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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 June 30, 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 (I.R.S. Employer
of incorporation or organization) Identification No.)
777 MAIN STREET, SUITE 800
FT. WORTH, TEXAS
(Address of principal executive offices)
76102
(Zip Code)
Registrant's telephone number, including area code: (817) 870-2601
Former name, former address and former fiscal year, 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 [ ]
56,002,697 Common Shares were outstanding on July 31, 2003.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
The financial statements included herein should be read in conjunction
with latest Form 10-K for Range Resources Corporation (the "Company"). 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, including selected notes, have been
prepared in accordance with the applicable rules of the Securities and Exchange
Commission (the "SEC") and do not include all of the information and disclosures
required by accounting principles generally accepted in the United States for
complete financial statements.
2
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
DECEMBER 31, JUNE 31,
2002 2003
------------ -----------
ASSETS (Unaudited)
Current assets
Cash and equivalents $ 1,334 $ 1,309
Accounts receivable 26,832 39,394
IPF receivables, net (Note 2) 6,100 5,500
Unrealized derivative gain (Note 2) 4 16
Inventory and other 3,084 2,301
Deferred tax asset, net (Note 13) - 25,284
---------- ----------
37,354 73,804
---------- ----------
IPF receivables, net (Note 2) 18,351 10,767
Unrealized derivative gain (Note 2) 13 99
Oil and gas properties, successful efforts method (Note 16) 1,154,549 1,242,089
Accumulated depletion and depreciation (590,143) (606,789)
---------- ----------
564,406 635,300
---------- ----------
Transportation and field assets (Note 2) 34,143 35,714
Accumulated depreciation and amortization (16,071) (17,520)
---------- ----------
18,072 18,194
---------- ----------
Deferred tax asset, net (Note 13) 15,785 -
Other (Note 2) 4,503 5,273
---------- ----------
$ 658,484 $ 743,437
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 27,044 $ 26,101
Asset retirement obligation (Note 3) - 16,399
Accrued liabilities 9,678 9,781
Accrued interest 4,449 4,342
Unrealized derivative loss (Note 2) 26,035 54,304
---------- ----------
67,206 110,927
---------- ----------
Senior debt (Note 6) 115,800 110,600
Non-recourse debt (Note 6) 76,500 73,500
Subordinated notes (Note 6) 90,901 89,521
Trust preferred securities - manditorily redeemable security of subsidiary 84,840 84,440
Deferred tax credits, net (Note 13) - 1,991
Unrealized derivative loss (Note 2) 9,079 29,186
Deferred compensation liability (Note 11) 8,049 11,262
Asset retirement obligation (Note 3) - 38,825
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, 550 559
54,991,611 and 55,952,379 issued and outstanding, respectively
Capital in excess of par value 391,082 396,302
Stock held by employee benefit trust, and 1,324,537
1,605,992 shares, respectively, at cost (Note 11) (6,188) (7,867)
Retained earnings (deficit) (158,059) (144,014)
Deferred compensation expense (125) (157)
Other comprehensive income (loss) (Note 2) (21,151) (51,638)
---------- ----------
206,109 193,185
---------- ----------
$ 658,484 $ 743,437
========== ==========
SEE ACCOMPANYING NOTES
3
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED, IN THOUSANDS EXCEPT PER SHARE DATA)
Three Months Six Months
Ended June 30, Ended June 30,
----------------------- -----------------------
2002 2003 2002 2003
---------- ---------- ---------- ----------
Revenues
Oil and gas sales $ 48,626 $ 55,273 $ 92,909 $ 109,603
Transportation and processing 924 940 1,698 1,967
IPF income (Note 2) 992 428 2,163 967
Gain (loss) on retirement of securities (Note 18) 845 (10) 2,030 140
Other (1,235) (1,913) (3,244) (985)
---------- ---------- ---------- ----------
50,152 54,718 95,556 111,692
---------- ---------- ---------- ----------
Expenses
Direct operating 9,938 12,644 19,142 25,672
IPF 2,178 568 3,950 1,186
Exploration 2,172 2,687 7,443 5,140
General and administrative (Note 11) 4,733 5,313 9,203 10,159
Debt conversion and extinguishment expense (Note 6) - - - 465
Interest expense and dividends on trust preferred 6,274 5,175 11,631 10,719
Depletion, depreciation and amortization 19,304 21,276 37,404 42,243
---------- ---------- ---------- ----------
44,599 47,663 88,773 95,584
---------- ---------- ---------- ----------
Income before income taxes and accounting change 5,553 7,055 6,783 16,108
Income taxes (Note 13)
Current 45 (6) 45 (2)
Deferred (1,802) 2,470 (4,913) 6,556
---------- ---------- ---------- ----------
(1,757) 2,464 (4,868) 6,554
---------- ---------- ---------- ----------
Income before cumulative effect of change in
accounting principle 7,310 4,591 11,651 9,554
Cumulative effect of change in accounting principle
(net of taxes of $2.4 million) (Note 3) - - - 4,491
---------- ---------- ---------- ----------
Net income $ 7,310 $ 4,591 $ 11,651 $ 14,045
========== ========== ========== ==========
Comprehensive income (loss) (Note 2) $ (1,155) $ (10,594) $ (24,227) $ (16,442)
========== ========== ========== ==========
Earnings per share (Note 14)
Before cumulative effect of change in
accounting principle - basic $ 0.14 $ 0.08 $ 0.22 $ 0.18
========== ========== ========== ==========
- diluted $ 0.13 $ 0.08 $ 0.22 $ 0.17
========== ========== ========== ==========
After cumulative effect of change in
accounting principle - basic $ 0.14 $ 0.08 $ 0.22 $ 0.26
========== ========== ========== ==========
- diluted $ 0.13 $ 0.08 $ 0.22 $ 0.25
========== ========== ========== ==========
SEE ACCOMPANYING NOTES.
4
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED, IN THOUSANDS)
SIX MONTHS ENDED JUNE 30,
-------------------------
2002 2003
---------- ----------
CASH FLOWS FROM OPERATIONS
Net income $ 11,651 $ 14,045
Adjustments to reconcile net income to
net cash provided by operations:
Cumulative effect of change in accounting principle - (4,491)
Deferred income tax expense (benefit) (4,913) 6,556
Depletion, depreciation and amortization 37,404 42,243
Write-down of marketable securities 1,220 -
Unrealized hedging (gains) losses 2,090 1,188
Allowance for bad debts 2,567 708
Exploration expense 7,443 5,140
Amortization of deferred issuance costs 411 446
Gain on retirement of securities (2,055) (140)
Debt conversion and extinguishment expense - 465
Deferred compensation adjustments 2,876 1,596
Gain on sale of assets (26) (157)
Changes in working capital:
Accounts receivable (3,511) (12,857)
Inventory and other 556 783
Accounts payable 1,446 535
Accrued liabilities (3,702) 1,436
---------- ----------
Net cash provided by operations 53,457 57,496
---------- ----------
CASH FLOWS FROM INVESTING
Oil and gas properties (37,692) (50,892)
Field service assets (912) (1,592)
IPF investments (2,729) (1,088)
IPF repayments 4,263 8,698
Exploration expense (7,443) (5,140)
Asset sales 20 302
---------- ----------
Net cash used in investing (44,493) (49,712)
---------- ----------
CASH FLOWS FROM FINANCING
Borrowings on senior debt and non-recourse debt 67,900 78,900
Repayments on senior debt and non-recourse debt (71,400) (87,100)
Debt issuance costs (952) (684)
Other debt repayments (4,981) (744)
Issuance of common stock 1,214 1,819
---------- ----------
Net cash used in financing (8,219) (7,809)
---------- ----------
Increase (decrease) in cash and cash equivalents 745 (25)
Cash and equivalents, beginning of period 3,380 1,334
---------- ----------
Cash and equivalents, end of period $ 4,125 $ 1,309
========== ==========
SEE ACCOMPANYING NOTES.
5
RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(1) ORGANIZATION AND NATURE OF BUSINESS
The Company is engaged in the development, exploration and acquisition
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 drilling and complementary
acquisitions. The Company 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. 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. These financial statements are unaudited but, in
the opinion of management, reflect all adjustments necessary for a fair
presentation of the results for the periods presented. All such adjustments are
of a normal recurring nature unless disclosed otherwise.
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; while 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 $826,000 at December 31, 2002 and June 30, 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 small publicly
traded exploration and production company. Based on its analysis of the
investment and its assessment 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. For the three months and
the six months ended June 30, 2002, $851,000 and $1.2 million, respectively, was
recorded as a reduction to Other revenues. This exploration and production
company is currently involved in Chapter 11 bankruptcy proceedings.
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 that relate to the return on investment are
recognized as income; while remaining receipts reduce receivables. No interest
income is recorded on impaired receivables and any payments received that are
applicable to impaired receivables are applied as a reduction of the receivable.
Receivables classified as current represent the return on 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 June
30, 2003, IPF's valuation allowance totaled $12.6 million and $10.7 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 second quarter of 2003, IPF revenues were $428,000
offset by $209,000 of general and administrative costs, $60,000 of interest and
a $299,000 increase in the valuation allowance. During the same period of the
prior year, revenues were $992,000 offset by $476,000 of general and
administrative expenses, $261,000 of interest and a $1.4 million increase in the
valuation allowance. IPF's net receivables have declined from a high of $77.2
million in 1998 to $16.3 million at June 30, 2003, as IPF has focused on
recovering its investment. The Company is continually assessing its strategic
alternatives with regard to IPF. Since 2001, IPF has not entered into any new
client financing agreements and 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 depletion, depreciation an amortization ("DD&A") rates were $1.41 and $1.48
per mcfe in the quarters ended June 30, 2002 and 2003, respectively, and $1.38
and $1.49 for the six months ended June 30, 2002 and 2003, respectively.
Unproved properties had a net book value of $19.0 million and $17.5 million at
December 31, 2002 and June 30, 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, 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.
7
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 June 30, 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 cost 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 June 30, 2003, these capitalized costs
totaled $3.0 million and $3.3 million, respectively. At June 30, 2003, Other
assets included $3.3 million unamortized debt issuance costs, $588,000 of
long-term deposits, and $1.4 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 June 30, 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.
Historically, the Company's hedging program was based on fixed price swaps. In
the second quarter of 2003, the hedging program was modified to include collars
which establish a minimum floor price and a predetermined ceiling price. Gains
or losses on open contracts are recorded in Other comprehensive income (loss)
("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. In prior
periods, certain of the interest rate swaps did not qualify as interest rate
hedges which required the changes in fair value to be reported in interest
expense.
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 OCI and
reclassified to earnings when the transaction is closed (settled). Changes in
the value of the ineffective portion of all open hedges are recognized in
earnings as they occur. At June 30, 2003, the Company reflected an unrealized
net pre-tax hedging loss on its balance sheet of $82.0 million. This accounting
can greatly increase the volatility of earnings and stockholders' equity for
companies that have hedging programs, such as the Company's hedging program.
