SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
AMENDMENT NO. 1
(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.
1
Introductory Note - Restatement
This Quarterly Amendment No. 1 to Form 10-Q/A amends Item 1 and 2 of
our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, including
the consolidated financial statements therein, originally filed on August 14,
2002. As described in Note 2 to the consolidated financial statements, a
restatement has been made to correct previously reported financial results. This
amendment does not otherwise update the other information in the originally
filed form 10-Q to reflect events after the original filing date.
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/A. 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.
2
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
DECEMBER 31, JUNE 30,
2001 2002
------------- -----------
Unaudited
(Restated) (Restated)
ASSETS
Current assets
Cash and equivalents $ 3,380 $ 4,125
Accounts receivable 25,295 25,668
IPF receivables (Note 5) 7,000 7,747
Unrealized derivative hedging gain (Note 3) 37,165 7,643
Inventory and other 4,895 3,091
------------- -----------
77,735 48,274
------------- -----------
IPF receivables (Note 5) 34,402 29,609
Unrealized derivative hedging gain (Note 3) 14,936 568
Oil and gas properties, successful efforts (Note 16) 1,047,629 1,081,535
Accumulated depletion (514,272) (550,039)
------------- -----------
533,357 531,496
------------- -----------
Transportation and field assets (Note 3) 31,288 32,225
Accumulated depreciation (13,108) (14,694)
------------- -----------
18,180 17,531
------------- -----------
Other (Note 3) 3,852 12,744
------------- -----------
$ 682,462 $ 640,222
============= ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 27,202 $ 22,976
Accrued liabilities 15,036 14,531
Accrued interest 5,244 4,946
Unrealized derivative hedging loss (Note 3) 397 834
------------- -----------
47,879 43,287
------------- -----------
Senior debt (Note 6) 95,000 98,300
Non-recourse debt (Note 6) 98,801 92,000
Subordinated notes (Note 6) 108,690 95,691
Trust Preferred - mandatorily redeemable securities
of subsidiary(Note 6) 89,740 87,340
Deferred taxes (Note 13) 4,496 --
Unrealized derivative hedging loss (Note 3) 2,235 2,965
Commitments and contingencies (Note 8)
Stockholders' equity (Notes 9 and 10)
Preferred stock, $1 par, 10,000,000 shares authorized,
$2.03 Convertible Preferred, none issued or outstanding -- --
Common stock, $.01 par, 100,000,000 shares authorized,
52,643,275 and 54,757,976 issued and outstanding, respectively 526 548
Capital in excess of par value 378,426 388,907
Stock held by employee benefit trust,
1,038,242 and 1,316,185 shares, respectively (Note 11) (4,890) (6,176)
Retained earnings (deficit) (183,825) (172,174)
Deferred compensation expense (139) (111)
Other comprehensive income (Note 3) 45,523 9,645
------------- -----------
235,621 220,639
------------- -----------
$ 682,462 $ 640,222
============= ===========
SEE ACCOMPANYING NOTES.
3
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED, IN THOUSANDS EXCEPT PER SHARE DATA)
THREE MONTHS SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
---------------------- ----------------------
2001 2002 2001 2002
--------- --------- --------- ---------
(Restated) (Restated) (Restated) (Restated)
Revenues
Oil and gas sales $ 54,788 $ 48,626 $ 112,880 $ 92,909
Transportation and processing 720 924 1,701 1,698
IPF 1,101 992 3,651 2,163
Interest and other 1,836 (1,235) 3,318 (3,244)
--------- --------- --------- ---------
58,445 49,307 121,550 93,526
--------- --------- --------- ---------
Expenses
Direct operating 11,743 9,938 24,346 19,142
IPF (411) 2,178 (298) 3,950
Exploration 1,362 2,172 2,445 7,443
General and administrative 4,221 4,733 6,290 9,203
Interest expense and dividends on trust 7,864 6,274 17,671 11,631
preferred
Depletion, depreciation and amortization 18,359 19,304 36,168 37,404
--------- --------- --------- ---------
43,138 44,599 86,622 88,773
--------- --------- --------- ---------
Pretax income 15,307 4,708 34,928 4,753
Income taxes (Note 13)
Current (51) 45 (51) 45
Deferred -- (1,802) -- (4,913)
--------- --------- --------- ---------
(51) (1,757) (51) (4,868)
--------- --------- --------- ---------
Income before extraordinary item 15,358 6,465 34,979 9,621
Gain on retirement of debt securities (Note 18) 1,610 845 2,042 2,030
--------- --------- --------- ---------
Net income $ 16,968 $ 7,310 $ 37,021 $ 11,651
========= ========= ========= =========
Comprehensive income (loss) (Note 3) $ 66,323 $ (1,155) $ 55,897 $ (24,227)
========= ========= ========= =========
Earnings per share, basic and diluted (Note 14)
Before extraordinary item
Basic $ 0.31 $ 0.12 $ 0.72 $ 0.18
========= ========= ========= =========
Diluted $ 0.30 $ 0.12 $ 0.70 $ 0.18
========= ========= ========= =========
After extraordinary item
Basic $ 0.34 $ 0.14 $ 0.76 $ 0.22
========= ========= ========= =========
Diluted $ 0.33 $ 0.13 $ 0.74 $ 0.22
========= ========= ========= =========
SEE ACCOMPANYING NOTES.
