<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE)
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended
December 31, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) 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
Securities registered pursuant to Section 12(b) of the Act:
None
COMMON STOCK, $.01 PAR VALUE
(Title of class)
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes x No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of voting stock of the registrant held by
non-affiliates (excluding voting shares held by officers and directors) was
$87,329,093 on March 9, 1999.
Indicate the number of shares outstanding of each of the registrant's
classes of stock on March 9, 1999: Common Stock $.01 par value: 36,273,196;
Preferred Stock $1 par value: 1,149,840.
DOCUMENTS INCORPORATED BY REFERENCE:
Part III of this report incorporates by reference the Proxy Statement relating
to the Registrant's 1999 Annual Meeting of Stockholders.
<PAGE> 2
RANGE RESOURCES CORPORATION
ANNUAL REPORT ON FORM 10-K
YEAR ENDED DECEMBER 31, 1998
PART I
ITEM 1. BUSINESS
GENERAL
Range Resources Corporation ("Range" or the "Company") is an
independent oil and gas company operating in the Appalachian, Permian,
Midcontinent and Gulf Coast regions. The Company seeks to build value through a
balanced approach of low-risk development and acquisition, higher risk
exploitation and exploration and producer finance. Through its Independent
Producer Finance subsidiary, the Company engages in financing activities by
purchasing term royalties in oil and gas properties. 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. At December 31, 1998, the Company had
combined proved reserves totaling 796 Bcfe, having a pre-tax present value at
constant prices on that date of $555 million. On an Mcfe basis, the reserves
were 80% natural gas, are 80% operated by the Company and have a reserve life
index in excess of 13 years.
In August 1998, the stockholders of Lomak Petroleum, Inc ("Lomak")
approved the acquisition via merger (the "Merger") of Domain Energy Corporation
("Domain"). As a result of the Merger, Domain became a wholly-owned subsidiary
of Lomak. Simultaneously, Lomak stockholders approved changing the Company's
name to Range Resources Corporation.
DESCRIPTION OF THE BUSINESS
Strategy
The Company's objective is to maximize stockholder value through a
balanced strategy that combines lower risk development and acquisition
activities with higher risk, higher impact exploitation and exploration
projects. Since 1990, total assets have grown from $24 million to $922 million
at year end 1998. During 1999, the Company's goal is to reduce leverage and
position the Company to benefit from, rather than merely endure, the downturn in
commodity prices. The Company plans to reduce leverage by cutting costs,
monetizing assets and limiting exploration and development capital expenditures
to internal cash flow. While it will be difficult to generate substantial
production growth with a reduced 1999 capital budget, the cost reductions and
monetization and sale of assets position Range to weather a prolonged downturn
in commodity prices. When prices rebound, the Company should be in position to
increase the rate of exploitation of its large development and exploration
inventory.
Management believes that the acquisitions completed since 1990 have
substantially enhanced the Company's ability to increase its production and
reserves through the ongoing development of the acquired properties. The Company
now has over 1,400 proven recompletions and development drilling projects. With
its large development inventory, the Company believes that if oil and gas prices
rebound it can achieve growth in reserves, production, cash flow and earnings
over the next several years, without the benefit of future acquisitions. The
Company currently anticipates spending approximately $35 million to $40 million
during 1999 on development and exploration activities. The Company's leasehold
position now totals approximately 1.9 million gross acres (1.2 million net),
providing significant long-term development and exploration potential.
In order to effectively implement its operating strategy, the Company
has concentrated its activities in selected geographic areas. In its core areas,
the Company has established separate business units, each with operating,
engineering, geological, land, acquisition and other personnel experienced in
their geographic area.
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The Company believes that this focus provides it with a competitive advantage in
sourcing and evaluating new business opportunities, as well as providing
economies of scale in operating and developing its properties.
Development. The Company's development activities include
recompletions of existing wells, infill drilling and installation of secondary
recovery projects. Development projects are generated within core areas where
the Company has significant operational and technical experience. At December
31, 1998, over 1,400 proven development projects were in inventory. In view of
the low current oil and gas prices, the Company plans to limit its 1999
development expenditures to approximately $35 million. The Company expects
development expenditures in the Appalachian, Gulf Coast and Southwest business
units to approximate $9 million, $10 million and $16 million, respectively.
Exploration. Beginning in 1996, the Company began to conduct
exploration activities on or near existing properties within its core operating
areas. Range has domestic onshore exploration projects covering 536,000 gross
acres. The Company's onshore exploration program targets deeper horizons within
existing Company-operated fields, as well as establishing new fields in
exploration trend areas in which Range's technical staff has experience. Range's
offshore exploration program focuses on the shallow waters of the Gulf of Mexico
where it holds contiguous 3D seismic data covering 3.5 million acres. Range has
offshore leases covering 11,000 gross acres on which it has identified 80
projects. Range's strategy is based upon limiting its risk by allocating no more
than 10% of its cash flow to exploration activities and by participating in a
variety of projects with differing characteristics. In view of the low current
oil and gas prices the Company anticipates exploratory expenditures to be less
than $5 million in 1999.
Acquisitions. Since 1990, 70 acquisitions have been completed for a
total consideration of $974 million. These acquisitions have been made at an
average cost of $0.77 per Mcfe. The Company's acquisition strategy has
historically been based on: (i) Locale: focusing in core areas where the Company
has operating and technical expertise; (ii) Efficiency: targeting acquisitions
in which operating and cost efficiencies can be obtained; (iii) Reserve
Potential: pursuing properties with the potential for reserve increases through
recompletions and drilling; (iv) Incremental Purchases: seeking acquisitions
where opportunities for purchasing additional interests in the same or adjoining
properties exist; and (v) Complexity: pursuing more complex but less competitive
corporate acquisitions.
DEVELOPMENT AND EXPLORATION ACTIVITIES
During 1998, the Company spent $81.5 million on development and
exploration activities versus $58.8 million in 1997. Of this total, $53 million
was expended in the Southwest, $18 million in Appalachia and $10 million in the
Gulf Coast. These expenditures funded 70 recompletions of existing wells, 234
new development wells and 14 exploratory wells, as well as leasehold and seismic
acquisition. As a result of these activities, 70 Bcfe of proved reserves were
added representing 115% of 1998 production.
Development Activities
The Company's development activities include recompletions of existing
wells, infill drilling and to a lesser extent, installation of secondary
recovery projects. Development projects are located within core operating areas
where the Company has established operational and technical expertise.
Currently, as described below, the Company has 1,493 proven development projects
in inventory. Those projects are geographically diverse, target a mix of oil and
gas and are generally less than 8,000 feet in depth. Approximately 74% of the
development projects are concentrated in 21 fields covering 512,000 gross acres.
Such large acreage blocks and concentration of projects provide economies of
scale, access to competitively priced oil field services and focused operating
and technical expertise. The following table sets forth information pertaining
to the Company's proven development inventory at December 31, 1998.
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<TABLE>
<CAPTION>
NUMBER OF PROJECTS
------------------------------------------------------
RECOMPLETION DRILLING
OPPORTUNITIES LOCATIONS TOTAL
--------------- -------------- ---------------
<S> <C> <C> <C>
Southwest
Permian................... 310 211 521
Midcontinent.............. 44 33 77
--------------- -------------- ---------------
Subtotal................ 354 244 598
Gulf Coast................... 110 44 154
Appalachia................... 2 739 741
-------------- --------------- ---------------
Total................... 466 1,027 1,493
============== =============== ===============
</TABLE>
In addition, the Company has identified over 200 projects on its
existing leasehold, which at December 31, 1998 were not classified as proven. A
portion of these projects are included in each year's development program. These
projects include field extension drilling and recompletions to formations not
extensively under production.
Range completed 304 development projects in 1998, including drilling
234 wells and 70 recompletions. This level of activity was 13% higher than in
1997. The 1998 development expenditures of $71.8 million exceeded 1997 by 27%,
reflecting increased activity and a higher average working interest. In the
Southwest business unit, the Company spent $47 million to recomplete 51 wells
and drill an additional 104 wells. Development activity in the Gulf Coast
included the drilling of 6 wells and the recompletion of 7 others for $6
million. In Appalachia, $18 million was spent to drill 124 wells and recomplete
12 others.
Exploration Activities
Domestic Onshore Exploration. Range has onshore exploration projects
covering 767,000 gross acres, including seven projects in the Southwest and
fifteen in Appalachia. Each project has multiple drilling prospects, some with
multiple targets. During 1998, the Company spent $4.7 million to acquire
established acreage, shoot and process seismic data and drill 11 wells.
Gulf of Mexico Exploration. Via Domain, Range acquired a 3D seismic
database covering 700 contiguous blocks in the shallow waters of the Gulf of
Mexico, primarily offshore Louisiana. This database has been used to map
geological trends within this 3.5 million acre area, identifying specific
targets for further exploration. To date, 80 prospects have been identified.
These prospects target the Miocene formation at depths of 10,000 to 12,000 feet.
Subsequent to the Merger, the Company participated in 3 gross, 1.2 net
exploration wells, all of which were plugged and abandoned, at a cost of
approximately $4.1 million.
ACQUISITION ACTIVITIES
In 1998, Range completed acquisitions for $224 million in
consideration. The significant acquisitions are described below.
In March 1998, oil and gas properties in the Powell Ranch Field in West
Texas (the "Powell Ranch Properties") were acquired for a purchase price of $60
million, comprised of $54.6 million in cash and $5.4 million of Common Stock.
In August 1998, the Company acquired Domain via merger for a purchase
price of $161.6 million, comprised of $50.5 million in cash and $111.1 million
of Common Stock. Domain's principal assets primarily included oil and gas
operations onshore in the Gulf Coast and in the Gulf of Mexico, as well as the
investment activities of IPF.
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PRODUCTION
Production revenue is generated through the sale of oil, natural gas
liquids and gas from properties owned directly and through partnerships and
joint ventures. Additional revenue is received from royalties. While production
is sold to a limited number of purchasers, only one accounts for more than 10%
of oil and gas revenues. Management believes that the loss of any one customer
would not have a material adverse effect on the business. Proximity to local
markets, availability of competitive fuels and overall supply and demand are
factors affecting the ability to market production. While the Company
anticipates an upward trend in energy prices, factors outside its control such
as political developments in the Middle East, overall energy supply, weather
conditions and economic growth rates have had, and will continue to have, a
significant effect on energy prices.
The following table sets forth historical production volumes, revenue
and expense information for the periods indicated (in thousands, except average
sales price and operating cost data).
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------
1994 1995 1996 1997 1998
---------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Production
Oil and NGL (Bbl) 640 913 1,068 1,794 2,655
Gas (Mcf) ........ 6,996 12,471 21,231 38,409 45,193
Total (Mcfe) (a) . 10,836 17,949 27,641 49,170 61,120
Revenues
Oil and NGL ...... $ 9,743 $ 15,133 $ 20,425 $ 28,800 $ 30,084
Gas .............. 14,718 22,284 47,629 101,217 105,509
---------- -------- -------- -------- --------
Total ............ $ 24,461 $ 37,417 $ 68,054 $130,017 $135,593
========== ======== ======== ======== ========
Average Sales Price
Oil (Bbl) ........ $ 15.23 $ 16.57 $ 19.56 $ 18.22 $ 12.01
NGL (Bbl) ........ - - $ 10.22 $ 9.06 $ 8.26
Gas (Mcf) ........ $ 2.10 $ 1.79 $ 2.24 $ 2.64 $ 2.33
Mcfe (a) ......... $ 2.26 $ 2.08 $ 2.46 $ 2.64 $ 2.22
Average Operating Cost
Per Mcfe (a) ..... $ 0.75 $ 0.63 $ 0.75 $ 0.64 $ 0.64
</TABLE>
(a) Oil and NGL is converted to Mcfe at a rate of 6 Mcf per barrel.
On a Mcfe basis, approximately 74% of 1998 production was natural gas.
Gas production was sold to utilities, brokers or directly to industrial users.
Gas sales are made pursuant to various arrangements ranging from month-to-month
contracts, one year contracts at fixed or variable prices and contracts at fixed
prices for the life of the well. All contracts other than the fixed price
contracts contain provisions for price adjustment, termination and other terms
customary in the industry. A number of the Appalachian gas contracts are at
prices which compare favorably to the spot market. 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
purchasers are selected on the basis of price and service. In 1998, revenues
from gas sales totaled $105.5 million or 78% of total oil and gas revenues while
revenues from oil and natural gas liquids production amounted to $30.1 million,
representing 22% of total oil and gas revenues. Oil and gas revenues for 1998
increased 4% over 1997.
GAS TRANSPORTATION, PROCESSING AND MARKETING
The gas transportation, processing and marketing revenues are comprised
of fees for the transportation of production through gathering lines and fees
from gas processing as well as, income from marketing of oil and gas.
Transportation, processing and marketing revenues decreased 14% to $6.7 million
versus $7.8 million in 1997. The decrease was principally due to the sale of a
gas processing plant in the San Juan Basin and a drop in natural gas liquid
prices which lowered gas processing revenue.
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The Company's natural gas transportation and processing assets are
primarily comprised of (i) approximately 2,700 miles of gas transportation and
gathering pipelines in Appalachia and (ii) nearly 300 miles of gathering lines
in the Sterling area of the Permian Basin. The Appalachian gas gathering systems
serve to transport a majority of the Company's Appalachian gas production as
well as third party gas to major trunklines and directly to industrial
end-users. This affords the Company considerable control and flexibility in
marketing its Appalachian production. Third parties who transport their gas
through the systems are charged a gathering fee based on throughput. The
Company's Sterling gas processing plant is a refrigerated turbo-expander
cryogenic gas plant that was placed in service in early 1995. The plant,
designed for approximately 25,000 Mcf/d, is currently operating at 74% of
capacity. The Company estimates that the plant's capacity can be increased to
35,000 Mcf/d for approximately $4.0 million in additional capital expenditures.
In order to maximize the price and better control credit risk, the
Company began to market its own gas production in 1993. The Company is currently
marketing 196 Mmcf/d for its own account as well as for third party producers.
The Company has managed the impact of potential price declines by developing a
balanced portfolio of fixed price and market sensitive contracts and commodity
hedging. Approximately 16% of average gas production at December 31, 1998 was
sold subject to fixed price sales contracts. These fixed price contracts are at
prices ranging from $1.50 to $5.00 per Mcf. The fixed price contracts with terms
of less than one year, between one and five years and greater than five years
constitute approximately 41%, 50% and 9%, respectively, of the volume sold under
fixed price contracts.
From time to time, the Company enters into oil and natural gas price
hedges to reduce its exposure to commodity price fluctuations. At December 31,
1998, approximately 13% of the Company's existing market sensitive 1999
production was fixed under hedging agreements which expire on a monthly basis in
January and April through October. Subsequent to December 31, 1998, the Company
entered into additional hedging agreements, which increased the percentage of
the Company's existing market sensitive production covered by hedging
arrangements to 30%. In the future, the Company may hedge a larger percentage of
its production, however, it currently anticipates that such percentage would not
exceed 80%. Although these hedging activities provide the Company some
protection against falling prices, these activities also reduce the potential
benefits to the Company of price increases above the levels of the hedges.
The Company has an above market gas contract with a major Texas gas
utility company, which expires June 30, 2000. During 1998, the Company sold 11%
of its gas production under this contract. At December 31, 1998 the price
received pursuant to the contract was $3.82 per Mcf ($3.40 per Mmbtu). The
agreement provides for a price escalation of $0.05 per Mmbtu on July 1 of each
year.
INDEPENDENT PRODUCER FINANCE ("IPF")
IPF provides capital to small oil and gas producers to finance
specifically identified acquisition and development projects. IPF advances money
to producers in exchange for a term overriding royalty interest in their
projects. The overrides are dollar-denominated and are calculated to provide IPF
with a contractually specified rate of return. IPF funds its business
principally with a combination of internally generated cash and borrowings under
a bank credit facility. At December 31, 1998 the portfolio had a book value of
$77.2 million (net of $14.0 million in valuation allowances) with underlying
reserves having a Present Value of $92.2 million. The IPF reserves and Present
Value are not included in Range's consolidated oil and gas reserve disclosure.
During 1998, IPF expenses were comprised of $.5 million general and
administrative expenses, $1.6 million of interest expense and a $5.9 million
valuation allowance.
IPF is staffed with four petroleum engineers and geologists who
identify and evaluate each project. These professionals are responsible for
defining transaction risk, establishing reserve coverage and negotiating the
contractual rate of return. The transactions are structured to minimize risk by
focusing on asset coverage ratios and taking direct title to the overriding
royalty interests. As dollar-denominated overrides, the transactions leave the
majority of the commodity price risk with the producer.
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IPF provides capital to small oil and gas producers who are generally
ignored by traditional financial institutions. IPF has doubled its portfolio
each year since 1993 despite its limited geographic scope, transaction size and
marketing effort. Range expects demand for IPF funding to increase, as oil and
gas acquisition and divestiture activities continue and consolidation of the
banking industry reduces the supply of traditional bank financing for small
transactions. IPF's growth has been financed through borrowing under its
revolving credit facility and internally generated cash flow. The IPF Facility
is recourse only to the assets of the IPF subsidiary. On March 10, 1999, the
borrowing base on the IPF Facility was $60.1 million which did not exceed the
amounts outstanding on that date. The Company is currently in the process of
completing a borrowing base redetermination. Upon completion of the
redetermination, the Company believes the borrowing base amount will decrease
slightly and that the outstanding obligations at that time will not exceed the
borrowing base.
INTEREST AND OTHER
The Company earns interest on its cash and investment accounts, as well
as on various notes receivable. Other income in 1998 was comprised principally
of gains on sales of marketable equity securities and gains on sales of
non-strategic properties. The Company expects to continue to sell properties
that are marginal or are not strategic. Interest and other income in 1998
amounted to $2.3 million, representing 2% of total revenues.
COMPETITION
The Company encounters substantial competition in acquiring oil and gas
leases and properties, marketing oil and gas, securing personnel and conducting
its drilling and field operations. Many competitors have financial and other
resources which substantially exceed those of the Company. The competitors in
development, exploration, acquisitions and production include the major oil
companies in addition to numerous independents, individual proprietors and
others. Therefore, competitors may be able to pay more for desirable leases and
to evaluate, bid for and purchase a greater number of properties or prospects
than the financial or personnel resources of the Company permit. The ability of
the Company to replace and expand its reserve base in the future will be
dependent upon its ability to select and acquire suitable producing properties
and prospects for future drilling.
The Company's acquisitions have been partially financed through
issuances of equity and debt securities and internally generated cash flow.
There is competition for capital to finance oil and gas acquisitions and
drilling. The ability of the Company to obtain such financing is uncertain and
can be affected by numerous factors beyond its control. The inability of the
Company to raise capital in the future could have an adverse effect on certain
areas of its business.
GOVERNMENTAL REGULATION
The Company's operations are affected from time to time in varying
degrees by political developments and federal, state and local laws and
regulations. In particular, oil and natural gas production and related
operations are or have been subject to price controls, taxes and other laws and
regulations relating to the oil and gas industry. Failure to comply with such
laws and regulations can result in substantial penalties. The regulatory burden
on the oil and natural gas industry increases the Company's cost of doing
business and affects its profitability. Although the Company believes it is in
substantial compliance with all applicable laws and regulations, because such
laws and regulations are frequently amended or reinterpreted, the Company is
unable to predict the future cost or impact of complying with such laws and
regulations.
ENVIRONMENTAL MATTERS
The Company's oil and natural gas exploration, development, production
and pipeline gathering operations are subject to stringent federal, state and
local laws governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental
departments such
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as the Environmental Protection Agency ("EPA") issue regulations to implement
and enforce such laws, which are often difficult and costly to comply with and
which carry substantial civil and criminal penalties for failure to comply.
These laws and regulations may require the acquisition of a permit before
drilling commences, restrict the types, quantities and concentrations of various
substances that can be released into the environment in connection with
drilling, production and pipeline gathering activities, limit or prohibit
drilling activities on certain lands lying within wilderness, wetlands, frontier
and other protected areas, require some form of remedial action to prevent
pollution from former operations such as plugging abandoned wells, and impose
substantial liabilities for pollution resulting from the Company's operations.
In addition, these laws, rules and regulations may restrict the rate of oil and
natural gas production below the rate that would otherwise exist. The regulatory
burden on the oil and gas industry increases the cost of doing business and
consequently affects its profitability. Changes in environmental laws and
regulations occur frequently, and any changes that result in more stringent and
costly waste handling, disposal or clean-up requirements could adversely affect
the Company's operations and financial position, as well as the oil and gas
industry in general. While management believes that the Company is in
substantial compliance with current applicable environmental laws and
regulations and the Company has not experienced any material adverse effect from
compliance with these environmental requirements, there is no assurance that
this will continue in the future.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances at the site
where the release occurred. Under CERCLA, such persons may be subject to joint
and several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damages allegedly caused by the release of hazardous substances or
other pollutants into the environment. Furthermore, although petroleum,
including crude oil and natural gas, is exempt from CERCLA, at least two courts
have ruled that certain wastes associated with the production of crude oil may
be classified as "hazardous substances" under CERCLA and thus such wastes may
become subject to liability and regulation under CERCLA. State initiatives to
further regulate the disposal of oil and natural gas wastes are also pending in
certain states, and these various initiatives could have a similar impact on the
Company.
Stricter standards in environmental legislation may be imposed in the
oil and gas industry in the future. For instance, legislation has been proposed
in Congress from time to time that would reclassify certain oil and natural gas
exploration and production wastes as "hazardous wastes" and make the
reclassified wastes subject to more stringent handling, disposal and clean-up
restrictions. If such legislation were to be enacted, it could have a
significant impact on the operating costs of the Company, as well as the oil and
gas industry in general. Compliance with environmental requirements generally
could have a material adverse effect upon the capital expenditures, earnings or
competitive position of the Company. Although the Company has not experienced
any material adverse effect from compliance with environmental requirements, no
assurance may be given that this will continue in the future.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions
and strict controls regarding the discharge of produced waters and other oil and
gas wastes into navigable waters. Permits must be obtained to discharge
pollutants into state and federal waters. The FWPCA and analogous state laws
provide for civil, criminal and administrative penalties for any unauthorized
discharges of oil and other hazardous substances in reportable quantities and
may impose substantial potential liability for the costs of removal, remediation
and damages. State water discharge regulations and the federal (NPDES) permits
prohibit or are expected to prohibit within the next year the discharge of
produced water and sand, and some other substances related to the oil and gas
industry, to coastal waters. Although the costs to comply with zero discharge
mandated under federal or state law may be significant, the entire industry will
experience similar costs and the Company believes that these costs will not have
a material adverse impact
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on the Company's financial condition and results of operations. Some oil and gas
exploration and production facilities are required to obtain permits for their
storm water discharges. Costs may be incurred in connection with treatment of
wastewater or developing storm water pollution prevention plans.
