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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003.
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ____ to ______
Commission file number 0-9592
RANGE RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 34-1312571
(State of or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
777 MAIN STREET
FT. WORTH, TEXAS
(Address of principal executive offices)
76102
(Zip Code)
Registrant's telephone number, including area code: (817) 870-2601
(Former name or former address, if changed since last report): Not applicable
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
55,571,945 Common Shares were outstanding on April 30, 2003.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
The financial statements included herein should be read in conjunction
with the Company's latest Form 10-K. The statements are unaudited but reflect
all adjustments which, in the opinion of management, are necessary to fairly
present the Company's financial position and results of operations. All
adjustments are of a normal recurring nature unless otherwise noted. 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, MARCH 31,
2002 2003
------------ ----------
ASSETS (Unaudited)
Current assets
Cash and equivalents $ 1,334 $ 1,388
Accounts receivable 26,832 45,350
IPF receivables, net (Note 2) 6,100 5,500
Unrealized derivative gain (Note 2) 4 78
Inventory and other 3,084 3,474
Deferred tax asset, net (Note 13) - 19,820
---------- ----------
37,354 75,610
---------- ----------
IPF receivables, net (Note 2) 18,351 15,589
Unrealized derivative gain (Note 2) 13 435
Oil and gas properties, successful efforts method (Note 16) 1,154,549 1,215,531
Accumulated depletion and depreciation (590,143) (587,839)
---------- ----------
564,406 627,692
---------- ----------
Transportation and field assets (Note 2) 34,143 35,225
Accumulated depreciation and amortization (16,071) (16,765)
---------- ----------
18,072 18,460
---------- ----------
Deferred tax asset, net (Note 13) 15,785 -
Other (Note 2) 4,503 4,517
---------- ----------
$ 658,484 $ 742,303
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 27,044 $ 29,425
Asset retirement obligation (Note 3) - 15,931
Accrued liabilities 9,678 8,987
Accrued interest 4,449 2,632
Unrealized derivative loss (Note 2) 26,035 43,380
---------- ----------
67,206 100,355
---------- ----------
Senior debt (Note 6) 115,800 121,800
Non-recourse debt (Note 6) 76,500 78,500
Subordinated notes (Note 6) 90,901 90,021
Trust preferred - manditorily redeemable security of subsidiary (Note 6) 84,840 84,440
Deferred tax credits, net (Note 13) - 2,319
Unrealized derivative loss (Note 2) 9,079 14,987
Deferred compensation liability (Note 11) 8,049 9,725
Asset retirement obligation (Note 3) - 38,113
Commitments and contingencies (Note 8)
Stockholders' equity (Notes 9 and 10)
Preferred stock, $1 par, 10,000,000 shares authorized,
none issued or outstanding - -
Common stock, $.01 par, 100,000,000 shares authorized, 550 554
54,991,611 and 55,433,212 issued and outstanding, respectively
Capital in excess of par value 391,082 394,091
Stock held by employee benefit trust, and 1,324,537
1,519,164 shares, respectively, at cost (Note 11) (6,188) (7,362)
Retained earnings (deficit) (158,059) (148,605)
Deferred compensation expense (125) (182)
Other comprehensive income (loss) (Note 2) (21,151) (36,453)
---------- ----------
206,109 202,043
---------- ----------
$ 658,484 $ 742,303
========== ==========
SEE ACCOMPANYING NOTES.
3
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED, IN THOUSANDS EXCEPT PER SHARE DATA)
THREE MONTHS
ENDED MARCH 31,
--------------------
2002 2003
-------- -------
Revenues
Oil and gas sales $ 44,283 $54,330
Transportation and processing 774 1,027
IPF income (Note 2) 1,171 539
Gain on retirement of securities (Note 18) 1,185 150
Other (2,009) 928
-------- -------
45,404 56,974
-------- -------
Expenses
Direct operating 9,204 13,028
IPF 1,772 618
Exploration 5,271 2,453
General and administrative (Note 11) 4,470 4,846
Debt conversion and extinguishment expense (Note 6) - 465
Interest expense and dividends on trust preferred 5,357 5,544
Depletion, depreciation and amortization 18,100 20,967
-------- -------
44,174 47,921
-------- -------
Income before income taxes and accounting change 1,230 9,053
Income taxes (Note 13)
Current - 4
Deferred (3,111) 4,086
-------- -------
(3,111) 4,090
-------- -------
Income before cumulative effect of change in
accounting principle 4,341 4,963
Cumulative effect of change in accounting principle
(net of taxes of $2.4 million) (Note 3) - 4,491
-------- -------
Net income $ 4,341 $ 9,454
======== =======
Comprehensive income (loss) (Note 2) $(23,072) $(5,848)
======== =======
Earnings per share (Note 14)
Before cumulative effect of change in
accounting principle - basic $ 0.08 $ 0.09
======== =======
- diluted $ 0.08 $ 0.09
======== =======
After cumulative effect of change in
accounting principle - basic $ 0.08 $ 0.18
======== =======
- diluted $ 0.08 $ 0.17
======== =======
SEE ACCOMPANYING NOTES.
4
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED, IN THOUSANDS)
THREE MONTHS ENDED MARCH 31,
----------------------------
2002 2003
-------- --------
CASH FLOWS FROM OPERATIONS
Net income $ 4,341 $ 9,454
Adjustments to reconcile net income to
net cash provided by operations:
Cumulative effect of change in accounting principle - (4,491)
Deferred income taxes (3,111) 4,086
Depletion, depreciation and amortization 18,100 20,967
Write-down of marketable securities 369 -
Unrealized hedging (gains) losses 1,328 (733)
Allowance for bad debts 1,126 334
Exploration expense 5,271 2,453
Amortization of deferred issuance costs 144 229
Gain on retirement of securities (1,185) (150)
Debt conversion and extinguishment expense - 465
Deferred compensation adjustments 1,359 564
Gain (loss) on sale of assets 1 (87)
Changes in working capital:
Accounts receivable (1,134) (18,725)
Inventory and other (69) (390)
Accounts payable (3,046) 922
Accrued liabilities (2,767) 3,236
-------- --------
Net cash provided by operations 20,727 18,134
-------- --------
CASH FLOWS FROM INVESTING
Oil and gas properties (18,633) (25,820)
Field service assets (390) (1,141)
IPF investments (1,599) (583)
IPF repayments 1,493 3,680
Exploration expense (5,271) (2,453)
Asset sales 35 292
-------- --------
Net cash used in investing (24,365) (26,025)
-------- --------
CASH FLOWS FROM FINANCING
Net borrowings on parent facility and non-recourse debt 37,900 37,100
Net repayments on parent facility and non-recourse debt (37,001) (29,100)
Other debt repayments (14) (236)
Issuance of common stock 57 181
-------- --------
Net cash provided by financing 942 7,945
-------- --------
Change in cash (2,696) 54
Cash and equivalents, beginning of period 3,380 1,334
-------- --------
Cash and equivalents, end of period $ 684 $ 1,388
======== ========
SEE ACCOMPANYING NOTES.
5
RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
The Company is engaged in the development, acquisition and exploration
of oil and gas properties primarily in the Southwestern, Gulf Coast and
Appalachian regions of the United States. To a minor extent, the Company also
provides financing to smaller oil and gas producers through a wholly-owned
subsidiary, Independent Producer Finance ("IPF"). The Company seeks to increase
its reserves and production primarily through development, exploratory 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 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 future 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) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts
of the Company, wholly-owned subsidiaries and a 50% pro rata share of the
assets, liabilities, income and expenses of Great Lakes. Liquid investments with
original maturities of 90 days or less are considered cash equivalents. Certain
reclassifications have been made to the presentation of prior periods to conform
to current year presentation. The interim financial statements reflect all
adjustments, including normal and recurring adjustments that are, in the opinion
of management, necessary for a fair presentation.
REVENUE RECOGNITION
The Company recognizes revenues from the sale of products and services
in the period delivered. Payments received at IPF relating to return on
investment are recognized as income; remaining receipts reduce receivables.
Although receivables are concentrated in the oil industry, the Company does not
view this as an unusual credit risk. The Company had allowances for doubtful
accounts relating to its exploration and production business of $835,000 and
$894,000 at December 31, 2002 and March 31, 2003, respectively.
6
MARKETABLE SECURITIES
Holdings of equity securities that qualify as available-for-sale are
recorded at fair value. The Company owns approximately 18% of a very small
publicly traded independent exploration and production company. This entity has
experienced growing difficulties, operationally and financially. During the
first three months of 2002, the Company determined that the decline in the
market value of this equity security was other than temporary and losses of
$369,000 were recorded as a reduction to Other revenues. Based on its analysis
of the investment and its assessment of the prospects of realizing any value on
the stock, the Company determined that the investment had no determinable value
at June 30, 2002 and the book value of the investment was fully reserved. In
October 2002, several creditors sought to place this entity in involuntary
bankruptcy. In February 2003, the United States Bankruptcy Court entered an
order for relief under Chapter 11 of the Bankruptcy Codes for this entity. As
of April 30, 2003, this company is still publicly traded.
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 on investment
are recognized as income; remaining receipts reduce receivables. No interest
income is recorded on impaired receivables and any payments received applicable
to impaired receivables are applied as a reduction of the receivable.
Receivables classified as current represent the return of capital expected
within 12 months. All receivables are evaluated quarterly and provisions for
uncollectible amounts are established based on the Company's valuation of its
royalty interest in the oil and gas properties. At December 31, 2002 and March
31, 2003, IPF's valuation allowance totaled $12.6 million and $13.7 million,
respectively. 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. 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. During the first quarter of 2003, IPF revenues were $539,000
offset by $258,000 of general and administrative costs, $101,000 of interest and
a $259,000 increase in the valuation allowance. During the same period of the
prior year, revenues were $1.2 million offset by a $1.1 million increase in the
valuation allowance, general and administrative expenses of $394,000 and
$253,000 of interest. IPF's net receivables have declined from a high of $77.2
million in 1998 to $21.1 million at March 31, 2003, as it has focused on
recovering its investment. The Company is continually assessing its strategic
alternatives with regards to IPF. Since 2001, IPF has not entered into any new
financing agreements and does not anticipate entering into any in the future.
