RANGE RESOURCES CORP - 10-Q Quarterly Report

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(MARK ONE)

{x} QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934.
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2002

{ } TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(D) OF THE SECURITIES EXCHANGE ACT OF 1934.

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, FT. WORTH, TEXAS 76102
(Address of principal executive offices) (Zip Code)

Registrant's telephone number: (817) 870-2601

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
--- ---

54,764,002 Common Shares were outstanding on July 26, 2002.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

The financial statements included herein should be read in conjunction
with the Company's latest Form 10-K. The statements are unaudited but reflect
all adjustments which, in the opinion of management, are necessary to fairly
present the Company's financial position and results of operations. All
adjustments are of a normal recurring nature unless otherwise disclosed. These
financial statements have been prepared in accordance with the applicable rules
of the Securities and Exchange Commission and do not include all of the
information and disclosures required by accounting principles generally accepted
in the United States for complete financial statements.

On July 11, 2002, the Board of Directors of the Company approved the
Audit Committee's recommendation to hire KPMG, LLP ("KPMG") as the Company's
independent auditors to replace Arthur Andersen LLP ("Arthur Andersen"), who was
dismissed immediately. KPMG's appointment was announced on July 15, 2002. As
part of the auditor selection process, KPMG performed its normal client
acceptance procedures with respect to the Company. In connection with these
procedures, KPMG advised the Company that it believes a different accounting
principle should have been used to determine the amount of gain recognized in
1999 upon the formation of the Great Lakes joint venture. The interim financial
statements included herein reflect this restatement. For additional details of
the transactions involved in the restatement and their impact on the
Consolidated Financial Statements, see Note 1 to Consolidated Financial
Statements.

While it was not required, the Company engaged KPMG to reaudit the
three years ended December 31, 2001. The reaudits are expected to be completed
by September 30, 2002. Upon completion of the reaudits, there could be a change
in the estimate of the proper amounts to be recorded for the Great Lakes
transaction (see below) as well as other adjustments for the years being
reaudited. As in the case of the Great Lakes restatement, adjustments to prior
periods would generally have an impact on current and future financial
statements due to adjustments to depreciation, depletion and amortization,
deferred tax accounting, stockholder's equity or other accounts. Any such
adjustments will be fully disclosed upon completion of the reaudits. Because
adjustments for the years being reaudited, if any, would likely have an impact
on the Company's reported financial statements for the three months ended June
30, 2002, KPMG has informed the Company that it can not complete its review in
accordance with statement on Auditing Standards No.71 until the reaudit is
substantially complete.

2

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED, IN THOUSANDS)

SEE ACCOMPANYING NOTES.

3

RANGE RESOURCES CORPORATION

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

SEE ACCOMPANYING NOTES.

4

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED, IN THOUSANDS)

SEE ACCOMPANYING NOTES.

5

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) RESTATEMENT

On July 11, 2002, KPMG LLP ("KPMG") was selected as the Company's
independent auditors to replace Arthur Andersen LLP ("AA"), who was dismissed
immediately. As part of the auditor selection process, KPMG performed its normal
client acceptance procedures with respect to the Company. In connection with
these procedures, KPMG advised the Company that it believes a different
accounting principle should have been used to determine the amount of gain
recognized in 1999 upon the formation of the Great Lakes joint venture. Under
this accounting principle, (i) the gain recognized in 1999 should be reduced
from $39.8 million to $31.0 million and (ii) income recognized in periods
subsequent to September 30, 1999 should be increased. The Company has restated
the financial statements included herein for the above mentioned item. Due to
this restatement, the December 2001 balance sheet, has been modified and;
therefore, that balance sheet is now unaudited until the completion of the three
year audit. At March 31, 2002, the restatement decreased oil and gas properties
$7.7 million, increased the deferred tax asset $0.8 million and decreased
stockholders' equity $6.8 million.

In connection with this process, KPMG advised AA of its different
interpretation of the accounting for the transaction. AA advised that it
continues to believe that the original amount of gain recognized in 1999 upon
the formation of the Great Lakes joint venture is appropriate.

While it was not required, in order to provide additional assurance to
its shareholders, the Company engaged KPMG to reaudit the three years ended
December 31, 2001. The reaudits are expected to be completed by September 30,
2002. Upon completion of the reaudits, there could be a change in the estimate
of the proper amounts to be recorded for the Great Lakes transaction (see below)
as well as other adjustments for the years being reaudited. As in the case of
the Great Lakes restatements, adjustments to prior periods would generally have
an impact on current and future financial statements due to amortization,
deferred tax accounting, stockholder's equity or other accounts. Any such
adjustments will be fully disclosed upon completion of the reaudits.

6

The following shows the effect of the restatement (in thousands, except per
share amounts):

9

(2) ORGANIZATION AND NATURE OF BUSINESS

Range Resources Corporation ("Range") is engaged in the development,
acquisition and exploration of oil and gas properties primarily in the
Southwestern, Gulf Coast and Appalachian regions of the United States. The
Company also provides financing to small oil and gas producers through a
subsidiary, Independent Producer Finance ("IPF"). The Company seeks to increase
its reserves and production principally through development drilling and
acquisitions. Range holds its Appalachian oil and gas assets through a 50% owned
joint venture, Great Lakes Energy Partners L.L.C. ("Great Lakes").

After a decade of rapid growth and consistent profitability, Range
concluded a series of unsuccessful acquisitions in 1997 and 1998. Due to the
poor performance of the purchases, substantial write-downs were required and the
Company was forced to retrench. Staff was reduced, capital expenditures cut,
assets sold and a program of exchanging common stock for fixed income securities
was initiated. Since year-end 1998, parent company bank debt has been reduced
73% to $98.3 million. Total debt, including Trust Preferred, has been reduced
49% to $373.3 million. As a result, the Company's financial position has
improved substantially. The Company expects to continue to retire debt with
internal cash flow and may continue to exchange common stock or equity-linked
securities for indebtedness. Stockholders could be materially diluted if a
substantial amount of debt is exchanged. The extent of dilution will depend on a
number of factors, including the number of shares issued, the price at which
stock is issued or newly issued securities are convertible into common stock and
the price at which debt is reacquired. While such exchanges reduce existing
stockholders' proportionate ownership, management believes they enhance the
Company's financial flexibility and should increase the market value of its
common stock over time.

With its financial strength largely restored, the Company began to
refocus on increasing production and reserves in 2001. As part of this effort,
the exploration and production effort was placed under the direction of a newly
hired Executive Vice President in early 2001. Due to reserve revisions and asset
sales, reserves and production fell in 1999 and 2000. In 2001, production
increased slightly but reserves continued to decrease as the capital program did
not replace production. The Company has announced a $100 million capital budget
of for 2002 and based on that budget, sought to increase production and reserves
during the year. Due to certain production interruptions experienced in the
first quarter of the year, production in 2002 may not increase over that
recorded in 2001. However, the Company believes production will again begin to
grow in comparison to prior year quarters by year-end.

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

(3) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION

The accompanying consolidated financial statements include the accounts
of the Company, majority-owned subsidiaries and a pro rata share of the assets,
liabilities, income and expenses of Great Lakes. Liquid investments with
maturities of ninety days or less are considered cash equivalents. Certain
reclassifications have been made to the presentation of prior periods to conform
with current year presentation. The Company's financial statements for the last
three years are currently being reaudited. The reaudits should be completed by
September 30, 2002. To date, the historical statements have been restated only
with respect to the gain reported on the Great Lakes transaction in 1999. Other
revisions may be required as a result of the reaudit. As in the case of

10

the Great Lakes restatement, adjustments to prior periods would generally have
an impact on current and future financial statements due to adjustments to
depreciation, depletion and amortization, deferred tax accounting, stockholders'
equity or other accounts. Any such adjustments will be fully disclosed upon
completion of the reaudits.