The Resources Conservation and Recovery Act ("RCRA"), as amended,
generally does not regulate most wastes generated by the exploration and
production of oil and natural gas. RCRA specifically excludes from the
definition of hazardous waste "drilling fluids, produced waters, and other
wastes associated with the exploration, development, or production of crude oil,
natural gas or geothermal energy." However, these wastes may be regulated by the
EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such
as paint wastes, waste solvents, laboratory wastes and waste compressor oils,
are regulated as hazardous wastes. Although the costs of managing solid
hazardous waste may be significant, the Company does not expect to experience
more burdensome costs than similarly situated companies involved in oil and gas
exploration and production.
In addition, the U.S. Oil Pollution Act ("OPA") requires owners and
operators of facilities that could be the source of an oil spill into "waters of
the United States" (a term defined to include rivers, creeks, wetlands and
coastal waters) to adopt and implement plans and procedures to prevent any spill
of oil into any waters of the United States. OPA also requires affected facility
owners and operators to demonstrate that they have at least $35 million in
financial resources to pay for the costs of cleaning up an oil spill and
compensating any parties damaged by an oil spill. Substantial civil and criminal
fines and penalties can be imposed for violations of OPA and other environmental
statutes.
EMPLOYEES
As of January 1, 1999, the Company had 390 full time employees, of whom
223 were field personnel. None are covered by a collective bargaining agreement
and management believes that its relationship with its employees is good.
ITEM 2. PROPERTIES
On December 31, 1998, the Company held working interests in 8,427 gross
(6,755 net) productive oil and gas wells and royalty interests in 373 additional
wells. The properties contained, net to the Company's interest, estimated proved
reserves of 633 Bcf of gas and 27 million barrels of oil and natural gas liquids
or a total of 796 Bcfe.
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PROVED RESERVES
The following table sets forth estimated proved reserves for each year
in the five year period ended December 31, 1998.
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Natural gas (Mmcf)
Developed.................... 97,251 174,958 207,601 369,786 436,062
Undeveloped.................. 52,119 57,929 87,993 204,632 197,255
------- ------- ------- ------- -------
Total.................... 149,370 232,887 295,594 574,418 633,317
------- ------- ------- ------- -------
Oil and NGL (Mbbls)
Developed.................... 6,431 8,880 10,703 14,971 19,649
Undeveloped.................. 2,018 1,983 3,972 14,803 7,480
------- ------- ------- ------- -------
Total.................... 8,449 10,863 14,675 29,774 27,129
------- ------- ------- ------- -------
Total (Mmcfe) (a) ............. 200,064 298,065 383,644 753,062 796,091
======= ======= ======= ======= =======
(a) Oil and NGL reserves are converted to Mcfe at a rate of 6 Mcf per barrel.
</TABLE>
In connection with the evaluation of its reserves, the Company engaged
the following independent petroleum consultants: Netherland, Sewell &
Associates, Inc. (Southwest and Gulf Coast), H.J. Gruy and Associates, Inc.
(Southwest and Gulf Coast), DeGoyler and MacNaughton (Gulf Coast), Wright &
Company, Inc. (Appalachia), and Clay, Holt & Klammer (Appalachia). These
engineers have been employed primarily based on geographic expertise as well as
their history in engineering certain of the acquired properties. At December 31,
1998, approximately 85% of the proved reserves set forth above were evaluated by
independent petroleum consultants, while the remainder were evaluated by the
Company's engineering staff. All estimates of oil and gas reserves are subject
to significant uncertainty.
The following table sets forth as of December 31, for the periods
presented, the estimated future net cash flow from and the Present Value of the
proved reserves in millions.
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Future net cash flow .......... $ 271 $ 413 $ 941 $ 1,276 $ 1,020
Present value..................
Pre-tax...................... 151 229 492 632 555
After tax.................... 120 174 351 511 517
</TABLE>
Future net cash flow represents future gross cash flow from the
production and sale of proved reserves, net of production costs (including
production taxes, ad valorem taxes and operating expenses) and future
development costs. Such calculations, which are prepared in accordance with the
Statement of Financial Accounting Standards No. 69 "Disclosures about Oil and
Gas Producing Activities" are based on cost and price factors at December 31,
1998. Average product prices in effect at December 31, 1998 were $10.00 per
barrel of oil and $2.25 per Mmbtu of gas. There can be no assurance that the
proved reserves will be developed within the periods indicated or that prices
and costs will remain constant. There are numerous uncertainties inherent in
estimating reserves and related information and different reservoir engineers
often arrive at different estimates for the same properties. No estimates of
reserves have been filed with or included in reports to another federal
authority or agency since December 31, 1998.
SIGNIFICANT PROPERTIES
The Company's reserves at December 31, 1998 were grouped into three
regions, Southwest, Gulf Coast and Appalachia. Properties in the Southwest
region are divided into two divisions, the Permian and Midcontinent. At December
31, 1998, the Company's properties included working interests in 8,427 gross
10
<PAGE> 11
(6,755 net) productive oil and gas wells and royalty interests in 373 additional
wells. The Company also held interests in 830,285 gross (445,817 net)
undeveloped acres. The following table sets forth summary information with
respect to the Company's estimated proved oil and gas reserves at December 31,
1998.
<TABLE>
<CAPTION>
Pre-tax
Present Value
-----------------
Amount
(In Oil & NGL Natural Gas Total
thousands) % (Mbbls) (Mmcf) (Mmcfe)
-------- --- ------ ------- -------
<S> <C> <C> <C> <C> <C>
Southwest
Permian................. $158,455 28% 21,997 138,865 270,847
Midcontinent............ 49,287 9% 1,005 58,155 64,185
-------- --- ------ ------- -------
Subtotal.............. 207,742 37% 23,002 197,020 335,032
-------- --- ------ ------- -------
Gulf Coast................. 154,298 28% 3,298 144,187 163,975
Appalachia................. 193,181 35% 829 292,110 297,084
-------- --- ------ ------- -------
Total................. $555,221 100% 27,129 633,317 796,091
======== === ====== ======= =======
</TABLE>
SOUTHWEST REGION
The Company's Southwestern properties are situated in the Permian and
Val Verde Basins of west Texas, the Anadarko Basin of western Oklahoma, the
Texas panhandle and the East Texas Basin. Reserves in these basins represent 37%
of total Present Value at December 31, 1998. Southwestern proved reserves
totaled 335 Bcfe, of which approximately 59% were natural gas. At December 31,
1998, the Southwest Region properties had a development inventory of 598 proven
drilling locations and recompletions.
Permian. The Permian business division properties, located in the
Permian and Val Verde Basins of west Texas, contained 271 Bcfe of proved
reserves, or 28% of total Present Value. Net daily production averages 5,719
barrels of oil and NGL and 29 Mmcf of gas. Producing wells total 2,196 (1,221
net), of which the Company operates 86% on a total reserve basis. Major
producing properties include the Sonora area, Sterling area, Big Lake area, and
Fuhrman-Mascho fields. The Oakridge and Frances Hill fields in the Sonora area
produce from multiple deltaic channel Canyon sandstones at depths of 2,600 to
6,000 feet. At Sterling, gas production is derived from Canyon/Cisco sub-marine
sand deposits at 4,000 to 8,000 foot depths, while oil production comes from
Silurian Fusselman carbonates. Sterling area gas production is liquids-rich and
is transported to the Company's 25,000 Mcf/d gas plant, which processes gas from
the Company's operated properties, as well as gas produced by third parties. The
Big Lake and Fuhrman-Mascho properties produce primarily oil from the San
Andres/Grayburg formations at depths ranging from 2,500 feet to 4,600 feet. At
December 31, 1998, the Permian properties contained a development inventory of
310 recompletions and 211 infill drilling locations.
Midcontinent. The Midcontinent business division properties, located in
the Anadarko Basin of western Oklahoma and the Texas panhandle, held proved
reserves of 64 Bcfe. These reserves, representing 9% of the total Present Value,
were 91% natural gas. Of 326 gross (190 net) wells, the Company operates 93%.
The unit's largest property is in the Okeene Field, including over 191 operated
wells. At December 31, the Midcontinent properties produce an average of 293
barrels of oil and 19 Mmcf of gas per day. The properties produce from a variety
of sands and carbonates in both structural and stratigraphic traps on the
Hunton, Red Fork, Simpson and Morrow formations at 6,000 to 12,000 foot depths.
The Midcontinent development inventory includes 44 recompletions and 33 drilling
locations.
GULF COAST REGION
The Company's Gulf Coast properties include onshore reserves in south
Texas, Louisiana and Mississippi, as well as, offshore reserves in the shallow
waters of the Gulf of Mexico. The Gulf Coast business unit properties contained
164 Bcfe of proved reserves at December 31, 1998, or 28% of the total Present
Value. The reserves were 88% natural gas. At December 31, 1998 daily production
from the Gulf Coast properties averaged 1,576 barrels of oil and 60 Mmcf of gas.
The properties are located from south
11
<PAGE> 12
Texas to Mississippi. Major fields onshore include Hagist Ranch, Alta Mesa, and
Oakvale. These fields produce from the Wilcox, Frio, Yegua, Vicksburg, Miocene,
and Hosston formations at depths ranging from 1,000 to 16,000 feet. In total,
the onshore properties include 178 wells (131 net), of which 78% are Company
operated. The offshore properties in the Gulf of Mexico include 54 platforms
offshore in water depths ranging from 20 to 400 feet. The entire Gulf Coast
region is characterized by relatively complex geology, multiple producing
horizons and substantial exploitation and exploration potential. At December 31,
1998, the Gulf Coast properties had a proven development inventory of 110
recompletions and 44 drilling locations.
APPALACHIAN REGION
At December 31, 1998, the Appalachian properties contained 297 Bcfe of
proved reserves, representing 35% of the Company's total Present Value. The
reserves are attributable to 5,932 gross wells (5,065 net wells) located in
Pennsylvania, Ohio, West Virginia and New York. The Company operates 95% of
these wells. The reserves, which on an Mcfe basis are 98% natural gas, produce
principally from the Medina, Clinton and Knox sequence of formations at depths
ranging from 2,500 to 7,000 feet. Net daily production currently totals 43 Mmcf
of gas and 316 barrels of oil. After initial flush production, these properties
are characterized by gradual decline rates. Gas production is transported
through over 2,700 miles of Company owned gas gathering systems and is sold
primarily to utilities and industrial end-users.
PRODUCTION
The following table sets forth production information for the preceding
five years (in thousands, except average sales price and operating cost data).
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------
1994 1995 1996 1997 1998
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Production
Oil and NGL (Bbl) ........... 640 913 1,068 1,794 2,655
Gas (Mcf) ................... 6,996 12,471 21,231 38,409 45,193
Total (Mcfe) (a) ............ 10,836 17,949 27,641 49,170 61,120
Revenues
Oil and NGL ................. $ 9,743 $ 15,133 $ 20,425 $ 28,800 $ 30,084
Gas ......................... 14,718 22,284 47,629 101,217 105,509
-------- -------- -------- -------- --------
Total ....................... $ 24,461 $ 37,417 $ 68,054 $130,017 $135,593
Direct operating expenses (b) . 8,130 11,302 20,676 31,481 39,001
-------- -------- -------- -------- --------
Gross margin .................. $ 16,331 $ 26,115 $ 47,378 $ 98,536 $ 96,592
======== ======== ======== ======== ========
Average sales price
Oil (Bbl) ................... $ 15.23 $ 16.57 $ 19.56 $ 18.22 $ 12.01
NGL (Bbl) ................... - - $ 10.22 $ 9.06 $ 8.26
Gas (Mcf) ................... $ 2.10 $ 1.79 $ 2.24 $ 2.64 $ 2.33
Mcfe (a) .................... $ 2.26 $ 2.08 $ 2.46 $ 2.64 $ 2.22
Average operating expense
Per Mcfe .................... $ 0.75 $ 0.63 $ 0.75 $ 0.64 $ 0.64
</TABLE>
(a) Oil is converted to Mcfe at a rate of 6 Mcf per barrel.
(b) Includes severance and production taxes.
12
<PAGE> 13
PRODUCING WELLS
The following table sets forth information relating to productive wells
at December 31, 1998. The Company owns royalty interests in an additional 373
wells. Wells are classified as oil or gas according to their predominant
production stream.
<TABLE>
<CAPTION>
Average
Gross Net Working
Wells Wells Interest
----------- ----------- -----------
<S> <C> <C> <C>
Crude oil.................. 1,613 1,071 66%
Natural gas................ 6,814 5,684 83%
----------- -----------
Total................. 8,427 6,755 80%
=========== ===========
</TABLE>
ACREAGE
The following table sets forth the developed and undeveloped acreage
held at December 31, 1998.
<TABLE>
<CAPTION>
Average
Working
Gross Net Interest
------------- ------------- -----------
<S> <C> <C> <C>
Developed.................. 1,033,199 756,537 73%
Undeveloped................ 830,285 445,817 54%
------------- -------------
Total................. 1,863,484 1,202,354 64%
============= =============
</TABLE>
DRILLING RESULTS
The following table summarizes drilling activities for the three years
ended December 31, 1998.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------
1996 1997 1998
------------------- ------------------ -------------------
Gross Net Gross Net Gross Net
------- ------- -------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Development wells:
Productive.................... 49.0 45.2 186.0 164.1 222.0 182.0
Dry........................... 3.0 2.2 7.0 5.4 12.0 8.8
Exploratory wells:
Productive.................... 7.0 3.4 12.0 2.8 9.0 3.9
Dry........................... 4.0 1.1 8.0 2.0 5.0 2.9
Total Wells:
Productive.................... 56.0 48.6 198.0 166.9 231.0 185.9
Dry........................... 7.0 3.3 15.0 7.4 17.0 11.7
------- ------- -------- ------- ------- -------
Total.................... 63.0 51.9 213.0 174.3 248.0 197.6
======= ======= ======== ======= ======= =======
</TABLE>
REAL PROPERTY
The Company owns a 24,000 square foot facility located on seven acres
in Ohio. The Company leases approximately 56,000 square feet in Texas and
Oklahoma under standard office lease arrangements that expire at various times
through March 2004. All facilities are adequate to meet the Company's current
needs and existing space could be expanded or additional space could be leased.
The Company owns various rolling stock and other equipment which is
used in its field operations. Such equipment is believed to be in good repair
and, while such equipment is important to its operations, it can be readily
replaced as necessary.
13
<PAGE> 14
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in various legal actions and claims arising in
the ordinary course of business. In the opinion of management, such litigation
and claims will be resolved without a material adverse effect on the Company's
financial position.
In July 1997, a gas utility filed an action in the state district
court. In the lawsuit, the gas utility asserted a breach of contract claim
arising out of a gas purchase contract. Under the gas utility's interpretation
of the contract it sought, as damages, the reimbursement of the difference
between the above-market contract price it paid and market price on a portion of
the gas it has taken beginning in July 1997. Range counterclaimed seeking
damages for breach of contract and repudiation of the contract. In May 1998, the
court granted a partial summary judgment on the contract interpretation issue in
favor of the gas utility. In October 1998, the gas utility dropped its damages
claim and the state district court signed a final judgment in this case. Range
has appealed the final judgment.
In May 1998, a Domain stockholder filed an action in the Delaware Court
of Chancery, alleging that the terms of the Merger were unfair to a purported
class of Domain stockholders and that the defendants (except Range) violated
their legal duties to the class in connection with the Merger. Range is alleged
to have aided and abetted the breaches of fiduciary duty allegedly committed by
the other defendants. The action sought an injunction enjoining the Merger as
well as a claim for money damages. On September 3, 1998, the parties executed a
Memorandum of Understanding (the "MOU"), which represents a settlement in
principle of the litigation. Under the terms of the MOU, appraisal rights
(subject to certain conditions) were offered to all holders of Domain common
stock (excluding the defendants and their affiliates). Domain also agreed to pay
any court-awarded attorneys' fees and expenses of the plaintiffs' counsel in an
amount not to exceed $290,000. The settlement in principle is subject to court
approval and certain other conditions that have not been satisfied.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED MATTERS
The Company's Common Stock is listed on New York Stock Exchange
("NYSE") under the symbol "RRC". Prior to the Merger the stock was listed under
the symbol "LOM". During 1998, trading volume averaged 144,236 shares per day.
On March 9, 1999, the closing price of the Common Stock was $2 9/16. The
following table sets forth the high and low sales prices as reported on the NYSE
Composite transaction tape on a quarterly basis for the periods indicated.
<TABLE>
<CAPTION>
Common
High Low Dividends
----------- ----------- -----------
<S> <C> <C> <C>
1997
----
First Quarter............................. 23 5/8 16 .02
Second Quarter............................ 19 16 .02
Third Quarter............................. 20 1/8 14 .03
Fourth Quarter............................ 20 3/16 15 1/2 .03
1998
----
First Quarter............................. 17 1/2 13 1/4 .03
Second Quarter............................ 16 11/16 9 3/4 .03
Third Quarter............................. 10 7/16 6 1/16 .03
Fourth Quarter............................ 6 13/16 21 5/16 .03
</TABLE>
14
<PAGE> 15
DIVIDENDS
Dividends on the Common Stock were initiated in late 1995 and have been
paid in each quarter since that time. The Convertible Preferred Stock is
entitled to receive cumulative quarterly dividends at the annual rate of $2.03
per share. If there is any arrearage in dividends on preferred stock, the
Company may not pay dividends on the Common Stock. The Company has never been in
arrears in the payment of preferred dividends.
The payment of dividends is subject to declaration by the Board of
Directors and may depend on earnings, capital expenditures and market factors
existing from time to time. Given the depressed oil and gas price environment
the Company may reduce or eliminate future dividends. The bank credit facility
and the indenture for the 6% Convertible Subordinated Debenture and 8.75% Senior
Subordinated Notes contain restrictions on the Company's ability to pay
dividends on capital stock. Under the most restrictive of these provisions, the
Company could have paid $10.4 million of dividends as of December 31, 1998.
HOLDERS OF RECORD
At March 9, 1999, the number of holders of record of the Common Stock
and Convertible Preferred Stock were approximately 3,478 and 1, respectively.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial information covering
the preceding five years.
<TABLE>
<CAPTION>
As of or for the Year Ended December 31,
1994 1995 1996 1997 1998
-------- -------- -------- --------- --------
(In thousands, except per share data)
<S> <C> <C> <C> <C> <C>
OPERATIONS
Revenues............................... $ 26,637 $ 41,169 $ 75,341 $ 145,417 $148,929
Net income (loss)...................... 2,619 4,390 12,615 (23,332) (175,150)
Earnings (loss) per share.............. .25 .31 .71 (1.31) (6.82)
Earnings (loss) per share - dilutive... .25 .31 .69 (1.31) (6.82)
BALANCE SHEET
Working capital........................ $ 1,002 $ 4,563 $ 12,896 $ (2,051) $ (9,484)
Oil and gas properties, net............ 112,964 176,702 229,417 623,807 662,099
Total assets........................... 141,768 214,788 282,547 758,833 921,612
Senior debt............................ 61,885 83,035 61,780 186,712 367,050
Non-recourse debt of IPF subsidiary.... - - - - 60,100
Subordinated debt...................... - - 55,000 180,000 180,000
Trust convertible preferred securities. - - - 120,000 120,000
Stockholders' equity................... 43,248 99,367 117,529 196,950 133,222
</TABLE>
15
<PAGE> 16
The following table sets forth summary unaudited financial information
on a quarterly basis for the past two years (in thousands, except per share
data).
<TABLE>
<CAPTION>
1997
-------------------------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
----------- ------------ ------------- -------------
<S> <C> <C> <C> <C>
Revenues............................... $ 36,881 $ 32,069 $ 35,069 $ 41,398
Net income (loss) (a).................. 6,562 2,369 2,809 (35,072)
Earnings (loss) per share (a).......... .35 .09 .11 (1.73)
Earnings (loss) per share - dilutive (a) .32 .09 .11 (1.73)
Total assets (a) ...................... 667,522 674,835 780,620 758,833
Senior debt............................ 210,230 206,711 309,007 186,712
Subordinated debt...................... 180,000 180,000 180,000 180,000
Trust convertible preferred securities. - - - 120,000
Stockholders' equity (a)............... 218,146 219,769 223,961 196,950
<CAPTION>
1998
--------------------------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
----------- ------------ ------------- -------------
<S> <C> <C> <C> <C>
Revenues............................... $ 36,010 $ 32,273 $ 35,431 $ 45,215
Net income (loss) (b).................. 2,769 (944) (66,907) (110,068)
Earnings (loss) per share (b).......... .10 (.07) (2.57) (3.13)
Earnings (loss) per share - dilutive (b) .10 (.07) (2.57) (3.13)
Total assets (b)....................... 800,252 822,984 1,036,111 921,612
Senior debt............................ 234,905 252,200 368,176 367,050
Non-recourse debt of IPF subsidiary.... - - 53,795 60,100
Subordinated debt...................... 180,000 180,000 180,000 180,000
Trust convertible preferred securities. 120,000 120,000 120,000 120,000
Stockholders' equity(b)................ 199,058 195,747 234,575 133,222
</TABLE>
(a) Includes a $58.7 million provision for impairment ($38.7 million after tax)
recorded in the fourth quarter.
(b) Includes a $97.9 million provision for impairment ($63.6 million after tax)
recorded in the third quarter and a $109.2 million provision for impairment
($92.6 million after tax) recorded in the fourth quarter.
The total of the earnings per share for each quarter does not equal the
earnings per share for the full year, either because the calculations are based
on the weighted average shares outstanding during each of the individual
periods, or due to rounding.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
FACTORS EFFECTING FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY AND CAPITAL RESOURCES
General
The following discussion compares the Company's financial condition at
December 31, 1998 to its financial condition at December 31, 1997. During 1998,
the Company spent approximately $369 million on acquisition, development and
exploration activities. At December 31, 1998, the Company had $11 million in
cash and total assets of $921.6 million. During 1998, debt rose from $367.1
million to $607.2 million. At December 31, 1998, debt to total book
capitalization was 71%.
In August 1998, the stockholders of the Company approved the Merger.
Pursuant to the Merger, stockholders of Domain received approximately 13.6
million shares of the Company's Common Stock. The Company also purchased 3.8
million Domain shares for $50.5 million in cash. As a result of the
16
<PAGE> 17
Merger, Domain became a wholly-owned subsidiary of Lomak. Simultaneously, Lomak
stockholders approved changing the company's name to Range Resources
Corporation.