Therefore, the size of its portfolio should continue to decline due to
collections.
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. Exploratory wells subsequently determined to be dry holes
are charged to expense. Costs resulting in exploratory discoveries and all
development costs, whether successful or not, are capitalized. Geological and
geophysical costs, delay rentals and unsuccessful exploratory wells are
expensed. Depletion is provided on the unit-of-production method. Oil is
converted to gas equivalent basis ("mcfe") at the rate of six mcf per barrel.
The DD&A rates were $1.35 and $1.51 per mcfe in the quarters ended March 31,
2002 and 2003, respectively. Unproved properties had a net book value of $19.0
million and $17.8 million at December 31, 2002 and March 31, 2003, respectively.
The Company's long-lived assets are reviewed for impairment quarterly
for events or changes in circumstances that indicate that the carrying amount of
an asset may not be recoverable in accordance with SFAS No. 144. The review is
done by determining if the historical cost of proved properties less the
applicable accumulated depreciation, depletion and amortization is less than the
estimated expected undiscounted future cash flows. The expected future cash
flows are estimated based on management's plans to continue to produce and
develop proved reserves. Expected future cash flow from the sale of production
of reserves is calculated based on estimated future prices. Management estimates
prices based upon market related information including published futures prices.
In years where market information is not available, prices are escalated for
inflation. The estimated future level of production is based on assumptions
surrounding future levels of prices and costs, field decline rates,
7
market demand and supply, and the economic and regulatory climates. When the
carrying value exceeds such cash flows, an impairment loss is recognized for the
difference between the estimated fair value and the carrying value of the
assets.
TRANSPORTATION, PROCESSING AND FIELD ASSETS
The Company's gas gathering systems are generally located in proximity
to certain of its principal fields. Depreciation on these systems is provided on
the straight-line method based on estimated useful lives of 10 to 15 years. The
Company receives third party income for providing certain field services which
are recognized as earned. These revenues approximated $500,000 in each of the
three month periods ended March 31, 2002 and 2003. Depreciation on the field
assets is calculated on the straight-line method based on estimated useful lives
of five to seven years. Buildings are depreciated over 10 to 15 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
which management believes does not differ materially from the effective interest
method). When a security is retired prior to maturity, related unamortized costs
are expensed. At December 31, 2002 and March 31, 2003, these capitalized costs
totaled $3.0 million and $2.8 million, respectively. At March 31, 2003, Other
assets included $2.8 million unamortized debt issuance costs, $588,000 of
long-term deposits, and $1.1 million of marketable securities held in a deferred
compensation plan.
GAS IMBALANCES
The Company uses the sales method to account for gas imbalances,
recognizing revenue based on cash received rather than gas produced. A liability
is recognized when the imbalance exceeds the estimate of remaining reserves. Gas
imbalances at December 31, 2002 and March 31, 2003 were immaterial.
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING
The Company enters into contracts to reduce the impact of volatile oil
and gas prices. These contracts generally qualify as cash flow hedges; however,
certain of the contracts have an ineffective portion (changes in realized prices
that do not match the changes in hedge price) which is recognized in earnings.
Gains or losses on open contracts are recorded in OCI. The Company also enters
into swap agreements to reduce the risk of changing interest rates. These
agreements qualify as cash flow hedges whereby changes in the fair value of the
swaps are reflected as an adjustment to OCI to the extent the swaps are
effective and are recognized in income as an adjustment to interest expense in
the period covered for the ineffective portion.
Derivatives are 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 (loss) ("OCI") and reclassified to earnings when the
transaction is consummated. Changes in the value of the ineffective portion of
all open hedges are recognized in earnings as they occur. At March 31, 2003, the
Company reflected an unrealized net pre-tax hedging loss on its balance sheet of
$56.0 million. This accounting can greatly increase volatility of earnings and
stockholders' equity of independent oil companies which have active hedging
programs, such as Range. Earnings are affected by the ineffective portion of a
hedge contract (changes in realized prices that do not match the changes in the
hedge price). Ineffective gains or losses are recorded in Other revenue while
the hedge contract is open and may increase or reverse until settlement of the
contract. Stockholders' equity is affected by the increase or decrease in OCI.
Typically, when oil and gas prices increase, OCI decreases. Of the $56.0 million
unrealized pre-tax loss at March 31, 2003, $41.8 million of losses would be
reclassified to earnings over the next twelve month period and $14.2 million for
the periods thereafter, if prices remained constant. Actual amounts that will be
reclassified will vary as a result of changes in prices.
The Company had hedge agreements with Enron North America Corp.
("Enron") for 22,700 Mmbtu per day at $3.20 per Mmbtu for the first three
contract months of 2002. At December 31, 2001, based on accounting requirements,
an allowance for bad debts of $1.4 million was recorded, offset by a $318,000
ineffective gain
8
included in income and a $1.0 million gain included in OCI related to these
defaulted hedge contracts. The gain included in OCI at year-end 2001 was
included in Other revenue in the first quarter of 2002. In the three months
ended March 31, 2002 the Company wrote off this receivable against the allowance
for bad debts. The last Enron contract expired in March 2002.
Other revenues in the Consolidated Statements of operations reflected
ineffective hedging losses of $1.7 million and gains of $804,000 for the three
months ended March 31, 2002 and March 31, 2003, respectively. Interest expense
includes ineffective interest hedging gains of $372,000 and losses of $71,000
for the three months ended March 31, 2002 and March 31, 2003, respectively. Net
unrealized hedging losses of $57.8 million (including $1.8 million of losses on
interest rate swaps) and OCI of a loss of $36.5 million (net of taxes) were
recorded on the balance sheet at March 31, 2003. See Note 7.
COMPREHENSIVE INCOME
Comprehensive Income is defined as changes in Stockholders' equity from
non-owner sources, which is calculated below (in thousands):
Three Months Ended
March 31,
------------------------
2002 2003
-------- --------
Net income $ 4,341 $ 9,454
Net amount of hedging (gain) loss reclassed to earnings (11,727) 25,890
Change in unrealized gains (losses), net (15,014) (41,192)
Defaulted hedge contracts, net (672) -
-------- --------
Comprehensive income (loss) $(23,072) $ (5,848)
======== ========
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 those estimates. Estimates which may significantly
impact the financial statements include oil and gas reserves, impairment tests
on oil and gas properties, IPF valuation allowance and the fair value of
derivatives.
RECENT ACCOUNTING PRONOUNCEMENTS
In April 2002, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 145 "Rescission of FASB
Statements No. 4, 44 and 64, amendment of FASB Statement 13 and Technical
corrections" ("SFAS 145"). Extinguishment of debt will be accounted for in
accordance with Accounting Principle Board Opinion No. 30 "Reporting the Results
of Operations, Reporting the effects of Disposal of a Segment of a Business and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions." As a
result gains from early extinguishment of debt will be reported in income from
continuing operations. The Company adopted the provisions of SFAS 145 as of
January 1, 2003. This adoption resulted in the reclassification of extraordinary
gain on sale of securities totaling $1.2 million to revenue in the three months
ended March 31, 2002, with no change to reported net income.
In December 2002, the FASB issued Statement of Financial Accounting
Standards 148, "Accounting for Stock-Based Compensation Transition and
Disclosure," ("SFAS 148"). This statement amends Statement of Financial
Accounting Standards 123, "Accounting for Stock-Based Compensation," and
establishes two alternative methods of transition from the intrinsic value
method to the fair value method of accounting for stock-based employee
compensation. In addition, SFAS 148 requires prominent disclosure about the
effects on reported net income and requires disclosure of these effects in
interim financial reporting. The provisions for the alternative transition
methods and disclosure requirements were effective for the year-ended December
31, 2002. The
9
Company currently plans to continue accounting for stock-based compensation
under APB 25, an allowable method, with additional disclosures as required in
all future filings (see below).
PROFORMA STOCK BASED COMPENSATION
The Company has adopted the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." Accordingly, no compensation cost has
been recognized for the stock option plans because the exercise prices employee
stock options equals the market prices of the underlying stock on the date of
grant. Had compensation cost been determined based on the fair value at the
grant date for awards in the three months ended March 31, 2002 and 2003,
respectively consistent with the provisions of SFAS No. 123, the Company's net
income and earnings per share would have been reduced to the pro forma amounts
indicated below (in thousands, except per share data):
Three Months Ended March 31,
----------------------------
2002 2003
------- --------
Net income, as reported - $ 4,341 $ 9,454
Deduct: Total stock based
employee compensation
expense determined under
fair value based method
for all awards, net of
related tax effects (220) (421)
------- --------
Pro forma net income $ 4,121 $ 9,033
======= ========
Earnings per share:
Basic-as reported 0.08 0.18
Basic-pro forma 0.08 0.17
Diluted-as reported 0.08 0.17
Diluted-pro forma 0.08 0.16
(3) ASSET RETIREMENT OBLIGATION
Beginning in 2003, Statement of Financial Accounting Standards No. 143
"Asset Retirement Obligations" ("SFAS 143") requires the Company to recognize an
estimated liability for the plugging and abandonment of its oil and gas wells
and associated pipelines and equipment. Previously, the Company had recognized a
plugging and abandonment obligation primarily for its offshore properties. This
liability was shown netted against oil and gas properties on the balance sheet.
Under SFAS 143, the Company now recognizes a liability for asset retirement
obligations in the period in which they are incurred, if a reasonable estimate
of fair value can be made. The associated asset retirement costs are capitalized
as part of the carrying amount of the long-lived asset. SFAS 143 requires the
Company to consider estimated salvage value in the calculation of DD&A.