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 an 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. At
December 31, 2001 and June 30, 2002, IPF had valuation allowances of $17.3
million and $19.8 million and the Company had other allowances for doubtful
accounts of $2.2 million and $825,000, respectively. A decrease in oil prices
would be likely to cause an increase in IPF's valuation allowance.

MARKETABLE SECURITIES

The Company has adopted Statement of Financial Accounting Standards
("SFAS") No. 115, "Accounting for Investments," 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. 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 has owned approximately
15% of a very small publicly traded independent exploration and production
company. This company has experienced growing difficulties, operationally and
financially. During the first six months of 2001 and 2002, the Company
determined that the decline in the market value of this equity security it holds
was other than temporary and losses of $1.3 million and $1.2 million,
respectively, were recorded as reductions to Interest and 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.

GREAT LAKES

In 1999, the Company contributed its Appalachian assets to Great Lakes,
retaining a 50% interest in the venture. The other 50% is held by FirstEnergy
Corp. Great Lakes' proved reserves, 86% of which are gas, were 423.1 Bcfe at
December 31, 2001. In addition, the joint venture owned 4,600 miles of gas
gathering and transportation lines and a leasehold position of approximately 1.1
million (497,000 net) acres. Great Lakes has over 1,400 proved drilling
locations within existing fields. At year-end, Great Lakes had a reserve life
index of 17 years. As mentioned in Note 1, the gain recognized in 1999 upon the
formation of Great Lakes has been restated in these financial statements.

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 return
is received. Payments received believed to relate to the return are recognized
as income; remaining receipts reduce receivables. Receivables classified as
current represent the return of capital expected within twelve months. All
receivables are evaluated quarterly and provisions for uncollectible amounts
established. At June 30, 2002, IPF's valuation allowance totaled $19.8 million.
On certain receivables, income is recorded at rates below those specified due to
an assessment of risk. The receivables are non recourse and are from small
independent operators who usually have limited access to capital and the
property interests backing the receivables frequently lack diversification. Due
to the decreasing significance of IPF to the Company, IPF's net results are
currently reported in one line in the revenue section of the Consolidated
Statements of Income. Due to favorable oil and gas prices in early 2001, certain
of IPF's receivables began to generate greater than anticipated returns. As a
result, $816,000

11

and $1.9 million increases in receivables were recorded as additional income for
the three months and the six months ended June 30, 2001, respectively. In
addition, the IPF valuation allowance was reduced $406,000 in the second quarter
of 2001 which had a favorable impact on IPF reported net revenues. In the first
quarter of 2002, based on price declines and the disappointing performance of
certain properties, the valuation allowance was increased $1.1 million which was
recorded as a decrease to income. In the second quarter of 2002, the valuation
allowance was increased again by $1.4 million. During the second quarter of
2002, IPF revenues were $992,000 offset by $476,000 of general and
administrative costs and $261,000 of interest. During the same period of the
prior year, revenues were $1.1 million, the $406,000 favorable valuation
adjustment and the $816,000 favorable increase to receivables offset by general
and administrative expenses of $419,000 and $393,000 of interest. IPF's
receivables have declined from a high of $77.2 million in 1998 to $37.4 million
at June 30, 2002, as it has focused on recovering as much as possible of its
investments. During this period, IPF's debt declined from $60.1 million to $23.5
million. The Company is assessing alternatives relating to its ownership of IPF.

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 a dry hole are then
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 mcfe at the rate of six mcf per barrel. DD&A rates were $1.36 and
$1.33 per mcfe in the quarters ended June 30, 2001 and 2002 and $1.36 and $1.31
for the six months ended June 30, 2001 and 2002, respectively. Unproved
properties had a net book value of $25.7 million and $21.5 million at December
31, 2001 and June 30, 2002, respectively.

TRANSPORTATION 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 four to fifteen
years. The Company also receives third party income for providing certain field
services which are recognized as earned. These earnings approximated $500,000 in
each of the three month periods ended June 2001 and 2002, and $900,000 and
$1,000,000 for the six month periods, respectively. Depreciation on the
associated field assets is calculated on the straight-line method based on
estimated useful lives of three to seven years. Buildings are depreciated over
ten years.

OTHER ASSETS

The expense of issuing debt is 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-years digits amortization
method). When a security is retired prior to maturity, related unamortized costs
are expensed. At June 30, 2002, these capitalized costs totaled $3.6 million. In
the second quarter of 2002, the Company had a deferred tax asset of $4.6 million
which is included in Other assets. This deferred tax asset was $4.9 million at
March 31, 2002. At December 31, 2001, the Company had a $6.8 million net tax
liability. At June 30, 2002, Other assets included $3.6 million unamortized debt
issuance costs, $4.6 million deferred tax assets and $916,000 of long-term
deposits and other assets.

GAS IMBALANCES

The Company uses the sales method to account for gas imbalances,
recognizing revenue based on cash received rather than gas produced. At June 30,
2002, a gas imbalance liability of $114,000 was included in Accrued liabilities.

12

COMPREHENSIVE INCOME

The Company follows SFAS No. 130, "Reporting Comprehensive Income,"
defined as changes in Stockholders' equity from nonowner sources, which is
calculated below (in thousands):

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 reported assets, liabilities, revenues and
expenses, as well as disclosure of contingent assets and liabilities. Actual
results could differ from estimates. Estimates which may significantly impact
the financial statements include reserves, impairment tests on oil and gas
properties, IPF valuation allowance and the fair value of derivatives. As part
of the three year audit (See Note 1), these estimates are being reviewed. As in
the case of the Great Lakes restatement, adjustments to prior periods generally
have an impact on current and future financial statements.

RECENT ACCOUNTING PRONOUNCEMENTS

In April 2002, the FASB issued SFAS No. 145, Rescission of SFAS Nos. 4,
44 and 64, Amendment of SFAS No. 13 and Technical Corrections, which rescinds
SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt and an
amendment of that statement, SFAS No. 64, Extinguishment of Debt Made to Satisfy
Sinking - Fund Requirements. Management has not yet determined the effects of
adopting this Statement on the financial position or results of operations.
However, it appears that gains or losses on debt extinguishments previously
reported as extraordinary will now generally be included in pretax income. The
Company intends to adopt SFAS No. 145 effective January 1, 2003.

In 2001, SFAS No. 143 "Accounting for Asset Retirement" established
rules for the recognition and measurement of retirement obligations associated
with long-lived assets. The pronouncement requires that retirement costs be
capitalized as part of the cost of related assets and subsequently expensed
using a systematic and rational method. The Company will adopt the statement
effective January 1, 2003. The transition adjustment resulting from the adoption
of SFAS No. 143 will be reported as the cumulative effect of a change in
accounting principle. At this time, the Company cannot estimate the effect of
SFAS No. 143's adoption on its financial position or results of operations.
However, given the large number of wells in which the Company owns an interest,
the effect could be significant.

In 2001, the FASB issued SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets." The Statement establishes a single accounting
model for long-lived assets to be disposed of by sale and provides additional
implementation guidance for assets to be held and used and assets to be disposed
of other than by sale. The statement requires operating losses from discontinued
operations to be recognized in the periods in which they are incurred. This
statement was adopted by the Company effective January 1, 2002 with no initial
effect on its financial statements.