4
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED, IN THOUSANDS)
SIX MONTHS ENDED JUNE 30,
------------------------------
2001 2002
------------- -------------
(Restated) (Restated)
CASH FLOWS FROM OPERATIONS
Net income $ 37,021 $ 11,651
Adjustments to reconcile net income to
net cash provided by operations:
Deferred income taxes -- (4,913)
Depletion, depreciation and amortization 36,168 37,404
Writedown of marketable securities 1,348 1,220
Unrealized hedging (gains) losses (2,672) 1,790
Adjustment to IPF receivables (2,320) 2,567
Non-cash compensation expense 548 2,435
Amortization of deferred offering costs 1,382 411
Gain on retirement of securities (1,948) (2,055)
Gain on sale of assets (1,066) (26)
Changes in working capital:
Accounts receivable (5,529) (3,511)
Inventory and other 690 556
Accounts payable 2,190 1,446
Accrued liabilities (2,764) (2,961)
------------- -------------
Net cash provided by operations 63,048 46,014
------------- -------------
CASH FLOWS FROM INVESTING
Oil and gas properties (32,595) (38,604)
IPF repayments (net of fundings) 6,862 1,534
Asset sales 1,031 20
------------- -------------
Net cash used in investing (24,702) (37,050)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
(Repayment)/borrowing of debt (39,208) (9,433)
Preferred dividends (8) --
Issuance of common stock 1,214 1,214
------------- -------------
Net cash used in financing (38,002) (8,219)
------------- -------------
Change in cash 344 745
Cash and equivalents, beginning of period 2,612 3,380
------------- -------------
Cash and equivalents, end of period $ 2,956 $ 4,125
============= =============
SEE ACCOMPANYING NOTES.
5
RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Range Resources Corporation ("Range") is engaged in the development,
acquisition and exploration of oil and gas properties primarily in the
Southwestern, Gulf Coast and Appalachian regions of the United States. The
Company also provides financing to 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"). The Company's
financial statements for the three years ended 2001 have been restated.
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.
(2) RESTATEMENT
In July 2002, the Company selected KPMG LLP is its new independent
auditor. The Company also chose 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, insure the Company's ongoing access to the capital markets and to
avoid any possible impediment to future transactions. As part of the auditor
selection process, KPMG performed its normal client acceptance procedures and
advised the Company that it believed 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. Specifically the gain recognized in
September 1999 should be reduced from $39.8 million to $30.9 million and income
in subsequent periods should increase as a result of lower depletion expense.
As a result of the actual reaudit, a series of additional issues came
to light which required restatement of the Company's previously reported
operating results and financial condition. These issues and their impact on
pretax income is outlined below.
In 1998, the Company acquired Domain Energy. In recording the
transaction, the purchase price was not appropriately allocated to the
individual oil and gas properties, causing a subsequent purchase price
adjustment to be miscalculated. As a result, impairments recognized at year-end
2001 were reduced. In addition, properties in Appalachia and Michigan, that had
been combined into accounting pools for the purpose of calculating depletion,
were subdivided into smaller pools and the depreciation rates historically
applied on non-oil and gas assets were reduced. As a result of these changes,
pretax income decreased $7.1 million in 1999, increased $4.8 million in 2000,
increased $7.6 million in 2001 and decreased $2.9 million in the first six
months of 2002.
The Company maintains a deferred compensation plan (the "Plan"), under
which eligible employees can defer all or a portion of their cash compensation
and invest those amounts in a variety of investment options (including Company
common stock) which are placed in a rabbi trust (the "Trust"). Eligible
employees can also place common stock awards in the Trust. Pursuant to a
consensus of the Emerging Issues Task Force, assets and
6
liabilities of the Trust must be consolidated on the Company's balance sheet.
While the Trust's assets and liabilities are of identical value, Company common
stock held in the Trust is treated as if it were treasury stock (it is deducted
from outstanding shares as shares held by an employee benefit plan).
Furthermore, because the Plan allows participants to diversify their
investments, the liability to Plan participants must be revalued on the balance
sheet each accounting period at the assets' then-quoted market prices and
increases or decreases between accounting periods reflected on the statement of
operations as increases or decreases in compensation expense. Historically, the
Company did not consolidate the Trust in its consolidated financial statements
nor added or subtracted changes in the market value of the Plan's assets on its
statement of operations. However, all material information about the Plan has
historically been disclosed in footnotes to the financial statements and in
proxy statements. In addition, the Company offers designated employees the
ability to purchase shares at a discount under a shareholder-approved Stock
Purchase Plan or to receive bonuses or a portion of their base pay in restricted
common stock issued at a discount from quoted market prices. Previously, such
shares had always been accounted for based on the Company's estimate of the fair
value of the stock granted or purchased. In the restated financial statements,
stock purchased through the Plan or granted to employees was expensed based on
the quoted market value without regard to the Company's estimate of fair value.