Consistent with industry practice, historically the Company had assumed the cost
of plugging and abandonment on its onshore properties would be offset by salvage
value received. The adoption of SFAS 143 resulted in (i) an increase of total
liabilities, because retirement obligations are required to be recognized (ii)
an increase in the recognized cost of assets, because the retirement costs are
added to the carrying amount of the long-lived asset and (iii) an increase in
DD&A expense, because of the accretion of the retirement obligation. The
majority of the asset retirement obligations recorded by the Company relate to
the plugging and abandonment of oil and gas wells.
The estimated liability is based on historical experience in plugging
and abandoning wells, estimated remaining lives of those wells based on reserves
estimates, external estimates as to the cost to plug and abandon the wells in
the future, and federal and state regulatory requirements. The liability is
discounted using an assumed
10
credit-adjusted risk-free interest rate of 9%. Revisions to the liability could
occur due to changes in estimates of plugging and abandonment costs or remaining
lives of the wells, or if federal or state regulators enact new plugging and
abandonment requirements.
The adoption of SFAS 143 as of January 1, 2003 resulted in a cumulative
effect gain of $4.5 million (net of income taxes of $2.4 million) or $0.08 per
share which is included in income for the quarter ended March 31, 2003. The
adoption resulted in a January 1, 2003 cumulative effect adjustment to record
(i) a $37.3 million increase in the carrying values of proved properties, (ii) a
$21.0 million decrease in accumulated depletion, (iii) a $2.3 million increase
in current plugging and abandonment liabilities, (iv) a $49.1 million increase
in non-current plugging and abandonment liabilities and (v) a $2.4 million
decrease in deferred tax assets. The net impact of items (i) through (v) was to
record a gain of $4.5 million, net of tax, as a cumulative effect adjustment of
a change in accounting principle. The pro forma effects of the application of
SFAS 143, as if the Statement had been adopted net-of-tax on January 1, 2002
(rather than January 1, 2003), are presented below (in thousands, except per
share data):
Pro Forma
Three Months Ended March
31,
----------------------------
2002 2003
-------- --------
Net income $ 8,686 $ 4,963
Earnings per share - basic $ 0.17 $ 0.09
- diluted $ 0.16 $ 0.09
A reconciliation of the Company's liability for plugging and
abandonment costs for the three months ended March 31, 2003 is as follows (in
thousands):
Asset retirement obligation, December 31, 2002 $ -
Cumulative effect adjustment 51,390
Liabilities incurred 1,773
Liabilities settled (226)
Accretion expense 1,107
----------
Asset retirement obligation, March 31, 2003 $ 54,044
==========
The pro forma asset retirement obligation liability balance as if SFAS
143 had been adopted on January 1, 2002 (rather than January 1, 2003) is as
follows (in thousands):
January 1,
2002
----------
Pro forma amounts of liability for asset
retirement obligation at beginning of period $ 48,294
(4) ACQUISITIONS
Acquisitions are accounted for under the purchase method. Purchase
prices are allocated to acquired assets and assumed liabilities based on their
estimated fair value at acquisition. The Company purchased various properties
for $1.0 million and $6.0 million during the three months ended March 31, 2002
and 2003, respectively. These purchases include $51,000 and $5.0 million for
proved oil and gas reserves, respectively, the remainder represents unproved
acreage purchases. Acquisitions have been funded with internal cash flow and
bank borrowings.
11
(5) SUPPLEMENTAL CASH FLOW INFORMATION
Three Months Ended
March 31,
------------------
2002 2003
-------- -------
(in thousands)
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Common stock issued
Under benefit plans $ 602 $ 1,274
Exchanged for fixed income securities 3,565 760
CASH USED IN OPERATING ACTIVITIES:
Income taxes paid - -
Interest paid 8,046 7,130
The Company has and will continue to consider exchanging common stock
or equity-linked securities for debt, despite the negative impact on its
financial statements due to Statement of Financial Accounting Standards 84 (See
Note 6). If, in the opinion of management, the transaction is favorable for the
Company and its shareholders, the transaction will be executed. Existing
stockholders may be materially diluted if substantial exchanges are consummated.
The extent of dilution will depend on the number of shares and price at which
common stock is issued, the price at which newly issued securities are
convertible and the price at which debt is acquired.
(6) INDEBTEDNESS
The Company had the following debt and Trust preferred (as hereinafter
defined) outstanding as of the dates shown (in thousands). Interest rates at
March 31, 2003 excluding the impact of interest rate swaps are shown
parenthetically:
December 31, March 31,
2002 2003
------------ ---------
Senior debt
Parent credit facility (3.3%) $ 115,800 $ 121,800
--------- ---------
Non-recourse debt
Great Lakes credit facility (3.2%) 76,500 78,500
--------- ---------
Subordinated debt
8.75% Senior Subordinated Notes due 2007 69,281 69,281
6% Convertible Subordinated Debentures due 2007 21,620 20,740
--------- ---------
90,901 90,021
--------- ---------
Total debt 283,201 290,321
--------- ---------
Trust preferred - manditorily redeemable securities
of subsidiary 84,840 84,440
--------- ---------
Total $ 368,041 $ 374,761
========= =========
Interest paid in cash during the three months ended March 31, 2002 and
2003 totaled $8.0 million and $7.1 million, respectively. No interest expense
was capitalized during the three months ended March 31, 2002 and 2003.
12
PARENT BANK DEBT
In May 2002, the Company entered into an amended $225.0 million
revolving bank facility (the "Parent Facility"). The Parent Facility provides
for a borrowing base subject to redeterminations each April and October. On
March 31, 2003, the borrowing base was $147.0 million, of which $25.2 million
was available. On April 1, 2003, the borrowing base was increased to $170.0
million and the term of the loan was extended to January 1, 2007. The borrowing
base at April 30, 2003 was $170.0 million of which $58.2 million was available.
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. The weighted average interest rate was 4.2% and 3.4% for
the three months ended March 31, 2002 and 2003, respectively. The interest rate
is LIBOR plus a margin of 1.50% to 2.25%, depending on outstanding borrowings. A
commitment fee is paid on the undrawn balance based on an annual rate of 0.375%
to 0.50%. At March 31, 2003, the commitment fee was 0.375% and the interest rate
margin was 0.75%. At April 30, 2003, the interest rate was 3.1%.
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 the Company and provides
for a borrowing base subject to semi-annual redeterminations each April and
October. Cash distributions to members of the joint venture are limited by a
covenant contained in the Great Lakes Facility. On March 31, 2003, the borrowing
base was $205.0 million of which $48.0 million was available. On April 1, 2003,
the term of the loan was extended to January 1, 2007 and the borrowing base was
increased to $225.0 million. The borrowing base at April 30, 2003 was $225.0
million, of which $77.0 million was available. 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 March 31, 2003, the commitment fee was 0.50% and the interest rate
margin was 0.625%. The average interest rate on the Great Lakes Facility,
excluding hedges, was 4.0% and 3.5% for the three months ended March 31, 2002
and 2003, respectively. After hedging (see Note 7), the rate was 4.9% and 6.0%
for the quarter ended March 31, 2002 and 2003, respectively. At April 30, 2003,
the interest rate was 3.1% excluding hedges and 5.5% after hedging.
SUBORDINATED NOTES
The 8.75% Senior Subordinated Notes Due 2007 (the "8.75% Notes") are
currently redeemable at 102.9167% 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 three month period ended March 31, 2002, the Company
exchanged $875,000 face amount of the 8.75% Notes for 182,709 shares of common
stock. Only cash repurchases are reflected on the cash flow statement. The gain
on all exchanges and repurchases is included as a Gain on retirement of
securities on the Consolidated Statement of operations. On April 30, 2003, $69.3
million of the 8.75% Notes was 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 102.5% of principal, declining 0.5% each February to 101% in 2006, remaining
at that level until maturity. The 6% Debentures are unsecured general
obligations subordinated to all senior indebtedness, including the 8.75% Notes.
During the three month ended March 31, 2002, $1.5 million of 6% Debentures were
retired at a discount in exchange for 247,000 shares of common stock. In
addition, during the three month period ended March 31, 2002, the Company
purchased $15,000 face amount of the 6% Debentures at a discount. During the
three month period ended March 31, 2003, $880,000 of 6% Debentures were retired
at a discount in exchange for 128,793 shares of common stock. The Company
recorded a $465,000 conversion expense related to this exchange (see discussion
below). On April 30, 2003, $20.7 million of the 6% Debentures was outstanding.
TRUST PREFERRED - MANDITORILY REDEEMABLE SECURITIES OF SUBSIDIARY
In 1997, a special purpose affiliate (the "Trust") issued $120 million
of 5.75% Trust Convertible Preferred Securities (the "Trust Preferred"). The
Trust Preferred is convertible into the Company's common stock at a price
13
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 102.875% 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 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 Consolidated Statement of
operations, are tax deductible and are subject to limitations in the Parent
facility as described below. During the three months ended March 31, 2002, $2.4
million of Trust Preferred were reacquired at a discount in exchange for 283,200
shares of common stock. During the three months ended March 31, 2003, the
Company repurchased for cash $400,000 face amount of the Trust Preferred at a
discount. On April 30, 2003, $84.4 million face amount of the Trust Preferred
was outstanding.