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 $82.0 million unrealized pre-tax loss
at June 30, 2003, $53.0 million of losses would be reclassified to earnings over
the next twelve month period and $29.0 million for the periods thereafter, if
prices remained constant. Actual amounts that will be reclassified will vary as
a result of future 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 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
8
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 $463,000 and $2.1 million for the three months
ended June 30, 2002 and June 30, 2003, respectively, and a loss of $2.2 million
and $1.3 million for the six months ended June 30, 2002 and 2003, respectively.
Interest expense includes ineffective interest hedging losses of $300,000 and a
gain of $154,000 for the three months ended June 30, 2002 and June 30, 2003, and
gains of $72,000 and $83,000 for the six months ended June 30, 2002 and 2003,
respectively. Unrealized hedging losses at June 30, 2003 are shown on the
Company's balance sheet as net unrealized hedging losses of $83.4 million
(including $1.4 million of losses on interest rate swaps) and OCI losses of
$51.6 million (net of taxes) (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 Six Months Ended
June 30, June 30,
---------------------- ------------------------
2002 2003 2002 2003
---------- --------- -------- ---------
Net income $ 7,310 $ 4,591 $ 11,651 $ 14,045
Net amount of hedging (gain) loss
reclassed to earnings (3,639) 15,365 (15,365) 41,255
Change in unrealized losses, net (4,899) (30,393) (19,700) (71,618)
Defaulted hedge contracts, net - - (672) -
Unrealized loss (gain) from available-for-sale
securities 73 (157) (141) (124)
---------- --------- -------- ---------
Comprehensive income (loss) $ (1,155) $ (10,594) $(24,227) $ (16,442)
========== ========= ======== =========
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 ("APB") 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 $845,000
to revenue in the three months and $2.0 million in the six months ended June 30,
2002, with no change to reported net income.
In January 2003, the FASB issued Interpretation No. 46 "Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51" (the "Interpretation"). The Interpretation will significantly change
whether entities included in its scope are consolidated by their sponsors,
transferors, or investors. The Interpretation introduces a new consolidation
model - the variable interest model - which determines control (and
consolidation) based on potential variability in gains and losses of the entity
being evaluated for consolidation. These provisions apply immediately to
variable interests in VIE's created after January 15, 2003 and are effective
9
beginning in the third quarter of 2003 for VIE's in which the Company holds a
variable interest that it acquired prior to February 1, 2003. The Company is
still evaluating the impact of this new interpretation.
In May 2003, the FASB issued Statement of Financial Accounting
Standards No. 150 "Accounting or Certain Financial Instruments with
Characteristics of Both Liabilities and Equity" ("SFAS 150"). SFAS 150
established standards for classification and measurement in the statement of
financial position of certain financial instruments with characteristics of both
liabilities and equity. It requires classification of a financial instrument
that is within its scope as a liability (or an asset in some circumstances).
SFAS 150 is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise is effective at the beginning of the first interim
period beginning after June 15, 2003. As the Company's 5-3/4% Trust Preferred
Securities is currently presented as a long-term liability in the consolidated
financial statements, the adoption of SFAS 150 is not expected to have a
material impact on the Company's consolidated financial statements.
The FASB and representatives of the accounting staff of the SEC are
engaged in discussions on the issue of whether the FASB's No. 141 and 142,
issued effective for June 30, 2001, called for mineral rights held under lease
or other contractual arrangements to be classified in the balance sheet as
intangible assets and accompanied by specific footnote disclosures.
Historically, the Company and all other oil and gas companies have included the
cost of these oil and gas leasehold interests as part of oil and gas properties.
Although, most of the Company's oil and gas property interests are held under
oil and gas leases, this interpretation, if adopted, would not have a material
impact on the Company's financial condition or its results of operations.
In the event this interpretation is adopted, a substantial portion of
acquisition costs of oil and gas properties since June 30, 2001 would be
separately classified on the balance sheets as intangible assets. As of June 30,
2003, the Company has expended approximately $23.6 million on the acquisition of
oil and gas properties since June 30, 2001. Some additional direct costs of
other oil and gas leases acquired since that date could also be categorized as
intangible under this interpretation. Results of operations would not be
affected by this interpretation, if adopted, since these costs would continue to
be depleted in accordance with successful efforts accounting for oil and gas
companies. Another possible effect of this interpretation, if adopted, could be
a change in some of the financial measurements used in financial covenants of
debt instruments that focus on tangible assets. The Company does not believe
that its debt covenants would be materially affected by the adoption of this
accounting interpretation.
PROFORMA STOCK BASED COMPENSATION
The Company has adopted the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation" ("SFAS 123"). 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. If compensation cost had been determined
based on the fair value at the grant date for awards in the three months and the
six months ended June 30, 2002 and 2003, consistent with the provisions of SFAS
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):
10
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -----------------------
2002 2003 2002 2003
---------- ---------- ---------- ----------
Net income, as reported - $ 7,310 $ 4,591 $ 11,651 $ 14,045
Deduct: Total stock based
employee compensation
fair value based method
for all awards, net of
related tax effects 346 428 549 826
---------- ---------- ---------- ----------
Pro forma net income $ 6,964 $ 4,163 $ 11,102 $ 13,219
========== ========== ========== ==========
Earnings per share:
Basic-as reported $ 0.14 $ 0.08 $ 0.22 $ 0.26
Basic-pro forma $ 0.13 $ 0.08 $ 0.21 $ 0.24
Diluted-as reported $ 0.13 $ 0.08 $ 0.22 $ 0.25
Diluted-pro forma $ 0.13 $ 0.07 $ 0.21 $ 0.24
(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 and
increased basis. 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 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 in the six months ended June 30, 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), including an associated proforma asset retirement
obligation on that date of $48.3 million, are presented below (in thousands,
except per share data):
11
Pro Forma Pro Forma
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- ---------------------------
2002 2003 2002 2003
------------ ------------ ------------ ------------
Net income $ 7,029 $ 4,591 $ 15,715 $ 14,045
Earnings per share - basic $ 0.13 $ 0.08 $ 0.30 $ 0.26
- diluted $ 0.13 $ 0.08 $ 0.29 $ 0.25
A reconciliation of the Company's liability for plugging and
abandonment costs for the six months ended June 30, 2003 is as follows (in
thousands):
Asset retirement obligation, December 31, 2002 $ -
Cumulative effect adjustment 51,390
Liabilities incurred 2,011
Liabilities settled (448)
Accretion expense 2,271
------------
Asset retirement obligation, June 30, 2003 $ 55,224
============
(4) ACQUISITIONS
Acquisitions are accounted for under the purchase method. Purchase
prices are assigned to acquired assets and assumed liabilities based on their
estimated fair value at acquisition. The Company purchased various properties
for $2.7 million and $9.7 million during the six months ended June 30, 2002 and
2003, respectively. These purchases include $75,000 and $6.3 million for proved
oil and gas reserves, respectively, while the remainder represents unproved
acreage purchases.
(5) SUPPLEMENTAL CASH FLOW INFORMATION
Six Months Ended
June 30,
-----------------------
2002 2003
---------- ----------
(in thousands)
Non-cash investing and financing activities:
Common stock issued
Under benefit plans $ 1,528 $ 1,958
Exchanged for fixed income securities 8,359 1,370
Cash used in operating activities:
Income taxes paid - -
Interest paid $ 11,889 $ 10,596
The Company has and will continue to consider exchanging common stock
or equity-linked securities for debt, despite the 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.
12
(6) INDEBTEDNESS
The Company had the following debt and 5-3/4% Trust Convertible
Preferred Securities ("Trust Preferred Securities") outstanding as of the dates
shown (in thousands). Interest rates at June 30, 2003, excluding the impact of
interest rate swaps, are shown parenthetically:
December 31, June 30,
2002 2003
------------ ----------
Senior debt:
Senior Credit Facility (2.9%) $ 115,800 $ 110,600
---------- ----------
Non-recourse debt:
Great Lakes Credit Facility (2.9%) 76,500 73,500
---------- ----------
Subordinated debt:
8-3/4% Senior Subordinated Notes due 2007 69,281 68,781
6% Convertible Subordinated Debentures due 2007 21,620 20,740
---------- ----------
90,901 89,521
---------- ----------
Total debt 283,201 273,621
---------- ----------
Trust Preferred Securities- manditorily redeemable securities
of subsidiary 84,840 84,440
---------- ----------
Total $ 368,041 $ 358,061
========== ==========
Interest paid in cash during the three months ended June 30, 2002 and
2003 totaled $3.8 million and $3.5 million, respectively. Interest paid in cash
during the six months ended June 30, 2002 and 2003 totaled $11.9 million and
$10.6 million, respectively. No interest expense was capitalized during the
three months or the six months ended June 30, 2002 and 2003.
SENIOR CREDIT FACILITY
In 2002, the Company entered into an amended and restated $225.0
million secured revolving bank facility (the "Senior Credit Facility") which is
secured by substantially all of the assets of the Company (excluding Great
Lakes). The Senior Credit Facility provides for a borrowing base subject to
redeterminations semi-annually each April and October and pursuant to certain
unscheduled redeterminations. As of June 30, 2003, the outstanding balance under
the Senior Credit Facility was $110.6 million and there was approximately $59.4
million of borrowing capacity available. At the Company's election, the
borrowing base may be increased by up to $10 million during any six month
borrowing base period based on a percentage of the face value of subordinated
debt retired by the Company. The loan matures on January 1, 2007. Borrowings
under the Senior Credit Facility can either be base rate loans or LIBOR loans.
On all base rate loans, the rate per annum is equal to the lesser of (i) the
maximum rate (the "weekly ceiling" as defined in Section 303 of the Texas
Finance Code or other applicable laws if greater) (the "Maximum Rate") or, (ii)
the sum of (A) the higher of (1) the prime rate for such date, or (2) the sum of
the federal funds effective rate for such date plus one-half of one percent
(.50%) per annum, plus a base rate margin of between .25% to 1.0% per annum
depending on the total outstanding under the Senior Credit Facility relative to
the borrowing base under the Senior Credit Facility. On all LIBOR loans, the
Company pays a varying rate per annum equal to the lesser of (i) the Maximum
Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B)
one minus the reserve requirement applicable to such interest period, plus a
LIBOR margin of between 1.50% and 2.25% per annum depending on the total
outstanding under the Senior Credit Facility relative to the borrowing base
under the Senior Credit Facility. The Company may elect, from time to time, to
convert all or any part of its LIBOR loans to base rate loans or to convert all
or any part of its base rate loans to LIBOR loans. The weighted
13
average interest rate was 4.0% and 3.2% for the three months ended June 30, 2002
and 2003 and 4.1% and 3.3% for the six months ended June 30, 2002 and 2003,
respectively. A commitment fee is paid on the undrawn balance based on an annual
rate of 0.375% to 0.50%. At June 30, 2003, the commitment fee was 0.375% and the
interest rate margin was 1.75%. At July 31, 2003, the interest rate was 2.6%.