The difference between previously reported values and market value will be
included as additional compensation expense on the restated statement of
operations. As a result of these changes, pretax income decreased $561,000 in
1999, decreased $3.8 million in 2000, increased $1.7 million in 2001 and
decreased $1.8 million in the first six months of 2002.
At June 30, 2002, the Company corrected a series of unreconciled
balance sheet accounts that had a net minimal statement of operations impact.
These balance sheet general ledger accounts were not supported by the underlying
subsidiary ledger detail when the Company's accounting department moved from
Ohio to Fort Worth. In the restatement, these corrections were reflected in the
periods in which they applied, rather than in the second quarter of 2002. As a
result, pretax income for periods prior to 1999 increased by $1.9 million,
increased by $627,000 in 1999, decreased $2.9 million in 2000, increased by
$190,000 in 2001 and increased by $134,000 in the first six months of 2002.
Finally, certain of GLEP's interest rate swaps had early cancellation
provisions but had been accounted for as cash flow hedges. Upon further review,
the swaps did not meet the documentation and effectiveness provisions of SFAS
133, requiring changes in fair value to be reported as interest expense on the
restated financial statements as opposed to changes in Other Comprehensive
Income. As a result, pretax income decreased $1.4 million in 2001 and will
increase by a corresponding amount in future periods. Additionally, the
ineffective portion of certain commodity hedges increased income $71,000 in
2001.
In total, all of the current changes (including the previously
announced change in the gain on the Great Lakes' transaction) increased net loss
by $15.7 million in 1999, decreased net income by $1.4 million in 2000 and
increased net income by $8.7 million in 2001. The changes decreased net income
by $2.3 million in the first half of 2002 but are projected to increase net
income by approximately $3.9 million in the second half of 2002.
7
PREVIOUSLY
2001 REPORTED RESTATED
---- ----------- -----------
Oil and gas sales $ 209,537 $ 208,854
Direct operating 44,504 43,430
General and administrative 13,511 12,212
Interest 30,689 32,179
Depletion, depreciation and amortization 77,825 77,573
Provision for impairment 38,945 31,085
Pretax income 4,994 13,306
Current income taxes (51) (406)
Income before extraordinary item 5,045 13,712
Net income 8,996 17,663
Earnings per share before extraordinary gain
Basic 0.11 0.28
Diluted 0.11 0.28
Earnings per share after extraordinary gain
Basic 0.19 0.36
Diluted 0.19 0.36
Cash and equivalents 3,253 3,380
Accounts receivable 27,495 25,295
Inventory and other 4,084 4,895
Unrealized derivative hedging gain - current 36,768 37,165
Unrealized derivative hedging gain - noncurrent 12,701 14,936
Oil and gas properties 1,057,881 1,047,629
Accumulated depletion (512,786) (514,272)
Accumulated depreciation (13,576) (13,108)
Other 3,055 3,852
Accounts payable 26,944 27,202
Accrued liabilities 9,947 15,036
Accrued interest 7,105 5,244
Unrealized derivative hedging loss - current -- 397
Unrealized derivative hedging loss - noncurrent -- 2,235
Deferred taxes 9,651 4,496
Stock held by employee benefit trust -- (4,890)
Capital in excess of par value 376,357 378,426
Retained earnings (deficit) (169,237) (183,825)
Other comprehensive income 38,041 45,523
Deferred compensation expense -- (139)
Stockholders' equity 245,687 235,621
Cash flows -
Net cash provided by operations 130,309 129,598
Net cash used in investing (78,900) (78,189)
8
PREVIOUSLY
1ST QUARTER 2001 REPORTED RESTATED
---------------- ----------- --------
General and administrative $ 3,470 $ 2,069
Interest expense 9,117 9,807
D,D&A expense 16,639 17,809
Pretax income 18,080 19,621
Net income 18,512 20,053
Earnings per share before extraordinary gain
Basic 0.37 0.41
Diluted 0.37 0.40
Earnings per share after extraordinary gain
Basic 0.38 0.42
Diluted 0.38 0.41
Cash and equivalents 1,524 1,651
Inventory and other 3,977 4,748
Oil and gas properties 1,029,022 1,010,538
Accumulated depletion (460,342) (460,407)
Accounts payable 21,939 22,728
Accrued liabilities 16,270 22,039
Stock held by employee benefit trust -- 5,010
Capital in excess of par value 366,573 368,325
Retained earnings (deficit) (159,714) (181,427)
Other comprehensive income (32,027) (31,118)
Deferred compensation expense -- (147)
Stockholders' equity 175,345 151,116
Cash flows -
Net cash provided by operations 33,294 32,583
Net cash used in investing (6,520) (5,809)
1ST QUARTER 2002
----------------
General and administrative 3,576 4,733
Interest expense 5,817 5,357
D,D&A expense 17,439 18,100
Pretax income 1,140 45
Deferred tax expense (2,186) (3,111)
Net income 4,511 4,341
