SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. 2
(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, 2001
{ } 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.)
777 MAIN STREET, FORT 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. { }
The aggregate market value of voting stock of the registrant held by
non-affiliates (excluding voting shares held by officers and directors) was
$237,932,024 on March 1, 2002.
Indicate the number of shares outstanding of each of the registrant's
classes of stock on March 1, 2002: Common Stock $.01 par value: 52,841,766.
DOCUMENTS INCORPORATED BY REFERENCE:
Part III of this report incorporates by reference the Proxy Statement
relating to the Registrant's 2002 Annual Meeting of
Stockholders, filed on April 17, 2002.
1
Explanatory Note
This Amendment No. 2 on Form 10-K/A to the Registrant's Form 10-K for
the year ended December 31, 2001 is being filed as certain amounts in the
accompanying 1999, 2000 and 2001 consolidated financial statements were
restated. Other than the information affected by the restatement, all other
information is presented as of the original filing on March 5, 2002.
RANGE RESOURCES CORPORATION
ANNUAL REPORT ON FORM 10-K/A AMENDMENT NO. 2
YEAR ENDED DECEMBER 31, 2001
PART I
ITEM 1. BUSINESS
GENERAL
Range Resources Corporation ("Range") is engaged in development,
acquisition and exploration of oil and gas properties, primarily in the
Southwestern, Gulf Coast and Appalachian regions of the United States. The
Company pursues development drilling and exploitation projects, acquisitions
and, to a lesser extent, exploration of its extensive acreage position. All
Appalachian assets are held through a 50% interest in a joint venture, Great
Lakes Energy Partners L.L.C. ("Great Lakes"). Independent Producer Finance
("IPF"), a wholly owned subsidiary, provides financing to small oil and gas
producers through the purchase of overriding royalty interests. Both Great Lakes
and IPF are independently financed and all of IPF and Range's proportionate
share of Great Lakes' assets and operations are consolidated in the Company's
financial statements. At December 31, 2001, the Company had 513 Bcfe of proved
reserves, having a pre-tax present value, excluding open hedging contracts, of
$399.2 million based on constant prices of $20.38 per barrel and $2.63 per
Mmbtu. The fair value of open hedging contracts at December 31, 2001
approximated a net unrealized pre-tax gain of $52.1 million. The Company's
proved reserves are 76% natural gas by volume, 70.2% developed and 84.4%
operated. At year-end, the Company's properties had a reserve life index of 9.2
years. In addition, the Company owned 558,862 gross (284,028 net) acres of
undeveloped leasehold.
After ten years of rapid growth and uninterrupted profitability, Range
concluded a series of disastrous acquisitions in 1997 and 1998. Due to the poor
performance of the acquired properties, the Company was forced to retrench.
Staff was sharply reduced, capital expenditures cut, assets sold, and a program
of exchanging common stock for fixed income securities initiated. Since year-end
1998, parent company bank debt has been reduced 74% to $95.0 million. Total
debt, including Trust Preferred, has been reduced 46% to $392.2 million. As a
result, the Company's financial position has stabilized. The Company expects to
continue to retire debt with internal cash flow and may exchange additional
common stock or other equity-linked securities for indebtedness. Stockholders
could be materially diluted if a substantial amount of the fixed income
securities are exchanged for stock. The extent of dilution will depend on a
number of factors, including the number of shares issued, the price at which
stock is issued or newly issued securities are convertible into common stock and
the price at which fixed income securities are reacquired. While such exchanges
reduce existing stockholders' proportionate ownership, management believes such
exchanges enhance the Company's financial flexibility and should increase the
market value of its common stock.
With its financial strength largely restored, the Company has refocused
on increasing production and reserves. As part of this effort, the Company's
exploration and production effort was placed under the control of a newly hired
Executive Vice President in early 2001. Due to reserve revisions and asset
sales, reserves and production fell in 1999 and 2000. In 2001, there was a
slight increase in production and reserves decreased as the Company's capital
program did not replace production. In 2002, the Company has announced a capital
budget of $100.0 million. Due to the current low product price environment, the
Company will monitor its capital expenditure program carefully and may elect not
to spend the entire amount.
2
RESTATEMENT
In July 2002, the Company selected KPMG LLP as its new independent
auditor. The Company also chose to have KPMG reaudit its consolidated financial
statements for the three years ended December 31, 2001, even though a reaudit
was not required. The reaudit was intended to provide additional assurance to
shareholders, insure the Company's ongoing access to the capital markets and to
avoid any possible impediment to future transactions.
As a result of the reaudits, the Company restated the financial
statements included herein. For the three years ended December 31, 2001, the
cumulative impact of the restatements reduced net income by $8.4 million, of
which, $7.8 million reduced the gain associated with the formation of Great
Lakes in 1999. The restatement increased the 1999 net loss by $15.7 million,
reduced 2000 net income by $1.4 million and increased 2001 net income by $8.7
million. The changes comprising the restatement are more fully described
hereafter.
HISTORY
Between 1988 and 1997, the Company actively pursued small acquisitions
as well as the further development of its properties. The Company was
consistently profitable and steadily increased its production and reserves.
Between late 1997 and mid-1998, a series of large acquisitions were consummated
which proved extremely disappointing. Production from the acquired properties
fell more rapidly than anticipated and further development of the principal
fields proved far less attractive than expected. In combination with a steep
decline in energy prices which began in late 1997 and the substantial burden
imposed by debt and fixed income securities taken on in connection with the
purchases, the adverse impact on the Company's operating results, balance sheet
and stock price was severe.
In 1998 and 1999, sharp reductions in staff and capital budgets, sales
of properties and the formation of Great Lakes allowed the Company to materially
reduce debt and stabilize its financial position. However, production and
reserves fell as a result of these actions. In the Great Lakes transaction, the
single most significant step in the debt reduction effort, Range and FirstEnergy
Corp. ("FirstEnergy") contributed their Appalachian oil and gas properties and
associated gas pipeline systems to a joint venture, forming one of the largest
production companies in the region. To achieve equal ownership despite Range's
contribution of a disproportionate share of the proved reserves, the venture
assumed $188.3 million of Range's bank debt and FirstEnergy contributed $2.0
million of cash.
Faced with high leverage and significant concern from its banks, the
Company moved aggressively to hedge its production as the oil and gas markets
began to recover in late 1999. These hedges, which covered roughly 80% of the
Company's anticipated production through the third quarter of 2000, were
designed to assure financial viability while the restructuring was completed.
Given the continuing sharp rise in oil and gas prices throughout 2000, these
hedges substantially limited the benefits to the Company of the price increases.
Because the Company has continued to hedge on a rolling twelve to eighteen month
basis since that time, the rise in prices has permitted a substantial increase
in the average price at which production is hedged, particularly since September
30, 2000. At year-end 2001, the Company had hedges in place on approximately
47.3 bcf of gas and 700,000 barrels of oil at average prices of $4.02 per mcf
and $25.97 per barrel. These hedges cover approximately 55%, 30%, 15% and 5% of
the Company's anticipated production from proved reserves on an mcfe basis for
2002 through 2005, respectively.
In 2000, with the benefit of rising oil and gas prices, the Company
began to gradually increase capital expenditures while keeping spending below
internal cash flow to allow the continued pay down of debt. Through these
repayments and exchanges of common stock for fixed income securities, debt was
again substantially reduced. Despite capital constraints, the Company managed to
modestly increase production in the course of the year, primarily by bringing
proved non-producing reserves on stream. While production rose during the year,
it fell 17% from the prior year level primarily due to the impact of the Great
Lakes transaction in late 1999. By mid-year 2000, the progress made in
restructuring began to be recognized and the market for the Company's stock
started to rebound. However, due to the lower capital expenditures the Company
was unable to replace production and proved reserves fell 5.4% during the year.
In 2001, the Company increased its capital spending 84% to roughly
$90.0 million. This generated a modest increase in production. The benefits of
sharply higher energy prices and reduced fixed charges allowed for continued
profitability and a further reduction of debt. By year-end 2001, leverage had
been reduced to a more manageable level and the Company was far better
positioned to pursue profitable long-term growth. The Company did not replace
production in 2001 and proved reserves declined 12.1% during the year. However,
the Company replaced production during the fourth quarter of 2001.
3
For 2002, the Company has announced a $100.0 million capital budget.
Given the current low product price environment, the Company will monitor its
capital expenditures carefully and may elect not to expend the entire budget.
Any decline in capital spending would have an adverse affect on production and
reserve replacement. Based on the authorized level of capital expenditures, the
Company expects to sustain or slightly increase reserves in 2002. The 2002
budget includes $86 million for drilling and recompletions, $11 million for land
and seismic and $3 million for pipelines and facilities.
During the fourth quarter of 2001, the Company recognized property
impairments of $31.1 million, including $5.1 million relating to unproved
acreage and $26.0 million relating to proven properties. The Company
periodically compares the carrying value of its acreage to estimated fair value
based on a variety of factors including geological and engineering assessments,
acreage transactions in the area, the value that could be recovered from sale,
farmout or exploitation, the timing of potential drilling, and the nature of the
specific property. An impairment evaluation of proven properties includes
estimated future cash flows including historical operating results and the
estimated recoverability of reserves. (See Management's Discussion and Analysis
- Results of Operations.)
DESCRIPTION OF THE BUSINESS
Strategy
Between 1988 and 1997, assets grew from $7 million to $759 million as
stockholders' equity increased from less than $1 million to $197 million. In
1998 and 1999, the Company incurred almost $200 million of losses as a result of
disappointing results on a series of large acquisitions. These losses led to a
series of impairments, up to and including those recorded in the fourth quarter
of 2001. These losses materially reduced stockholders' equity and increased
leverage. The significant improvement in oil and gas prices since mid-1999
combined with the benefits of reduced costs allowed the Company to return to
profitability in 2000 and 2001. In 2001, production began to increase slightly.