In December 1998, the Company implemented an overhead reduction program
in response to the depressed energy price environment. The cuts included the
termination of 54 employees and the closure of the Midland, Texas office. In
addition, during 1999 the Company plans to sell assets and limit exploration and
development capital expenditures to reduce debt.
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.
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.
Recent decreases in the market price of oil and gas have reduced cash flow and
could reduce the borrowing base under the Credit Facility. As a result, the
Company has reduced its development and exploration budget to between $35
million to $40 million in 1999. The 1999 expenditures will be funded by
internally generated cash flow and therefore may be reduced further depending
upon commodity prices.
The Company's net cash provided by operations for the years ended
December 31, 1996, 1997 and 1998 was $38.4 million, $77.1 million and $45.0
million, respectively. The decline in the Company's 1998 cash flow from
operations is attributed to sharply lower energy prices, as well as increased
interest expense resulting from higher outstanding debt balances incurred to
finance acquisitions and development activities.
The Company's net cash used in investing for the years ended December
31, 1996, 1997 and 1998 was $69.7 million, $501.1 million and $172.3 million,
respectively. Investing activities for these periods are comprised primarily of
additions to oil and gas properties through acquisitions and development and, to
a lesser extent, exploration and additions of field service assets. These uses
of cash have historically been partially offset through the Company's policy of
divesting those properties that it deems to be non-strategic. The Company's
activities have been financed through a combination of operating cash flow, bank
borrowings and capital raised through equity and debt offerings. The Company's
net cash provided by financing for the years ended December 31, 1996, 1997 and
1998 was $36.8 million, $425.2 million and $128.5 million, respectively. Sources
of financing used by the Company have been primarily borrowings under its Credit
Facility and capital raised through equity and debt offerings.
Capital Requirements
In 1998, $81.5 million of capital was expended on development and
exploration activities. In an effort to reduce outstanding debt the Company has
significantly reduced its 1999 exploration and development capital budget to
between $35 million to $40 million. The development and exploration expenditures
are currently expected to be funded entirely by internally generated cash flow.
The remaining cash flow will be available for debt repayment. See
"Business--Development and Exploration Activities."
Bank Facilities
The Credit Facility permits the Company to obtain revolving credit
loans and to issue letters of credit for the account of the Company from time to
time in an aggregate amount not to exceed $400 million. The Borrowing Base is
currently $385 million and 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 revolving credit commitments may
be reduced, in whole or in part at any time in certain minimum amounts. At
December 31, 1998, the Company had $19.8 million of availability under the
Credit Facility. Until amounts
17
<PAGE> 18
under the Credit Facility are reduced to $300 million or the redetermined
borrowing base the interest rate will be LIBOR plus 1.75% and will increase to
LIBOR plus 2.0% on May 1, 1999. When outstanding amounts are reduced to levels
at or below $300 million or the redetermined borrowing base the interest rate on
the Credit Facility will return to interest at prime rate or LIBOR plus 0.625%
to 1.125% depending on the percentage of borrowing base drawn. If amounts
outstanding under the Credit Facility exceed the higher of the redetermined
borrowing base or $300 million on June 30, 1999, then the Company will have 10
days to repay any excess.
The Company plans to reduce outstanding amounts under the Credit
Facility through operating cash flow and the sale of assets. Since the borrowing
base is principally determined by the estimated value of oil and gas reserves
these asset sales are expected to reduce the borrowing base and cash flows due
to the loss of future production. The Company has developed a number of packages
of oil and gas assets to offer for sale. The Company will utilize the proceeds
from the sale of assets to reduce amounts outstanding under the Credit Facility.
Additionally, the Company is considering the monetization of oil and gas assets
whose proceeds would be used to reduce the Credit Facility. At December 31,
1998, the Company classified $55.2 million of Credit Facility borrowings as
current to reflect an estimate of the amounts outstanding at December 31, 1998
that will be repaid during 1999.
The IPF Facility is secured by substantially all of IPF's assets and is
non-recourse to the Company. The borrowing base under the IPF Facility is
subject to redeterminations, which occur routinely during the year. On March 10,
1999, the borrowing base on the IPF Facility was $60.1 million, which did not
exceed the amounts outstanding on that date. The Company is currently in the
process of completing a borrowing base redetermination. Upon completion of the
redetermination, the Company believes the borrowing base will decrease slightly
and that the outstanding obligations at that time will not exceed the borrowing
base. 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
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 December 31, 1998, the Company had open contracts for gas price swaps
of 6.4 Bcf of its production. The swap contracts are designed to set average
prices ranging from $1.90 to $2.64 per Mmbtu. While these transactions have no
carrying value, the Company's mark-to-market exposure under these contracts at
December 31, 1998 was a net gain of approximately $44,500. These contracts
expire monthly through October 1999. 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 oil and
gas revenues in the period the hedged production or inventory is sold. Net gains
or (losses) relating to these derivatives for the years ended December 31, 1996,
1997 and 1998 approximated $(.7) million, $(.9) million and $3.1 million
respectively.
INFLATION AND CHANGES IN PRICES
The Company's revenues and the value of its oil and gas properties have
been and will be affected by changes in oil and gas prices. The Company's
ability to maintain current borrowing capacity and to obtain additional capital
on attractive terms is also substantially dependent on oil and gas prices. Oil
and gas prices are subject to significant seasonal and other fluctuations that
are beyond the Company's ability to control or predict. During 1998, the Company
received an average of $12.01 per barrel of oil and $2.33 per Mcf of gas.
Although certain of the Company's costs and expenses are affected by the level
of inflation, inflation did not have a significant effect in 1998. Should
conditions in the industry improve, inflationary cost pressures may resume.
18
<PAGE> 19
RESULTS OF OPERATIONS
Comparison of 1998 to 1997
The Company reported a net loss for the year ended December 31, 1998 of
$175.2 million, as compared to a net loss of $23.3 million for 1997. Due
principally to the depressed energy price environment, the Company recorded a
provision for impairment of $207.1 million ($156.2 million after tax) and $5.9
million ($5.0 million after tax) of valuation allowances on IPF receivables. The
Company initiated a restructuring plan to reduce costs and improve operating
efficiencies. In connection with the cost reduction program the Company recorded
a charge of $3.1 million ($2.7 million after tax).
Oil and gas revenues increased 4% to $135.6 million. During the year,
oil and gas production volumes increased 24% to 61.1 Bcfe, an average of 167,500
Mmcfe per day. The increased revenues recognized from production volumes were
negatively impacted by a 16% decrease in the average price received per Mcfe of
production to $2.22. The average oil price decreased 34% to $12.01 per barrel
and average gas prices decreased 12% to $2.33 per Mcf. As a result of the
Company's larger base of producing properties and production, oil and gas
production expenses increased 24% to $39.0 million in 1998 versus $31.5 million
in 1997. The average operating cost per Mcfe produced was $0.64 during both
periods.
Transportation, processing and marketing revenues decreased 14% to $6.7
million versus $7.8 million in 1997, the decrease was principally due to the
sale of a gas processing plant in the San Juan Basin and a drop in natural gas
liquid prices which lowered gas processing revenues. IPF income has been
recorded for periods following the Merger. IPF income consists of the interest
portion of the term overriding royalty interests. During 1998, IPF expenses
included $.5 million of administrative expenses, $1.6 million of interest
expense and a $5.9 million valuation allowance.
Exploration expense increased 346% to $11.3 million due to the
Company's higher levels of seismic and exploratory drilling activity. During
1998 the Company spent $4.3 million on 5 exploratory dry holes compared to
$294,000 of dry hole costs in 1997.
General and administrative expenses increased 74% from $5.3 million in
1997 to $9.2 million in 1998. As a percentage of revenues, general and
administrative expenses were 6% in 1998 as compared to 4% in 1997. The increase
was due to higher personnel costs associated with the Company's growth, as well
as, increased legal expenditures during 1998. In December 1998, the Company
implemented an overhead reduction program in response to the depressed energy
price environment. The cuts included the termination of 54 employees,
representing 27% of non-field staff.
Interest and other income decreased 70% to $2.3 million primarily due
to lower levels of non-strategic assets sales. Interest expense increased 50% to
$40.6 million as compared to $27.2 million in 1997. This was primarily a result
of the higher average outstanding debt balance during the year due to the
financing of acquisitions and drilling activities. The average outstanding
balances on the Credit Facility were $192.1 million and $271.6 million for 1997
and 1998, respectively. The weighted average interest rate on these borrowings
were 7.3% and 6.7% for the years ended December 31, 1997 and 1998, respectively.
Depletion, depreciation and amortization increased 9% compared to 1997
as a result of increased production volumes. This increase was partially offset
by a decrease in the average depletion rate per Mcfe. The Company-wide depletion
rate was $1.03 per Mcfe in 1997 and $.89 per Mcfe in 1998.
Comparison of 1997 to 1996
The Company reported a net loss for the year ended December 31, 1997 of
$23.3 million, as compared to $12.6 million net income for 1996. During the
fourth quarter of 1997, the Company recorded a provision for impairment with
regard to certain of its oil and gas properties amounting to $58.7 million
($38.7
19
<PAGE> 20
million after tax). Excluding the effects of the non-cash impairment charge, net
income would have risen 22% to $15.4 million. The increase is principally the
result of (i) higher production volumes, (ii) lower per unit operating and
overhead costs and (iii) higher average product prices. During the year, oil and
gas production volumes increased 78% to 49.2 Bcfe, an average of 134.7 Mmcfe per
day. The increased revenues recognized from production volumes were aided by an
7% increase in the average price received per Mcfe of production to $2.64. The
average oil price decreased 7% to $18.22 per barrel while average gas prices
increased 18% to $2.64 per Mcf. As a result of the Company's larger base of
producing properties and production, oil and gas production expenses increased
52% to $31.5 million in 1997 versus $20.7 million in 1996. The average operating
cost per Mcfe produced decreased 15% from $0.75 in 1996 to $0.64 in 1997.
Transportation, processing and marketing revenues increased 100% to
$7.8 million versus $3.9 million in 1996 principally due to production growth.
Exploration expense increased 73% to $2.5 million due to the Company's increased
involvement in seismic and exploratory drilling activity.
General and administrative expenses increased 33% from $4.0 million in
1996 to $5.3 million in 1997. As a percentage of revenues, general and
administrative expenses were 4% in 1997 as compared to 5% in 1996. This
decreasing trend reflects the spreading of administrative costs over a growing
asset base.
Interest and other income rose 124% to $7.6 million primarily due to
$3.2 million on gains from sale of marketable securities (which were not related
to hedging activities), and $4.1 million from the gain on the sale of
non-strategic assets. Interest expense increased 263% to $27.2 million as
compared to $7.5 million in 1996. This was primarily as a result of the higher
average outstanding debt balance during the year due to the financing of
acquisitions and drilling activities. The average outstanding balances on the
Credit Facility were $107.2 million and $192.1 million for 1996 and 1997,
respectively. The weighted average interest rate on these borrowings were 6.7%
and 7.3% for the years ended December 31, 1996 and 1997, respectively.
Depletion, depreciation and amortization increased 148% compared to
1996 as a result of increased production volumes and increased depletion rates
per volume. The Company-wide depletion rate was $0.73 per Mcfe in 1996 and $1.03
per Mcfe in 1997.
Comparison of 1996 to 1995
The Company reported net income for the year ended December 31, 1996 of
$12.6 million, a 187% increase over 1995. The increase is the result of (i)
higher production volumes, over 60% of which is attributable to acquisitions and
the remainder of which is attributable to development activities, (ii) increased
prices received from the sale of oil and gas products and (iii) gains from asset
sales. During the year, oil and gas production volumes increased 54% to 27.6
Bcfe, an average of 76 Mmcfe/d. The increased revenues recognized from
production volumes were aided by an 18% increase in the average price received
per Mcfe of production to $2.46. The average oil price increased 18% to $19.56
per barrel while average gas prices increased 25% to $2.24 per Mcf. As a result
of the Company's larger base of producing properties and production, oil and gas
production expenses increased 83% to $20.7 million in 1996 versus $11.3 million
in 1995. The average operating cost per Mcfe produced increased 19% from $0.63
in 1995 to $0.75 in 1996 due to unsuccessful recompletion costs and increases in
personnel costs. Exploration expense increased 185% to $1.5 million due to the
Company's increased involvement in seismic and exploratory drilling. The Company
participated in 11 exploratory wells in 1996 versus 7 exploratory wells in 1995.
Gas transportation and marketing revenues increased 60% to $3.9 million
versus $2.4 million in 1995 principally due to production growth.
General and administrative expenses increased 45% from $2.7 million in
1995 to $4.0 million in 1996. As a percentage of revenues, general and
administrative expenses were 5% in 1996 as compared to 7% in 1995. This
decreasing trend reflects the spreading of administrative costs over a growing
asset base.
Interest and other income rose 157% to $3.4 million primarily due to
$1.4 million on gains from sales of marketable securities (which were not
related to hedging activities), and $1.2 million from the gain on
20
<PAGE> 21
the sale of the Oklahoma well servicing assets. Interest expense increased 34%
to $7.5 million as compared to $5.6 million in 1995. This was primarily as a
result of the higher average outstanding debt balance during the year due to the
financing of capital expenditures. The average outstanding balances on the
Credit Facility were $73.3 million and $107.2 million for 1995 and 1996,
respectively. The weighted average interest rate on these borrowings were 7.3%
and 6.7% for the years ended December 31, 1995 and 1996, respectively.
Depletion, depreciation and amortization increased 50% compared to 1995
as a result of increased production volumes during the year. The Company-wide
depletion rate was $0.73 per Mcfe in 1995 and 1996.
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.
The Company is in the process of assessing its information technology
("IT") and its non-IT systems. The term "computer equipment and software"
includes systems that are commonly thought of as IT systems, including personal
computers, accounting / data processing and other miscellaneous systems. Range
is in the process of replacing the computer equipment and software it currently
uses to become Year 2000 compliant. The Company estimates that 85% of its
computer equipment and software are currently Year 2000 compliant. Also, in the
ordinary course of replacing computer equipment and software, Range plans to
obtain replacements that are in compliance with the Year 2000. The Company
estimates that the cost to complete these efforts, which include software
upgrades under normal maintenance agreements with third party vendors, based
upon information developed to date, will not exceed $350,000.
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 gas
processing, telemetry and safety shutdown controls. The estimated cost
associated with correcting the operational and control systems is $250,000.
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. The Company expects to complete this assessment by June
30, 1999. 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 effect its vendors and
customers. However, management believes that ongoing communication with and
assessment of the compliance efforts of these third parties will minimize these
risks.
The discussion of the Company's efforts and management's expectations
relating to Year 2000 compliance contains forward-looking statements. Range is
currently conducting a comprehensive analysis of the operational problems and
costs that would be reasonably likely to result from failure by Range and
significant third parties to complete efforts necessary to achieve Year 2000
compliance on a timely basis. The Company plans to establish a contingency plan
for dealing with the most reasonably likely worst case scenario. To date, such
scenario has not been clearly identified. Range plans to complete such analysis
and contingency planning by the third quarter of 1999.
21
<PAGE> 22
Range presently does not expect to experience significant operational
problems due to the Year 2000 issue. However, if all Year 2000 issues are not
properly and timely identified, assessed, remediated and tested, there can be no
assurance that the Year 2000 issue will not materially impact Range's results of
operations or adversely affect its relationship with customers, vendors, or
others. Additionally, there can be no assurance that the Year 2000 issues of
other entities will not have a material impact on Range's systems or results of
operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to the Index to Financial Statements on page 28 for a
listing of the Company's financial statements and notes thereto and for
supplementary schedules. Schedules I, III, IV, V, VI, VII, VIII, IX, X, XI, XII
and XIII have been omitted as not required or not applicable or because the
information required to be presented is included in the financial statements and
related notes.
MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS
The financial statements have been prepared by management in conformity
with generally accepted accounting principles. Management is responsible for the
fairness and reliability of the financial statements and other financial data
included in this report. In the preparation of the financial statements, it is
necessary to make informed estimates and judgments based on currently available
information on the effects of certain events and transactions.
The Company maintains accounting and other controls which management
believes provide reasonable assurance that financial records are reliable,
assets are safeguarded, and that transactions are properly recorded. However,
limitations exist in any system of internal control based upon the recognition
that the cost of the system should not exceed benefits derived.
The Company's independent auditors, Arthur Andersen LLP, are engaged to
audit the financial statements and to express an opinion thereon. Their audit is
conducted in accordance with generally accepted auditing standards to enable
them to report whether the financial statements present fairly, in all material
respects, the financial position and results of operations in accordance with
generally accepted accounting principles.
ITEM 9. CHANGE IN ACCOUNTANTS AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
22
<PAGE> 23
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
The current executive officers and directors of the Company are listed
below, together with a description of their experience and certain other
information. Each of the directors was elected for a one-year term at the
Company's 1999 annual meeting of stockholders. Executive officers are appointed
by the Board of Directors.
<TABLE>
<CAPTION>
HELD
NAME AGE OFFICE SINCE POSITION WITH COMPANY
---- --- ------------ ---------------------
<S> <C> <C> <C>
Thomas J. Edelman 48 1988 Chairman and Chairman of the Board
John H. Pinkerton 44 1988 President, Chief Executive Officer
and Director
Michael V. Ronca 45 1998 Chief Operating Officer and Director
Robert E. Aikman 67 1990 Director
Anthony V. Dub 49 1995 Director
Allen Finkelson 52 1994 Director
Ben A. Guill 48 1995 Director
Jonathan S. Linker 50 1998 Director
Steven L. Grose 50 1980 Senior Vice President - Appalachia
Herbert A. Newhouse 54 1998 Senior Vice President - Gulf Coast
Catherine L. Sliva 40 1998 Senior Vice President - Independent Producer
Finance
Chad L. Stephens 43 1990 Senior Vice President - Southwest
Thomas W. Stoelk 43 1994 Senior Vice President - Finance
and Administration
Jeffery A. Bynum 44 1985 Vice President - Land and Corporate Secretary
Geoffrey T. Doke 32 1996 Vice President and Controller
</TABLE>
Thomas J. Edelman, Chairman and Chairman of the Board of Directors,
joined the Company in 1988. He served as its Chief Executive Officer until 1992.
From 1981 to 1997, Mr. Edelman served as a director and President of Snyder Oil
Corporation ("SOCO"), an independent, publicly traded oil and gas company. In
1996, Mr. Edelman was appointed Chairman, President and Chief Executive Officer
of Patina Oil & Gas Corporation. Prior to 1981, Mr. Edelman was a Vice President
of The First Boston Corporation. From 1975 through 1980, Mr. Edelman was with
Lehman Brothers Kuhn Loeb Incorporated. Mr. Edelman received his Bachelor of
Arts Degree from Princeton University and his Masters Degree in Finance from
Harvard University's Graduate School of Business Administration. Mr. Edelman
serves as a director of Petroleum Heat & Power Co., Inc., a Connecticut-based
fuel oil distributor, Star Gas Corporation, a private company, which is the
general partner of Star Gas Partners, L.P., a publicly-traded master limited
partnership, which distributes propane gas, as well as Paradise Music &
Entertainment, Inc.
John H. Pinkerton, President, Chief Executive Officer and a Director,
joined the Company in 1988. He was appointed President in 1990 and Chief
Executive Officer in 1992. Previously, Mr. Pinkerton was Senior Vice
President-Acquisitions of SOCO. Prior to joining SOCO in 1980, Mr. Pinkerton was
with Arthur Andersen & Co. Mr. Pinkerton received his Bachelor of Arts Degree in
Business Administration from Texas Christian University and his Master of Arts
Degree in Business Administration from the University of Texas. Mr. Pinkerton is
also director of North Coast Energy, Inc. ("North Coast"), and Venus
Exploration, Inc. publicly traded exploration and production companies in which
Range owned 17.4% and 21.7%, respectively, at December 31, 1998.
Michael V. Ronca, Chief Operating Officer and a Director, joined the
Company in 1998. Prior to joining Range, Mr. Ronca served as President and Chief
Executive Officer of Domain Energy Corporation. He was the founder and former
President of Tenneco Ventures Corporation. Mr. Ronca was an employee of
23
<PAGE> 24
Tenneco for over 20 years. Other positions held at Tenneco included
Administrative Assistant to the Chairman and CEO, with focus on acquisition and
disposition analysis, strategic planning and operational issues.
Robert E. Aikman, a Director, joined the Company in 1990. Mr. Aikman
has more than 40 years experience in petroleum and natural gas exploration and
production throughout the United States and Canada. From 1984 to 1994 he was
Chairman of the Board of Energy Resources Corporation. From 1979 through 1984,
he was the President and principal shareholder of Aikman Petroleum, Inc. From
1971 to 1977, he was President of Dorchester Exploration Inc. and from 1971 to
1980, he was a Director and a member of the Executive Committee of Dorchester
Gas Corporation. Mr. Aikman is also Chairman of Provident Communications, Inc.,
President of OGP Technologies, Inc., and President of The Hawthorne Company, an
entity which organizes joint ventures and provides advisory services for the
acquisition of oil and gas properties, including the financial restructuring,
reorganization and sale of companies. He was President of Enertec Corporation
which was reorganized under Chapter 11 of the Bankruptcy Code in December 1994.
In addition, Mr. Aikman is a director of the Panhandle Producers and Royalty
Owners Association and a member of the Independent Petroleum Association of
America, Texas Independent Producers and Royalty Owners Association and American
Association of Petroleum Landmen. Mr. Aikman graduated from the University of
Oklahoma in 1952.
Anthony V. Dub was elected to serve as a Director of the Company in
1995. Mr. Dub is Chairman of Indigo Capital, LLC, a financial advisory firm
based in New York City. Prior to forming Indigo Capital in 1997, he served as an
officer of Credit Suisse First Boston, an investment banking firm. Mr. Dub
joined Credit Suisse First Boston in 1971 and was named a Managing Director in
1981. Mr. Dub received his Bachelor of Arts Degree from Princeton University in
1971.
Allen Finkelson, was appointed a Director in 1994. Mr. Finkelson has
been a partner at Cravath, Swaine & Moore since 1977, with the exception of the
period from September 1983 through August 1985, when he was a managing director
of Lehman Brothers Kuhn Loeb Incorporated. Mr. Finkelson was first employed by
Cravath, Swaine & Moore as an associate in 1971. Mr. Finkelson received his
Bachelor of Arts Degree from St. Lawrence University and his Doctor of Laws
Degree from Columbia University School of Law.
