1
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 quarter ended September 30, 1999
{ } TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transaction 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
--- ---
37,635,727 Common Shares were outstanding on November 10, 1999.
2
PART I. FINANCIAL INFORMATION
The financial statements included herein have been prepared in
conformity with generally accepted accounting principles and should be read in
conjunction with the Company's December 31, 1998 Form 10-K. The statements are
unaudited but reflect all adjustments which, in the opinion of management, are
necessary to fairly present the Company's financial position and results of
operations.
2
3
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
December 31, September 30,
1998 1999
---------------- ---------------
(unaudited)
ASSETS
Current assets
Cash and equivalents ......................................................... $ 10,954 $ 11,289
Accounts receivable .......................................................... 30,384 25,967
IPF receivables (Note 4) ..................................................... 7,140 11,000
Marketable securities ........................................................ 3,258 3,219
Assets held for sale (Note 5) ................................................ 51,822 19,867
Inventory and other .......................................................... 3,373 9,562
--------- ---------
106,931 80,904
--------- ---------
IPF receivables, net (Note 4) .................................................. 70,032 58,263
Oil and gas properties, successful efforts method .............................. 935,822 926,544
Accumulated depletion and impairment ....................................... (273,723) (322,684)
--------- ---------
662,099 603,860
--------- ---------
Transportation, processing and field assets .................................... 89,471 27,657
Accumulated depreciation ................................................... (15,146) (3,252)
--------- ---------
74,325 24,405
--------- ---------
Other .......................................................................... 8,225 8,353
--------- ---------
$ 921,612 $ 775,785
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable ............................................................. $ 28,163 $ 26,847
Accrued liabilities .......................................................... 23,626 19,636
Accrued interest ............................................................. 9,439 4,749
Current portion of long-term debt (Note 6) ................................... 55,187 29
--------- ---------
116,415 51,261
--------- ---------
Senior debt (Note 6) ........................................................... 311,875 146,650
Non-recourse debt (Note 6) ..................................................... 60,100 146,755
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
(liquidation preference $28,746,000) ..................................... 1,150 1,150
Common stock, $.01 par, 50,000,000 shares authorized,
35,933,523 and 37,489,311 issued ......................................... 359 375
Capital in excess of par value ............................................... 334,817 339,188
Retained deficit ............................................................. (203,396) (204,600)
Other comprehensive income .................................................... 292 977
--------- ---------
133,222 137,090
--------- ---------
$ 921,612 $ 775,785
========= =========
SEE ACCOMPANYING NOTES.
3
4
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
1998 1999 1998 1999
----------- ----------- ----------- ------------
(unaudited) (unaudited)
Revenues
Oil and gas sales ..................................... $ 32,467 $ 37,530 $ 95,748 $ 108,611
Transportation, processing and marketing .............. 1,682 2,100 5,045 5,798
IPF income ............................................ 1,130 2,065 1,130 5,520
Gain on sales, net (Note 17) .......................... 140 39,259 1,619 40,736
Interest and other .................................... 116 141 275 579
--------- --------- --------- ---------
35,535 81,095 103,817 161,244
--------- --------- --------- ---------
Expenses
Direct operating ...................................... 9,999 11,041 26,041 33,126
IPF expense ........................................... 452 1,412 452 4,389
Exploration ........................................... 1,997 368 4,428 1,730
General and administrative ............................ 2,401 2,244 6,336 5,906
Interest .............................................. 10,995 12,126 29,103 36,579
Depletion, depreciation and amortization .............. 14,618 18,770 39,371 57,708
Provision for impairment (1999 amount relates to assets
held for sale) ...................................... 97,862 20,988 97,862 20,988
--------- --------- --------- ---------
138,324 66,949 203,593 160,426
--------- --------- --------- ---------
Income (loss) before taxes ............................... (102,789) 14,146 (99,776) 818
Income taxes
Current ............................................... 57 1,424 192 1,594
Deferred .............................................. (35,939) -- (34,884) --
--------- --------- --------- ---------
(35,882) 1,424 (34,692) 1,594
Income (loss) before extraordinary item ................. (66,907) 12,722 (65,084) (776)
Extraordinary item
Gain on retirement of securities, net (Note 18) ...... -- -- -- 2,430
--------- --------- --------- ---------
Net income (loss) ........................................ $ (66,907) $ 12,722 $ (65,084) $ 1,654
========= ========= ========= =========
Comprehensive income (loss) Note (2) ..................... $ (68,243) $ 11,559 $ (67,679) $ 1,894
========= ========= ========= =========
Earnings (loss) per common share
Basic ............................................. $ (2.57) $ 0.33 $ (2.92) $ 0.00
========= ========= ========= =========
Dilutive .......................................... $ (2.57) $ 0.33 $ (2.92) $ 0.00
========= ========= ========= =========
SEE ACCOMPANYING NOTES.