Cash and equivalents 557 684
Accounts receivable, net 27,181 26,493
Inventory and other 3,348 4,580
Oil and gas properties 1,073,682 1,063,558
Accumulated depletion (529,359) (531,701)
Accumulated depreciation (14,401) (13,865)
Other 5,004 11,102
Accounts payable 21,171 21,429
Accrued liabilities 8,419 14,571
Stock held by employee benefit trust -- (5,420)
Capital in excess of par value 380,437 382,643
Retained earnings (deficit) (164,726) (179,483)
Deferred compensation expense -- (164)
Other comprehensive income 11,546 18,110
Stockholders' equity 227,792 216,221
9
PREVIOUSLY
2ND QUARTER 2001 REPORTED RESTATED
---------------- ----------- -----------
General and administrative $ 3,455 $ 4,221
Interest expense 7,978 7,864
D,D&A expense 18,998 18,359
Pretax income 15,322 15,307
Income from extraordinary item 13,845 15,358
Net income 14,740 16,968
Earnings per share - basic 0.33 0.34
Earnings per share - diluted 0.33 0.33
Cash and equivalents 2,829 2,956
Inventory and other 3,759 4,793
Oil and gas properties 1,045,871 1,027,506
Accumulated depletion (477,864) (477,409)
Accounts payable 23,382 24,171
Accrued liabilities 13,636 20,057
Stock held by employee benefit trust -- (4,898)
Capital in excess of par value 370,833 372,813
Retained earnings (deficit) (144,979) (164,465)
Other comprehensive income 17,406 18,237
Deferred compensation expense -- (144)
Stockholders' equity 243,781 222,064
Cash flows -
Net cash provided by operations 63,759 63,048
Net cash used in investing (25,413) (24,702)
2ND QUARTER 2002
----------------
General and administrative 3,863 4,470
Interest expense 5,974 6,274
D,D&A expense 18,329 19,304
Pretax income 6,853 4,708
Income before extraordinary item 6,476 6,465
Deferred tax expense 332 (1,802)
Net income 7,321 7,310
Earnings per share - basic 0.15 0.14
Earnings per share - diluted 0.15 0.13
Inventory and other 2,018 3,091
Unrealized derivative hedging gain - current 6,809 7,643
Unrealized derivative hedging gain - noncurrent -- 568
Oil and gas properties 1,091,532 1,081,535
Accumulation depletion (546,528) (550,039)
Accumulation depreciation (15,298) (14,694)
Other 6,455 12,744
Accrued liabilities 6,398 14,531
Unrealized derivative hedging loss - current -- 834
Unrealized derivative hedging loss - noncurrent 2,937 2,965
Stock held by employee benefit trust -- (6,176)
Capital in excess of par value 386,375 388,907
Retained earnings (deficit) (157,405) (172,174)
Deferred compensation expense -- (111)
Other comprehensive income 4,797 9,645
Stockholders' equity 234,315 220,639
Cash flows -
Net cash provided by operations 46,141 46,014
10
(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 have been restated.
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. The Company's
receivables are concentrated in the oil and gas industry. 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 $2.9 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.
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 based on the Company's valuation of its royalty interest in the oil
and gas properties. At June 30, 2002, IPF's valuation allowance totaled $19.8
million. 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 favorable oil
and gas prices in early 2001, certain of IPF's receivables began to generate
cash flows which favorably impacted the valuation of the receivable. As a
result, $816,000 and $1.9 million increases in receivables were recorded as
reduction to expense 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
income. 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 an increase to expense. 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
11
administrative costs, $261,000 of interest and the unfavorable $1.1 million
valuation allowance. 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 $1.32 and
$1.41 per mcfe in the quarters ended June 30, 2001 and 2002 and $1.32 and $1.38
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 $8.1 million
which is included in Other assets. This deferred tax asset was $8.3 million at
March 31, 2002. At December 31, 2001, the Company had a $4.5 million net tax
liability. At June 30, 2002, Other assets included $3.6 million unamortized debt
issuance costs, $8.1 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):
Three Months Ended Six Months Ended
June 30, June 30,
2001 2002 2001 2002
------------ ------------ ------------ ------------
Restated Restated Restated Restated
Net income $ 16,968 $ 7,310 $ 37,021 $ 11,651
Change in unrealized gains (losses),
net of taxes 49,355 (8,465) 18,876 (35,206)
Defaulted hedge contracts, net -- -- -- (672)
------------ ------------ ------------ ------------
Comprehensive income (loss) $ 66,323 $ (1,155) $ 55,897 $ (24,227)
============ ============ ============ ============
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.
