolidated financial statements "Recent Accounting
Pronouncements" for further discussion.

Impairment of properties - The Company continually monitors its
long-lived assets recorded in Property, plant and equipment in the Consolidated
Balance sheet to ensure they are fairly presented. The Company must evaluate its
properties for potential impairment when circumstances indicate that the
carrying value of an asset could exceed its fair value. A significant amount of
judgment is involved in performing these evaluations since the results are based
on estimated future events. Such events include a projection of future oil and
natural gas sales prices, an estimate of the ultimate amount of recoverable oil
and gas reserves that will be produced from a field, the timing of future
production, future production costs, and future inflation. The need to test a
property for impairment can be based on several factors, including a significant
reduction in sales prices for oil and/or gas, unfavorable adjustment to
reserves, or other changes to contracts, environmental regulations or tax laws.
All of these factors must be considered when testing a property's carrying value
for impairment. The Company cannot predict whether impairment charges may be
required in the future.

Income taxes - The Company is subject to income and other similar taxes
in all areas in which it operates. When recording income tax expense, certain
estimates are required because: (a) income tax returns are generally filed many
months after the close of a calendar year; (b) tax returns are subject to audit
which can take years to complete; and (c) future events often impact the timing
of when income tax expenses and benefits are recognized. The Company has
deferred tax assets relating to tax operating loss carryforwards and other
deductible differences. The Company routinely evaluates all deferred tax assets
to determine the likelihood of realization. A valuation allowance is recognized
on deferred tax assets when management believes that certain of these assets are
not likely to be realized.

The Company's deferred tax assets exceeded its deferred tax liabilities
at year-end 2001 before considering the effects of Other comprehensive income
(loss) ("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 caused deferred tax liabilities to exceed deferred
tax assets by $4.5 million at year-end 2001 and this amount was recorded as a
deferred tax liability on the balance sheet. At year-end 2002, deferred tax
assets exceeded deferred tax liabilities by $15.8 million with $11.4 million of
deferred tax assets related to deferred hedging losses included in OCI. Based on
the Company's projected profitability, no valuation allowance was deemed
necessary.

The Company occasionally is challenged by taxing authorities over the
amount and/or timing of recognition of revenues and deductions on its various
income tax returns. Although the Company believes that it has adequate accruals
for unresolved tax matters, gains or losses could occur in the future due to
changes in estimates or resolution of outstanding matters.

Legal, environmental and other contingent matters - A provision for
legal, environmental and other contingent matters is charged to expense when the
loss is probable and the cost can be reasonably estimated. Judgment is often
required to determine when expenses should be recorded for legal, environmental
and contingent matters. In addition, the Company often must estimate the amount
of such losses. In many cases, management's judgment is based on an
interpretation of laws and regulations, which can be interpreted differently by
regulators and/or the courts. Management closely monitors known and potential
legal, environmental and other contingent matters and makes its best estimate
of when the Company should record losses for these based on available
information.

Other significant accounting policies requiring estimates include the
following: The Company recognizes revenues from the sale of products and
services in the period delivered. Revenues at IPF are recognized as earned. 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. Such provisions for
uncollectible amounts are recorded when management believes that a related
receivable is not recoverable based on current estimates of expected discounted
cash flows. The Company records a write down of marketable securities when the
decline in market value is considered to be other than temporary. Changes in the
value of the ineffective portion of all open hedges is recognized in earnings
quarterly. The fair value of open hedging contracts is an estimated amount that
could be realized upon termination. The Company stock held in the deferred
compensation plan is treated as treasury stock and the carrying value of the
deferred compensation is adjusted to fair value each reporting period by a
charge or credit to operations in general and administrative expense.

25

FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY

LIQUIDITY AND CAPITAL RESOURCES

During 2002, the Company spent $111.3 million on development,
exploration and acquisitions. Fixed income obligations including Trust preferred
were reduced by $24.2 million. At December 31, 2002, the Company had $1.3
million in cash, total assets of $658.5 million and a debt (including Trust
preferred) to capitalization (including debt, deferred taxes and stockholders'
equity) ratio of 64%. Available borrowing capacity on the Company's bank lines
at December 31, 2002 was $31.1 million on the Parent credit facility and $52.0
million at Great Lakes (of which $26.0 million was net to Range). Long-term debt
(including Trust preferred) at December 31, 2002 totaled $368.0 million and
included $115.8 million of borrowings under the Parent credit facility, $76.5
million under the non-recourse Great Lakes facility, $69.3 million of 8.75%
Senior subordinated notes, $21.6 million of 6% Convertible subordinated
debentures and $84.8 million of Trust preferred. At December 31, 2002, the
Company had a working capital deficit of $29.8 million which included a net
hedging liability of $26.0 million due to the mark-to-market of all open hedges.
Because payments on this hedging liability are made monthly and the Company will
also collect production proceeds to which this hedging relates, the amount
should be self funding.

During 2002, 1.6 million shares of common stock were exchanged for $2.4
million of Trust preferred, $875,000 of 8.75% Senior subordinated notes and $7.1
million of 6% Debentures. In addition, $815,000 of 6% Debentures, $9.0 million
of 8.75% Senior subordinated notes and $2.5 million of 5.75% Trust preferred
were repurchased for cash. A $3.1 million extraordinary gain ($2.0 million after
tax) was recorded, as the securities were retired at a discount. Since 1998,
15.2 million shares of common stock have been exchanged for $95.8 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 12 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. A material drop in oil and gas prices or a reduction in production
and reserves would reduce the Company's ability to fund capital expenditures,
reduce debt and meet 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 substantially. 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. 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 financial
obligations at December 31, 2002 and their future maturities (in thousands):

(a) 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.

26

Total long-term debt (including Trust preferred) at December 31, 2002,
was $368.0 million. Long-term debt of $192.3 million was subject to floating
interest rates (of which certain amounts have interest swap agreements) and
$175.7 million of debt had a fixed interest rate. 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
90%, 75% and 10% of its anticipated production from proved reserves for 2003,
2004 and 2005, respectively. Decreases in prices and lower production at certain
properties reduced cash flow sharply in 1998 and 1999 and resulted in a
reduction of the Company's borrowing base. Simultaneously, the Company sharply
reduced its development and exploration spending. The $111.9 million of capital
expenditures for 2002, excluding acquisitions was funded with internal cash
flow. The amount expended replaced 222% of production. In the absence of price
revisions, net reserves added during the year replaced 160% of production. The
$105.0 million 2003 capital budget, which excludes acquisitions, is expected to
increase production and to expand the reserve base. Based on current
projections, oil and gas futures prices and the Company's hedge position, the
2003 capital program is expected to be funded with approximately 75% of internal
cash flow.

Net cash provided by operations in 2000, 2001 and 2002 was $74.9
million, $129.6 million, and $109.2 million respectively. In 2001, cash flow
from operations increased as higher prices and lower interest expense more than
offset increasing operating and exploration expenses. In 2002, cash flow from
operations decreased with lower prices and volumes, higher exploration and
general and administrative costs, somewhat offset by lower interest and direct
operating costs.

Net cash used in investing in 2000, 2001 and 2002 was $6.0 million,
$78.2 million and $98.7 million respectively. In 2000, $47.5 million of
additions to oil and gas properties were offset by $25.9 million proceeds from
sales of assets and $24.8 million of IPF repayments. The 2001 period included
$87.0 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. The 2002 period included $109.1 million of additions to oil and
gas properties and $5.1 million of IPF investments partially offset by $17.3
million of IPF receipts. Net cash used in financing (to repay debt) in 2000,
2001 and 2002 was $79.3 million, $50.6 million and $12.6 million respectively.
Historically, sources of financing have been primarily bank borrowings and
capital raised through equity and debt offerings. During 2000, recourse debt
decreased $45.1 million and total debt (including Trust preferred) decreased
$113.5 million. The reduction in debt was the result of applying excess internal
cash flow and proceeds from asset sales to debt repayment and exchanges of
common stock for fixed income securities. 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 internal cash
flow, proceeds from asset sales and exchanges of common stock for fixed income
securities. During 2002, recourse debt increased $20.8 million and total debt
(including Trust preferred) decreased by $24.2 million. Recourse debt increased
due to the retirement of the IPF credit facility and the repurchase of fixed
income securities with borrowing under the Parent credit facility.

Capital Requirements

During 2002, $111.9 million of capital was expended, primarily on
development projects. The capital program, excluding acquisitions, was funded
with approximately 83% of net cash flow from operations. The Company manages its
capital budget with the goal of fully funding it with internal cash flow. The
2003 capital budget of $105.0 million is expected to increase production and
expand the reserve base by more than replacing production. 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."

27

Banking

The Company maintains two separate revolving credit facilities, a
$225.0 million Parent facility and a $275.0 million Great Lakes facility (of
which 50% is consolidated at Range). In December 2002, the IPF credit facility
was retired with borrowings under the Parent credit facility. Each facility is
secured by substantially all of the assets of the borrower. The Great Lakes
facility is non-recourse to Range. As Great Lakes is 50% owned, half of its
borrowings are consolidated in Range's financial statements. Availability under
the facilities is subject to borrowing bases set by the 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, 2003, a $147.0 million borrowing base was in
effect at Range of which $23.5 million was available and a $205.0 million
borrowing base was in effect at Great Lakes, of which $44.0 million was
available.