On September 11, 2002, the Emerging Issues Task Force ("EITF") issued
EITF Issue No. 02-15, Determining Whether Certain conversions of Convertible
Debt to Equity Securities are within the Scope of FASB Statement 84 "Induced
Conversions of Convertible Debt" ("SFAS 84"). SFAS 84 was issued to amend APB
Opinion No. 26, "Early Extinguishment of Debt" to exclude from its scope
convertible debt that is converted to equity securities of the debtor pursuant
to conversion privileges different from those included in the terms of the debt
at issuance, and the change in conversion privileges is effective for a limited
period of time, involves additional consideration, and is made to induce
conversion. SFAS 84 applies only to conversions that both (a) occur pursuant to
changed conversion privileges that are exercisable only for a limited period of
time and (b) include the issuance of all of the equity securities issuable
pursuant to conversion privileges included in the terms of the debt at issuance
for each debt instrument that is converted. The Task Force reached a consensus
that SFAS 84 applies to all conversions that both (a) occur pursuant to changed
conversion privileges that are exercisable only for a limited period of time and
(b) include the issuance of all of the equity securities issuable pursuant to
conversion privileges included in the terms of the debt at issuance for each
debt instrument that is converted, regardless of the party that initiates the
offer. This consensus should be applied prospectively to debt conversions
completed after September 11, 2002. Since 1999, the Company has retired 6%
Debentures and Trust Preferred securities, each of which are convertible into
common stock under the terms of the issue, by either purchasing securities for
cash or issuing common stock in exchange for such securities. Since the
exchanges of common stock for these convertible debt securities were at relative
market values, the convertible securities were retired at a substantial discount
to face value. Under the provisions of SFAS No. 84, when an inducement is issued
to retire convertible debt, the face value of the convertible debt security
shall be charged to Stockholders' equity (common stock and paid in capital), the
shares of common stock issued in excess of the shares that would have been
issued under the terms of the debt instrument are expensed at the market value
of such shares and an offsetting increase to paid in capital will also be
recorded. Therefore, instead of recording gains on retirements of such
securities acquired at substantial discounts to face value, an expense will be
recorded. There will be no difference in total Stockholders' equity from the
change in methods of recording the transactions.
The debt agreements contain covenants relating to net worth, working
capital, dividends and financial ratios. The Company was in compliance with all
covenants at March 31, 2003. Under the most restrictive covenant, which is
embodied in the 8.75% Notes, approximately $560,000 of restricted payments could
be made at March 31, 2003. As this covenant limits the ability to repurchase the
6% Convertible Debentures and Trust Preferred, the Company may seek to amend it.
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. Due to the retirement of the separate IPF
credit facility with borrowings under the Parent Facility in December 2002, IPF
is no longer excluded from this calculation. The Company estimates that $22.7
million was available under the Parent Facility's restricted payment basket on
March 31, 2003.
14
(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 March 31, 2003, the Company had hedging contracts covering 76.7 Bcf
of gas at prices averaging $4.05 per mcf and 1.9 million barrels of oil
averaging $24.82 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 Exchange ("NYMEX") price on March 31, 2003, was a net
unrealized pre-tax loss of $56.0 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 increased by $11.7 million and decreased by $25.9 million due to
hedging in the quarters ended March 31, 2002 and 2003, respectively.
The following table sets forth the book and estimated fair values of
financial instruments (in thousands):
December 31, 2002 March 31, 2003
---------------------------- --------------------------
Book Fair Book Fair
Value Value Value Value
----------- ----------- ---------- ----------
Assets
Cash and equivalents $ 1,334 $ 1,334 $ 1,388 $ 1,388
Marketable securities 1,040 1,040 1,113 1,113
Commodity swaps 17 17 513 513
---------- ----------- ---------- ----------
Total 2,391 2,391 3,014 3,014
---------- ----------- ---------- ----------
Liabilities
Commodity swaps (32,964) (32,964) (56,558) (56,558)
Interest rate swaps (2,150) (2,150) (1,809) (1,809)
Long-term debt(1) (283,201) (279,894) (290,321) (287,592)
Trust Preferred(1) (84,840) (52,177) (84,440) (50,292)
---------- ----------- ---------- ----------
Total (403,155) (367,185) (433,128) (396,251)
---------- ----------- ---------- ----------
Net financial instruments $ (400,764) $ (364,794) $ (430,114) $ (393,237)
========== =========== ========== ==========
(1) Fair value based on quotes received from certain brokerage houses. Quotes
for March 31, 2003 were 101.0% for the 8.75% Notes, 83.5% for the 6%
Debentures and 60.0% for the 5.75% Trust Preferred.
15
The following schedule shows the effect of closed oil and gas hedges
since January 1, 2002 and the value of open contracts at March 31, 2003 (in
thousands):
Hedging
Quarter Gain/
Ended (Loss)
- ----------------------------------------------------- -------
Closed Contracts
2002
March 31 11,727
June 30 3,638
September 30 3,484
December 31 (1,059)
-------
Subtotal 17,790
2003
March 31 (25,890)
--------
Total realized loss $ (8,100)
========
Open Contracts
2003
June 30 (12,084)
September 30 (11,201)
December 31 (10,498)
--------
Subtotal (33,783)
2004
March 31 (7,980)
June 30 (4,503)
September 30 (3,379)
December 31 (3,380)
--------
Subtotal (19,242)
2005
March 31 (2,308)
June 30 (114)
September 30 27
December 31 (625)
--------
Subtotal (3,020)
--------
Total unrealized loss (56,045)
--------
Total realized and unrealized gain loss $(64,145)
========
16
Interest rate swaps are accounted for on the accrual basis. Through
Great Lakes, the Company uses interest rate swap agreements to manage the risk
that future cash flows associated with interest payments on amounts outstanding
under the variable rate Great Lakes Facility may be adversely affected by
volatility in market interest rates. Under the Company's interest swap
agreements, the Company agrees to pay an amount equal to a specified fixed rate
of interest times a notional principal amount, and to receive in return, a
specified variable rate of interest times the same notional principal amount.
Changes in the fair value of the Company's interest rate swaps, which qualify
for cash flow hedge accounting treatment are reflected as adjustments to Other
comprehensive income (loss) to the extent the swaps are effective and will be
recognized as an adjustment to interest expense during the period in which the
cash flows related to the Company's interest payments are made. The ineffective
portion of the changes in fair value of the Company's interest rate swaps is
recorded in interest expense in the period incurred. At March 31, 2003, Great
Lakes had nine interest rate swap agreements totaling $100.0 million, of which
50% is consolidated at the Company. These swaps consist of two agreements
totaling $35.0 million at rates averaging 4.6% which expire in June 2003, two
agreements totaling $45.0 million at 7.1% which expire in May 2004, and two
agreements totaling $20.0 million at rates averaging 2.3% which expire in
December 2004. The fair value of these swaps at March 31, 2003 approximated a
net loss of $3.6 million, of which 50% is consolidated at the Company.
The combined fair value of net losses on oil and gas hedges and net
losses on interest rate swaps totaled $57.8 million and appear as short-term and
long-term Unrealized derivative gains and short-term and long-term Unrealized
derivative 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 which, in the opinion of management, are likely
to be resolved without material adverse effect on the Company's financial
position or results of operations.
(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.
Stockholders' equity was $202.0 million at March 31, 2003. The following is a
schedule of changes in the number of outstanding common shares since the
beginning of 2002:
Twelve Months Three Months
Ended Ended
December 31, 2002 March 31, 2003
----------------- --------------
Beginning Balance 52,643,275 54,991,611
Issuances:
Employee benefit plans 417,661 217,938
Stock options exercised 130,566 74,870
Stock purchase plan 168,500 20,000
Exchanges for:
6% Debentures 1,165,700 128,793
Trust Preferred 283,200 -
8.75% Senior notes 182,709 -
---------- ----------
2,348,336 441,601
---------- ----------
Ending Balance 54,991,611 55,433,212
========== ==========
17
(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, 2002 131,702 453,580 152,000 2,544,862 3,282,144
Granted - - - 1,422,900 1,422,900
Exercised (28,670) (30,825) - (15,375) (74,870)
Expired - (3,500) - (5,675) (9,175)
------- ------- -------- --------- ---------
(28,670) (34,325) - 1,401,850 1,338,855
------- ------- -------- --------- ---------
Outstanding on March 31, 2003 103,032 419,255 152,000 3,946,712 4,620,999
======= ======= ======== ========= =========
In 1999, shareholders approved a stock option plan (the "1999 Plan")
providing for the issuance of options on 1.4 million common shares. In 2001,
shareholders approved an increase in the number of options issuable to 3.4
million. In May 2002, shareholders approved an increase in the number of options
issuable to 6.0 million. All options issued under the 1999 Plan from August 5,
1999 through May 22, 2002 vested 25% per year beginning after one year and had a
maximum term of 10 years. Options issued under the 1999 Plan after May 22, 2002
vest 30%, 30% and 40% over a three year period and have a maximum term of five
years. During the three months ended March 31, 2003, options were granted under
the 1999 Plan at exercise prices of $5.83 a share to eligible employees,
including 175,000 and 150,000 options granted to the Chairman and the President,
respectively. At March 31, 2003, 3.9 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 re-election at the annual meeting.
At March 31, 2003, 152,000 options were outstanding under the Directors' Plan at
exercise prices of $2.81 to $6.00 a share.
The Company maintains the 1989 Stock Option Plan (the "1989 Plan")
which authorized the issuance of options on 3.0 million common shares. No
options have been granted under this plan since March 1999. Options issued under
the 1989 Plan vest 30%, 30% and 40% over a three year period and expire in five
years. At March 31, 2003, 419,255 options remained outstanding under the 1989
Plan at exercise prices of $2.62 to $7.62 a share.
The Domain stock option plan was adopted when that company was
acquired, with existing Domain options becoming exercisable into the Company's
common stock. No options have been granted under this plan since the
acquisition. At March 31, 2003, 103,032 options, all of which were vested,
remained outstanding at an exercise price of $3.46 a share.
18
In total, 4.6 million options were outstanding at March 31, 2003 at
exercise prices of $1.93 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 $ 3.37 103,032 278,080 56,000 1,114,249 1,551,361
$ 5.00 - $ 7.63 $ 5.94 - 141,175 96,000 2,832,463 3,069,638
------- ------- -------- --------- ---------
Total $ 5.08 103,032 419,255 152,000 3,946,712 4,620,999
======= ======= ======== ========= =========
In 1997, shareholders approved a plan (the "Stock Purchase Plan")
authorizing the sale of 900,000 shares of common stock to officers, directors,
key employees and consultants. In May 2001, shareholders approved an increase in
the number of shares authorized under the Stock Purchase Plan to 1,750,000.