The 2002 capital budget of $100.0 million is expected to increase production 5%
or more and expand the reserve base. The Company's hedge position, which covers
approximately 50% of anticipated 2002 production from proved reserves, is
expected to allow the capital program to be funded with internal cash flow even
in this low price environment. However, in such a low price environment,
management expects little excess cash flow to be available for reduction in
debt. Should prices decline further, it would be unlikely that the Company would
be able to fund its entire capital program with internal cash flow. The Company
intends to monitor its capital expenditures closely and results of operations;
therefore, this current low price environment may negatively affect the amount
of capital spending for the year.
At year-end, the Company had almost 1,900 proven development projects
in inventory. Given current oil and gas prices, the Company's hedge position and
this development inventory, the Company believes it can achieve growth in
reserves, production, cash flow and earnings over the next several years while
further reducing debt. The Company currently anticipates spending $100.0 million
on capital expenditures in 2002, although, the current price environment may
affect the actual level of spending. The Company's approximately 558,862 gross
(284,028 net) acre undeveloped leasehold position provides significant long-term
exploration and development potential.
Development. Development projects include recompletions of existing
wells, infill drilling and the installation of secondary recovery projects. Such
projects are pursued within core areas where the Company has significant
operational and technical experience. At December 31, 2001, the Company had an
inventory of 1,604 proven drilling locations and 274 proven recompletions.
During 2002, the Company plans to drill 161 proven locations and recomplete 41
wells. In addition, the Company also plans to drill an additional 109 not yet
proven projects in 2002. The following table illustrates the activity for
development projects during 2001:
Development Projects
----------------------------------------
Recompletion Drilling
Opportunities Locations Total
------------- --------- -----
December 31, 2000 318 1,812 2,130
Drilled (40) (167) (207)
Added 25 151 176
Deleted & other (29) (192) (221)
------ ------ ------
December 31, 2001 274 1,604 1,878
====== ====== ======
Exploration. Onshore exploration projects cover 268,122 gross (106,810
net) acres. These projects target deeper horizons in existing fields as well as
prospective fields in trend areas. Offshore exploration focuses on the shallow
waters of the
4
Gulf of Mexico where 3D seismic data covering 3.5 million contiguous acres are
held. The Company has offshore leases covering 174,724 gross (49,055 net) acres
on which it has to date identified eleven specific projects. The Company's
exploration strategy is based on limiting risk by allocating no more than 10% to
15% of the capital budget to such projects. At times, other companies pay all or
a disproportionate share of exploration costs to earn an interest in a project.
The Company currently anticipates participating in up to thirteen exploratory
wells in 2002.
Acquisitions. After a two year period during which the Company
withdrew from the acquisition market, it expects to reactivate this effort in
2002. At least initially, the focus will be on modest purchases of incremental
interests in existing and adjacent properties. To the extent the acquisition
effort is successfully reinitiated and capital constraints are reduced, a more
substantial effort will be considered in the latter part of 2002.
DEVELOPMENT AND EXPLORATION
In 2001, the Company spent $80.6 million on oil and gas related capital
expenditures, an increase of 59% over that expended in 2000. Of this amount,
$35.8 million was expended in the Southwest, $22.2 million in Appalachia and
$22.6 million in the Gulf Coast. These expenditures were primarily focused on
placing proved non-producing reserves on stream. They funded 51 recompletions,
264 development and 8 exploratory wells, minor lease acquisitions and seismic
work. Exploration and development spending brought 26.1 Bcfe of proved
non-producing reserves on stream and added a net 34.4 Bcfe of new reserves. In
the absence of price revisions, net reserves added during the year replaced 71%
of production.
Development
Development includes recompletions, infill drilling and to a lesser
extent, installation of secondary recovery projects. As described below, the
Company currently has 1,878 proven recompletion opportunities and drilling
locations in inventory. Drilling prospects are geographically diverse and target
a mix of oil and gas, generally at depths of less than 8,000 feet. Approximately
88% of the proved development locations are concentrated in ten fields covering
824,000 gross (446,000 net) acres. The Company believes that such large acreage
blocks and concentration of to be drilled wells provides economies of scale,
access to competitively priced field services and focused operating and
technical expertise. The following table sets forth information pertaining to
the proven development inventory at December 31, 2001.
Development Projects
------------------------------------------
Recompletion Drilling
Opportunities Locations Total
------------- --------- -----
Southwest 176 120 296
Gulf Coast 47 16 63
Appalachia 51 1,468 1,519
----- ----- -----
Total 274 1,604 1,878
===== ===== =====
Exploration
Onshore. The Company currently has 117 onshore exploration projects
covering 268,122 gross (106,810 net) acres. Each project has multiple drilling
prospects, some with several targeted formations. Given the continuing emphasis
on debt reduction, it is expected that only a limited amount of work will be
done on these projects in 2002.
Gulf of Mexico. The Company owns exclusive license to a 3D seismic
database covering 700 contiguous blocks in the shallow water of the Gulf of
Mexico, primarily offshore Louisiana. In February 2001, a joint venture was
formed between the Company, Callon Petroleum Co. ("Callon") and Cheyenne
Petroleum Company ("Cheyenne") to reprocess the data and utilize it to identify
and capture exploration and exploitation opportunities in a 3.5 million acre
area. Callon has a 50% interest in the joint venture with the Company and
Cheyenne sharing the remainder. The joint venture was awarded two blocks in the
March 2001 OCS lease sale. The Company's current offshore leasehold inventory
totals only 174,724 gross (49,055 net) acres. To more fully exploit the 3D
seismic data base, it will be necessary to lease or farm in significant
additional acreage. To date, the joint venture has identified 24 specific
prospects and leads on acreage not currently controlled. These projects target
Miocene and Pliocene formations at depths of 3,000 to 16,000 feet.
5
PRODUCTION
Production revenue is generated through the sale of natural gas, crude
oil and natural gas liquids ("NGL") from properties owned directly or through
partnerships and joint ventures. The Company receives additional revenue from
royalties. Production is sold to a limited number of purchasers of which three
accounted for more than 10% of oil and gas revenues. These three purchasers
currently accounted for 50% of oil and gas revenues in 2001. However, the
Company believes that the loss of any individual customer would not have a
material adverse long-term effect on the Company. Proximity to local markets,
availability of competitive fuels and overall supply and demand are factors
affecting the prices at which production can be marketed. Factors outside the
Company's control, such as international political developments, overall energy
supply and demand, weather conditions, economic growth rates and other factors
in the United States and world economies have had, and will continue to have, a
significant effect on energy prices.
On an mcfe basis, 76% of the Company's production for 2001 was natural gas.
Gas is sold to utilities, marketing companies and industrial users. Gas sales
are made pursuant to various contractual arrangements including month-to-month,
one to three-year contracts at fixed or variable prices and fixed prices for the
life of the well. Contracts other than those with fixed prices contain
provisions for price adjustment, termination and other terms customary in the
industry. From the inception of Great Lakes through June 30, 2001, the joint
venture sold 90% of its gas production to FirstEnergy based on closing prices on
the New York Mercantile Exchange ("NYMEX") plus a basis differential. For the
last six months of 2001, Great Lakes sold 33% of its gas to First Energy, with
the remaining 67% being sold to eight other companies. Currently 91% of Great
Lakes gas is sold at prices based on the close of the NYMEX contract each month
plus a basis differential. The remainder is sold at a fixed price. Oil is sold
under contracts that can be terminated on 30 days notice. The price received is
generally equal to a posted price set by major purchasers in the area. Oil
purchasers are selected on the basis of price and service. In 2001, gas revenues
totaled $154.2 million or 74% of oil and gas revenues while revenues from oil
and natural gas liquids totaled $54.7 million. Oil and gas revenues in 2001
increased 21% over the prior year due to a slight increase in production and
substantially higher prices.
TRANSPORTATION, PROCESSING AND MARKETING
Transportation, processing and marketing revenues are comprised of fees
for the transportation and processing of gas as well as oil and gas marketing
income. Transportation, processing and marketing revenues decreased 35% in 2001
to $3.4 million primarily as a result of the sale of the Sterling Plant in April
2000 and lower NGL prices.
The Company's gas transportation and processing assets include (i) 50%
ownership in approximately 4,600 miles of gas pipelines in Appalachia held
through Great Lakes and (ii) a number of smaller gathering systems associated
with the Company's producing properties. The Appalachian gathering systems
transport a majority of Great Lakes' gas production as well as third party gas
to major trunklines and directly to end-users. Third parties who transport gas
through the systems are charged a fee based on throughput. In the Southwest and
Gulf Coast regions gas production is transported through a combination of
Company-owned and third party gathering systems. The Company is typically
charged a fee based on throughput to transport its gas through third party
systems.
The Company markets its own gas production and attempts to reduce the
impact of price fluctuations through hedging. Only 2% of gas production is
currently sold pursuant to fixed price contracts at prices ranging from $1.25 to
$4.73 per mcf (averaging $3.80 per mcf). The remaining 98% of gas production is
sold at market (generally index) related prices.
HEDGING ACTIVITIES
The Company regularly enters into hedging agreements to reduce the
impact on its operations of fluctuations in oil and gas prices. All such
contracts are entered into solely to hedge prices and limit volatility. The
Company's current policy is to hedge between 50% and 75% of its production, when
futures prices justify, on a rolling twelve to eighteen month basis. Due to the
exceptional gas prices in 2001, the Company extended their hedging program into
2005. At December 31, 2001, hedges were in place covering 47.3 Bcf at prices
averaging $4.02 per mcf and 700,000 barrels of oil averaging $25.97 per barrel.
Their fair value, excluding hedge contracts with Enron North America Corp.
("Enron"), represented by the estimated amount that would be realized on
termination, approximated a net unrealized pre-tax gain of $52.1 million at
December 31, 2001, which is presented on the balance sheet as a short-term gain
of $37.2 million and a long-term gain of $14.9 million based on contract
expiration. The contracts expire monthly through December 2005 and cover
approximately 55%, 30%, 15% and 5% of anticipated 2002 through 2005 production
from proved reserves, respectively. Gains or losses on both realized and
unrealized hedging transactions are determined as the difference between the
contract price and a reference price, generally NYMEX. Transaction gains and
losses are determined monthly and are included as increases or decreases in oil
and gas revenues in the period the hedged production is sold. Any ineffective
portion of such hedges is recognized in
6
earnings as it occurs. Net pre-tax losses relating to these derivatives in 1999,
2000 and 2001 were $10.6 million, $43.2 million, and $6.2 million, respectively.