HEDGING

Oil and Gas Prices

The Company regularly enters into hedging agreements to reduce the
impact of oil and gas price fluctuations on its operations. The Company's
current policy, when futures prices justify, is to hedge between 50% and 75% of
projected production on a rolling 12 to 24 month basis. At December 31, 2002,
hedges were in place covering 64.6 Bcf of gas at prices averaging $3.96 per mcf
and 1.6 million barrels of oil at prices averaging $24.45 per barrel. The hedges
fair value, represented by the estimated amount that would be realized or
payable on termination, based on contract versus NYMEX prices, approximated a
pretax loss of $32.9 million at December 31, 2002. The contracts expire monthly
through December 2005 and cover approximately 90% of anticipated 2003 production
from proved reserves, 75% of 2004 production and a minor amount of 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. Changes in the value of
the ineffective portion of all open hedges is recognized in earnings quarterly.
Pre-tax losses relating to hedging in 2000 and 2001 were $43.2 million and $6.2
million, respectively. A hedging gain of $17.8 million was realized in 2002.
Over the last three years, the Company has recorded a cumulative pre-tax hedging
loss of $31.6 million. When combined with the $32.9 million unrealized pre-tax
loss at year-end 2002, this results in a cumulative net loss of $64.5 million.
Since 2001, unrealized gains or losses on hedging positions are recorded at an
estimate of 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. Due to additional hedging activity and rising
prices, the fair value on March 31, 2003 was a loss of $108.7 million.

Interest Rates

At December 31, 2002, the Company had $368.0 million of debt (including
Trust preferred) outstanding. Of this amount, $175.7 million bears interest at
fixed rates averaging 7.0%. Senior debt and non-recourse debt totaling $192.3
million bears interest at floating rates, which averaged 3.3% at year-end 2002,
excluding interest rate swaps. At December 31, 2002, Great Lakes had $100.0
million subject to interest rate swap agreements, of which 50% is consolidated
at Range. These swaps consist of five agreements totaling $35.0 million at an
average rate of 4.6% which expire in June 2003, two agreements totaling $45.0
million at rates of 7.1% which expire in May 2004 and two agreements of $10.0
million each at an average rate of 2.3% which expire in December 2004. The
30-day LIBOR rate on December 31, 2002 was 1.4%. A 1% increase in short-term
interest rates on the floating-rate debt outstanding at December 31, 2002 would
cost the Company approximately $1.4 million in additional annual interest, net
of swaps.

Capital Restructuring Program

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 $115.8 million and total debt (including Trust
preferred) to $368.0 million at December 31, 2002. While the Company believes
its financial position has stabilized, management believes its leverage remains
too high. The Company believes it should further reduce debt as a percentage of
its capitalization. The Company currently believes it has sufficient liquidity
and cash flow to meet its obligations for the next 12 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.

28

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 2002, the Company received an average of $22.25 per barrel of
oil and $3.50 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. During 2002, the Company experienced a
slight decline in certain drilling and operational costs when compared to the
prior year. The Company expects an increase in these costs for 2003. Increases
in commodity prices can cause inflationary pressures specific to the industry to
also increase.

RESULTS OF OPERATIONS

Volumes and Sales Prices

29

The following table identifies certain items included in the results of
operation. It is presented to assist in a comparison of the last three years.
The table should be read in conjunction with the following discussion of results
of operations.

(a) Provision for additional G&A representing the mark-to-market expense
related to stock held in the deferred compensation plan.

30

Comparison of 2002 to 2001

Net income in 2002 totaled $25.8 million compared to $17.7 million in
2001. A $4.0 million gain on retirement of securities was realized in 2001
versus $2.0 million in 2002. The 2002 gain was net of deferred taxes of $1.1
million. Production decreased 2% to 150.1 Mmcfe per day due to lower production
at Matagorda 519 and other production declines in the Gulf Coast. Revenues of
$195.3 million were $24.1 million lower than 2001 due to the production decline
and a 7% decrease in average prices to $3.49 per mcfe. The average prices
received for oil decreased 13% to $22.25 per barrel and for gas decreased 4% to
$3.50 per mcfe. Production expenses decreased $3.0 million to $40.4 million as a
result of lower production and property taxes, and reduced workover costs in the
Gulf of Mexico. Operating cost per mcfe produced averaged $0.74 in 2002 versus
$0.78 in 2001.

Transportation and processing revenues were about the same as 2001 at
$3.5 million. IPF's $3.8 million of revenues declined 43% from 2001. IPF records
income on payments received on transactions that do not have a valuation
allowance. On accounts with a valuation allowance, IPF reduces the carrying
value of the receivable. Due to a declining portfolio balance in 2001, less
income was recorded from payments received. Due to a significantly lower
portfolio balance in 2002, less income was again recorded. During 2001, IPF
expenses included $1.8 million of administrative costs, $1.8 million of interest
and a net unfavorable adjustment of $122,000 to IPF receivables, net. During
2002, IPF expenses included $1.7 million of administrative costs, $937,000 of
interest costs and $4.2 million was added to its valuation allowances.

Exploration expense increased 96% to $11.5 million in 2002 primarily
due to higher dry hole cost, additional seismic purchases and personnel
expenses. General and administrative expenses increased 41% due to an increase
in non-cash mark-to-market compensation expense ($3.4 million), additional
personnel costs ($1.4 million), higher insurance costs ($233,000), higher legal
and consulting costs ($317,000) offset by lower bad debt expenses. The average
number of general and administrative personnel increased 12% between 2001 and
2002.

Other income decreased from income of $490,000 in 2001 to a loss of
$2.9 million in 2002. 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 write-down of marketable securities and a $1.4 million bad debt expense
related to Enron hedges. The 2002 period included a $2.7 million ineffective
loss and $1.2 million write-down of marketable securities, offset by a $715,000
recovery on an arbitration. Interest expense decreased 28% to $23.2 million
primarily as a result of lower debt balances and falling interest rates. Average
outstandings on the Parent credit facility were $90.5 million and $105.3 million
for 2001 and 2002, respectively, and the average interest rates were 6.4% and
3.4%, respectively.

Depletion, depreciation and amortization ("DD&A") decreased 1% to $76.8
million as a result of lower production and the mix of production between
depletion pools offset by higher depletion rates. The DD&A rate per mcfe in 2002
was $1.40, a $0.01 increase from 2001. The DD&A rate is determined based on
year-end reserves (based on NYMEX futures prices averaging $4.11 per mcf and
$23.36 per barrel) and the net book value associated with them and to a lesser
extent, depreciation on other assets owned. The DD&A rate in the fourth quarter
of 2002 was $1.44 per mcfe, reflecting year-end 2002 reserves. The Company
currently estimates that the DD&A rate for 2003 will remain at roughly $1.44 per
mcfe.

The Company recorded a $31.1 million provision for impairment on
acreage and proved properties at year-end 2001. No impairment was recorded in
2002.

Comparison of 2001 to 2000

Net income in 2001 totaled $17.7 million compared to $36.6 million in
2000. A $17.8 million gain on retirement of securities was realized in 2000
versus $4.0 million in 2001. The fourth quarter of 2001 included an impairment
charge of $31.1 million. Production increased to 152.7 Mmcfe per day, a 1%
increase from the prior year. Revenues benefited from a 20% increase in average
prices to $3.75 per mcfe. The average price received for oil increased 10% to
$25.59 per barrel and for gas increased 26% to $3.65 per mcfe. Production
expenses increased $2.9 million to $43.4 million as a result of higher
production and property taxes, increased workover costs and slightly higher
costs for labor, services and supplies. Operating cost per mcfe produced
averaged $0.78 in 2001 versus $0.73 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 mid-2000 and lower
NGL prices. IPF's $6.6 million of revenues declined 7% from 2000. IPF records

31

income on payments for transactions that do not have a valuation allowance. On
accounts with a valuation allowance, IPF reduces the carrying value of the
receivable. Due to a declining portfolio balance in 2001, less income was
recorded from payments received. During 2001, IPF expenses included $1.8 million
of administrative costs and $1.8 million of interest. In 2001, a favorable
adjustment to IPF reserves of $1.8 million, due to favorable prices early in the
year, was more than offset by a year-end increase in the valuation allowance of
$2.0 million. During 2000, IPF expenses included $1.5 million of administrative
costs and $3.4 million of interest costs. In 2000, a favorable adjustment of
$2.9 million was recorded to IPF valuation allowances.

Exploration expense increased 84% to $5.9 million primarily due to
additional seismic activity and increased personnel expenses. General and
administrative expenses decreased 18% due to a decline in non-cash
mark-to-market compensation expense of $5.8 million offset by additional
personnel costs ($1.4 million), higher legal and occupancy costs ($1.2 million)
and additional costs ($600,000) incurred from having duplicate functions at
Great Lakes and Range. The average number of general and administrative
personnel increased 15% from 2000 to 2001.

Other income increased from a loss of $722,000 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
write-down of marketable securities and a $1.4 million bad debt expense related
to Enron hedges. The 2000 period included a $1.1 million loss on asset sales.
Interest expense decreased 19% to $32.2 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.

DD&A increased 16% to $77.6 million as a result of the mix of production
between depletion pools and higher depletion rates. The DD&A rate per mcfe in
2001 was $1.39, an $0.18 increase from 2000. The DD&A rate is determined based
on year-end reserves (based on futures prices) and the net book value associated
with them and to a lesser extent, depreciation on other assets owned. The DD&A
rate in the fourth quarter of 2001 was $1.60 per mcfe.

