<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
(MARK ONE)
{x} QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarter ended June 30, 1999
{ } TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ________
COMMISSION FILE NUMBER 0-9592
RANGE RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 34-1312571
(State of incorporation) (I.R.S. Employer
Identification No.)
500 THROCKMORTON STREET, FT. WORTH, TEXAS 76102
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (817) 870-2601
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
37,567,786 Common Shares were outstanding on August 10, 1999
<PAGE> 2
PART I. FINANCIAL INFORMATION
The financial statements included herein have been prepared in
conformity with generally accepted accounting principles. They should be read in
conjunction with the December 31, 1998 Form 10-K filing. 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.
2
<PAGE> 3
<TABLE>
<CAPTION>
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
December 31, June 30,
1998 1999
------------ ---------
(unaudited)
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents ..................................................... $ 10,954 $ 15,757
Accounts receivable ...................................................... 30,384 27,701
IPF receivables (Note 4) ................................................. 7,140 8,600
Marketable securities .................................................... 3,258 4,422
Assets held for sale (Note 5) ............................................ 51,822 48,687
Inventory and other ...................................................... 3,373 5,289
--------- ---------
106,931 110,456
--------- ---------
IPF receivables, net (Note 4) .............................................. 70,032 63,634
Oil and gas properties, successful efforts method .......................... 935,822 945,372
Accumulated depletion and impairment ................................... (273,723) (302,302)
--------- ---------
662,099 643,070
--------- ---------
Transportation, processing and field assets ................................ 89,471 89,452
Accumulated depreciation ............................................... (15,146) (18,491)
--------- ---------
74,325 70,961
--------- ---------
Other ...................................................................... 8,225 7,556
--------- ---------
$ 921,612 $ 895,677
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable ......................................................... $ 28,163 $ 21,987
Accrued liabilities (Note 13) ............................................ 23,626 21,109
Accrued interest ......................................................... 9,439 9,245
Current portion of debt (Note 6) ......................................... 55,187 52,052
--------- ---------
116,415 104,393
--------- ---------
Senior debt (Note 6) ....................................................... 311,875 317,085
Non-recourse debt of IPF (Note 6) .......................................... 60,100 54,200
Subordinated notes (Note 6) ................................................ 180,000 176,360
Commitments and contingencies (Note 8)
Company-obligated preferred securities of subsidiary trust (Note 9) ........ 120,000 117,669
Stockholders' equity (Notes 9 and 10)
Preferred stock, $1 par, 10,000,000 shares authorized,
$2.03 convertible preferred, 1,149,840 issued and outstanding
(liquidation preference $28,746,000) ................................... 1,150 1,150
Common stock, $.01 par, 50,000,000 shares authorized,
35,933,523 and 37,401,248 issued and outstanding ..................... 359 374
Capital in excess of par value ........................................... 334,817 339,027
Retained deficit ......................................................... (203,396) (216,364)
Other comprehensive income ............................................... 292 1,783
--------- ---------
133,222 125,970
--------- ---------
$ 921,612 $ 895,677
========= =========
</TABLE>
SEE ACCOMPANYING NOTES.
3
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<TABLE>
<CAPTION>
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------- ----------------------------
1998 1999 1998 1999
----------- ------------ ------------ ----------
(unaudited) (unaudited)
<S> <C> <C> <C> <C>
Revenues
Oil and gas sales ......................................... $ 30,740 $ 37,282 $63,280 $ 71,082
Transportation, processing and marketing .................. 1,636 1,855 3,364 3,698
IPF income ................................................ -- 2,081 -- 3,454
Interest and other ........................................ (103) 978 1,639 1,915
-------- -------- ------- --------
32,273 42,196 68,283 80,149
-------- -------- ------- --------
Expenses
Direct operating .......................................... 7,647 10,816 16,043 22,085
IPF expense ............................................... -- 1,474 -- 2,976
Exploration ............................................... 2,018 432 2,431 1,362
General and administrative ................................ 2,096 1,779 3,936 3,662
Interest .................................................. 9,374 12,353 18,108 24,453
Depletion, depreciation and amortization .................. 12,556 19,809 24,764 38,939
-------- -------- ------- --------
33,691 46,663 65,282 93,477
-------- -------- ------- --------
Income (loss) before taxes ................................... (1,418) (4,467) 3,001 (13,328)
Income taxes
Current ................................................... 26 50 135 170
Deferred .................................................. (500) -- 1,051 0
-------- -------- ------- --------
(474) 50 1,186 170
-------- -------- ------- --------
Income (loss) before extraordinary item ...................... (944) (4,517) 1,815 (13,498)
Extraordinary item
Gain on retirement of securities, net (Note 18) ............ -- 2,430 -- 2,430
-------- -------- ------- --------
Net income (loss) ............................................ $ (944) $ (2,087) $ 1,815 $(11,068)
======== ======== ======= ========
Comprehensive income (loss) (Note 2) ......................... $ (2,326) $ (1,258) $ 556 $ (9,665)
======== ======== ======= ========
Earnings (loss) per common share
Basic ................................................... $ (0.07) $ (0.07) $ 0.03 $ (0.34)
======== ======== ======= ========
Dilutive ................................................ $ (0.07) $ (0.07) $ 0.03 $ (0.34)
======== ======== ======= ========
</TABLE>
SEE ACCOMPANYING NOTES.
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<TABLE>
<CAPTION>
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
Six Months Ended June 30,
---------------------------------
1998 1999
--------- ---------
(unaudited)
<S> <C> <C>
Cash flows from operations:
Net income (loss) ................................................. $ 1,815 $ (11,068)
Adjustments to reconcile net income to
net cash provided by operations:
Depletion, depreciation and amortization ..................... 24,764 38,939
Amortization of deferred offering costs ...................... 654 596
Deferred taxes ............................................... 1,051 --
Changes in working capital net of
effects of purchases of businesses:
Accounts receivable ................................. 5,444 2,683
Allowance for IPF receivables ....................... -- 2,197
Marketable securities ............................... (127) --
Inventory and other ................................. 419 (1,987)
Accounts payable .................................... (2,625) (6,215)
Accrued liabilities ................................. 2,892 (2,712)
Gain on sale of assets and other ............................. (1,479) (1,478)
Gain on exchange of securities ............................... -- (2,430)
--------- ---------
Net cash provided by operations ................................... 32,808 18,525
Cash flows from investing:
Oil and gas properties ....................................... (107,528) (15,629)
Additions to property and equipment .......................... (807) (176)
IPF investments of capital ................................... -- (2,733)
IPF repayments of capital .................................... -- 5,474
Proceeds on sale of assets ................................... 16,363 4,199
--------- ---------
Net cash used in investing ........................................ (91,972) (8,865)
Cash flows from financing:
Proceeds from indebtedness ................................... 65,500 7,363
Repayments of indebtedness ................................... (399) (11,189)
Preferred stock dividends .................................... (1,167) (1,167)
Common stock dividends ....................................... (1,305) (733)
Proceeds from common stock issuance .......................... 446 891
Repurchase of common stock ................................... (110) (22)
--------- ---------
Net cash provided by financing .................................... 62,965 (4,857)
--------- ---------
Change in cash .................................................... 3,801 4,803
Cash and equivalents at beginning of period ....................... 9,725 10,954
--------- ---------
Cash and equivalents at end of period ............................. $ 13,526 $ 15,757
========= =========
Supplemental disclosures of non-cash investing and
financing activities:
Common stock issued in connection with benefit plans ............ $ 1,067 $ 374,910
Common stock issued in connection with retirement of
Securities (Note 18) ............................................ -- 3,355
</TABLE>
SEE ACCOMPANYING NOTES.
5
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RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION:
Range Resources Corporation ("Range" or the "Company") is an
independent oil and gas company engaged in development, exploration and
acquisition primarily in three core areas of the United States: the Southwest,
the Gulf Coast and Appalachia. Through its IPF subsidiary, the Company also
provides financing to smaller producers by purchasing term overriding royalty
interests in oil and gas properties. Historically, the Company has increased its
reserves and production through acquisitions, development and exploration. In
pursuing this strategy, the Company has concentrated its activities in selected
geographic areas. In each core area, the Company has established operating,
engineering, geoscience, marketing and acquisition expertise.
In August 1998, the stockholders of the Company approved the
acquisition via merger (the "Merger") of Domain Energy Corporation ("Domain").