Over the last three years, the Company has recorded cumulative net pre-tax
hedging losses of $60.0 million in income, which, when combined with the $52.1
million unrealized pre-tax gain at year-end 2001, result in a $7.9 million
cumulative net loss. Effective January 1, 2001, the unrealized gains (losses) on
these hedging positions are recorded at an estimate of fair value which the
Company bases on a comparison of the contract price and a reference price,
generally NYMEX, on the Company's balance sheet as Other comprehensive income
(loss) ("OCI"), a component of Stockholders' Equity.
The Company had hedge agreements with Enron for 22,700 Mmbtus per day,
at $3.20 per Mmbtu covering the first three months of 2002. Amounts due from
Enron are not included in the open hedges described in the previous paragraph.
Based on accounting regulations, the Company has recorded an allowance for bad
debts at year-end 2001 of $1.4 million, offset by a $318,000 ineffective gain
included in income and $1.0 million gain included in OCI at year-end 2001
related to these amounts due from Enron. The gain included in OCI at year-end
2001 will be included in income in the first quarter of 2002. The last of the
Enron contracts will expire in March 2002.
INDEPENDENT PRODUCER FINANCE ("IPF")
IPF provides capital to small oil and gas producers to finance
acquisition and development projects in exchange for term overriding royalty
interests. The overrides are dollar-denominated and calculated to provide a
contractual rate of return that typically ranges between 15% and 25%. Interest
earned on the overrides is reported as IPF revenues. Almost all of the advances
are for less than $5.0 million and most are for $2.0 million or less. IPF funds
itself through a combination of internal cash flow and bank borrowings. At
December 31, 2001, IPF's portfolio included 44 transactions having an aggregate
book value of $41.4 million (net of $17.3 million of valuation allowances). The
portfolio balance declined 15% in 2001 primarily due to $19.0 million of
repayments received during the year. The reserves underlying IPF's royalty
interests are not included in Range's consolidated reserve disclosure.
IPF provides valuation allowances against advances which may not be
recoverable. Increases and decreases in the valuation allowances are reported in
IPF expenses. IPF expenses include general and administrative costs and interest
expense, which totaled $4.9 million and $3.6 million, respectively, in 2000 and
2001. IPF recorded valuation allowances of $603,000 in early 2000. Because of
higher product prices and the resultant increase in cash receipts, IPF reversed
$1.9 million of previously reserved amounts in the second half of 2000. Due to
the continued favorable oil and gas prices, $1.8 million of increases in
receivables were also recorded as a reduction to IPF expenses in the first nine
months of 2001. However, because of lower product prices, IPF increased its
reserve allowance by $2.0 million in the fourth quarter of 2001. At year-end
commodity prices, the Company believes that IPFs valuation allowances were
adequate.
IPF has two petroleum engineers with an average of 19 years of
experience who identify and evaluate projects. The staff is responsible for
defining transaction risk, assessing reserve coverage and negotiating terms.
Transactions are structured to minimize risk by focusing on asset coverage and
taking direct title to the royalty interests. As dollar-denominated royalties,
the transactions leave a portion of the commodity price risk with the producer.
However, when extreme price declines occur, as they did in 1998 and 1999, IPF is
exposed to substantial losses.
IPF provides capital to parties who are generally ignored by
traditional financial institutions. These producers are typically denied access
to financing because: (i) they are too small to access the public securities
markets; (ii) private equity and debt financing is too restrictive and
expensive; and (iii) few commercial banks are interested in small energy loans
as consolidation in the banking industry has raised the size threshold for
lending. IPF's portfolio decreased in 2001 as a limited number of fundings were
more than offset by principal repayments. IPF's bank debt is non-recourse to
Range.
IPF investments involve the purchase of a term overriding royalty
interest pursuant to which it receives a specified share of revenues from
specific properties. The producer's obligation is non-recourse unless he fails
to operate prudently, there is title failure and in certain other circumstances.
Consequently, IPF's success is based on its ability to accurately estimate
reserves underlying its royalty, the prices at which the production will be
sold, and the operator's ability to recover the reserves on a timely and cost
efficient basis. Because the override is considered a property interest, if a
producer goes bankrupt, IPF's interest should be beyond the reach of creditors.
If a creditor, the producer as debtor-in-possession or a trustee in a bankruptcy
proceeding were to argue successfully that the transaction should be
characterized as a loan, IPF may have only a creditor's claim for repayment.
IPF's ownership in these production payments is a non-operated interest. While
IPF is unlikely to be exposed to liabilities associated with direct working
interests, such as environmental matters, personal injuries or death and
property damage, such events could result in a loss of IPF's economic interest
in the properties. The producer's obligation to deliver a specified share of
revenues to IPF is subject to the ability of the burdened reserves to produce
such revenues. As a result, IPF bears the risk that revenues will not be
sufficient to amortize its investment or provide an acceptable return.
7
IPF was acquired in 1998. The following table summarizes IPF's
historical investments:
Year Ended December 31,
-------------------------------------------------------
1997 1998 1999 2000 2001
------- ------- ------- ------- -------
Total advances ($000) $40,150 $45,822 $ 4,259 $ 6,985 $11,629
Number of advances 39 75 30 26 32
Average advance ($000) $ 1,029 $ 611 $ 142 $ 269 $ 363
INTEREST AND OTHER
The Company earns interest on cash balances and certain receivables.
Interest and other income in 2000 was comprised principally of losses on
property sales. The Company expects to continue to sell non-strategic
properties. In 2001, Interest and other income also includes ineffective hedging
gains or losses. The 2001 period included $2.3 million of the ineffective
hedging gains and a $689,000 gain on asset sales partially offset by a $1.7
million writedown of marketable securities and a $1.4 million bad debt expense
related to the Enron hedges. Interest and other income in 2001 amounted to
$490,000, representing 0.2% of revenues.
COMPETITION
The Company encounters substantial competition in acquiring oil and gas
leases, marketing its production, securing personnel and conducting drilling and
field operations. Competitors in development, exploration, acquisitions and
production include the major oil companies as well as numerous independents,
individual proprietors and others. Many competitors have financial and other
resources substantially exceeding those of the Company. 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 will depend on its ability to identify and acquire
suitable producing properties and prospects for future drilling.
Acquisitions have generally been financed through the issuance of debt
and equity securities and internally generated cash flow. There is competition
for capital to finance oil and gas projects. The ability of the Company to
obtain financing on satisfactory terms is uncertain and can be affected by
numerous factors beyond its control. The inability of the Company to raise
external capital in the future could have a material adverse effect on its
business.
The Company currently has three issues of debt outstanding in addition
to its bank debt. The 8.75% senior subordinated notes, 6% convertible debentures
and 5.75% trust preferred had a combined book value of $198.4 million at
December 31, 2001. Their combined fair market value, based on market quotes, was
$148.5 million. The Company has in the past and expects to continue in the
future to exchange equity for these debt instruments. Such exchanges could have
a dilutive effect on existing shareholders.
GOVERNMENTAL REGULATION
The Company's operations are affected in varying degrees by federal,
state and local laws and regulations. In particular, oil and gas production and
related operations are or have been subject to price controls, taxes and other
laws and regulations. Failure to comply with such laws and regulations can
result in substantial penalties. The regulatory burden on the 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 precisely predict the future cost or
impact of complying.
THE RESTRUCTURING
A series of significant acquisitions financed principally with debt and
convertible securities were completed between late-1997 and mid-1998. Due to the
poor performance of the acquired properties compounded by a decline in oil and
gas prices which began in late 1997, the Company was forced to take a number of
steps. These included a workforce reduction, a significant decrease in capital
expenditures, the sale of assets, the formation of Great Lakes and the exchange
of common stock for fixed income securities. Between year-end 1998 and December
31, 2001, these initiatives reduced parent company bank debt from over $365.0
million to $95.0 million. Total debt, including trust preferred, has been
reduced 46% to $392.2
8
million. While the Company believes its financial position has stabilized,
management believes debt remains too high. To return to its historical posture
of consistent profitability and growth, the Company believes it should further
reduce debt. The Company expects to utilize excess cash flow to retire debt and
to continue to exchange additional stock for indebtedness. Stockholders could be
materially diluted if a substantial amount of fixed income securities are
exchanged for stock. Since 1998, 8.2 million shares of common stock have been
issued in exchange for debt and 5.4 million shares have been exchanged for $2.03
preferred stock for a total of 13.6 million shares. The shares were exchanged
for $56.7 million face value of 8.75% senior subordinated notes, 6% convertible
debentures, 5.75% trust preferred securities and $28.7 million of $2.03
preferred stock for a total of $85.4 million. The extent of any future dilution
will depend on a number of factors, including the number of shares issued, the
price at which stock is issued or any newly issued securities are convertible
into common stock and the price at which fixed income securities are reacquired.
While such exchanges reduce existing stockholders' proportionate ownership,
management believes they enhance financial flexibility and will ultimately
increase the value of the Company's stock.
The Company believes it has sufficient liquidity and cash flow to meet
its obligations. However, a material decline in oil and gas prices or a
reduction in production and/or reserves would reduce its ability to fund capital
expenditures, meet financial obligations and reduce leverage. In addition, the
Company's high depletion depreciation and amortization ("DD&A") rate may make it
difficult to remain profitable if oil and gas prices decline further.
ENVIRONMENTAL MATTERS
The Company's 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 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 transporting through pipelines,
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
operations. In addition, these laws, rules and regulations may restrict the rate
of production. The regulatory burden on the oil and gas industry increases the
cost of doing business and affects profitability. Changes in environmental laws
and regulations occur frequently, and 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 industry in
general. Management believes the Company is in substantial compliance with
current applicable environmental laws and regulations. The Company has not
experienced any material adverse effect from compliance with environmental
requirements, there is no assurance that this will continue. The Company did not
have any material capital expenditures in connection with environmental matters
in 2001, nor does it anticipate that such expenditures will be material in 2002.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), 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 of
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. 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 that such wastes may become subject to
liability and regulation under CERCLA. State initiatives to further regulate the
disposal of oil and gas wastes are pending in certain states and these
initiatives could have a significant impact on the Company.