4
5
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
Nine Months Ended September 30,
--------------------------------------
1998 1999
----------------- ---------------
(unaudited)
Cash flows from operations:
Net income (loss) ........................................................ $ (65,084) $ 1,654
Adjustments to reconcile net income (loss) to
net cash provided by operations:
Depletion, depreciation and amortization ............................ 39,371 57,708
Provision for impairment ............................................ 97,862 20,988
Amortization of security issuance costs ............................. 868 887
Deferred taxes ...................................................... (34,884) --
Changes in working capital net of effects of purchases of businesses:
Accounts receivable ........................................ 5,314 4,417
Allowance for IPF receivables .............................. -- 2,965
Marketable securities ...................................... (67) --
Inventory and other ........................................ (583) (6,219)
Accounts payable ........................................... (5,747) (4,639)
Accrued liabilities ........................................ 1,620 (8,680)
Gain on sale of assets and other .................................... (2,874) (40,736)
Gain on exchange of securities ...................................... -- (2,430)
--------- ---------
Net cash provided by operations .......................................... 35,796 25,915
Cash flows from investing:
Acquisition of businesses, net of cash .............................. (46,277) --
Investment in Great Lakes ........................................... -- 97,095
Oil and gas properties .............................................. (128,485) (8,901)
Additions to property and equipment ................................. (1,131) (432)
IPF investments of capital .......................................... (3,397) (4,180)
IPF repayments of capital ........................................... 596 9,124
Proceeds on sale of assets .......................................... 18,195 17,270
--------- ---------
Net cash provided by (used in) investing ................................. (160,499) 109,976
Cash flows from financing:
Proceeds from indebtedness .......................................... 130,608 --
Repayments of indebtedness .......................................... (406) (133,729)
Preferred stock dividends ........................................... (1,751) (1,750)
Common stock dividends .............................................. (2,490) (1,108)
Proceeds from common stock issuance ................................. 1,415 1,054
Repurchase of common stock .......................................... (2,705) (23)
--------- ---------
Net cash provided by (used in) financing ................................. 124,671 (135,556)
--------- ---------
Change in cash ........................................................... (32) 335
Cash and equivalents at beginning of period .............................. 9,725 10,954
--------- ---------
Cash and equivalents at end of period .................................... $ 9,693 $ 11,289
========= =========
Supplemental disclosures of non-cash investing and
financing activities:
Purchase of property and equipment financed with
common stock ......................................................... $ 111,062 --
Common stock issued in connection with benefit plans ................... 1,267 777
Common stock issued in connection with retirement of
securities (Note 18) ................................................ -- 3,355
SEE ACCOMPANYING NOTES.
5
6
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 Independent Producer Finance
subsidiary ("IPF"), 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 nine months ended September 30, 1999 Range sold $1.2 million
of marketable equity securities for a $0.4 million gain.
GREAT LAKES ENERGY PARTNERS, L.L.C. ("GREAT LAKES")
In September 1999, Range and FirstEnergy Corp. ("FirstEnergy") each
contributed all of their Appalachia oil and gas properties and associated gas
gathering and transportation systems to Great Lakes. In addition, Range
contributed $188.3 million of indebtedness and FirstEnergy contributed $2.0
million in cash. Great Lakes expects to increase production by active
development of existing fields and exploitation of deeper formations. In
addition, Great Lakes intends to pursue acquisition opportunities in Appalachia.
Range and FirstEnergy each retained a 50% ownership interest in Great Lakes. The
Company consolidates its pro rata interest in the joint venture's assets and
liabilities based upon its ownership interest in Great Lakes.
Great Lakes had proved reserves of approximately 450 Bcfe as of
September 30, 1999, of which 90 percent is natural gas, 4,700 miles of gas
gathering and transportation lines and a leasehold position of nearly one
million gross acres. The joint venture owns interest in over 1,000 proved
drilling locations within existing fields and has a reserve life of 18 years.
6
7
INDEPENDENT PRODUCER FINANCE
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 nine months of 1999, IPF
recorded gross income of $8.5 million and allowances against its portfolio of
receivables of $3.0 million. At September 30, 1999 IPF's allowance for
uncollectible receivables totaled $16.9 million. During the first nine months of
1999, IPF expenses were comprised of $3.2 million of interest and $1.2 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 capitalized 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 $0.87 and $0.99 in the
nine months of 1998 and 1999, respectively. Approximately $75.9 million and
$72.5 million of oil and gas properties were classified as unproved properties
as of December 31, 1998 and September 30, 1999, respectively.
The Company has adopted SFAS No. 121 "Accounting for the Impairment of
Long-Lived Assets", which establishes accounting standards for the impairment of
long-lived assets, certain identifiable intangibles and goodwill. SFAS No. 121
requires a review for impairment whenever circumstances indicate that the
carrying amount of an asset may not be recoverable. In performing the review for
recoverability at September 30, 1998, the Company recorded provision for
impairment of $97.8 million which reduced the carrying value of certain oil and
gas properties to what the Company estimates to have been their fair value at
that time. The provision for impairment on the oil and gas properties was due to
reserve revisions as a result of drilling results and declines in oil and gas
prices in 1998. The impairment was determined based on the difference between
the carrying amount of the assets and the present value of the future cash
flows from proved properties discounted at 10%. Impairment is recognized only
if the carrying amount of a property is greater than its expected undiscounted
future cash flows. A change in reserve or price estimates could occur which
would adversely affect management's estimate of future cash flows and
consequently the carrying value of the properties.
Unproved properties are assessed periodically to determine whether
there has been a decline in value. If such decline is indicated, a loss is
recognized. The Company compares the carrying value of its unproved properties
to the present value of the future cash flows of unproved properties discounted
at 10% or considers such other information the Company believes is relevant in
evaluating the properties' fair value. Such other information may include the
Company's geological assessment of the area or other acreage purchases in the
area. The present value of future cash flows from such properties has been
adjusted for the Company's assessment of risk related to the unproved
properties.
7
8
TRANSPORTATION, PROCESSING AND FIELD ASSETS
The Company's gas gathering systems and gas processing plant are in
proximity to its principal gas properties. Depreciation is calculated on the
straight-line method based on estimated useful lives ranging from four to
fifteen years. At September 30, 1999, the Company decided to sell its gas
processing plant and certain related assets. See Note (5) - Assets Held For Sale
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 seven 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 sheet and are being amortized on the interest
method over the term of the securities.
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
September 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 nine month periods ended September 30, 1998 and 1999.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ---------------------------------
1998 1999 1998 1999
-------------- ------------- ------------- ---------------
Net income (loss).......................... $ (66,907) $ 12,722 $ (65,084) $ 1,654
Add: Unrealized gain/(loss)
Gross................................ (2,138) (806) (4,087) 685
Tax effect........................... 802 - 1,533 -
Less: Realized gain/(loss)
Gross................................ - (357) (66) (445)
Tax effect........................... - - 25 -
-------------- ------------- ------------- ---------------
Comprehensive income (loss)................ $ (68,243) $ 11,559 $ (67,679) $ 1,894
============== ============= ============= ===============
8
9
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 debt securities.