Pursuant to the Merger, Domain became a wholly owned subsidiary.
Simultaneously, the Company's name was changed to Range Resources Corporation.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION
The accompanying financial statements include the accounts of the
Company, all majority owned subsidiaries and its pro rata share of the assets,
liabilities, income and expenses of certain oil and gas partnerships and joint
ventures. Highly liquid temporary investments with an initial maturity of ninety
days or less are considered cash equivalents. The Company recognizes revenues
from the sale of its respective products in the period delivered. Revenue for
services is recognized in the period the services are provided.
MARKETABLE SECURITIES
Debt and marketable equity securities are classified in one of three
categories: trading, available-for-sale, or held to maturity. Equity securities
of other companies held by Range qualify as available-for-sale. Such securities
are recorded at fair value, and unrealized holding gains and losses, net of the
related tax effect, are reflected as a separate component of stockholders'
equity. A decline in the market value of an available-for-sale security below
cost that is deemed other than temporary is charged to earnings and results in
the establishment of a new cost basis for the security. Realized gains and
losses are determined on the specific identification method and are reflected in
income. During the six months ended June 30, 1999 Range sold $416,000 of
marketable equity securities for an $88,000 gain.
INDEPENDENT PRODUCER FINANCE ("IPF")
Through IPF, Range acquires dollar denominated term overriding royalty
interests in properties owned by smaller oil and gas producers. The Company
accounts for the acquired term overriding royalty interests as receivables
because the funds advanced to a producer for these interests are repaid from an
agreed upon share of cash proceeds from the sale of production until the amount
advanced plus a specified return is received. Only the interest portion of
payments, net of reserves, received from producers is recognized as IPF income.
The remaining cash receipts are recorded as a reduction in receivables on the
balance sheet and as a return of capital on the statements of cash flows. The
portion of the term overriding royalty interests classified as a current asset
are those expected to be received as repayments over the next twelve month
period. Periodically, the Company reviews IPF's receivables and provides an
allowance for uncollectible amounts. During the first six months of 1999, IPF
recorded gross income of $5.7 million and allowances against its portfolio of
receivables of $2.2 million. At June 30, 1999 IPF's
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<PAGE> 7
allowance for uncollectible receivables totaled $16.2 million. During the first
six months of 1999, IPF expenses were comprised of $2.2 million of interest and
$0.8 million of administrative expenses.
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for oil
and gas properties. Exploratory costs are captialized pending determination of
whether the well has found proved reserves. Exploratory costs which result in
the discovery of proved reserves and the cost of development wells are
capitalized. In the absence of a determination as to whether the reserves found
from an exploratory well can be classified as proved, the costs of drilling such
an exploratory well are not carried as an asset for more than one year following
the completion of drilling. Geological and geophysical costs, delay rentals and
costs to drill unsuccessful exploratory wells are expensed. Depletion is
provided on the unit-of-production method. Oil is converted to Mcfe at the rate
of 6 Mcf per barrel. The depletion rates per Mcfe were $0.84 and $0.98 in the
first six months of 1998 and 1999, respectively. Per unit depletion rates rose
because of the impact of low year-end 1998 oil and gas prices and performance
adjustments on the reserve volumes used to calculate the depletion rate for
1999. Approximately $75.9 million and $72.4 million of oil and gas properties
were classified as unproved leaseholds as of December 31, 1998 and June 30,
1999, respectively.
The Company performs a review for impairment at least annually or
whenever circumstances indicate that the carrying amount of an asset may not be
recoverable. The Company compares the carrying value of its properties to the
present value of their future cash flows of unproved properties discounted at
10%, or considers such other information the Company believes relevant in
evaluating the properties' fair value. Such other information may include the
Company's geological assessment of the area, other acreage purchases occurring
in the area, or the properties' uniqueness. Impairment is recognized if the
carrying amount of an asset is greater than its expected future cash flows or
realizable value. The amount of the impairment is based on the difference
between a property's carrying value and estimated fair value of the asset.
Unproved leaseholds whose acquisition costs are not individually significant are
aggregated, and the portion of such costs estimated to ultimately prove
unproductive are amortized over an average holding period. If such decline is
indicated, a loss is recognized. Changes in reserves or prices could occur in
the near term and adversely impact management's estimate of future cash flows
and consequently the carrying value of the properties.
TRANSPORTATION, PROCESSING AND FIELD ASSETS
The Company owns and operates over 3,000 miles of gas gathering systems
as well as a gas processing plant in proximity to its gas properties.
Depreciation is calculated on the straight-line method based on estimated useful
lives ranging from four to ten years.
The Company receives fees for providing field related services. These
fees are recognized as earned. Depreciation is calculated on the straight-line
method based on estimated useful lives ranging from one to five years, except
buildings which are being depreciated over ten to twenty-five year periods.
SECURITY ISSUANCE COSTS
Expenses associated with the issuance of the 6% Convertible
Subordinated Debentures due 2007, the 8.75% Senior Subordinated Notes due 2007
and the 5 3/4% Trust Convertible Preferred Securities are included in Other
Assets on the accompanying balance sheets and are being amortized on the
interest method over the term of the securities.
7
<PAGE> 8
GAS IMBALANCES
The Company uses the sales method to account for gas imbalances. Under
the sales method, revenue is recognized based on cash received rather than the
proportionate share of gas produced. Gas imbalances at December 31, 1998 and
June 30, 1999 were not material.
COMPREHENSIVE INCOME
Comprehensive income is defined as changes in stockholders' equity from
nonowner sources which includes net income and changes in the fair value of
marketable securities. The following is a calculation of comprehensive income
for the three and six month periods ended June 30, 1998 and 1999.
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------ ------------------------------
1998 1999 1998 1999
------------ ----------- ------------- ------------
<S> <C> <C> <C> <C>
Net income (loss) $ (944) $ (2,087) $ 1,815 $(11,068)
Add: Unrealized gain (loss)
Gross (2,145) 915 (1,949) 1,491
Tax effect 804 -- 731 --
Less: Realized gain (loss)
Gross (66) (86) (66) (88)
Tax effect 25 -- 25 --
-------- -------- -------- --------
Comprehensive income (loss) $ (2,326) $ (1,258) $ 556 $ (9,665)
======== ======== ======== ========
</TABLE>
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
NATURE OF BUSINESS
The Company operates in an environment with many financial and
operating risks, including, but not limited to, the ability to acquire
additional economically recoverable oil and gas reserves, the inherent risks of
the search for, development of and production of oil and gas, the ability to
sell oil and gas at prices which will provide attractive rates of return, and
the highly competitive nature of the industry and worldwide economic conditions.
The Company's ability to expand its reserve base and diversify its operations is
also dependent on its ability to obtain the necessary capital through operating
cash flow, borrowings or the issuance of equity.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative
Instruments and Hedging Activities, which is effective for fiscal years
beginning after June 15, 1999.
SFAS No. 133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. It also requires that an entity
recognize all derivatives as either assets or liabilities on the balance sheet
and measure those items at fair value. If certain conditions are met, a
derivative may be specifically
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<PAGE> 9
designated as (a) a hedge of the exposure to change in the fair value of a
recognized asset or liability or an unrecognized firm commitment, (b) a hedge of
the exposure to variable cash flows of a forecasted transaction or (c) a hedge
of the foreign currency exposure of a net investment in a foreign operation, an
unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated forecasted transaction. The Company plans to adopt
SFAS No. 133 during 2000 and is currently evaluating its effects.
RECLASSIFICATIONS
Certain reclassifications have been made to prior periods presentation
to conform with current classifications.
(3) ACQUISITION AND DEVELOPMENT:
All of the Company's acquisitions have been accounted for as purchases.
Purchase prices were allocated to the assets acquired based on estimates of the
fair value of such assets and liabilities at the respective acquisition dates.
The acquisitions were funded by working capital, advances under the Credit
Facility and the issuance of securities.
In March 1998, oil and gas properties in the Powell Ranch Field in West
Texas (the "Powell Ranch Properties") were acquired for $60 million, comprised
of $54.6 million in cash and $5.4 million of Common Stock.
As described in Note 1, the Company acquired Domain for a purchase
price of $161.6 million, comprised of $50.5 million of cash and $111.1 million
of Common Stock. Domain's principal assets included oil and gas properties in
the Gulf Coast and the Gulf of Mexico, as well as IPF.