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 National
Pollutant Discharge Elimination System general permits applicable to the oil and
gas industry generally prohibit the discharge
9
of produced water, sand and some other substances into coastal waters. The cost
to comply with zero discharges mandated under federal and state law have not had
a material adverse impact 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 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.
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.
Stricter standards in environmental legislation may be imposed on 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 gas
exploration and production wastes as "hazardous wastes" and make the waste
subject to more stringent handling, disposal and clean-up restrictions. If such
legislation were enacted, it could have a significant impact on the Company's
operating costs, as well as the industry in general. Compliance with
environmental requirements generally could have a material adverse effect on 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.
RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE SAFE HARBOR PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Certain information included in this report, other materials filed or
to be filed by the Company with the Securities and Exchange Commission ("SEC"),
as well as information included in oral statements or other written statements
made or to be made by the Company contain or incorporate by reference certain
statements (other than statements of historical fact) that constitute
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used
herein, the words "budget," "budgeted," "assumes," "should," "goal,"
"anticipates," "expects," "believes," "seeks," "plans," "estimates," "intends,"
or "projects" and similar expressions that convey the uncertainty of future
events or outcomes are intended to identify forward-looking statements. Where
any forward-looking statement includes a statement of the assumptions or bases
underlying such forward-looking statement, we caution that while we believe
these assumptions or bases to be reasonable and to be made in good faith,
assumed facts or bases almost always vary from actual results and the difference
between assumed facts or bases and the actual results could be material,
depending on the circumstances. It is important to note that our actual results
could differ materially from those projected by such forward-looking statements.
Although we believe that the expectations reflected in such forward-looking
statements are reasonable and such forward-looking statements are based upon the
best data available at the date this report is filed with the SEC, we cannot
assure you that such expectations will prove correct. Factors that could cause
our results to differ materially from the results discussed in such
forward-looking statements include, but are not limited to, the following:
production variance from expectations, volatility of oil and gas prices, hedging
results, the need to develop and replace reserves, the substantial capital
expenditures required to fund operations, exploration risks, environmental
risks, uncertainties about estimates of reserves, competition, litigation,
government regulation, political risks, and our ability to implement our
business strategy. All such forward-looking statements in this document are
expressly qualified in their entirety by the cautionary statements in this
paragraph.
With the previous paragraph in mind, you should consider the following
important factors that could cause actual results to differ materially from
those expressed in any forward-looking statement made by the Company or on its
behalf.
10
Common shareholders will be diluted if additional shares are issued
The Company has filed shelf registration statements which allow it to
issue additional common stock and the Company has exchanged common stock for its
fixed income securities over the past three years. In 1999, 2000 and 2001, the
Company exchanged common stock for 5-3/4% trust convertible preferred
securities, 6% convertible debentures, 8.75% senior subordinated notes and $2.03
convertible preferred stock. The exchanges were made based on the relative
market value of the common stock and the convertible securities at the time of
the exchange, incorporating negotiated terms ranging from a 10% discount to a 4%
premium, in 2001. In 2001, the convertible securities were acquired at discounts
to their face value ranging from 4% to 44%. During 2000, $25.0 million of trust
preferred, $13.8 million of 6% convertible debentures and $23.2 million of $2.03
convertible preferred stock was acquired in exchange for common stock. During
2001, $2.9 million of trust preferred, $5.7 million of 6% convertible
debentures, $5.4 million of $2.03 convertible preferred stock and $3.4 million
of 8.75% senior subordinated notes was acquired in exchange for common stock.
Since 1998, $85.4 million face value of convertible securities have been
exchanged for 13,568,000 shares of common stock. See Notes 7 and 10 to the
financial statements. While the exchanges reduce interest expense, dividends and
future repayment obligations, the larger number of common shares outstanding
have a dilutive effect on existing shareholders. The Company's ability to
repurchase additional convertible securities is limited by the parent credit
facility and the 8.75% senior subordinated notes restricted payment baskets. As
of December 31, 2001, the Company has only $3.0 million available under the most
restrictive basket. The amount of the restrictive baskets limit the Company's
flexibility in repurchasing debt securities at attractive discounts to par, when
they become available. Therefore, the Company may seek changes in these
covenants.
The Company continues to review alternatives to further strengthen its
balance sheet and to retire debt and convertible securities. Several
alternatives involve the issuance of a large number of shares of common stock.
Therefore, such alternatives could materially dilute current shareholders. The
Company expects to continue to exchange common stock or other equity linked
securities for its fixed income securities. While the Company anticipates
reacquiring fixed income securities at a discount to face value, existing
stockholders will be substantially diluted if material portions of the fixed
income securities are exchanged. The extent of dilution will depend on various
factors, including the number of shares issued, the price at which newly issued
securities are convertible into common stock and the price at which fixed income
securities are reacquired. While such exchanges reduce existing stockholders'
proportionate ownership, management believes they enhance financial flexibility
and will ultimately increase the market value of the Company's common stock. The
Company's ability to consummate exchanges and the terms of the exchanges is
dependent on a number of factors beyond its control, such as the level of
various interest rates, the willingness of other parties to engage in
transactions, state and federal regulations covering such transactions and
capital market conditions.
Dividend restrictions
Restrictions on the payment of dividends and other restricted payments
as defined are imposed under the Company's bank credit agreements and the 8.75%
senior subordinated notes. No common dividends may be paid under the current
bank agreement. Partially in response to these restrictions, a new $2.03
Convertible Exchangeable Preferred Stock Series D was authorized in September
2000. The Series D had terms substantially identical to the previously
outstanding Series C except that dividends could be paid in common stock. In
November 2000, 91% of the Series C was exchanged for Series D. In December 2000,
62% of the Series D was exchanged for common stock and the Company elected to
pay fourth quarter 2000 Series D dividends in common stock. Fourth quarter 2000
dividends paid on the Series C amounted to only $10,000. During 2001, all
remaining shares of Series D and all remaining shares of Series C were
repurchased or exchanged for common stock.
The terms of the 8.75% senior subordinated notes limited restricted
payments (including dividends) to the greater of $20.0 million or a formula
based on earnings since the issuance of the notes. Given the Company's losses
over the past few years, the formula provides no availability. Therefore, the
Company must rely on the $20.0 million basket. At December 31, 2001, only $3.0
million of the $20.0 million basket remained available. The covenant limits the
Company's flexibility in continuing to reduce debt. The Company may attempt to
change this basket restriction.
Oil and gas prices are volatile, which can adversely affect cash flow available
for reinvestment
The oil industry is cyclical and prices for oil and gas are volatile.
Historically, the industry has experienced severe downturns characterized by
oversupply and/or weak demand. Many factors affect oil and gas prices including
general economic conditions, consumer preferences, discretionary spending
levels, interest rates and the availability of capital to the industry. In 1998
and early 1999, oil and gas prices fell substantially, which contributed to the
substantial losses reported by the Company in those years. By early 2001, oil
and gas prices reached levels substantially above their historical norm. Since
11
that time, prices have declined significantly. Decreases in oil and gas prices
from current levels could adversely affect the Company's revenues, net income,
cash flow and proved reserves. Significant and prolonged price decreases could
have a materially adverse effect on the Company's operations and limit its
ability to fund capital expenditures. To help limit this risk, the Company has
entered into hedging agreements covering approximately 55% and 30% of its
anticipated production from proved reserves on an mcfe basis for 2002 and 2003,
respectively and lesser amounts of 2004 and 2005 production. However, if prices
rise above the level at which the hedges were entered into, they would limit the
benefit of the rise in prices.
Hedging activities expose us to certain risks
We enter into hedging arrangements covering a portion of our future
production to limit volatility and increase the predictability of cash flow.
Hedging instruments are generally fixed price swaps but have at times included
or may include collars, puts and options on futures. While hedging limits our
exposure to adverse price movements, hedging limits the benefit of price
increases and is subject to a number of risks, including the risk the
counterparty to the hedge may not perform.
Estimates of oil and gas reserves may change; we may not replace production
The information on proved oil and gas reserves included in this
document are simply estimates. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological
interpretation and judgment, assumptions used regarding quantities of oil and
gas in place, recovery rates and future prices for oil and gas. Actual prices,
production, development expenditures, operating expenses and quantities of
recoverable oil and gas reserves will vary from those assumed in our estimates,
and such variances may be significant. If the assumptions used to estimate
reserves later prove incorrect, the actual quantity of reserves and future net
cash flow could be materially different from the estimates used herein. In
addition, results of drilling, testing and production along with changes in oil
and gas prices may result in substantial upward or downward revisions.
Between late 1997 and mid-1998, a series of large acquisitions were
consummated which proved extremely disappointing. Production from the acquired
properties fell more rapidly than anticipated and further development results
were far less attractive than projected in the acquisition engineering. The
steep decline in energy prices, which began in late 1997, combined with the less
than expected performance caused certain downward reserve revisions in 1998. In
1999, a series of exhaustive field performance studies were conducted and the
properties were re-engineered. The studies included a complete review of 1997
and 1998 capital expenditures and development results, a re-examination of
estimates of reservoir thickness, oil and gas in place, ultimate recoverable
reserves and the relationship of pressures and production declines to these
estimates. Reserve reductions were recorded in 1999, based primarily on
performance and a reassessment of the size of the reservoirs offset to a minor
degree by upward revisions due to price increases. The 1999 development program
in these fields was in part designed to confirm revised engineering forecasts.
Downward revisions at year-end 2000 represented what is believed to be the final
integration of the field studies, 1999 and 2000 development results, pressure
data and production declines. Adjustments at year-end 2000 involved removing
from proved reserves drilling and recompletion locations that, based on
perceived risk, will probably not be drilled. A downward revision that occurred
at year-end 2001 is unlike the previous revisions the Company has experienced.