Ben A. Guill, was elected to serve as a Director of the Company in
1995. In September 1998 Mr. Guill joined First Reserve Corporation as President
of its Houston office. First Reserve is a private equity firm, dedicated to the
energy industry. Prior to joining First Reserve, Mr. Guill was a Partner and
Managing Director of Simmons & Company International, an investment banking firm
located in Houston, Texas which focuses on the oil service and equipment
industry. Mr. Guill had been with Simmons & Company since 1980. Prior to that
Mr. Guill was with Blyth Eastman Dillon & Company from 1978 to 1980. Mr. Guill
received his Bachelor of Arts Degree from Princeton University and his Masters
Degree in Finance from the Wharton Graduate School of Business at the University
of Pennsylvania.
Jonathan S. Linker has served as a Director of the Company since the
Merger in August 1998. Mr. Linker has been a Managing Director of First Reserve
since 1996, the President and a director of IDC Energy Corporation since 1987,
and a Vice President and Director of Sunset Production Corporation since 1991.
Mr. Linker earned a Bachelor of Arts degree in Geology from Amherst College, a
Master of Arts degree in Geology from Harvard University and a Master of
Business Administration degree from the Harvard Business School.
Steven L. Grose, Senior Vice President - Appalachia, joined the Company
in 1980. Previously, Mr. Grose was employed by Halliburton Services, Inc. as a
Field Engineer from 1971 until 1974. In 1974, he was promoted to District
Engineer and in 1978, was named Assistant District Superintendent based in
Pennsylvania. Mr. Grose is a member of the Society of Petroleum Engineers and is
currently serving as President of the Ohio Oil and Gas Association. Mr. Grose
received his Bachelor of Science Degree in Petroleum Engineering from Marietta
College.
24
<PAGE> 25
Herbert A. Newhouse, Senior Vice President - Gulf Coast, joined the
Company in 1998. Prior to joining Range, Mr. Newhouse served as Executive Vice
President of Domain Energy Corporation. He was a former Vice President of
Tenneco Ventures Corporation. Mr. Newhouse was an employee of Tenneco for over
17 years and has 30 years of operational and managerial experience in oil and
gas exploration and production. Mr. Newhouse received his Bachelor's degree in
Chemical Engineering from Ohio State University.
Catherine L. Sliva, Senior Vice President - Independent Producer
Finance, joined the Company in connection with the Merger in August 1998. Prior
to joining Range, Ms. Sliva served as Executive Vice President and Secretary of
Domain Energy Corporation. She was formerly with Tenneco Ventures Corporation
for 16 years. Ms. Sliva is a registered Petroleum Engineer and has over 18 years
experience in petroleum engineering, economics, producer finance and strategic
planning and analysis. She received her Bachelor's degree in Petroleum
Engineering from Texas A&M University.
Chad L. Stephens, Senior Vice President - Southwest, joined the Company
in 1990. Previously, Mr. Stephens was with Duer Wagner & Co., an independent oil
and gas producer, since 1988. Prior thereto, Mr. Stephens was an independent oil
operator in Midland, Texas for four years. From 1979 to 1984, Mr. Stephens was
with Cities Service Company and HNG Oil Company. Mr. Stephens received his
Bachelor of Arts Degree in Finance and Land Management from the University of
Texas.
Thomas W. Stoelk, Senior Vice President - Finance and Administration,
joined the Company in 1994. Mr. Stoelk is a Certified Public Accountant and was
a Senior Manager with Ernst & Young LLP. Prior to rejoining Ernst & Young LLP in
1986 he was with Partners Petroleum, Inc. Mr. Stoelk received his Bachelor of
Science Degree in Industrial Administration from Iowa State University.
Jeffery A. Bynum, Vice President - Land and Corporate Secretary, joined
the Company in 1985. Previously, Mr. Bynum was employed by Crystal Oil Company
and Kinnebrew Energy Group. Mr. Bynum holds a Professional Certification with
American Association of Petroleum Landmen and attended Louisiana State
University in Baton Rouge, Louisiana and Centenary College in Shreveport,
Louisiana.
Geoffrey T. Doke, Vice President and Controller, joined the Company in
1991. He was appointed Treasurer in 1996 and Controller in 1997. Previously, Mr.
Doke served in the accounting department of Edisto Resources Corporation. Mr.
Doke received his Bachelor of Business Administration Degree in Finance and
International Business from Baylor University and his Master of Business
Administration Degree from Case Western Reserve University.
The Range Board has established three committees to assist in the
discharge of its responsibilities.
AUDIT COMMITTEE. The Audit Committee reviews the professional services
provided by Range's independent public accountants and the independence of such
accountants from management of Range. This Committee also reviews the scope of
the audit coverage, the annual financial statements of Range and such other
matters with respect to the accounting, auditing and financial reporting
practices and procedures of Range as it may find appropriate or as have been
brought to its attention. Messrs. Aikman, Dub and Guill are the members of the
Audit Committee.
COMPENSATION COMMITTEE. The Compensation Committee reviews and approves
executive salaries and administers bonus, incentive compensation and stock
option plans of Range. This Committee advises and consults with management
regarding pensions and other benefits and significant compensation policies and
practices of Range. This Committee also considers nominations of candidates for
corporate officer positions. The members of the Compensation committee are
Messrs. Aikman, Guill and Finkelson.
EXECUTIVE COMMITTEE. The Executive Committee reviews and authorizes
actions required in the management of the business and affairs of Range, which
would otherwise be determined by the Board, where it is not practicable to
convene the full Board. One of the principal responsibilities of the Executive
25
<PAGE> 26
Committee will be to review and approve smaller acquisitions. The members of the
Executive Committee are Messrs. Edelman, Finkelson and Pinkerton.
ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
Information with respect to executive compensation is incorporated
herein by reference to the Company's Proxy Statement for its 1999 annual meeting
of stockholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information with respect to security ownership of certain beneficial
owners and management is incorporated herein by reference to the Company's Proxy
Statement for its 1999 annual meeting of stockholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information with respect to certain relationships and related
transactions is incorporated herein by reference to the Company's Proxy
Statement for its 1999 annual meeting of stockholders.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K
(a) 1. and 2. Financial Statements and Financial Statement
Schedules. The items listed in the accompanying index to
financial statements are filed as part of this Annual Report
on Form 10-K.
3. Exhibits.
The items listed on the accompanying index to exhibits are
filed as part of this Annual Report on Form 10-K.
(b) Reports on Form 8-K.
The Company's Current Report on Form 8-K, dated August 25,
1998, as amended by Form 8-K/A, dated November 9, 1998.
(c) Exhibits required by Item 601 of Regulation S-K.
Exhibits required to be filed by the Company pursuant to
Item 601 of Regulation S-K are contained in Exhibits listed
in response to Item 14 (a)3, and are incorporated herein by
reference.
(d) Financial Statement Schedules Required by Regulation S-X.
The items listed in the accompanying index to financial
statements are filed as part of this Annual Report on Form
10-K.
26
<PAGE> 27
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE COMPANY HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
Dated: March 12, 1999
RANGE RESOURCES CORPORATION
By: /s/ John H. Pinkerton
----------------------------
John H. Pinkerton
President
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE PERSONS ON BEHALF OF THE COMPANY AND IN
THE CAPACITIES AND ON THE DATES INDICATED.
<TABLE>
<S> <C>
/s/ Thomas J. Edelman Thomas J. Edelman,
- ------------------------------- Chairman and Chairman of the Board
March 12, 1999
/s/ John H. Pinkerton John H. Pinkerton,
- ------------------------------- Chief Executive Officer, President and
March 12, 1999 Director
/s/ Michael V. Ronca Michael V. Ronca,
- ------------------------------- Chief Operating Officer, and Director
March 12, 1999
/s/ Thomas W. Stoelk Thomas W. Stoelk,
- ------------------------------- Chief Financial Officer and Senior Vice
March 12, 1999 President-Finance & Administration
/s/ Geoffrey T. Doke Geoffrey T. Doke,
- ------------------------------- Chief Accounting Officer and Vice President
March 12, 1999 and Controller
/s/ Robert E. Aikman Robert E. Aikman, Director
- -------------------------------
March 12, 1999
/s/ Allen Finkelson Allen Finkelson, Director
- -------------------------------
March 12, 1999
/s/ Anthony V. Dub Anthony V. Dub, Director
- -------------------------------
March 12, 1999
/s/ Ben A. Guill Ben A. Guill, Director
- -------------------------------
March 12, 1999
/s/ Jonathan S. Linker Jonathan S. Linker, Director
- -------------------------------
March 12, 1999
</TABLE>
27
<PAGE> 28
RANGE RESOURCES CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(ITEM 14[a], [d])
<TABLE>
<CAPTION>
Page
Number
------
<S> <C>
Reports of Independent Public Accountants 29
Consolidated balance sheets at December 31, 1997 and 1998 30
Consolidated statements of income for the years ended December 31, 1996, 1997 and 1998 31
Consolidated statements of stockholders' equity for the years ended December 31, 1996, 1997 and 1998 32
Consolidated statements of cash flows for the years ended December 31, 1996, 1997 and 1998 33
Notes to consolidated financial statements 34
</TABLE>
Exhibits
All other schedules have been omitted since the required information is
not present in amounts sufficient to require submission of the schedule, or
because the information required is included in the financial statements or
footnotes.
28
<PAGE> 29
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS
RANGE RESOURCES CORPORATION
We have audited the accompanying consolidated balance sheets of Range
Resources Corporation (a Delaware corporation) as of December 31, 1997 and 1998,
and the related consolidated statements of income, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1998. These
financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Range Resources
Corporation as of December 31, 1997 and 1998, and the results of its operations
and its cash flows for the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
February 19, 1999
29
<PAGE> 30
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
December 31,
-------------------------
1997 1998
--------- ---------
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents .................................... $ 9,725 $ 10,954
Accounts receivable ..................................... 29,200 30,384
IPF receivables (Note 4) ................................ - 7,140
Marketable securities ................................... 5,777 3,258
Assets held for sale (Note 5) ........................... - 51,822
Inventory and other ..................................... 2,779 3,373
--------- ---------
47,481 106,931
--------- ---------
IPF receivables, net (Note 4) ............................. - 70,032
Oil and gas properties, successful efforts method ......... 785,223 935,822
Accumulated depletion and impairment .................. (161,416) (273,723)
--------- ---------
623,807 662,099
--------- ---------
Transportation, processing and field assets ............... 85,904 89,471
Accumulated depreciation .............................. (9,730) (15,146)
--------- ---------
76,174 74,325
--------- ---------
Other ..................................................... 11,371 8,225
--------- ---------
$ 758,833 $ 921,612
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable ........................................ $ 26,878 $ 28,163
Accrued liabilities ..................................... 10,048 15,773
Accrued payroll and benefit costs ....................... 3,195 5,156
Accrued interest ........................................ 8,998 9,439
Accrued business restructuring costs (Note 13) .......... - 2,697
Current portion of debt (Note 6) ........................ 413 55,187
--------- ---------
49,532 116,415
--------- ---------
Senior debt (Note 6) ...................................... 186,712 311,875
Non-recourse debt of IPF subsidiary (Note 6) .............. - 60,100
Subordinated debt (Note 6) ................................ 180,000 180,000
Deferred taxes (Note 12) .................................. 25,639 -
Commitments and contingencies (Note 8) .................... - -
Company-obligated preferred securities
of subsidiary trust (Note 9) .......................... 120,000 120,000
Stockholders' equity (Notes 9 and 10)
Preferred stock, $1 Par, 10,000,000 shares authorized,
$2.03 convertible preferred, 1,149,840 issued
and outstanding (liquidation preference $28,746,000) 1,150 1,150
Common stock, $.01 par, 50,000,000 shares authorized,
21,058,442 and 35,933,523 issued .................... 211 359
Capital in excess of par value ........................... 217,631 334,817
Retained deficit ......................................... (22,412) (203,396)
Other comprehensive income ............................... 370 292
--------- ---------
196,950 133,222
--------- ---------
$ 758,833 $ 921,612
========= =========
</TABLE>
SEE ACCOMPANYING NOTES.
30
<PAGE> 31
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------
1996 1997 1998
------------ ------------ ------------
<S> <C> <C> <C>
Revenues
Oil and gas sales......................... $ 68,054 $ 130,017 $ 135,593
Transportation, processing and marketing.. 3,901 7,806 6,711
IPF income................................ - - 4,370
Interest and other........................ 3,386 7,594 2,255
------------ ------------ ------------
75,341 145,417 148,929
------------ ------------ ------------
Expenses
Direct operating.......................... 20,676 31,481 39,001
IPF expense............................... - - 7,996
Exploration............................... 1,460 2,527 11,265
General and administrative................ 3,966 5,290 9,215
Interest.................................. 7,487 27,175 40,642
Depletion, depreciation and amortization.. 22,303 55,407 60,153
Provision for impairment.................. - 58,700 207,128
Business restructuring costs (Note 13).... - - 3,147
------------ ------------ ------------
55,892 180,580 378,547
------------ ------------ ------------
Income (loss) before taxes................... 19,449 (35,163) (229,618)
Income taxes
Current................................... 729 684 278
Deferred.................................. 6,105 (12,515) (54,746)
------------ ------------ ------------
6,834 (11,831) (54,468)
------------ ------------ ------------
Net income (loss)............................ $ 12,615 $ (23,332) $(175,150)
============ ============ ============
Comprehensive income (loss) (Note 2)......... $ 12,729 $ (24,524) $(175,260)
============ ============ ============
Earnings (loss) per common share (Note 14)...
Basic ................................... $ 0.71 $ (1.31) $ (6.82)
============ ============ ============
Dilutive................................. $ 0.69 $ (1.31) $ (6.82)
============ ============ ============
</TABLE>
SEE ACCOMPANYING NOTES.
31
<PAGE> 32
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
Preferred Stock Common Stock
------------------------------ ------------------------------ Capital in Retained
Par Par Excess of Earnings
Shares Value Shares Value Par Value (Deficit)
-------------- -------------- --------------- -------------- --------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995 1,350 $ 1,350 13,323 $ 133 $ 101,773 $ (4,013)
Preferred dividends......... - - - - - (2,454)
Common dividends at $.06 per (857)
share................... - - - - -
Common issued............... - - 887 9 8,687 -
Common repurchased.......... - - (36) - (406) -
Conversion of 7 1/2 preferred (200) (200) 577 6 194 -
Net income.................. - - - - - 12,615
-------------- -------------- --------------- -------------- --------------- ---------------
Balance, December 31, 1996 1,150 1,150 14,751 148 110,248 5,291
Preferred dividends......... - - - - - (2,334)
Common dividends at $.10 per
share................... - - - - - (2,037)
Common issued............... - - 6,307 63 107,293 -
Common repurchased.......... - - - - (107) -
Compensation in connection
with stock options...... - - - - 197 -
Net loss.................... - - - - - (23,332)
-------------- -------------- --------------- -------------- --------------- ---------------
Balance, December 31, 1997 1,150 1,150 21,058 211 217,631 (22,412)
Preferred dividends......... - - - - - (2,334)
Common dividends at $.12 per
share................... - - - - - (3,500)
Common issued............... - - 15,276 152 120,188 -
Common repurchased.......... - - (401) (4) (3,002) -
Net loss.................... - - - - - (175,150)
-------------- -------------- --------------- -------------- --------------- ---------------
Balance, December 31, 1998 1,150 $ 1,150 35,933 $ 359 $ 334,817 $ (203,396)
============== ============== =============== ============== =============== ===============
</TABLE>
SEE ACCOMPANYING NOTES.
32
<PAGE> 33
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1996 1997 1998
--------- --------- ---------
<S> <C> <C> <C>
Cash flows from operations:
Net income (loss) ............................................. $ 12,615 $ (23,332) $(175,150)
Adjustments to reconcile net income (loss) to net cash provided
by operations:
Depletion, depreciation and amortization .................... 22,303 55,407 60,153
Provision for impairment .................................... - 58,700 207,128
Valuation reserve of IPF receivables ........................ - - 5,918
Amortization of deferred offering costs ..................... - 999 1,293
Deferred income taxes ....................................... 6,105 (12,541) (54,746)
Changes in working capital net of effects of acquired
businesses:
Accounts receivable .................................... (494) (11,079) 2,842
Marketable securities .................................. (5,264) (7,964) (253)
Inventory and other .................................... 137 (1,981) 6,996
Accounts payable ....................................... 5,385 17,825 (4,274)
Accrued liabilities .................................... 781 9,186 (3,068)
Gain on sale of assets and other ............................ (3,123) (8,154) (1,817)
--------- --------- ---------
Net cash provided by operations ................................. 38,445 77,066 45,022
Cash flows from investing:
Acquisition of businesses, net of cash ........................ (13,950) - (41,170)
Oil and gas properties ........................................ (59,137) (492,259) (135,399)
Additions to property and equipment ........................... (1,250) (64,945) (3,732)
IPF investments of capital .................................... - - (12,649)
IPF repayments of capital ..................................... - - 3,556
Proceeds on sale of assets .................................... 4,671 56,070 17,081
--------- --------- ---------
Net cash used in investing ...................................... (69,666) (501,134) (172,313)
Cash flows from financing:
Proceeds from indebtedness .................................... 85,201 246,025 135,788
Repayments of indebtedness .................................... (53,268) (26) (413)
Preferred stock dividends ..................................... (2,454) (2,334) (2,334)
Common stock dividends ........................................ (857) (2,037) (3,500)
Proceeds from trust preferred securities issuance, net ........ - 115,999 -
Proceeds from common stock issuance, net ...................... 8,315 67,648 1,985
Repurchase of common stock .................................... (138) (107) (3,006)
--------- --------- ---------
Net cash provided by financing .................................. 36,799 425,168 128,520
--------- --------- ---------
Change in cash .................................................. 5,578 1,100 1,229
Cash and equivalents at beginning of period ..................... 3,047 8,625 9,725
--------- --------- ---------
Cash and equivalents at end of period ........................... $ 8,625 $ 9,725 $ 10,954
========= ========= =========
Supplemental disclosures of non-cash investing and
financing activities:
Purchase of property and equipment financed with
common stock ............................................. $ - $ 39,537 $ 116,469
Common stock issued in connection with benefit plans ....... 381 398 1,887
</TABLE>
SEE ACCOMPANYING NOTES.
33
<PAGE> 34
RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
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: Southwest, Gulf Coast and Appalachia.
In addition, through its IPF subsidiary, the Company provides financing to
smaller independent oil and gas 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. At December 31,
1998, proved reserves totaled 796 Bcfe, having a pre-tax present value at
constant prices on that date of $555 million and a reserve life index in excess
of 13 years.
In August 1998, the stockholders of the Company approved the
acquisition via merger (the "Merger") of Domain Energy Corporation ("Domain").
Pursuant to the Merger, stockholders of Domain received approximately 13.6
million shares of the Company's Common Stock. The Company also purchased 3.8
million Domain shares for $50.5 million in cash. As a result of the Merger,
Domain became a wholly-owned subsidiary of Lomak. Simultaneously, Lomak
stockholders approved changing the company's name 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.
REVENUE RECOGNITION
The Company recognizes revenues from the sale of its respective
products in the period delivered. Revenue for services are recognized in the
period the services are provided.
MARKETABLE SECURITIES
The Company has adopted Statement of Financial Accounting Standards
("SFAS") No. 115, "Accounting for Certain Investments in Debt and Equity
Securities." Under Statement No. 115, debt and marketable equity securities are
required to be classified in one of three categories: trading,
available-for-sale, or held to maturity. The Company's equity securities qualify
under the provisions of Statement No. 115 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 comprehensive
income. 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. At December 31, 1998
certain securities classified as available-for-sale were written down by $10.3
million to their estimated realizable value, because in the opinion of
management, the decline in market value was considered to be other than
temporary. Realized gains and losses are determined on the specific
identification method and are reflected in income.
34
<PAGE> 35
INDEPENDENT PRODUCER FINANCE ("IPF")
Through IPF, Range acquires dollar denominated term overriding royalty
interests in oil and gas properties owned by independent 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 or interest is paid. Only the
interest portion of payments received from a producer is recognized as IPF
income on the statement of income. The remaining cash receipts are recorded as a
reduction in receivables on the balance sheet and as a return of capital on the
statement of cash flows. Periodically, the Company performs a review for
possible uncollectible accounts receivable and provides for unrecoverable
amounts in its allowance for uncollectible receivable. At December 31, 1998 the
Company's allowance for uncollectible receivables totaled $14 million. During
1998, IPF expenses were comprised of $.5 of general and administrative expenses,
$1.6 million of interest expense and a $5.9 million valuation allowance.
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for oil
and gas properties. Exploratory costs which result in the discovery of reserves
and the cost of development wells are capitalized. 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 $.73, $1.03 and $.89 in 1996, 1997 and 1998, respectively. Approximately
$22.8 million, $111.2 million and $75.9 million of oil and gas properties were
not subject to amortization as of December 31, 1996, 1997 and 1998,
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 during 1997 and 1998, the Company recorded provision for
impairment of $58.7 million and $196.8 million respectively, 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 primarily due to declines in oil and gas prices. Fair
value was based on estimated future cash flows to be generated by the oil and
gas properties, discounted at the hurdle rate used by the Company in assessing
investments in comparable assets. Impairment is recognized only if the carrying
amount of a property is greater than its expected undiscounted future cash
flows. The amount of the impairment was based on an estimate of fair value.
TRANSPORTATION, PROCESSING AND FIELD ASSETS
The Company owns and operates approximately 3,000 miles of gas
gathering systems and a gas processing plant in proximity to its principal gas
properties. Depreciation is calculated on the straight-line method based on
estimated useful lives ranging from four to twenty years.
The Company receives fees for providing field related services. These
fees are recognized as earned. Depreciation is calculated on the straight-line
method based on estimated useful lives ranging from one to five years, except
buildings which are being depreciated over ten to twenty-five year periods.
SECURITY ISSUANCE COSTS
Expenses associated with the issuance of the 6% Convertible
Subordinated Debentures due 2007, the 8.75% Senior Subordinated Notes due 2007
and the 5 3/4% Trust Convertible Preferred Securities are included in Other
Assets on the accompanying balance sheets and are being amortized on the
interest method over the term of the securities.
35
<PAGE> 36
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 year end 1997 and 1998
were not material.
COMPREHENSIVE INCOME
Effective January 1, 1998 the Company adopted SFAS No. 130 "Reporting
Comprehensive Income" which requires disclosure of comprehensive income and its
components. Comprehensive income is defined as changes in stockholders' equity
from nonowner sources and, for the Company, includes net income and changes in
the fair value of marketable securities. The following is a calculation of the
Company's comprehensive income for the years ended December 31, 1996, 1997 and
1998.