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 certain 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 reclassified to earnings when the transaction
is consummated. Ineffective portions of such hedges are recognized
13
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 accounting requirements, 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
Operations 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 and losses of $4.4 million (net of $2.4 million losses on interest
rate swaps) and restated OCI of $9.6 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 and assumed liabilities 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. 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.
14
(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):
December 31, June 30,
2001 2002
------------- --------
SENIOR DEBT
Parent credit facility (3.6%) $ 95,000 $ 98,300
------------- --------
NON-RECOURSE DEBT
Great Lakes credit facility (3.6%) 75,001 68,500
IPF credit facility (4.0%) 23,800 23,500
------------- --------
98,801 92,000
------------- --------
SUBORDINATED DEBT
8.75% Senior Subordinated Notes due 2007 79,115 73,271
6% Convertible Subordinated Debentures due 2007 29,575 22,420
------------- --------
108,690 95,691
------------- --------
TOTAL DEBT 302,491 285,991
TRUST PREFERRED - MANDATORILY REDEEMABLE SECURITIES
OF WHOLLY-OWNED SUBSIDIARY 89,740 87,340
------------- --------
TOTAL $ 392,231 $373,331
============= ========
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. No interest expense was capitalized during the
three months or the six months ended June 30, 2001 and 2002, respectively.
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 7), the rate was 7.1% and 8.6% for the quarters and 9.4% and
6.7% 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
debt securities on the Consolidated Statements of Operations. 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 - MANDATORILY REDEEMABLE SECURITIES OF SUBSIDIARIES
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 in the
statement of operations, 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 $22.6 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 derivatives. 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):
December 31, 2001 June 30, 2002
---------------------------- ----------------------------
Book Fair Book Fair
Value Value Value Value
------------ ------------ ------------ ------------
Restated Restated Restated Restated
Assets
Cash and equivalents $ 3,380 $ 3,380 $ 4,125 $ 4,125
Marketable securities 2,323 2,323 1,074 1,074
Commodity swaps 52,100 52,100 6,767 6,767
------------ ------------ ------------ ------------
Total 57,803 57,803 11,966 11,966
------------ ------------ ------------ ------------
Liabilities
Interest rate swaps (2,631) (2,631) (2,355) (2,355)
Long-term debt(1) (302,491) (292,028) (285,991) (281,671)
Trust Preferred(1) (89,740) (50,254) (87,340) (49,976)
------------ ------------ ------------ ------------
Total (394,862) (344,913) (375,686) (334,002)
------------ ------------ ------------ ------------
Net financial instruments $ (337,059) $ (287,110) $ (363,720) $ (322,036)
============ ============ ============ ============
(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):
Quarter Hedging Gain/
Ended (Loss)
-------- ------------
Closed Contracts
2001
March 31 $ (23,440)
June 30 (5,250)
March 31 8,450
December 31 14,047
------------
Subtotal (6,193)
2002
March 31 11,727
June 30 3,638
------------
Subtotal 15,365
------------
Total closed $ 9,172
============
Open Contracts
2002
September 30 $ 3,719
December 31 2,886
------------
Subtotal 6,605
2003
March 31 731
June 30 119
September 30 457
December 31 (180)
------------
Subtotal 1,127
2004
March 30 (318)
June 30 (21)
September 30 (112)
December 31 (160)
------------
Subtotal (611)
2005
March 31 (146)
June 30 (77)
September 30 (63)
December 31 (68)
------------
Subtotal (354)
------------
Total open $ 6,767
============
Total gain $ 15,939
============
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. 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 derivative hedging gains and short-term and long-term
Unrealized derivative 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 $220.6 million at June 30,
2002.