The Company recorded a provision for impairment on acreage of $5.1
million and proved properties for $25.9 million at year-end 2001. In evaluating
possible impairment, the Company evaluates acreage on a separate basis from
proved properties. 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 acreage to the
assessment of value that could be recovered from sale, farm-out or exploitation.
The Company considers other additional information it believes relevant in
evaluating the properties' fair value, such as geological assessment of the
area, other acreage purchases in the area and the timing of associated drilling.
The following acreage was impaired in 2001 for the reasons indicated (in
thousands).

The impairment evaluation on proven properties is based on proved
reserves and estimated future cash flows, including revenues from anticipated
oil and gas production, severance taxes, direct operating expenses and capital
costs. The following properties were impaired in 2001 based on analysis of
future cash flows (in thousands):

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 the Company'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 the Company's views and manages its
ongoing market-risk exposures. All of the Company's market-risk sensitive
instruments were entered into for purposes other than trading.

Commodity Price Risk. The Company's major market risk is exposure to
oil and gas prices. Realized prices are 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 from proved reserves. Pursuant to these swaps, Range
receives a fixed price for its production and pays market prices to the
counterparty. 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, 2002, Range had oil and gas hedges in place covering
64.6 Bcf of gas and 1.6 million barrels of oil. Their fair value, represented by
the estimated amount that would be realized upon termination, based on contract
versus NYMEX prices, approximated a net pre-tax loss of $32.9 million at that
date. These contracts expire monthly through December 2005 and cover
approximately 90%, 75% and 10% of anticipated production from proved reserves
for 2003, 2004 and 2005, respectively. 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 2000 and 2001 were $43.2 million
and $6.2 million, respectively. A gain of $17.8 million was recorded in 2002.
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 Mmbtus per day,
at $3.20 per Mmbtu for the first three contract months of 2002. Based on
accounting requirements, the Company 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 was
included in income in the first quarter of 2002. The last of the Enron contracts
expired in March 2002.

In 2002, a 10% reduction in oil and gas prices, excluding amounts fixed
through hedging transactions, would have reduced revenue by $17.5 million. If
oil and gas futures prices at December 31, 2002 had declined by 10%, the
unrealized hedging loss at that date would have decreased 95% or $31.3 million.

Interest Rate Risk. At December 31, 2002, the Company had $368.0
million of debt (including Trust preferred) outstanding. Of this amount, $175.7
million bears interest at fixed rates averaging 7.0%. Senior debt and
non-recourse debt totaling $192.3 million bears interest at floating rates,
excluding interest rate swaps, which averaged 3.4% at that date. At December 31,
2002, Great Lakes had interest rate swap agreements totaling $100.0 million, 50%
of which is consolidated by Range. Five agreements totaling $35.0 million at an
average rate of 4.6% expire in June 2003. Two agreements totaling $45.0 million
at rates of 7.1% expire in May 2004. Two agreements of $10.0 million each at
2.3% expire in December 2004. On December 31, 2002, the 30-day LIBOR rate was
1.4%. A 1% decrease in short-term interest rates on the floating-rate debt
outstanding (net of amounts fixed through hedging transactions) at December 31,
2002 would cost the Company approximately $1.4 million in additional annual
interest.

33

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reference is made to the Index to Financial Statements on page 43 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, KPMG
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

As more fully disclosed in our Form 8K and Form 10-Q filed by the
Company on July 15, 2002, the Company dismissed its auditor, Arthur Andersen
LLP, and appointed KPMG LLP, during 2002. There were no disagreements with our
prior accounting firm prior to its dismissal.

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 2002 annual stockholders' meeting. Officers are appointed
by the Board.

Thomas J. Edelman, Chairman and Chairman of the Board of Directors,
joined the Company in 1988. From 1981 to 1997, he served as a Director and
President of Snyder Oil Corporation ("SOCO"), a publicly traded independent oil
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 a Bachelor of Arts,
magna cum laude, from Princeton University and his Masters 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 in Business Administration from Texas Christian University and
his Master of Arts in Business Administration from the University of Texas.

Robert E. Aikman became a Director in 1990. Mr. Aikman has more than 50
years experience in oil and 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 Chairman of WhamTech, Inc. and Vision Resources L.L.C. and is also
President of The Hawthorne Company, an entity which organizes joint ventures and
provides advisory services for the acquisition of oil and gas properties and the
restructuring, reorganization and/or sale of oil and gas 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 received a Bachelor of
Arts/Sciences from the University of Oklahoma.

Anthony V. Dub became a Director in 1995. Mr. Dub is Chairman of Indigo
Capital, LLC, a financial advisory firm based in New York. Prior to forming
Indigo Capital in 1997, he served as an officer of Credit Suisse First Boston.
Mr. Dub joined CSFB in 1971 and was named a Managing Director in 1981. Mr. Dub
led a number of departments during his 27 year career at CSFB including the
Investment Banking Department. Mr. Dub is a director of Capital IQ, Inc. Mr. Dub
received a Bachelor of Arts, magna cum laude, from Princeton University.

35

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 earned a Bachelor of Arts from St. Lawrence University and a J.D. 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.

Jonathan S. Linker was elected to the Board at the 2002 Annual Meeting.
Mr. Linker served as a Director of the Company from August 1998 until October
2000. He has been active in the energy business since 1972. Mr. Linker began
working with First Reserve Corporation, the largest private equity firm
investing exclusively in energy, in 1988 and was a Managing Director of the firm
from 1996 until July 2001. Mr. Linker has been President and a director of IDC
Energy Corporation since 1987, a director and officer of Sunset Production
Corporation since 1991 serving currently as Chairman, and Manager of Shelby
Resources Inc., a small, privately-owned exploration and production company. He
is a director of First Wave Marine, Inc., a private company providing shipyard
and related services in the Houston-Galveston area. Mr. Linker received a
Bachelor of Arts in Geology from Amherst College, a Masters in Geology from
Harvard University and a MBA from Harvard University's Graduate School of
Business Administration.

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 is a 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 acquired by Beacon in 1997. Prior to 1991, Mr.
Lynch was a Managing Director of Lehman Brothers. Mr. Lynch received a Bachelor
of Arts from the University of Pennsylvania and a Masters from the Wharton
School of Business at the University of Pennsylvania.

Terry W. Carter, Executive Vice President-Exploration and Production,
joined the Company in 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,
Mr. LeBlanc served as Senior Vice President and Chief Financial Officer. Mr.
LeBlanc's 27 years of experience include assignments in the oil and gas
subsidiaries of Celeron Corporation and Goodyear Tire and Rubber. Prior to
entering the oil industry, Mr. LeBlanc was with a national accounting firm, he
is a certified public accountant, a chartered financial analyst and received a
Bachelor of Science from University of Southwestern Louisiana.

Herbert A. Newhouse, Senior Vice President - Gulf Coast, joined the
Company in 1998. Previously, Mr. Newhouse served as Executive Vice President of
Domain Energy Corporation and as a 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 the oil industry. Mr.
Newhouse received a Bachelor of Science in Chemical Engineering from Ohio State
University.

Chad L. Stephens, Senior Vice President - Corporate Development, joined
the Company in 1990. Previously, Mr. Stephens was with Duer Wagner & Co., an
independent oil and gas producer, since 1988. Prior to that, 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 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 was a Senior Vice President of SOCO,
now part of Devon Energy Corporation. Before joining SOCO, Mr. Waller was with
Arthur Andersen. Mr. Waller received a Bachelor of Arts from Harding University.

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

Audit Committee. The Audit Committee engages the Company's independent
public accountants and reviews their professional services and the independence
of such accountants. 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. Dub,
Eales and Linker 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 candidates for officer positions. The members of the Compensation
Committee are Messrs. Aikman, Finkelson and Lynch.

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

Nominating Committee. The Nominating Committee reviews background
information on 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 and Lynch.

ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS

Information with respect to officers' compensation is incorporated
herein by reference to the Company's 2003 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 2003
Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14. CONTROLS AND PROCEDURES

Within the 90 days prior to the date of this report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the Company's Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Exchange Act Rule
13a-14. Based upon that evaluation, the Chief Executive Officer and the Chief
Financial Officer concluded that the Company's disclosure controls and
procedures are effective in timely alerting them to material information
relating to the Company (including its consolidated subsidiaries) required to be
included in the Company's periodic filings with the Securities and Exchange
Commission. No significant changes in the Company's internal controls or other
factors that could affect these controls have occurred subsequent to the date of
such evaluation.

37

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K

(A) Documents filed as part of the report.

1. Financial Statements
Financial Statements filed as part of this report are
included in Item 8 - Financial Statements and
Supplementary data.

2. Financial Statements Schedules and Supplementary Data.
All other schedules have been omitted since 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 notes thereto.

3. Exhibits.

The following documents are filed or incorporated by reference
as exhibits to this report.

- -----------
* Filed herewith.

(B) Reports on Form 8-K.

Form 8K dated November 13, 2002 (filed on November 13, 2002)
reporting under Item 9 - Regulation FD Disclosure.

Form 8K dated November 14, 2002 (filed on November 20, 2002)
reporting under Item 4 - Changes in Registrants Certifying
Accountants.

Form 8K/A dated December 2, 2002 (filed on December 2, 2002)
reporting under Item 4 - Changes in Registrants Certifying
Accountants.

Form 8K/A dated November 14, 2002 (filed on December 9, 2002)
reporting under Item 4 - Changes in Registrants Certifying
Accountants.