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 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 the prior period
presentation to conform with current period 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 with bank debt 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
$22 million and $2 million during the nine months ended September 30, 1998 and
1999, respectively.
9
10
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 Great Lakes transaction.
Nine Months Ended September 30,
----------------------------------------
1998 1999
------------------ ------------------
(In thousands, except per share data)
Revenues............................ $ 95,210 $ 154,495
Net income (loss)................... (59,777) 3,845
Earnings (loss) per share-basic..... (2.69) 0.06
Earnings (loss) per share-diluted... (2.69) 0.06
Total assets........................ 936,600 775,785
Stockholders' equity................ 234,575 137,090
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 transaction occurred at the beginning of each
period presented or to necessarily be indicative of future results.
(4) IPF RECEIVABLES
At September 30, 1999, IPF had net receivables of $69.3 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 $11.0 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 $16.9 million at December 31, 1998 and
September 30, 1999, respectively.
(5) ASSETS HELD FOR SALE
At September 30, 1999, assets held for sale consisted of the Company's
gas processing plant and associated assets located in the Permian Basin. In
connection with the 1999 plan of disposal, the Company determined that the
carrying value of the gas processing plant exceeded its fair value. Accordingly,
an impairment loss of $21.0 million represents the excess of the carrying value
over the fair value.
Fair value was determined by reference to the present value of the
estimated future cash inflows of the gas processing plant. The impairment
estimate on the gas processing plant recorded in the third quarter 1999 was
based on estimates of future cash flows for the property. Future cash flows
include revenues from residue gas, plant liquids and by-products derived from
both equity and third party proved natural gas reserves, which are estimated to
pass through the plant, direct operating costs and capitalized costs. The
Company used estimated future gas prices by referencing ten year future strip
prices in the calculation of the plant revenues estimated over the anticipated
life of the property. These prices were then adjusted for the effect of the
estimated throughput production, subject to existing sales contracts, and are
not necessarily indicative of actual prices received by the Company at the date
of the impairment charge.
Operating costs and capitalized costs were estimated based on the
Company's historical operating experience. These costs and expenses were
adjusted for changes in variable costs attributable to changes in estimated
throughput volumes. The impairment estimate was determined based on the
difference between the carrying value of the plant and the present value of
future cash flows discounted at 10%. It is reasonably possible that a change in
10
11
reserve or price estimates could occur in the near term and adversely impact
management's estimate of future cash flows and consequently the carrying value
of property.
At December 31, 1998, assets held for sale primarily consisted of oil
and gas properties located in south Texas and in the Gulf of Mexico. The Company
entered into agreements with an independent firm to assist it in selling these
assets. The assets were 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.
(6) INDEBTEDNESS
The Company had the following debt outstanding as of the dates shown.
Interest rates at September 30, 1999 are shown parenthetically (in thousands):
December 31, September 30,
1998 1999
-------- --------
Senior debt
Credit Facility (7.4%) ........................... $365,175 $146,600
Other (6.3%) ..................................... 1,887 79
-------- --------
367,062 146,679
Less amounts due within one year ................. 55,187 29
-------- --------
Senior debt, net ................................. $311,875 $146,650
======== ========
Non-recourse debt
Great Lakes (7.6%) ............................... $ -- $ 94,139
IPF (7.5%) ....................................... 60,100 52,616
-------- --------
Non-recourse debt ................................ $ 60,100 $146,755
======== ========
Subordinated notes
8.75% Senior Subordinated Notes due 2007 ......... $125,000 $125,000
6% Convertible Subordinated Debentures due 2007 .. 55,000 51,360
-------- --------
Subordinated notes ............................... $180,000 $176,360
======== ========
The Company maintains a $225 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 November 10, 1999, the borrowing base on
the Credit Facility was $160 million of which $18.0 million was available. The
borrowing base is subject to semi-annual determination 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 the revolving credit commitment
may be reduced, in whole or in part at anytime in certain minimum amounts. The
next redetermination occurs on April 1, 2000. If amounts outstanding at April 1,
2000 exceed the redetermined borrowing base, one-half of the excess, if any,
must be repaid within 90 days and the remaining excess, if any, must be repaid
within 180 days. Any borrowing base in excess of $135 million requires the
approval of all lenders. 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 0.50% depending upon the percentage of the
borrowing base drawn. It is the Company's policy to extend the term of the
Credit Facility annually. The interest rate on the Credit Facility is LIBOR plus
between 1.50% and 2.25%, depending upon amounts outstanding. The weighted
average interest rates on these borrowings were 6.8% and 7.2% for the three
months ended September 30, 1998 and 1999, respectively.
11
12
The Company pro rata consolidates 50% of amounts outstanding under the
$275 million revolving bank facility (the "Great Lakes Facility") through its
participation in Great Lakes. The Great Lakes Facility is non-recourse to Range.
The Great Lakes Facility provides for a borrowing base, which is subject to
semi-annual redeterminations. The Great Lakes Facility is secured by the Great
Lakes oil and gas properties. At November 10, 1999, the borrowing base on the
Great Lakes Facility was $195 million of which $5.7 million was available.
Beginning December 1, 1999, the borrowing base reduces by $1 million per month
to $190 million at April 1, 2000. The borrowing base is subject to a semi-annual
borrowing review on April 1, 2000. The redetermined borrowing base on April 1,
2000 requires the approval of all lenders. Interest is payable quarterly or as
LIBOR notes mature and the loan matures in September 2002. The interest rate on
the Great Lakes Facility is LIBOR plus between 1.50% and 2.00%, depending upon
amounts outstanding. A commitment fee is paid quarterly on the undrawn balance
at a rate of 0.25% to 0.50% depending upon the percentage of the borrowing base
drawn.