GREAT LAKES CREDIT FACILITY
The Company consolidates its proportionate share of borrowings on the
Great Lakes' $275.0 million secured revolving bank facility (the "Great Lakes
Credit Facility"). The Great Lakes Credit Facility is non-recourse to the
Company and provides for a borrowing base subject to redeterminations
semi-annually each April and October and pursuant to certain unscheduled
redeterminations. As of June 30, 2003, the Company's portion of the outstanding
balance owed under the Great Lakes Credit Facility was $73.5 million. The loan
matures on January 1, 2007. Any advance under the commitment may be a base rate
loan or a Eurodollar loan. On all base rate loans the Company pays a varying
rate per annum equal to the lesser of (i) the maximum nonusurious rate of
interest under applicable law, or (ii) the sum of the base rate plus a base rate
margin of between .25% to .75% per annum depending on the amounts outstanding on
the loan, plus all outstanding letters of credit, divided by the borrowing base
under the Great Lakes Credit Facility. On all Eurodollar loans, the Company pays
a varying rate per annum equal to the lesser of (i) the maximum nonusurious rate
of interest under applicable law, or (ii) the Eurodollar rate plus a Eurodollar
margin of between 1.50% to 2.0% per annum depending on the amounts outstanding
on the loan, plus all outstanding letters of credit, divided by the borrowing
base under the Great Lakes Credit Facility. Great Lakes may elect, from time to
time, to convert all or any part of its Eurodollar loans to base rate loans or
to convert all or any part of its base rate loans to Eurodollar loans. Cash
distributions to members of the joint venture are limited by a covenant
contained in the Great Lakes Credit Facility. A commitment fee is paid on the
undrawn balance at an annual rate of 0.25% to 0.50%. At June 30, 2003, the
commitment fee was 0.50% and the interest rate margin was 1.75%. The average
interest rate on the Great Lakes Credit Facility, excluding hedges, was 3.9% and
3.1% for the three months ended June 30, 2002 and 2003, respectively, and 3.9%
and 3.2% for the six months then ended, respectively. After hedging (see Note
7), the rate was 6.8% and 5.5% for the three months ended June 30, 2002 and
2003, respectively, and 6.8% and 5.6% for the six months ended June 30, 2002 and
2003, respectively. At July 31, 2003, the interest rate was 2.9% excluding
hedges and 5.0% after hedging.
8-3/4% SENIOR SUBORDINATED NOTES DUE 2007
In 1997, the Company sold $125 million in aggregate principal amount of
its 8-3/4% Senior Subordinated Notes due 2007 (the "8-3/4% Notes"). Interest on
the 8-3/4% Notes accrues at the rate of 8-3/4% per annum and is payable
semi-annually in arrears in January and July of each year. The 8-3/4% Notes
mature on January 15, 2007, unless previously redeemed. The 8-3/4% Notes are
subject to redemption at the Company's option, in whole or in part, at
redemption prices from 102.9% of the principal amount as of June 30, 2003, and
declining to 100% in 2005. The 8-3/4% Notes are the Company's unsecured general
obligations and are subordinated to all of the Company's senior indebtedness.
The 8-3/4% Notes are guaranteed on a senior subordinated basis by certain of the
Company's subsidiaries and each guarantor is one of the Company's wholly owned
subsidiaries. The guarantees are full, unconditional, and joint and several.
During the three month period ended June 30, 2003, the Company
repurchased $500,000 of the 8-3/4% Notes. During the three month period ended
June 30, 2002, the Company repurchased $5.0 million of the 8-3/4% Notes at a
discount. Only cash repurchases are reflected on the cash flow statement. The
net gain on all exchanges and repurchases is included as a Gain on retirement of
securities on the Consolidated Statement of Operations. As of July 31, 2003,
$68.8 million of the 8-3/4% Notes was outstanding. On July 21, 2003, the Company
announced its election to redeem all of its outstanding 8-3/4% Notes on August
20, 2003. The 8-3/4% Notes are being called at 102.9% of principal amount, plus
accrued interest. Interest on the notes ceases to accrue on the redemption date.
The aggregate redemption price, including the premium, will be $70.8 million.
The redemption was financed by the issuance of the 7-3/8% Notes.
14
6% CONVERTIBLE SUBORDINATED DEBENTURES DUE 2007
In 1996, the Company sold $55.0 million aggregate principal amount of
6% Convertible Subordinated Debentures due 2007 (the "6% Debentures"). Interest
on the 6% Debentures is payable semi-annually in February and August of each
year. The 6% Debentures are convertible into shares of the Company's common
stock at the option of the holder at any time prior to maturity, unless
previously redeemed or repurchased, at a conversion price of $19.25 per share,
subject to adjustment in certain events. The 6% Debentures will mature in 2007.
The 6% Debentures are subject to redemption at the Company's option, in whole or
in part, at redemption prices from 102.5% of the principal amount as of June 30,
2003, and declining to 101.0% in 2006. Upon a change of control, the Company is
required to offer to repurchase each holder's 6% Debenture at a purchase price
equal to 100% of the principal amount thereof, plus accrued and unpaid interest
to the date of repurchase. The 6% Debentures are unsecured general obligations
and are the Company's subordinated to all of the Company's senior indebtedness.
During the three months ended June 30, 2002, $5.6 million of 6%
Debentures were retired at a discount in exchange for 918,700 shares of common
stock. During the six months ended June 30, 2002, $7.1 million of 6% Debentures
were retired at a discount in exchange for 1,165,700 shares of common stock and
$15,000 were repurchased for cash at a discount. During the six month period
ended June 30, 2003, $880,000 was 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 July 31, 2003, $20.7 million
of the 6% Debentures was outstanding.
5-3/4%TRUST PREFERRED SECURITIES - MANDITORILY REDEEMABLE SECURITIES OF
SUBSIDIARY
In 1997, the Company issued $120.0 million of the Trust Preferred
Securities through a newly-formed affiliate Lomak Financing Trust (the "Trust").
The Trust issued 2,400,000 shares of the Trust Preferred Securities at $50 per
share. Each Trust Preferred Security is convertible at the holder's option into
shares of the Company's common stock, at a conversion price of $23.50 per share.
The Trust invested the $120 million of proceeds in the 5-3/4%
convertible junior subordinated debentures (the "Junior Debentures"). The sole
assets of the Trust are the Junior Debentures. The Junior Debentures and the
related Trust Preferred Securities mature in November 2027. The Company and the
Trust may redeem the Junior Debentures and the Trust Preferred Securities,
respectively, in whole or in part. As of June 30, 2003, the price at which these
redemptions could be made was 102.9% of the principal amount. The premium
declines proportionally every 12 months until November 2007, when the redemption
price becomes fixed at 100% of the principal amount. If any Junior Debentures
are redeemed prior to the scheduled maturity date, the Trust must redeem Trust
Preferred Securities having an aggregate liquidation amount equal to the
aggregate principal amount of the Junior Debentures the Company redeems.
The Company has guaranteed the payments of distributions and other
payments on the Trust Preferred Securities only if and to the extent that the
Trust has funds available. The Company's guarantee, when taken together with the
Company's obligation under the Junior Debentures and related indenture and
declaration of trust, provide a full and unconditional guarantee on a
subordinated basis of amounts due on the Trust Preferred Securities.
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 Senior Credit Facility as described below. During the six
months ended June 30, 2002, $2.4 million of Trust Preferred Securities were
retired at a discount in exchange for 283,200 shares of common stock. During the
six months ended June 30, 2003, the Company repurchased for cash $400,000 of the
Trust Preferred Securities at a discount. On July 31, 2003, $84.4 million of the
Trust Preferred Securities was outstanding.
INDUCED CONVERSIONS
In September 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 No. 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
15
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, 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 discount to face value. Under the provisions of
SFAS 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 discounts to face value, an expense
will be recorded. There will be no difference in Stockholders' equity from the
change in methods of recording the transactions.
DEBT COVENANTS
The debt agreements contain covenants relating to net worth, working
capital, dividends and financial ratios. The Company was in compliance with all
covenants at June 30, 2003. Under the most restrictive covenant, which is
embodied in the 8-3/4% Notes, approximately $560,000 of restricted payments
could be made at June 30, 2003. Under the Senior Credit Facility, common
dividends are permitted. Dividends on the Trust Preferred Securities may not be
paid unless certain ratio requirements are met. The Senior Credit Facility
provides for a restricted payment basket of $20.0 million plus 50% of net income
(excluding Great Lakes) plus 66-2/3% of distributions, dividends or payments of
debt from or proceeds from sales of equity interests of Great Lakes plus 66-2/3%
of net cash proceeds from common stock issuances. The Company estimates that
$25.2 million was available under the Senior Credit Facility's restricted
payment basket on June 30, 2003.
7-3/8% SENIOR SUBORDINATED NOTES DUE 2013
On July 21, 2003, the Company issued $100.0 million aggregate principal
amount of 7-3/8% Senior Subordinated Notes due 2013. The Company pays interest
on the 7-3/8% Notes semi-annually in arrears in January and July of each year,
starting in January 2004. The 7-3/8% Notes mature in July 2013. The 7-3/8% Notes
are guaranteed by certain of the Company's subsidiaries (the "Subsidiary
Guarantors"). The Company may redeem the 7-3/8% Notes, in whole or in part, at
any time on or after July 15, 2008, at redemption prices from 103.7% of the
principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011
and thereafter. Prior to July 15, 2006, the Company may redeem up to 35% of the
original aggregate principal amount of the notes at a redemption price of 107.4%
of the principal amount thereof plus accrued and unpaid interest, if any, with
the proceeds of certain equity offerings. If the Company experiences a change of
control, the Company may be required to repurchase all or a portion of the
7-3/8% Notes at 101% of the principal amount thereof plus accrued and unpaid
interest, if any. The 7-3/8% Notes and the guarantees by the Subsidiary
Guarantors are general, unsecured obligations and are subordinated to the
Company's and the Subsidiary Guarantors senior debt and will be subordinated to
future senior debt that the Company and the Subsidiary Guarantors are permitted
to incur under the senior credit facilities and the indenture governing the
7-3/8% Notes.
16
(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.