Under the Stock Purchase Plan, the right to purchase shares at prices ranging
from 50% to 85% of market value may be granted. To date, all purchase rights
have been granted at 75% of market. Due to the discount from market value, the
Company recorded additional compensation expense of $62,000 and $0 in the three
months ended March 31, 2003 and 2002, respectively. Through March 31, 2003,
1,309,819 shares have been sold under the Stock Purchase Plan for $5.5 million.
At March 31, 2003, rights to purchase 146,500 shares were outstanding with terms
expiring in May 2003.
(11) DEFERRED COMPENSATION
During 1996, the Board of the Company adopted a deferred compensation
plan (the "Plan"). The Plan gives certain senior employees the ability to defer
all or a portion of their salaries and bonuses and invests in common stock of
the Company or makes other investments at the employee's discretion. The
Company's stock held in the employee benefit trust is treated in a manner
similar to treasury stock with an offsetting amount reflected as a deferred
compensation liability of the Company and the carrying value of the deferred
compensation is adjusted to fair value each reporting period by a charge or
credit to operations in the General and administrative expense category on the
Company's Consolidated Statement of operations. The Company recorded
mark-to-market expense related to deferred compensation of $782,000 and $385,000
in the three months ended March 31, 2002 and 2003, respectively.
(12) BENEFIT PLAN
The Company maintains a 401(k) Plan for its employees. The Plan permits
employees to contribute up to 50% of their salary (subject to Internal Revenue
limitations) on a pre-tax basis. Historically, the Company has made
discretionary contributions of Company stock to the 401(k) Plan annually. All
Company contributions become fully vested after the individual employee has
three years of service with the Company. In 2000, 2001 and 2002 the Company
contributed $483,000, $554,000 and $602,000 at then market value, respectively,
of the Company's common stock to the 401(k) Plan. The Company does not require
that employees hold the contributed stock in their account. Employees have a
variety of investment options in the 401(k) Plan. Employees are encouraged to
diversify out of Company stock based on their personal investment strategy.
19
(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, March 31,
2002 2003
------------- ---------
Deferred tax assets
Net operating loss carryover $ 71,661 $ 71,264
Allowance for doubtful accounts 4,717 5,114
Net unrealized loss on hedging 11,388 19,608
AMT credits and other 665 665
-------- ---------
Total 88,431 96,651
Deferred tax liabilities
Depreciation (72,646) (79,150)
-------- ---------
Total (72,646) (79,150)
-------- ---------
Net deferred tax asset $ 15,785 $ 17,501
======== =========
A deferred tax liability of $4.5 million was recorded on the balance
sheet at year-end 2001. Without considering the tax effects of certain deferred
hedging gains included in Other comprehensive income (loss) at December 31,
2001, deferred tax assets exceeded deferred tax liabilities by $12.2 million, at
December 31, 2001. The inclusion of deferred tax liabilities related to OCI
caused the deferred tax liabilities to exceed deferred tax assets by the amount
recorded on the balance sheet and accordingly, the valuation allowance on the
deferred tax asset was reversed in 2001 through a reduction of $6.1 million and
an increase to OCI of $12.2 million. During 2002, the $12.2 million included in
OCI at December 31, 2001 was reversed as the related hedge positions closed as
an $11.2 million reduction of 2002 income tax expense, an $18,000 adjustment of
prior-period estimates and a $960,000 increases to Capital in excess of par
value. The $960,000 increase to Capital in excess of par value relates to the
tax benefits of employer stock option plans. At December 31, 2002, deferred tax
assets exceeded deferred tax liabilities by $15.7 million with $11.4 million of
deferred tax assets related to deferred hedging losses included in OCI. Based on
the Company's recent profitability and its current outlook, no valuation
allowance was deemed necessary at December 31, 2002. At March 31, 2003, deferred
tax assets exceeded deferred tax liabilities by $17.5 million with $19.6 million
of deferred tax assets related to hedging losses in OCI. The quarter ended March
31, 2003 deferred tax expense includes $917,000 of expense related to prior
periods' percentage depletion carryover.
At December 31, 2002, the Company had regular net operating loss
("NOL") carryovers of $218.2 million and alternative minimum tax ("AMT") NOL
carryovers of $198.5 million that expire between 2003 and 2022. Regular NOLs
generally offset taxable income and to such extent, no income tax payments are
required. To the extent that AMT NOLs offset AMT income, no alternative minimum
tax payment is due. NOLs generated prior to a change-of-control are subject to
limitations. The Company experienced several changes-of-control events between
1994 and 1998 due to acquisitions. Consequently, the use of $34.1 million of
NOLs is limited to $10.2 million per year. Remaining NOLs are not limited. At
December 31, 2002, the Company had an AMT credit carryover of $665,000 which is
not subject to limitation or expiration.
20
(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,
March 31,
----------------------
2002 2003
------- --------
Numerator
Numerator for earnings per share,
before extraordinary item $ 4,341 $ 4,963
Cumulative effect of accounting change - 4,491
------- --------
Numerator for earnings per share,
basic and diluted $ 4,341 $ 9,454
======= ========
Denominator
Weighted average shares, basic 52,978 55,196
Stock held by employee benefit trust (1,040) (1,327)
------- --------
Weighted average shares, basic 51,938 53,869
Stock held by employee benefit trust 1,040 1,327
Dilutive potential common shares stock options 304 413
------- --------
Denominator for dilutive earnings per share 53,282 55,609
======= ========
Earnings per share basic and diluted:
Before cumulative effect of accounting change
Basic $ 0.08 $ 0.09
Diluted $ 0.08 $ 0.09
After cumulative effect of accounting change
Basic $ 0.08 $ 0.18
Diluted $ 0.08 $ 0.17
During the three months ended March 31, 2002 and 2003, 339,000 and
445,000 stock options were included in the computation of diluted earnings per
share. Remaining stock options, the 6% Debentures and the Trust Preferred were
not included because their inclusion would have been antidilutive.
(15) MAJOR CUSTOMERS
The Company markets its production on a competitive basis. Gas is sold
under various types of contracts ranging from life-of-the-well to short-term
contracts that are cancelable within 30 days. Oil purchasers may be changed on
30 days notice. The price for oil is generally equal to a posted price set by
major purchasers in the area. The Company sells to oil purchasers on the basis
of price and service. For the three months ended March 31, 2003, three
customers, Petrocom Energy Group, Ltd, Duke Energy Trading and Marketing,
and First Energy, accounted for 18%, 13% and 10%, respectively, 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.
21
(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):
Three
Year Ended Months Ended
December 31, March 31,
2002 2003
------------ ------------
Book value
Properties subject to depletion $ 1,135,590 $ 1,197,677
Unproved properties 18,959 17,854
----------- -----------
Total 1,154,549 1,215,531
Accumulated depletion (590,143) (587,839)
----------- -----------
Net $ 564,406 $ 627,692
=========== ===========
Costs incurred(a)
Development $ 66,284 $ 17,821
Exploration(b) 23,232 4,158
Acquisition(c) 21,790 5,988
----------- -----------
Total $ 111,306 $ 27,967
=========== ===========
(a) Excludes asset retirement costs of $1.8 million in the three months ended
March 31, 2003.
(b) Includes $11,525 and $2,453 of exploration costs expensed in the year ended
2002 and the three months ended March 31, 2003, respectively.
(c) Includes $15,643 and $5,048 for oil and gas reserves, the remainder
represents acreage purchases for the year ended 2002 and the three months
ended March 31, 2003, respectively.
22
(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 three months ended March 31, 2002 and 2003 (in thousands):
March 31, March 31,
2002 2003
--------- ---------
Balance Sheet
Current assets $ 8,768 $ 11,827
Oil and gas properties, net 167,662 206,098
Transportation and field assets, net 15,397 15,190
Unrealized derivative gain 782 435
Other assets 78 92
Current liabilities 7,792 20,106
Unrealized derivative loss 1,867 4,779
Asset retirement obligation -- 17,277
Long-term debt 72,000 78,500
Members' equity 111,028 112,980
Statement of Operations
Revenues $ 12,804 $ 14,453
Direct operating expense 2,064 2,589
Exploration 613 294
G&A expense 452 466
Interest expense(1) 913 1,264
DD&A 3,215 3,668
Pretax income 5,547 6,172
Cumulative effect of change in
accounting principle (before income taxes -- 1,601
(1) March 31, 2002 included $372,000 income on ineffective portion of interest
hedges versus $71,000 expense in the first quarter of 2003.
(18) GAIN ON RETIREMENT OF SECURITIES
In the first quarter of 2003, $400,000 of Trust Preferred was
repurchased for cash and $880,000 of 6% Debentures was exchanged for common
stock. A gain of $150,000 was recorded on the cash transaction because the
securities were acquired at a discount. The exchange transaction included
conversion expense of $465,000. (See Note 6 regarding further guidance on SFAS
84 and accounting for gains on sale of securities). In the first quarter of
2002, $15,000 of 6% Debentures was repurchased for cash and $2.4 million, $1.5
million and $875,000 of Trust Preferred, 6% Debentures and $8.75% Notes,
respectively, was exchanged for common stock. A gain of $1.2 million was
recorded because the securities were acquired at a discount and SFAS 84 did not
apply to these transactions because they occurred before the effective date of
September 11, 2002.
23
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 unaudited consolidated financial statements,
which have been prepared in accordance with accounting principles generally
accepted in the United States. The preparation of these financial statements
requires the Company to make estimates and judgments that affect the reported
amounts of assets, liabilities, revenues and expenses. Application of certain of
the Company's 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. Reserve estimates are
updated at least annually and consider recent production levels and other
technical information about each well. Estimated reserves are often subject to
future revision, which could be substantial, based on the availability of
additional information, including: reservoir performance, new geological and
geophysical data, additional drilling, technological advancements, price changes
and other economic factors. Changes in oil and gas prices can lead to a decision
to start-up or shut-in production, which can lead to revisions to reserve
quantities. Reserve revisions in turn cause adjustments in the depletion rates
utilized by the Company. The Company can not predict what reserve revisions may
be required in future periods.