The Company acquired other properties for an aggregate consideration of
$2.7 million and $1.1 million during the year ended December 31, 1998 and the
six months ended June 30, 1999, respectively.
UNAUDITED PRO FORMA FINANCIAL INFORMATION
The following table presents unaudited pro forma operating results as
if certain transactions had occurred at the beginning of each period presented.
The pro forma operating results include the Domain and Powell Ranch
acquisitions.
<TABLE>
<CAPTION>
Six months ended June 30,
--------------------------------------
1998 1999
----------------- -----------------
(in thousands, except per share data)
<S> <C> <C>
Revenues............................... $ 102,049 $ 80,149
Net income (loss)...................... (753) (11,068)
Earnings (loss) per share.............. (0.06) (0.34)
Earnings (loss) per share - dilutive... (0.06) (0.34)
Total assets........................... 1,066,274 895,677
Stockholders' equity................... 270,743 125,970
</TABLE>
The pro forma operating results have been prepared for comparative
purposes only. They do not purport to present actual operating results that
would have been achieved had the acquisitions been made at the beginning of each
period presented or to necessarily be indicative of future results of
operations.
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(4) IPF RECEIVABLES
At June 30, 1999, IPF had net receivables of $72.2 million. The
receivables result from the purchase of term overriding royalty interests
representing an agreed share of revenues from certain properties until the
amount invested and a specified rate of return are received. These royalty
interests constitute property interests that serve as security for the
receivables. The Company has estimated that $8.6 million of receivables will be
repaid in the next twelve months and has classified such receivables as current
assets. The net outstanding receivables include an allowance for uncollectible
receivables of $14.0 million and $16.2 million at December 31, 1998 and June 30,
1999, respectively.
(5) ASSETS HELD FOR SALE
Assets held for sale primarily consist of oil and gas properties
located in south Texas and in the Gulf of Mexico. The Company has entered into
agreements with an independent firm to assist it in selling these assets. The
assets are recorded at the lower of cost or estimated market value of the
properties as assets held for sale in the current asset section of the
Consolidated Balance Sheets as of December 31, 1998 and June 30, 1999. These
sales are expected to be completed during 1999. The Company sold properties for
$4.1 million during the six months ended June 30, 1999. In July 1999, the
Company subsequently sold properties for $16.9 million.
(6) INDEBTEDNESS:
The Company had the following debt outstanding as of the dates shown.
Interest rates at June 30, 1999 are shown parenthetically (in thousands):
<TABLE>
<CAPTION>
December 31, June 30,
1998 1999
------------- ------------
<S> <C> <C>
Credit Facility (7.1%) .................................. $365,175 $369,100
Other (0.9%) ............................................ 1,887 37
-------- --------
367,062 369,137
Less amounts due within one year ........................ 55,187 52,052
-------- --------
Senior debt, net ........................................ $311,875 $317,085
======== ========
Non-recourse debt of IPF subsidiary (7.3%) .............. $ 60,100 $ 54,200
8.75% Senior Subordinated Notes due 2007 ............... $125,000 $125,000
6% Convertible Subordinated Debentures due 2007 ........ 55,000 51,360
-------- --------
Subordinated debt ....................................... $180,000 $176,360
======== ========
</TABLE>
The Company maintains a $400 million revolving bank facility (the
"Credit Facility"). The Credit Facility provides for a borrowing base, which is
subject to semi-annual redeterminations. The Credit Facility is secured by the
Company's oil and gas properties. At August 10, 1999, the borrowing base on the
Credit Facility was $385 million of which $41.9 million was available to be
drawn. Interest is payable quarterly or as LIBOR notes mature and the loan
matures in February 2003. A commitment fee is paid quarterly on the undrawn
balance at a rate of 0.25% to 0.375% depending upon the percentage of the
borrowing base drawn. It is the Company's policy to extend the term period of
the Credit Facility annually. Through April 30, 1999, the interest rate on the
Credit Facility was LIBOR plus 1.75%. Until amounts under the Credit Facility
are reduced to $300 million or the redetermined borrowing base, the interest
rate is LIBOR plus 2.0%. The Company is subject to a redetermination on
September 30, 1999.
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If amounts outstanding under the Credit Facility exceed the higher of the
redetermined borrowing base or $300 million on August 31, 1999, then the Company
will have 10 days to repay any excess. At June 30, 1999, the Company classified
$52.1 million of borrowings under the Credit Facility as current to reflect an
estimate of the amounts outstanding that will be repaid during the next twelve
months. The weighted average interest rates on these borrowings were 6.6% and
7.05% for the six months ended June 30, 1998 and 1999, respectively.
IPF has a $150 million revolving credit facility (the "IPF Facility")
through which it finances its activities. The IPF Facility matures July 1, 2001
at which time all amounts owed thereunder are due and payable. The IPF Facility
is secured by substantially all of IPF's assets and is non-recourse to the
Company. The Company has no rights or obligations as to the IPF Facility. The
borrowing base under the IPF Facility is subject to redeterminations, which
occur routinely during the year and is currently under review. On August 10,
1999, the borrowing base on the IPF Facility was $56.5 million of which $2.9
million was available to be drawn. The IPF Facility bears interest at prime rate
or interest at LIBOR plus a margin of 1.75% to 2.25% per annum depending on the
total amount outstanding. Interest expense during the first six months of 1999
amounted to $2.2 million and is included in IPF expenses on the Consolidated
Statements of Income. A commitment fee is paid quarterly by IPF on the average
undrawn balance at a rate of 0.375% to 0.50%. The weighted average interest rate
on these borrowings was 7.26% on June 30, 1999.
The 8.75% Senior Subordinated Notes due 2007 (the "8.75% Notes") are
not redeemable prior to January 15, 2002. Thereafter, the 8.75% Notes will be
subject to redemption at the option of the Company, in whole or in part, at
redemption prices beginning at 104.375% of the principal amount and declining to
100% in 2005. The 8.75% Notes are unsecured general obligations of the Company
and are subordinated to all senior debt (as defined) including borrowings under
the Credit Facility. The 8.75% Notes are guaranteed on a senior subordinated
basis by the Company's subsidiaries.
The 6% Convertible Subordinated Debentures Due 2007 (the "Debentures")
are convertible into shares of Common Stock at the option of the holder at any
time prior to maturity. The Debentures are convertible at a conversion price of
$19.25 per share, subject to adjustment in certain events. Interest is payable
semi-annually in January and June. The Debentures mature in 2007 and are
redeemable beginning on February 1, 2000 at a price of 104% of the face amount
and declining 0.5% annually though 2007. The Debentures are unsecured general
obligations and are subordinated to all senior indebtedness (as defined), which
includes the 8.75% Notes and the Credit Facility. During the first six months of
1999, $3.6 million of Debentures were retired at the option of the holders in
exchange for approximately 496,000 shares of Common Stock. An extraordinary gain
of $1.2 million was recorded because the Debentures were retired at a discount
to their face value.
The debt agreements contain covenants relating to net worth, working
capital maintenance and financial ratio requirements. The Company is in
compliance with these various covenants as of June 30, 1999. Interest paid
during the six month periods ended June 30, 1998 and 1999 totaled, $17.9 million
and $24.4 million, respectively. The Company has not capitalized any interest in
the periods presented.
(7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES:
The Company's financial instruments include cash and equivalents,
accounts receivable, accounts payable, debt obligations, commodity and interest
rate futures, options, and swaps. The book value of cash and equivalents,
accounts receivable and payable and short term debt are considered to be
representative of fair value because of the short maturity of these instruments.
The Company believes that the carrying value of its borrowings under its bank
credit facility approximates their fair value as they bear interest at rates
indexed to LIBOR. The Company's accounts receivable are concentrated in the oil
and gas industry. The Company does not view such a concentration as an unusual
credit risk. The Company had allowances for doubtful accounts (excluding IPF) of
$782,000 and $921,000 at December 31, 1998 and June 30, 1999, respectively.
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<PAGE> 12
A portion of the Company's crude oil and natural gas sales are
periodically hedged against price risks through the use of futures, option or
swap contracts. The gains and losses on these instruments are included in the
valuation of the production being hedged in the contract month and are included
as an adjustment to oil and gas revenue. The Company also manages interest rate
risk on its Credit Facility through the use of interest rate swap agreements.