The following is a schedule of changes in the number of outstanding
common shares since the beginning of 2001:
Six Months
Ended
2001 June 30, 2002
----------- -------------
Beginning Balance 49,187,682 52,643,275
Issuance
Employee benefit plans 372,398 294,828
Stock options exercised 223,594 95,764
Stock purchase plan 263,000 92,500
Exchanges for
6% Debentures 758,597 1,165,700
Trust Preferred 291,211 283,200
$2.03 Preferred 766,889 --
8.75% Notes 779,960 182,709
Other (56) --
----------- -------------
3,455,593 2,114,701
----------- -------------
Ending Balance 52,643,275 54,757,976
=========== =============
Supplemental disclosures of non-cash investing and financing activities
Six months Ended
June 30,
------------------------
2001 2002
---------- ----------
(in thousands)
Restated Restated
Common stock issued
Under benefit plans $ 818 $ 732
Exchanged for fixed income securities $ 9,380 $ 8,359
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:
Inactive Active
------------------------ ----------------------
Domain 1989 Directors' 1999
Plan Plan Plan Plan Total
---------- ---------- ---------- ---------- ----------
Outstanding on December 31, 2001 137,484 542,700 120,000 1,315,113 2,115,297
Granted -- -- 48,000 1,428,850 1,476,850
Exercised (5,782) (40,857) -- (49,125) (95,764)
Expired -- (30,338) -- (124,263) (154,601)
---------- ---------- ---------- ---------- ----------
(5,782) (71,195) 48,000 1,255,462 1,226,485
---------- ---------- ---------- ---------- ----------
Outstanding on June 30, 2002 131,702 471,505 168,000 2,570,575 3,341,782
========== ========== ========== ========== ==========
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 22, 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:
Inactive Active
--------------------- ----------------------
Range of Average Domain 1989 Directors' 1999
Exercise Prices Exercise Price Plan Plan Plan Plan Total
--------------- -------------- -------- --------- ---------- --------- -----------
$ 1.94 - $ 4.99 $ 3.34 131,702 326,405 64,000 1,155,825 1,677,932
$ 5.00 - $ 9.99 $ 6.06 -- 145,100 104,000 1,414,750 1,663,850
-------- --------- ---------- ---------- -----------
Total $ 4.69 131,702 471,505 168,000 2,570,575 3,341,782
======== ========= ========== ========== ===========
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. Due to the discount from
market value, in the restatement, the Company recorded additional compensation
expense of $220,000 and $126,000 in the three months ended June 30, 2001 and
2002, respectively. 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
with terms expiring in May 2003.
(11) DEFERRED COMPENSATION
In 1996, the Board of Directors of the Company adopted a deferred
compensation plan (the Plan) to encourage employees to invest in the shares of
the Company. The Plan gives employees the ability to defer all or a portion of
their salaries and bonuses and invest in Common Stock of the Company at a
discount to market prices or make other investments at the employee's
discretion. The stock held in the 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 is marked-to-market, with any necessary adjustment
to general and administrative expense. The Company recorded total expenses
related to deferred compensation of $545,000 and $791,000 million the three
months ended June 30, 2001 and 2002, respectively. For the six months ended June
30, 2001 and 2002, the Company recorded total expenses of ($648,000) and $1.7
million, respectively.
(12) 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
(13) 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):
December 31, June 30,
2001 2002
------------- ----------
(Restated) (Restated)
Deferred tax assets
Net operating loss carryover $ 53,977 $ 55,990
Allowance for doubtful accounts 7,035 7,208
Percentage depletion carryover 5,256 5,256
AMT credits and other 660 660
------------- ----------
Total 66,928 69,114
Deferred tax liabilities
Depreciation (54,732) (57,106)
Unrealized gain on hedging (16,692) (3,865)
------------- ---------
Total (71,424) (60,971)
------------- ---------
Net deferred tax (liability) asset $ (4,496) $ 8,143
============= =========
A deferred tax liability, generated by gains in OCI of $4.5 million,
was recorded on the balance sheet at December 31, 2001. The deferred tax asset
of $12.2 million at December 31, 2001 was used to offset the majority of the
deferred tax liability generated by OCI. Therefore, the benefit of the reduced
liability will be recorded in 2002 as the hedges creating the gains in OCI
transfer to realized revenue. During the three and six months ended June 30,
2002, the Company recorded a deferred tax benefit in the income statement of
$3.1 million and $4.9 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 $3.0 million and $1.9 million deferred tax benefit will be
reclassified from other comprehensive income to income in the third quarter and
fourth quarters of 2002, respectively.
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 and to such extent, no income tax payments are required.
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
(14) EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted
earnings per common share (in thousands except per share amounts):
Three Months Ended, Six Months Ended,
June 30, June 30,
---------------------------- ----------------------------
2001 2002 2001 2002
------------ ------------ ------------ ------------
(Restated) (Restated) (Restated) (Restated)
Numerator
Income before extraordinary item $ 15,358 $ 6,465 $ 34,979 $ 9,621
Gain on retirement Preferred Stock 3 -- 532 --
Preferred dividends (4) -- (8) --
------------ ------------ ------------ ------------
Numerator for earnings per share,
before extraordinary item 15,357 6,465 35,503 9,621
Extraordinary item
Gain on retirement of securities, net 1,610 845 2,042 2,030
------------ ------------ ------------ ------------
Numerator for earnings per share,
basic and diluted $ 16,967 $ 7,310 $ 37,545 $ 11,651
============ ============ ============ ============
Denominator
Weighted average shares, basic 50,919 54,540 50,554 53,763
Stock held by employee benefit trust (1,067) (1,172) (961) (1,106)
------------ ------------ ------------ ------------
Weighted average shares, basic 49,852 53,368 49,593 52,657
Stock held by employee benefit trust 1,067 1,172 961 1,106
Dilutive potential common shares stock options 124 239 118 149
------------ ------------ ------------ ------------
Denominator for dilutive earnings per share 51,043 54,779 50,672 53,912
============ ============ ============ ============
Earnings per share basic and diluted:
Before extraordinary gain
Basic 0.31 0.12 0.72 0.18
Diluted 0.30 0.12 0.70 0.18
After extraordinary gain
Basic 0.34 0.14 0.76 0.22
Diluted 0.33 0.13 0.74 0.22
During the three months ended June 30, 2001 and 2002, 150,000 and
262,000 stock options were included in the computation of diluted earnings per
share and for the six months then ended, 154,000 and 173,000 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.