The following table sets forth the book and estimated fair values of
financial instruments as of December 31, 2002 and June 30, 2003 (in thousands):
December 31, 2002 June 30, 2003
-------------------------------- -------------------------------
Book Fair Book Fair
Value Value Value Value
------------- ------------- ------------- --------------
Assets
Cash and equivalents $ 1,334 $ 1,334 $ 1,309 $ 1,309
Marketable securities 1,040 1,040 1,404 1,404
Interest swaps - - 43 43
Commodity derivatives 17 17 72 72
----------- ------------ ------------ ------------
Total 2,391 2,391 2,828 2,828
----------- ------------ ------------ ------------
Liabilities
Commodity derivatives (32,964) (32,964) (82,091) (82,091)
Interest rate swaps (2,150) (2,150) (1,399) (1,399)
Long-term debt(1) (283,201) (279,894) (273,621) (273,695)
Trust Preferred Securities(1) (84,840) (52,177) (84,440) (54,042)
----------- ------------ ------------ ------------
Total (403,155) (367,185) (441,551) (411,227)
----------- ------------ ------------ ------------
Net financial instruments $ (400,764) $ (364,794) $ (438,723) $ (408,399)
=========== ============ ============ ============
(1) Fair value based on quotes received from certain brokerage houses.
Quotes for June 30, 2003 were 101.5% for the 8-3/4% Notes, 95.4% for
the 6% Debentures and 64.0% for the Trust Preferred Securities.
A portion of future oil and gas sales is periodically hedged through
the use of option or swap contracts. In the second quarter of 2003, the hedging
program was modified to include collars which assume a minimum floor price and a
predetermined ceiling price. Realized gains and losses on these instruments are
reflected in the contract month being hedged as an adjustment to oil and gas
revenue. At times, the Company seeks to manage interest rate risk through the
use of swaps. Gains and losses on interest rate swaps are included as an
adjustment to interest expense in the relevant periods.
At June 30, 2003, the Company had hedging contracts covering 68.7 Bcf
of gas at prices averaging $4.07 per mcf and 1.6 million barrels of oil at
prices averaging $25.05 per barrel. The 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 June 30, 2003, was a net
unrealized pre-tax loss of $82.0 million. The contracts expire monthly through
December 2006. Gains or losses on open and closed hedging transactions are
determined as the difference between the contract price and the reference price,
which are 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 $3.6 million and decreased by $15.4 million due to
hedging in the quarters ended June 30, 2002 and 2003, respectively.
17
The following schedule shows the effect of closed oil and gas
hedges since January 1, 2002 and the value of open contracts at June 30, 2003
(in thousands):
Quarter Hedging 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)
June 30 (15,365)
-----------
Subtotal (41,255)
-----------
Total realized loss $ (23,465)
===========
Open Contracts
2003
September 30 $ (15,342)
December 31 (15,277)
-----------
Subtotal (30,619)
2004
March 31 (13,574)
June 30 (8,774)
September 30 (7,940)
December 31 (8,281)
-----------
Subtotal (38,569)
2005
March 31 (5,983)
June 30 (2,282)
September 30 (2,047)
December 31 (2,545)
-----------
Subtotal (12,857)
2006
March 31 (36)
June 30 30
September 30 32
December 31 -
-----------
Subtotal 26
-----------
Total unrealized loss $ (82,019)
18
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 Credit Facility may be
adversely affected by volatility in market interest rates. Under the 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 OCI 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. Interest expense also includes the fair value effect of
non-qualifying interest rate swaps. At June 30, 2003, Great Lakes had seven
interest rate swap agreements totaling $110.0 million, of which 50% is
consolidated at the Company. These swaps consist of two agreements totaling
$45.0 million at 7.1% which expire in May 2004, two agreements totaling $20.0
million at rates averaging 2.3% which expire in December 2004 and three
agreements totaling $45.0 million at rates averaging 1.7% which expire in June
2006. The fair value of these swaps at June 30, 2003 approximated a net loss of
$2.7 million, of which 50% is consolidated at the Company.
The combined fair value of net unrealized losses on oil and gas hedges
and net losses on interest rate swaps totaled $83.4 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 shares of common stock and 10 million shares of preferred
stock. Stockholders' equity was $193.2 million at June 30, 2003. The following
is a schedule of changes in the number of outstanding common shares from
December 31, 2002 to June 30, 2003:
Twelve Months Six Months
Ended Ended
December 31, 2002 June 30, 2003
--------------------- ------------------
Beginning Balance 52,643,275 54,991,611
Issuances:
Employee benefit plans 417,661 217,938
Stock options exercised 130,566 526,537
Stock purchase plan 168,500 87,500
Exchanges for:
6% Debentures 1,165,700 128,793
Trust Preferred Securities 283,200 -
8-3/4% Senior notes 182,709 -
---------- ----------
2,348,336 960,768
---------- ----------
Ending Balance 54,991,611 55,952,379
========== ==========
19
(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 - - 56,000 1,436,900 1,492,900
Exercised (28,670) (134,518) (4,000) (259,849) (427,037)
Expired - (3,500) - (271,536) (275,036)
---------- ---------- ---------- ---------- ----------
(28,670) (138,018) 52,000 905,515 790,827
---------- ---------- ---------- ---------- ----------
Outstanding on June 30, 2003 103,032 315,562 204,000 3,450,377 4,072,971
========== ========== ========== ========== ==========
In 1999, shareholders approved a stock option plan (the "1999 Plan").
In May 2003, shareholders approved an increase in the number of options issuable
to 8.75 million. All options issued under the 1999 Plan from August 1999 through
May 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 2002 vest 30%, 30% and
40% over a three year period and have a maximum term of five years. During the
six months ended June 30, 2003, options were granted under the 1999 Plan at
exercise prices of $5.83 and $5.62 a share to eligible employees, including
250,000 and 175,000 options granted to the former Chairman and the President,
respectively. At June 30, 2003, 3.4 million options were outstanding under the
1999 Plan at exercise prices ranging from $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.
In May 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 June 30,
2003, 204,000 options were outstanding under the Directors' Plan at exercise
prices ranging from $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 June 30, 2003, 315,562 options remained outstanding under the 1989
Plan at exercise prices ranging from $2.63 to $7.63 a share.
The Domain stock option plan was adopted when that company was acquired
in 1998, with existing Domain options becoming exercisable into the Company's
common stock. No options have been granted under this plan since the
acquisition. At June 30, 2003, 103,032 options remained outstanding at an
exercise price of $3.46 a share.
20
In total, 4.1 million options were outstanding at June 30, 2003 at
exercise prices of $1.94 to $7.63 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 $ 3.44 103,032 174,387 52,000 869,343 1,198,762
$ 5.00 - $7.63 $ 5.93 - 141,175 152,000 2,581,034 2,874,209
------- ------- ------- --------- ---------
Total $ 5.20 103,032 315,562 204,000 3,450,377 4,072,971
======= ======= ======= ========= =========
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 2001, shareholders approved an increase in the
number of shares authorized under the Stock Purchase Plan to 1.75 million. 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 $126,000 and $96,000 in the three
months ended June 30, 2002 and 2003, respectively. Through June 30, 2003,
1,377,319 shares have been sold under the Stock Purchase Plan for $5.8 million.
At June 30, 2003, there were no rights outstanding to purchase shares.
(11) DEFERRED COMPENSATION
In 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 assets of
the Plan are held in a rabbi trust (the "Rabbi Trust") and, therefore, are
available to satisfy the claims of the Company's creditors in the event of
bankruptcy or insolvency of the Company. The Company's stock held in the Rabbi
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 liability 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 assets of the Rabbi Trust, other than common stock of the
Company, are invested in marketable securities and reported at market value in
Other assets on the Company's balance sheet. The Deferred Compensation liability
on the Company's balance sheet reflects the face market value of the marketable
securities and the Company's common stock held in the Rabbi Trust. The cost of
common stock held in the Rabbi Trust is shown as a reduction to Stockholders'
equity. Changes in the market value of the marketable securities are reflected
in OCI, while changes in the market value of the common stock held in the Rabbi
Trust is charged or credited to General and administrative expense each quarter.
The Company recorded mark-to-market expense related to the Company stock held in
the Rabbi Trust of $538,000 and $912,000 in the three months ended June 30, 2002
and 2003, respectively. The Company recorded mark-to-market expense related to
deferred compensation of $1.3 million in both the six months ended June 30, 2002
and 2003.
(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 common 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 may at any time
diversify out of Company stock based on their personal investment strategy.
21
(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 on December 31, 2002 and June 30, 2003 were as follows (in
thousands):
December 31, June 30,
2002 2003
----------- --------
Deferred tax assets/(liabilities)
Net unrealized loss on hedging $ 11,388 $ 27,869
Other 4,397 (4,576)
-------- --------
Net deferred tax asset $ 15,785 $ 23,293
======== ========
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 June 30, 2003, deferred tax assets exceeded
deferred tax liabilities by $23.3 million with $27.9 million of deferred tax
assets related to hedging losses in OCI. For six months ended June 30, 2003,
deferred tax expense includes $917,000 of expense related to an adjustment of
prior periods' deferred tax asset for the Company's 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. At December 31,
2002, the Company had an AMT credit carryover of $665,000 which is not subject
to limitation or expiration.
22
(14) EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted
earnings per common share (in thousands except per share amounts):
Three Months Ended, Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2003 2002 2003
-------- -------- -------- --------
Numerator
Numerator for earnings per share,
before extraordinary item $ 7,310 $ 4,591 $ 11,651 $ 9,554
Cumulative effect of accounting change - - - 4,491
-------- -------- -------- --------
Numerator for earnings per share,
basic and diluted $ 7,310 $ 4,591 $ 11,651 $ 14,045
======== ======== ======== ========
Denominator
Weighted average shares outstanding 54,540 55,682 53,763 55,440
Stock held by employee benefit trust (1,172) (1,520) (1,106) (1,424)
-------- -------- -------- --------
Weighted average shares, basic 53,368 54,162 52,657 54,016
Stock held by employee benefit trust 1,172 1,520 1,106 1,424
Dilutive potential common shares stock options 399 486 345 404
-------- -------- -------- --------
Denominator for dilutive earnings per share 54,939 56,168 54,108 55,844
======== ======== ======== ========
Earnings per share basic and diluted:
Before cumulative effect of accounting change
Basic $ 0.14 $ 0.08 $ 0.22 $ 0.18
Diluted $ 0.13 $ 0.08 $ 0.22 $ 0.17
After cumulative effect of accounting change
Basic $ 0.14 $ 0.08 $ 0.22 $ 0.26
Diluted $ 0.13 $ 0.08 $ 0.22 $ 0.25
During the three months ended June 30, 2002 and 2003, 420,000 and
515,000 stock options were included in the computation of diluted earnings per
share and for the six months then ended, 367,000 and 435,000 stock options were
included in such computation. Remaining stock options, the 6% Debentures and the
Trust Preferred Securities 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 June 30, 2003, three customers,
Duke Energy Field Services, Inc, Petrocom Energy Group, Ltd. and Conoco, Inc.,
accounted for 23%, 22% and 11%, 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.