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------
1996 1997 1998
--------- --------- ---------
<S> <C> <C> <C>
Net income (loss) ...................... $ 12,615 $ (23,332) $(175,150)
Add: Change in unrealized gain/(loss)
Gross ............................ 568 (322) (78)
Tax effect ....................... (199) 109 19
Less: Realized gain/(loss)
Gross ............................ (393) (1,473) (66)
Tax effect ....................... 138 494 15
--------- --------- ---------
Comprehensive income (loss) ............ $ 12,729 $ (24,524) $(175,260)
========= ========= =========
</TABLE>
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
NATURE OF BUSINESS
The Company operates in an environment with many financial and
operating risks, including, but not limited to, the ability to acquire
additional economically recoverable oil and gas reserves, the inherent risks of
the search for, development of and production of oil and gas, the ability to
sell oil and gas at prices which will provide attractive rates of return, and
the highly competitive nature of the industry and worldwide economic conditions.
The Company's ability to expand its reserve base and diversify its operations is
also dependent upon obtaining the necessary capital through operating cash flow,
borrowings or the issuance of additional equity.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative
Instruments and Hedging Activities, which is effective for fiscal years
beginning after June 15, 1999.
SFAS No. 133 establishes accounting and reporting standards for
derivative instrument, 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
36
<PAGE> 37
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 the first quarter of the year ended December 31, 2000 and is
currently evaluating the effects of this pronouncement.
RECLASSIFICATIONS
Certain reclassifications have been made to prior periods presentation
to conform with current period classifications.
(3) ACQUISITIONS
All acquisitions have been accounted for as purchases. The purchase
prices were allocated to the assets acquired based on the estimated fair value
of such assets and liabilities at the respective acquisition dates. The
acquisitions were funded by working capital, advances under a revolving credit
facility and the issuance of debt and equity securities.
In the first quarter of 1997, oil and gas properties located in West
Texas, South Texas and the Gulf of Mexico (the "Cometra Properties") were
acquired for $385 million. The Cometra Properties are located primarily in the
Company's core operating areas and include producing oil and gas properties,
leasehold acreage, gas pipelines, a 25,000 Mcf/d gas processing plant and an
above-market gas contract with a utility. The utility filed an action concerning
the above-market gas contract which is discussed in Note 8.
In September 1997, properties in Appalachia (the "Meadville
Properties") were acquired for a purchase price of $92.5 million. The Meadville
Properties are located in certain of the Company's core operating areas and
included producing oil and gas properties, leasehold acreage and gas pipelines.
In December 1997, the Company sold a net profits interest in the properties for
$36.3 million.
In December 1997, certain oil properties located in the Fuhrman-Mascho
field in West Texas (the "Fuhrman-Mascho Properties") were acquired for a
purchase price of $40 million. The Fuhrman-Mascho Properties included producing
oil and gas properties and leasehold acreage.
In March 1998, oil and gas properties in the Powell Ranch Field in West
Texas (the "Powell Ranch Properties") were acquired for a purchase price of $60
million, comprised of $54.6 million in cash and $5.4 million of Common Stock.
As described in Note 1, the Company completed the Merger for a purchase
price of $161.6 million, comprised of $50.5 million in cash and $111.1 million
of Common Stock. Domain's principal assets included oil and gas operations
primarily onshore in the Gulf Coast and in the Gulf of Mexico, as well as, IPF.
In addition to the above mentioned acquisitions, the Company purchased
various other properties for consideration of $26.1 million and $2.7 million
during the years ended December 31, 1997 and 1998, respectively.
UNAUDITED PRO FORMA FINANCIAL INFORMATION
The following table presents unaudited pro forma operating results as
if certain transactions had occurred at the beginning of each period presented.
In addition to the Merger, the pro forma operating results include the following
transactions: (i) the sale of approximately 4 million shares of Common Stock
and the application of the net proceeds therefrom, (ii) the sale of $125
million of 8.75% Senior Subordinated Notes and the application of the net
proceeds therefrom, (iii) the sale of $120 million of 5 3/4% Trust Convertible
Preferred Securities and the application of the net proceeds therefrom,
37
<PAGE> 38
(iv) the purchase of the Meadville Properties, (v) the purchase of the Powell
Ranch Properties; and the following Domain transactions: (i) the disposition of
its interest in certain natural gas properties located in Michigan, (ii) the
sale of approximately 6.3 million shares of its common stock and the
application of the net proceeds therefrom, and (iii), the purchase of certain
net profits overriding royalty interests owned by three institutional
investors. All acquisitions were accounted for as purchase transactions.
<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------
1997 1998
----------------- ----------------
(in thousands except per share data)
<S> <C> <C>
Revenues....................... $ 217,690 $ 188,721
Net income..................... (25,290) (177,878)
Earnings per share............. (.90) (5.11)
Earnings per share - dilutive.. (.90) (5.11)
Total assets................... 979,331 921,612
Stockholders' equity........... 281,134 133,222
</TABLE>
The pro forma operating results have been prepared for comparative
purposes only. They do not purport to present actual operating results that
would have been achieved had the acquisitions and financings been made at the
beginning of each period presented or to necessarily be indicative of future
results of operations.
(4) IPF RECEIVABLES
At December 31, 1998, IPF had net receivables of $77.2 million. The
receivables result from the Company's purchase of production payments in the
form of term overriding royalty interests in exchange for an agreed upon share
of revenues from identified properties until the amount invested and a specified
rate of return on investment is paid in full. IPF's overriding royalty interest
constitutes a property interest that serves as security for the receivables. The
Company has estimated that $7.1 million of receivables at December 31, 1998 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 million.
(5) ASSETS HELD FOR SALE
Assets held for sale primarily consists of oil and gas properties
located in south Texas and in the Gulf of Mexico. The Company has entered into
agreements with an independent firm to assist it in selling these assets. The
assets are recorded at the lower of cost or estimated market value of the
properties as assets held for sale in the current asset section of the
Consolidated Balance Sheet as of December 31, 1998. These sales are expected to
be completed during 1999.
38
<PAGE> 39
(6) INDEBTEDNESS
The Company had the following debt outstanding as of the dates shown.
Interest rates at December 31, 1998 are shown parenthetically (in thousands):
<TABLE>
<CAPTION>
December 31,
----------------------
1997 1998
-------- --------
<S> <C> <C>
Credit Facility (6.4%) ......................... $186,700 $365,175
Other (6.4%) ................................... 425 1,887
-------- --------
187,125 367,062
Less amounts due within one year ............... 413 55,187
-------- --------
Senior debt, net ............................... $186,712 $311,875
======== ========
Non-recourse debt of IPF subsidiary (7.8%) ..... $ - $ 60,100
-------- --------
8.75% Senior Subordinated Notes due 2007 ...... $125,000 $125,000
6% Convertible Subordinated Debentures due 2007 55,000 55,000
-------- --------
Subordinated debt .............................. $180,000 $180,000
======== ========
</TABLE>
The Company maintains a $400 million revolving bank facility (the
"Credit Facility"). The Credit Facility provides for a borrowing base, which is
subject to semi-annual redeterminations. At December 31, 1998, the borrowing
base on the facility was $385 million of which $19.8 million was available to be
drawn. Interest is payable quarterly and the loan matures in February 2003. A
commitment fee is paid quarterly on the undrawn balance at a rate of .25% to
.375% depending upon the percentage of the borrowing base not drawn. It is the
Company's policy to extend the term period of the credit facility annually.
Until amounts under the Credit Facility are reduced to $300 million or the
redetermined borrowing base, the interest rate will be LIBOR plus 1.75% and will
increase to LIBOR plus 2.0% on May 1, 1999. When outstanding amounts are reduced
to levels at or below $300 million or the redetermined borrowing base, the
interest rate on the Credit Facility will return to interest at prime rate or
LIBOR plus .625% to 1.125% depending on the percentage of borrowing base drawn.
If amounts outstanding under the Credit Facility exceed the higher of the
redetermined borrowing base or $300 million on June 30, 1999, then the Company
will have 10 days to repay any excess. At December 31, 1998, the Company
classified $55.2 million of borrowings under the Credit Facility as current to
reflect an estimate of the amounts outstanding at December 31, 1998 that will be
repaid during 1999. The weighted average interest rates on these borrowings were
7.3% and 6.7% for the years ended December 31, 1997 and 1998, respectively.
IPF has a $150 million revolving credit facility (the "IPF Facility")
through which it finances its activities. The IPF Facility matures June 1, 2000
at which time all amounts owed thereunder are due and payable. The IPF Facility
is secured by substantially all of IPF's assets and is non-recourse to the
Company. The borrowing base under the IPF Facility is subject to
redeterminations, which occur routinely during the year. On March 10, 1999, the
borrowing base on the IPF Facility was $60.1 million, which did not exceed the
amounts outstanding on that date. The Company is currently in the process of
completing a borrowing base redetermination. Upon completion of the
redetermination the Company believes the borrowing base amount will decrease
slightly and that the outstanding obligations at that time will not exceed the
borrowing base. 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 1998 amounted to $1.5 million and is
included in IPF expenses on the statement of income. 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 7.8% on December 31,
1998.
39
<PAGE> 40
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) of the Company. The 8.75%
Notes are guaranteed on a senior subordinated basis by all of the subsidiaries
of the Company and each guarantor is a wholly owned subsidiary of the Company.
The guarantees are full, unconditional and joint and several. Separate financial
statements of each guarantor are not presented because they are included in the
consolidated financial statements of the Company and management believes that
their disclosure provides no additional benefits.
The 6% Convertible Subordinated Debentures Due 2007 (the "Debentures")
are convertible into shares of the Company's 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. The Debentures will mature in 2007 and are
not redeemable prior to February 1, 2000. The Debentures are unsecured general
obligations of the Company subordinated to all senior indebtedness (as defined)
of the Company.
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 December 31, 1998. Interest paid
during the years ended December 31, 1996, 1997 and 1998 totaled $7.5 million,
$18.2 million and $39.6 million, respectively.
Maturities of senior indebtedness and the IPF Facility as of December
31, 1998 were as follows (in thousands):
<TABLE>
<S> <C>
1999............................. $ 55,187
2000............................. 60,100
2001............................. -
2002............................. -
2003............................. 311,875
Remainder........................ -
----------
$427,162
==========
</TABLE>
(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 the Credit
and IPF Facilities (collectively "the Bank Facilities") approximate their fair
value as they bear interest at rates indexed to LIBOR. In connection with the
Merger, the IPF receivables were adjusted to what the Company estimates to have
been their fair values at that time. The Company's receivables are concentrated
in the oil and gas industry. The Company does not view such a concentration as
an unusual credit risk. Excluding IPF's valuation allowances, the Company had
recorded an allowance for doubtful accounts of $539,000 and $782,000 at December
31, 1997 and 1998, 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
40
<PAGE> 41
through the use of interest rate swap agreements. Gains and losses on interest
rate swap agreements are included as an adjustment to interest expense.
The following table sets forth the book value and estimated fair values
of the Company's financial instruments:
<TABLE>
<CAPTION>
December 31, December 31,
1997 1998
------------------------------ ------------------------------
(In thousands)
Book Fair Book Fair
Value Value Value Value
------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Cash and equivalents................ $ 9,725 $ 9,725 $ 10,954 $ 10,954
Marketable securities............... 5,407 5,777 2,966 3,258
Long-term debt...................... (367,125) (367,125) (607,162) (607,162)
Commodity swaps..................... - 1,071 - 45
Interest rate swaps................. - 73 - (361)
</TABLE>
At December 31, 1998, the Company had open contracts for gas price
swaps of 6.4 Bcf. The swap contracts are designed to set average prices ranging
from $1.90 to $2.64 per Mcf. While these transactions have no carrying value,
their fair value, represented by the estimated amount that would be required to
terminate the contracts, was a net gain of approximately $44,500 at December 31,
1998. These contracts expire monthly through October 1999. 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
NYMEX. The resulting transaction gains and losses are determined monthly and are
included in oil and gas revenues in the period the hedged production or
inventory is sold. Net gains or (losses) relating to these derivatives for the
years ended December 31, 1996, 1997 and 1998 approximated $(.7) million, $(.9)
million and $3.1 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 interest 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 December 31, 1998,
the Company had $100 million of borrowings subject to five interest rate swap
agreements at rates of 5.71%, 5.59%, 5.35%, 4.82% and 5.64% through September
1999, October 1999, January 2000, September 2000 and October 2000 respectively.
The interest rate swaps may be extended at the counterparties' option for two
years. The agreements require that the Company pay the counterparty interest at
the above fixed swap rates and requires the counterparty to pay the Company
interest at the 30-day LIBOR rate. The closing 30-day LIBOR rate on December 31,
1998 was 5.06%. The fair value of the interest rate swap agreements at December
31, 1998, is based upon current quotes for equivalent agreements. As discussed
in Note 6, the Company's Bank Facilities are based on LIBOR plus Applicable
Margin (as defined).
These hedging activities are conducted with major financial or
commodities trading institutions which management believes entail acceptable
levels of market and credit risks. At times such risks may be concentrated with
certain counterparties or groups of counterparties. The credit worthiness of
counterparties is subject to continuing review and full performance is
anticipated.
(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, although an adverse outcome could have a material
effect on the results of operations for a given period.
41
<PAGE> 42
In July 1997, a gas utility filed an action in the state district
court. In the lawsuit, the gas utility asserted a breach of contract claim
arising out of a gas purchase contract. Under the gas utility's interpretation
of the contract it sought, as damages, the reimbursement of the difference
between the above-market contract price it paid and market price on a portion of
the gas it has taken beginning in July 1997. Range counterclaimed seeking
damages for breach of contract and repudiation of the contract. In May 1998, the
court granted a partial summary judgment on the contract interpretation issue in
favor of the gas utility. In October 1998, the gas utility dropped its damages
claim and the state district court signed a final judgment in this case. Range
has appealed the final judgment.
In May 1998, a Domain stockholder filed an action in the Delaware Court
of Chancery, alleging that the terms of the Merger were unfair to a purported
class of Domain stockholders and that the defendants (except Range) violated
their legal duties to the class in connection with the Merger. Range is alleged
to have aided and abetted the breaches of fiduciary duty allegedly committed by
the other defendants. The action sought an injunction enjoining the Merger as
well as a claim for money damages. On September 3, 1998, the parties executed a
Memorandum of Understanding (the "MOU"), which represents a settlement in
principle of the litigation. Under the terms of the MOU, appraisal rights
(subject to certain conditions) were offered to all holders of Domain common
stock (excluding the defendants and their affiliates). Domain also agreed to pay
any court-awarded attorneys' fees and expenses of the plaintiffs' counsel in an
amount not to exceed $290,000. The settlement in principle is subject to court
approval and certain other conditions that have not been satisfied.
The Company leases certain office space and equipment under cancelable
and non-cancelable leases, most of which expire within 10 years and may be
renewed by the Company. Rent expense under such arrangements totaled $406,000,
$628,000 and $595,000 in 1996, 1997 and 1998, respectively. Future minimum
rental commitments under non-cancelable leases are as follows (in thousands):
<TABLE>
<S> <C> <C>
1999...................................... $ 1,000
2000...................................... 899
2001...................................... 778
2002...................................... 569
2003...................................... 195
2004 and thereafter....................... 195
------------
$ 3,636
============
</TABLE>
(9) EQUITY SECURITIES AND CONVERTIBLE PREFERRED SECURITIES
On October 16, 1997, the Company, through a newly-formed affiliate
Lomak Financing Trust (the "Trust"), completed the issuance of $120 million of
5 3/4% trust convertible preferred securities (the "Convertible Preferred
Securities"). The Trust issued 2,400,000 shares of the Convertible Preferred
Securities at $50 per share. Each Convertible Preferred Security is convertible
at the holder's option into 2.1277 shares of Common Stock, representing a
conversion price of $23.50 per share.
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 Range redeems any Junior Debentures prior to the scheduled maturity
date, the Trust must redeem Convertible Preferred Securities having an aggregate
liquidation amount equal to the aggregate principal amount of the Junior
Debentures so redeemed.
42
<PAGE> 43
Range has guaranteed the payments of distributions and other payments
on the Convertible Preferred Securities only if and to the extent that the Trust
has funds available. Such guarantee, when taken together with Range's
obligations under the Junior Debentures and related indenture and declaration of
trust, provide a full and unconditional guarantee of amounts due on the
Convertible Preferred Securities.
Range owns all the common securities of the Trust. As such, the
accounts of the Trust have been included in Range's consolidated financial
statements after appropriate eliminations of intercompany balances. The
distributions on the Convertible Preferred Securities have been recorded as a
charge to interest expense on Range's consolidated statements of income, and
such distributions are deductible by Range for income tax purposes.
In March 1997, the Company sold 4 million shares of common stock in a
public offering for $69 million. Warrants to acquire 20,000 shares of common
stock at a price of $12.88 per share were exercised in May 1997. At December 31,
1998 the Company had no outstanding warrants.
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 any time on or after November 1, 1998, at redemption prices beginning at
105%. At the option of the Company, the $2.03 Preferred Stock is exchangeable
into 8-1/8% Convertible Subordinated Notes due 2005. The notes would be subject
to the same redemption and conversion terms as the $2.03 Preferred Stock.
(10) STOCK OPTION AND PURCHASE PLAN
The Company has four stock option plans as well as a stock purchase
plan. Two of the stock option plans were adopted as a result of the Merger.
Information with respect to these stock option plans is summarized as follows:
<TABLE>
<CAPTION>
Plans adopted via the Merger
-------------------------------
Option Director's Option Director's
Plan Plan Plan Plan Total
--------- ------- ------- ------ ---------
<S> <C> <C> <C> <C> <C>
Outstanding at December 31, 1997: 1,507,692 108,000 - - 1,615,692
Granted.................... 828,395 32,000 - - 860,395
Adopted in Merger.......... - - 1,143,665 19,340 1,163,005
Exercised.................. (54,610) - (49,155) - (103,765)
Expired/Cancelled.......... (238,720) - (155,534) - (394,254)
--------- ------- --------- ------ ---------
Outstanding at December 31, 1998: 2,042,757 140,000 938,976 19,340 3,141,073
========= ======= ========= ====== =========
</TABLE>
Range maintains a stock option plan (the "Option Plan") which
authorizes the grant of options on up to 3.0 million shares of Common Stock.
However, no new options may be granted which would result in there being
outstanding aggregate options exceeding 10% of common shares outstanding plus
those shares issuable under convertible securities. Under the Option Plan,
incentive and non-qualified options may be issued to officers, key employees and
consultants. The Option Plan is administered by the Compensation Committee of
the Board. All options issued under the Option Plan before September 1998 vest
30% after one year, 60% after two years and 100% after three years and options
issued after that date vest 25% per year beginning one year after the grant
date. During the year ended December 31, 1998, options covering 54,610 shares
were exercised at prices ranging from $5.12 to $10.50 per share. At December 31,
1998, there were 903,442 options exercisable at prices ranging from $3.375 to
$17.75 per share.
43
<PAGE> 44
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 December 31, 1998, there were outstanding 72,800
options which were exercisable at prices ranging from $7.75 to $16.88 per share.
In connection with the Merger, Range adopted the Second Amended and
Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain Energy
Corporation and Affiliates (the "Domain 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 year ended December 31, 1998 options
covering 49,155 shares were exercised at prices ranging from $0.01 to $3.46 per
share. At December 31, 1998, 469,014 options were currently exercisable under
the Domain Option Plan at $3.46 to $11.70 per share. The remaining 469,962
options are currently exercisable at an exercise price of $0.01 per share. At
December 31, 1998, options totaling 19,340 shares were outstanding and
exercisable under the Domain Director Plan at $11.77 per share.
In June 1997, the stockholders approved the 1997 Stock Purchase Plan
(the "1997 Plan") which authorizes the sale of up to 500,000 shares of common
stock to officers, directors, key employees and consultants. Under the Plan, the
right to purchase shares at prices ranging from 50% to 85% of market value may
be granted. The Company previously had stock purchase plans which covered
833,333 shares. The previous stock purchase plans have been terminated. The
plans are administered by the Compensation Committee of the Board. During the
year ended December 31, 1998, officers, key employees and outside directors
purchased 306,141 registered common shares from the Company for total
consideration of $1.6 million. From inception through December 31, 1998, a total
of 759,141 unregistered shares had been sold through stock purchase plans, for a
total consideration of approximately $5.3 million.
The Company has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock Based
Compensation." Accordingly, no compensation cost has been recognized for the
stock option plans. Had compensation cost for the Corporation's stock option
plans been determined based on the fair value at the grant date for awards in
1996, 1997 and 1998 consistent with the provisions of SFAS No. 123, the
Company's net earnings and earnings per share would have been reduced to the pro
forma amounts indicated below:
<TABLE>
<CAPTION>
1996 1997 1998
---------- ---------- -----------
(in thousands, except
per share data)
<S> <C> <C> <C>
Net earnings (loss)--as reported .............. $ 12,615 $ (23,332) $ (175,150)
Earnings (loss) per share--as reported ........ $ 0.71 $ (1.31) $ (6.82)
Earnings (loss) per share dilutive--as reported $ 0.69 $ (1.31) $ (6.82)
Net earnings (loss)--pro forma ................ $ 12,262 $ (24,563) $ (176,083)
Earnings (loss) per share--pro forma .......... $ 0.68 $ (1.37) $ (6.86)
Earnings (loss) per share dilutive--pro forma . $ 0.66 $ (1.37) $ (6.86)
</TABLE>
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option pricing model with the following weighted-average
assumptions used for 1996, 1997 and 1998, respectively: dividend yields of $.06,
$.10 and $.12 per share; expected volatility factors of .41, .46 and .79
risk-free interest rates of 6.0%; 6.5% and 4.75%; and a average expected life of
3 to 5 years.
(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 1996, 1997 and 1998 were $548,000, $701,000 and $678,000
respectively. The 1997 and 1998 contributions were made with Range common stock,
which was valued at fair market value.
44
<PAGE> 45
(12) INCOME TAXES
Federal income tax provision (benefit) was $6.8 million, $(11.8)
million and $(54.7) million for the years 1996, 1997 and 1998, respectively. The
current portion of the income tax provision represents state income tax
currently payable. A reconciliation between the statutory federal income tax
rate and the Company's effective federal income tax rate is as follows:
<TABLE>
<CAPTION>
1996 1997 1998
----------- ----------- -----------
<S> <C> <C> <C>
Statutory tax rate..... 34% (34)% (34)%
Valuation allowance.... - - 10
Other ................. 1 - -
----------- ----------- -----------
Effective tax rate..... 35% (34)% (24)%
=========== =========== ===========
Income taxes paid...... $ 590,000 $ 1,216,000 $ 36,000
=========== =========== ===========
</TABLE>
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.