Gains and losses on swap agreements are included as an adjustment to interest
expense.
The following table sets forth the book value and estimated fair values
of the Company's financial instruments:
<TABLE>
<CAPTION>
December 31, June 30,
1998 1999
------------------------------- -------------------------------
(In thousands)
Book Fair Book Fair
Value Value Value Value
-------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Cash and equivalents ........................ $ 10,954 $ 10,954 $ 15,757 $ 15,757
Marketable securities ....................... 2,966 3,258 2,639 4,422
Long-term debt .............................. (607,162) (607,162) (599,697) (599,697)
Commodity swaps ............................. -- 45 -- (6,795)
Interest rate swaps ......................... -- (361) -- (69)
</TABLE>
At June 30, 1999, the Company had open contracts for gas and oil price
derivative swaps of 25 Bcf of gas and 1,000,000 Bbls of oil. The swap contracts
are designed to set average prices ranging from $1.90 to $2.75 per Mcf of gas
and fix oil prices ranging form $16.82 to $19.15 per Bbl. While these
transactions have no carrying value, their fair value, represented by the
estimated amount that would be required to terminate the contracts, was a net
loss of approximately $6.8 million at June 30, 1999. These contracts expire
monthly through September 2000 on gas and through March 2000 on oil. The gains
or losses on the Company's hedging transactions are determined as the difference
between the contract price and the reference price, generally closing prices on
the New York Mercantile Exchange. The resulting transaction gains and losses are
determined monthly and are included in net income in the period the hedged
production or inventory is sold. Net gains or (losses) relating to these
derivatives for the six months ended June 30, 1998 and 1999 approximated $1.4
million and $1.3 million, respectively.
Interest rate swap agreements, which are used by the Company in the
management of interest rate exposure, are accounted for on the accrual basis.
Income and expense resulting from these agreements are recorded in the same
category as expense arising from the related liability. Amounts to be paid or
received under interest rate swap agreements are recognized as an adjustment to
expense in the periods in which they accrue. At June 30, 1999, the Company had
$100 million of borrowings subject to five interest rate swap agreements at
rates of 5.71%, 5.59%, 5.35%, 4.82% and 5.64% through September 1999, October
1999, January 2000, September 2000 and October 2000, respectively. The interest
rate swaps may be extended at the counterparties' option for two years. The
agreements require that the Company pay the counterparty interest at the above
fixed swap rates and requires the counterparty to pay the Company interest at
the 30-day LIBOR rate. The closing 30-day LIBOR rate on June 30, 1999 was 5.22%.
The fair value of the interest rate swap agreements at June 30, 1999 is based
upon current quotes for equivalent agreements. As discussed in Note 6, the
Company's bank facilities are based on LIBOR plus applicable margin (as
defined).
These hedging activities are conducted with major financial or
commodities trading institutions which management believes entail acceptable
levels of market and credit risks. At times such risks may be concentrated with
certain counterparties or groups of counterparties. The credit worthiness of
counterparties is subject to continuing review and full performance is
anticipated.
12
<PAGE> 13
(8) COMMITMENTS AND CONTINGENCIES:
The Company is involved in various legal actions and claims arising in
the ordinary course of business. In the opinion of management, such litigation
and claims are likely to be resolved without material adverse effect on the
Company's financial position or results of operations.
In July 1997, a gas utility filed an action in the State District Court
of Texas. In the lawsuit, the gas utility asserted a breach of contract claim
arising out of a gas purchase contract. Under the gas utility's interpretation
of the contract, it sought, as damages, the reimbursement of the difference
between the above-market contract price it paid and market price on a portion of
the gas it has taken beginning in July 1997. In May 1998, the court granted a
partial summary judgment on the contract interpretation issue in favor of the
gas utility. The summary judgment allows the utility to take or pay for a
limited volume of gas defined in the contract as the "contract volume" at the
contract price. In October 1998, the gas utility dropped its damages claim and
the state district court signed a final judgment in this case. Range appealed
the judgment and in August 1999 the court of appeals affirmed the lower court's
judgement. Range believes it has fully reflected the effects of the litigation
in its financial statements.
In May 1998, a Domain stockholder filed an action in the Delaware Court
of Chancery, alleging that the terms of the Merger were unfair to a purported
class of Domain stockholders and that the defendants (except Range) violated
their legal duties to the class in connection with the Merger. Range is alleged
to have aided and abetted the breaches of fiduciary duty allegedly committed by
the other defendants. The action sought an injunction enjoining the Merger as
well as a claim for money damages. On September 3, 1998, the parties executed a
Memorandum of Understanding (the "MOU"), which represents a settlement in
principle of the litigation. Under the terms of the MOU, appraisal rights
(subject to certain conditions) were offered to all holders of Domain common
stock (excluding the defendants and their affiliates). Domain also agreed to pay
any court-awarded attorneys' fees and expenses of the plaintiffs' counsel in an
amount not to exceed $290,000. The settlement in principle is subject to court
approval and certain other conditions that have not been satisfied.
(9) EQUITY SECURITIES:
On October 16, 1997, the Company, through a newly-formed affiliate
Lomak Financing Trust (the "Trust"), completed the issuance of $120 million of 5
3/4% trust convertible preferred securities (the "Convertible Preferred
Securities"). The Trust issued 2,400,000 shares of the Convertible Preferred
Securities at $50 per share. Each Convertible Preferred Security is convertible
at the holder's option into 2.1277 shares of Common Stock, representing a
conversion price of $23.50 per share. During the first six months of 1999, $2.3
million of Convertible Preferred Securities were retired at the option of the
holders in exchange for approximately 202,000 shares of Common Stock. An
extraordinary gain of $1.2 million was recorded because the Trust Convertible
Preferred Securities were retired at a discount to their face value.
The Trust invested the $120 million of proceeds in 5 3/4% convertible
junior subordinated debentures issued by Range (the " Junior Debentures"). In
turn, Range used the net proceeds from the issuance of the Junior Debentures to
repay a portion of its Credit Facility. The sole assets of the Trust are the
Junior Debentures. The Junior Debentures and the related Convertible Preferred
Securities mature on November 1, 2027. Range and the Trust may redeem the Junior
Debentures and the Convertible Preferred Securities, respectively, in whole or
in part, on or after November 4, 2000. For the first twelve months thereafter,
redemptions may be made at 104.025% of the principal amount. This premium
declines proportionally every twelve months until November 1, 2007, when the
redemption price falls to 100% of the principal. If Range redeems any Junior
Debentures prior to the scheduled maturity date, the Trust must redeem
Convertible Preferred Securities having an aggregate liquidation amount equal to
the aggregate principal amount of the Junior Debentures so redeemed.
13
<PAGE> 14
The Company has guaranteed the payments of distributions and other
payments on the Convertible Preferred Securities only if and to the extent that
the Trust has funds available. Such guarantee, when taken together with Range's
obligations under the Junior Debentures and related indenture and declaration of
trust, provide a full and unconditional guarantee of amounts due on the
Convertible Preferred Securities.
Range owns all the common securities of the Trust. As such, the
accounts of the Trust have been included in Range's consolidated financial
statements after appropriate eliminations of intercompany balances. The
distributions on the Convertible Preferred Securities have been recorded as a
charge to interest expense on Range's consolidated statements of income, and
such distributions are deductible by Range for income tax purposes.
In November 1995, the Company issued 1,150,000 shares of $2.03
convertible exchangeable preferred stock (the "$2.03 Preferred Stock") for $28.8
million. The $2.03 Preferred Stock is convertible into the Company's common
stock at a conversion price of $9.50 per share, subject to adjustment in certain
events. The $2.03 Preferred Stock is currently redeemable, at the option of the
Company, at a price of $26.25 per share beginning November 1, 1998, declining
$.25 per share annually through 2003. At the option of the Company, the $2.03
Preferred Stock is exchangeable for the Company's 8-1/8% Convertible
Subordinated Notes due 2005. The notes would be subject to the same redemption
and conversion terms as the $2.03 Preferred Stock.
(10) STOCK OPTION AND PURCHASE PLAN:
The Company has four stock option plans as well as a stock purchase
plan. Two of the stock option plans were adopted as a result of the Merger.