Depletion rates are determined based on reserve quantity estimates and
the capitalized costs of producing properties. As the estimated reserves are
adjusted, the depletion expense for a property will change, assuming no change
in production volumes or the costs capitalized. Estimated reserves are used as
the basis for calculating the expected future cash flows from a property, which
are used to determine whether that property may be impaired. Reserves are also
used to estimate the supplemental disclosure of the standardized measure of
discounted future net cash flows relating to its oil and gas producing
activities and reserve quantities annual disclosure to the consolidated
financial statements. Changes in the estimated reserves are considered changes
in estimates for accounting purposes and are reflected on a prospective basis.
Successful efforts accounting - The Company utilizes the successful
efforts method to account for exploration and development expenditures.
Unsuccessful exploration wells are expensed and can have a significant effect on
operating results. Successful exploration drilling costs and all development
costs are capitalized and systematically charged to expense using the units of
production method based on proved developed oil and natural gas reserves as
estimated by the Company's and third-party engineers. Leasehold costs are
charged expense using the units of production method based on total proved
reserves. The Company also uses proved developed reserves as the divisor to
accrue the expense of estimated future dismantlement and abandonment costs.
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
24
produced from a field, the timing of future production, future production costs,
and future inflation. The need to test a property for impairment can be based on
several factors, including a significant reduction in sales prices for oil
and/or gas, unfavorable adjustment to reserves, or other changes to contracts,
environmental regulations or tax laws. All of these factors must be considered
when testing a property's carrying value for impairment. The Company cannot
predict whether impairment charges may be 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 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 not
been recognized for deferred tax assets due to management's belief that these
assets are likely to be realized.
The Company's deferred tax assets exceeded 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 caused deferred tax liabilities to exceed deferred tax assets
by $4.5 million at year-end 2001 and this amount was recorded as a deferred tax
liability on the balance sheet. At year-end 2002, deferred tax assets exceeded
deferred tax liabilities by $15.8 million with $11.4 million of deferred tax
assets related to deferred hedging losses included in OCI. Based on the
Company's projected profitability, no valuation allowance was deemed necessary.
The Company occasionally is challenged by taxing authorities over the
amount and/or timing of recognition of revenues and deductions 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. Management closely monitors known and potential legal,
environmental and other contingent matters, and makes its best estimate of when
the Company should record losses for these based on available information.
Other significant accounting policies requiring estimates include the
following: The Company recognizes revenues from the sale of products and
services in the period delivered. Revenues at IPF are recognized as earned. An
allowance for doubtful accounts is provided for specific receivables which is
unlikely to be collected. At IPF, all receivables are evaluated quarterly and
provisions for uncollectible amounts are established. Such provisions for
uncollectible amounts are recorded when management believes that a related
receivable is not recoverable based on current estimates of expected discounted
cash flows. The Company records a write down of marketable securities when the
decline in market value is considered to be other than temporary. Change in the
value of the ineffective position of all open hedges is recognized in earnings
quarterly. The fair value of open hedging contracts is an estimated amount that
could be realized upon termination. The Company stock held in the deferred
compensation plan is treated as treasury stock and the carrying value of the
deferred compensation is adjusted to fair value each reporting period by a
charge or credit to operations in general and administrative expense.
LIQUIDITY AND CAPITAL RESOURCES
During the three months ended March 31, 2003, the Company spent $28.0
million on development, exploration and acquisitions. During the period, debt
and Trust Preferred increased by $6.7 million. At March 31, 2003, the Company
had $1.4 million in cash, total assets of $742.3 million and, including the
Trust Preferred as debt, a debt to capitalization (including debt, deferred
taxes and stockholders' equity) ratio of 65%. Excluding the Trust Preferred from
debt and equity, the debt to capitalization ratio was 59%. Available borrowing
capacity on
25
the Company's bank lines at March 31, 2003 was $25.2 million at the parent and
$24.0 million at Great Lakes. Long-term debt at March 31, 2003 totaled $374.8
million. This included $121.8 million of Parent bank borrowings, a net $78.5
million at Great Lakes, $69.3 million of 8.75% Notes, $20.7 million of 6%
Debentures and $84.4 million of Trust Preferred.
During the three months ended March 31, 2003, 129,000 shares of common
stock were exchanged for $880,000 of 6% Debentures. In addition, $400,000 face
amount of 5.75% Trust Preferred was repurchased for cash. A $150,000 gain on
retirement was recorded on the cash repurchase as the securities were acquired
at a discount and a conversion expense of $465,000 was recorded on the exchange.
The Company believes its capital resources are adequate to meet its
requirements for at least the next twelve months; however, future cash flows are
subject to a number of variables including the level of production and prices as
well as various economic conditions that have historically affected the oil and
gas business. There can be no assurance that internal cash flow and other
capital sources will provide sufficient funds to maintain planned capital
expenditures.
Cash Flow
The Company's principal sources of cash are operating cash flow and
bank borrowings. The Company's cash flow is highly dependent on oil and gas
prices. The Company has entered into hedging agreements covering approximately
80%, 70%, and 40% of anticipated production from proved reserves on a mcfe basis
for the remainder of 2003, 2004 and 2005, respectively. The $27.0 million of
capital expenditures in the three months ended March 31, 2003 was funded with
internal cash flow and bank borrowings. Net cash provided by operations for the
three months ended March 31, 2002 and 2003 was $20.7 million and $18.1 million,
respectively. Cash flow from operations was lower than the prior year with
significantly higher prices and volumes, lower exploration expense being
somewhat offset by higher direct operating expenses. Accounts receivable
increased $18.5 million from December 31, 2002 due to higher prices and volumes.
These receivables will be collected in the second quarter of 2003. Net cash used
in investing for the three months ended March 31, 2002 and 2003 was $24.4
million and $26.0 million, respectively. The 2002 period included $18.6 million
of additions to oil and gas properties. The 2003 period included $25.8 million
of additions to oil and gas properties partially offset by $3.1 million of IPF
receipts (net of fundings) and lower exploration expenditures. Net cash provided
by financing for the three months ended March 31, 2002 and 2003 was $942,000 and
$7.9 million, respectively. During the first three months of March 2003, total
debt, including Trust Preferred increased $6.7 million. Parent bank debt and
non-recourse bank debt increased $8.0 million, Subordinated Notes (8.75% Notes
and 6% Debentures) decreased $880,000 and the Trust Preferred decreased
$400,000. The net increase in debt was the result of timing of cash flows.
Capital Requirements
During the three months ended March 31, 2003, $27.0 million of capital
expenditures was funded with internal cash flow and bank borrowings. The Company
seeks to entirely fund its capital budget with internal cash flow. Based on the
2003 capital budget of $110.0 million, the Company will seek to increase
production and expand the reserve base.
Banking
The Company maintains two separate revolving bank credit facilities: a
$225.0 million Parent facility and a $275.0 million Great Lakes facility (of
which 50% is consolidated at Range). Each facility is secured by substantially
all the borrowers' assets. The Great Lakes facility is non-recourse to the
Company. As Great Lakes is 50% owned, half its borrowings are consolidated in
the Company'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 April 30, 2003, the Parent had a $170.0 million borrowing base of
which $58.2 million was available. Great Lakes, half of which is consolidated at
Range, had a $225.0 million borrowing base, of which $77.0 million was
available.
26
HEDGING
Oil and Gas Prices
The Company regularly enters into hedging agreements to reduce the
impact of oil and gas price fluctuations. The Company's current policy, when
futures prices justify, is to hedge 50% to 75% of projected production on a
rolling 12 to 24 month basis. At March 31, 2003, hedges were in place covering
76.7 Bcf of gas at prices averaging $4.05 per Mmbtu and 1.9 million barrels of
oil at prices averaging $24.82 per barrel. Their fair value at March 31, 2003
(the estimated amount that would be realized on termination based on contract
versus NYMEX prices) was a net unrealized pre-tax loss of $56.0 million. The
contracts expire monthly and cover approximately 80%, 70% and 40% of anticipated
production from proved reserves on a mcfe basis for the remainder of 2003, 2004
and 2005, respectively. Gains or losses on open and closed hedging transactions
are determined based on the difference between the 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 three months ended 2003 were $25.9
million and oil and gas revenues were increased by $11.7 million from hedging
for the three months ended March 31, 2002.
Interest Rates
At March 31, 2003, Range had $374.8 million of debt (including Trust
Preferred) outstanding. Of this amount, $174.5 million bore interest at fixed
rates averaging 7.0%. Senior debt and non-recourse debt totaling $200.3 million
bore interest at floating rates which averaged 3.3% at March 31, 2003. At times,
the Company enters into interest rate swap agreements to limit the impact of
interest rate fluctuations on its floating rate debt. At March 31, 2003, Great
Lakes had interest rate swap agreements totaling $100.0 million, 50% of which is
consolidated at the Company. These swaps consist of five agreements totaling
$35.0 million at rates averaging 4.6% which expire in June 2003, two agreements
totaling $45.0 million at 7.1% which expire in May 2004, and two agreements
totaling $20.0 million at rates averaging 2.3% which expire in December 2004.
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 March 31, 2003
was a net loss of $3.6 million, of which 50% is consolidated at the Company. The
30 day LIBOR rate on March 31, 2003 was 1.3%. A 1% increase or decrease in
short-term interest rates would cost or save the Company approximately $1.5
million in annual interest expense.