Previous revisions were associated with the disappointing performance of the
properties that were acquired during the late 1990's. The entire reserve
revision in 2001 is associated with the dramatic reduction in commodity prices
between year-end 2000 and year-end 2001. The approximate 73% reduction in gas
price on the Company's proved reserves, which are 76% gas by reserve volume,
resulted in a significant revision. If there had been no change in commodity
prices, the Company would have experienced a slightly positive revision. While
there can be no assurance that future reserve revisions will not occur,
management believes that it has fully assessed all data available through this
date. That assumption is supported by the fact that performance in the fields
appears to have stabilized.
Without success in exploration, development or acquisitions, our
reserves, production and revenues from the sale of oil and gas will decline over
time. Exploration, the continuing development of our properties and acquisitions
all require significant expenditures as well as expertise. If cash flow from
operations proves insufficient for any reason, we may be unable to fund
exploration, development and acquisitions at levels we deem advisable.
Our oil and gas properties' carrying value have been and may continue to be
written down
Accounting rules require that the carrying value of oil and gas
properties be periodically reviewed for possible impairment. An "impairment" is
recognized when the book value of a proven property is greater than the expected
undiscounted future cash flows from that property and on acreage when the
assessment of fair value is less than the book value. We may be required to
write down the carrying value of a property based on oil and gas prices at the
time of the impairment review, as well as a continuing evaluation of development
results, production data, economics and other factors.
12
While an impairment charge does not impact cash or cash flow from operating
activities, it reduces earnings, increases leverage ratios and reflects the
long-term ability to recover a prior investment.
Based primarily on the poor performance of certain properties acquired
between late-1997 and mid-1998 and significantly decreased oil and gas prices,
impairments of $215 million in 1998 and $29.9 million in 1999 were recorded. In
2000, no impairments were required. At year-end 2001, an impairment of $31.1
million was recorded. (See Management's Discussion and Analysis - Results of
Operations.) For a further discussion of accounting policies related to oil and
gas properties, see Note 3 to the Consolidated Financial Statements.
We could incur substantial environmental liabilities
Our industry is subject to numerous federal, state and local laws and
regulations relating to the environment. We may incur significant costs and
liabilities in complying with existing or future environmental laws and
regulations. It is possible that increasingly strict environmental laws,
regulations and enforcement policies or claims for damages to property,
employees, other persons and the environment resulting from current or
discontinued operations, could result in substantial costs and liabilities in
the future. For additional information concerning environmental matters, see the
"Business-Environmental Matters."
Our activities involve operating hazards and uninsured risks
While we maintain insurance against certain of the risks associated
with our operations, including, but not limited to, explosion, pollution and
fires, an event against which we are not fully insured could have a significant
negative effect on our business. Such occurrences could include title defects on
properties, lost equipment in drilling operations when the drilling contractor
is not responsible for such loss, costs to redrill wells due to down hole
equipment and casing failures, and property damage caused over a period of time
not covered by standard industry insurance policies.
We maintain insurance in amounts and areas of coverage normal for a
company of our size and industry. These include, but are not limited to,
workers' compensation, employers' liability, automotive liability and general
liability. In addition, umbrella liability and operator's extra expense policies
are maintained. All such insurance is subject to normal deductible levels. We do
not insure against all risks associated with our business either because
insurance is unavailable or because we elect not to insure due to cost or other
considerations.
Individuals or companies who feel the Company or those acting on its
behalf damaged them physically or financially, have the right under the law to
seek recovery in court. In today's legal climate, the likelihood of suits
continues to increase. As verdicts or judgments are so uncertain, the Company
may elect to settle claims. Settlements may not be covered by insurance and
costs might have to be borne solely by the Company. Even when the Company elects
to contest a claim, it may be held liable by the courts. Often, the cost of
defending oneself or one's rights cannot be recovered from the other parties
even if you prove successful and the costs must be borne solely by the Company.
Such costs and settlements could have a material adverse effect on the Company's
financial position. See Item 3 "Legal Proceedings" included in this report and
Note 9 to Consolidated Financial Statements as to certain proceedings and
contingencies.
We are subject to financing and interest rate exposure risks
Our business and operating results can be harmed by factors such as the
availability and cost of capital, increases in interest rates, changes in the
tax rates, market perceptions of the oil and gas industry or the Company, or a
reduction in credit rating. These changes could cause our cost of doing business
to increase, limit our ability to pursue opportunities and place us at a
competitive disadvantage. At December 31, 2001, the Company had a portion of its
borrowings subject to interest rate swap agreements. See Note 8 to the financial
statements.
We face considerable competition
We face competition in every aspect of our business, including, but not
limited to, acquiring reserves, leases, obtaining goods, services, and employees
needed to operate and manage the Company, and marketing oil and gas. Competitors
include multinational oil companies, independent production companies and
individual producers and operators. Many of our competitors have greater
financial and other resources than we do.
13
The oil industry is subject to extensive regulation
The oil industry is subject to various types of regulations in the
United States by local, state and federal agencies. Legislation affecting the
industry is under constant review for amendment or expansion, frequently
increasing the regulatory burden. Numerous departments and agencies, both state
and federal, are authorized by statute to issue rules and regulations binding on
the industry and participants in it. Compliance with such rules and regulations
is often difficult and costly and may carry substantial penalties for
non-compliance. As the regulatory burden on the industry increases, the cost of
complying affects profitability. Generally these burdens do not appear to affect
the Company to any greater or lesser extent than other companies in the industry
with similar types and quantities of properties in the same areas of the
country.
Our high fixed charge burden could impact our liquidity, profitability and cash
flow
The Company pays significant interest charges associated with its bank
debt, 8.75% senior subordinated notes, 6% convertible debentures and 5.75% trust
preferred. The Company's bank debt is at floating interest rates and the other
debt securities are at fixed interest rates. At December 31, 2001, the face
value of the Company's fixed rate obligations totaled $198.4 million and the
annual associated interest payments, based on rates in effect at that date
totaled $13.9 million a year.
In addition, these obligations have certain requirements that the
Company must meet to avoid the acceleration of the maturity of these
instruments. See Note 7 to the Consolidated Financial Statements for their
stated maturities. The acceleration of the maturity of one or more of such
obligations could have a material adverse effect on the Company.
The Company's significant debt burden could have other important
consequences such as, but not limited to, requiring the sale of assets at
unfavorable prices, the impact of an increase in interest rates which would
increase financing costs and limit capital available for developing and
acquiring new properties, limit the ability to raise capital in the equity
and/or debt markets, preclude financing options available to less leveraged
companies, and make the Company more vulnerable to losses during periods of low
oil and gas prices.
Risks associated with IPF
IPF purchases term overriding royalty interests through which it
receives an agreed upon share of revenues from certain properties. The
producer's obligation to deliver revenues to us is non-recourse. Consequently,
IPF can only recover its investment and a return through revenues from those
properties. These revenues are subject to our ability to accurately estimate
reserves and production rates and the operator's ability to produce and recover
these reserves. In summary, IPF bears the risk that future revenues it receives
will be insufficient to amortize the price paid for its overrides or to provide
an acceptable return. IPF's production, on a net equivalent barrel basis, is
more than 80% oil. Any further decline in oil prices, may cause additional
increases in the IPF valuation allowance.
Acquisitions are subject to numerous risks
It generally is not feasible to review in detail every individual
property acquired. Ordinarily, a review is focused on higher-valued properties.
However, even a detailed review of all properties and records may not reveal
existing or potential problems, nor will it permit us to become sufficiently
familiar with the properties to assess fully their deficiencies and
capabilities. We do not always inspect every well we acquire, and environmental
problems, such as groundwater contamination, are not necessarily observable even
when an inspection is performed. In late 1997 and 1998, a series of acquisitions
were consummated which proved extremely unsuccessful. Ongoing results showed the
potential of the properties was far less than our engineering and geological
review, as well as a review by one of our independent petroleum engineering
firms, had suggested.
Our Chairman has an interest in another oil and gas company that could compete
with us
Our Chairman also serves as the Chairman and Chief Executive Officer of
Patina Oil & Gas Corporation, a publicly traded oil and gas company in which he
is a significant investor. He is also an officer, director and/or significant
investor in several other public and private companies engaged in various
aspects of the energy industry. We currently have no business relationship with
any of these companies, none of them owns our securities nor do we hold any of
theirs. Historically, no material conflict has arisen with regard to these
companies. However, conflicts of interests may arise. Board policies are in
place that require Mr. Edelman, along with all other officers and directors, to
give us notification of any potential conflicts that arise. However, we cannot
assure you that we will not compete with one or more of these companies,
particularly for acquisitions, or encounter other conflicts of interest in the
future.
14
Success depends on key members of our management
The Company's success is highly dependent on its senior management
personnel, of which only one is currently subject to an employment contract. The
loss of one or more of these individuals could have a material adverse effect on
the Company.
EMPLOYEES
As of January 1, 2002, the Company had 141 full time employees, 54 of
whom were field personnel. None are covered by a collective bargaining
agreement. Management believes its relationship with employees is good.
ITEM 2. PROPERTIES
On December 31, 2001, the Company held working interests in 9,719 gross
(4,743 net) productive wells and royalty interests in an additional 215 wells.
Including its 50% share of Great Lakes' reserves, its properties contained, net
to its interest, estimated proved reserves of 389 Bcf of gas and 21 million
barrels of oil and NGL or a total of 513 Bcfe.
PROVED RESERVES
The following table sets forth estimated proved reserves over the past
five years.
December 31,
-----------------------------------------------------------
1997 1998 1999 2000 2001
------- ------- ------- ------- -------
Natural gas (Mmcf)
Developed 369,786 436,062 299,437 305,796 276,162
Undeveloped 204,632 197,255 144,346 121,871 112,765
------- ------- ------- ------- -------
Total 574,418 633,317 443,783 427,667 388,927
------- ------- ------- ------- -------
Oil and NGL (Mbbls)
Developed 14,971 19,649 17,884 17,215 14,066
Undeveloped 14,803 7,480 10,933 8,787 6,613
------- ------- ------- ------- -------
Total 29,774 27,129 28,817 26,002 20,679
------- ------- ------- ------- -------
Total (Mmcfe) (a) 753,062 796,091 616,685 583,679 513,001
======= ======= ======= ======= =======
% Developed 61.0% 69.6% 66.0% 70.1% 70.3%
(a) Oil and NGL are converted to mcfe at a rate of 6 mcf per barrel.