Significant components of the Company's deferred tax liabilities and
assets are as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
-----------------------
1997 1998
-------- --------
<S> <C> <C>
Deferred tax liabilities:
Depreciation ............................... $ 38,305 $ 30,232
======== ========
Deferred tax assets:
Net operating loss carryforward ............ $ 9,268 $ 51,810
Percentage depletion carryforward .......... 2,753 2,753
AMT credits and other ...................... 685 685
-------- --------
Total deferred tax assets .................. 12,706 55,248
Valuation allowance for deferred tax assets (40) (25,016)
-------- --------
Net deferred tax assets ....................... $ 12,666 $ 30,232
======== ========
Net deferred tax liabilities .................. $ 25,639 $ -
======== ========
</TABLE>
Utilization of the deferred tax asset of $55.2 million is dependent on
future taxable profits being in excess of profits arising from existing taxable
temporary differences. The Company has established a $25 million valuation
allowance and has written down to zero its net deferred tax assets at December
31, 1998. Management believes sufficient uncertainty exists regarding its net
deferred tax assets that a valuation allowance is required. Upon future
realization of the deferred tax asset, $25 million of the valuation allowance
will reduce the Company's future income tax expense.
45
<PAGE> 46
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 $25.9 million respectively, were recorded. In
1997 the Company acquired Arrow Operating Company accounted for as a tax free
business combination accounted for as a purchase. A net deferred tax liability
of $12.4 million was recorded in the transaction. 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.
As a result of the Company's issuance of equity and convertible debt
securities, it experienced a change in control during 1988 as defined by Section
382 of the Internal Revenue Code. The change in control and the Merger have
placed limitations to the utilization of net operating loss carryovers. At
December 31, 1998, the Company had available for federal income tax reporting
purposes net operating loss carryovers of approximately $131 million which 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 which 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
$911,000. The statutory depletion carryover and alternative minimum tax credit
carryover are not subject to limitation or expiration.
(13) BUSINESS RESTRUCTURING COSTS
In the fourth quarter of 1998, the Company initiated a restructuring
plan to reduce costs and improve operating efficiencies. In connection with the
restructuring plan, 54 employees have been terminated. These employees were
associated with operations that have been consolidated or eliminated in response
to the depressed energy price environment. Estimated employee termination costs
of $2.1 million have been accrued in 1998. Of the total number of employees
affected, 42 were terminated in 1998.
In addition to the costs of terminating employees, the principal costs
of the restructuring plan include the writedown of the carrying value of assets
impaired due to the restructuring and lease and contract termination costs.
Estimated charges of $658,000 for lease and contract terminations and $363,000
for asset impairments were recorded during the fourth quarter of 1998.
At December 31, 1998, $2.7 million was accrued in connection with the
restructuring plan.
46
<PAGE> 47
(14) EARNINGS PER COMMON SHARE
The following table sets forth the computation of earnings per common
share and earnings per common share - assuming dilution (in thousands):
<TABLE>
<CAPTION>
1996 1997 1998
------------ ------------- -------------
<S> <C> <C> <C>
Numerator:
Net income (loss)........................... $ 12,615 $ (23,332) $(175,150)
Preferred stock dividends................... (2,454) (2,334) (2,334)
------------ ------------- -------------
Numerator for earnings per common share..... 10,161 (25,666) (177,484)
Effect of dilutive securities:
Preferred stock dividends................. - - -
------------ ------------- -------------
Numerator for earnings per common
Share - assuming dilution................. $ 10,161 $ (25,666) $(177,484)
============ ============= =============
Denominator:
Denominator for earnings per common
Share - weighted average shares........... 14,334 19,641 26,008
Effect of dilutive securities:
Employee stock options.................... 464 - -
Warrants.................................. 14 - -
------------ ------------- -------------
Dilutive potential common shares 478 - -
------------ ------------- -------------
Denominator for diluted earnings per share
Adjusted weighted-average shares and
Assumed conversions....................... 14,812 19,641 26,008
============ ============= =============
Earnings (loss) per common share................ $ .71 $ (1.31) $ (6.82)
============ ============= =============
Earnings (loss) per common
Share - assuming dilution................. $ .69 $ (1.31) $ (6.82)
============ ============= =============
</TABLE>
For additional disclosure regarding the Company's Debentures, the
7 1/2% Preferred Stock and the $2.03 Preferred Stock, see Notes 6, and 9
respectively. The Debentures were outstanding during 1996, 1997 and 1998 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 7 1/2% Preferred Stock was
converted into 576,945 additional shares of common stock during 1996. The
576,945 additional shares were not included in the computation of diluted
earnings per share because the effect was antidilutive. The $2.03 Preferred
Stock was outstanding during 1996, 1997 and 1998 and was convertible into
3,026,316 of additional shares of common stock. The 3,026,316 additional shares
were not included in the computation of diluted earnings per share because the
conversion price was greater than the average market price of common shares and,
therefore, the effect would be antidilutive. There were stock options
outstanding during 1997 which were exercisable, resulting in 642,720 additional
shares under the treasury method of accounting for common stock equivalents.
These were stock options outstanding during 1998 which were exercisable,
resulting in 718,279 additional shares for common stock equivalents. These
additional shares were not included in the 1997 or 1998 computations of diluted
earnings per share because the effect was antidilutive.
47
<PAGE> 48
(15) MAJOR CUSTOMERS
The Company markets its oil and gas production on a competitive basis.
The type of contract under which gas production is sold varies but can generally
be grouped into three categories: (a) life-of-the-well; (b) long-term (1 year or
longer); and (c) short-term contracts which may have a primary term of one year,
but which are cancelable at either party's discretion in 30-120 days.
Approximately 71% of the Company's gas production is currently sold under market
sensitive contracts which do not contain floor price provisions. For the year
ended December 31, 1998, one customer accounted for 14% of the Company's total
oil and gas revenues. Management believes that the loss of any one customer
would not have a material adverse effect on the operations of the Company. Oil
is sold on a basis such that the purchaser can be changed on 30 days notice. The
price received is generally equal to a posted price set by the major purchasers
in the area. The Company sells to oil purchasers on a basis of price and
service.
(16) OIL AND GAS ACTIVITIES
The following summarizes selected information with respect to oil and
gas producing activities:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------
1996 1997 1998
--------- --------- ---------
(in thousands)
<S> <C> <C> <C>
Oil and gas properties:
Subject to depletion ........... $ 259,681 $ 674,067 $ 859,911
Not subject to depletion ....... 22,838 111,156 75,911
--------- --------- ---------
Total ...................... 282,519 785,223 935,822
Accumulated depletion .......... (53,102) (161,416) (273,723)
--------- --------- ---------
Net oil and gas properties.. $ 229,417 $ 623,807 $ 662,099
========= ========= =========
Costs incurred:
Acquisition .................... $ 63,579 $ 448,822 $ 286,974
Development .................... 12,536 56,430 71,793
Exploration .................... 2,025 2,375 9,756
--------- --------- ---------
Total costs incurred ....... $ 78,140 $ 507,627 $ 368,523
========= ========= =========
</TABLE>
(17) UNAUDITED SUPPLEMENTAL RESERVE INFORMATION
The Company's proved oil and gas reserves are located in the United
States. Proved reserves are those quantities of crude oil and natural gas which,
upon analysis of geological and engineering data, can with reasonable certainty
be recovered in the future from known oil and gas reservoirs. Proved developed
reserves are those proved reserves, which can be expected to be recovered from
existing wells with existing equipment and operating methods. Proved undeveloped
oil and gas reserves are proved reserves that are expected to be recovered from
new wells on undrilled acreage.
48
<PAGE> 49
QUANTITIES OF PROVED RESERVES
<TABLE>
<CAPTION>
Crude Oil Natural Gas
--------- -----------
(Bbls) (Mcf)
(in thousands)
<S> <C> <C>
Balance, December 31, 1995 ................ 10,863 232,887
Revisions ............................. 280 (7,545)
Extensions, discoveries and additions . 952 16,696
Purchases ............................. 3,884 86,022
Sales ................................. (236) (11,235)
Production ............................ (1,068) (21,231)
-------- --------
Balance, December 31, 1996 ................ 14,675 295,594
Revisions ............................. (2,603) (70,763)
Extensions, discoveries and additions . 1,664 55,324
Purchases ............................. 18,541 339,447
Sales ................................. (709) (6,775)
Production ............................ (1,794) (38,409)
-------- --------
Balance, December 31, 1997 ................ 29,774 574,418
Revisions ............................. (14,195) (76,728)
Extensions, discoveries and additions . 2,121 57,261
Purchases ............................. 15,332 140,120
Sales ................................. (3,248) (16,561)
Production ............................ (2,655) (45,193)
-------- --------
Balance, December 31, 1998 ................ 27,129 633,317
======== ========
PROVED DEVELOPED RESERVES
December 31, 1996 ......................... 10,703 207,601
======== ========
December 31, 1997 ......................... 14,971 369,786
======== ========
December 31, 1998 ......................... 19,649 436,062
======== ========
</TABLE>
The revisions which occurred during 1998 include 13,126 Mbbl of oil and
49,004 Mmcf of gas which became uneconomic due to lower commodity prices at
December 31, 1998 as compared to December 31, 1997. The commodity prices used to
estimate the December 31, 1998 reserve information were $10.25 per barrel for
oil, $6.61 per barrel for natural gas liquids and $2.34 per Mcf for gas. The
average prices at December 31, 1997 were $16.00 per barrel for oil, $10.27 per
barrel for natural gas liquids and $2.79 per Mcf for gas.
49
<PAGE> 50
The "Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves" (Standardized Measure) is a disclosure
requirement under Statement of Financial Accounting Standards No. 69
"Disclosures about Oil and Gas Producing Activities". The Standardized Measure
does not purport to present the fair market value of proved oil and gas
reserves. This would require consideration of expected future economic and
operating conditions, which are not taken into account in calculating the
Standardized Measure.
Future cash inflows were estimated by applying year end prices to the
estimated future production less estimated future production costs based on year
end costs. Future net cash inflows were discounted using a 10% annual discount
rate to arrive at the Standardized Measure.
STANDARDIZED MEASURE
<TABLE>
<CAPTION>
As of December 31
-----------------------------------------------------------
1996 1997 1998
------------------ ------------------ -------------------
(in thousands)
<S> <C> <C> <C>
Future cash inflows $ 1,393,338 $ 2,037,357 $ 1,744,653
Future costs:
Production.................................... (365,753) (512,657) (513,119)
Development................................... (86,192) (248,553) (211,236)
------------------ ------------------ -------------------
Future net cash flows.............................. 941,393 1,276,147 1,020,298
Income taxes....................................... (271,023) (280,189) (104,500)
------------------ ------------------ -------------------
Total undiscounted future net cash flows........... 670,370 995,958 915,798
10% discount factor................................ (319,481) (485,258) (398,703)
------------------ ------------------ -------------------
Standardized measure............................... $ 350,889 $ 510,700 $ 517,095
================== ================== ===================
</TABLE>
CHANGES IN STANDARDIZED MEASURE
<TABLE>
<CAPTION>
For the year ended December 31
-----------------------------------------------------------
1996 1997 1998
------------------ ------------------ -------------------
(in thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year $ 174,050 $ 350,889 $510,700
Revisions:
Prices........................................ 151,508 (210,429) (138,985)
Quantities.................................... (6,762) (29,409) (112,012)
Estimated future development cost............. (2,971) (37,788) 26,465
Accretion of discount......................... 22,924 49,217 63,233
Income taxes.................................. (86,095) 10,360 88,222
------------------ ------------------ -------------------
Net revisions................................. 78,604 (218,049) (73,007)
Purchases.......................................... 125,871 460,753 134,186
Extensions, discoveries and additions.............. 22,816 55,751 35,169
Production......................................... (43,598) (93,865) (87,668)
Sales.............................................. (6,854) (14,406) (26,197)
Changes in timing and other........................ - (30,373) 23,982
------------------ ------------------ -------------------
Standardized measure, end of year.................. $ 350,889 $ 510,700 $ 517,095
================== ================== ===================
</TABLE>
50
<PAGE> 51
RANGE RESOURCES CORPORATION
INDEX TO EXHIBITS
(Item 14[a 3])
Exhibit No Description
- ---------- -----------
3.1(a) Certificate of Incorporation of Lomak dated March 24, 1980
(incorporated by reference to the Company's Registration
Statement (No. 33-31558)).
3.1(b) Certificate of Amendment of Certificate of Incorporation
dated July 22, 1981 (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
3.1(c) Certificate of Amendment of Certificate of Incorporation
dated September 8, 1982 (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
3.1(d) Certificate of Amendment of Certificate of Incorporation
dated December 28, 1988 (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
3.1(e) Certificate of Amendment of Certificate of Incorporation
dated August 31, 1989 (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
3.1(f) Certificate of Amendment of Certificate of Incorporation
dated May 30, 1991 (incorporated by reference to the
Company's Registration Statement (No. 333-20259)).
3.1(g) Certificate of Amendment of Certificate of Incorporation
dated November 20, 1992 (incorporated by reference to the
Company's Registration Statement (No. 333-20257)).
3.1(h) Certificate of Amendment of Certificate of Incorporation
dated May 24, 1996 (incorporated by reference to the
Company's Registration Statement (No. 333-20257)).
3.1(i) Certificate of Amendment of Certificate of Incorporation
dated October 2, 1996 (incorporated by reference to the
Company's Registration Statement (No. 333-20257)).
3.1(j) Restated Certificate of Incorporation as required by Item
102 of Regulation S-T (incorporated by reference to the
Company's Registration Statement (No. 333-20257)).
3.1(k) Certificate of Amendment of Certificate of Incorporation
dated August 25, 1998 (incorporated by reference to the
Company's Registration Statement (No. 333-62439)).
3.2 By-Laws of the Company (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
4 Specimen certificate of Lomak Petroleum, Inc. (incorporated
by reference to the Company's Registration Statement (No.
333-20257)).
4.4 Certificate of Trust of Lomak Financing Trust (incorporated
by reference to the Company's Registration Statement (No.
333-43823)).
4.5 Amended and Restated Declaration of Trust of Lomak
Financing Trust dated as of October 22, 1997 by The Bank of
New York (Delaware) and the Bank of New York as Trustees
and Lomak Petroleum, Inc. as Sponsor (incorporated by
reference to the Company's Registration Statement (No.
333-43823)).
4.6 Indenture dated as of October 22, 1997, between Lomak
Petroleum, Inc. and The Bank of New York (incorporated by
reference to the Company's Registration Statement (No.
333-43823)).
4.7 First Supplemental Indenture dated as of October 22, 1997,
between Lomak Petroleum, Inc. and The Bank of New York
(incorporated by reference to the Company's Registration
Statement (No. 333-43823)).
51
<PAGE> 52
4.8 Form of 5 3/4% Preferred Convertible Securities (included
in Exhibit 4.5 above).
4.9 Form of 5 3/4% Convertible Junior Subordinated Debentures
(included in Exhibit 4.7 above).
4.10 Convertible Preferred Securities Guarantee Agreement dated
October 22, 1997, between Lomak Petroleum, Inc., as
Guarantor, and The Bank of New York as Preferred Guarantee
Trustee (incorporated by reference to the Company's
Registration Statement (No. 333-43823)).
4.11 Common Securities Guarantee Agreement dated October 22,
1997, between Lomak Petroleum, Inc., as Guarantor, and The
Bank of New York as Common Guarantee Trustee. (incorporated
by reference to the Company's Registration Statement No.
333-43823)).
4.12 Purchase and Sale Agreement between Cometra Energy, L.P.
and Cometra Production Company, L.P., as seller, and Lomak
Petroleum, Inc., as buyer, dated December 31, 1996,
including First Amendment to Purchase and Sale Agreement,
dated January 10, 1997 (incorporated by reference to the
Company's Registration Statement (No. 333-20257)).
4.13 Purchase and Sale Agreement between Rockland, L.P., as
seller, and Lomak Petroleum, Inc., as buyer, dated December
31, 1996 (incorporated by reference on the Company's
Registration Statement (No. 333-20257)).
4.14 Form of Trust Indenture relating to the Senior Subordinated
Notes due 2007 between Lomak Petroleum, Inc., and Fleet
National Bank as trustee (incorporated on the Company's
Registration Statement (No. 333-20257)).
4.15 Purchase and Sale Agreement dated as of September 8, 1997
by and among Cabot Oil & Gas Corporation, Cranberry
Pipeline Corporation, Big Sandy Gas Company, and Lomak
Petroleum, Inc. (incorporated by reference to Form 10-K
dated March 20, 1998).
4.16 Agreement and Plan of Reorganization dated December 5, 1997
between Arrow Operating Company, Kelly W. Hoffman and L .S.
Decker and Lomak Petroleum, Inc. (incorporated by reference
to the Company's Registration Statement (No. 333-43823)).
10.1(a) Incentive and Non-Qualified Stock Option Plan dated March
13, 1989 (incorporated by reference to the Company's
Registration Statement (No. 33-31558)).
10.1(b) Advisory Agreement dated September 29, 1988 between Lomak
and SOCO (incorporated by reference to the Company's
Registration Statement (No. 33-31558)).
10.1(c) 401(k) Plan Document and Trust Agreement effective January
1, 1989 (incorporated by reference to the Company's
Registration Statement (No. 33-31558)).
10.1(d) 1989 Stock Purchase Plan (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
10.1(e) Form of Directors Indemnification Agreement (incorporated
by reference to the Company's Registration Statement (No.
333-47544)).
10.1(f) 1994 Outside Directors Stock Option Plan (incorporated by
reference to the Company's Registration Statement (No.
33-47544)).
10.1(g) 1994 Stock Option Plan (incorporated by reference to the
Company's Registration Statement (No. 33-47544)).
10.1(h) $400,000,000 Credit Agreement Among Lomak Petroleum, Inc.,
as Borrower, and the Several Lenders from Time to Time
parties Hereto, including Bank One, Texas, N.A. as
Administrative Agent, The Chase Manhattan Bank, as
Syndication Agent, and Nationsbank of Texas, N.A., as
Documentation Agent (incorporated by reference to Form 10-K
dated February 7, 1997).
10.1(i) Registration Rights Agreement dated October 22, 1997, by
and among Lomak Petroleum, Inc., Lomak Financing Trust,
Morgan Stanley & Co. Incorporated, Credit Suisse First
Boston, Forum Capital markets L.P. and McDonald Company
Securities, Inc., (incorporated by reference to the
Company's Registration Statement (No. 333-43823)).
10.1(j) Amendment to the Lomak Petroleum, Inc., 1989 Stock Purchase
Plan, as amended (incorporated by reference to the
Company's Registration Statement (No. 333-44821)).
52
<PAGE> 53
10.1(k) 1997 Stock Purchase Plan (incorporated by reference to the
Company's Registration Statement (No. 333-44821)).
10.1(l) 1997 Stock Purchase Plan, as amended (incorporated by
reference to the Company's Registration Statement (No.
333-44821)).
10.1(m)* Fourth Amendment to $400,000,000 Credit Agreement dated
January 27, 1999
10.1(n) Second Amended and Restated 1996 Stock Purchase and Option
Plan for Key Employees of Domain Energy Corporation and
Affiliates (incorporated by reference to the Company's
Registration Statement (No. 333-62439)).
10.1(o) Domain Energy Corporation 1997 Stock Option Plan for
Nonemployee Directors (incorporated by reference to the
Company's Registration Statement (No. 333-62439)).
10.1(p)* Employment Agreement, dated August 25, 1998, between the
Company and Michael V. Ronca.
21* Subsidiaries of the Registrant.
23.1* Consent of Independent Public Accountants.
27* Financial Data Schedule.
- ---------------
* Filed herewith.
53
<PAGE> 1
EXHIBIT 10.1(m)
FOURTH AMENDMENT TO CREDIT AGREEMENT
------------------------------------
This Fourth Amendment to Credit Agreement (this "AMENDMENT") is entered
into effective January 27, 1999, by and among RANGE RESOURCES CORPORATION
(formerly Lomak Petroleum, Inc.), a Delaware corporation ("BORROWER"), BANK ONE,
TEXAS, N.A., as Administrative Agent ("BANK ONE" or "ADMINISTRATIVE AGENT"),
CHASE BANK OF TEXAS, N.A., as Syndication Agent ("CHASE"), NATIONSBANK, N.A., as
Documentation Agent ("NATIONSBANK"), and Lenders (as defined in the Credit
Agreement).
RECITALS:
- ---------
A. Borrower and Lenders entered into a Credit Agreement dated February
14, 1997, as amended by a First Amendment dated September 30, 1997, by a Second
Amendment dated May 1, 1998, and by a Third Amendment dated August 25, 1998 (as
amended, the "CREDIT AGREEMENT").
B. Pursuant to SECTION 4.02 of the Credit Agreement, Lenders have
conducted a Periodic Determination of the Borrowing Base, and Lenders and
Borrower now desire to confirm such Determination in writing.
C. Some of Borrower's Subsidiaries changed their names subsequent to
the name change of Borrower from Lomak Petroleum, Inc. to Range Resources
Corporation, and some of Borrower's Subsidiaries have been merged into other
Subsidiaries.
D. Borrower and Lenders desire to amend the Credit Agreement as
hereinafter set forth in order to, among other things, acknowledge the new
Borrowing Base resulting from the Periodic Determination and acknowledge
Borrower's current Subsidiaries and the new names of the Subsidiaries who have
changed their names.
AGREEMENT:
- ----------
In consideration of the premises, the representations, warranties,
covenants, and agreements contained herein, and other good and valuable
consideration, the receipt and adequacy of which are hereby acknowledged,
Borrower and Lenders agree as follows, effective only upon satisfaction of each
condition precedent set forth in SECTION 4.1 below:
<PAGE> 2
ARTICLE 1 - DEFINITIONS.
- ------------------------
1.1 CREDIT AGREEMENT DEFINITIONS. Capitalized terms used but not
defined in this Amendment have the meanings given such terms in the Credit
Agreement.
ARTICLE 2 - AMENDMENTS.
- -----------------------
2.1 AMENDMENTS TO ARTICLE 1 - DEFINITIONS. (a) The definition of
Applicable Margin appearing in SECTION 1.01 of the Credit Agreement is hereby
amended in its entirety to read as follows:
"APPLICABLE MARGIN" means, on any day:
(a) Subject to the provisions of paragraph (b) below:
(i) through April 30, 1999, Eurodollar Rate plus 175
basis points; and
(ii) from and after April 30, 1999, Eurodollar Rate
plus 200 basis points.