IPF has a $150 million revolving credit facility (the "IPF Facility")
through which it finances its activities. The IPF Facility is non-recourse to
Range. The IPF Facility matures in July 2001 at which time all amounts owed
thereunder are due and payable. The IPF Facility is secured by substantially all
of IPF's assets. The borrowing base under the IPF Facility is subject to
redeterminations, which occur routinely during the year. On November 10, 1999,
the borrowing base on the IPF Facility was $56 million of which $3.4 million was
available. 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 nine months of 1999 amounted to
$3.2 million and is included in IPF expenses on the Consolidated Statements of
Operations. A commitment fee is paid quarterly on the average undrawn balance at
a rate of 0.375% to 0.50%. The weighted average interest rate on these
borrowings was 7.5% for the nine months ended September 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 are
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 nine 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 as the Debentures were retired at a discount to
their face value.
The debt agreements contain various covenants relating to net worth,
working capital maintenance and financial ratio requirements. The Company is in
compliance with these various covenants as of September 30, 1999. Interest paid
during the nine months ended September 30, 1998 and 1999 totaled $32.1 million
and $36.6 million, respectively. The Company does not capitalized any interest
expense.
(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 receivables are concentrated in the oil
and gas industry. The Company does not view such a
12
13
concentration as an unusual credit risk. The Company had allowances for doubtful
accounts (excluding IPF) of $.8 million and $1.0 million at December 31, 1998
and September 30, 1999, respectively.
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:
December 31, September 30,
1998 1999
------------------------------- -------------------------------
(In thousands)
Book Fair Book Fair
Value Value Value Value
-------------- ------------- -------------- --------------
Cash and equivalents................ $ 10,954 $ 10,954 $ 11,289 $ 11,289
Marketable securities............... 2,966 3,258 2,242 3,219
Long-term debt...................... (607,162) (607,162) (469,794) (469,794)
Commodity swaps..................... - 45 - (6,908)
Interest rate swaps................. - (361) - (13)
At September 30, 1999, the Company had open contracts for gas and oil
price derivative swaps of 36 Bcfe of gas and 800,000 Bbls of oil. The swap
contracts are designed to set average NYMEX prices ranging from $1.90 to $3.17
per Mmbtu of gas and fix oil prices ranging from $17.32 to $20.71 per Bbl. While
these transactions have no carrying value, the fair value of these and
subsequent transactions entered into, represented by the estimated amount that
would be required to terminate the contracts, was a net loss of approximately
$3.4 million at November 10, 1999. These contracts expire monthly through
September 2000. 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
(losses) relating to these derivatives for the nine months ended September 30,
1998 and 1999 approximated $2.8 million and $(6.6) 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 September 30, 1999, the Company
had $80 million of borrowings subject to four interest rate swap agreements at
rates of 5.35%, 4.82%, 5.64% and 5.59% through January 2000, September 2000,
October 2000 and October 2001, 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 September 30, 1999 was 5.40%. The fair value of
the interest rate swap agreements at September 30, 1999 is based upon quotes at
that date 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
13
14
with certain counterparties or groups of counterparties. The credit worthiness
of counterparties is subject to continuing review and full performance is
anticipated.
(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 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. In September 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 $.3 million. The settlement in principle is subject to
court approval and certain other conditions that have not been satisfied.
(9) EQUITY AND TRUST SECURITIES
In October 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 nine months of 1999, $2.3 million of
Convertible Preferred Securities were retired at the option of the holder in
exchange for approximately 202,000 shares of Common Stock. An extraordinary gain
of $1.2 million was recorded as the 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 Convertible
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 becomes fixed at 100% of the principal
amount. If the Company 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.
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.
The Company owns all the common securities of the Trust. As such, the
accounts of the Trust will be included in Range's consolidated financial
statements after appropriate eliminations of intercompany balances. The
distributions on the Convertible Preferred Securities will be recorded as a
charge to interest expense on Range's consolidated statements of operations, and
such distributions are deductible by Range for income tax purposes.
14
15
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 redeemable, at the option of the Company,
at a price of $26.25 per share beginning November 1, 1998, declining $0.25 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, one stock incentive plan, 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 stock option plans is
summarized as follows:
Plans Adopted Via
the Merger
1999 ----------------------
Incentive Option Director's Option Director's
Plan Plan Plan Plan Plan Total
---------- ---------- ----------- ---------- ----------- ----------
Outstanding at December 31, 1998 - 2,042,757 140,000 938,976 19,340 3,141,073
Granted........................ 60,000 904,150 40,000 - 1,004,150
Exercised...................... - - - (374,264) - (374,264)
Expired/Cancelled.............. - (426,871) (12,000) (12,833) - (451,704)
---------- ---------- ---------- ---------- ----------- ---------
Outstanding at September 30, 1999 60,000 2,520,036 168,000 551,879 19,340 3,319,255
========== ========== =========== ========== =========== ==========
In May 1999, the shareholders approved the Company's 1999 Stock
Incentive Plan (the "Incentive Plan") providing for the issuance of up to 1.4
million shares of common stock. The Incentive Plan is administered by the
Compensation Committee of the Board. All options issued under the Incentive Plan
vest 25% per year beginning one year after the grant date and expire 10 years
from date of grant. During the nine months ended September 30, 1999, 60,000
options were granted, none of which were exercisable.
Range maintains the 1989 stock option plan ("Option Plan") which
authorized the grant of options of up to 3.0 million shares of Common Stock,
however, no new options will be granted under this plan. Under the Option Plan,
incentive and non-qualified options have been issued to officers, 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 and expire 5
years from date of grant. Options issued after September 1998 vest 25% per year
beginning one year after the grant date and expire 10 years from date of grant.