23
(16) OIL AND GAS ACTIVITIES
The following summarizes selected information with respect to producing
activities. Exploration costs include capitalized as well as expensed outlays
(in thousands):
Six
Year Ended Months Ended
December 31, June 30,
2002 2003
------------ -----------
Book value
Properties subject to depletion $ 1,135,590 $ 1,224,560
Unproved properties 18,959 17,529
----------- -----------
Total 1,154,549 1,242,089
Accumulated depletion (590,143) (606,789)
----------- -----------
Net $ 564,406 $ 635,300
=========== ===========
Costs incurred(a)
Development $ 66,284 $ 39,879
Exploration(b) 23,232 8,266
Acquisition(c) 21,790 9,729
----------- -----------
Total $ 111,306 $ 57,874
=========== ===========
(a) Excludes asset retirement costs of $2.0 million in the six months ended
June 30, 2003.
(b) Includes $11,525 and $5,140 of exploration costs expensed in the year
ended 2002 and the six months ended June 30, 2003, respectively.
(c) Includes $15,643 and $6,339 for oil and gas reserves, the remainder
represents acreage purchases for the year ended 2002 and the six months
ended June 30, 2003, respectively.
24
(17) INVESTMENT IN GREAT LAKES
The Company owns 50% of Great Lakes and consolidates its proportionate
interest in the joint venture's assets, liabilities, revenues and expenses. The
following table summarizes the 50% interest in Great Lakes financial statements
as of or for the six months ended June 30, 2002 and 2003 (in thousands):
June 30, June 30,
2002 2003
-------------- ---------------
Balance Sheet
Current assets $ 9,799 $ 11,365
Oil and gas properties, net 168,747 209,601
Transportation and field assets, net 15,308 15,004
Unrealized derivative gain - 99
Other assets 199 347
Current liabilities 10,445 25,322
Unrealized derivative loss 2,820 8,170
Asset retirement obligation - 17,657
Long-term debt 68,500 73,500
Members' equity 112,288 111,767
Statement of Operations
Revenues $ 25,660 $ 28,147
Direct operating expense 4,092 5,046
Exploration 1,200 781
G&A expense 921 930
Interest expense 2,499 2,280
DD&A 6,771 7,126
Pretax income 10,175 11,983
Cumulative effect of change in
accounting principle (before income taxes) - 1,601
(18) GAIN ON RETIREMENT OF SECURITIES
In the second quarter of the 2003, $500,000 of the 8-3/4% Notes were
repurchased for cash and a loss of $10,400 was recorded on the transaction. In
the six months of 2003, $400,000 of Trust Preferred Securities and $500,000 of
8-3/4% Notes were repurchased for cash and $880,000 of 6% Debentures was
exchanged for common stock. A net gain of $139,600 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 second quarter of 2002, $5.0 million of 8-3/4% Notes were repurchased for
cash and $5.6 million of 6% Debentures were exchanged for common stock. In the
first six months of 2002, $5.0 million of 6% Debentures were repurchased for
cash. Also, $2.4 million, $7.1 million, and $875,000 of Trust Preferred
Securities, 6% Debentures, and 8-3/4% Notes, respectively, were exchanged for
common stock. A gain of $845,000 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.
25
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, oil and gas properties, income taxes, and litigation, bad debts,
marketable securities, hedging and the deferred compensation plan, 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.
The FASB and representatives of the accounting staff of the SEC are
engaged in discussions on the issue of whether the FASB's No. 141 and 142,
issued effective for June 30, 2001, called for mineral rights held under lease
or other contractual arrangements to be classified in the balance sheet as
intangible assets and accompanied by specific footnote disclosures.
Historically, the Company and all other oil and gas companies have included the
cost of these oil and gas leasehold interests as part of oil and gas properties.
Although, most of the Company's oil and gas property interests are held under
oil and gas leases, this interpretation, if adopted, would not have a material
impact on the Company's financial condition or its results of operations.
In the event this interpretation is adopted, a substantial portion of
acquisition costs of oil and gas properties since June 30, 2001 would be
separately classified on the balance sheets as intangible assets. As of June 30,
2003, the Company's has expended approximately $23.6 million on the acquisition
of oil and gas properties since June 30, 2001. Some additional direct costs of
other oil and natural gas leases acquired since that date could also be
categorized as intangible under this interpretation. Results of operations would
not be affected by this interpretation, if adopted, since these costs would
continue to be depleted in accordance with successful efforts accounting for oil
and gas companies. Another possible effect of this interpretation, if adopted,
would be a change in some of the financial measurements used in financial
covenants of debt instruments that focus on tangible assets. The Company does
not believe that its debt covenants would be materially affected by the adoption
of this accounting interpretation.
Proved oil and natural gas reserves - Proved reserves are defined by
the 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
26
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. Proven leasehold costs are
charged expense to using the units of production method based on total proved
reserves. Unproved properties are assessed periodically within specific
geographic areas and impairments to value are charged to expense.
Impairment of properties - The Company 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
gas sales prices, an estimate of the ultimate amount of recoverable oil and
natural gas reserves that will be produced, 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 carry forwards and other deductible
differences. The Company routinely evaluates its 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. 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. The Company uses the sales method to account
for gas imbalances. Revenues at IPF are recognized as earned. An allowance for
doubtful accounts is provided for specific receivables which are 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
27
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. As of January 1, 2003, the accounting for expected future costs to
retire long-lived assets changed with the adoption of SFAS 143.
LIQUIDITY AND CAPITAL RESOURCES
During the six months ended June 30, 2003, the Company spent $57.9
million on development, exploration and acquisitions. During the period, debt
and Trust Preferred Securities decreased by $10.0 million. At June 30, 2003, the
Company had $1.3 million in cash, total assets of $743.4 million and, including
the Trust Preferred Securities as debt, a debt to capitalization (including
debt, deferred taxes and stockholders' equity) ratio of 65%. Excluding the Trust
Preferred Securities from debt and equity, the debt to capitalization ratio was
59%. Available borrowing capacity on the credit facilities at June 30, 2003 was
$59.4 million on the Senior Credit Facility and $78.0 million on the Great Lakes
Credit Facility. Long-term debt at June 30, 2003 totaled $358.1 million. This
included $110.6 million of Senior Credit Facility debt, a net $73.5 million of
Great Lakes Credit Facility debt, $68.8 million of 8-3/4% Notes, $20.7 million
of 6% Debentures and $84.4 million of Trust Preferred Securities.
During the six months ended June 30, 2003, 129,000 shares of common
stock were exchanged for $880,000 of 6% Debentures. In addition, $400,000 of
Trust Preferred Securities and $500,000 of 8-3/4% Notes were repurchased for
cash. A $139,600 net gain on retirement was recorded on the cash repurchase as
most securities were acquired at a discount and a conversion expense of $465,000
was recorded on the exchange.
7-3/8% Subordinated Notes Issuance
On July 21, 2003, the Company issued $100.0 million principal amount of
7-3/8% Senior Subordinated Notes due 2013. The Company pays interest on the
7-3/8% Notes semi-annually in arrears in January and July of each year, starting
in January 2004. The 7-3/8% Notes mature on July 2013. The 7-3/8% Notes are
guaranteed by certain of the Company's subsidiaries (the "Subsidiary
Guarantors"). The Company may redeem the 7-3/8% Notes, in whole or in part, at
any time on or after July 15, 2008, at redemption prices from 103.7% of the
principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011
and thereafter. Prior to July 15, 2006, the Company may redeem up to 35% of the
original aggregate principal amount of the notes at a redemption price of 107.4%
of the principal amount thereof plus accrued and unpaid interest, if any, with
the proceeds of certain equity offerings. If the Company experiences a change of
control, the Company may be required to repurchase all or a portion of the
7-3/8% Notes at 101% of the principal amount thereof plus accrued and unpaid
interest, if any. The 7-3/8% Notes and the guarantees by the Subsidiary
Guarantors are general, unsecured obligations and are subordinated to the
Company's and the Subsidiary Guarantors senior debt and will be subordinated to
future senior debt that the Company and the Subsidiary Guarantors are permitted
to incur under the senior credit facilities and the indenture governing the
7-3/8% Notes.
The Company believes its capital resources are adequate to meet its
requirements for at least the next twelve months; however, future cash flows are
subject to a number of variables including the level of production and prices as
well as various economic conditions that have historically affected the oil and
gas business. There can be no assurance that internal cash flow and other
capital sources will provide sufficient funds to maintain planned capital
expenditures.
The debt agreements contain covenants relating to net worth, working
capital, dividends and financial ratios. The Company was in compliance with all
covenants at June 30, 2003. Under the most restrictive covenant, which is
embodied in the 8-3/4% Notes, approximately $560,000 of restricted payments
could be made at June 30, 2003. Under the Senior Credit Facility, common
dividends are permitted. Dividends on the Trust Preferred Securities may not be
paid unless certain ratio requirements are met. The Senior Credit Facility
provides for a restricted payment basket of $20.0 million plus 50% of net income
(excluding Great Lakes) plus 66-2/3% of distributions, dividends or payments of
debt from or proceeds from sales of equity interests of Great Lakes plus 66-2/3%
of net cash proceeds from common stock issuances. The Company estimates that
$25.2 million was available under the Senior Credit Facility's restricted
payment basket on June 30, 2003.
28
During the six months ended January 30, 2003, there were no material
changes from the 2002 Form 10K disclosures regarding the Company's contractual
commitments, other than the extension of the Senior Credit Facility's maturity
date from 2005 to 2007.
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 68.7 bcf of gas
and 1.6 million barrels of oil for the remainder of 2003, 2004, 2005, and 2006,
respectively. The $52.5 million of capital expenditures in the six months ended
June 30, 2003 was funded with internal cash flow. Net cash provided by
operations for the six months ended June 30, 2002 and 2003 was $53.5 million and
$57.5 million, respectively. Cash flow from operations was higher than the prior
year due to higher prices and volumes and lower exploration expense partially
offset by higher direct operating expenses. Accounts receivable increased $12.6
million from December 31, 2002 due to higher prices and volumes. These
receivables will be collected in the third quarter of 2003. Net cash used in
investing for the six months ended June 30, 2002 and 2003 was $44.5 million and
$49.7 million, respectively. The 2002 period included $37.7 million of additions
to oil and gas properties. The 2003 period included $50.9 million of additions
to oil and gas properties partially offset by $7.6 million of IPF receipts (net
of fundings) and lower exploration expenditures. Net cash provided by financing
for the six months ended June 30, 2002 and 2003 was $8.2 million and $7.8
million, respectively. During the first six months of 2003, total debt,
including Trust Preferred Securities decreased $10.0 million. Senior Credit
Facility debt and Great Lake Credit Facility debt decreased $8.2 million,
subordinated notes (8-3/4% Notes and 6% Debentures) decreased $1.4 million and
the Trust Preferred Securities decreased $400,000. The net decrease in debt was
the result of excess cash flows. On July 21, 2003, the Company elected to redeem
all of its outstanding 8-3/4% Notes on August 20, 2003. The redemption price,
including the premium, will be $70.8 million. The redemption was financed by the
issuance of $100.0 million of 7-3/8% Notes due 2013.