(b) At and after the date of reduction of the Outstanding
Obligations and of a corresponding reduction of the Borrowing Base
(either voluntarily by Borrower or otherwise pursuant to the terms of
this Agreement) to (i) $300,000,000 or (ii) the redetermined Borrowing
Base resulting from any Determination approved by Required Lenders
subsequent to January 27, 1999, the basis points set out below,
determined based upon the type of Loan and the Borrowing Base Usage on
any such day:
BORROWING BASE USAGE
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------
greater than or equal to 50% less than or
less than 50% less than 75% equal to 75%
- -------------------------- ----------------------------- ----------------------------- ------------------------------
<S> <C> <C> <C>
Eurodollar Loans 62.5 basis points 87.5 basis points 112.5 basis
points
ABR Loans 0 basis points 0 basis points 25 basis points
</TABLE>
(b) SECTION 1.01 of the Credit Agreement is hereby amended to add the
definition of Pledge Agreement set out below:
FOURTH AMENDMENT - Page 2
<PAGE> 3
"PLEDGE AGREEMENT" means the Pledge Agreement executed and
delivered by Borrower and its Subsidiaries, as appropriate,
substantially in the form of EXHIBIT D attached to the Fourth Amendment
to Credit Agreement dated January 27, 1999, as such Pledge Agreement
may be amended, modified, or supplemented from time to time, pursuant
which such Person will pledge 100% of the Capital Stock of Borrower's
Subsidiaries to secure the Obligations.
2.2 AMENDMENT TO ARTICLE 4 - BORROWING BASE. SECTION 4.05 of the Credit
Agreement is hereby amended in its entirety to read:
"4.05. INITIAL BORROWING BASE. Subject to the rights of
Borrower to request an earlier Special Determination pursuant to
SECTION 4.03 above and the rights of Lenders to reduce the Borrowing
Base as provided in SECTION 7.03(C) below, the Borrowing Base in effect
under this Agreement for the period from January 27, 1999, until June
30, 1999, shall be $385,000,000. As of June 30, 1999, the Borrowing
Base will be redetermined by the Required Lenders."
2.3 AMENDMENT TO ARTICLE 5 - COLLATERAL. SECTION 5.01 of the Credit
Agreement is hereby amended in its entirety to read:
"5.01. SECURITY. (a) The Obligations shall be secured by first
and prior Liens (subject only to Permitted Encumbrances) on 100% of the
issued and outstanding Capital Stock of Borrower's Subsidiaries. As of
January 27, 1999, Borrower and its Subsidiaries will execute and
deliver (i) a Pledge Agreement and (ii) any financing statements
relating thereto. Provided that no Default or Event of Default has
occurred which is continuing, if on June 30, 1999, the Outstanding
Obligations are equal to or less than the lesser of $300,000,000 or the
Borrowing Base then in effect, Lenders authorize Administrative Agent
to release, and Administrative Agent hereby agrees that it will
release, all Collateral, and execute for the benefit of Borrower and
its Subsidiaries all documents reasonably requested by Borrower to
evidence such release.
(b) On each occasion on which Borrower and its
Subsidiaries may be required to grant Liens on any asset, upon
submission to Borrower by Administrative Agent, Borrower and its
Subsidiaries shall promptly execute and deliver to Administrative
Agent, for the ratable benefit of each Lender, Security Documents in
form and substance acceptable to Administrative Agent granting first
and prior Liens (subject only to Permitted Encumbrances) on the
designated properties. Borrower acknowledges that all Mortgages now or
hereafter executed by Borrower or its Subsidiaries will be recorded
promptly and all other action
FOURTH AMENDMENT - Page 3
<PAGE> 4
necessary to perfect the liens and security interests evidenced by the
Mortgages will be taken. Borrower represents and warrants to Lenders
that all Mortgages (i) are or will be duly authorized, executed, and
delivered by the Person executing them, (ii) constitute the valid,
binding, and enforceable obligations of each Person that executed the
Mortgages in accordance with their terms, and (iii) operate to create
in favor of Administrative Agent, for the ratable benefit of each
Lenders, first priority liens in the interests covered thereby."
2.4 AMENDMENTS TO ARTICLE 7 - REPRESENTATIONS, WARRANTIES AND
COVENANTS. SECTION 7.04 of the Credit Agreement is hereby amended in its
entirety to read:
"7.04. FINANCIAL COVENANTS. So long as this Agreement
remains in force, Borrower and its Consolidated Subsidiaries shall
maintain, on a consolidated basis, the following (all calculated in
accordance with GAAP):
(a) CONSOLIDATED TANGIBLE NET WORTH.
A minimum Consolidated Tangible Net Worth as of any date which is not
less than the sum of (i) $175,000,000, plus (ii) 50% of the net
proceeds to Borrower from the issuance of equity securities on or after
August 25, 1998 (for purposes of this SECTION 7.04(A) only,
Consolidated Tangible Net Worth shall exclude non-cash impairments of
long-lived assets as prescribed under Financial Accounting Standards
Board Statement No. 121);
(b) SENIOR DEBT INTEREST COVERAGE RATIO.
A ratio of EBITDA to Consolidated Interest Expense on Senior Debt for
each period of four immediately preceding consecutive fiscal quarters
of at least 3.0 to 1.0;
(c) TOTAL DEBT INTEREST COVERAGE RATIO.
For the fiscal quarter ended December 31, 1998, through the fiscal
quarter ending December 31, 1999, a ratio of EBITDA to Consolidated
Interest Expense on Total Debt for each period of four immediately
preceding consecutive fiscal quarters of at least 2.0 to 1.0, and for
each fiscal quarter ending after December 31, 1999, a ratio of EBITDA
to Consolidated Interest Expense on Total Debt for each period of four
immediately preceding consecutive fiscal quarters of at least 2.5 to
1.0;
(d) SENIOR DEBT LEVERAGE RATIO. For
the fiscal quarter ended December 31, 1998, through the fiscal quarter
ending December 31, 1999, a ratio of Senior Debt as of the last day of
any fiscal quarter to EBITDA for the period of four immediately
preceding fiscal quarters then ended not in excess of 4.0 to 1.0, and
for each fiscal quarter ending after December 31, 1999, a ratio of
FOURTH AMENDMENT - Page 4
<PAGE> 5
Senior Debt as of the last day of any fiscal quarter to EBITDA for each
period of four immediately preceding consecutive fiscal quarters then
ended not in excess of 3.0 to 1.0;
(e) TOTAL DEBT LEVERAGE RATIO. For the
fiscal quarter ended December 31, 1998, through the fiscal quarter
ending December 31, 1999, a ratio of Total Debt as of the last day of
any fiscal quarter to EBITDA for the period of four immediately
preceding consecutive fiscal quarters then ended not in excess of 6.0
to 1.0, and for each fiscal quarter ending after December 31, 1999, a
ratio of Total Debt as of the last day of any fiscal quarter to EBITDA
for each period of four immediately preceding consecutive fiscal
quarters then ended not in excess of 5.0 to 1.0; and
(f) CURRENT RATIO. A ratio of current
assets to current liabilities on any date of at least 1.0 to 1.0 (for
purposes of this calculation, current assets will include an amount
equal to the Unused Availability)."
2.5 AMENDMENTS TO SCHEDULES AND EXHIBITS. The Credit Agreement is
hereby amended to replace SCHEDULES 1, 2, and 3 to the Credit Agreement with
SCHEDULES 1, 2, and 3 attached to this Amendment and to add as EXHIBIT D to the
Credit Agreement the Pledge Agreement attached to this Amendment as EXHIBIT D.
2.6 NAME CHANGES. Lenders acknowledge that some of Borrower's
Subsidiaries have changed their names and some have merged into other
Subsidiaries, and Borrower represents that the current Subsidiaries and their
correct names are set out in SCHEDULE 3 attached hereto.
ARTICLE 3 - BORROWING BASE DETERMINATION.
3.1 PERIODIC DETERMINATION OF BORROWING BASE. (a) Pursuant to SECTIONS
4.01 and 4.02 of the Credit Agreement and effective only upon satisfaction of
the conditions precedent set out in ARTICLE 4 below, Lenders who are signatory
parties to this Amendment (whose Commitment Percentages aggregate at least 75%,
resulting in approval of this Amendment by Required Lenders) and Borrower agree
that the Borrowing Base will remain at $385,000,000 (subject to the provisions
of SECTION 4.05 of the Credit Agreement as amended hereby) until June 30, 1999.
As of June 30, 1999, the Borrowing Base will be redetermined by the Required
Lenders. In accordance with the provisions of ARTICLE 4 of the Credit Agreement,
as amended hereby, if on June 30, 1999, the Outstanding Obligations equal or
exceed $300,000,000 or such higher Borrowing Base as may be determined by
Required Lenders as of such date, then on or before July
FOURTH AMENDMENT - Page 5
<PAGE> 6
10, 1999, Borrower shall pay to Administrative Agent, for the ratable benefit of
Lenders, the amount by which the Outstanding Obligations exceed $300,000,000 or
the higher Borrowing Base then in effect. If the Borrowing Base determined by
Required Lenders as of June 30, 1999, is less than $300,000,000, then Borrower
shall be required to eliminate the deficiency between $300,000,000 and the
Borrowing Base then in effect in accordance with SECTION 4.06(a) of the Credit
Agreement. The Determination effective as of June 30, 1999, and all subsequent
Determinations of the Borrowing Base shall be made in accordance with the terms
of the Credit Agreement. Notwithstanding the provisions of SECTION 4.02 of the
Credit Agreement, the parties agree that there will be no Periodic Determination
made as of May 1, 1999.
(b) In consideration of the amendments and changes made
herein, Borrower agrees to pay to Administrative Agent, for the ratable benefit
of the Lenders and allocated in accordance with the Commitment Percentages shown
on SCHEDULE 1 to the Credit Agreement, a fee equal to $425,000.
ARTICLE 4 - CONDITIONS PRECEDENT.
4.1 CONDITIONS PRECEDENT. The effectiveness of this Amendment is
subject to the satisfaction of the following conditions precedent, unless
specifically waived in writing by Administrative Agent:
(a) CLOSING DELIVERIES. Administrative Agent shall have
received the following documents, instruments, agreements, and other
information, each of which shall be in form and substance and executed in such
counterparts as shall be acceptable to Administrative Agent and Required Lenders
and each of which shall, unless otherwise indicated, be dated the Effective
Date:
(i) this Amendment;
(ii) a Pledge Agreement duly executed by Borrower and
its Subsidiaries, as appropriate, together with (A) certificates evidencing (1)
100% of the issued and outstanding Capital Stock of Borrower's Subsidiaries (all
certificates delivered pursuant to this provision shall be duly endorsed or
accompanied by duly executed blank stock powers), and (B) accompanied by such
financing statements executed by Borrower as Administrative Agent shall request
to perfect the Liens granted pursuant to the Pledge Agreement;
(iii) a certificate executed by an Authorized Officer
of Borrower stating that (A) the representations and warranties of Borrower
contained in this
FOURTH AMENDMENT - Page 6
<PAGE> 7
Amendment, the Credit Agreement, and the other Loan Documents are true and
correct in all respects, (B) no Default or Event of Default has occurred which
is continuing, and (C) all conditions set forth in this SECTION 4.1(a) and in
SECTION 6.02 of the Credit Agreement have been satisfied; and
(iv) such resolutions, certificates and other
documents relating to the existence of the Loan Parties, the corporate,
partnership, or limited liability company authority for the execution, delivery
and performance of this Amendment, the Credit Agreement, the other Loan
Documents, and certain other matters relevant hereto, in form and substance
satisfactory to Administrative Agent, which resolutions, certificates and
documents include resolutions of the directors of each Loan Party authorizing
the execution, delivery, and performance of the Loan Documents and certificates
of incumbency for each Loan Party.
(b) NO MATERIAL ADVERSE EFFECT. Other than the decline in
commodity prices, no event or condition shall have occurred which is reasonably
expected to have a Material Adverse Effect.
(c) NO LEGAL PROHIBITION. The transactions contemplated by
this Amendment shall be permitted by applicable law and regulation and shall not
subject Agents, any Lender, Borrower, or any Subsidiary to any material adverse
change in their assets, liabilities, financial condition, or prospects.
(d) NO LITIGATION. No litigation, arbitration, or similar
proceeding shall be pending or threatened against Borrower or any Subsidiary
which calls into question the validity or enforceability of the Credit Agreement
(as amended hereby) or the other Loan Documents.
(e) NO DEFAULT. No Default or Event of Default shall have
occurred and be continuing.
(f) OTHER MATTERS. All matters related to this Amendment, the
other Loan Documents, and Borrower and its Subsidiaries shall be acceptable to
Administrative Agent and each Lender in their discretion, and Borrower shall
have delivered to Administrative Agent and each Lender such evidence as they
shall request to substantiate any matters related to the Credit Agreement (as
amended hereby), the other Loan Documents and Borrower and its Subsidiaries as
Administrative Agent or any Lender shall request.
FOURTH AMENDMENT - Page 7
<PAGE> 8
(g) CLOSING FEES. Borrower shall have paid to Agents and
Lenders the fee described in SECTION 3.1 above.
ARTICLE 5 - RATIFICATIONS, REPRESENTATIONS, AND COVENANTS.
5.1 RATIFICATIONS. The terms and provisions set forth in this Amendment
shall modify and supersede all inconsistent terms and provisions set forth in
the Credit Agreement and the other Loan Documents, and, except as expressly
modified and superseded by this Amendment, the terms and provisions of the
Credit Agreement and the other Loan Documents are ratified and confirmed and
shall continue in full force and effect. Borrower and Lenders agree that the
Credit Agreement and the other Loan Documents, as amended hereby, shall continue
to be legal, valid, binding, and enforceable in accordance with their respective
terms.
5.2 REPRESENTATIONS AND COVENANTS. Borrower hereby represents and
warrants to Lenders that (a) the execution, delivery, and performance of this
Amendment and any and all other Loan Documents executed or delivered in
connection herewith have been authorized by all requisite corporate action on
the part of Borrower and will not violate the Articles of Incorporation or
Bylaws of Borrower; (b) the representations and warranties contained in the
Credit Agreement, as amended hereby, and any other Loan Documents are true and
correct on and as of the date hereof, as though made on and as of such date; (c)
no Default or Event of Default under the Credit Agreement, as amended hereby,
has occurred and is continuing; and (d) Borrower is in full compliance with all
covenants and agreements contained in the Credit Agreement and the other Loan
Documents, as amended hereby.
ARTICLE 6 - MISCELLANEOUS PROVISIONS.
6.1 NO WAIVER. Except as specifically provided in this Amendment,
nothing contained in this Amendment shall be construed as a waiver by Lenders of
any covenant or provision of the Credit Agreement, the other Loan Documents,
this Amendment, or of any other contract or instrument between Borrower and
Lenders, and the failure of Lenders at any time or times hereafter to require
strict performance by Borrower of any provision thereof shall not waive, affect,
or diminish any right of Lenders to thereafter demand strict compliance
therewith. Lenders hereby reserve all rights granted under the Credit Agreement,
the other Loan Documents, this Amendment, and any other contract or instrument
between Borrower and Lenders.
6.2 SURVIVAL OF REPRESENTATIONS AND WARRANTIES. All representations
and warranties made in the Credit Agreement or any other Loan Documents,
including,
FOURTH AMENDMENT - Page 8
<PAGE> 9
without limitation, any document furnished in connection with this Amendment,
shall survive the execution and delivery of this Amendment and the other Loan
Documents, and no investigation by Agents or any Lender shall affect the
representations and warranties or the right of Agents or any Lender to rely upon
them.
6.3 REFERENCE TO CREDIT AGREEMENT. Each of the Credit Agreement and the
other Loan Documents, and any and all other agreements, documents, or
instruments now or hereafter executed and delivered pursuant to the terms hereof
or pursuant to the terms of the Credit Agreement, as amended hereby, are hereby
amended so that any reference in the Credit Agreement and such other Loan
Documents to the Credit Agreement shall mean a reference to the Credit Agreement
as amended hereby.
6.4 EXPENSES OF AGENT. As provided in the Credit Agreement, Borrower
agrees to pay on demand all reasonable costs and expenses incurred by
Administrative Agent in connection with the preparation, negotiation, and
execution of this Amendment and the other Loan Documents executed pursuant
hereto and any and all amendments, modifications, and supplements thereto,
including, without limitation, the costs and fees of Administrative Agent's
legal counsel, and all reasonable costs and expenses incurred by Lenders in
connection with the enforcements or preservation of any rights under the Credit
Agreement, as amended hereby, or any other Loan Documents, including, without
limitation, the reasonable costs and fees of Administrative Agent's legal
counsel.
6.5 SEVERABILITY. Any provisions of this Amendment held by a court of
competent jurisdiction to be invalid or unenforceable shall not impair or
invalidate the remainder of this Amendment and the effect thereof shall be
confined to the provisions so held to be invalid or unenforceable.
6.6 SUCCESSORS AND ASSIGNS. This Amendment is binding upon and shall
inure to the benefit of Lenders and Borrower and their respective successors and
assigns, except that Borrower may not assign or transfer any of its rights or
obligations hereunder without the prior written consent of Lenders.
6.7 COUNTERPARTS. This Amendment may be executed in one or more
counterparts, each of which when so executed shall be deemed to be an original,
but all of which when taken together shall constitute one and the same
instrument.
6.8 EFFECT OF WAIVER. No consent or waiver, express or implied, by
Administrative Agent or any Lender to or for any breach of or deviation from any
covenant or condition by Borrower shall be deemed a consent to or waiver of any
other breach of the same or any other covenant, condition, or duty.
FOURTH AMENDMENT - Page 9
<PAGE> 10
6.9 HEADINGS. The headings, captions, and arrangements used in this
Amendment are for convenience only and shall not affect the interpretation of
this Amendment.
6.10 APPLICABLE LAW. THIS AMENDMENT AND ALL OTHER LOAN DOCUMENTS
EXECUTED PURSUANT HERETO SHALL BE DEEMED TO HAVE BEEN MADE AND TO BE PERFORMABLE
IN AND SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE
STATE OF TEXAS UNLESS THE LAWS GOVERNING NATIONAL BANKS SHALL HAVE APPLICATION.
6.11 FINAL AGREEMENT. THE CREDIT AGREEMENT AND THE OTHER LOAN
DOCUMENTS, EACH AS AMENDED HEREBY, REPRESENT THE ENTIRE AGREEMENT OF THE PARTIES
WITH RESPECT TO THE SUBJECT MATTER HEREOF ON THE DATE THIS AMENDMENT IS
EXECUTED. THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS, AS AMENDED HEREBY,
MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT
ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN AGREEMENTS BETWEEN THE
PARTIES. NO MODIFICATION, RESCISSION, WAIVER, RELEASE, OR AMENDMENT OF ANY
PROVISION OF THIS AMENDMENT SHALL BE MADE EXCEPT BY A WRITTEN AGREEMENT SIGNED
BY BORROWER AND LENDERS.
BORROWER:
RANGE RESOURCES CORPORATION
By:
--------------------------------------
Thomas W. Stoelk,
Senior Vice President -
Finance and Administration
AGENTS:
BANK ONE, TEXAS, N.A.,
as Administrative Agent and a Lender
By:
--------------------------------------
W. Mark Cranmer, Vice President
FOURTH AMENDMENT - Page 10
<PAGE> 11
CHASE BANK OF TEXAS, N.A.,
as Syndication Agent and a Lender
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
NATIONSBANK, N.A.,
as Documentation Agent and a Lender
By:
--------------------------------
J. Scott Fowler, Vice President
BANKERS TRUST COMPANY
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
OTHER LENDERS:
PNC BANK, NATIONAL ASSOCIATION
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
BANKBOSTON, N.A.
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
CIBC INC.
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
FOURTH AMENDMENT - Page 11
<PAGE> 12
WELLS FARGO BANK (TEXAS), N.A.
By:
--------------------------------
Charles D. Kirkham, Vice President
CREDIT LYONNAIS NEW YORK BRANCH
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
ABN AMRO BANK N.V.
By: ABN AMRO North America, Inc.
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
BANK OF SCOTLAND
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
THE SANWA BANK, LIMITED
By:
--------------------------------
Name:
------------------------------
Title:
-----------------------------
FOURTHAM.WPD [March 11, 1999]aa
FOURTH AMENDMENT - Page 12
<PAGE> 1
EXHIBIT 10.1(p)
EMPLOYMENT AGREEMENT
AGREEMENT, made August 25, 1998 by and between Range
Resources Corporation, a Delaware corporation (the "Company"),
and Michael V. Ronca ("Executive").
RECITALS
Executive and Domain Energy Corporation ("Domain") are parties
to an Employment Agreement dated December 31, 1996 (the "Domain Employment
Agreement"). Pursuant to an Agreement and Plan of Merger dated May 12, 1998, as
amended (the "Merger Agreement"), among the Company, DEC Acquisition, Inc.
("Merger Sub") and Domain, Merger Sub has merged with and into Domain (the
"Merger"), and Domain as a result is a wholly owned subsidiary of the Company.
Paragraph 4 of Schedule 6.1(m) to the Merger Agreement
contemplates an amendment to the Domain Employment Agreement, and the Company
and Executive desire to execute this Agreement in lieu of amending the Domain
Employment Agreement as contemplated therein. Upon the execution and delivery
hereof, the Domain Employment Agreement will be deemed terminated with the same
effect as if it terminated by expiration of its term on the Termination Date (as
defined therein).
In order to induce Executive to serve as the Chief Operating
Officer of the Company, the Company desires to provide
<PAGE> 2
Executive with compensation and other benefits on the terms and conditions set
forth in this Agreement.
Executive is willing to accept such employment and perform
services for the Company, on the terms and conditions hereinafter set forth.
It is therefore hereby agreed by and between the parties as
follows:
1. EMPLOYMENT.
1.1 POWERS. Subject to the terms and conditions of this
Agreement, the Company hereby employs Executive during the term hereof as its
Chief Operating Officer. In his capacity as the Chief Operating Officer of the
Company, Executive shall report to the President and Chief Executive Officer of
the Company (the "CEO") and shall have the customary powers, responsibilities
and authorities of chief operating officers of corporations of the size, type
and nature of the Company, as it exists from time to time, and such additional
powers, responsibilities and authorities commensurate with such position as are
assigned by the Board of Directors of the Company (the "Board") or the CEO.
1.2 DUTIES. Subject to the terms and conditions of this
Agreement, Executive hereby accepts employment as the Chief Operating Officer of
the Company and agrees to devote his full working time and efforts, to the best
of his ability, experience and talent, to the performance of services, duties
and
2
<PAGE> 3
responsibilities in connection therewith. Executive shall perform such duties
and exercise such powers, commensurate with his position as the Chief Operating
Officer of the Company, as the Board or the CEO shall from time to time delegate
to him on such terms and conditions and subject to such restrictions as the
Board or the CEO may reasonably from time to time impose.