Capital Restructuring Program
The Company took a number of steps beginning in 1998 to strengthen its
financial position. These steps included the sale of assets and the exchange of
common stock for fixed income securities. These initiatives have helped reduce
Parent company bank debt from $365.2 million to $121.8 million and total debt
(including Trust Preferred) from $727.2 million to $374.8 million at March 31,
2003. While the Company's financial position has improved, management believes
debt remains too high. The Company believes it should further reduce debt as a
percentage of its capitalization. The Company currently believes it has
sufficient liquidity and cash flow to meet its obligations for the next 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.
27
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 three months of 2003, the Company received an average
of $23.64 per barrel of oil and $3.95 per mcf of gas after hedging compared to
$22.66 per barrel of oil and $3.26 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, inflation does not normally have a significant effect on
the Company. During 2002, the Company experienced a slight decline in certain
drilling and operational costs when compared to the prior year. Increases in
commodity prices can cause inflationary pressures specific to the industry to
also increase certain costs. The Company expects an increase in these costs in
2003.
RESULTS OF OPERATIONS
VOLUMES AND SALES DATA:
Three Months Ended
March 31,
-------------------------
2002 2003
---------- ----------
Production:
Crude oil and liquid (bbls) 534,165 583,140
Natural gas (mcfs) 10,214,311 10,358,359
Average daily production:
Crude oil (bbls) 4,890 5,434
NGLs (per bbls) 1,045 1,045
Natural gas (mcfs) 113,492 115,093
Total (mcfes) 149,103 153,969
Average sales prices (excluding hedging):
Crude oil (bbls) $ 18.80 $ 31.44
NGLs (bbls) $ 10.92 $ 20.17
Natural gas (mcfs) $ 2.28 $ 6.08
Average sales price (including hedging):
Crude oil (bbls) $ 22.66 $ 23.64
NGLs (bbls) $ 10.92 $ 20.17
Natural gas (mcfs) $ 3.26 $ 3.95
Total (mcfes) $ 3.30 $ 3.92
28
The following table identifies certain items included in the results of
operations and is presented to assist in comparison of the first quarter of 2003
to the same period of the prior year. The table should be read in conjunction
with the following discussions of results of operations (in thousands):
Three Months Ended
March 31,
--------------------
2002 2003
-------- --------
Increase (decrease) in revenues:
Write-down of marketable securities $ (369) $ --
Ineffective portion of hedges (1,699) 804
Gain (loss) from sales of assets (1) 88
Realized hedging gains (losses) 11,726 (25,890)
-------- --------
$ 9,657 $(24,998)
======== ========
Increase (decrease) to expenses:
Fair value deferred compensation adjustment $ 782 $ 385
Bad debt expense accrual -- 75
Adjustment to IPF valuation allowance 1,126 259
Ineffective portion of interest rate hedges 372 (71)
-------- --------
$ 2,280 $ 648
======== ========
Cumulative effect of change in
accounting principle (net of tax) $ -- $ 4,491
======== ========
Comparison of 2003 to 2002
Quarters Ended March 31, 2003 and 2002
Net income in the first quarter of 2003 totaled $9.5 million, compared
to $4.3 million in the prior year period. 2003 includes a favorable effect of
$4.5 million on adoption of a new accounting principle (see footnote 3) in
addition to a tax expense of $4.1 million versus a tax benefit in the prior year
of $3.1 million. Production increased to 154.0 Mmcfe per day, a 3% increase from
the prior year period. Production increased when compared to the prior year due
to higher production in the Appalachia and Southwest divisions and higher
production at West Cameron 45 somewhat offsetting the natural production
declines in other Gulf Coast wells. Revenues increased primarily due to an
increase in average prices per mcfe to $3.92. The average prices received for
oil increased 4% to $23.64 per barrel, increased 21% for gas to $3.95 per mcf
and increased 85% for NGLs to $20.17 per barrel. Production expenses increased
42% to $13.0 million as a result of significantly higher production taxes,
increased costs from new wells and higher other operating costs. Production
taxes averaged $0.08 per mcfe in 2002 versus $0.20 per mcfe in 2003. Operating
cost, including production taxes, per mcfe produced averaged $0.69 in 2002
versus $0.94 in 2003.
Transportation and processing revenues increased 33% to $1.0 million in
2003 with higher oil trading margins and higher gas prices. IPF recorded income
of $539,000, a decrease of $632,000 from the 2002 period. 2002 IPF expenses
included a $1.1 million unfavorable valuation allowance adjustment. IPF expenses
in 2003 include a $259,000 unfavorable valuation allowance. IPF revenue declined
from the previous year due to a smaller portfolio balance. During the quarter
ended March 31, 2003, IPF expenses included $258,000 of administrative costs and
$82,000 of interest, compared to prior year period administrative expenses of
$394,000 and interest of $253,000.
Exploration expense decreased $2.8 million to $2.5 million in 2003,
primarily due to lower dry hole costs of $3.1 million somewhat offset by higher
seismic costs. General and administrative expenses increased 8% or $376,000 to
$4.8 million in the quarter with higher legal fees, accounting and engineering
technical consulting costs, bad debt expenses and salary related expenses offset
by a lower deferred compensation adjustment. The fair value deferred
compensation adjustment included in general and administrative expense is
expense of $385,000 in
29
the three months ended 2003 and an expense of $782,000 in the same period of the
prior year. (See Note 11 to the consolidated financial statements).
Other income was $928,000 in 2003 and a loss of $2.1 million in 2002.
The 2003 period included $804,000 of ineffective hedging gains and $88,000 of
gains on asset sales. The 2002 period included $1.7 million of ineffective
hedging losses and a $369,000 write down of marketable securities. Interest
expense increased 3% to $5.5 million with higher mark to market swap interest
expense and amortization costs somewhat offset by falling interest rates and
lower outstanding debt balances. Total debt was $388.3 million and $374.8
million at March 31, 2002 and 2003, respectively. The average interest rates
(excluding hedging) were 5.3% and 5.0%, respectively, at March 31, 2002 and 2003
including fixed and variable rate debt.
Depletion, depreciation and amortization ("DD&A") increased 15% from
the first quarter of 2002. The per mcfe DD&A rate for the first quarter of 2003
was $1.51, a $0.16 increase from the rate for the first quarter of 2002 with
higher rates and an additional $1.1 million of accretion expense related to the
adoption of the new accounting principle (see footnote 3). The DD&A rate is
determined based on year-end reserves 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 2003 to approximate $1.50
per mcfe. The high DD&A rate will make it difficult for the Company to remain
profitable if commodity prices fall materially.
Income taxes were a benefit of $3.1 million in the first quarter of
2002 versus a tax expense of $4.1 million in the three months ended March 31,
2003. The quarter ended March 31, 2003 includes a $917,000 deferred tax expense
associated with prior periods' percentage depletion carryover.
30
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. The term "market risk" refers to the risk of
loss arising from adverse changes in oil and gas prices and interest rates. The
disclosures are not meant to be indicators of expected future losses, but rather
an indicator of reasonably possible losses. This forward-looking information
provides indicators of how the Company views and manages its ongoing market-risk
exposures. All of the Company's market-risk sensitive instruments were entered
into for purposes other than trading.
Commodity Price Risk. The Company's major market risk exposure is to
oil and gas prices. Realized prices are primarily driven by worldwide prices for
oil and spot market prices for North American gas production. Oil and gas prices
have been volatile and unpredictable for many years.
The Company periodically enters 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 counterparty. Hedging is
intended to reduce the impact of oil and gas price fluctuations. 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 and losses realized as a result of hedging are substantially offset in
the cash market when the commodity is delivered. Of the $56.0 million unrealized
pre-tax loss included in OCI at March 31, 2003, $41.8 million of losses 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 March 31, 2003, the Company had oil and gas hedges in place
covering 76.7 Bcf of gas and 1.9 million barrels of oil. Their fair value,
represented by the estimated amount that would be realized on termination, based
on contract versus NYMEX prices, approximated a net unrealized pre-tax loss of
$56.0 million at that date. These contracts expire monthly through December 2005
and cover approximately 80%, 70% and 40% of anticipated production from proved
reserves on a mcfe basis for the remainder of 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. Any ineffective portion of such hedges is recognized
in earnings as it occurs. Net realized losses relating to these derivatives for
the three months ended March 31, 2003 were $25.9 million and net realized gains
were $11.7 million for the three months ended March 31, 2002.
In the first three months of 2003, a 10% reduction in oil and gas
prices, excluding amounts fixed through hedging transactions, would have reduced
revenue by $7.9 million. If oil and gas future prices at March 31, 2003 had
declined 10%, the unrealized hedging loss at that date would have decreased
$40.1 million.
Interest rate risk. At March 31, 2003, the Company had $374.8 million
of debt (including Trust Preferred) outstanding. Of this amount, $174.5 million
bore interest at fixed rates averaging 7.0%. Senior debt and non-recourse debt
totaling $200.3 million bore interest at floating rates averaging 3.3%. At March
31, 2003 Great Lakes had 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 $1.8 million at that date. A 1% increase or decrease in
short-term interest rates would cost or save the Company approximately $1.5
million in annual interest expense.
31
ITEM 4. CONTROLS AND PROCEDURES.
Within the 90 days prior to the date of this report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the Company's Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Exchange Act Rule
13a-14. Based upon that evaluation, the Chief Executive Officer and the Chief
Financial Officer concluded that the Company's disclosure controls and
procedures are effective in timely alerting them to material information
relating to the Company (including its consolidated subsidiaries) required to be
included in the Company's periodic filings with the Securities and Exchange
Commission. No significant changes in the Company's internal controls or other
factors that could affect these controls have occurred subsequent to the date of
such evaluation.
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.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.
(a) Not applicable
(b) Not applicable
(c) At various times during the three months ended March 31, 2003,
the Company issued common stock in exchange for fixed income
securities. Shares of common stock issued in such exchanges
were exempt from registration under Section 3(a) (9) of the
Securities Act of 1933. The following table summarizes
exchanges during the three months ended March 31, 2003:
Face Amount ($000) Common Stock Issued (000's)
-------------------- ------------------------------
Three Months Ended Three Months Ended
Security Exchanged March 31, 2003 March 31, 2003
- ---------------------- -------------------- ------------------------------
6% Debentures $880 129
(d) Not applicable.