(C) Exhibits required to be filed pursuant to Item 601 of Regulation
S-K are contained in Exhibits listed in response to Item 15 (a)3,
and are incorporated herein by reference

(D) The required financial statements and financial schedules are filed
as part of this report.

41

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

Dated: March 5, 2003
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 following persons on behalf of the
registrant and in the capacities and on the dates indicated.

/s/ Thomas J. Edelman Thomas J. Edelman March 5, 2003
- --------------------------------------
Chairman and Chairman of the Board

/s/ John H. Pinkerton John H. Pinkerton March 5, 2003
- --------------------------------------
President and Director

/s/ Eddie M. LeBlanc III Eddie M. LeBlanc III March 5, 2003
- --------------------------------------
Chief Financial and Accounting Officer

/s/ Robert E. Aikman Robert E. Aikman March 5, 2003
- --------------------------------------
Director

/s/ Anthony V. Dub Anthony V. Dub March 5, 2003
- --------------------------------------
Director

/s/ V. Richard Eales V. Richard Eales March 5, 2003
- --------------------------------------
Director

/s/ Allen Finkelson Allen Finkelson March 5, 2003
- --------------------------------------
Director

/s/ Jonathan S. Linker Jonathan S. Linker March 5, 2003
- --------------------------------------
Director

/s/ Alexander P. Lynch Alexander P. Lynch March 5, 2003
- --------------------------------------
Director

42

I, John H. Pinkerton, certify that:

1. I have reviewed this annual report on Form 10-K of Range
Resources Corporation;

2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
annual report;

3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as of,
and for, the periods presented in this annual report.

4. The registrant's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to
ensure that material information relating to the
registrant, including its consolidated subsidiaries,
is made known to us by others within those entities,
particularly during the period in which this annual
report is being prepared;

b) evaluated the effectiveness of the registrant's
disclosure controls and procedures as of a date
within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about
the effectiveness of the disclosure controls and
procedures based on our evaluation of the Evaluation
Date;

5. The registrant's other certifying officer and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):

a) all significant deficiencies in the design or
operation of internal controls which could adversely
affect the registrant's ability to record, process,
summarize and report financial data and have
identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves
management or other employees who have a significant
role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated
in this annual report whether there were significant changes
in internal controls or in other factors that could
significantly affect internal controls subsequent to the date
of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.

Date: March 5, 2003

/s/ John H. Pinkerton
----------------------------
John H. Pinkerton, President

43

I, Eddie M. LeBlanc, certify that:

1. I have reviewed this annual report on Form 10-K of Range
Resources Corporation;

2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
annual report; and

3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition,
results of operations and cash flows of the registrant as of,
and for, the periods presented in this annual report.

4. The registrant's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to
ensure that material information relating to the
registrant, including its consolidated subsidiaries,
is made known to us by others within those entities,
particularly during the period in which this annual
report is being prepared;

b) evaluated the effectiveness of the registrant's
disclosure controls and procedures as of a date
within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about
the effectiveness of the disclosure controls and
procedures based on our evaluation of the Evaluation
Date;

5. The registrant's other certifying officer and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):

a) all significant deficiencies in the design or
operation of internal controls which could adversely
affect the registrant's ability to record, process,
summarize and report financial data and have
identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves
management or other employees who have a significant
role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated
in this annual report whether there were significant changes
in internal controls or in other factors that could
significantly affect internal controls subsequent to the date
of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.

Date: March 5, 2003

/s/ Eddie M. LeBlanc
-----------------------------------------
Eddie M. LeBlanc, Chief Financial Officer

44

GLOSSARY

The terms defined in this glossary are used in this report.

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.

Parent credit facility. Range Resource's $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 oil or natural gas in
sufficient economic quantities.

exploratory well. A well drilled to find oil or gas in an unproved area, to find
a new reservoir in an existing field 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 many high value transactions.

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

mcf. One thousand cubic feet of gas.

mcf per day. One thousand cubic feet of gas per day.

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

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

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

Mmcf. One million cubic feet of gas.

Mmcfe. One million cubic feet of gas equivalents.

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

Present Value (PV). 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.

45

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 another formation in an existing
well bore.

reserve life index. Proved reserves at a point in time divided by the then
annual production rate.

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 necessarily extend to the
economic life of the property and may be of shorter duration than the underlying
working interest. The term overriding royalties in which the Company
participates through Independent Producer Finance typically extend until amounts
financed and a designated rate of return have been achieved. If such point in
time is reached, 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.

46

RANGE RESOURCES CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES

(ITEM 15[a], [d])

47

INDEPENDENT AUDITORS' REPORT

TO THE BOARD OF DIRECTORS AND STOCKHOLDERS
RANGE RESOURCES CORPORATION:

We have audited the accompanying consolidated balance sheets of Range
Resources Corporation as of December 31, 2001 and 2002, and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the years in the three-year period ended December 31, 2002. These
consolidated financial statements are the responsibility of Range Resources
Corporation's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits. We did not audit the
financial statements of Great Lakes Energy Partners L.L.C., a fifty percent
owned consolidated subsidiary (see Note 2), as of December 31, 2002 and for the
year then ended, which statements reflect total assets constituting 32 percent
and total revenues constituting 27 percent in 2002 of the related consolidated
totals. These statements were audited by other auditors whose report has been
furnished to us, and our opinion, insofar as it relates to the amounts included
in Great Lakes Energy Partners L.L.C. for the year-ended December 31, 2002, is
based solely on the report of the other auditors.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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 and the report of
the other auditors provides a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the other
auditors, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Range Resources
Corporation as of December 31, 2001 and 2002, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2002, in conformity with accounting principles generally
accepted in the United States of America.

As discussed in Note 2 to the financial statements, effective January
1, 2001, the Company changed their method of accounting for derivative financial
instruments and hedging activities.

KPMG LLP

Dallas, Texas
March 4, 2003

48

REPORT OF INDEPENDENT AUDITORS

To The Management Committee of
Great Lakes Energy Partners, L.L.C.

We have audited the consolidated balance sheets of Great Lakes Energy Partners,
L.L.C. and subsidiaries, (a Delaware limited liability company) (the Company) as
of December 31, 2002, and the related consolidated statements of income,
members' equity, accumulated other comprehensive income (loss) and comprehensive
income (loss) and cash flows for the year then ended (not presented separately
herein). These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audit. The financial statements
of Great Lakes Energy Partners, L.L.C. as of December 31, 2001 and for the years
ended December 31, 2000 and 2001, were audited by other auditors whose report
dated September 17, 2002, expressed an unqualified opinion on those statements,
included explanatory paragraphs that disclosed the change in the Company's
method of accounting for derivative financial instruments and that the Company
had restated its consolidated financial statements from inception (September 30,
1999) to December 31, 1999 and the years ended December 31, 2000 and 2001, which
consolidated financial statements were previously audited by other independent
auditors, who have ceased operations.

We conducted our audit 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 consolidated financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the consolidated
financial statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall consolidated financial statement presentation. We believe that our audit
provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Great
Lakes Energy Partners, L.L.C. and subsidiaries as of December 31, 2002 and the
consolidated results of their operations and their cash flows for year then
ended in conformity with accounting principles generally accepted in the United
States.

/s/ ERNST & YOUNG LLP

Pittsburgh, Pennsylvania
January 31, 2003

49

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

SEE ACCOMPANYING NOTES.

50

RANGE RESOURCES CORPORATION

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

SEE ACCOMPANYING NOTES.

51

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

SEE ACCOMPANYING NOTES.

52

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)

SEE ACCOMPANYING NOTES.

53

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) ORGANIZATION AND NATURE OF BUSINESS

The Company 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 and exploratory 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").

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION

The accompanying consolidated financial statements include the accounts
of the Company, wholly-owned subsidiaries and a 50% pro rata share of the
assets, liabilities, income and expenses of Great Lakes. Liquid investments with
original maturities of 90 days or less are considered cash equivalents. The
Company has no off-balance sheet assets or liabilities other than those referred
to in the consolidated financial statements.

REVENUE RECOGNITION

The Company recognizes revenues from the sale of products and services
in the period delivered. Payments received at IPF relating to return are
recognized as income; remaining receipts reduce receivables. Although
receivables are concentrated in the oil industry, the Company does not view this
as unusual credit risk. However, IPF's receivables are from small independent
operators who usually have limited access to capital and the assets which
underlie the receivables lack diversification. Therefore, operational risk is
substantial and there is significant risk that required maintenance and repairs,
development and planned exploitation may be delayed or not accomplished. A
decrease in oil prices could cause an increase in IPF's valuation allowances and
a corresponding decrease in income. At December 31, 2001 and 2002, IPF had
valuation allowances of $13.0 million and $12.6 million, respectively. The
Company had other allowances for doubtful accounts relating to its exploration
and production business of $2.9 million and $835,000 at December 31, 2001 and
2002, respectively.

MARKETABLE SECURITIES

The Company has adopted Statement of Financial Accounting Standards No.
115, "Accounting for Certain Investments," ("SFAS 115") pursuant to which the
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 (loss). 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. The Company owns
approximately 18% of a very small publicly traded independent exploration and
production company. This entity has experienced growing difficulties,
operationally and financially. During 2001 and 2002, 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 and $1.2 million, respectively, were
recorded as reductions to Other revenues. Based on its analysis of the
investment and its assessment of the prospects of realizing any value on the
stock, the Company determined that the investment had no determinable value at
June 30, 2002 and the book value of the investment was fully reserved. In
October 2002, several creditors sought to place this entity in involuntary
bankruptcy.