At year-end 2001, the Company engaged the following independent
petroleum consultants to evaluate its reserves: H.J. Gruy and Associates, Inc.
(Southwest), DeGolyer and MacNaughton (Southwest and Gulf Coast), and Wright and
Company, Inc. (Appalachia). These engineers were employed primarily based on
their geographic expertise as well as their history in engineering certain
properties. At December 31, 2001, these consultants collectively evaluated
approximately 82% of the proved reserves set forth above. The remainder were
evaluated by the internal engineering staff. All estimates of oil and gas
reserves are subject to significant uncertainty.
The following table sets forth the estimated future net revenues,
excluding open hedging contracts, from proved reserves, the Present Value of
those revenues and the realized prices over the past five years (in millions).
December 31,
--------------------------------------------------
1997 1998 1999 2000 2001
------ ------ ------ ------ ------
Future net revenues $1,276 $1,020 $1,013 $3,764 $ 750
Present Value
Pre-tax 632 555 556 1,964 399
After tax 511 517 503 1,506 311
Oil price (per
barrel) $16.00 $10.26 $23.49 $24.46 $17.59
Gas price (per mcf) $ 2.79 $ 2.34 $ 2.34 $ 9.57 $ 2.70
15
Future net revenues represent future revenues from the sale of proved
reserves net of production and development costs (including production and ad
valorem taxes and operating expenses). Such calculations, prepared in accordance
with SFAS No. 69, "Disclosures about Oil and Gas Producing Activities," are
based on costs and prices in effect at December 31, 2001. Average product prices
(average of the last three days NYMEX) at December 31, 2001 were $17.59 per
barrel of oil, $12.38 per barrel for natural gas liquids, and $2.70 per mcf of
gas using benchmark NYMEX prices of $20.38 per barrel and $2.63 per Mmbtu. There
can be no assurance that the proved reserves will be produced 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 year-end.
SIGNIFICANT PROPERTIES
The Company's proved reserves at December 31, 2001 were concentrated in
three regions, Southwest, Gulf Coast and Appalachia. The Southwest is divided
into the Permian and Midcontinent divisions. The Appalachian properties
represent the Company's 50% ownership in Great Lakes. At year-end, the Company's
properties included working interests in 9,719 gross (4,743 net) productive oil
and gas wells and royalty interests in 215 additional wells. The Company also
held interests in 558,862 gross (284,028 net) undeveloped acres. The following
table sets forth summary information with respect to estimated proved reserves
at December 31, 2001.
Pre-tax Present Value
------------------------
Amount Oil & NGL Natural Gas Total
(In thousands) % (Mbbls) (Mmcf) (Mmcfe)
-------------- -------- ------- ------ -------
Southwest
Permian $111,156 28 13,065 68,550 146,940
Midcontinent 53,987 13 724 54,483 58,827
-------- -------- -------- -------- --------
Subtotal 165,143 41 13,789 123,033 205,767
-------- -------- -------- -------- --------
Gulf Coast 94,017 24 1,896 84,288 95,664
Appalachia 139,996 35 4,994 181,606 211,570
-------- -------- -------- -------- --------
Total $399,156 100 20,679 388,927 513,001
======== ======== ======== ======== ========
SOUTHWEST REGION
The Southwest region has production and field operations located in the
Permian Basin of West Texas and the East Texas Basin (the Permian division) as
well as in the Texas Panhandle and the Anadarko Basin of western Oklahoma (the
Midcontinent division.) This region represents 41% of total reserve value and
40% of its total reserve volume. Proved reserves totaled 206 Bcfe, of which 60%
was gas. The Southwest's daily production volume of 64.6 Mmcfe per day
represents approximately 42% of total daily production.
At December 2001, the Southwest region properties had a development
inventory of 176 proven recompletions and 120 proven drilling locations. Acreage
owned by the Southwest region at December 31, 2001 included 269,242 gross
(191,813 net) developed acres and 128,372 gross (107,821 net) undeveloped acres.
During 2001, 42 development wells (27.4 net) were drilled, of which 38 (24.2
net) were productive. One exploratory well (one net) was drilled which was
productive.
Permian. The Permian division's total proved reserves at December 31,
2001 contained 147 Bcfe, down 16% compared to year-end 2000. This change was due
90% to lower commodity prices year-over-year and 10% to poor well performance.
These reserves represented 29% by volume and 28% by value of total proved
reserves and were 53% oil and NGL. In the fourth quarter of 2001, net production
averaged 3,612 barrels of oil and NGLs and 23.9 Mmcf of gas per day, or 45.6
Mmcfe per day in total. On an annual basis, production increased 1% to 47.6
Mmcfe per day. Producing wells total 1,347 (1,046 net), of which the Company
operates approximately 90%. At December 31, 2001, the Permian division had a
development inventory of 148 proven recompletions and 108 proven drilling
locations. Acreage owned by the Permian division at December 31, 2001 included
68,922 gross (64,673 net) developed acres and 113,561 gross (96,890 net)
undeveloped acres. In 2001, $24.9 million of capital funded the drilling of 21
development wells (14.4 net), 18 (12.2 net) were productive and one exploratory
well (one net) which was productive. During the year, the division achieved an
86% drilling success rate.
16
In East Texas, the Permian division participated in the drilling of two
gross (0.4 net) horizontal wells in the James Lime formation, a fractured
carbonate. Both wells were successfully completed for combined initial rates of
13 (3.5 net) Mmcfe per day. Also in East Texas, the Company drilled its first
Bossier sand test (the Linder #1). The well was unsuccessful in the Bossier
formation at depths ranging from 11,500 to 12,500 feet. However, the Linder #1
was successfully recompleted uphole in the Travis Peak formation yielding rates
of 3.0 (2.5 net) Mmcfe per day. To date, Range has accumulated an acreage
position in East Texas totaling 34,600 (11,000 net) acres in the horizontal
James Lime play and 31,600 (21,400 net) acres in the Bossier sand play. Further
Bossier drilling has been deferred, pending the results of a thorough technical
review; however the Company plans to continue drilling in the Travis Peak
formation. At year-end 2001, acreage in East Texas was impaired by $825,000 to
reflect the lack of success in the Bossier sand. (See Management's Discussion
and Analysis - Results of Operations.)
In West Texas, the Permian division had disappointing drilling results
in 2001 at the Powell Ranch in Glasscock County, Texas. Between 1997, when Range
acquired the property, and year-end 2000, Range drilled 11 seismically
identified locations with six successes for a 55% success rate. Of the five
wells drilled at Powell Ranch in 2001, three were dry and two were productive.
Current total net production from the field is 9.5 Mmcfe per day.
In other West Texas drilling, 5 gross (5 net) wells successfully
drilled in 2001 in the Sterling Field of West Texas. Three of these wells
expanded the productive limits of this field on its eastern edge. Current total
net production from this field approximates 11.0 Mmcfe per day.
Midcontinent. In the Midcontinent division, total proved reserves at
December 31, 2001 were 58.8 Bcfe, about the same as a year earlier. In 2001,
production climbed 14% to an average of 17.0 Mmcfe per day. December 2001
production reached 19.9 Mmcfe per day as the result of successful drilling,
recompletion and workover activities. During 2001, $17.8 million of capital was
spent to drill 21 (13.0 net) development wells and to recomplete 10 (6.9 net)
wells. Twenty (12.0 net) of the development wells proved successful, resulting
in a 92% success rate.
In the Texas Panhandle, 6 (5.9 net) wells were drilled. As of December
2001, four of the wells were producing 4.5 Mmcfe per day net to Range, one of
the wells was being completed and one was abandoned as a dry hole. The most
significant completion in the Texas Panhandle was the Pioneer #1, which targeted
the Upper Morrow sands, and is producing 4 (3.2 net) Mmcfe per day. The
offsetting Pioneer #2 is currently being completed in the Upper and Lower Morrow
sands. The Saturn #1, which was the only dry hole in the area, was abandoned due
to lack of reservoir quality sand in the Upper Morrow.
In four trends in the Anadarko Basin, including the Sooner, Watonga
Chickasha, Granite Wash and Northwest Shelf, 15 (7.8 net) wells were drilled in
2001. The only dry hole in the area was the Dalton #1, which was abandoned due
to a pipe failure but later successfully redrilled. Notable in this area was the
Gemini #1, which was completed in the Granite Wash and is producing in excess of
1.5 Mmcfe (1.1 net) per day. The division plans to drill at least two offsets to
the Gemini #1 in 2002. In addition, a significant workover was performed on the
Greene #1, which increased production to 1.8 Mmcfe per day (1.4 net). An offset
to the Greene #1 is currently being drilled. The 340 (199 net) producing wells
in the Midcontinent are 92% operated.
GULF COAST REGION
The Gulf Coast region represents 24% of total reserve value and 19% of
total reserve volumes of the Company. Proved reserves totaled 95.7 Bcfe, down
13% from 110 Bcfe at year-end 2000. In 2001, the region only partially replaced
the reserves lost through property dispositions of 2.6 Bcfe and the production
of 20 Bcfe. Gulf Coast reserves are 88% natural gas. Properties are located in
the shallow waters of the Gulf of Mexico and onshore in Texas, Louisiana and
Mississippi. The region's wells are characterized by high initial rates and
relatively short reserve lives. Production by the region represented 36% of the
Company's total average daily production. Major onshore fields include Alta Mesa
in Brooks County, Texas, which produces from depths of 6,000 to 7,000 in the
Frio and Vicksburg formations, and Oakvale, in Jefferson Davis County,
Mississippi, which produces at depths ranging from 15,000 to 16,500 feet in the
Sligo and Hosston formations. Offshore properties include interests in 50
platforms in water depths ranging from 20 to 210 feet, none of which are
operated. The Gulf Coast's development inventory includes 47 recompletions and
16 drilling locations on 155,020 gross (43,277 net) developed acres and 93,388
gross (22,245 net) undeveloped acres. At year-end 2001, the Company impaired
acreage by $4.3 million and proved properties by $25.9 million in the Gulf Coast
region. (See Management's Discussion and Analysis - Results of Operations.)