Beginning in 2001, SFAS No. 133, "Accounting for Derivatives," required
that derivatives be recorded on the balance sheet as assets or liabilities at
fair value. For derivatives qualifying as hedges, the effective portion of
changes in fair value is recognized in stockholders' equity as Other
Comprehensive Income ("OCI") and

13

reclassified to earnings when the transaction is consummated. Ineffective
portions of such hedges are recognized in earnings as they occur. On adopting
SFAS No. 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. Due to the decline in oil and gas prices since then, the roll off of
expiring hedges and the effect of new hedges, this loss had become a $6.8
million unrealized pre-tax gain at June 30, 2002. SFAS No. 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 Interest and 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 reduced OCI at June 30, 2002 related to
increases in oil and gas prices since December 31, 2001. Of the $6.8 million
unrealized pre-tax gain at June 30, 2002, $7.6 million would be reclassified to
earnings over the next twelve month period 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 for the first three months
of 2002. At December 31, 2001, based on accountants guidance, an allowance for
bad debts of $1.3 million was recorded, offset by a $318,000 ineffective gain
included in income and a $1.0 million gain included in OCI related to these
amounts. The gain included in OCI at year-end 2001 was included in Interest and
other revenue in the first quarter of 2002. In the three months ended June 30,
2002, the Company wrote off this receivable against the allowance for bad debts.
The last Enron contract expired in March 2002. If the Company recovers any of
its $1.6 million unsecured claim, the recovery will be reported as income at
that time.

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

Interest and other revenues in the Consolidated Statements of Income
reflected ineffective hedging gains of $1.0 million and $3.3 million for the
three months and the six months ended June 30, 2001, respectively. Ineffective
hedging losses of $462,000 and $2.2 million are included for the three months
and six months ended June 30, 2002, respectively. Net unrealized hedging gains
of $4.4 million (net of $2.4 million losses on interest rate swaps) and OCI of
$5.7 million (net of tax) were recorded on the balance sheet at June 30, 2002.
See Note 7.

(4) ACQUISITIONS

Acquisitions are accounted for as purchases. Purchase prices are
allocated to acquired assets based on estimates of fair value. Acquisitions have
been funded with internal cash flow, bank borrowings and the issuance of debt
and equity securities. The Company purchased various properties for $2.2 million
and $2.7 million during the six months ended June 30, 2001 and 2002,
respectively.

(5) IPF RECEIVABLES

At June 30, 2002, IPF had net receivables of $37.4 million after a
$19.8 million valuation allowance. The receivables represent overriding royalty
interests payable from an agreed-upon share of revenues until a specified return
is achieved. The royalties are property interests that serve as security for
receivables. On certain receivables, income has been recorded at rates below
those specified based on an assessment of risk. The Company estimates that $7.7
million of receivables at June 30, 2002 will be repaid in the next twelve months
and are classified as current. Since IPF's receivables primarily relate to oil
properties, a decrease in the oil price could cause an increase in IPF's
valuation allowance.

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(6) INDEBTEDNESS

The Company had the following debt and Trust Preferred (as hereinafter
defined) outstanding as of the dates shown. Interest rates at June 30, 2002,
excluding the impact of interest rate swaps, are shown parenthetically (in
thousands):

Subsequent to June 30, 2002, the Company repurchased $3.0 million of 8.75% Notes
and $500,000 of 6% Debentures at a discount.

Interest paid in cash during the three months ended June 30, 2001 and
2002 totaled $4.9 million and $2.9 million, respectively. Interest paid in cash
during the six months ended June 30, 2001 and 2002 totaled $17.1 million and
$12.0 million, respectively. The Company does not capitalize interest expense.

15

PARENT SENIOR DEBT

On May 2, 2002, the Company entered into an amended and restated $225.0
million revolving bank facility (the "Parent Facility"). The Parent Facility
provides for a borrowing base subject to redeterminations each April and
October. The initial borrowing base was $135.0 million. The Company has the
right to increase the borrowing base by up to $10 million during any six month
borrowing base period based on a percentage of the face value of subordinated
debt (8.75% Notes, 6% Debentures or Trust Preferred) retired by the Company. In
July 2002, the Company elected to increase the borrowing base to $141.0 million
under this provision. On July 26, 2002, the borrowing base was $141.0 million,
of which $39.5 million was available. The loan matures in July 2005. The
weighted average interest rate was 6.7% and 4.0% for the three months ended June
30, 2001 and 2002, and 7.5% and 4.1% for the six months then ended,
respectively. The interest rate is LIBOR plus a margin of 1.50% to 2.25%,
depending on outstandings. A commitment fee is paid on the undrawn balance based
on an annual rate of 0.375% to 0.50%. At June 30, 2002, the commitment fee was
0.375% and the interest rate margin was 1.75%. At July 26, 2002, the interest
rate was 3.6%.

NON-RECOURSE DEBT

The Company consolidates its proportionate share of borrowings on Great
Lakes' $275.0 million secured revolving bank facility (the "Great Lakes
Facility"). The Great Lakes Facility is non-recourse to Range and provides for a
borrowing base subject to redeterminations each April and October. On July 26,
2002, the borrowing base was $205.0 million of which $62.0 million was
available. The loan matures in January 2005. The interest rate on the Great
Lakes Facility is LIBOR plus 1.50% to 2.00%, depending on outstandings. A
commitment fee is paid on the undrawn balance at an annual rate of 0.25% to
0.50%. At June 30, 2002, the commitment fee was 0.375% and the interest rate
margin was 1.75%. The average interest rate on the Great Lakes Facility,
excluding hedges, was 6.7% and 3.9% for the three months ended June 30, 2001 and
2002 and 7.4% and 3.9% for the six months then ended, respectively. After
hedging (see Note 6), the rate was 7.7% and 6.8% for the quarters and 8.0% and
6.8% for the six months ended June 30, 2001 and 2002, respectively. At July 26,
2002, the interest rate was 3.6% excluding hedges and 6.6% after hedging.

IPF has a $100.0 million secured revolving credit facility (the "IPF
Facility"). The IPF Facility is non-recourse to Range and matures in January
2004. The borrowing base under the IPF Facility is subject to redeterminations
each April and October. On July 26, 2002, the borrowing base was $27 million of
which $3.5 million was available. The IPF Facility bears interest at LIBOR plus
1.75% to 2.25% depending on outstandings. A commitment fee is paid on the
undrawn balance at an annual rate of 0.375% to 0.50%. The weighted average
interest rate on the IPF Facility was 6.6% and 4.1% for the three months ended
June 30, 2001 and 2002, and 7.4% and 4.1% for the six months ended June 30, 2001
and 2002, respectively. As of July 26, 2002, the interest rate was 4.4%.

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 to par in
2005. The 8.75% Notes are unsecured general obligations subordinated to senior
debt. During the six month period ended June 30, 2002, the Company exchanged
$875,000 face amount of the 8.75% Notes for 183,000 shares of common stock. In
addition, during the second quarter ended June 30, 2002, the Company repurchased
$5.0 million face amount of the 8.75% Notes. During the six months ended June
30, 2001, the Company repurchased $25.0 million face amount of the 8.75% Notes
in the market at a discount. Only cash repurchases are reflected on the cash
flow statement. The gain on all exchanges is included as a Gain on retirement of
securities on the Consolidated Statements of Income. Subsequent to June 30,
2002, the Company repurchased $3.0 million face amount of the 8.75% Notes at a
discount. On July 26, 2002, $70.2 million of the 8.75% Notes were outstanding.