INDEPENDENT PRODUCER FINANCE

IPF acquires dollar denominated royalties in oil and gas properties
from small producers. The royalties are accounted for as receivables because the
investment is recovered from a percentage of revenues until a specified rate of
return is received. Payments received believed to relate to the return is
recognized as income; remaining receipts reduce receivables. No interest income
is recorded on impaired receivables and any payments received applicable to
impaired receivables are applied as a reduction of the receivable. Receivables
classified as current represent the return of capital expected to be received
within 12 months. All receivables are evaluated quarterly and provisions for
uncollectible amounts are established based on the Company's valuation of its
royalty interest in the oil and gas properties. As of December 31, 2002,
receivables for which no valuation

54

allowance existed totaled $12.2 million and the weighted average rate of return
on that balance was 17%. 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 cash flow that
favorably impacted the valuation of the receivables. As a result, $1.8 million
of increases in receivables were recorded as a reduction in IPF expenses in
2001. However, because of lower prices and lower anticipated cash flows, IPF
increased its reserve allowance by $2.0 million in the fourth quarter of 2001.
During 2001 and 2002, IPF expenses were comprised of $1.8 million and $1.7
million of general and administrative costs and $1.8 million and $937,000 of
interest, respectively. In 2000, IPF recorded a $2.9 million favorable
adjustment to their valuation allowance. In 2001 and 2002, IPF recorded a $2.0
million and $4.2 million unfavorable adjustment to their valuation allowance,
respectively. Based on the decline on the performance of the assets underlying
the IPF receivables, $4.2 million was added to the valuation allowances in 2002.
The valuation allowance at December 31, 2001 and 2002 was $13.0 million and
$12.6 million, respectively.

The following table describes the activity for the past three years
included in the IPF valuation allowance (in thousands):

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. Wells subsequently determined to be dry holes are charged to
expense. Costs resulting in exploratory discoveries and all development costs,
whether successful or not, are capitalized. Geological and geophysical costs,
delay rentals and unsuccessful exploratory wells are expensed. Depletion is
provided on the unit-of-production method. Oil is converted to gas equivalent
basis ("mcfe") at the rate of six mcf per barrel. The depletion, depreciation
and amortization ("DD&A") rates were $1.21, $1.39 and $1.40 per mcfe in 2000,
2001 and 2002, respectively. Unproved properties had a net book value of $49.5
million, $25.7 million and $19.0 million at December 31, 2000, 2001 and 2002,
respectively. Unproved properties are reviewed each period for impairment and
reduced to fair value if required.

The Company adopted Statements of Financial Accounting Standards No.
144 "Accounting for Impairment or Disposal of Long-Lived Assets" ("SFAS 144") on
January 1, 2002 and there was no material impact on the Company. The Company's
long-lived assets are reviewed for impairment quarterly for events or changes in
circumstances that indicate that the carrying amount of an asset may not be
recoverable in accordance with SFAS No. 144. Long-lived assets are reviewed for
potential impairments at the lowest level for which there are identifiable cash
flows that are largely independent of other groups of assets. The review is done
by determining if the historical cost of proved properties less the applicable
accumulated depreciation, depletion and amortization and abandonment is less
than the estimated expected undiscounted future cash flows. The expected future
cash flows are estimated based on management's plans to continue to produce and
develop proved reserves. Expected future cash flow from the sale of production
of reserves is calculated based on estimated future prices. Management estimates
prices based upon market related information including published futures prices.
In years where market information is not available, prices are escalated for
inflation. The estimated future level of production is based on assumptions
surrounding future levels of prices and costs, field decline rates, market
demand and supply, and the economic and regulatory climates. When the carrying
value exceeds such cash flows, an impairment loss is recognized for the
difference between the estimated fair market value and the carrying value of the
assets.

55

The following acreage was impaired in 2001 for the reasons indicated
(in thousands):

The following are the proved property values impaired, due to declines
in gas prices, in 2001 based on the analysis of estimated future cash flows (in
thousands):

TRANSPORTATION, PROCESSING AND FIELD ASSETS

The Company's gas gathering systems are generally 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 10 to 15 years. The
Company sold its only remaining gas processing facility in June 2000. The
Company receives third-party income 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 five to
seven years. Buildings are depreciated over 10 to 15 years.

OTHER ASSETS

The expenses of issuing 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 (using the sum-of-the year's digits
amortization method which does not differ materially from the effective interest
method). When a security is retired prior to maturity, related unamortized costs
are expensed. At December 31, 2002, such deferred financing costs totaled $3.0
million. Other assets at December 31, 2002 includes $3.0 million unamortized
debt issuance costs, $1.0 million of marketable securities held in the deferred
compensation plan and $403,000 of long-term deposits.

GAS IMBALANCES

The Company uses the sales method to account for gas imbalances,
recognizing revenue based on cash received rather than gas produced. Gas
imbalances at December 31, 2001 and December 31, 2002 were not significant.
However, the Company has recorded a net liability of $218,000 at December 31,
2002 for those wells where there are insufficient reserves to retire the
imbalance.

STOCK OPTIONS

The Company applies the intrinsic value-based method of accounting
prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees, and related interpretations, in accounting for its fixed
plan stock options. As such, compensation expense would be recorded on the date
of grant only if the current market price of the underlying stock exceeded the
exercise price. SFAS No. 123, Accounting for Stock-Based Compensation,
established accounting and disclosure requirements using a fair value-based
method of accounting for stock-based employee compensation plans. As allowed by
SFAS No. 123, the Company has elected to continue to apply the intrinsic
value-based method of accounting described above, and has adopted the disclosure
requirements of SFAS No. 123, as amended by SFAS No. 148, Accounting for
Stock-Based Compensation -- Transition and Disclosure, which are included in
Note 10 to the Consolidated financial statements.

56

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING

Beginning in 2001, Statement of Financial Accounting Standards No. 133
"Accounting for Derivatives" ("SFAS 133") required that derivatives be recorded
on the balance sheet as assets or liabilities at fair value. For derivatives
qualifying as hedges, the effective portion of any changes in fair value is
recognized in Stockholders' equity as Other comprehensive income (loss) ("OCI")
and then reclassified to earnings when the transaction is consummated. Changes
in the value of the ineffective portion of all open hedges is recognized in
earnings quarterly. On adopting SFAS 133 in January 2001, the Company recorded a
$72.1 million net unrealized pre-tax hedging loss on its balance sheet and an
offsetting deficit in OCI. At December 31, 2002, this loss had become $32.9
million by year-end. SFAS 133 can greatly increase volatility of earnings and
stockholders' equity of independent oil companies which have active hedging
programs such as Range. Earnings are affected by the ineffective portion of a
hedge contract (changes in realized prices that do not match the changes in the
hedge price). Ineffective gains or losses are recorded in Other revenue while
the hedge contract is open and may increase or reverse until settlement of the
contract. Stockholders' equity is affected by the increase or decrease in OCI.
Typically, when oil and gas prices increase, OCI decreases. The reduction in OCI
at December 31, 2002 related to increases in oil and gas prices since December
31, 2001. Of the $32.9 million unrealized pre-tax loss at December 31, 2002,
$24.4 million of losses would be reclassified to earnings over the next 12 month
period and $8.5 million for the periods thereafter, if prices remained constant.
Actual amounts that will be reclassified will vary as a result of changes in
prices.

The Company had hedge agreements with Enron North America Corp.
("Enron") for 22,700 Mmbtu per day, at $3.20 per Mmbtu covering the first three
contract months of 2002. Based on accounting requirements, the Company 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 due to Enron's collapse. The gain included in OCI at
year-end 2001 was included in income in the first quarter of 2002. The last
Enron contracts expired in March 2002.

The Company enters into hedging agreements to reduce the impact of
volatile oil and gas prices. These contracts generally qualify as cash flow
hedges, however, certain of the contracts have an ineffective portion (changes
in realized prices that do not match the changes in hedge price) which is
recognized in earnings. 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 in OCI.
The Company also enters into swap agreements to reduce the risk of changing
interest rates. These agreements generally qualify as cash flow hedges whereby
changes in the fair value of the swaps are reflected as an adjustment to OCI to
the extent the swaps are effective and are recognized in income as an adjustment
to interest expense in the period covered.

COMPREHENSIVE INCOME

The Company follows Statement of Financial Accounting Standards No.
130, "Reporting Comprehensive Income," defined as changes in Stockholders'
equity from non-owner sources. The following is a calculation of comprehensive
income (loss) for each of the three years ended December 31, 2002 (in
thousands):

(a) On adopting SFAS 133 on January 1, 2001, the Company recorded a $72.1
million liability for an unrealized pre-tax hedging loss on its balance
sheet and an offsetting deficit in Other comprehensive income (loss).

(b) Includes $1.0 million gain related to amounts due from Enron.

57

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States 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 reserves, impairment tests on
oil and gas properties, IPF valuation allowance and fair value of derivatives.