Information with respect to these plans is summarized below:
<TABLE>
<CAPTION>
Plans adopted via the Merger
---------------------------------------------
Option Director's Option Director's
Plan Plan Plan Plan Total
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Outstanding at December 31, 1998: .... 2,042,757 140,000 938,976 19,340 3,141,073
Granted ........................ 904,150 40,000 -- -- 944,150
Exercised ...................... -- -- (368,482) -- (368,482)
Expired/Cancelled .............. (303,575) (12,000) (1,445) -- (317,020)
---------- ---------- ---------- ---------- ----------
Outstanding at June 30, 1999: ........ 2,643,332 168,000 569,049 19,340 3,399,721
========== ========== ========== ========== ==========
</TABLE>
Range maintains a stock option plan (the "Option Plan") which
authorizes the grant of options on up to 3.0 million shares of Common Stock.
Under the Option Plan, incentive and non-qualified options may be issued to
officers, key employees and consultants. The Option Plan is administered by the
Compensation Committee of the Board. All options issued under the Option Plan
before September 1998 vest 30% after one year, 60% after two years and 100%
after three years. Options issued after that date vest 25% per year beginning
one year after the grant date. During the six months ended June 30, 1999, no
options were exercised. At June 30, 1999, 963,477 options were exercisable at
prices ranging from $3.375 to $18.00 per share.
In 1994, the stockholders approved an Outside Directors Stock Option
Plan (the "Directors Plan"). Only Directors who are not employees of the Company
are eligible to participate in the Directors Plan. The Directors Plan covers a
maximum of 200,000 shares. At June 30, 1999, 92,800 director options were
exercisable at prices ranging from $7.75 to $16.88 per share.
In connection with the Merger, Range adopted the Second Amended and
Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain Energy
Corporation and Affiliates (the "Domain
14
<PAGE> 15
Option Plan") and the Domain Energy Corporation 1997 Stock Option Plan for
Nonemployee Directors (the "Domain Director Plan"). Subsequent to the Merger, no
new options will be granted under the Domain Option and Director Plans and
existing options are exercisable into shares of Range Common Stock. During the
six months ended June 30, 1999 options covering 356,812 shares were exercised at
a price of $0.01 per share and 11,670 shares were exercised at $3.46 per share.
At June 30, 1999, 457,626 options were currently exercisable under the Domain
Option Plan at $3.46 to $11.70 per share. The remaining 13,008 options are
currently exercisable at an exercise price of $0.01 per share. At June 30, 1999,
options totaling 19,340 shares were outstanding and exercisable under the Domain
Director Plan at $11.17 per share.
In June 1997, the stockholders approved the 1997 Stock Purchase Plan
(the "1997 Plan") which authorizes the sale of up to 900,000 shares of common
stock to officers, directors, key employees and consultants. Under the Plan, the
right to purchase shares at prices ranging from 50% to 85% of market value may
be granted. The Company previously had stock purchase plans which covered
833,333 shares. The previous stock purchase plans have been terminated. The
plans are administered by the Compensation Committee of the Board. From
inception through June 30, 1999, a total of 417,397 registered shares had been
sold under this plan through stock purchase plans, for a total consideration of
approximately $2.6 million.
(11) BENEFIT PLAN:
The Company maintains a 401(K) Plan for the benefit of its employees.
The Plan permits employees to make contributions on a pre-tax salary reduction
basis. The Company makes discretionary contributions to the Plan. Company
contributions for 1998 totaled $0.7 million of Common Stock, valued at market on
date of contribution.
(12) INCOME TAXES:
The Company follows FASB Statement No. 109, "Accounting for Income
Taxes". Under Statement 109, the liability method is used in accounting for
income taxes. 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 laws
that will be in effect when the differences are expected to reverse.
The income tax provisions for the six month periods ended June 30, 1998
and 1999 were $1.2 million and $0.2 million, respectively. The current portion
of the income tax provisions represent state income taxes currently payable.
Statement 109 requires a valuation allowance be recorded when it is more likely
than not that some or all of the deferred tax assets will not be realized. A
valuation allowance for the full amount of the net deferred tax asset was
recorded due to the uncertainties as to the amount of taxable income that would
be generated in future years. The Company established a valuation allowance of
$25 million at December 31, 1998 and increased the allowance to $30 million at
June 30, 1999. Upon future realization of the deferred tax asset, $30 million of
the valuation allowance will reduce the Company's future income tax expense.
The Company has entered into several business combinations accounted
for as purchases. In connection with these transactions, deferred tax assets and
liabilities of $7.7 million and $38.3 million respectively, were recorded. In
1998 the Company acquired Domain Energy Corporation in a taxable business
combination accounted for as a purchase. A net deferred tax liability of $29
million was recorded in the transaction.
At December 31, 1998, the Company had available for federal income tax
reporting purposes net operating loss carryovers of approximately $131 million
that are subject to annual limitations as to their utilization and otherwise
expire between 1999 and 2013, if unused. The Company has alternative minimum tax
net operating loss carryovers of $116 million that are subject to annual
limitations as to
15
<PAGE> 16
their utilization and otherwise expire from 1999 to 2013 if unused. The Company
has statutory depletion carryover of approximately $4 million and an alternative
minimum tax credit carryover of approximately $911,000. The statutory depletion
carryover and alternative minimum tax credit carryover are not subject to
limitation or expiration.
(13) ACCRUED RESTRUCTURING COSTS:
In 1998, the Company implemented a restructuring plan to reduce costs
and improve operating efficiencies. The restructuring plan included actions by
the Company to close certain field offices, eliminate a number of technical
positions, cancel certain exploration and drilling obligations, as well as
consolidate administrative functions. In connection with this plan, 54 employees
were terminated. In addition to termination costs, the restructuring costs
include the writedown of certain impaired assets and lease and contract
termination costs. Estimated charges of $0.7 million for lease and contract
terminations and $0.4 million for asset impairments were recorded during the
fourth quarter of 1998. At December 31, 1998 and June 30, 1999, $2.7 million and
$0.5 million, respectively, were accrued in connection with the restructuring
and are included in Consolidated Balance Sheet as accrued liabilities. The
accrual remaining at June 30, 1999 was comprised primarily of lease and contract
termination costs. The plan is anticipated to be completed during the third
quarter of 1999.
(14) EARNINGS PER COMMON SHARE
The following table sets forth the computation of earnings per common
share and earnings per common share - assuming dilution (in thousands, except
per share data):
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------- -------------------------
1998 1999 1998 1999
-------- -------- -------- --------
Numerator:
<S> <C> <C> <C> <C>
Net Income ........................................ $ (944) $ (2,087) $ 1,815 $(11,068)
Preferred stock dividends ......................... (584) (584) (1,167) (1,167)
-------- -------- -------- --------
Numerator for earnings per common share ........... (1,528) (2,671) 648 (12,235)
Effect of dilutive securities:
Preferred stock dividends ....................... -- -- -- --
-------- -------- -------- --------
Numerator for earnings per common
share - assuming dilution ....................... $ (1,528) $ (2,671) $ 648 $(12,235)
======== ======== ======== ========
Denominator:
Denominator for basic earnings per common
share - weighted average shares ................. 21,162 36,619 21,136 36,442
Effect of dilutive securities:
Employee stock options .......................... 350 -- 443 --
Warrants ........................................ -- -- -- --
-------- -------- -------- --------
Dilutive potential common shares .................. 350 -- 443 --
-------- -------- -------- --------
Denominator for diluted earnings per share
adjusted weighted-average shares and
assumed conversions ............................. 21,512 36,619 21,579 36,442
======== ======== ======== ========
Earnings (loss) per common share ...................... $ (0.07) $ (0.07) $ 0.03 $ (0.34)
======== ======== ======== ========
Earnings (loss) per common
share - assuming dilution ....................... $ (0.07) $ (0.07) $ 0.03 $ (0.34)
======== ======== ======== ========
</TABLE>
16
<PAGE> 17
For additional disclosure regarding the Debentures and the $2.03
Preferred Stock, see Notes 6 and 9, respectively. The Debentures were
outstanding during 1998 and the first six months of 1999 but were not included
in the computation of diluted earnings per share because the conversion price
was greater than the average market price of common shares and, therefore, the
effect would be antidilutive. The $2.03 Preferred Stock was outstanding during
1998 and the first six months of 1999 and was convertible into 3,026,316 of
additional shares of common stock. The 3,026,316 additional shares were not
included in the computation of diluted earnings per share because the conversion
price was greater than the average market price of common shares and, therefore,
the effect would be antidilutive. There were employee stock options outstanding
during the first six months of 1998 and 1999 which were exercisable, resulting
in 1,104,150 and 1,636,583 additional shares, respectively, under the treasury
method of accounting for common stock equivalents. These additional shares were
not included in the first six months 1999 computations of diluted earnings per
share because the effect was antidilutive.