The 6% Convertible Subordinated Debentures Due 2007 (the "6%
Debentures") are convertible into common stock at the option of the holder at a
price of $19.25 per share. The 6% Debentures mature in 2007 and are 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 the quarters ended June 30, 2001 and 2002, $2.6 million and

16

$5.6 million of 6% Debentures were retired at a discount in exchange for 340,000
and 919,000 shares of common stock, respectively. During the six months ended
June 30, 2001 and 2002, $4.2 million and $7.1 million of 6% Debentures were
retired at a discount in exchange for 533,000 and 1,166,000 shares of common
stock, respectively. In addition, $15,000 face amount were repurchased in the
six months ended June 30, 2002. Extraordinary gains of $365,000 and $914,000
were recorded in the second quarter of 2001 and 2002, and $647,000 and
$1,154,000 for the six months ended June 30, 2001 and 2002, respectively.
Subsequent to June 30, 2002, the Company repurchased $500,000 face amount of the
6% Debentures at a discount. On July 26, 2002, $21.9 million of 6% Debentures
were outstanding.

TRUST PREFERRED

In 1997, a special purpose affiliate (the "Trust") issued $120 million
of 5.75% Trust Convertible Preferred Securities (the "Trust Preferred"). The
Trust Preferred is convertible into the Company's common stock at a price of
$23.50 a share. The Trust invested the proceeds in 5.75% convertible junior
subordinated debentures of the Company (the "Junior Debentures"). The Junior
Debentures and the Trust Preferred mature in 2027 and are currently redeemable
at 103.450% of principal, declining 0.58% each November to par in 2007. The
Company guarantees payment on the Trust Preferred to a limited extent, which
taken with other obligations, provides a full subordinated guarantee. 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 Trust are included in the consolidated financial statements
after eliminations. Distributions are recorded as interest expense and are tax
deductible. In the quarter ended June 30, 2001, $2.4 million of Trust Preferred
was reacquired at a discount in exchange for 231,000 shares of common stock.
During the six months ended June 30, 2001 and 2002, $2.4 million and $2.4
million of Trust Preferred were reacquired at a discount in exchange for 231,000
and 283,000 shares of common stock. An extraordinary gain of $619,000 was
recorded for the quarter ended June 30, 2001 and $619,000 and $900,000 for the
six months ended June 30, 2001 and 2002, respectively. On July 26, 2002, $87.3
million face amount of the Trust Preferred was outstanding.

The debt agreements contain covenants relating to net worth, working
capital, dividends and financial ratios. The Company was in compliance with all
covenants at June 30, 2002. Under the most restrictive covenant, which is
embodied in the 8.75% Notes, approximately $3.0 million of other restricted
payments could be made at June 30, 2002. As this covenant limits the ability to
repurchase the 6% Convertible Debentures and Trust Preferred, the Company may
seek to amend it. Subsequent to June 30, 2002, the Company repurchased $500,000
face amount of the 6% Debentures for cash which reduced the restricted payment
basket to approximately $2.5 million. Under the Parent Facility, common
dividends are permitted beginning January 1, 2003. Dividends on the Trust
Preferred may not be paid unless certain ratio requirements are met. The Parent
Facility provides for a restricted payment basket of $20.0 million plus 50% of
net income (excluding Great Lakes and IPF) plus 66 2/3% of distributions,
dividends or payments of debt from or proceeds from sales of equity interests of
Great Lakes and IPF plus 66 2/3% of net cash proceeds from common stock
issuances. The Company estimates that $23.0 million was available under the
Parent Facility's restricted payment basket on June 30, 2002.

(7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

The Company's financial instruments include cash and equivalents,
receivables, payables, debt and commodity and interest rate hedges. The book
value of cash and equivalents, receivables and payables is considered
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
through the use of swaps. Gains and losses on interest rate swaps are included
as an adjustment to interest expense in the relevant periods.

At June 30, 2002, the Company had hedging contracts covering 52.7 Bcf
of gas at prices averaging $3.97 per mcf and 1.2 million barrels of oil
averaging $23.25 per barrel. Their fair value, represented by the estimated
amount that would be realized upon termination, based on contract prices versus
the New York Mercantile

17

Exchange ("NYMEX") price on June 30, 2002, was a net unrealized pre-tax gain of
$6.8 million. The 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, which is closing prices on
the NYMEX. Transaction gains and losses on settled contracts are determined
monthly and are included as increases or decreases to oil and gas revenues in
the period the hedged production is sold. Oil and gas revenues were decreased by
$5.3 million and increased by $3.6 million due to hedging in the quarters ended
June 30, 2001 and 2002 and decreased by $28.7 million and increased by $15.4
million for the six months then ended, respectively.

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

(1) Fair value based on quotes received from certain brokerage houses.
Quotes were 99.5% for the 8.75% Notes, 84% for the 6% Debentures and
57.2% for the 5.75% Trust Preferred.

18

The following schedule shows the effect of closed oil and gas hedges
since January 1, 2001 and the value of open contracts at June 30, 2002 (in
thousands):

19

Interest rate swaps are accounted for on the accrual basis with income
or expense being recorded as an adjustment to interest expense in the period
covered. For the quarter and the six months ended June 30, 2002, the related
losses were insignificant. Neither the Parent Company nor IPF had interest rate
swaps in effect. However, Great Lakes had nine interest rate swap agreements
totaling $100.0 million, of which 50% is consolidated at Range. Two agreements
totaling $45.0 million at LIBOR rates of 7.1% expire in May 2004. Two agreements
totaling $20.0 million at 6.2% expire in December 2002. Five agreements totaling
$35.0 million at rates averaging 4.63% expire in June of 2003. Since January 1,
2001, the total loss of interest rate hedges at Great Lakes, net to Range has
been $2.2 million. The fair value of these swaps at June 30, 2002 approximated a
net loss of $4.7 million of which 50% is consolidated at Range.

The combined fair value of gains on oil and gas hedges and net losses
on interest rate swaps totaled $4.4 million and appear as short-term and
long-term Unrealized hedging gains and short-term and long-term Unrealized
hedging losses on the balance sheet. Hedging activities are conducted with major
financial or commodities trading institutions which management believes are
acceptable credit risks. At times, such risks may be concentrated with certain
counterparties. The creditworthiness of these counterparties is subject to
continuing review.

(8) COMMITMENTS AND CONTINGENCIES

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

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

20

(9) STOCKHOLDERS' EQUITY

The Company has authorized capital stock of 110 million shares which
includes 100 million of common stock and 10 million 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. Stockholders Equity was $229.5 million at June 30,
2002.

The following is a schedule of changes in the number of outstanding
common shares since the beginning of 2001:

Supplemental disclosures of non-cash investing and financing activities

21

(10) STOCK OPTION AND PURCHASE PLANS

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

In 1999, shareholders approved a stock option plan (the "1999 Plan")
authorizing the issuance of up to 1.4 million options. In 2001, shareholders
approved an increase in the number of options issuable to 3.4 million. The
Company submitted a proposal to shareholders, which was approved at the annual
meeting of shareholders in May 2002, increasing the number of options issuable
to 6.0 million. All options issued under the 1999 Plan from August 5, 1999
through May 22, 2002 vest 25% per year beginning after one year and have a
maximum term of 10 years. Options issued under the 1999 Plan after May 23, 2002
vest 30%/30%/40% over a three year period and have a maximum term of 5 years.
During the six months ended June 30, 2002, 1,428,850 options were granted under
the 1999 Plan at exercise prices of $4.43, $5.19 and $5.49 a share to eligible
employees, including 250,000 and 175,000 options granted to the Chairman and the
President, respectively. At June 30, 2002, 2.6 million options were outstanding
under the 1999 Plan at exercise prices of $1.94 to $6.67.