During the nine months ended September 30, 1999, no options were exercised.
At September 30, 1999, 972,216 options were exercisable at prices ranging from
$3.375 to $18.00 per share.
In 1994, the stockholders approved the 1994 Outside Directors Stock
Option Plan (the "Directors Plan"). Only Directors who are not employees of the
Company are eligible under the Directors Plan. The Directors Plan covers a
maximum of 200,000 shares. At September 30, 1999, 92,800 options were
exercisable at prices ranging from $8.00 to $16.875 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 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 first nine months ended September 30,
1999 options covering 356,812 shares were exercised at $0.01 per share and
17,452 shares were exercised at $3.46 per share. At September 30, 1999, 440,174
options were currently exercisable under the Domain Option Plan at $3.46 per
share. The remaining 111,705 options have an exercise price of $0.01 per share.
15
16
At September 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 1997
Plan, the right to purchase shares at prices ranging from 50% to 85% of market
value may be granted. Through September 30, 1999, no rights had been granted
for less than 75% of market value. The Company previously had stock purchase
plans which covered 833,333 shares. The previous stock purchase plans have been
terminated. The 1997 Plan is administered by the Compensation Committee of the
Board. From inception through September 30, 1999, a total of 499,897 registered
shares had been sold through stock purchase plans, for a total consideration of
approximately $2.9 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 nine month periods ended September
30, 1998 and 1999 were $(34.7) million and $1.6 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 $29
million at September 30, 1999. Upon future realization of the deferred tax
asset, $29 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 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 $.9
million. The statutory depletion carryover and alternative minimum tax credit
carryover are not subject to limitation or expiration.
16
17
(13) 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):
Three months ended Nine months ended
September 30, September 30,
----------------------------- -----------------------------
1998 1999 1998 1999
--------------- --------------- --------------- ---------------
Numerator:
Net Income ................................. $ (66,907) $ 12,722 $ (65,084) $ 1,654
Preferred stock dividends................... (584) (584) (1,751) (1,751)
-------------- -------------- -------------- --------------
Numerator for earnings per common share..... (67,491) 12,138 (66,835) (97)
Effect of dilutive securities:
Preferred stock dividends................. - - - -
-------------- -------------- -------------- --------------
Numerator for earnings per common
Share - assuming dilution................. $ (67,491) $ 12,138 $ (66,835) $ (97)
============== ============== ============== ==============
Denominator:
Denominator for basic earnings per common
Share - weighted average shares........... 26,243 37,477 22,857 36,745
Effect of dilutive securities:
Employee stock options.................... 385 - 469 -
Warrants.................................. - - - -
-------------- -------------- -------------- --------------
385 - 469 -
-------------- -------------- -------------- --------------
Dilutive potential common shares
Denominator for diluted earnings per share
Adjusted weighted-average shares and
Assumed conversions....................... 26,628 37,477 23,326 36,745
============== ============== ============== ==============
Earnings (loss) per common share................ $ (2.57) $ 0.33 $ (2.92) $ 0.00
============== ============== ============== ==============
Earnings (loss) per common
Share - assuming dilution................. $ (2.57) $ 0.33 $ (2.92) $ 0.00
============== ============== ============== ==============
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 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 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 effect would be antidilutive. There were employee
stock options outstanding during the first nine months of 1998 and 1999 which
were exercisable, resulting in 1,051,370 and 1,683,936 additional shares,
respectively, under the treasury method of accounting for common stock
equivalents. These additional shares were not included in the first nine months
1999 computations of diluted earnings per share because the effect was
antidilutive.
17
18
(14) 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 89% of gas production is currently sold under market sensitive
contracts, which do not contain floor price provisions. For the nine months
ended September 30, 1999, no one customer accounted for 10% or more of total oil
and gas revenues. Management believes that the loss of any one customer would
not have a material adverse effect on operations. 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.
(15) OIL AND GAS ACTIVITIES
The following summarizes selected information with respect to oil and
gas activities (in thousands):
December 31, September 30,
1998 1999
----------------- ----------------
(unaudited)
Oil and gas properties:
Proved properties.................................. $ 859,911 $ 854,090
Unproved properties................................ 75,911 72,454
----------------- ----------------
Total.......................................... 935,822 926,544
Accumulated depletion and impairment............... (273,723) (322,684)
----------------- ----------------
Net oil and gas properties..................... $ 662,099 $ 603,860
================= ================
Nine Months
Year Ended Ended
December 31, September 30,
1998 1999
----------------- ----------------
(unaudited)
Costs incurred:
Acquisition........................................ $ 286,974 $ 2,084
Development........................................ 71,793 20,074
Exploration........................................ 9,756 2,438
----------------- ----------------
Total costs incurred........................... $ 368,523 $ 24,596
================= ================
18
19
(16) INVESTMENT IN GREAT LAKES
As described in Note 2, the Company has a 50% ownership interest in
Great Lakes. At September 30, 1999, the Company pro rata consolidated its
interest in the joint venture's assets and liabilities based upon its ownership
interest in Great Lakes. No operations for Great Lakes are reflected in the
Company's Statements of Operations due to the fact that the joint venture was
completed on September 30, 1999. The following table summarizes the financial
information for 100% of Great Lakes (in thousands).
September 30,
1999
-----------------
(unaudited)
Current assets............................................ $ 2,708
Oil and gas properties, net............................... 288,941
Transportation, processing and field assets, net.......... 39,710
Other assets.............................................. 2,166
Current liabilities....................................... 5,003
Long-term debt............................................ 188,277
Net equity................................................ 140,245
(17) GAIN ON SALE
In September 1999, Range transferred all of its Appalachian oil and gas
properties and associated gas gathering and transportation systems to Great
Lakes in exchange for a non-controlling ownership interest. Additionally, the
Company contributed $188.3 million of indebtedness to Great Lakes. The Great
Lakes partners have no commitment to support the operations or related
obligations of Great Lakes. In connection with the transfer, Range recognized a
gain of $41.0 million, which was attributable to the portion of the net assets
conveyed to Great Lakes. The gain was calculated by comparing the Company's
estimate of the fair market value of the assets and liabilities conveyed to
their net book value.