Capital Requirements
During the six months ended June 30, 2003, $52.5 million of capital
expenditures was funded with internal cash flow. The Company seeks to fund its
capital budget with internal cash flow. Based on the 2003 capital budget of
$110.0 million, the Company seeks to increase production and expand its reserve
base.
Banking
The Company maintains two separate revolving bank credit facilities: a
$225.0 million Senior Credit Facility and a $275.0 million Great Lakes Credit
Facility (of which 50% is consolidated at the Company). Each facility is secured
by substantially all the borrowers' assets. The Great Lakes Credit 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. Redeterminations, other than increases, require
approval of 75% of the lenders while, increases require unanimous approval.
At July 31, 2003, the Senior Credit Facility had a $170.0 million
borrowing base of which $154.8 million was available. The Great Lakes Credit
Facility, half of which is consolidated at the Company, had a $225.0 million
borrowing base, of which $75.0 million was available.
HEDGING
Oil and Gas Prices
The Company 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 June 30, 2003, hedges were in place covering 68.7 Bcf of gas at
prices averaging $4.07 per Mmbtu and 1.6 million barrels of oil at prices
averaging $25.05 per barrel. Their fair value at June 30, 2003 (the estimated
amount that would be realized on termination based on contract versus NYMEX
prices) was a net unrealized pre-tax loss of $82.0 million. 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
29
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 June 30, 2003 were
$15.4 million and Oil and gas revenues were increased by $3.6 million from
hedging for the three months ended June 30, 2002.
Interest Rates
At June 30, 2003, the Company had $358.1 million of debt (including
Trust Preferred Securities) outstanding. Of this amount, $174.0 million bore
interest at fixed rates averaging 7.0%. Senior Credit Facility debt and Great
Lakes Credit Facility debt totaling $184.1 million bore interest at floating
rates which averaged 2.9% at June 30, 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 June 30, 2003, Great Lakes had interest rate swap
agreements totaling $110.0 million, 50% of which is consolidated at the Company.
These swaps consist of two agreements totaling $45.0 million at 7.1% which
expire in May 2004, two agreements totaling $20.0 million at rates averaging
2.3% which expire in December 2004 and three agreements totaling $45.0 million
at rates averaging 1.7% which expire in June 2006. The fair value of the swaps,
based on then current quotes for equivalent agreements at June 30, 2003 was a
net loss of $2.7 million, of which 50% is consolidated at the Company. The 30
day LIBOR rate on June 30, 2003 was 1.1%.
Capital Restructuring Program
The Company has taken a number of steps since 1998 to strengthen its
financial position. These steps included the sale of assets and the exchange of
common stock for debt. These initiatives have helped reduce the Senior Credit
Facility debt from $365.2 million to $110.6 million and total debt (including
Trust Preferred Securities) from $727.2 million to $358.1 million at June 30,
2003. 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.
INFLATION AND CHANGES IN PRICES
The Company's revenues, the value of its assets, its ability to obtain
bank loans or additional capital on attractive terms have been and will continue
to be affected by changes in oil and gas prices. Oil and gas prices are subject
to significant fluctuations that are beyond the Company's ability to control or
predict. During the first six months of 2003, the Company received an average of
$23.38 per barrel of oil and $3.91 per mcf of gas after hedging compared to
$22.46 per barrel of oil and $3.42 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.
30
RESULTS OF OPERATIONS
VOLUMES AND SALES DATA:
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2002 2003 2002 2003
-------------- -------------- -------------- --------------
Production:
Crude oil and liquid (bbls) 559,553 630,600 1,093,718 1,213,739
Natural gas (mcfs) 10,358,893 10,619,549 20,573,203 20,977,908
Average daily production:
Crude oil (bbls) 5,008 5,807 4,949 5,622
NGLs (bbls) 1,141 1,123 1,093 1,084
Natural gas (mcfs) 113,834 116,698 113,664 115,900
Total (mcfes) 150,728 158,276 149,920 156,134
Average sales prices (excluding hedging):
Crude oil (per bbl) $ 23.09 $ 26.71 $ 20.98 $ 28.98
NGLs (per bbl) $ 12,58 $ 18.46 $ 11.79 $ 19.28
Natural gas (per mcf) $ 3.20 $ 5.14 $ 2.74 $ 5.61
Average sales price (including hedging):
Crude oil (per bbl) $ 22.27 $ 23.14 $ 22.46 $ 23.38
NGLs (per bbl) $ 12.58 $ 18.46 $ 11.79 $ 19.28
Natural gas (per mcf) $ 3.59 $ 3.88 $ 3.42 $ 3.91
Total (per mcfe) $ 3.55 $ 3.84 $ 3.42 $ 3.88
31
The following table identifies certain items included in the results of
operations and is presented to assist in comparison of the second quarter and
year to date 2003 to the same periods of the prior year. The table should be
read in conjunction with the following discussions of results of operations (in
thousands):
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2003 2002 2003
-------- -------- -------- --------
Increase (decrease) in revenues:
Write-down of marketable securities $ (851) $ - $ (1,220) $ -
Gains (losses) on retirement of securities 845 (10) 2,030 140
Ineffective portion of commodity hedges (463) (2,075) (2,162) (1,271)
Gain from sales of assets 27 69 26 157
Realized hedging gains (losses) 3,639 (15,365) 15,365 (41,255)
-------- -------- -------- --------
$ 3,197 $(17,381) $ 14,039 $(42,229)
======== ======== ======== ========
Increase (decrease) to expenses:
Fair value deferred compensation adjustment $ 538 $ 912 $ 1,320 $ 1,297
Bad debt expense accrual - 75 - 150
Adjustment to IPF valuation allowance 1,441 299 2,567 558
Non-qualifying interest rate swaps 300 (154) (72) (83)
-------- -------- -------- --------
$ 2,279 $ 1,132 $ 3,815 $ 1,922
======== ======== ======== ========
Cumulative effect of change in
accounting principle (net of tax) $ - $ - $ - $ 4,491
======== ======== ======== ========
Comparison of 2002 to 2003
Quarters Ended June 30, 2002 and 2003
Net income in the second quarter of 2003 totaled $4.6 million, compared
to $7.3 million in the prior year period. The second quarter of 2003 includes a
tax expense of $2.5 million versus a tax benefit in the prior year of $1.8
million. Production increased to 158.3 Mmcfe per day, a 5% increase from the
prior year period. The production increase was due to higher production in the
Appalachia and Southwest divisions offset by lower production in the Gulf Coast
division. Revenues increased primarily due to an 8% increase in average prices
per mcfe to $3.84. The average prices received for oil increased 4% to $23.14
per barrel, increased 8% for gas to $3.88 per mcf and increased 47% for NGLs to
$18.46 per barrel. Production expenses increased 27% to $12.6 million as a
result of significantly higher production taxes, increased costs from new wells
and higher workover costs. Production taxes averaged $0.12 per mcfe in 2002
versus $0.18 per mcfe in 2003. Production taxes are paid on market prices not on
hedged prices. Operating costs, including production taxes, per mcfe produced
averaged $0.72 in 2002 versus $0.88 in 2003.
Transportation and processing revenues increased 2% to $940,000 in 2003
with higher oil trading margins and higher gas prices. IPF recorded income of
$428,000, a decrease of $564,000 from the 2002 period due to a smaller portfolio
balance. 2002 IPF expenses included a $1.4 million unfavorable valuation
allowance adjustment. IPF expenses in 2003 include a $299,000 unfavorable
valuation allowance. During the quarter ended June 30, 2003, IPF expenses
included $209,000 of administrative costs and $60,000 of interest, compared to
prior year period administrative expenses of $476,000 and interest of $261,000.
Exploration expense increased $515,000 to $2.7 million in 2003 due to
higher dry hole costs. General and administrative expenses increased 12% or
$580,000 to $5.3 million in the quarter with higher mark-to-market expenses
relating to the deferred compensation plan and higher legal and other
professional fees partially offset by certain bank fee and other refunds. The
fair value deferred compensation adjustment included in general and
administrative expense was $912,000 in the three months ended 2003 versus
$538,000 in the same period of the prior year period. (See Note 11 to the
consolidated financial statements).
Other income reflected a loss of $1.2 million in 2002 and a loss of
$1.9 million in 2003. The 2003 period included $2.1 million of ineffective
hedging losses partially offset by $69,000 of gains on asset sales. The 2002
period included $463,000 of ineffective hedging losses and an $851,000 write
down of marketable securities. Interest expense
32
decreased 18% to $5.2 million with lower expense related to the non-qualifying
interest swaps, lower interest rates and lower outstanding debt. Total debt was
$373.3 million and $358.1 million at June 30, 2002 and 2003, respectively. The
average interest rates (excluding hedging) were 5.3% and 4.9%, respectively, at
June 30, 2002 and 2003 including fixed and variable rate debt.
DD&A increased 10% from the second quarter of 2002 with higher
production and an additional $1.2 million of accretion expense related to the
adoption of the new accounting principle (see Note 3 to the consolidated
financial statements). The per mcfe DD&A rate for the second quarter of 2003 was
$1.48, a $0.07 increase from the rate for the second quarter of 2002. This
increase is due to higher accretion expense ($0.08 per mcfe) and the mix of
production offset by lower depletion rates. 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.
Income taxes reflected a benefit of $1.8 million in the second quarter
of 2002 versus tax expenses of $2.5 million in the three months ended June 30,
2003. (See Note 13 to the consolidated financial statements).
Six Months Periods Ended June 30, 2002 and 2003
Net income for the six months ended June 30, 2003 totaled $14.0 million
compared to $11.7 million for the comparable period of 2002. The six months
ended June 2003 includes tax expenses of $6.6 million versus a tax benefit of
$4.9 million in the prior year. 2003 also includes $4.5 million gain on adoption
of a new accounting principle. Production for the six months increased to 156.1
Mmcfe per day, an increase of 4% from the prior year period. The production
increase was due to higher production in the Appalachia and Southwest divisions
and higher production at West Cameron 45 somewhat offsetting natural production
declines in other Gulf Coast wells. Revenues increased primarily due to higher
prices which averaged $3.88 per mcfe. The average prices received for oil
increased 4% to $23.38 per barrel, 14% for gas to $3.91 per mcf and 64% for NGLs
to $19.28 per barrel. Production expenses increased 34% to $25.7 million as a
result of higher production taxes, costs from new wells and higher workover
costs in the Gulf of Mexico. Operating cost (including production taxes) per
mcfe produced averaged $0.91 in 2003 versus $0.71 in 2002.