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 options 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 reelection at the Annual Meeting.
At June 30, 2002, 168,000 options were outstanding under the Directors' Plan at
exercise prices of $2.81 to $6.00.

The Company maintains the 1989 Stock Option Plan (the "1989 Plan")
which authorizes the issuance of up to 3.0 million options. No options have been
granted under this plan since March 1999. Options issued under the 1989 Plan
vest 30% after a year, 60% after two years and 100% after three years and expire
in 5 years. At June 30, 2002, 471,505 options remained outstanding under the
1989 Plan at exercise prices of $2.63 to $7.63 a share.

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 the Plan since the acquisition. At June 30,
2002, 131,702, all of which were vested, options remained outstanding under the
Plan at an exercise price of $3.46 a share.

22

In total, 3.3 million options were outstanding at June 30, 2002 at
exercise prices of $1.94 to $7.62 a share 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. Under the Stock Purchase Plan, the right to
purchase shares at prices ranging from 50% to 85% of market value may be
granted. Acquired shares are subject to a one year holding requirement. To date,
all purchase rights have been granted at 75% of market. Those individuals
receiving stock under the Stock Purchase Plan have additional compensation for
the difference between 75% and 85% of market value. This was valued at $50,000
for the first six months of 2002. In May 2001, shareholders approved an increase
in the number of shares authorized under the Stock Purchase Plan to 1,750,000.
Through June 30, 2002, 1,213,819 shares have been sold under the Stock Purchase
Plan for $5.1 million. At June 30, 2002, rights to purchase 110,500 shares were
outstanding.

(11) BENEFIT PLAN

The Company maintains a 401(k) Plan which permits employees to
contribute up to 50% of their salary (subject to Internal Revenue limitations)
on a pre-tax 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 December 2000 and 2001, the Company contributed $483,000 and
$554,000, at then market value, respectively, of the Company's common stock to
the 401(k) Plan. Employees have a variety of investment options in the 401(k)
Plan. The Company does not require that employees hold the contributed stock in
their account and are encouraged to diversify out of Company stock based on
their personal investment strategies.

23

(12) INCOME TAXES

The Company follows SFAS 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. The significant components of deferred tax liabilities
and assets were as follows (in thousands):

A deferred tax liability of $6.8 million was recorded on the balance
sheet at December 31, 2001. At March 31, 2002, the Company had generated a
deferred tax asset of $4.9 million which was expected to be used in the course
of the year. As of June 30, 2002, the deferred tax asset had been reduced to
$4.6 million. During the three and six months ended June 30, 2002, the Company
recorded a deferred tax benefit in the income statement of $0.7 million and $3.7
million, respectively. The deferred tax benefit included $3.9 million and $3.4
million which was reclassified from other comprehensive income during the first
and second quarters of 2002. The Company estimates an additional $2.6 million
deferred tax benefit will be reclassified from other comprehensive income to
income in the third quarter.

At December 31, 2001, the Company had regular net operating loss (NOL)
carryovers of $174.3 million and alternative minimum tax ("AMT") NOL carryovers
of $155.9 million that expire between 2012 and 2020. Regular NOL's generally
offset taxable income. To the extent that AMT NOL's offset AMT Income, no
alternative minimum tax payment is due. NOL's generated prior to a change of
control are subject to limitations. The Company experienced several changes of
control between 1994 and 1998. Consequently, the use of $34.1 million of NOL's
is limited to $10.2 million per year. No such annual limitation exists on the
remaining NOL's. At December 31, 2001, the Company had a statutory depletion
carryover of $6.6 million and an AMT credit carryover of $660,000 which are not
subject to limitation or expiration.

24

(13) EARNINGS PER SHARE

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

During the three months ended June 30, 2001 and 2002, 233,000 and
242,000 stock options were included in the computation of diluted earnings per
share and for the six months then ended, 238,000 and 266,000 stock options were
included in such computation. Remaining stock options, the 6% Debentures, the
Trust Preferred and the $2.03 Preferred were not included because their
inclusion would have been antidilutive.

The Company has and will continue to consider exchanging common stock
or equity-linked securities for debt. 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.

The Company's financial statements for the last three years are
currently being reaudited. As in the case of the Great Lakes restatement,
adjustments to prior periods would generally have an impact on current and
future financial statements due to adjustments to depreciation, depletion and
amortization, deferred tax accounting, stockholders' equity or other accounts.
Any such adjustments will be fully disclosed upon completion of the reaudits.

(14) MAJOR CUSTOMERS

The Company markets its production on a competitive basis. Gas is sold
under various types of contracts ranging from life-of-the-well to short-term
contracts that are cancelable within 30 days. Oil purchasers may be changed on
30 days notice. The price for oil is generally equal to a posted price set by
major purchasers in the area. The Company sells to oil purchasers on the basis
of price and service. For the six months ended June 30, 2002, two customers,
Duke Energy Trading and Marketing and Petrocom Energy Group, LTD, accounted for
10%

25

and 11%, respectively, or more of oil and gas revenues. Management believes that
the loss of any one customer would not have a material long-term adverse effect
on the Company.

Between late 1999 and June 30, 2001, Great Lakes sold approximately 90%
of its gas production to FirstEnergy, at prices based on the close of NYMEX
contracts each month plus a basis differential. In mid-2001, Great Lakes began
selling its gas to various purchasers including FirstEnergy. Over the next
twelve months, Great Lakes expects to sell approximately a third of its gas to
FirstEnergy. At December 31, 2001, 91% of Great Lakes gas was being sold at
prices based on the close of NYMEX contracts each month plus a basis
differential. The remainder is sold at a fixed price.

(15) 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 $5,879 and $7,443 of exploration costs expensed in 2001 and
the six months ended June 30, 2002, respectively.

(b) Includes $3,792 and $75 for oil and gas reserves, the remainder
represents acreage purchases in 2001 and the six months ended June 30,
2002, respectively.

26

(16) 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 financial statements
as of or for the six months ended June 30, 2002 (in thousands):

(17) EXTRAORDINARY ITEM

During the second quarter of 2001, 571,000 shares of common stock were
exchanged for $2.6 million of 6% Debentures, and $2.3 million of Trust
Preferred. In addition, $25.0 million face amount of 8.75% Notes were
repurchased. An extraordinary gain of $1.6 million was recorded because the
securities were acquired at a discount. In addition, 1,800 shares of common
stock were exchanged for $12,500 of $2.03 Preferred. In the second quarter of
2002, 919,000 shares of common stock were exchanged for $5.6 million of 6%
Debentures and $5.0 million of 8.75% Notes were repurchased for cash. An
extraordinary gain of $845,000 was recorded because the securities were acquired
at a discount.

27

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY

CRITICAL ACCOUNTING POLICIES

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 accepted
in the United States. The preparation of these financial statements requires the
Company to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses. The Company analyzes its estimates,
including those related to oil and gas revenues, bad debts, oil and gas
properties, marketable securities, income taxes and contingencies litigation.
The Company bases its estimates on historical experience and various other
assumptions that are believed to be reasonable under the circumstances. Actual
results may differ from these estimates under different assumptions or
conditions. The Company believes the following critical accounting policies
affect its more significant judgments and estimates used in the preparation of
its consolidated financial statements. The Company recognized revenues from the
sales of products and services in the period delivered. Revenues at IPF are
recognized as received. We provide an allowance for doubtful accounts against
specific receivables we judge unlikely to be collected in full. At IPF, all
receivables are evaluated quarterly and provisions for uncollectible amounts are
established. Oil and gas properties are accounted for under the successful
efforts method of accounting and are periodically evaluated for possible
impairment. The Company records a write down of marketable securities when the
decline in market value is considered to be other than temporary. Impairments
are recorded when management believes that a property's net book value is not
fully recoverable based on current estimates of expected future cash flows. Upon
completion of the reaudits, there could be changes in certain policies and
estimates. (See Note 1 to the Consolidated Financial Statements.)