The estimated fair market value of oil and gas properties was based
upon future net cash flows from the assets discounted 10% at September 30, 1999.
The present value of future cash flows from such properties has been adjusted
for the Company's assessment of risk related to the properties. For purposes of
determining the fair market value of oil and gas properties, risk factors
ranging from 20% to 60% were used depending on the nature of the reserve
category. The Company assumed NYMEX prices of $19.00 per barrel of oil and
$2.65 per mcf of gas for purposes of calculating future net cash flows. Prices
were escalated 2.5% annually, with oil capped at the price of $30.00 per barrel
and gas capped at the price of $5.00 per mcf. These prices were then adjusted
for the effect of the Company's production subject to existing sales contracts,
and are not necessarily indicative of actual prices received by the Company at
the dates of the impairment charges. Severance taxes, direct operating costs
and capitalized costs were estimated based on the Company's historical
operating experience. These costs and expenses were escalated at 2.5% per year.
These prices and costs were applied to production profiles developed by the
Company's engineers using estimates of proved reserves and unproved reserves.
The estimated fair market value of other assets contributed to Great Lakes was
determined by an internally generated cash flow model which was developed to
determine the future revenues and costs associated with these activities,
discounted 10% annually. These discounted cash flows were risked individually
at rates ranging between 30% and 60%.
During the nine months ended September 30, 1999, the Company sold
various non-strategic properties. A net loss in the amount of $1.8 million was
recognized on the sale of these properties due to their net book value being
greater than proceeds received upon their sale.
19
20
(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.
20
21
MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
------------------------------------------------
FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY AND CAPITAL RESOURCES
General
During the nine months ended September 30, 1999, the Company spent
approximately $24.6 million on acquisition, development and exploration
activities. At September 30, 1999, the Company had $14.5 million in cash and
marketable securities and total assets of $776 million. At that date working
capital was $29.6 million. During the first nine months of 1999, total debt
decreased $137.4 million. At September 30, 1999, debt to total book
capitalization was 65%.
Long-term debt at September 30, 1999 included $147 million of
borrowings under the Credit Facility, $94 million under the non-recourse Great
Lakes Facility, $53 million under the non-recourse IPF Facility, $125 million of
8.75% Senior Subordinated Notes and $51 million of 6% Convertible Subordinated
Debentures. The Company's exposure to its recourse Credit Facility was reduced
60% from $365 million at December 31, 1998 to $147 million at September 30,
1999. Including the debt exchanges noted below, total debt fell from $607.2
million at December 31, 1998 to $469.8 million at September 30, 1999.
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 as the Convertible Preferred securities and
Debentures were retired at a discount to their face value.
The Company believes that its capital resources are adequate to meet
the requirements of its business. However, future cash flows are subject to a
number of variables including the level of production and oil and gas prices,
and there can be no assurance that operations and other capital resources will
provide cash in sufficient amounts to maintain planned levels of capital
expenditures.
In September 1999, the Company elected to pursue the sale of its gas
processing plant and associated assets located in the Permian Basin. At
September 30, 1999, the Company classified these assets as held for sale. In
that connection, the Company determined that the carrying value of the plant
exceeded its fair value. Accordingly, an impairment loss of $21.0 million was
recorded which represented the excess of the carrying value over the estimated
fair value.
Fair value of the gas processing plant was estimated by reference to
the present value of the estimated future cash inflows of the gas processing
plant. The impairment estimate on the gas processing plant recorded in the third
quarter 1999 was based on estimates of future cash flows for the property.
Future cash flows include revenues from residue gas, plant liquids and
by-products derived from both equity and third party proved natural gas
reserves, which are estimated to pass through the plant, direct operating costs
and capitalized costs. The Company used an estimated future gas prices by
referencing ten year future strip prices in the calculation of the plant
revenues estimated over the anticipated life of the property. These prices were
then adjusted for the effect of the estimated throughput production, subject to
existing sales contracts, and are not necessarily indicative of actual prices
received by the Company at the date of the impairment charge.
21
22
Cash Flow
The Company's principal operating sources of cash include sales of oil
and gas, revenues from transportation, processing and marketing and IPF
revenues. The Company's cash flow is highly dependent upon oil and gas prices.
Decreases in the market price of oil and gas in late 1998 reduced cash flow and
resulted in the reduction of the borrowing base under the Credit Facility. As a
result, the Company reduced its development and exploration budget to $38
million in 1999. For the first nine months of 1999, the Company spent
approximately $22.5 million on these activities. The 1999 expenditures have been
funded primarily by internally generated cash flow.
The Company's net cash provided by operations for the nine months ended
September 30, 1998 and 1999 was $35.8 million and $25.9 million, respectively.
The decrease in the Company's cash flow from operations is attributed primarily
to decreases in oil and gas prices and increased interest on amounts outstanding
under the Credit Facility.
The Company's net cash provided by (used in) investing for the nine
months ended September 30, 1998 and 1999 was $(160.5) million and $110.0
million, respectively. Investing activities for these periods are comprised
primarily of additions to oil and gas properties through the Company's
investment in Great Lakes, acquisitions and development, proceeds on sale of
assets, IPF investments and, to a lesser extent, exploration and additions of
field assets. Cash flows from investing in 1999 also included the Company's
investment in Great Lakes. These uses of cash have historically been partially
offset by cash inflows associated with asset sales and IPF return of capital.