Transportation and processing revenues increased 16% to $2.0 million
with higher gas prices and higher oil trading margin. IPF recorded income of
$967,000 million, a decrease of $1.2 million from the 2002. IPF revenue declined
from the previous year due to a smaller portfolio balance. 2002 IPF expenses
included $2.6 million of unfavorable valuation allowance adjustments. IPF
expenses for the six months ended June 2003 included $558,000 of unfavorable
valuation allowance adjustments. During the six months ended June 30, 2003, IPF
expenses included $467,000 of administrative costs and $161,000 of interest,
compared to prior year period administrative expenses of $870,000 and interest
of $513,000.
Exploration expense decreased $2.3 million to $5.1 million, primarily
due to lower dry hole costs partially offset by higher seismic costs. General
and administrative expenses increased 10% to $10.2 million in the six months
ended June 30, 2003 due to higher compensation related expenses and legal and
other professional fees. The fair value deferred compensation adjustment
included in general and administrative expense is an expense of $1.3 million in
both the six months ended 2002 and 2003.
Other income reflected a loss of $3.2 million and a loss of $985,000.
The 2002 period included $2.2 million of ineffective hedging losses and a $1.2
million write down of marketable securities. The 2003 period included a $1.3
million ineffective hedging loss and a $157,000 gain on sale of assets. Interest
expense decreased 9% to $10.7 million as a result of lower outstanding debt and
lower interest rates.
DD&A increased 13% from the same period of the prior year with higher
production and an additional $2.3 million of accretion expense related to the
adoption of the new accounting principle.. The per mcfe DD&A rate for the six
months of 2003 was $1.49, a $0.11 increase from the rate for the same period
with higher accretion expense ($0.08 per mcfe) and higher depletion rates.
Income taxes reflected a benefit of $4.9 million in the six months of
2002 versus tax expenses of $6.6 million in the same period of 2003.
33
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about the Company's
potential exposure to market risks. 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, the Company 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. In
the second quarter of 2003, the hedging program was modified to include collars
which assume a minimum floor price and predetermined ceiling price. 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 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 $82.0 million unrealized pre-tax
loss included in OCI at June 30, 2003, $53.0 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. The Company does not hold or issue derivative instruments for
trading purposes.
As of June 30, 2003, the Company had oil and gas hedges in place
covering 68.7 Bcf of gas and 1.6 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
$82.0 million at that date. These contracts expire monthly through December
2006. 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 six months ended June 30, 2003 were $41.3 million and net
realized gains were $15.4 million for the six months ended June 30, 2002.
In the first six months of 2003, a 10% reduction in oil and gas prices,
excluding amounts fixed through hedging transactions, would have reduced revenue
by $15.1 million. If oil and gas future prices at June 30, 2003 had declined
10%, the unrealized hedging loss at that date would have decreased $38.6
million.
Interest rate risk. At June 30, 2003, the Company had $358.1 million of
debt (including Trust Preferred Securities) outstanding. Of this amount, $174.0
million bore interest at fixed rates averaging 7.0%. Senior Credit Facility debt
and the Great Lakes Credit Facility debt totaling $184.1 million bore interest
at floating rates averaging 2.9%. At June 30, 2003 Great Lakes had interest rate
swap agreements totaling $110.0 million (See Note 7), 50% of which is
consolidated at the Company, which had a fair value loss (the Company's share)
of $1.4 million at that date. A 1% increase or decrease in short-term interest
rates would cost or save the Company approximately $1.3 million in annual
interest expense.
34
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
Acting 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 (c) and Rule 15d-14(c). Based upon that evaluation, the Chief
Executive Officer and the Acting 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
SEC. 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, including any corrective actions with regard to significant
deficiencies and material weaknesses.
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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 21, 2003, the Company held its Annual Meeting of Stockholders to
(a) elect a Board of seven directors, each for a one-year term and (b) consider
and vote on a proposal to (i) amend the 1999 Plan increasing the number of
shares of common stock authorized to be issued from 6,000,000 to 8,750,000 and
(ii) amend the 1999 Plan to prohibit the repricing of stock options granted
under the 1999 Plan without a vote by the stockholders (collectively (a)(i) and
(a)(ii) shall hereinafter be referred to as the "1999 Plan Amendments"). At such
meeting, Robert E. Aikman, Anthony V. Dub, V. Richard Eales, Allen Finkelson,
Jonathan S. Linker and John H. Pinkerton were reelected as Directors of the
Company and Charles L. Blackburn was elected to serve as a director and Chairman
of the Board. In addition, the 1999 Plan Amendments were approved by the
Stockholders of the Company.
The following is a summary of the votes cast at the Annual Meeting:
Results of Voting Votes For Withheld Abstentions
----------------- ----------- ----------- -----------
1. Election of Directors
Robert E. Aikman 43,302,684 7,796,868 -
Charles L. Blackburn 43,483,026 7,616,526 -
Anthony V. Dub 43,126,349 7,973,203 -
V. Richard Eales 43,124,899 7,974,653 -
Allen Finkelson 43,321,546 7,778,006 -
Jonathan S. Linker. 43,124,711 7,974,841 -
John H. Pinkerton 43,393,308 7,706,244 -
Results of Voting Votes For Against Abstentions
----------------- ----------- ----------- -----------
2. 1999 Plan Amendments 30,093,708 20,791,451 214,392
35
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a)
(a) Exhibits:
3.1.1 Certificate of Incorporation of Lomak Petroleum, Inc.
("Lomak") dated March 24, 1980 (incorporated by reference to
Exhibit 3.1.1 to the Range Resources Corporation (the
"Company") Registration Statement (File No. 33-31558))
3.1.2 Certificate of Amendment to the 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 to the Certificate of Incorporation
of Lomak dated August 27, 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 to the Certificate of Incorporation
of Lomak 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 to the Certificate of Incorporation
of Lomak 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 to the Certificate of Incorporation
of Lomak dated May 17, 1991 (incorporated by reference to
Exhibit 4.4(f) to the Company's Form S-3/A (File No.
333-20257) as filed with the Securities and Exchange
Commission (the "SEC") on March 4, 1997)
3.1.7 Certificate of Amendment to the Certificate of Incorporation
of Lomak dated November 20, 1992 (incorporated by reference to
Exhibit 4.4(g) to the Company's Form S-3/A (File No.
333-20257) as filed with the SEC on March 4, 1997)
3.1.8 Certificate of Amendment to the Certificate of Incorporation
of Lomak dated May 24, 1996 (incorporated by reference to
Exhibit 4.4(h) to the Company's Form S-3/A (File No.
333-20257) as filed with the SEC on February 14, 1997)
3.1.9 Certificate of Amendment to the Certificate of Incorporation
of Lomak dated October 2, 1996 (incorporated by reference to
Exhibit 4.4(i) to the Company's Form S-3/A (File No.
333-20257) as filed with the SEC on February 14, 1997)
3.1.10 Restated Certificate of Incorporation of Lomak as required by
Item 102 of Regulation S-T (incorporated by reference to
Exhibit 4.4(j) to the Company's Form S-3/A (File No.
333-20257) as filed with the SEC on March 4, 1997)
3.1.11* Certificate of Amendment to the Certificate of Incorporation
of Lomak dated June 20, 1997
3.1.12 Certificate of Amendment to the Certificate of Incorporation
of Lomak dated August 25, 1998 (incorporated by reference to
Exhibit 3.1 to the Company's Form S-8 (File No. 333-62439) as
filed with the SEC on August 28, 1998)
3.1.13 Certificate of Amendment to the Certificate of Incorporation
of the Company dated May 24, 2000 (incorporated by reference
to Exhibit 3.1.12 to the Company's Form 10-Q (File No.
001-12209) as filed with the SEC on May 17, 2003)
3.2.1 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 10-K (File No. 001-12209) as filed with the SEC on March
5, 2002)
4.1.1 Form of 6% Convertible Subordinated Debentures due 2007
(contained as an exhibit to Exhibit 4.1.2 hereto)
4.1.2 Indenture dated December 20, 1996 by and between Lomak and
Keycorp Shareholders Services, Inc., as trustee (incorporated
by reference to Exhibit 4.1(A) to the Company's Form S-3 (File
No. 333-23955) as filed with the SEC on March 25, 1997)
4.2.1 Form of 8-3/4% Senior Subordinated Notes due 2007 (contained
as an exhibit to Exhibit 4.2.2 hereto)
4.2.2 Indenture dated March 14, 1997 by and among Lomak, the
Subsidiary Guarantors (as defined therein) and Fleet National
Bank, as trustee (incorporated by reference to Exhibit 4.3 to
the Company's Form S-3/A (File No. 333-20257) as filed with
the SEC on February 14, 1997)
4.3.1 Form of 5-3/4% Convertible Preferred Securities (contained as
an exhibit to Exhibit 4.3.5 hereto)
36
4.3.2 Form of 5-3/4% Convertible Junior Subordinated Debentures
(contained as an exhibit to Exhibit 4.3.4 hereto)
4.3.3 Indenture dated October 22, 1997 by and between Lomak and The
Bank of New York, as trustee (incorporated by reference to
Exhibit 4.6 of the Company's Form S-3 (File No.
333-43823) as filed with the SEC on January 7, 1998)
4.3.4 First Supplemental Indenture dated October 22, 1997 by and
between Lomak and The Bank of New York, as trustee
(incorporated by reference to Exhibit 4.7 to the Company's
Form S-3 (File No. 333-43823) as filed with the SEC on January
7, 1998)
4.3.5 Certificate of Trust of Lomak Financing Trust dated October 8,
1997 (incorporated by reference to Exhibit 4.4 to the
Company's Form S-3 (File No. 333-43823) as filed with the SEC
on January 7, 1998)
4.3.6 Amended and Restated Declaration of Trust of Lomak Financing
Trust dated October 22, 1997 by and between the Trustees (as
defined therein), the Sponsor (as defined therein) and the
holders, from time to time, of undivided beneficial ownership
interests in the Trust (as defined therein) (incorporated by
reference to Exhibit 4.5 to the Company's Form S-3 (File No.