(15) MAJOR CUSTOMERS:
The Company markets its oil and gas production on a competitive basis.
The type of contract under which gas production is sold varies but can generally
be grouped into three categories: (a) life-of-the-well; (b) long-term (1 year or
longer); and (c) short-term contracts which may have a primary term of one year,
but which are cancelable at either party's discretion in 30-120 days.
Approximately 11.5% of the Company's gas production is currently sold under
market sensitive contracts which do not contain floor price provisions. For the
six months ended June 30, 1999, no one customer accounted for 10% or more of the
Company's total oil and gas revenues. Management believes that the loss of any
one customer would not have a material adverse effect on the operations of the
Company. Oil is sold on a basis such that the purchaser can be changed on 30
days notice. The price received is generally equal to a posted price set by the
major purchasers in the area. Oil is sold on a basis of price and service.
(16) OIL AND GAS ACTIVITIES:
The following summarizes selected information with respect to oil and
gas activities (in thousands):
<TABLE>
<CAPTION>
December 31, June 30,
1998 1999
------------- ------------
(unaudited)
<S> <C> <C>
Oil and gas properties:
Subject to depletion ..................................... $ 859,911 $ 873,017
Not subject to depletion ................................. 75,911 72,355
--------- ---------
Total ................................................ 935,822 945,372
Accumulated depletion .................................... (273,723) (302,302)
--------- ---------
Net oil and gas properties ........................... $ 662,099 $ 643,070
========= =========
</TABLE>
17
<PAGE> 18
<TABLE>
<CAPTION>
Six months
Year Ended Ended
December 31, June 30,
1998 1999
----------- ----------
(unaudited)
<S> <C> <C>
Costs incurred:
Acquisition ................................................. $286,974 $ 1,134
Development ................................................. 71,793 14,495
Exploration ................................................. 9,756 1,362
-------- --------
Total costs incurred ...................................... $368,523 $ 16,991
======== ========
</TABLE>
(17) SUBSEQUENT EVENTS
In June 1999, Range signed a letter of intent to form a joint venture
with First Energy Corporation. Under the terms of the letter, Range and First
Energy will contribute their Appalachian oil and gas properties and associated
gas gathering and transportation systems to the venture and each partner will
own 50% of the joint venture. Range will be contributing approximately $300
million of assets and $200 million of debt from its Credit Facility. The
Appalachian properties Range intends to contribute to the joint venture
represent approximately $17.5 million of the Company's oil and gas revenues for
the six months ended June 30, 1999. Subsequent to closing, Range intends to
consolidate its 50% interest in the assets, liabilities and operations of the
joint venture. The parties need to negotiate and execute definitive agreements,
complete due diligence, obtain financing and receive regulatory approval.
(18) EXTRAORDINARY ITEM
During 1999 Range exchanged $2.3 million of Convertible Preferred
Securities and $3.6 million of Debentures for approximately 698,000 shares of
Common Stock. In connection with the exchange a $2.4 million extraordinary gain
was recorded because the Convertible Preferred Securities and Debentures were
retired at a discount to their face value.
18
<PAGE> 19
MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
------------------------------------------------
FACTORS EFFECTING FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY AND CAPITAL RESOURCES
General
At June 30, 1999, the Company had $20 million in cash and marketable
securities and total assets of $896 million. At that date, working capital was
$6.1 million. During the first six months of 1999, total debt decreased $4.3
million.
Approximately $369 million of the long-term debt at that date was
comprised of borrowings under the Credit Facility, $125 million of 8.75% Senior
Subordinated Notes and $51 million of 6% Convertible Subordinated Debentures.
The Credit Facility currently provides for quarterly payments of interest, or as
LIBOR notes mature, with principal due in February 2003.
During 1999 Range exchanged $2.3 million of Convertible Preferred
Securities and $3.6 million of Debentures for approximately 698,000 shares of
Common Stock. In connection with the exchange a $2.4 million extraordinary gain
was recorded because the Convertible Preferred securities and Debentures were
retired at a discount to their face value.
Cash Flow
The Company's principal operating sources of cash include sales of oil
and gas and revenues from gas transportation and marketing. The Company's cash
flow is highly dependent upon oil and gas prices. Recent decreases in the market
price of oil or gas have reduced cash flow and could reduce the borrowing base
under the Credit Facility.
The Company's principal operating sources of cash are sales of oil,
natural gas and natural gas liquids, sales of natural gas, revenues from
transportation, processing and marketing and IPF repayments. The decreases in
the Company's cash flow from operations can be attributed primarily to decreases
in oil and natural gas prices.
The Company's net cash used in investing for the six months ended June
30, 1998 and 1999 was $92 million and $8.9 million, respectively. Investing
activities for these periods are comprised primarily of additions to oil and gas
properties through acquisitions and development and, to a lesser extent,
exploitation and additions of field assets. These uses of cash have historically
been partially offset through the Company's policy of divesting those properties
that it deems to be marginal or outside of its core areas of operation. The
Company's acquisition and development activities have been financed through a
combination of operating cash flow, bank borrowings and capital raised through
equity and debt offerings.
The Company's net cash provided by financing for the six months ended
June 30, 1998 and 1999 was $63 million and $(4.9) million, respectively. Sources
of financing used by the Company have been primarily borrowings under its Credit
Facility and capital raised through the various debt and equity offerings.
Capital Requirements
During the first six months of 1999, $15.9 million of costs were
incurred for development and exploration activities. In an effort to reduce
outstanding debt, the Company reduced its 1999 exploration
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<PAGE> 20
and development capital budget to $38 million. The development and exploration
expenditures are currently expected to be funded entirely by internally
generated cash flow. Bank Facilities
The Credit Facility permits the Company to obtain revolving credit
loans and to issue letters of credit for the account of the Company from time to
time in an aggregate amount not to exceed $400 million. The Credit Facility is
secured by the Company's oil and gas properties. The borrowing base is currently
$385 million and is subject to semi-annual redetermination and certain other
redeterminations based upon a variety of factors, including the discounted
present value of estimated future net cash flow from oil and gas production. At
the Company's option, loans may be prepaid, and revolving credit commitments may
be reduced, in whole or in part at any time in certain minimum amounts. At
August 10, 1999, the Company had $41.9 million of availability under the Credit
Facility. Through April 30, 1999, the interest rate on the Credit Facility was
LIBOR plus 1.75%. Until amounts under the Credit Facility are reduced to $300
million or the redetermined borrowing base, the interest rate will be LIBOR plus
2.0%. The Company is subject to a redetermination on September 30, 1999. If
amounts outstanding under the Credit Facility exceed the higher of the
redetermined borrowing base or $300 million on August 31, 1999, then the Company
will have 10 days to repay any excess.
The Company plans to reduce outstanding amounts under the Credit
Facility through operating cash flow and the sale of assets. Since the borrowing
base is principally determined by the estimated value of oil and gas reserves
these asset sales are expected to reduce the borrowing base and cash flows due
to the loss of future production. The Company has developed a number of packages
of oil and gas assets to offer for sale. The Company will utilize the proceeds
from the sale of assets to reduce amounts outstanding under the Credit Facility.
Additionally, the Company is considering the monetization of oil and gas assets
whose proceeds would be used to reduce the Credit Facility. At June 30, 1999,
the Company classified $55.2 million of Credit Facility borrowings as current to
reflect an estimate of the amounts outstanding at June 30, 1999 that will be
repaid during the next twelve months.
The IPF Facility is secured by substantially all of IPF's assets and is
non-recourse to the Company. The borrowing base under the IPF Facility is
subject to redeterminations, which occur routinely during the year. On August
10, 1999, the borrowing base on the IPF Facility was $56.5 million of which $2.9
million was available to be drawn. The IPF Facility bears interest at prime rate
or interest at LIBOR plus a margin of 1.75% to 2.25% per annum depending on the
amount outstanding.