(15) MAJOR CUSTOMERS
The Company markets its production on a competitive basis. Gas is sold
under various types of contracts ranging from life-of-the-well to short-term
contracts that are cancelable within 30 days. Oil purchasers may be changed on
30 days notice. The price for oil is generally equal to a posted price set by
major purchasers in the area. The Company sells to oil purchasers on the basis
of price and service. For the 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 First Energy, 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.
(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):
Six
Year Ended Months Ended
December 31, June 30,
2001 2002
------------- -------------
(Restated) (Restated)
Book value
Properties subject to depletion $ 1,021,898 $ 1,060,032
Unproved properties 25,731 21,503
------------- -------------
Total 1,047,629 1,081,535
Accumulated depletion (514,272) (550,039)
------------- -------------
Net $ 533,357 $ 531,496
============= =============
Costs incurred
Development $ 69,162 $ 25,179
Exploration(a) 11,405 8,994
Acquisition(b) 9,489 2,689
------------- -------------
Total $ 90,056 $ 36,862
============= =============
(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
(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 financial statements
as of or for the six months ended June 30, 2002 (in thousands):
June 30,
2002
----------
(Restated)
Balance Sheet
Current assets $ 9,799
Oil and gas properties, net 168,747
Transportation and field assets, net 15,308
Other assets 199
Current liabilities 12,061
Long-term debt 68,500
Members' equity 96,384
Income Statement
Revenues $ 25,494
Net income 6,479
(18) EXTRAORDINARY ITEM
During the second quarter of 2001, 571,000 shares of common stock were
exchanged for $2.6 million of 6% Debentures, and $2.4 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 adopted in
the Unites 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
Companies accounting policies, including those related to oil and gas revenues,
bad debts, 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 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.
Proved oil and natural gas 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 as established by the SEC, the estimation of
reserves requires the engineers to make a significant number of assumptions
based on professional judgment. Estimated reserves are often subject to future
revision, certain of 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 natural gas prices can lead to a
decision to start-up or shut-in production, which can lead to revisions to
reserve quantities. Reserve revisions inherently lead to adjustments of
depreciation rates utilized by the Company. The Company can not predict the
types of reserve revisions that will be required in future periods.
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
capital expenditures are capitalized and systematically charged to expense using
the units of production method based on proved developed oil and natural gas
reserves as estimated by the Company's engineers. The Company also uses proved
developed reserves to recognize expense for future estimated dismantlement and
abandonment costs. Costs of exploration wells in progress at year-end 2001 were
not significant.
Impairment of properties - The Company continually monitors its
long-lived assets recorded in Property, Plant and Equipment in the Consolidated
Balance Sheet to make sure that 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 natural gas reserves that will be produced from a field, the
timing of this future production, future costs to produce the oil and natural
gas, and future inflation levels. 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 natural gas, unfavorable adjustment to reserves, or other changes
to contracts environmental regulations or tax laws. All of these same factors
must be considered when testing a property's carrying value for impairment. The
Company can not predict the amount of impairment charges that may be recorded 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
months after the close of its calendar year; (b) tax returns are subject to
audit by taxing authorities and audits
28
can often take years to complete and settle; and (c) future events often impact
the timing of when income tax expenses and benefits are recognized by the
Company. 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 their realization. A
valuation allowance has been recognized for deferred tax assets due to
management's belief that certain of these assets are not likely to be realized.
The Company's deferred tax assets exceed deferred tax liabilities at
year-end 2001, before considering the effects of Other comprehensive income
("OCI"). In determining deferred tax liabilities, accounting rules require OCI
to be considered, even though such income (loss) has not yet been earned. The
inclusion of OCI causes deferred tax liabilities to exceed deferred tax assets
by $4.5 million of pre-tax income from the unrealized hedges included in OCI at
year-end before statutory taxes will be recorded on the income statement. Due to
the complexity of the accounting rules regarding taxes, the timing of when the
Company will record deferred taxes is uncertain.
The Company occasionally is challenged by taxing authorities over the
amount and/or timing of recognition of revenues and deductions in its various
income tax returns. Although the Company believes that it has adequate accruals
for matters not resolved with various taxing authorities, gains or losses could
occur in future years from 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 interpretation
of laws and regulations, which can be interpreted differently by regulators
and/or courts of law. The Company's 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 information
available to the Company.