The Company's acquisition, drilling and IPF 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 (used in) financing for the nine
months ended September 30, 1998 and 1999 was $124.7 million and $(135.6)
million, respectively. Sources of financing used by the Company during the most
recent nine month period were borrowings under its Credit Facilities. The
Company decreased its debt borrowings by $133.7 million during the period
primarily due to the conveyance of debt to Great Lakes.
Capital Requirements
During the nine months ended September 30, 1999, $22.5 million and of
costs were incurred for development and exploration activities. In an effort to
reduce outstanding debt, the Company reduced its 1999 exploration and
development capital budget to $38 million. The development and exploration
activities are highly discretionary and in 1999 have been reduced to levels
below internally generated cash flow. The remaining cash flow has been available
for debt repayment. The Company does not expect any additional material capital
expenditures outside its normal operations over the next 12 month period.
Bank Facilities
The Company maintains a $225 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 November 10, 1999, the borrowing base on
the Credit Facility was $160 million of which $18.0 million was available to be
drawn. The borrowing base is subject to semi-annual determination 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 the revolving credit commitment
may be reduced, in whole or in part at anytime in certain minimum amounts. The
next redetermination occurs on April 1, 2000. If amounts outstanding at April 1,
2000 exceed the redetermined borrowing base, one-half of the excess, if any,
must be repaid within 90 days and the remaining excess, if any, must be repaid
within 180 days. Any borrowing base in excess of $135 million requires the
approval of all lenders. 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 0.50% depending upon the percentage of the
borrowing base drawn. It is the Company's policy to extend the term period of
the Credit
22
23
Facility annually. The interest rate on the Credit Facility is LIBOR plus
between 1.50% and 2.25%, depending upon amounts outstanding. The weighted
average interest rates on these borrowings were 6.8% and 7.2% for the three
months ended September 30, 1998 and 1999, respectively.
The Company pro rata consolidates 50% of amounts outstanding under the
$275 million revolving bank facility (the "Great Lakes Facility") through its
participation in Great Lakes. The Great Lakes Facility is non-recourse to Range.
The Great Lakes Facility provides for a borrowing base, which is subject to
semi-annual redeterminations. The Great Lakes Facility is secured by the Great
Lakes oil and gas properties. At November 10, 1999, the borrowing base on the
Great Lakes Facility was $195 million of which $5.7 million was available to be
drawn. Beginning December 1, 1999, the borrowing base reduces $1 million per
month to $190 million at April 1, 2000. The borrowing base is subject to a
semi-annual borrowing review on April 1, 2000. The redetermined borrowing base
on April 1, 2000 requires the approval of all lenders. Interest is payable
quarterly or as LIBOR notes mature and the loan matures in September 2002. The
interest rate on the Great Lakes Facility is LIBOR plus between 1.50% and 2.00%,
depending upon amounts outstanding. A commitment fee is paid quarterly on the
undrawn balance at a rate of 0.25% to 0.50% depending upon the percentage of the
borrowing base drawn.
IPF has a $150 million revolving credit facility (the "IPF Facility")
through which it finances its activities. The IPF Facility is non-recourse to
Range. The IPF Facility matures in July 2001 at which time all amounts owed
thereunder are due and payable. The IPF Facility is secured by substantially all
of IPF's assets. The borrowing base under the IPF Facility is subject to
redeterminations, which occur routinely during the year. On November 10, 1999,
the borrowing base on the IPF Facility was $56 million of which $3.4 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 nine months of 1999 amounted to
$3.2 million and is included in IPF expenses on the Consolidated Statements of
Operations. A commitment fee is paid quarterly on the average undrawn balance at
a rate of 0.375% to 0.50%. The weighted average interest rate on these
borrowings was 7.5% for the nine months ended September 30, 1999.
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 September 30, 1999, the Company had open hedges for natural gas of 36
Bcf and oil swaps of 800,000 barrels. While these transactions have no carrying
value, the fair value of these and subsequent transactions entered into,
represented by the estimated amount that would be required to terminate the
contracts, was a net loss of approximately $3.4 million at November 10, 1999.
The gas contracts are at prices ranging from $1.90 to $3.17 per Mmbtu and the
oil contracts range from $17.32 to $22.95 per Bbl. The gains or losses on the
Company's hedging transactions are 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 nine months ended September 30, 1998 and
1999, approximated $2.8 million and $(6.6) million respectively.
Interest Rate Risk
At September 30, 1999, Range had debt outstanding of $469.8 million. Of
this amount, $176.4 million, or 38% bears interest at fixed rates averaging
7.9%. The remaining $293.4 million of debt outstanding at September 30, 1999
bears interest at floating rates which averaged 7.6%. The terms of the credit
facilities in place allow interest rates to be fixed at Range's option for
periods of between 30 and 180 days. At September 30, 1999, the Company had $80
million of borrowings subject to four interest rate swap agreements at rates of
5.35%, 4.82%, 5.64% and 5.59% through January 2000, September 2000, October 2000
and October 2001, 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 require the
counterparty to pay the Company interest at the 30-day LIBOR rate. The closing
30-day LIBOR rate on September 30, 1999 was 5.40%. A 10% increase in short-term
interest rates on the floating-rate debt outstanding at the end of 1998 would
equal
23
24
approximately 76 basis points. Such an increase in interest rates would increase
Range's nine month 1999 interest expense by approximately $1.7 million, assuming
borrowed amounts remain outstanding.
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.
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 dependent on oil and gas prices. Oil and gas prices
are subject to significant seasonal and other fluctuations that are beyond the
Company's ability to control or predict. During the first nine months of 1999,
the Company received an average of $13.97 per barrel of oil, an increase of 13%
from the comparable 1998 period, and $2.01 per Mcf of gas, a decrease of 17%
from the comparable 1998 period. 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 nine months of 1999.