333-43823) as filed with the SEC on January 7, 1998)
4.3.7 Convertible Preferred Securities Guarantee Agreement dated
October 22, 1997 by and between Lomak, as guarantor, and The
Bank of New York, as trustee (incorporated by reference to
Exhibit 4.10 to the Company's Form S-3 (File No. 333-43823) as
filed with the SEC on January 7, 1998)
4.3.8 Common Securities Guarantee Agreement dated October 22, 1997
executed and delivered by Lomak, as guarantor, for the benefit
of the Holders (as defined therein) from time to time of the
Common Securities (as defined therein) of Lomak Financing
Trust (incorporated by reference to Exhibit 4.11 to the
Company's Form S-3 (File No. 333-43823) as filed with the SEC
on January 7, 1998)
4.4.1* Form of 7-3/8% Senior Subordinated Notes due 2013 (contained
as an exhibit to Exhibit 4.4.2 hereto)
4.4.2* Indenture dated July 21, 2003 by and among the Company, as
issuer, the Subsidiary Guarantors (as defined therein), as
guarantors, and Bank One, National Association, as trustee
4.4.3* Registration Rights Agreement dated July 21, 2003 by and
between the Company and UBS Securities LLC, Banc One Capital
Markets, Inc., Credit Lyonnais Securities (USA) Inc. and
McDonald Investments Inc.
10.1* Amended Application Service Provider and Outstanding Agreement
dated June 2, 2003 by and between the Company and CGI
Information Systems and Management Consultants, Inc.
10.2* Consulting Agreement dated May 7, 2003 by and between the
Company and Thomas J. Edelman
10.3* Third Amendment to Amended and Restated Credit Agreement dated
April 1, 2003 by and among the Company, Bank One, NA, the
Lenders (as defined therein), Fleet National Bank, Fortis
Capital Corp., JPMorgan Chase Bank, Credit Lyonnais New York
Branch, Banc One Capital Markets, Inc. and JPMorgan Securities
Inc.
10.4.1* Restated Credit Agreement dated May 3, 2002 by and among Great
Lakes Energy Partners, L.L.C. ("Great Lakes"), Bank One, NA,
JPMorgan Chase Bank, The Bank of Nova Scotia, Bank of
Scotland, Credit Lyonnais New York Branch, Fortis Capital
Corp., The Frost National Bank, Union Bank of California, N.A.
and each Lender (as defined therein)
10.4.2* First Amendment to Restated Credit Agreement dated April 1,
2003 by and among Great Lakes, Bank One, NA, JPMorgan Chase
Bank, The Bank of Nova Scotia, Bank of Scotland, Credit
Lyonnais New York Branch, Fortis Capital Corp., The Frost
National Bank, Union Bank of California, N.A., Comerica
Bank-Texas, Natexis Banques Populaires, each Lender (as
defined therein), Banc One Capital Markets, Inc. and JPMorgan
Securities, Inc.
31.1* Certification by the President and Chief Executive Officer of
the Company Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002
31.2* Certification by the Acting Chief Financial Officer of the
Company Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002
32.1* Certification by the President and Chief Executive Officer of
the Company Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2* Certification by the Acting Chief Financial Officer of the
Company Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
- ------------------------------------
* filed herewith
37
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
RANGE RESOURCES CORPORATION
By: /s/ RODNEY L. WALLER
-------------------------------
Rodney L. Waller
Acting Chief Financial Officer
August 6, 2003
38
EXHIBIT INDEX
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
3.1.1 Certificate of Incorporation of Lomak Petroleum, Inc.
("Lomak") dated March 24, 1980 (incorporated by reference to
Exhibit 3.1.1 to the Range Resources Corporation (the
"Company") Registration Statement (File No. 33-31558))
3.1.2 Certificate of Amendment to the 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 to the Certificate of Incorporation
of Lomak dated August 27, 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 to the Certificate of Incorporation
of Lomak 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 to the Certificate of Incorporation
of Lomak 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 to the Certificate of Incorporation
of Lomak dated May 17, 1991 (incorporated by reference to
Exhibit 4.4(f) to the Company's Form S-3/A (File No.
333-20257) as filed with the Securities and Exchange
Commission (the "SEC") on March 4, 1997)
3.1.7 Certificate of Amendment to the Certificate of Incorporation
of Lomak dated November 20, 1992 (incorporated by reference to
Exhibit 4.4(g) to the Company's Form S-3/A (File No.
333-20257) as filed with the SEC on March 4, 1997)
3.1.8 Certificate of Amendment to the Certificate of Incorporation
of Lomak dated May 24, 1996 (incorporated by reference to
Exhibit 4.4(h) to the Company's Form S-3/A (File No.
333-20257) as filed with the SEC on February 14, 1997)
3.1.9 Certificate of Amendment to the Certificate of Incorporation
of Lomak dated October 2, 1996 (incorporated by reference to
Exhibit 4.4(i) to the Company's Form S-3/A (File No.
333-20257) as filed with the SEC on February 14, 1997)
3.1.10 Restated Certificate of Incorporation of Lomak as required by
Item 102 of Regulation S-T (incorporated by reference to
Exhibit 4.4(j) to the Company's Form S-3/A (File No.
333-20257) as filed with the SEC on March 4, 1997)
3.1.11* Certificate of Amendment to the Certificate of Incorporation
of Lomak dated June 20, 1997
3.1.12 Certificate of Amendment to the Certificate of Incorporation
of Lomak dated August 25, 1998 (incorporated by reference to
Exhibit 3.1 to the Company's Form S-8 (File No. 333-62439) as
filed with the SEC on August 28, 1998)
3.1.13 Certificate of Amendment to the Certificate of Incorporation
of the Company dated May 24, 2000 (incorporated by reference
to Exhibit 3.1.12 to the Company's Form 10-Q (File No.
001-12209) as filed with the SEC on May 17, 2003)
3.2.1 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 10-K (File No. 001-12209) as filed with the SEC on March
5, 2002)
4.1.1 Form of 6% Convertible Subordinated Debentures due 2007
(contained as an exhibit to Exhibit 4.1.2 hereto)
4.1.2 Indenture dated December 20, 1996 by and between Lomak and
Keycorp Shareholders Services, Inc., as trustee (incorporated
by reference to Exhibit 4.1(A) to the Company's Form S-3 (File
No. 333-23955) as filed with the SEC on March 25, 1997)
4.2.1 Form of 8-3/4% Senior Subordinated Notes due 2007 (contained
as an exhibit to Exhibit 4.2.2 hereto)
4.2.2 Indenture dated March 14, 1997 by and among Lomak, the
Subsidiary Guarantors (as defined therein) and Fleet National
Bank, as trustee (incorporated by reference to Exhibit 4.3 to
the Company's Form S-3/A (File No. 333-20257) as filed with
the SEC on February 14, 1997)
4.3.1 Form of 5-3/4% Convertible Preferred Securities (contained as
an exhibit to Exhibit 4.3.5 hereto)
41
4.3.2 Form of 5-3/4% Convertible Junior Subordinated Debentures
(contained as an exhibit to Exhibit 4.3.4 hereto)
4.3.3 Indenture dated October 22, 1997 by and between Lomak and The
Bank of New York, as trustee (incorporated by reference to
Exhibit 4.6 of the Company's Form S-3 (File No. 333-43823) as
filed with the SEC on January 7, 1998)
4.3.4 First Supplemental Indenture dated October 22, 1997 by and
between Lomak and The Bank of New York, as trustee
(incorporated by reference to Exhibit 4.7 to the Company's
Form S-3 (File No. 333-43823) as filed with the SEC on January
7, 1998)
4.3.5 Certificate of Trust of Lomak Financing Trust dated October 8,
1997 (incorporated by reference to Exhibit 4.4 to the
Company's Form S-3 (File No. 333-43823) as filed with the SEC
on January 7, 1998)
4.3.6 Amended and Restated Declaration of Trust of Lomak Financing
Trust dated October 22, 1997 by and between the Trustees (as
defined therein), the Sponsor (as defined therein) and the
holders, from time to time, of undivided beneficial ownership
interests in the Trust (as defined therein) (incorporated by
reference to Exhibit 4.5 to the Company's Form S-3 (File No.
333-43823) as filed with the SEC on January 7, 1998)
4.3.7 Convertible Preferred Securities Guarantee Agreement dated
October 22, 1997 by and between Lomak, as guarantor, and The
Bank of New York, as trustee (incorporated by reference to
Exhibit 4.10 to the Company's Form S-3 (File No. 333-43823) as
filed with the SEC on January 7, 1998)
4.3.8 Common Securities Guarantee Agreement dated October 22, 1997
executed and delivered by Lomak, as guarantor, for the benefit
of the Holders (as defined therein) from time to time of the
Common Securities (as defined therein) of Lomak Financing
Trust (incorporated by reference to Exhibit 4.11 to the
Company's Form S-3 (File No. 333-43823) as filed with the SEC
on January 7, 1998)
4.4.1* Form of 7-3/8% Senior Subordinated Notes due 2013 (contained
as an exhibit to Exhibit 4.4.2 hereto)
4.4.2* Indenture dated July 21, 2003 by and among the Company, as
issuer, the Subsidiary Guarantors (as defined therein), as
guarantors, and Bank One, National Association, as trustee
4.4.3* Registration Rights Agreement dated July 21, 2003 by and
between the Company and UBS Securities LLC, Banc One Capital
Markets, Inc., Credit Lyonnais Securities (USA) Inc. and
McDonald Investments Inc.
10.1* Amended Application Service Provider and Outstanding Agreement
dated June 2, 2003 by and between the Company and CGI
Information Systems and Management Consultants, Inc.
10.2* Consulting Agreement dated May 7, 2003 by and between the
Company and Thomas J. Edelman
10.3* Third Amendment to Amended and Restated Credit Agreement dated
April 1, 2003 by and among the Company, Bank One, NA, the
Lenders (as defined therein), Fleet National Bank, Fortis
Capital Corp., JPMorgan Chase Bank, Credit Lyonnais New York
Branch, Banc One Capital Markets, Inc. and JPMorgan Securities
Inc.
10.4.1* Restated Credit Agreement dated May 3, 2002 by and among Great
Lakes Energy Partners, L.L.C. ("Great Lakes"), Bank One, NA,
JPMorgan Chase Bank, The Bank of Nova Scotia, Bank of
Scotland, Credit Lyonnais New York Branch, Fortis Capital
Corp., The Frost National Bank, Union Bank of California, N.A.
and each Lender (as defined therein)
10.4.2* First Amendment to Restated Credit Agreement dated April 1,
2003 by and among Great Lakes, Bank One, NA, JPMorgan Chase
Bank, The Bank of Nova Scotia, Bank of Scotland, Credit
Lyonnais New York Branch, Fortis Capital Corp., The Frost
National Bank, Union Bank of California, N.A., Comerica
Bank-Texas, Natexis Banques Populaires, each Lender (as
defined therein), Banc One Capital Markets, Inc. and JPMorgan
Securities, Inc.
31.1* Certification by the President and Chief Executive Officer of
the Company Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002
31.2* Certification by the Acting Chief Financial Officer of the
Company Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002
32.1* Certification by the President and Chief Executive Officer of
the Company Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2* Certification by the Acting Chief Financial Officer of the
Company Pursuant to 18 U.S.C. Section 1350, as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
- ------------------------------------
* filed herewith
42