ITEM 3. NOT APPLICABLE
ITEM 4. NOT APPLICABLE
ITEM 5. NOT APPLICABLE
32
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 Exhibit 3.1.1 to the Company's
Registration Statement (File No. 33-31558)).
3.1.2 Certificate of Amendment of Certificate of Incorporation dated July 22,
1981 (incorporated by reference to Exhibit 3.1.2 to the Company's
Registration Statement (File No. 33-31558)).
3.1.3 Certificate of Amendment of Certificate of Incorporation dated
September 8, 1982 (incorporated by reference to Exhibit 3.1.3 to the
Company's Registration Statement (File No. 33-31558)).
3.1.4 Certificate of Amendment of Certificate of Incorporation dated December
28, 1988 (incorporated by reference to Exhibit 3.1.4 to the Company's
Registration Statement (File No. 33-31558)).
3.1.5 Certificate of Amendment of Certificate of Incorporation dated August
31, 1989 (incorporated by reference to Exhibit 3.1.5 to the Company's
Registration Statement (File No. 33-31558)).
3.1.6 Certificate of Amendment of Certificate of Incorporation dated May 30,
1991 (incorporated by reference to Exhibit 3.1.6 to the Company's
Registration Statement (File No. 333-20259)).
3.1.7 Certificate of Amendment of Certificate of Incorporation dated November
20, 1992 (incorporated by reference to Exhibit 3.1.7 to the Company's
Registration Statement (File No. 333-20257) as filed with the SEC on
January 23, 1997).
3.1.8 Certificate of Amendment of Certificate of Incorporation dated May 24,
1996 (incorporated by reference to Exhibit 3.1.8 to the Company's
Registration Statement (File No. 333-20257) as filed with the SEC on
January 23, 1997).
3.1.9 Certificate of Amendment of Certificate of Incorporation dated October
2, 1996 (incorporated by reference to Exhibit 3.1.9 to the Company's
Registration Statement (File No. 333-20257) as filed with the SEC on
January 23, 1997).
3.1.10 Restated Certificate of Incorporation as required by Item 102 of
Regulation S-T (incorporated by reference to Exhibit 3.1.10 to the
Company's Registration Statement (File No. 333-20257) as filed with the
SEC on January 23, 1997).
3.1.11 Certificate of Amendment of Certificate of Incorporation dated August
25, 1998 (incorporated by reference to Exhibit 3.1.11 to the Company's
Registration Statement (File No. 333-62439) as filed with the SEC on
August 28, 1998).
3.1.12* Certificate of Amendment of Certificate of Incorporation dated May
25, 2000.
3.2.1 By-Laws of the Company (incorporated by reference to Exhibit 3.2.1 to
the Company's Registration Statement (File No. 33-31558).
3.2.2 Amended and Restated By-laws of the Company dated May 24, 2001
(incorporated by reference to Exhibit 3.2.2 to the Company's Form 10K
(File No. 001-12209) as filed with the SEC on March 5, 2002).
10.1* $225,000,000 Second Amendment to Credit Agreement among Range Resources
Corporation, as Borrowers, certain parties, as lenders, Bank One,
Texas, N.A., as Administrative Agent, JP Morgan Chase Bank and Credit
Lyonnais, New York Branch, as Co-Syndication Agents and Fleet National
Bank and Fortis Capital Corporation as Co-Documentation Agents dated
January 24, 2003.
10.2* 225,000,000 Third Amendment to Credit Agreement among Range Resources
Corporation, as Borrowers, certain parties as Lenders, Bank One Texas,
N.A., as Administrative Agent, Chase JP Morgan Chase Bank and Credit
Lyonnais New York Branch as Co-Syndication Agents and Fleet National
Bank and Fortis Capital Corporation, as Co-Documentation Agents dated
April 1, 2003.
- ---------------------
* filed herewith
33
(b) Reports on Form 8/K
On March 5, 2003, the Company filed a Current Report on Form 8-K,
pursuant to Item 9 of Form 8-K, regarding the filing of the Company's
Form 10-K and the submission of certificates to the SEC by the
President and Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
34
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 thereunto duly authorized.
RANGE RESOURCES CORPORATION
By: /s/ EDDIE M. LEBLANC
-------------------------
Eddie M. LeBlanc
Chief Financial Officer
Date: May 7, 2003
35
I, John H. Pinkerton, certify that:
1. I have reviewed this quarterly report on Form 10-Q 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;
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;
4. The registrant's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to
ensure that material information relating to the
registrant, including its consolidated subsidiaries,
is made known to us by others within those entities,
particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's
disclosure controls and procedures as of a date
within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions
about the effectiveness of the disclosure controls
and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or
operation of internal controls which could adversely
affect the registrant's ability to record, process,
summarize and report financial data and have
identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant
role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated
in this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date
of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: May 7, 2003
/s/ JOHN H. PINKERTON
---------------------------------
John H. Pinkerton, President
36
I, Eddie M. LeBlanc, certify that:
1. I have reviewed this quarterly report on Form 10-Q 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;
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;
4. The registrant's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules
13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to
ensure that material information relating to the
registrant, including its consolidated subsidiaries,
is made known to us by others within those entities,
particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's
disclosure controls and procedures as of a date
within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions
about the effectiveness of the disclosure controls
and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officer and I have
disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's
board of directors (or persons performing the equivalent
function):
d) all significant deficiencies in the design or
operation of internal controls which could adversely
affect the registrant's ability to record, process,
summarize and report financial data and have
identified for the registrant's auditors any material
weaknesses in internal controls; and
e) any fraud, whether or not material, that involves
management or other employees who have a significant
role in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated
in this quarterly report whether or not there were significant
changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date
of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: May 7, 2003
/s/ EDDIE M. LEBLANC
---------------------------------
Eddie M. LeBlanc, Chief Financial Officer
37
EXHIBIT INDEX
Exhibit
Number Description of Exhibit
- ------- ---------------------------------------------------------------------
3.1.1 Certificate of Incorporation of Lomak dated March 24, 1980
(incorporated by reference to Exhibit 3.1.1 to the Company's
Registration Statement (File No. 33-31558)).
3.1.2 Certificate of Amendment of Certificate of Incorporation dated July
22, 1981 (incorporated by reference to Exhibit 3.1.2 to the Company's
Registration Statement (File No. 33-31558)).
3.1.3 Certificate of Amendment of Certificate of Incorporation dated
September 8, 1982 (incorporated by reference to Exhibit 3.1.3 to the
Company's Registration Statement (File No. 33-31558)).
3.1.4 Certificate of Amendment of Certificate of Incorporation dated
December 28, 1988 (incorporated by reference to Exhibit 3.1.4 to the
Company's Registration Statement (File No. 33-31558)).
3.1.5 Certificate of Amendment of Certificate of Incorporation dated August
31, 1989 (incorporated by reference to Exhibit 3.1.5 to the Company's
Registration Statement (File No. 33-31558)).
3.1.6 Certificate of Amendment of Certificate of Incorporation dated May
30, 1991 (incorporated by reference to Exhibit 3.1.6 to the Company's
Registration Statement (File No. 333-20259)).
3.1.7 Certificate of Amendment of Certificate of Incorporation dated
November 20, 1992 (incorporated by reference to Exhibit 3.1.7 to the
Company's Registration Statement (File No. 333-20257) as filed with
the SEC on January 23, 1997).
3.1.8 Certificate of Amendment of Certificate of Incorporation dated May
24, 1996 (incorporated by reference to Exhibit 3.1.8 to the Company's
Registration Statement (File No. 333-20257) as filed with the SEC on
January 23, 1997).
3.1.9 Certificate of Amendment of Certificate of Incorporation dated
October 2, 1996 (incorporated by reference to Exhibit 3.1.9 to the
Company's Registration Statement (File No. 333-20257) as filed with
the SEC on January 23, 1997).
3.1.10 Restated Certificate of Incorporation as required by Item 102 of
Regulation S-T (incorporated by reference to Exhibit 3.1.10 to the
Company's Registration Statement (File No. 333-20257) as filed with
the SEC on January 23, 1997).
3.1.11 Certificate of Amendment of Certificate of Incorporation dated August
25, 1998 (incorporated by reference to Exhibit 3.1.11 to the
Company's Registration Statement (File No. 333-62439) as filed with
the SEC on August 28, 1998).
3.1.12* Certificate of Amendment of Certificate of Incorporation dated May
25, 2000.
3.2.1 By-Laws of the Company (incorporated by reference to Exhibit 3.2.1 to
the Company's Registration Statement (File No. 33-31558).
3.2.2 Amended and Restated By-laws of the Company dated May 24, 2001
(incorporated by reference to Exhibit 3.2.2 to the Company's Form 10K
(File No. 001-12209) as filed with the SEC on March 5, 2002).
10.1* $225,000,000 Second Amendment to Credit Agreement among Range
Resources Corporation, as Borrowers, certain parties, as lenders,
Bank One, Texas, N.A., as Administrative Agent, JP Morgan Chase Bank
and Credit Lyonnais, New York Branch, as Co-Syndication Agents and
Fleet National Bank and Fortis Capital Corporation as
Co-Documentation Agents dated January 24, 2003.
10.2* 225,000,000 Third Amendment to Credit Agreement among Range Resources
Corporation, as Borrowers, certain parties as Lenders, Bank One
Texas, N.A., as Administrative Agent, Chase JP Morgan Chase Bank and
Credit Lyonnais New York Branch as Co-Syndication Agents and Fleet
National Bank and Fortis Capital Corporation, as Co-Documentation
Agents dated April 1, 2003.
- ----------------------------
* filed herewith
38