17
In 2001, the region spent $23.1 million to drill 13 (4.2 net) wells,
recomplete 10 (4.1 net) others and to upgrade facilities. In addition, the
division participated in the abandonment of one platform and reduced its overall
plugging and abandonment exposure through assignment of its Chandeleur 37
facility and a property trade at West Delta 30. In the fourth quarter of 2001,
net production averaged 782 barrels of oil and 48.6 Mmcf of gas per day or 53.3
Mmcfe per day in total. On an annual basis, production declined 4% to 55.5 Mmcfe
per day due to the natural decline of mature properties. In total, the onshore
properties include 56 wells (40 net), of which 77% are operated. These operated
onshore properties represent 8.5% of the Company's pre-tax present value of the
Gulf Coast properties at December 31, 2001. During 2001, 13 development wells
(4.2 net) were drilled, of which 11 (2.7 net) were productive. Two exploratory
wells (0.3 net) were drilled, of which both were productive.
A total of $5.1 million was spent at the Matagorda Island 519 offshore
gas field, which is operated by BP Amoco. The Company has a 17% working interest
in the field's seven wells, which produce from as deep as 16,800 feet in the
lower Miocene sands. While the field is non-operated, the Company assigns
technical and operational staff to study and monitor it given its significance.
The field contributed 6% (3.3 Bcfe) of the Company's production in 2001. In
2000, the 519 L-3 well was drilled and turned to sales in December. In 2001, the
519 L-4 well was drilled and turned to sales in September. The initial flow
rates from both wells were disappointing. To address this problem, an additional
interval was opened to production in the L-3 well in September of 2001,
increasing the well's rate from 5.0 to 35.0 Mmcfe per day, for a net increase to
Range of 3.8 Mmcfe per day. A similar operation is currently in progress in the
L-4 well. No additional drilling activity is forecast for Matagorda Island 519
in 2002. The operator has historically significantly overspent its authorized
expenditures for capital projects and has consistently encountered numerous
delays in completion of those projects. Largely as a result, the Company
impaired Matagorda Island 519 by $8.1 million at year-end 2001. (See
Management's Discussion - Results of Operations.) Other offshore activity
included drilling one well each at West Cameron 206, West Cameron 192, East
Cameron 33 and Mobile 864. The four wells are currently producing at a combined
rate of 28.1 (5.3 net) Mmcfe per day.
Onshore, Range was active in the Hartburg play in Orange County, Texas
and Calcasieu Parish, Louisiana, where five wells were drilled and one is in
progress. These wells targeted Frio sands at depths of approximately 9,000 feet.
The Stephenson #1, #2 and #3 as well as the Stark #2 are all online producing at
a combined rate of 20.2 (2.0 net) Mmcfe per day. The one disappointment was the
Lawton #1, which was abandoned after the target sands proved wet. Currently the
Stephenson #4 is completing. In the Oakvale field in Mississippi, Range
completed the Polk 36-3 #1 and drilled and completed the 31-7 #1 in 2001. Both
wells have been fracture stimulated and are online at a combined rate of 5.5
(3.4 net) Mmcfe per day.
APPALACHIAN REGION
Through its 50% interest in Great Lakes Energy Partners L.L.C., the
Company's Appalachian region represents 212 Bcfe of proved reserves, or 41% by
volume and 35% by value of total proved reserves. The Appalachian Region has an
interest in 8,128 gross (3,567 net) wells and 4,600 miles of gas gathering
lines. Great Lakes sells its gas on a negotiated basis. Effective July 1, 2001,
Great Lakes began selling its gas to several different companies, including
First Energy. At December 31, 2001, Great Lakes had a development inventory of
51 proven recompletions and 1,468 proven drilling locations.
Development Projects
-------------------------------------
Recompletion Drilling
Opportunities Locations Total
------------- --------- -----
December 31, 2000 74 1,635 1,709
Drilled (8) (142) (150)
Added 13 148 161
Deleted (28) (173) (201)
------ ------ ------
December 31, 2001 51 1,468 1,519
====== ====== ======
Acreage owned by the Appalachian region at December 31, 2001 included
730,142 gross (343,019 net) developed acres and 334,102 gross (153,962 net)
undeveloped acres. During 2001, 209 development wells (86.8 net) were drilled,
of which 207 (86.0 net) were productive. Five exploratory wells (1.5 net) were
drilled, of which three (0.6 net) were productive. At December 31, 2001, Great
Lakes operated 99% of the wells. The reserves are 86% gas and produce
principally from the upper-Devonian, Medina, Clinton, Knox and Oriskany
formations at depths ranging from 2,500 to 7,000 feet. In the fourth quarter of
2001, net daily production averaged 28,915 Mmcf of gas and 869 barrels of oil
per day or a total of 34,128 mcfe per day. The region's properties, with 1,468
(663 net) proven projects at year-end, are located in the Appalachian and, to a
minor degree, the Michigan Basins of the northeastern United States. After
initial flush production, these properties are characterized by gradual decline
rates, on average, producing from 10-35 years.
18
In 2001, $22 million in capital expenditures funded the drilling of
193.0 (84.8 net) shallow development wells, 16 (5.7 net) medium depth wells, and
five (2.5 net) deep exploitation wells. In addition, capital was expended on 11
(4.2 net) recompletions as well as the purchase of 1,021 miles of 2-D and 3-D
seismic data and 48,750 acres of leasehold. Out of 209 development wells
drilled, 207 were successful. Three of the five exploration wells were also
successful, indicating an overall 98% success rate. Production during the year
averaged 32.6 Mmcfe/day net, a 4% increase. Year-end proved reserves decreased
approximately 12% to 211.6 Bcfe primarily as a result of lower pricing. At
year-end 2001, Great Lakes recorded an impairment of $99,000 on their Oceana
property.
During 2001 exploration prospects at Great Lakes consisted of activity
in the Knox Unconformity, Huntersville-Oriskany, and Trenton Black River plays.
The largest effort (14 gross/12.1 net) was directed to the Knox play in Ohio.
Great Lakes significantly increased its use of 3D seismic for the Knox
Unconformity play in Ohio shooting or acquiring over 30 square miles of data in
three separate project areas. Each of these 3D shoots yielded new discovery
wells with additional drilling opportunities. Great Lakes shot a moderate amount
of 2D seismic and drilled 3 gross (2 net) wells in the Huntersville/Oriskany
play in Pennsylvania. While all three wells were completed, initial production
rates are below expectations. In the Trenton Black River play, Great Lakes
acquired leases on over 125,000 gross acres in four major prospect areas, and
has plans for seismic and drilling in 2002. While Great Lakes successfully
established land positions in this play, our initial drilling results were
unsuccessful on all three gross (0.6 net) wells drilled in 2001.
Five major geologic plays comprise Great Lakes' exploration and
development portfolio. The two major development plays, consisting primarily of
shallow low-risk, lower impact wells include the Clinton Medina and Upper
Devonian Sandstone plays. Production from these shallower blanket-type,
tight-sand formations is characteristically long-lived with estimated ultimate
production anywhere from 150-750 Mmcf per well. The three exploration plays,
consisting of medium to deep wells with higher-risk and higher potential impact,
include the Knox Unconformity play, the Huntersville/Oriskany Sandstone play and
the Trenton Black River play. Wells drilled in the Knox Unconformity are
characterized by a relatively short well life of 10 years or less and have
reserves in the 250 Mmcf to 1 Bcf range. Production from the deeper and more
structurally complex formations such as the Oriskany is in the 500 Mmcf to 3 Bcf
range with a 15-25 year well life or greater. Recent discoveries in the
fault-related Trenton Black River play indicate per well recoveries in the 500
Mmcf to 5 Bcf range, particularly in the deeper structures of the play.
Management of Great Lakes is directed by a committee comprised of three
representatives from each of the Company and FirstEnergy. Disagreements that
cannot be resolved by the committee may be resolved through arbitration.
19
PRODUCTION
The following table sets forth total company production information for
the preceding five years (in thousands, except average sales price and operating
cost data).
Year Ended December 31,
------------------------------------------------------------
1997 1998 1999 2000 2001
-------- -------- -------- -------- --------
Restated Restated Restated
Production
Gas (Mmcf) 38,409 45,193 50,808 41,039 42,278
Crude oil (Mbbl) 1,371 2,175 2,247 2,035 1,916
Natural gas liquids (Mbbl) 423 480 412 363 326
Total (Mmcfe) (a) 49,173 61,123 66,762 55,427 55,730
Revenues
Gas $101,217 $105,509 $108,115 $118,977 $154,175
Crude oil 24,967 26,119 33,075 47,414 49,033
Natural gas liquids 3,833 3,965 4,302 6,691 5,646
-------- -------- -------- -------- --------
Total 130,017 135,593 145,492 173,082 208,854
Direct operating expenses (b) 31,481 39,001 43,074 40,552 43,430
-------- -------- -------- -------- --------
Gross margin $ 98,536 $ 96,592 $102,418 $132,530 $165,284
======== ======== ======== ======== ========
Average sales price(c)
Gas (mcf) $ 2.64 $ 2.33 $ 2.13 $ 2.90 $ 3.65
Crude oil (bbl) 18.21 12.01 14.72 23.30 25.59
Natural gas liquids (bbl) 9.06 8.26 10.44 18.43 17.33
Mcfe (a) (d) 2.64 2.22 2.18 3.12 3.75
Operating cost (mcfe)
Direct costs $ 0.57 $ 0.57 $ 0.58 $ 0.62 $ 0.66
Severance and production taxes 0.07 0.07 0.07 0.11 0.12
-------- -------- -------- -------- --------
Total $ 0.64 $ 0.64 $ 0.65 $ 0.73 $ 0.78
======== ======== ======== ======== ========
(a) Oil and NGL are converted to mcfe at a rate of 6 mcf per barrel.
(b) Includes severance and production taxes.