LIQUIDITY AND CAPITAL RESOURCES

During the six months ended June 30, 2002, the Company spent $36.9
million on development, exploration and acquisitions. During the period, debt
and Trust Preferred were reduced by $18.9 million. At June 30, 2002, the Company
had $4.1 million in cash, total assets of $640.9 million and, including the
Trust Preferred as debt, a debt to capitalization (including debt, deferred
taxes and stockholders' equity) ratio of 62%. Excluding the Trust Preferred as
debt, the debt to Capitalization ratio was 55%. Available borrowing capacity on
the Company's bank lines at June 30, 2002 was $39.5 million at the parent, a net
$31.0 million at Great Lakes and $3.5 million at IPF. Long-term debt at June 30,
2002 totaled $373.3 million. This included $98.3 million of parent bank
borrowings, a net $68.5 million at Great Lakes, $23.5 million at IPF, $73.3
million of 8.75% Notes, $22.4 million of 6% Debentures and $87.3 million of
Trust Preferred.

During the six months ended June 30, 2002, 1.6 million shares of common
stock were exchanged for $7.1 million of 6% Debentures, $2.4 million of Trust
Preferred and $875,000 of 8.75% Notes. In addition, $15,000 face amount of 6%
Debentures and $5.0 million face amount of 8.75% Notes were repurchased for
cash. A $2.0 million extraordinary gain was recorded as the securities were
acquired at a discount. Subsequent to June 30, 2002, the Company repurchased
$500,000 face amount of the 6% Debentures and $3.0 million of 8.75% Notes.

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

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
70%, 55%, 30% and 5% of anticipated production from proved reserves on an mcfe
basis for the remainder of 2002, 2003, 2004 and 2005, respectively. The $38.6
million of capital expenditures (which included

28

$6.0 million for abandonment) in the six months ended June 30, 2002 was funded
with internal cash flow. Net cash provided by operations for the six months
ended June 30, 2001 and 2002 was $63.8 million and $46.1 million, respectively.
Cash flow from operations decreased from the prior year with lower prices and
higher exploration expense being somewhat offset by lower direct operating and
interest expense. Net cash used in investing for the six months ended June 30,
2001 and 2002 was $25.4 million and $37.1 million, respectively. The 2001 period
included $33.3 million of additions to oil and gas properties partially offset
by $6.9 million of IPF receipts (net of fundings) and $1.0 million in asset
sales. The 2002 period included $38.6 million of additions to oil and gas
properties partially offset by $1.5 million of IPF receipts (net of fundings).
Net cash used in (provided by) financing for the six months ended June 30, 2001
and 2002 was $38.0 million and $8.2 million, respectively. During the first six
months of 2002, total debt (including Trust Preferred) declined $18.9 million.
Parent bank debt increased which was more than offset by decreases in
non-recourse bank debt of $6.8 million, Subordinated Notes (8.75% Notes and 6%
Debentures) of $13.0 million and the Trust Preferred of $2.4 million. The net
reduction in debt was the result of exchanges of common stock and the use of
excess cash flow to reduce debt.

Capital Requirements

During the six months ended June 30, 2002, the $38.6 million of capital
expenditures was funded with internal cash flow. The Company seeks to entirely
fund its capital budget with internal cash flow. Based on the 2002 capital
budget of $100.0 million, the Company sought to increase production and expand
the reserve base. Due to certain production interruptions experienced in the
first quarter of this year, production during the year may not increase.
However, the Company believes production will grow on a quarterly basis by
year-end. The Company currently anticipates the capital expenditure program will
be entirely funded with internal cash flow in 2002.

Banking

The Company maintains three separate revolving bank credit facilities:
a $225.0 million facility at the Parent; a $100.0 million facility at IPF and a
$275.0 million facility at Great Lakes. Each facility is secured by
substantially all the borrowers' assets. The IPF and Great Lakes facilities are
non-recourse to Range. As Great Lakes is 50% owned, half 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 the future cash flows. Redeterminations,
other than increases, require approval of 75% of the lenders, increases require
unanimous approval.

At July 26, 2002, the Parent had a $141.0 million borrowing base of
which $39.5 million was available. IPF had a $27.0 million borrowing base, of
which $3.5 million was available. Great Lakes, half of which is consolidated at
Range, had a $205.0 million borrowing base, of which $62.0 million was
available.

Hedging
Oil and Gas Prices

The Company regularly enters into hedging agreements to reduce the
impact of fluctuations in oil and gas prices. The Company's current policy, when
futures prices justify, is to hedge 50% to 75% of anticipated production from
existing proved reserves on a rolling 12 to 18 month basis. At June 30, 2002,
hedges were in place covering 52.7 Bcf of gas at prices averaging $3.97 per
Mmbtu and 1.2 million barrels of oil at prices averaging $23.25 per barrel.
Their fair value at June 30, 2002 (the estimated amount that would be realized
on termination based on contract versus NYMEX prices) was a net unrealized
pre-tax gain of $6.8 million. The contracts expire monthly and cover
approximately 70%, 55%, 30% and 5% of anticipated production from proved
reserves on an mcfe basis for the remainder of 2002, 2003, 2004 and 2005,
respectively. Gains or losses on open and closed hedging transactions are
determined as the difference between contract price and a reference price,
generally closing prices on the NYMEX. 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. An ineffective portion (changes in contract
prices that do not match changes in the hedge price) of open hedge contracts is
recognized in earnings as it occurs. Net decreases to oil and gas revenues from
hedging for the six months ended June 30, 2001 were

29

$28.7 million and oil and gas revenues were increased by $15.4 million from
hedging for the six months ended June 30, 2002.

Interest Rates

At June 30, 2002, Range had $373.3 million of debt (including Trust
Preferred) outstanding. Of this amount, $183.0 million bore interest at fixed
rates averaging 7.0%. Senior debt and non-recourse debt totaling $190.3 million
bore interest at floating rates which averaged 3.7% at that date. At times, the
Company enters into interest rate swap agreements to limit the impact of
interest rate fluctuations on its floating rate debt. At June 30, 2002, Great
Lakes had interest rate swap agreements totaling $100.0 million, 50% of which is
consolidated at Range. Two agreements totaling $45.0 million at rates of 7.1%
expire in May 2004, two agreements totaling $20.0 million at 6.2% expire in
December 2002, and five agreements totaling $35.0 million at rates averaging
4.65% expire in June 2003. The values of these swaps are marked to market
quarterly. The fair value of the swaps, based on then current quotes for
equivalent agreements at June 30, 2002, was a net loss of $4.7 million, of which
50% is consolidated at Range. The 30-day LIBOR rate on June 30, 2002 was 1.8%. A
1% increase or decrease in short-term interest rates would cost or save the
Company approximately $1.4 million in annual interest expense.

Capital Restructuring Program

As described in Note 2 to the Consolidated Financial Statements, the
Company took a number of steps beginning in 1998 to strengthen its financial
position. These steps included asset sales and the exchange of common stock for
fixed income securities. These initiatives have helped reduce parent company
bank debt from $365.2 million to $98.3 million and total debt (including Trust
Preferred) from $727.2 million to $373.3 million at June 30, 2002. While the
Company's financial position has stabilized, management believes debt remains
too high. To return to its historical posture of consistent profitability and
growth, the Company believes it should further reduce debt. Management currently
believes the Company has sufficient cash flow and liquidity to meet its
obligations for the next twelve months. However, a significant drop in oil and
gas prices or a reduction in production or reserves would reduce the Company's
ability to fund capital expenditures and meet its financial obligations.