1.3 OTHER ACTIVITIES. Nothing in this Agreement shall preclude
Executive from engaging, so long as, in the reasonable determination of the
Board or the CEO, such activities do not interfere with his duties and
responsibilities hereunder, in charitable and community affairs, from managing
any passive investment made by him in equity securities or other assets
(provided that no such investment may exceed 5% of the equity of any entity,
without the prior approval of the Board or the CEO and Executive shall give the
CEO prior written notice of any investment in an entity that is not publicly
traded) or from serving, subject to the prior approval of the Board or the CEO,
as a member of boards of directors or as a trustee of any other corporation,
association or entity. For purposes of the preceding sentence, any approval of
the Board or the CEO required therein shall not be unreasonably withheld.
1.4 BOARD MEMBERSHIP. The Company shall take action to cause
the number of members of the Board, upon the execution and delivery hereof, to
be increased by two directors, and shall cause Executive to be elected to the
Board concurrently therewith. The Company agrees to nominate Executive for
election
3
<PAGE> 4
by the Company stockholders at the Company's 1999 Annual Meeting of
Stockholders. Executive agrees to serve, if elected, as a member of the Board.
2. TERM OF EMPLOYMENT. Executive's term of employment under
this Agreement shall commence as of the date hereof and, subject to the terms
hereof, shall terminate on the earlier of (i) December 31, 1999 (the
"Termination Date") or (ii) termination of Executive's employment pursuant to
this Agreement; PROVIDED, HOWEVER, that any termination of employment by
Executive (other than for death, Permanent Disability or Good Reason) may only
be made upon 60 days prior written notice to the Company and any termination of
employment by Executive for Good Reason may only be made upon 30 days prior
written notice to the Company.
3. COMPENSATION.
3.1 SALARY. The Company shall pay Executive a base salary
("Base Salary") at the rate of $260,000 per annum for the period commencing on
the beginning of Executive's term of employment hereunder and ending on the
Termination Date. Base Salary shall be payable in accordance with the ordinary
payroll practices of the Company. Any increase in Base Salary shall be in the
discretion of the Board or the CEO and, as so increased, shall constitute "Base
Salary" hereunder.
3.2 ANNUAL BONUS. In addition to his Base Salary,
Executive shall be considered for an annual bonus (the "Bonus")
during the term of his employment hereunder based on performance
4
<PAGE> 5
criteria determined by the Board in its sole discretion. For purposes of
Paragraph 6 hereunder, "Target Bonus" shall equal 50% of Base Salary.
3.3 COMPENSATION PLANS AND PROGRAMS. Executive shall be
entitled to participate in any compensation, deferred compensation, stock
option, stock purchase or other incentive compensation plan or program
maintained by the Company in which other senior executives of the Company
participate on terms comparable to those applicable to such other senior
executives, including, without limitation, (i) as a member of the "Management
Group" with full vesting under the Company's change in control plan described in
the Company's Proxy Statement for its 1997 Annual Meeting of Stockholders (the
"Change in Control Plan") and (ii) as an "Eligible Person" under the Company's
1997 Stock Purchase Plan (the "Stock Purchase Plan").
4. EMPLOYEE BENEFITS.
4.1 EMPLOYEE BENEFIT PROGRAMS, PLANS AND PRACTICES. The
Company shall provide Executive during the term of his employment hereunder with
coverage under all employee pension and welfare benefit programs, plans and
practices (commensurate with his positions in the Company and to the extent
permitted under any employee benefit plan) in accordance with the terms thereof,
which the Company makes available to its senior executives (including, without
limitation, participation in health, dental, group life, disability, retirement
and all other plans and fringe
5
<PAGE> 6
benefits to the extent generally provided to such senior executives).
4.2 VACATION AND FRINGE BENEFITS. Executive shall be entitled
to no less than twenty-five (25) business days paid vacation in each calendar
year, which shall be taken at such times as are consistent with Executive's
responsibilities hereunder. Such vacation time shall accrue at a rate of 2.08
vacation days for each calendar month worked. Unless otherwise approved by the
Board or the CEO, any vacation days not taken in any calendar year shall be
forfeited without payment therefor. In addition, Executive shall be entitled to
the perquisites and other fringe benefits commensurate with his position with
the Company. The Company shall furnish Executive with a private office in
Houston, Texas and a private secretary and all other reasonable assistance and
accommodations.
5. EXPENSES. Executive is authorized to incur reasonable
expenses in carrying out his duties and responsibilities under this Agreement
and promoting the business of the Company, including, without limitation,
expenses for travel, lodging, entertainment and similar items related to such
duties and responsibilities. The Company will reimburse Executive for all such
expenses upon presentation by Executive from time to time of appropriately
itemized and approved (consistent with the Company's policy) accounts of such
expenditures.
6
<PAGE> 7
6. TERMINATION OF EMPLOYMENT.
6.1 TERMINATION NOT FOR CAUSE OR TERMINATION FOR GOOD
REASON.
(a) Subject to the terms and conditions of this Agreement, the
Company may terminate Executive's employment at any time for any reason. If
Executive's employment is terminated by the Company other than for Cause (as
defined in Section 6.4(b) hereof) or other than as a result of Executive's
death, Retirement (as defined below in this Section 6.1(a)) or Permanent
Disability (as defined in Section 6.2 hereof) or if Executive terminates his
employment for Good Reason (as defined in Section 6.1(c) hereof) prior to the
Termination Date, Executive shall receive all such payments, if any, under
applicable compensation and employee benefit plans or programs, including but
not limited to those referred to in Section 3.3 hereof, to which he is entitled
pursuant to the terms of such plans or programs. In addition, Executive shall
receive a lump sum cash payment (the "Termination Amount") in lieu of any Bonus
in respect of all or any portion of the fiscal year in which such termination
occurs and any other cash compensation (other than the Vacation Payment and the
Compensation Payment referred to below). The Termination Amount shall consist of
the greater of (i) an amount equal to the Executive's Base Salary at its then
current annual rate plus the amount of Executive's Target Bonus for the entire
year in which his termination occurs (irrespective of whether the performance
criteria have been met) and (ii) the aggregate amount of Base
7
<PAGE> 8
Salary which Executive would have received for the remaining term of this
Agreement. In addition, Executive shall receive a cash lump sum payment in
respect of accrued but unused vacation days (the "Vacation Payment") and all
compensation earned but not yet paid (including any deferred Bonus payments)
(the "Compensation Payment"). "Retirement" means the termination of Executive's
employment with the Company and all of its affiliates as a result of his
reaching a retirement age (not less than 62 years of age) established by the
Board for his retirement.
(b) The Termination Amount, the Vacation Payment and the
Compensation Payment shall be paid by the Company to Executive within 30 days
after the termination of Executive's employment by check payable to the order of
Executive or by wire transfer to an account specified by Executive. Payments or
amounts to which Executive is entitled under applicable compensation and
employee benefit plans or programs will be paid to Executive pursuant to the
terms of such plans or programs.
(c) For purposes of this Agreement, "Good Reason" shall mean
any of the following (without Executive's express prior written consent):
(i) any removal of Executive as the Chief Operating
Officer of the Company or any material reduction by the Company of
Executive's authority, duties or responsibilities (except in connection
with the termination of Executive's employment for Cause, as a result
of Permanent Disability, or as a result of Executive's death or
Retirement);
(ii) any reduction by the Company in Executive's Base
Salary, other than a reduction which is part of a uniformly applied
general salary reduction program affecting senior executives of the
Company;
8
<PAGE> 9
(iii) the Company's moving Executive's place of
employment outside the Houston, Texas metropolitan area; or
(iv) Executive's election to terminate his employment
for any reason within 30 calendar days following a Change in Control
(as defined in the Change in Control Plan).
6.2 PERMANENT DISABILITY. If the Executive becomes totally and
permanently disabled (as defined in the Company's Long-Term Disability Income
Plan (Policy No. 0034 2460-010) applicable to senior executive officers as in
effect on the date hereof ("Permanent Disability"), the Company or Executive may
terminate Executive's employment on written notice thereof, and in any such case
Executive shall receive or commence receiving:
(i) as soon as possible under the terms thereof, all
amounts payable pursuant to the terms of any disability insurance
policy or similar arrangement which the Company maintains during the
term hereof;
(ii) within 30 days after the giving or receipt of such
notice by the Company, as the case may be, the Target Bonus in respect
of the fiscal year in which his termination occurs (irrespective of
whether the performance criteria have been met), prorated by a
fraction, the numerator of which is the number of days of the fiscal
year until termination and the denominator of which is 365;
(iii) within 30 days after the giving or receipt of such
notice by the Company, as the case may be, the Vacation Payment and the
Compensation Payment; and
(iv) as soon as possible under the terms thereof, all
such payments under applicable plans or programs, including but not
limited to those referred to in Sections 3.3 and 4.1 hereof, to which
he is entitled pursuant to the terms of such plans or programs, in
accordance with their terms.
6.3 DEATH. In the event of Executive's death during the term of his
employment hereunder, Executive's estate or designated beneficiaries shall
receive or commence receiving:
9
<PAGE> 10
(i) within 30 days after the Company knows of
Executive's death, the Target Bonus in respect of
the fiscal year in which his death occurs
(irrespective of whether the performance criteria
have been met), prorated by a fraction, the
numerator of which is the number of days of the
fiscal year until his death and the denominator of
which is 365;
(ii) within 30 days after the Company knows of
Executive's death, the Vacation Payment and the
Compensation Payment; and
(iii) as soon as possible under the terms thereof, all
such payments under applicable plans or programs,
including but not limited to those referred to in
Sections 3.3 and 4.1 hereof, to which Executive's
estate or designated beneficiaries are entitled
pursuant to the terms of such plans or programs, in
accordance with their terms.
6.4 VOLUNTARY TERMINATION BY EXECUTIVE; DISCHARGE FOR CAUSE. (a) The
Company shall have the right to terminate the employment of Executive for Cause.
In the event that Executive's employment is terminated by the Company for Cause,
as hereinafter defined, or by Executive other than for Good Reason or other than
as a result of the Executive's Permanent Disability, Retirement or death,
Executive shall only be entitled to receive, within 30 days after such
termination, the Compensation Payment and the Vacation Payment and any other
then-vested benefits under any compensation or employee benefit plans or
programs to which he is entitled pursuant to the terms of such plans or
programs. Executive shall not be entitled, among other things, to the payment of
any Bonus in respect of all or any portion of the fiscal year in which such
termination occurs. After the termination of Executive's employment under this
Section 6.4, the obligations of the Company under this Agreement to make any
10
<PAGE> 11
further payments, or provide any benefits other than those specified herein, to
Executive shall thereupon cease and terminate.
(b) As used herein, the term "Cause" shall be limited to (i)
Executive's commission of any act of fraud or embezzlement against the Company
or any of its affiliates, irregardless of whether such act results in material
financial loss to the Company or any of its affiliates, or other willful
malfeasance or willful misconduct by Executive in connection with his employment
that results in material financial loss to the Company or any of its affiliates,
(ii) continuing refusal by Executive to perform his duties hereunder or any
lawful direction of the Board or the CEO as required under Section 1.2, after
written notice of any such refusal to perform such duties or direction was given
to Executive by the Board and Executive has been given a 30-day cure period
after receipt of such notice to take reasonable corrective action, (iii) any
material breach of the provisions of Section 13 of this Agreement by Executive
or any other material breach of this Agreement by Executive after written notice
of any such breach was given to Executive by the Board and Executive has been
given a 30-day cure period after receipt of such notice to take reasonable
corrective action or (iv) the conviction of Executive for any felony.
Termination of Executive pursuant to Section 6.4 shall be made by delivery to
Executive of a copy of a resolution duly adopted by the affirmative vote of not
less than a majority of the entire Board at a meeting of the Board called and
held for
11
<PAGE> 12
such purpose (after 30 days prior written notice (which may include the 30 day
period referred to in (ii) above) to Executive and reasonable opportunity for
Executive to be heard before the Board prior to such vote), finding that in the
reasonable judgment of such Board, Executive was guilty of conduct set forth in
any of clauses (i) through (iv) above and specifying the particulars thereof.
7. OTHER ARRANGEMENTS.
7.1 STOCK ARRANGEMENTS. Upon the execution and delivery hereof
by Executive, effective September 15, 1998, the Company will (i) issue to the
Executive an option to purchase, under the Company's 1989 Stock Option Plan, up
to 40,000 shares of the Company's Common Stock, par value $.01 per share and
(ii) at the next Purchase Date (as defined in the Stock Purchase Plan) following
the date hereof, grant Executive eligibility to purchase up to 25,000 shares of
the Company's Common Stock pursuant to the Stock Purchase Plan.
7.2 "KEEP WHOLE" AGREEMENT. Within 10 days after the execution
and delivery hereof by Executive, pursuant to a Keep Whole Agreement, the
Company will agree to make a non-interest bearing, non-amortizing 5-year term
loan to Executive in an original principal amount to be determined upon
consummation of the Merger, which principal amount will represent the estimated
U.S. federal income tax liability to be incurred by Executive upon exchange of
his shares of Domain Common Stock for Company Common Stock in the Merger. In
addition, annually during the
12
<PAGE> 13
term of such loan, the Company will make a cash payment to Executive in an
amount equal to the product of (i) imputed annual interest on such loan as
calculated pursuant to Internal Revenue Service requirements and (ii) the
greater of (A) 41.05% and (B) the sum of, for any particular taxable year, (x)
the highest effective marginal combined rate of Federal, state and city income
tax imposed on an individual taxpayer and (y) the FICA withholding percentage,
where the rate of "state and city income tax" to be taken into account for
purposes of determining the percentage referred to in subclause (x) of this
clause (B) shall be deemed to be the highest combined Texas and Houston, Texas
income tax rate imposed on individuals for such taxable year.
8. MITIGATION OF DAMAGES. Executive shall not be required to mitigate
any damages or the amount of any payment provided for under this Agreement by
seeking other employment or otherwise after the termination of his employment
hereunder, and any amounts earned by Executive, whether from self-employment, as
a common-law employee or otherwise, shall not reduce the amount of any
Termination Amount or other payments or amounts otherwise payable to him.
9. NOTICES. All notices or communications hereunder shall be in
writing, addressed as follows:
13
<PAGE> 14
To the Company:
Range Resources Corporation
500 Throckmorton
Fort Worth, TX 76102
Attention: President and Chief Executive Officer
To Executive:
Michael V. Ronca
17318 Chagal Lane
Spring, TX 77379
Any such notice or communication shall be delivered by hand or by courier or
sent certified or registered mail, return receipt requested, postage prepaid,
addressed as above (or to such other address as such party may designate in a
notice duly delivered as described above), and the third business day after the
actual date of mailing (or, if earlier, the actual date of receipt) shall
constitute the time at which notice was given.
10. SEPARABILITY; LEGAL FEES. If any provision of this
Agreement shall be declared to be invalid or unenforceable, in whole or in part,
such invalidity or unenforceability shall not affect the remaining provisions
hereof which shall remain in full force and effect. In any dispute between the
Executive and the Company pertaining to this Agreement, the non-prevailing party
shall pay the costs of any legal fees and other fees and expenses which may be
incurred by the prevailing party in such dispute. For these purposes, the
plaintiff shall be deemed to be the prevailing party if the plaintiff is awarded
in excess of 50% of the amount claimed in the complaint and the defendant shall
be
14
<PAGE> 15
deemed to be the prevailing party if the plaintiff is awarded 50% or less of the
amount claimed in the complaint.
11. ASSIGNMENT. This Agreement shall be binding upon and inure
to the benefit of the heirs and legal representatives of Executive and the
permitted assigns and successors of the Company, but neither this Agreement nor
any rights or obligations hereunder shall be assignable or otherwise subject to
hypothecation by Executive (except by will or by operation of the laws of
intestate succession) or by the Company, except that the Company may assign this
Agreement to any successor (whether by merger, purchase or otherwise) to all or
substantially all of the stock, assets or businesses of the Company, if such
successor expressly agrees to assume the obligations of the Company hereunder.
12. AMENDMENT. This Agreement may only be amended by written
agreement of the parties hereto.
13. NONDISCLOSURE OF CONFIDENTIAL INFORMATION; NON-
COMPETITION. (a) Executive shall not, without the prior written consent of the
Company, use, divulge, disclose or make accessible to any other person, firm,
partnership, corporation or other entity any Confidential Information pertaining
to the business of the Company or any of its affiliates, except (i) while
employed by the Company, in the business of and for the benefit of the Company,
or (ii) when required to do so by a court of competent jurisdiction, by any
governmental agency having supervisory authority over the business of the
Company, or by any
15
<PAGE> 16
administrative body or legislative body (including a committee thereof) with
jurisdiction to order Executive to divulge, disclose or make accessible such
information. For purposes of this Section 13(a), "Confidential Information"
shall mean non public information concerning the financial data, strategic
business plans, product development (or other proprietary product data),
customer lists, marketing plans and other non-public, proprietary and
confidential information of the Company that is not otherwise available to the
public (other than by Executive's breach of the terms hereof).
(b) During the period of his employment hereunder and for six
(6) months thereafter, Executive agrees that, without the prior written consent
of the Company, (A) he will not, directly or indirectly, either as principal,
manager, agent, consultant, officer, stockholder, partner, investor, lender or
employee or in any other capacity, carry on, be engaged in or have any financial
interest in, any business or entity which is in competition with the Company and
(B) he shall not, on his own behalf or on behalf of any person, firm or company,
directly or indirectly, solicit or offer employment to any person who has been
employed by the Company at any time during the 12 months immediately preceding
such solicitation.
(c) For purposes of this Section 13, a business shall be
deemed to be in competition with a member of the Restricted Group engaged in the
oil and gas exploration and production business if it is also principally
engaged in the oil and gas
16
<PAGE> 17
exploration and production business within the same geographic area in which the
Company is so engaged. Nothing in this Section 13 shall be construed so as to
preclude Executive from investing in any publicly or privately held company,
provided Executive's beneficial ownership of any class of such company's
securities does not exceed 5% of the outstanding securities of such class.
(d) Executive and the Company agree that this covenant not to
compete is a reasonable covenant under the circumstances, and further agree that
if in the opinion of any court of competent jurisdiction such restraint is not
reasonable in any respect, such court shall have the right, power and authority
to excise or modify such provision or provisions of this covenant as to the
court shall appear not reasonable and to enforce the remainder of the. covenant
as so amended. Executive agrees that any breach of the covenants contained in
this Section 13 would irreparably injure the Company. Accordingly, Executive
agrees that the Company may, in addition to pursuing any other remedies it may
have in law or in equity, cease making any payments otherwise required by this
Agreement (until any such breach is cured) and obtain an injunction against
Executive from any court having jurisdiction over the matter restraining any
further violation of this Agreement by Executive.
14. BENEFICIARIES; REFERENCES. Executive shall be entitled to
select (and change, to the extent permitted under any applicable law) a
beneficiary or beneficiaries to receive any compensation or benefit payable
hereunder following Executive's
17
<PAGE> 18
death, and may change such election, in either case by giving the Company
written notice thereof. In the event of Executive's death or a judicial
determination of his incompetence, reference in this Agreement to Executive
shall be deemed, where appropriate, to refer to his beneficiary, estate or other
legal representative. Any reference to the masculine gender in this Agreement
shall include, where appropriate, the feminine.
15. SURVIVORSHIP. The respective rights and obligations of the
parties hereunder shall survive any termination of this Agreement to the extent
necessary to the intended preservation of such rights and obligations. The
provisions of this Section 15 are in addition to the survivorship provisions of
any other section of this Agreement.
16. GOVERNING LAW. THIS AGREEMENT SHALL BE CONSTRUED,
INTERPRETED AND GOVERNED IN ACCORDANCE WITH THE LAWS OF THE STATE
OF TEXAS, WITHOUT REFERENCE TO RULES RELATING TO CONFLICTS OF
LAW.
17. EFFECT ON PRIOR AGREEMENTS. This Agreement contains the
entire understanding between the parties hereto with respect to the subject
matter hereof and supersedes in all respects any prior or other agreement or
understanding between the Company or any affiliate of the Company and Executive
with respect to such subject matter.
18. WITHHOLDING. The Company shall be entitled to withhold
from payment any amount of withholding required by law.
18
<PAGE> 19
19. COUNTERPARTS. This Agreement may be executed in
two or more counterparts, each of which will be deemed an
original.
20. DOMAIN EMPLOYMENT AGREEMENT. Upon the execution and
delivery hereof, the Domain Employment Agreement shall be deemed terminated,
without the need for further act or evidence, with the same effect as if it
terminated by expiration of its term on the Termination Date (as defined
therein).
Range Resources Corporation
By
------------------------------------
Name:
Title:
--------------------------------------
Michael V. Ronca
19
<PAGE> 1
EXHIBIT 21
RANGE RESOURCES CORPORATION
SUBSIDIARIES OF REGISTRANT
<TABLE>
<CAPTION>
Percentage of Voting
Jurisdiction of Securities Owned by
Name Incorporation Immediate Parent
- ----------------------------------- ------------------- --------------------
<S> <C> <C>
Range Operating Company Ohio 100%
Range Production Company Delaware 100%
Buffalo Oilfield Services, Inc. Ohio 100%
Range Energy Services Company Delaware 100%
Range Resources Development Company Delaware 100%
Range Energy I, Inc. Delaware 100%
Range Gathering & Processing Company Delaware 100%
Range Gas Company Delaware 100%
Lomak Financing Trust Delaware 100%
RRC Operating Company Ohio 100%
Range Energy Finance Corporation Delaware 100%
Range Energy Ventures Corporation Delaware 100%
Gulfstar Energy, Inc. Delaware 100%
Gulfstar Seismic, Inc. Delaware 100%
Domain Energy International Corporation British Virgin Islands 100%
</TABLE>
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report on the consolidated financial statements of Range
Resources Corporation for the year ended December 31, 1998, included in this
Form 10-K, into the Company's previously filed Registration Statements on Form
S-1 File No. 333-08211, Form S-3 File No. 333-23955, Form S-8 File No. 10719,
Form S-8 File No. 33-66322, Form S-3 File No. 33-64303, Form S-3 File No.
333-20257, Form S-3 File No. 333-43823, Form S-8 File No. 333-44821, Form S-3
File No. 333 51503, Form S-4 File No. 333-57639 and Form S-8 File No. 333-62439.
ARTHUR ANDERSEN LLP
Cleveland, Ohio
March 12, 1999
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