RECENT ACCOUNTING PRONOUNCEMENTS

On September 11, 2002, the Emerging Issues Task Force issued EITF Issue
No. 02-15, Determining Whether Certain Conversions of Convertible Debt to Equity
Securities are within the Scope of FASB Statement No. 84 "Induced Conversions of
Convertible Debt." Statement No. 84 was issued to amend APB Opinion No. 26,
"Early Extinguishment of Debt" to exclude from its scope convertible debt that
is converted to equity securities of the debtor pursuant to conversion
privileges different from those included in the terms of the debt at issuance,
and the change in conversion privileges is effective for a limited period of
time, involves additional consideration, and is made to induce conversion.
Statement 84 applies only to conversions that both (a) occur pursuant to changed
conversion privileges that are exercisable only for a limited period of time and
(b) include the issuance of all of the equity securities issuable pursuant to
conversion privileges included in the terms of the debt at issuance for each
debt instrument that is converted. The Task Force reached a consensus that
Statement 84 applies to all conversions that both (a) occur pursuant to changed
conversion privileges that are exercisable only for a period of time and (b)
include the issuance of all of the equity securities issuable pursuant to
conversion privileges included in the terms of the debt at issuance for each
debt instrument that is converted regardless of the party that initiates the
offer. This consensus should be applied prospectively to debt conversions
completed after September 11, 2002. Since, 1999, the Company has retired 6%
Debentures and Trust Preferred securities, each of which are convertible into
common stock under the terms of the issue, by either purchasing securities for
cash or issuing common stock in exchange for such securities. Since the
exchanges of common stock for these convertible debt securities were at relative
market values, the convertible securities were retired at a substantial discount
to face value. Under the provisions of SFAS No. 84, when an inducement is issued
to retire convertible debt, the face value of the convertible debt security
shall be charged to Stockholders' equity (common stock and paid in capital), the
shares of common stock issued in excess of the shares that would have been
issued under the terms of the debt instrument are expensed at the market value
of such shares and an offsetting increase to paid in capital. Therefore, instead
of recording gains on retirements of such securities acquired at substantial
discounts to face value, an expense will be recorded. There will be no
difference in total Stockholders' equity from the change in methods of recording
the transactions. The Company intends to continue to consider exchanging debt
securities for common stock of the Company, despite the negative impact on its
financial statements. If, in the opinion of management, the transaction is
favorable for the Company and its shareholders, the transaction will be executed
despite the negative impact on the financial statements.

In April 2002, the FASB issued Statement of Financial Accounting
Standards No. 145 "Rescission of FASB Statements No. 4, 44 and 64, amendment of
FASB Statement 13 and Technical corrections ("SFAS 145"). Extinguishment of debt
will be accounted for in accordance with Accounting Principles Board Opinion No.
30 "Reporting the Results of Operations, Reporting the Effects of Disposal of a
Segment of a Business and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions." SFAS 145 has a dual effective date. The provisions
relating to accounting for leases were applicable to transactions occurring
after May 15, 2002. The provisions relating to the early extinguishment of debt
will be adopted by the Company on January 1, 2003. As a result, gains from early
extinguishment of debt, which are currently reported as extraordinary items,
will be reported in income from continuing operations in comparative financial
statements subsequent to the adoption of SFAS 145.

In June 2001, FASB issued Statement of Financial Accounting Standards
No. 143 "Asset Retirement Obligations" ("SFAS 143") establishing a new
accounting model for the recognition of retirement obligations associated with
tangible long-lived assets and requiring that retirement cost should be
capitalized as part of an asset's cost and subsequently systematically expensed.
The Company will adopt SFAS 143 on January 1, 2003 as required. The adoption of
this statement will result in a cumulative effect and be reported as a change in
accounting principle relating to the abandonment of oil and gas producing
facilities. The Company cannot reasonably quantify the effect of the adoption on
either its financial position or results of operations at this time.

In June 2002, the FASB issued Statement of Financial Accounting
Standards No. 146 "Accounting for Exit or Disposal Activities ("SFAS 146").
SFAS 146 will be effective for exit or disposal activities that are initiated
after December 31, 2002.

58

RECLASSIFICATIONS

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

(3) ACQUISITIONS

Acquisitions are accounted for as purchases. Purchase prices were
allocated to acquired assets and assumed liabilities 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 properties for consideration of $4.7 million, $9.5
million and $21.8 million, during the years ended December 31, 2000, 2001 and
2002, respectively. These purchases include $1.7 million, $4.2 million and $15.6
million for proved oil and gas reserves, respectively, the remainder represents
unproved acreage purchases.

(4) 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.

(5) SUPPLEMENTAL CASH FLOW INFORMATION

The Company has and will continue to consider exchanging common stock
or equity-linked securities for debt, despite the negative impact on its
financial statements due to SFAS 84 (see Note 2 "Recent Accounting
Pronouncements"). If, in the opinion of management, the transaction is favorable
for the Company and its shareholders, the transaction will be executed. Existing
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 and the price at which debt is acquired.

59

(6) INDEBTEDNESS

The Company had the following debt and Trust preferred (as herein
defined) outstanding as of the dates shown (in thousands). Interest rates,
excluding the impact of interest rate swaps, at December 31, 2002 are shown
parenthetically:

From January 1, 2003 to March 1, 2003, the Company exchanged an
additional $880,000 face amount of the 6% Debentures for 129,000 shares of
common stock and repurchased for cash $400,000 face value of $5.75% Trust
preferred. The recording of 6% Debenture exchange includes an inducement expense
of $465,000. Interest paid in cash during the years ended December 31, 2001 and
2002 totaled $31.2 million and $23.3 million, respectively. No interest expense
was capitalized during 2000, 2001 and 2002.

PARENT SENIOR DEBT

In May 2002, the Company entered into an amended $225 million secured
revolving bank facility (the "Parent Facility"). The Parent Facility provides
for a borrowing base subject to redeterminations in April and October. On
December 31, 2002, the borrowing base on the Parent Facility was $147.0 million,
of which $31.1 million was available. On March 1, 2003, the borrowing base on
the Parent Facility was $147.0 million of which $23.5 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. The Company
has the right to increase the borrowing base by up to $10.0 million during any
six-month borrowing base period based on a percentage of the fair value of
subordinated debt (8.75% Senior subordinated notes, 6% Convertible subordinated
debentures or Trust preferred) retired by the Company. Interest is payable the
earlier of quarterly or as LIBOR notes mature. The loan matures in July 2005. A
commitment fee is paid quarterly on the undrawn balance at an annual 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, 2002, the commitment fee was
0.375% and the interest rate margin was 0.75%. The weighted average interest
rates on the Parent Facility was 6.4% and 3.9% for the years ended December 31,
2001 and 2002, respectively. As of March 1, 2003, the interest rate was 3.4%.

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

60

base, which is subject to semi-annual redeterminations in April and October.
Cash distributions to members of the joint venture are limited by a covenant
contained in the Great Lakes Facility. As of December 31, 2002, $25.1 million
was available for distribution to members. There is an agreement between the
parties of the joint venture that Great Lakes will distribute, on a quarterly
basis, amounts deemed to be a tax distribution. This amount, net to the Company,
was $3.2 million in 2002 and is estimated to be $4.5 million in 2003. As of
December 31, 2002, $25.1 million was available for distribution to members. As
of December 31, 2002, the borrowing base was $205.0 million of which $52.0
million was available. On March 1, 2003, the borrowing base was $205.0 million
of which $44.0 million was available. Interest is payable the earlier of
quarterly or as LIBOR notes mature. The loan matures in January 2005. The
interest rate on the facility is LIBOR plus 1.50% to 2.00%, depending on
outstandings. A commitment fee is paid quarterly on the undrawn balance at an
annual rate of 0.25% to 0.50%. At December 31, 2002, the commitment fee was
0.375% and the interest rate margin was 1.50%. The weighted average interest
rates on these borrowings, excluding interest rate hedges, were 6.4% and 3.9%
for the years ended December 31, 2001 and 2002, respectively. After hedging, the
effective rate was 9.4% and 6.8% for the 12 months ended December 31, 2001 and
2002, respectively. At March 1, 2003, the interest rate was 3.3%, excluding
interest rate hedges and 5.5% including interest rate hedges.

IPF had a $100.0 million secured revolving credit facility (the "IPF
Facility"). In late December 2002, the $12.9 million balance of the IPF Facility
was retired with borrowings from the Parent Facility and the facility was
terminated. The IPF Facility was non-recourse to Range. The IPF Facility bore
interest at LIBOR plus 1.75% to 2.25% depending on outstandings. Interest
expense attributable to the IPF Facility is included in IPF expenses in the
Consolidated statements of operations and amounted to $1.8 million and $937,000
for the years ended December 31, 2001 and 2002, respectively. A commitment fee
was paid quarterly on the undrawn balance at an annual rate of 0.375% to 0.50%.

SUBORDINATED NOTES

The 8.75% Senior Subordinated Notes due 2007 (the "8.75% Notes") are
redeemable 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 senior
debt. 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 12 months ended December 31, 2001, the Company repurchased $42.5
million face amount of the 8.75% Notes at a discount. The cash flow reflects a
$41.2 million repayment of debt relating to these repurchases. The Company also
exchanged $3.4 million of the 8.75% Notes for common stock. During 2002, the
Company repurchased $9.0 million face amount of the 8.75% Notes for $8.9
million. The Company also exchanged $875,000 of the 8.75% Notes for common
stock. Exchanges are not reflected on the cash flow statement. The gain on these
repurchases is included as an Extraordinary Gain on retirement of debt
securities on the Consolidated statements of operations. The repurchased notes
are held in treasury and may be reissued. As of March 1, 2003, $69.3 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 103.0% of principal, declining 0.5% each February to 101% in 2006,
remaining at that level until it becomes par at maturity. The 6% Debentures are
unsecured general obligations subordinated to all senior indebtedness, including
the 8.75% Notes. During 2001 and 2002, $5.7 million and $7.1 million of 6%
Debentures were retired at a discount in exchange for 759,000 and 1.2 million
shares of common stock, respectively. In addition, $2.3 million and $815,000
were repurchased in 2001 and 2002, respectively. Exchanges are not reflected on
the cash flow statement. Extraordinary gains of $1.9 million and $1.3 were
recorded in 2001 and 2002, respectively. Subsequent to December 31, 2002, the
Company exchanged for 129,000 shares of common stock, an additional $880,000
face amount of the 6% Debentures. As of March 1, 2003, $20.7 million of the 6%
Debentures remained outstanding.