INFLATION AND CHANGES IN PRICES

The Company's revenues, the value of its assets, its ability to obtain
bank loans or additional capital on attractive terms have been and will continue
to be affected by changes in oil and gas prices. Oil and gas prices are subject
to significant fluctuations that are beyond the Company's ability to control or
predict. During the first six months of 2002, the Company received an average of
$22.46 per barrel of oil and $3.42 per mcf of gas after hedging compared to
$26.12 per barrel of oil and $4.04 per mcf of gas in the same period of the
prior year. Although certain of the Company's costs and expenses are affected by
the general inflation, such inflation does not normally have a significant
effect on the Company. However, industry specific inflationary pressure built up
in late 2000 and 2001 due to favorable conditions in the industry. While product
prices declined in late 2001 and the first quarter of 2002, the cost of services
in the industry have not declined by the same percentage. Increases in product
prices could cause industry specific inflationary pressures to again increase.

30

RESULTS OF OPERATIONS

The following table identifies certain items in the results of
operations and is presented to assist in comparison of the second quarter and
six month period of 2002 to the same periods of the prior year. The table should
be read in conjunction with the following discussions of results of operations
(in thousands):

Comparison of 2002 to 2001

The Company's financial statements for the last three years are
currently being reaudited. As in the case of the Great Lakes restatement,
adjustments to prior periods would generally have an impact on current and
future financial statements due to adjustments to depreciation, depletion and
amortization, deferred tax accounting, stockholders' equity or other accounts.
Any such adjustments will be fully disclosed upon completion of the reaudits.

Quarters Ended June 30, 2001 and 2002

Net income in the second quarter of 2002 totaled $8.5 million, compared
to $17.1 million in the prior year period. Gains on retirement of securities of
$1.6 million and $845,000 are included in the three months ended June 30, 2001
and 2002, respectively. Production declined to 150.7 Mmcfe per day, a 1%
decrease from the prior year period. The decline was due to lower production at
Matagorda Island 519 and other natural production declines in the Gulf Coast
area. Late in 2001, the operator of Matagorda Island 519 began a workover on the
L-4 well with the intent of adding production from a shallower formation. During
the workover, the well was damaged and attempts to bring it back have failed to
date. Revenues declined primarily due to a decrease in average prices per mcfe
to $3.55. The average prices received for oil decreased 12% to $22.27 per
barrel, 7% for gas to $3.59 per mcf and 47% for NGL's to $12.58 per barrel.
Production expenses decreased 15% to $9.9 million as a result of significantly
lower production taxes and workover costs in the Gulf of Mexico. Operating cost
(including production taxes) per mcfe produced averaged $0.72 in 2002 versus
$0.84 in 2001.

Transportation and processing revenues increased 29% to $924,000 with
significantly lower compressor rental expense and higher oil trading margins due
to lower oil inventories. IPF recorded a loss of $1.2 million, a decrease of
$2.7 million from the 2001 period. The 2001 period included a $406,000 favorable
valuation allowance adjustment and an $816,000 favorable increase to
receivables. The 2002 period includes a $1.4 million unfavorable valuation
allowance adjustment. IPF net also declined from the previous year due to lower
oil and gas prices and a smaller portfolio balance. During the quarter ended
June 30, 2002, IPF expenses included $476,000 of administrative costs and
$261,000 of interest, compared to prior year period administrative expenses of
$419,000 and interest of $393,000.

Exploration expense increased $809,000 to $2.2 million, primarily due
to additional seismic activity. General and administrative expenses increased
12% to $3.9 million in the quarter primarily due to higher accounting and
engineering technical consulting costs, information systems programming costs
and salary related expenses.

31

Interest and other income decreased from a positive $1.8 million in
2001 to a loss of $1.2 million. The 2001 period included $1.0 million of
ineffective hedging gains and $768,000 of gains on asset sales. The 2002 period
included $462,000 of ineffective hedging gains and a $851,000 write down of
marketable securities. Interest expense decreased 25% to $6.0 million as a
result of the lower outstanding debt and falling interest rates. Total debt was
$412.3 million and $373.3 million at June 30, 2001 and 2002, respectively. The
average interest rates were 6.6% and 5.3%, respectively, at June 30, 2001 and
2002 including fixed and variable rate debt.

Depletion, depreciation and amortization ("DD&A") decreased 4% from the
second quarter of 2001 primarily due to the effect of a provision for impairment
of proved properties taken at year-end 2001 and lower production. The per mcfe
DD&A rate for the second quarter of 2002 was $1.33, a $0.03 decrease from the
rate for the second quarter of 2001. The DD&A rate is determined based on
year-end reserves (which are evaluated based on a published ten-year price
forecast) and the net book value associated with them and, to a lesser extent,
deprecation on other assets owned. The Company currently expects its DD&A rate
for the remainder of 2002 to approximate $1.32 per mcfe. The high DD&A rate will
make it difficult for the Company to remain profitable if commodity prices fall
materially.

Six Month Periods Ended June 30, 2001 and 2002

Net income for the six months ended June 30, 2002 totaled $13.9 million
compared to $35.7 million for the comparable period of 2001. Gains on retirement
of securities of $2.0 million are included in each of the six months ended June
30, 2001 and 2002, respectively. Production for the six months declined to 149.9
Mmcfe per day, a 1% decrease from the prior year period. The decline was due to
lower production at Matagorda Island 519 and other natural production declines
in the Gulf Coast area. Revenues declined primarily due to a decrease in average
prices per Mcfe to $3.42. The average prices received for oil decreased 14% to
$22.46 per barrel, 15% for gas to $3.42 per mcf and 49% for NGL's to $11.79 per
barrel. Production expenses decreased 21% to $19.1 million as a result of lower
production taxes and workover costs in the Gulf of Mexico. Operating cost
(including production taxes) per mcfe produced averaged $0.71 in 2002 versus
$0.89 in 2001.

Transportation and processing revenues were the same as the prior year
at $1.7 million. IPF recorded a loss of $1.8 million, a decrease of $5.7 million
from the 2001 period, which included $1.9 million of favorable valuation
allowance adjustments and increases to receivables. The 2002 period includes
$2.5 million unfavorable valuation allowance adjustments. IPF net also declined
from the previous year due to lower oil and gas prices and a smaller portfolio
balance. During the six months ended June 30, 2002, IPF expenses included
$870,000 of administrative costs and $513,000 of interest, compared to prior
year period administrative expenses of $938,000 and interest of $1,084,000.

Exploration expense increased $5.0 million to $7.4 million, primarily
due to additional seismic activity and the first quarter $3.5 million dry hole
cost in East Texas. General and administrative expenses increased 7% to $7.4
million in the six months ended June 30, 2002 due to higher accounting and
engineering consulting costs, information systems programming costs and salary
related expenses.

Interest and other income decreased from a positive $3.3 million to a
loss of $3.2 million. The 2001 period included $3.3 million of ineffective
hedging gains, $1.1 million of gains on asset sales offset by a $1.3 million
write down of marketable securities. The 2002 period included $2.2 million of
ineffective hedging losses and a $1.2 million write down of marketable
securities. Interest expense decreased 31% to $11.8 million as a result of lower
outstanding debt and falling interest rates.