RESULTS OF OPERATIONS
Comparison of 1999 to 1998
The Company reported net income for the three months ended September
30, 1999 of $12.7 million compared to net loss of $66.9 million in the third
quarter of 1998. Production volumes increased 7% from 165,760 Mcfe/d in 1998 to
177,816 Mcfe/d in 1999. The average price received on an equivalent unit basis
increased 8% from $2.13 per Mcfe in 1998 to $2.29 per Mcfe in 1999. The average
oil price increased 38% to $16.21 per barrel while average gas prices decreased
2% to $2.18 per Mcf. As a result of the Company's larger base of producing
properties and production, oil and gas production expenses increased 10% to
$11.0 million in 1999 versus $10.0 million in 1998. The average operating cost
per Mcfe of production increased 2% from $0.66 in the third quarter of 1998 to
$0.67 in 1999 due to higher production taxes.
Transportation, processing and marketing net revenues increased 25% to
$2.1 million versus $1.7 million in 1998. IPF net income consists of the
interest portion of the term overriding royalty interest and is net an allowance
for possible uncollectable accounts. During the third quarter of 1999, IPF
expense included $1.0 million of interest and $0.4 million of administrative
expense.
General and administrative expenses decreased 7% from $2.4 million in
1998 to $2.2 million in 1999. General and administrative cost per Mcfe produced
decreased 13% from $0.16 in 1998 to $0.14 in 1999. Exploration expense decreased
from $2.0 million to $.4 million due to the farming out of projects in exchange
for carried interests and decreased expenditures resulting from a reduced
capital expenditure budget.
Gain on sale relates to the net excess of proceeds received on the sale
of properties over their book value. The increase in gain on sale of $39.1
million over that in the third quarter 1998 primarily due to the $41 million
proportional gain recognized on the Great Lakes transaction (See Note (17) -
Gain on Sale).
Interest and other income remained relatively constant compared to the
same 1998 period. Interest and other income is primarily comprised of interest
on bank deposits. In 1999 interest expense increased 10% to $12.1 million as
compared to $11.0 million in 1998. The increase was primarily 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 borrowing.
The average outstanding balances on the Credit Facility were $240 million and
$363 million and the nine months ended September 30, 1998 and 1999,
respectively. The weighted average interest rate on these borrowings was 6.7%
and 7.0% for the nine month periods ended September 30, 1998 and 1999,
respectively.
24
25
Depletion, depreciation and amortization increased 28% compared to 1998
as a result of increased production volumes. The Company's depletion rate was
$0.84 per Mcfe in the third quarter of 1998 versus $1.02 per Mcfe in the third
quarter of 1999. In the third quarter of 1999, the Company recognized a $21
million impairment on a gas processing plant and related assets located in the
Permian Basin. The Company has decided to sell the plant and related assets and
the net book value of these assets is classified as a current asset at September
30, 1999 on the Consolidated Balances Sheets (See Note (5) Assets Held For
Sale).
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 miscellaneous systems. Range's
computerized accounting / production / land system was upgraded and tested to be
Year 2000 compliant. The Company's personal computer systems are also Year 2000
compliant.
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 September 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 has
conducted 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. Business contingency plans for mission critical systems have been
developed to deal with misrepresentations by equipment manufacturers and the
inability of purchasers or partners to conduct normal operations.
The total costs for the Year 2000 Project is not expected to be in
excess of $180,000. Of this amount, approximately $150,000 had been incurred as
of September 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 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.
25
26
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.
26
27
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 operating activities 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.
27
28
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 the
Company's financial position.
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 $.3 million. The settlement in principle is subject to
court approval and certain other conditions that have not been satisfied.
Items 2 - 5. Not applicable
Item 6. Exhibits and Report on Form 8-K
(a) Exhibits
10.1 $225,000,000 Amended and Restated Credit Agreement among Range
Resources Corporation, as Borrower, The Lenders from Time to
Time Parties Hereto, as Lenders, Bank One, Texas, N.A., as
Administrative Agent, Chase Bank of Texas, N.A., as
Syndication Agent, and Bank of America, N.A., as Documentation
Agent dated September 30, 1999.
10.2 Credit Agreement Among Great Lakes Energy Partners,
L.L.C., as Borrower and Bank One, Texas, N.A., as
Administrative Agent, Chase Bank of Texas, N.A., as
Syndication Agent, Bankers Trust Company, as Documentation
Agent, The Bank of Nova Scotia and Credit Lyonnais New
York Branch, as Managing Agents Banc One Capital Markets,
Inc., as Co-Lead Arranger and Chase Securities Inc., as
Co-Lead Arranger, as dated September 30, 1999.
27 Financial data schedule
(b) Reports on Form 8-K
Current Report on Form 8-K, dated October 15, 1999 regarding
the Great Lakes transaction.
28
29
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: (Thomas W. Stoelk)
---------------------------
Thomas W. Stoelk
Senior Vice President
Finance & Administration
Chief Financial Officer
November 15, 1999
29
30
EXHIBIT INDEX
Exhibit Number Description of Exhibit
- ----------------------- ----------------------------------------------------
10.1 $225,000,000 Amended and Restated Credit Agreement
among Range Resources Corporation, as Borrower, The
Lenders from Time to Time Parties Hereto, as Lenders,
Bank One, Texas, N.A., as Administrative Agent, Chase
Bank of Texas, N.A., as Syndication Agent, and Bank
of America, N.A., as Documentation Agent dated
September 30, 1999.
10.2 Credit Agreement Among Great Lakes Energy Partners,
L.L.C., as Borrower and Bank One, Texas, N.A., as
Administrative Agent, Chase Bank of Texas, N.A., as
Syndication Agent, Bankers Trust Company, as
Documentation Agent, The Bank of Nova Scotia and
Credit Lyonnais New York Branch, as Managing Agents
Banc One Capital Markets, Inc., as Co-Lead Arranger
and Chase Securities Inc., as Co-Lead Arranger, as
dated September 30, 1999.
27 Financial data schedule
30