TRUST PREFERRED - MANDITORILY REDEEMABLE SECURITIES OF SUBSIDIARY

In 1997, a special purpose affiliate, (the "Trust") issued $120 million
of 5.75% 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 5.75% 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 102.875% 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 to suspend distributions on the Trust Preferred for five
years without triggering a default. During such suspension, accumulated
distributions accrue additional interest at a rate of 5.75% per annum. The
accounts of the

61

Trust are included in the consolidated financial statements after eliminations.
Distributions are recorded as interest expense in the Statement of operations,
are deductible for tax purposes, and are subject to limitations in the Parent
facility as described below. In the 12 months ended December 31, 2002, $2.4
million of Trust Preferred was reacquired at a discount in exchange for 283,000
shares of common stock. In addition $2.5 million face value was repurchased at a
cost of $1.5 million. An extraordinary gain of $1.8 million was recorded in
2002. In the 12 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 extraordinary gain of
$1.2 million was recorded in 2001. Subsequent to December 31, 2002, the Company
repurchased $400,000 face value of the Trust Preferred for $236,000. The
exchange transactions are not reflected on the cash flow statement because no
cash was involved. As of March 1, 2003, $84.4 million of the Trust Preferred
remained outstanding.

The debt agreements contain covenants relating to net worth, working
capital, dividends and financial ratios. If certain ratio requirements are not
met, payments of interest on the Trust Preferred would be restricted. The Parent
facility allows the payment of common dividends on common stock, beginning
January 1, 2003. The Company (including Great Lakes) was in compliance with all
such covenants at December 31, 2002. Under the most restrictive covenant,
$803,000 of dividends or other restricted payments could be paid at December 31,
2002.

Following is the principal maturity schedule for the long-term debt
outstanding as of December 31, 2002 (in thousands):

(7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

The Company's financial instruments include cash and equivalents,
receivables, payables, debt and commodity and interest rate derivatives. The
book value of cash and equivalents, receivables and payables are considered to
be representative of fair value because of their short maturity. The book value
of bank borrowings is believed to approximate fair value because of their
floating rate structure.

A portion of 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.

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

(a) Fair Value based on quotes received from certain brokerage houses.
Quotes for December 31, 2002 were 101.0% for the 8.75% Notes, 81.5% for
the 6% Debentures and 61.5% for the 5.75% Trust Preferred.

At December 31, 2002, the Company had open hedging contracts covering
64.6 Bcf of gas at prices averaging $3.96 per mcf and 1.6 million barrels of oil
at prices averaging $24.45 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 loss of $32.9 million at December 31, 2002. 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 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. Due to additional
hedging activity and rising prices, the Company estimates the net unrealized
loss at March 1, 2003 was $108.7 million. Net pre-tax losses incurred relating
to these derivatives for the years ended December 31, 2000, and 2001 were $43.2
million and $6.2 million, respectively. A hedging gain of $17.8 million was
realized in 2002. 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. Other revenues in the Consolidated
statement of operations were decreased for ineffective hedging losses of $1.1
million and $2.7 million in the year-ended December 31, 2001 and 2002,
respectively.

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. Based on accounting
requirements, the Company had 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 was included
in income in the first quarter of 2002. The last of the Enron contracts expired
as of March 2002.

The following schedule shows the effect of the closed oil and gas
hedges since January 1, 2001 and the value of open contracts at December 31,
2002 (in thousands):

63

Interest rate swap agreements are accounted for on the accrual basis.
Through Great Lakes, the Company uses interest rate swap agreements to manage
the risk that future cash flows associated with interest payments on amounts
outstanding under the variable rate Great Lakes facility may be adversely
affected by volatility in market interest rates. Under the Company's interest
rate swap agreements, the Company agrees to pay an amount equal to a specified
fixed rate of interest times a notional principal amount, and to receive in
return, a specified variable rate of interest times the same notional principal
amount. Changes in the fair value of the Company's interest rate swaps, which
qualify for cash flow hedge accounting treatment are reflected as adjustments to
other comprehensive income to the extent the swaps are effective and will be
recognized as an adjustment to interest expense during the period in which the
cash flows related to the Company's interest payments are made. The ineffective
portion of the changes in fair value of the Company's interest rate swaps is
recorded in income in the period incurred. At December 31, 2002, Great Lakes had
interest rate swap agreements totaling $100.0 million, 50% of which is
consolidated at Range. These swaps consist of five agreements totaling $35.0
million at an average rate of 4.6% which expire in June 2003, two agreements
totaling $45.0 million at rates of 7.1% which expire in May 2004 and two
agreements of $10.0 million each at rates of 2.3% which expire in December 2004.
Range's

64

share of the fair value of the swaps at December 31, 2002, was a hedge liability
of $2.1 million based on current quotes. On December 31, 2002, the 30-day LIBOR
rate was 1.4%. The Company recognized additional interest expense of $85,000,
$1.1 million and $2.4 million due to interest swaps in 2000, 2001 and 2002,
respectively.

The combined fair value of net losses on oil and gas hedges and net
losses on interest rate swaps totaling $35.1 million appeared as Unrealized
derivative gains and Unrealized derivative losses on the balance sheet at
December 31, 2002. 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, which includes a royalty owner suit filed in
2000 asking for class action certification against Great Lakes and the Company.
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 2002, approximately $250,000 of costs were
expensed in defense of litigation, and $385,000 reduced an accrued liability
related to the period prior to the formation of Great Lakes. The Company
received a $715,000 arbitration recovery, net of $72,000 of legal expenses.

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 $1.6
million, $1.7 million and $1.7 million in 2000, 2001 and 2002, respectively.
Future minimum rental commitments under non-cancelable leases are as follows (in
thousands):

2003 $1,808
2004 1,128
2005 974
2006 561
2007 and thereafter 299
------
$4,770
======

(9) STOCKHOLDERS' EQUITY

The Company has authorized capital stock of 110 million shares which
includes 100 million shares of common stock and 10 million shares of preferred
stock. In 1995, the Company issued $28.8 million of $2.03 Convertible
exchangeable preferred stock which was convertible into common stock at a price
of $9.50. The issue was retired in December 2001. The following is a schedule of
changes in the number of outstanding common shares since the beginning of 2001:

65

(10) STOCK OPTION AND PURCHASE PLANS

The Company has five 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 of Directors.
Information with respect to the option plans is summarized below:

There were options exercisable of 1,043,452 (weighted average price of
$9.32), 585,526 (weighted average price of $4.04) and 975,026 (weighted average
price of $4.46) at December 31, 2000, 2001 and 2002, respectively.

In 1999, shareholders approved the stock option plan (the "1999 Plan")
providing for the issuance of options on 1.4 million common shares. In 2001,
shareholders approved an increase in the number of options issuable to 3.4
million shares. In May 2002, shareholders approved an increase in the number of
options issuable to 6.0 million. All options issued under the 1999 Plan from
August 5, 1999 through May 22, 2002 vested 25% per year beginning after one year
and had a maximum term of 10 years. Options issued under the 1999 Plan after May
22, 2002 vest 30%, 30% and 40%, over a three year period and have a maximum term
of five years. During the year-ended December 31, 2002, 1,438,850 options were
granted under the 1999 Plan at exercise prices of $4.43, $5.26 and $5.49 a
share. At December 31, 2002, 2.5 million options were outstanding under the 1999
Plan at exercise prices of $1.94 to $6.67.

The Company 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 March 1999. Options issued under
the 1989 Plan vest 30%, 30% and 40% over a three year period and expire in five
years. At December 31, 2002, 453,580 options remained outstanding under the 1989
Plan at exercise prices of $2.63 to $7.62.

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 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.
Effective May 22, 2002, the term of the option was changed to five years with
vesting immediately upon grant. Director's options are normally granted upon
election of a director or annually upon their re-election at the annual meeting.
During the 12 months ended December 31, 2002, 48,000 options were granted under
the Directors' Plan at exercise prices of $5.49 share. At December 31, 2002,
152,000 options were outstanding under the Directors' Plan at exercise prices of
$2.81 to $6.00.

66

The Domain stock option plan was adopted when that company was
acquired, with existing Domain options becoming exercisable into Range common
stock. No options have been granted under this plan since the acquisition. At
December 31, 2002, 131,702 options remained outstanding under the Plan at a
price of $3.46 a share.