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. 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 recoverable based on current
estimates of expected future cash flows.
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 $640.2 million and, including the
Trust Preferred as debt, a debt to capitalization (including debt, deferred
taxes and stockholders' equity) ratio of 63%. Excluding the Trust Preferred as
debt, the debt to Capitalization ratio was 56%. 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
29
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 $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 $63.0
million and $46.0 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 $24.7 million and
$37.1 million, respectively. The 2001 period included $32.6 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 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
30
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 $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
4.63% 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 1 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.
31
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):
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------- ----------------------------
2001 2002 2001 2002
------------ ------------ ------------ ------------
Restated Restated Restated Restated
Increase (Decrease) in Revenues:
Writedown of marketable securities $ (38) $ (851) $ (1,348) $ (1,220)
Ineffective portion of hedges 984 (462) 3,250 (2,162)
Gain from sales of assets 768 27 1,066 26
Hedging gains (losses) (5,250) 3,638 (28,690) 15,365
------------ ------------ ------------ ------------
$ (3,536) $ 2,352 $ (25,722) $ 12,009
============ ============ ============ ============
Increase (decrease) to expenses:
Mark-to-market cash compensation 534 538 (962) 1,320
Adjustment to IPF valuation
reserves/receivables (1,223) 1,442 (2,320) 2,567
Ineffective portion of hedges (112) 300 578 (72)
------------ ------------ ------------ ------------
$ (801) $ 2,280 $ (2,704) $ 3,815
============ ============ ============ ============
Extraordinary Items:
Gain on retirement of securities $ 1,610 $ 845 $ 2,042 $ 2,030
============ ============ ============ ============
Comparison of 2002 to 2001
Quarters Ended June 30, 2001 and 2002
Net income in the second quarter of 2002 totaled $7.3 million, compared
to $17.0 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 income of $1.0 million, a decrease of
$109,000 from the 2001 period. IPF expenses in 2001 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 $810,000 to $2.2 million, primarily due
to additional seismic activity. General and administrative expenses increased
12% to $4.7 million in the quarter primarily due to higher
32
accounting and engineering technical consulting costs, information systems
programming costs, salary related expenses and non-cash compensation expenses.
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 20% to $6.3 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") increased 5% from the
second quarter of 2001. The per mcfe DD&A rate for the second quarter of 2002
was $1.41, a $0.09 increase 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 $1.38
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 $11.7 million
compared to $37.0 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 income of $2.2 million, a decrease of $1.5 million
from the 2001 period. IPF expenses in 2001 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 revenue
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 46% to $9.2
million in the six months ended June 30, 2002 due to higher non-cash
compensation expense, 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 34% to $11.6 million as a result of lower
outstanding debt and falling interest rates.
Depletion, depreciation and amortization increased 3% from the six
month period of 2001. The per mcfe DD&A rate for the six months of 2002 was
$1.38, a $0.06 increase from the rate for the same period of the prior year.
33
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.
34
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 183,000 shares of common stock, $2.4 million face
value of Trust Preferred were exchanged for 283,000 shares of
common stock.
(d) Not applicable.
35
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.
Results of Voting Votes For Withheld Abstentions
----------------- --------- -------- -----------
1. Directors
Robert E. Aikman 47,369,411 3,807,902 --
Anthony Dub 47,404,873 3,772,440 --
V. Richard Eales 47,396,053 3,781,260 --
Thomas J. Edelman 47,558,930 3,618,383 --
Allen Finkelson 47,578,714 3,598,599 --
Alexander P. Lynch 46,633,453 4,543,860 --
Jonathan S. Linker 47,558,924 3,618,389 --
John H. Pinkerton 47,586,550 3,590,763 --
Votes For Against Abstentions
--------- ---------- ------------
2. Increase in number 34,091,333 16,980,529 105,451
of shares authorized
under the Company's
1999 Stock Option
Plan to 6,000,000
36
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 8-K/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.
Form 8-K dated August 14, 2002 (filed on August 14, 2002)
reporting under Item 9 - Regulation FD Disclosure.
37
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
October 24, 2002
38
I, John H. Pinkerton, certify that:
1. I have reviewed this quarterly report on Form 10-Q/A of Range
Resources Corporation;
2. Based on my knowledge, this quarterly 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
quarterly report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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
quarterly report.
Date: October 24, 2002
/s/ John H. Pinkerton
------------------------------------------
John H. Pinkerton, President
I, Eddie M. LeBlanc, certify that:
1. I have reviewed this quarterly report on Form 10-Q/A of Range
Resources Corporation;
2. Based on my knowledge, this quarterly 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
quarterly report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this quarterly 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
quarterly report.
Date: October 24, 2002
/s/ Eddie M. LeBlanc
------------------------------------------
Eddie M. LeBlanc, Chief Financial Officer
39
EXHIBIT INDEX
Exhibit
Number Description of Exhibit
------- ----------------------
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