Hedging Activities
Periodically, the Company enters into futures, option and swap
contracts to reduce the effects of fluctuations in crude oil and natural gas
prices. At June 30, 1999, the Company had open hedges for natural gas swaps of
25 Bcf and oil swaps of 1,000,000 barrels. The hedged contracts are designed to
set average prices ranging from $1.90 to $2.75 per Mcf of gas and fix oil prices
at $18.24 per barrel. While these transactions have no carrying value, the
Company's mark-to-market exposure under these contracts at June 30, 1999 was a
net loss of $6.8 million. The gains or losses on the Company's hedging
transactions is determined as the difference between the contract price and a
reference price, generally closing prices on the NYMEX. The resulting
transaction gains and losses are determined monthly and are included in the
period the hedged production or inventory is sold. Net gains (losses) relating
to these derivatives for the six months ended June 30, 1998 and 1999
approximated $1.4 million and $1.3 million, respectively.
INFLATION AND CHANGES IN PRICES
The Company's revenues and the value of its oil and gas properties have
been and will be affected by changes in oil and gas prices. The Company's
ability to maintain current borrowing capacity and to obtain additional capital
on attractive terms is also substantially dependent on oil and gas prices. Oil
and gas prices are subject to significant seasonal and other fluctuations that
are beyond the Company's
20
<PAGE> 21
ability to control or predict. During the first six months of 1999, the Company
received an average of $12.94 per barrel of oil and $1.94 per Mcf of gas.
Although certain of the Company's costs and expenses are affected by the level
of inflation, inflation did not have a significant effect during the first six
months of in 1999. Should conditions in the industry improve, inflationary cost
pressures may resume. RESULTS OF OPERATIONS
Comparison of 1999 to 1998
The Company reported a net loss for the three months ended June 30,
1999 of $2.1 million, versus a $0.9 million loss in the prior year period. The
decrease was primarily the result of lower product prices received on oil and
gas production and higher interest and depletion expenses. During the periods
presented, oil and gas production volumes increased 35% to 18.0 Bcfe, an average
of 197,650 Mcfe per day. Production revenues were impacted by a 10% decrease in
the average price received per Mcfe of production from $2.31 in 1998 to $2.07 in
1999. The average oil price increased 25% to $15.21 per barrel while average gas
prices decreased 19% to $2.00 per Mcf. As a result of the Company's larger base
of producing properties and production, oil and gas production expenses
increased 41% to $10.8 million in 1999 versus $7.6 million in 1998. The average
operating cost per Mcfe produced increased 5% from $0.57 to $0.60 in the three
months ended June 30, 1998 and 1999, respectively.
Transportation, processing and marketing revenues increased only
marginally during 1999. IPF income consists of the interest portion of the term
overriding royalty interests and is net of an allowance for possible
uncollectible accounts. During the second quarter of 1999, IPF expenses included
$1.1 million of interest and $0.4 million of administrative expenses.
Exploration expense decreased approximately $1.6 million to $0.4
million due to restructuring and the cost reduction program. General and
administrative expenses decreased 15% to $1.8 million. General and
administrative cost per Mcfe produced decreased 38% from $0.16 in 1998 to $0.10
in 1999. The decrease is principally attributable to the cost reduction program.
Interest and other income increased from $(0.1) million in 1998 to $1.0
million in 1999 primarily due to increased sales of oil and gas properties. In
1999 interest expense increased 32% to $12.4 million as compared to $9.4 million
in 1998. This was primarily as a result of the higher average outstanding debt
balance during the year due to the financing of acquisitions and capital
expenditures and a higher average cost of borrowings. The average outstanding
balances on the Credit Facility were $202 million and $370 million for the first
six months of 1998 and 1999, respectively. The weighted average interest rate on
these borrowings were 6.6% and 6.9% for the six months ended June 30, 1998 and
1999, respectively.
Depletion, depreciation and amortization increased 58% compared to 1998
as a result of increased production volumes and the amortization of $1.9 million
of unproved acreage. The Company's depletion rate was $0.84 per Mcfe in the
first six months of 1998 and $0.98 per Mcfe in the first six months of 1999.
YEAR 2000
The Company has developed a plan (the "Year 2000 Plan") to address the
Year 2000 issue caused by computer programs and applications that utilize two
digit date fields rather than four to designate a year. As a result, computer
equipment, software and devices with embedded technology that are date sensitive
may be unable to recognize or misinterpret the actual date. This could result in
a system failure or miscalculations causing disruptions of operations. The
Company's Board of Directors has established a Year 2000 committee to review the
adoption and implementation of the Year 2000 Plan.
Assessment of the information technology ("IT") and non-IT systems has
been completed. The term "IT systems" include personal computers,
accounting/data processing software and other
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miscellaneous systems. Range's computerized accounting system was upgraded and
tested to be Year 2000 compliant. The Company's personal computer systems will
be compliant with minor upgrades provided by the software vendors and with the
purchase of a nominal amount of additional computer equipment.
The non-IT systems include operational and control equipment with
embedded chip technology that is utilized in the offices and field operations.
The systems were reviewed as part of the Year 2000 Plan. Most of the wells are
operated by non-computerized equipment. The potentially affected areas are the
gas processing plant in the Midland Basin, telemetry that controls approximately
10% of the wells and portable metering devices which are used on less than 2% of
the wells. As of June 30, 1999, Range has completed the remediation of all known
Year 2000 problems associated with non-IT systems.
Range is also monitoring the compliance efforts of its significant
suppliers, customers and service providers with whom it does business and whose
IT and non-IT systems interface with those of the Company to ensure that they
will be Year 2000 compliant. If they are not, such failure could affect the
ability of the Company to sell its oil and gas and receive payments therefrom
and the ability of vendors to provide products and services in support of the
Company's operations. Although the Company has no reason to believe that its
vendors and customers will not be compliant by the year 2000, the Company is
unable to determine the extent to which Year 2000 issues will affect its vendors
and customers. However, management believes that ongoing communication with and
assessment of the compliance efforts of these third parties will minimize these
risks.
The discussion of the Company's efforts and management's expectations
relating to Year 2000 compliance contains forward-looking statements. Range is
currently conducting a comprehensive analysis of the financial and operational
problems that would be reasonably likely to result from failure by Range and
significant third parties to complete efforts necessary to achieve Year 2000
compliance on a timely basis. The Company intends to complete its contingency
plan by the third quarter of 1999. The primary goals are to maintain continuity
of operations, preserve Company assets and protect the environment.
The total costs for the Year 2000 Project is not expected to be in
excess of $180,000. Of this amount, approximately $127,000 had been incurred as
of June 30, 1999.
Range presently does not expect to experience significant operational
problems due to the Year 2000 issues. However, if all Year 2000 issues are not
properly and timely identified, assessed, remediated and tested, there can be no
assurance that the Year 2000 issue will not materially impact Range's results of
operations or adversely affect its relationship with customers, vendors, or
others. Additionally, there can be no assurance that the Year 2000 issues of
other entities will not have a material impact on Range's systems or results of
operations.
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GLOSSARY
The terms defined in this glossary are used throughout this From 10-Q.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6
Mcf for each barrel of oil, which reflects the relative energy content.
Development well. A well drilled within the proved area of an oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil or natural gas in
sufficient quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find and produce oil or gas in an unproved
area, to find a new reservoir in a field previously found to be productive of
oil or gas in another reservoir, or to extend a known reservoir.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Infill well. A well drilled between known producing wells to better exploit the
reservoir.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6
Mcf for each barrel of oil, which reflects the relative energy content.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
MmBtu. One million British thermal units. One British thermal unit is the heat
required to raise the temperature of a one-pound mass of water from 58.5 to 59.5
degrees Fahrenheit.
Mmcf. One million cubic feet.
Mmcfe. One million cubic feet of natural gas equivalents.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Net oil and gas sales. Oil and natural gas sales less oil and natural gas
production expenses.
Present Value. The pre-tax present value, discounted at 10%, of future net cash
flows from estimated proved reserves, calculated holding prices and costs
constant at amounts in effect on the date of the report (unless such prices or
costs are subject to change pursuant to contractual provisions) and otherwise in
accordance with the Commission's rules for inclusion of oil and gas reserve
information in financial statements filed with the Commission.
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Productive well. A well that is producing oil or gas or that is capable of
production.
Proved developed non-producing reserves. Reserves that consist of (i) proved
reserves from wells which have been completed and tested but are not producing
due to lack of market or minor completion problems which are expected to be
corrected and (ii) proved reserves currently behind the pipe in existing wells
and which are expected to be productive due to both the well log characteristics
and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves. Proved reserves that can be expected to be
recovered from currently producing zones under the continuation of present
operating methods.