In total, 3.3 million options were outstanding at December 31, 2002 at
exercise prices ranging from $1.94 to $7.62 as follows:

In 1997, shareholders approved a plan (the "Stock Purchase Plan")
authorizing the sale of 900,000 shares of common stock to officers, directors,
key employees and consultants. In May 2001, shareholders approved an increase in
the number of shares authorized under the Stock Purchase Plan to 1,750,000.
Under the Stock Purchase Plan, the right to purchase shares at prices ranging
from 50% to 85% of market value may be granted. To date, all purchase rights
have been granted at 75% of market. Due to the discount from market value, the
Company recorded additional compensation expense of $236,000, $375,000 and
$227,800 during 2000, 2001 and 2002, respectively. Through December 31, 2002,
1,289,819 shares have been sold under the Stock Purchase Plan for $5.4 million.
At December 31, 2002, rights to purchase 166,500 shares were outstanding with
terms expiring in May 2003.

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 2000, 2001
and 2002 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 on the date of grant for the
disclosures is estimated by using the Black-Scholes option pricing model with
the following weighted-average assumptions used for 2000, 2001 and 2002,
respectively: fair value of $2.14, $6.50 and $4.89 per share; dividend yields of
$0 per share; expected volatility factors of, 64.89, 69.80 and 166.19; risk-free
interest rates of 5.5%, 5.0% and 4.9%, and an average expected life of 6 years,
6 years and nine years.

67

(11) DEFERRED COMPENSATION

In 1996, the Board of Directors of the Company adopted a deferred
compensation plan (the "Plan"). The Plan gives certain senior employees the
ability to defer all or a portion of their salaries and bonuses and invest in
common stock of the Company or make other investments at the employee's
discretion. The stock held in the employee benefit trust is treated in a manner
similar to treasury stock with an offsetting amount reflected as a deferred
compensation liability of the Company and the carrying value of the deferred
compensation is adjusted to fair value each reporting period by a charge or
credit to operations in the general and administrative expense category on the
Company's Statement of operations. The Company recorded mark-to-market expenses
related to deferred compensation of $3.4 million in 2000, a benefit of $2.4
million in 2001, and an expense of $1.1 million in 2002.

(12) BENEFIT PLAN

The Company maintains a 401(k) Plan for its employees. The Plan permits
employees to contribute up to 50% of their salary (subject to Internal Revenue
limitations) on a pretax basis. Historically, the Company has made discretionary
contributions to the 401(k) Plan annually. All Company contributions become
fully vested after the individual employee has three years of service with the
Company. In 2000, 2001 and 2002, the Company contributed $483,000, $554,000 and
$602,000, at then market value, respectively, of the Company's common stock to
the 401(k) Plan. The Company does not require that employees hold the
contributed stock in their account. Employees have a variety of investment
options available in the 401(k) Plan. Employees are encouraged to diversify out
of Company stock based on their personal investment strategy.

(13) INCOME TAXES

The Company's federal income tax benefit for the years ended December
31, 2000, 2001 and 2002, was ($1.6 million), ($406,000) and ($3.4 million),
respectively. A reconciliation between the statutory federal income tax rate and
the Company's effective federal income tax rate is as follows (in thousands):

68

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 deferred tax
liabilities and assets are as follows (in thousands):

A valuation allowance on the net deferred tax asset was originally
established (in years prior to 2000) due to the uncertainty of whether future
taxable income would be sufficient to utilize it. 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 $4.5 million is recorded on the balance sheet at year-end 2001.
Without considering the tax effects of certain deferred hedging gains included
in Other comprehensive income (loss) at December 31, 2001, deferred tax assets
exceeded deferred tax liabilities by $12.2 million, at December 31, 2001. The
inclusion of deferred tax liabilities related to OCI caused the deferred tax
liabilities to exceed deferred tax assets by the amount recorded on the balance
sheet and accordingly, the valuation allowance on the deferred tax asset was
reversed in 2001 through a reduction of $6.1 million and an increase to OCI of
$12.2 million. During 2002, the $12.2 million valuation allowance included in
OCI at December 31, 2001 was reversed as the related hedge positions closed as a
$11.2 million reduction of 2002 income tax expense, an $18,000 adjustment of
prior-period estimates and a $960,000 increase to Capital in excess of par
value. The $960,000 increase to Capital in excess of par value relates to the
tax benefits of employer stock option plans. At December 31, 2002, deferred tax
assets exceeded deferred tax liabilities by $15.7 million with $11.4 million of
deferred tax assets related to deferred hedging losses included in OCI. Based on
the Company's recent profitability and its current outlook, no valuation
allowance was deemed necessary at December 31, 2002.

At December 31, 2002, the Company had regular net operating loss
("NOL") carryovers of $218.2 million and alternative minimum tax ("AMT") NOL
carryovers of $198.5 million that expire between 2003 and 2022. Regular NOLs
generally offset taxable income and to such extent, no income tax payments are
required. To the extent that AMT NOLs offset AMT income, no alternative minimum
tax payment is due. 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, 2002, the Company had a statutory depletion carryover of $6.6
million and AMT credit carryovers of $665,000 that are not subject to limitation
or expiration.

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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:

(14) EARNINGS (LOSS) PER COMMON SHARE

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

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During 2001 and 2002, 129,000 and 160,000 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
because their inclusion would have been antidilutive.

(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 each of the years ended December 31, 2000, 2001 and
2002, three customers accounted for 10% or more of total oil and gas revenues
and the combined sales to those three customers accounted for 50%, 50% and 35%
of total oil and gas revenues, respectively. 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. In the year-ended December 31, 2002,
approximately 92% of Great Lakes gas was sold at prices based on the close of
NYMEX contracts each month plus a basis differential. The remainder is sold at a
fixed price.

(16) OIL AND GAS ACTIVITIES

The following summarizes selected information with respect to producing
activities. Exploration costs include capitalized as well as expensed outlays
(in thousands):

(a) Includes $1,719, $4,227 and $15,643 for oil and gas reserves, respectively;
the remainder represents acreage purchases.

(b) Includes $3,187, $5,879, and $11,525 of exploration cost expensed in 2000,
2001 and 2002, respectively.

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(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 50% interest in Great Lakes' audited financial
statements as of or for the years ended December 31, 2001 and 2002 (in
thousands):

With respect to certain revenue and expense items derived from the
Company's 50% interest in Great Lakes, the Company makes certain
reclassifications to the above items, primarily related to transportation and
gathering.

(18) EXTRAORDINARY ITEM

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. During 2002, 1.6 million shares of common stock were exchanged for
$2.4 million of Trust Preferred, $7.1 million of 6% Debentures and $875,000 of
8.75% Notes. In addition, $2.5 million of Trust Preferred, $815,000 of 6%
Debentures and $9.0 million of 8.75% Notes were repurchased. Since 1998, there
have been 15.2 million shares of common stock exchanged for convertible debt and
securities in the amount of $95.8 million. In connection with these exchanges,
an extraordinary gain net of costs of $17.8 million, $4.0 million and $3.1
million ($2.0 million net of taxes) was recorded in 2000, 2001 and 2002,
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 shares of $2.03 Preferred were repurchased for $74,000. The
gain on retirement of debt securities was net of taxes of $0, $0 and $1.1
million in 2000, 2001 and 2002, respectively.

(19) UNAUDITED SUPPLEMENTAL RESERVE INFORMATION

The Company and its 50% pro rata portion of Great Lakes' 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.

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The following schedules are presented in accordance with SFAS No. 69
("SFAS 69"), "Disclosures about Oil and Gas Producing Activities," to provide
users with a common base for preparing estimates of future cash flows and
comparing reserves among companies.

Estimated Net Proved Oil and Natural Gas Reserves - Reserves of crude
oil, condensate, natural gas liquids and natural gas are estimated by the
Company's engineers and are adjusted to reflect contractual arrangements and
royalty rates in effect at the end of each year. Many assumptions and judgmental
decisions are required to estimate reserves. Reported quantities are subject to
future revisions, some of which may be substantial, as additional information
becomes available from: reservoir performance, new geological and geophysical
data, additional drilling, technological advancements, price changes and other
economic factors.

The U.S. Securities and Exchange Commission defines proved reserves as
those volumes of crude oil, condensate, natural gas liquids and natural gas that
geological and engineering data demonstrate with reasonable certainty are
recoverable from known reservoirs under existing economic and operating
conditions. Proved undeveloped reserves are volumes expected to be recovered as
a result of additional investments for drilling new wells to offset productive
units, recompleting existing wells, and/or installing facilities to collect and
transport production.

Production quantities shown are net volumes withdrawn from reservoirs.
These may differ from sales quantities due to inventory changes, and especially
in the case of natural gas, volumes consumed for fuel and/or shrinkage from
extraction of natural gas liquids.

SFAS 69 requires calculation of future net cash flows using a 10%
annual discount factor and year-end prices, costs and statutory tax rates,
except for known future changes such as contracted prices and legislated tax
rates. The reported value of proved reserves is not necessarily indicative of
either fair market value or present value of future cash flows because prices,
costs and governmental policies do not remain static; appropriate discount rates
may vary; and extensive judgment is required to estimate the timing of
production. Other logical assumptions would likely have resulted in
significantly different amounts.

The average prices used at December 31, 2002 to estimate the reserve
information were $27.52 per barrel for oil, $18.72 per barrel for natural gas
liquids and $4.76 per mcf for gas using the benchmark NYMEX prices of $31.17 per
barrel and $4.75 per Mmbtu. The average prices at December 31, 2001 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.

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QUANTITIES OF PROVED RESERVES

The "Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves" ("Standardized Measure") is a disclosure
requirement of SFAS 69. 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.

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STANDARDIZED MEASURE

CHANGES IN STANDARDIZED MEASURE

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RANGE RESOURCES CORPORATION

INDEX TO EXHIBITS

(Item 15[a 3])

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* Filed herewith.