Depletion, depreciation and amortization decreased 5% from the six
month period of 2001 primarily due to the effect of a provision for impairment
of proved properties taken at year-end 2001 and lower production. The per mcfe
DD&A rate for the six months of 2002 was $1.31, a $0.05 decrease from the rate
for the same period of the prior year.

32

ITEM 3. 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. In the Company's case, the term "market
risk" refers primarily to the risk of loss arising from adverse changes in oil
and gas prices and interest rates. The disclosures are not meant to be
indicators of expected future losses, but rather indicators of reasonably
possible losses. This forward-looking information provides indicators of how
Range views and manages its ongoing market risk exposures. The Company's market
risk sensitive instruments were entered into for purposes other than trading.

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

The Company periodically enters into hedging arrangements with respect
to its oil and gas production. Pursuant to these swaps, Range receives a fixed
price for its production and pays market prices to the contract counterparty.
This hedging is intended to reduce the impact of oil and gas price fluctuations
on the Company's results and not to increase profits. Realized gains or 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 or
losses realized as a result of hedging are substantially offset in the cash
market when the commodity is delivered. Of the $6.8 million unrealized pre-tax
gain included in OCI at June 30, 2002, $7.6 million would be reclassified to
earnings over the next twelve month period if prices remained constant. The
actual amounts that will be reclassified will vary as a result of changes in
prices. Range does not hold or issue derivative instruments for trading
purposes.

As of June 30, 2002, oil and gas hedges were in place covering 52.7 Bcf
of gas and 1.2 million barrels of oil. Their fair value, represented by the
estimated amount that would be realized on termination based on contract versus
NYMEX prices, was a net unrealized pre-tax gain of $6.8 million at June 30,
2002. These contracts expire monthly through December 2005 and cover
approximately 70%, 55%, 30% and 5% of anticipated production from proved
reserves on an mcfe basis for the remainder of 2002, 2003, 2004 and 2005,
respectively. 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. Net realized losses
incurred relating to these swaps for the six months ended June 30, 2001 were
$28.7 million and net realized gains were $15.4 million for the six months ended
June 30, 2002.

In the first six months of 2002, a 10% reduction in oil and gas prices,
excluding amounts fixed through hedging transactions, would have reduced revenue
by $7.8 million. If oil and gas future prices at June 30, 2002 had declined 10%,
the unrealized hedging gain at that date would have increased $22.3 million.

Interest rate risk. At June 30, 2002, Range had $373.3 million of debt
(including Trust Preferred) outstanding. Of this amount, $183.0 million bore
interest at fixed rates averaging 7.0%. Senior debt and non-recourse debt
totaling $190.3 million bore interest at floating rates averaging 3.7%. At June
30, 2002, Great Lakes had nine interest rate swap agreements totaling $100.0
million (See Note 7), 50% of which is consolidated at Range, which had a fair
value loss (Range's share) of $2.4 million at that date. A 1% increase or
decrease in short-term interest rates would cost or save the Company
approximately $1.4 million in annual interest expense.

33

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

The Company is involved in various legal actions and claims arising in
the ordinary course of business. In the opinion of management, such litigation
and claims are likely to be resolved without material adverse effect on its
financial position or results of operations. In February 2000, a royalty owner
filed suit asking for class certification against Great Lakes and the Company in
New York federal district court, alleging that gas was sold to affiliates and
gas marketers at low prices and inappropriate post production expenses reduced
proceeds to the royalty owners and that the royalty owners' share of gas was
improperly accounted for. The action sought a proper accounting, an amount equal
to the difference in prices paid and the highest obtainable prices, punitive
damages and attorneys' fees. While the outcome is uncertain, the Company
believes the suit will be resolved without material adverse effect on its
financial position or result of operations.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.

(a) Not applicable

(b) Not applicable

(c) At various times during the quarter and six months ended June
30, 2002, the Company issued common stock in exchange for
fixed income securities. The shares of common stock issued in
such exchanges were exempt from registration under Section
3(a)(9) of the Securities Act of 1933. During the quarter and
the six months ended June 30, 2002, a total of $5.6 million
and $7.1 million face value of the 6% Debentures were retired
in exchange for 919,000 and 1.2 million shares of common
stock, $875,000 face value of $8.75 Notes was retired in
exchange for 175,000 shares of common stock, $2.4 million face
value of Trust Preferred were exchanged for 283,000 shares of
common stock.

(d) Not applicable.

34

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

On May 23, 2002, the Company held its Annual Meeting of Stockholders.
At such meeting Robert E. Aikman, Anthony Dub, V. Richard Eales, Thomas J.
Edelman, Allen Finkelson, Alexander P. Lynch and John H. Pinkerton were
reelected as Directors of the Company. Jonathan S. Linker was also elected as a
Director of the Company.

At the Annual Meeting, the shareholders approved the following:

1. An increase in the Common shares authorized for
issuance under the Company's Stock Option Plan to
6,000,000 shares.

35

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

(a) Exhibits:

3.1.1. Certificate of Incorporation of Lomak dated March 24, 1980
(incorporated by reference to the Company's Registration
Statement (No. 33-31558)).

3.1.2. Certificate of Amendment of Certificate of Incorporation dated
July 22, 1981 (incorporated by reference to the Company's
Registration Statement (No. 33-31558)).

3.1.3. Certificate of Amendment of Certificate of Incorporation dated
September 8, 1982 (incorporated by reference to the Company's
Registration Statement (No. 33-31558)).

3.1.4. Certificate of Amendment of Certificate of Incorporation dated
December 28, 1988 (incorporated by reference to the Company's
Registration Statement (No. 33-31558)).

3.1.5. Certificate of Amendment of Certificate of Incorporation dated
August 31, 1989 (incorporated by reference to the Company's
Registration Statement (No. 33-31558)).

3.1.6. Certificate of Amendment of Certificate of Incorporation dated
May 30, 1991 (incorporated by reference to the Company's
Registration Statement (No. 333-20259)).

3.1.7. Certificate of Amendment of Certificate of Incorporation dated
November 20, 1992 (incorporated by reference to the Company's
Registration Statement (No. 333-20257)).

3.1.8. Certificate of Amendment of Certificate of Incorporation dated
May 24, 1996 (incorporated by reference to the Company's
Registration Statement (No. 333-20257)).

3.1.9. Certificate of Amendment of Certificate of Incorporation dated
October 2, 1996 (incorporated by reference to the Company's
Registration Statement (No. 333-20257)).

3.1.10. Restated Certificate of Incorporation as required by Item 102
of Regulation S-T (incorporated by reference to the Company's
Registration Statement (No. 333-20257)).

3.1.11. Certificate of Amendment of Certificate of Incorporation dated
August 25, 1998 (incorporated by reference to the Company's
Registration Statement (No. 333-62439)).

3.1.12. Certificate of Amendment of Certificate of Incorporation dated
May 25, 2000 (incorporated by reference to the Company's Form
10-Q dated August 8, 2000).

3.2.1. By-Laws of the Company (incorporated by reference to the
Company's Registration Statement (No. 33-31558).

3.2.2 Amended and Restated By-laws of the Company dated May 24,
2001.

(b) Reports on Form 8-K

Form 8K/A dated July 17, 2002 (filed on July 17, 2002)
reporting under Item 4 - Changes in Registrant's Certifying
Accountant.

Form 8-K dated July 15, 2002 (filed on July 15, 2002)
reporting under Item 4 - Changes in Registrant's Certifying
Accountant.

36

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned.

RANGE RESOURCES CORPORATION

By: /s/ Eddie M. LeBlanc
------------------------------------
Eddie M. LeBlanc
Chief Financial Officer

July 26, 2002

37

EXHIBIT INDEX