Proved developed reserves. Proved reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in another
formation from that in which the well has previously been completed.
Reserve life index. The presentation of proved reserves defined in number of
years of annual production.
Royalty interest. An interest in an oil and gas property entitling the owner to
a share of oil and natural gas production free of costs of production.
Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves after income taxes calculated holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change pursuant to contractual provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.
Term overriding royalty. A royalty interest that is carved out of the operating
or working interest in a well. Its term does not extend to the economic life of
the property and is of shorter duration than the underlying working interest.
The term overriding royalties in which the Company participates through its
Independent Producer Finance subsidiary typically extend until amounts financed
and a designated rate of return have been achieved. At such point in time, the
override interest reverts back to the working interest owner.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operatingactivities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
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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 will be resolved without a material adverse effect on the Company's
financial position.
In July 1997, a gas utility filed an action in the State District Court
of Texas. In the lawsuit, the gas utility asserted a breach of contract claim
arising out of a gas purchase contract. Under the gas utility's interpretation
of the contract, it sought, as damages, the reimbursement of the difference
between the above-market contract price it paid and market price on a portion of
the gas it has taken beginning in July 1997. In May 1998, the court granted a
partial summary judgment on the contract interpretation issue in favor of the
gas utility. The summary judgment allows the utility to take or pay for a
limited volume of gas defined in the contract as the "contract volume" at the
contract price. In October 1998, the gas utility dropped its damages claim and
the state district court signed a final judgment in this case. Range appealed
the judgment and in August 1999 the court of appeals affirmed the lower court's
judgement. Range believes it has fully reflected the effects of the litigation
in its financial statements.
In May 1998, a Domain stockholder filed an action in the Delaware Court
of Chancery, alleging that the terms of the Merger were unfair to a purported
class of Domain stockholders and that the defendants (except Range) violated
their legal duties to the class in connection with the Merger. Range is alleged
to have aided and abetted the breaches of fiduciary duty allegedly committed by
the other defendants. The action sought an injunction enjoining the Merger as
well as a claim for money damages. On September 3, 1998, the parties executed a
Memorandum of Understanding (the "MOU"), which represents a settlement in
principle of the litigation. Under the terms of the MOU, appraisal rights
(subject to certain conditions) were offered to all holders of Domain common
stock (excluding the defendants and their affiliates). Domain also agreed to pay
any court-awarded attorneys' fees and expenses of the plaintiffs' counsel in an
amount not to exceed $290,000. The settlement in principle is subject to court
approval and certain other conditions that have not been satisfied.
Items 2 Not applicable
Item 3 Quantitative and Qualitative Disclosure About Market Risk
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about Range's potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in oil and gas prices and interest rates. The
disclosures are not meant to be precise indicators of expected future losses,
but rather indicators of reasonably possible losses. This forward-looking
information provides indicators of how Range views and manages its ongoing
market risk exposures. All of Range's market risk sensitive instruments were
entered into for purposes other than trading.
Commodity Price Risk. Range's major market risk exposure is in the
pricing applicable to its oil and gas production. Realized pricing is primarily
driven by the prevailing worldwide price for crude oil and spot market prices
applicable to U.S. natural gas production. Pricing for oil and gas production
has been volatile and unpredictable for several years.
Range periodically enters into financial hedging activities with
respect to a portion of its projected oil and natural gas production through
financial swaps whereby Range will receive a fixed price for its production and
pay a variable market price to the contract counterparty. These financial
hedging activities are intended to support oil and gas price fluctuations.
Realized gains and losses from the settlement of these financial hedging
instruments are recognized in oil and gas revenues when the
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associated production occurs. The gains and losses realized as a result of
these hedging activities are substantially offset in the cash market when the
commodity is delivered. Range does not hold or issue derivative instruments for
trading purposes.
As of June 30, 1999, Range had financial oil and gas price hedging
instruments in place that represented approximately 1 million barrels of oil
production through March 2000 and approximately 25 Bcf of gas production through
September 2000. At June 30, 1999, the 1999 hedged oil and gas volumes
represented an average of approximately 70% and 55%, respectively, of the
remaining monthly production. The 2000 hedged oil and gas volumes represent
approximately 25% and 24%, respectively, of expected 2000 production. While
these transactions have no carrying value, their fair value, represented by the
estimated amount that would be required to terminate the contracts, was a net
loss of approximately $6.7 million at June 30, 1999. These contracts expire
monthly through September 2000 on gas and through March 2000 on oil. The gains
or losses on the Company's hedging transactions are determined as the difference
between the contract price and the reference price, generally closing prices on
the New York Mercantile Exchange. The resulting transaction gains and losses are
determined monthly and are included in net income in the period the hedged
production or inventory is sold. Net gains or (losses) relating to these
derivatives for the six months ended June 30, 1998 and 1999 approximated $1.4
million and $1.3 million, respectively.
Range uses a sensitivity analysis technique to evaluate the
hypothetical effect that changes in the market value of oil and gas may have on
the fair value of its commodity hedging instruments. At June 30, 1999, a 10%
increase in the underlying commodities' prices would have reduced the fair value
of Range's commodity hedging instruments by $3.1 million.
In addition to the commodity hedging instruments described above, Range
also manages its exposure to gas price risks by periodically entering into
fixed-price gas contracts. The majority of these fixed-price contracts relate to
Range's Appalachian and Oakridge gas production. For the remainder of 1999 and
2000 through 2003, Range's fixed-price gas contracts cover approximately 3.0
Bcf, 6.4 Bcf, 0.7 Bcf, 0.7 Bcf and 0.7 Bcf of production, respectively. Range
also has gas volumes subject to fixed-price contracts from 2004 forward, but the
yearly volumes are less than 1.0 Bcf. The amount of 1999's remaining production
covered by fixed-price contracts represents approximately 12% of expected
remaining 1999 total production.
Interest Rate Risk. At June 30, 1999, Range had long-term debt
outstanding of $599.7 million. Of this amount, $176.3 million, or 29%, bears
interest at fixed rates averaging 7.9%. The remaining $423.4 million of debt
outstanding at June 30, 1999 is comprised of the Credit Facility and the IPF
Facility (See Note 6) which bear interest at floating rates that averaged 7.1%
at June 30, 1999. The terms of the Credit Facility and IPF Facility in place
allow interest rates to be fixed at the Company's option for periods of between
30 to 360 days. To manage its potential interest rate exposure, the Company uses
interest rate swap arrangements. Income and expense resulting from these
arrangements are recorded in the same category as expense arising from the
related liability. Amounts to be paid or received under interest rate swap
agreements are recognized as an adjustment to expense in the periods in which
they accrue. At June 30, 1999, the Company had $100 million of borrowings
subject to five interest rate swap agreements at rates of 5.71%, 5.59%, 5.35%,
4.82% and 5.64% through September 1999, October 1999, January 2000, September
2000 and October 2000, respectively. The interest rate swaps may be extended at
the counterparties' option for two years. The interest rate swaps require that
the Company pay the counterparty interest at the above fixed swap rates and
requires the counterparty to pay the Company interest at the 30-day LIBOR rate.
The closing 30-day LIBOR rate on June 30, 1999 was 5.22%. A 10% increase in
short-term interest rates on the floating-rate debt outstanding on June 30, 1999
would equal approximately 71 basis points. Such an increase in interest rates
would increase Range's annual interest expense by approximately $3.0 million
assuming borrowed amounts were at June 30, 1999 levels throughout the period.
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The above sensitivity analysis for interest rate risk excludes accounts
receivable, accounts payable and accrued liabilities because of the short-term
maturity of such instruments.
Item 4-5 Not applicable
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit Number Description of Exhibit
---------------- -------------------------------------------
27* Financial Data Schedule
(b) No reports filed on Form 8-K.
*Previously filed.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned.
RANGE RESOURCES CORPORATION
By: (Thomas W. Stoelk)
--------------------------------------
Thomas W. Stoelk
Senior Vice President - Finance and
Administration and Chief Financial Officer
September 17, 1999
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EXHIBIT INDEX
Exhibit Number Description of Exhibit
- --------------------- ---------------------------------------------
27* Financial Data Schedule
*Previously filed.
29