(c) Average sales prices are net of hedging, which increased average oil prices
in 2001 by $2.21 a barrel and decreased average gas prices by $0.25 per
mcf, respectively. In 2000, average sales prices are net of hedging, which
reduced average oil and gas prices in 2000 by $4.85 a barrel and $0.81 per
mcf, respectively.
(d) Average prices realized excluding hedging were $2.34, $3.90, and $3.86 per
mcfe, in 1999, 2000 and 2001, respectively.
PRODUCING WELLS
The following table sets forth information relating to productive wells
at December 31, 2001. The Company owns royalty interests in an additional 215
wells. Wells are classified as oil or gas according to their predominant
production stream.
Wells Average
------------------------- Working
Gross Net Interest
----- ----- --------
Crude oil 1,430 965 67%
Natural gas 8,289 3,778 46%
----- -----
Total 9,719 4,743 49%
===== =====
20
ACREAGE
The following table sets forth total acreage held by the Company at
December 31, 2001.
Acres Average
----------------------------- Working
Gross Net Interest
--------- ------- --------
Developed 1,154,304 578,109 50%
Undeveloped 558,862 284,028 51%
--------- -------
Total 1,713,166 862,137 50%
========= =======
The following table sets forth, for the preceding three years, the book
value of acreage where the Company has not yet identified proved reserves (in
thousands):
1999 2000 2001
------- ------- -------
Southwest region $50,121 $38,815 $20,906
Gulf Coast region 8,870 9,103 3,081
Appalachian region 2,821 1,605 1,743
------- ------- -------
Total $61,812 $49,523 $25,730
======= ======= =======
DRILLING RESULTS
The following table summarizes drilling activities for the past three
years.
1999 2000 2001
-------------- --------------- ---------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Development wells
Productive 43.0 20.6 173.0 82.5 256.0 112.9
Dry 3.0 1.7 6.0 4.4 8.0 5.5
Exploratory wells
Productive 1.0 0.5 9.0 2.9 6.0 1.9
Dry 3.0 0.8 7.0 1.7 2.0 0.9
Total wells
Productive 44.0 21.1 182.0 85.4 262.0 114.8
Dry 6.0 2.5 13.0 6.1 10.0 6.4
----- ----- ----- ----- ----- -----
Total 50.0 23.6 195.0 91.5 272.0 121.2
===== ===== ===== ===== ===== =====
REAL PROPERTY
The Company leases approximately 59,000 square feet of office space in
Texas and Oklahoma under standard office lease arrangements that expire at
various dates through March 2006. All facilities are believed adequate to meet
the Company's current needs and existing space could be expanded or additional
space could be leased if required.
In March 2000, a tornado struck the Company's headquarters in Fort
Worth. The Company temporarily relocated to 801 Cherry Street in Fort Worth. In
January 2001, the Company entered into a five-year lease for approximately
26,000 square feet of office space located at 777 Main Street in Fort Worth, and
moved in April 2001. The annual lease payments on this office space will average
$500,000 for the term of the lease.
The Company owns various vehicles and other equipment that 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.
21
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in various legal actions and claims arising in
the ordinary course of business. During 2001, the Company incurred approximately
$480,000 of litigation costs for such matters. In the opinion of management,
such litigation and claims are likely to be resolved without material adverse
effect on its financial position or results of operations.
In February 2000, a royalty owner filed a suit asking for a class
action certification against Great Lakes Energy Partners, LLC in the New York
Supreme Court, alleging that gas was sold to affiliates and gas marketers at low
prices, that inappropriate post production expenses reduced proceeds to the
royalty owners, and that the royalty owners' share of gas was improperly
accounted for. The action sought a proper accounting, an amount equal to the
difference in prices paid and the highest obtainable prices, punitive damages
and attorneys' fees. The case has been remanded to the state court in New York.
While the outcome is still uncertain, Great Lakes believes it will be resolved
without material adverse effect on its financial position or result of
operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during
the fourth quarter of 2001.
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 August 1998, the stock was listed
under the symbol "LOM." During 2001, trading volume averaged 339,141 shares per
day. On March 1, 2002, the closing price of the common stock was $4.78. The
following table sets forth the high and low sales prices as reported on the NYSE
composite tape over the past two years.
Average
Daily
High Low Volume
---- --- ------
2000
First quarter $ 3.44 $ 1.88 230,470
Second quarter 3.31 1.44 382,015
Third quarter 5.31 2.88 366,314
Fourth quarter 7.00 4.00 339,306
2001
First quarter 7.13 5.15 374,390
Second quarter 6.68 4.90 392,240
Third quarter 6.20 4.25 353,008
Fourth quarter 4.76 3.93 240,491
From January 1, 2002 to March 1, 2002 the common stock has traded at
prices between $4.03 and $5.09 per share. The Company's 5.75% trust preferred,
6% convertible debentures and 8.75% senior subordinated notes are not listed on
an exchange but trade over the counter. The fair value of these securities,
quoted from certain market makers, was $148.5 million or 75% of the par value of
$198.4 million.
At various times during 2001, the Company issued common stock in
exchange for fixed income securities. The shares of common stock issued in such
exchanges were exempt from registration under Section 3(a)(9) of the Securities
Act of 1933. During the fourth quarter of 2001, a total of $3.4 million face
value amount of 8.75% Subordinated Notes was exchanged for 753,601 shares of
common stock and a total of $0.5 million face value of Trust Preferred was
exchanged for 60,503 shares of common stock.
HOLDERS OF RECORD
At March 1, 2002 there were approximately 2,368 holders of record of
the common stock.
22
DIVIDENDS
Common stock dividends were initiated in 1995 and paid quarterly
through the third quarter of 1999. In the first quarter of 1999, the dividend
was reduced and in the fourth quarter of 1999 it was eliminated in connection
with continuing losses.
In September 2000, the Company authorized a $2.03 Convertible
Exchangeable Preferred Stock Series D, having terms substantially identical to
the outstanding Series C Preferred, with the exception that dividends could be
paid in common stock. In November 2000, 523,140 shares of Series C were
exchanged for Series D on a one-for-one basis. In December 2000, 323,140 shares
of Series D were exchanged for common stock. The Company elected to pay fourth
quarter 2000 Series D dividends in common stock. During 2001, all remaining
shares of Series D and all remaining shares of Series C were exchanged for
common stock or repurchased for cash. The elimination of the $2.03 Convertible
Exchangeable Preferred Stock reduced the Company's annual dividend requirement
by $2.3 million.
The payment of dividends is subject to declaration by the Board of
Directors and depends on earnings, capital expenditures and various other
factors. The bank credit facility and the 8.75% senior subordinated notes
contain restrictions on the ability to pay dividends. The bank credit facility
currently prohibits common stock dividends. Under the terms of the 8.75% senior
subordinated notes, the Company may pay restrictive payments, including
dividends, equal to the greater of: i) $20.0 million or ii) a formula which
includes earnings and losses since the issuance of the notes. Given the
Company's losses since 1997, the Company cannot make payments under the formula
and must rely on the $20.0 million basket. At December 31, 2001, $3.0 million
remained available under the basket. The Company may seek to amend this basket
covenant.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial information covering
the last five years.
As of or for the Year Ended December 31,
------------------------------------------------------------------
1997 1998 1999 2000 2001
---- ---- ---- ---- ----
(In thousands, except per share data)
Restated Restated Restated Restated
OPERATIONS
Revenues $ 145,417 $ 148,929 $ 193,047 $ 184,828 $ 219,425
Net income (loss) (23,332) (181,273) (23,542) 36,578 17,663
Earnings (loss) per share before extraordinary
items - basic (1.31) (7.11) (0.78) 0.55 0.28
Earnings (loss) per share before extraordinary
items - diluted (1.31) (7.11) (0.78) 0.54 0.28
Earnings (loss) per share - basic (1.31) (7.11) (0.71) 0.97 0.36
Earnings (loss) per share - diluted (1.31) (7.11) (0.71) 0.96 0.36
Dividends per share 0.10 0.12 0.03 -- --
BALANCE SHEET
Working capital $ (2,051) $ (8,198) $ 20,011 $ 9,665 $ 29,856
Oil and gas properties, net 623,807 653,260 570,643 553,173 533,357
Total assets 758,833 913,970 732,228 671,826 682,462
Senior debt 186,712 367,062 140,000 89,900 95,000
Non-recourse debt -- 60,100 142,520 113,009 98,801
Subordinated debt 180,000 180,000 176,360 162,550 108,690
Trust Preferred 120,000 120,000 117,669 92,640 89,740
Stockholders' equity (a) 196,950 125,669 103,238 159,944 235,621
(a) Stockholders equity includes other comprehensive income/(loss) of $370,
$292, $189, $(639) and $45,523 in 1997, 1998, 1999, 2000 and 2001,
respectively.
23
The following table sets forth summary unaudited financial information
on a quarterly basis for the two years ended December 31, 2001 (in thousands,
except per share data).
2000
-------------------------------------------------------------------------------------------------
March 31 June 30 September 30
-------------------------------------------------------------------------------------------------
As Filed Restated As Filed Restated As Filed Restated
-------- -------- -------- -------- -------- --------
Revenues $42,839 $42,951 $41,336 $40,195 $44,819 $43,455
Net income (a) 4,281 6,643 8,735 9,229 7,756 7,366
Earnings per share - basic 0.12 0.19 0.23 0.25 0.19 0.18
Earnings per share - diluted 0.12 0.19 0.23 0.24 0.19 0.18
Total assets 727,214 705,885 700,439 680,566 687,500 669,147
Senior debt 142,000 142,000 112,000 112,000 99,900 99,900
Non-recourse debt 130,619 130,619 124,516 124,516 120,012 120,012
Subordinated debt 176,060 176,060 174,810 174,810 165,660 165,660
Trust Preferred 111,490 111,490 100,240 100,240 97,340 97,340
Stockholder's equity 134,164 112,715 147,900 126,793 162,371 141,062
2000
----------------------------------------------------------------------
December 31 Total
-------------------------------------------------------------
As Filed Restated As Filed Restated
-------- -------- -------- --------
Revenues $ 58,725 $ 58,227 $ 187,719 $ 184,828
Net income (a) 17,189 13,340 37,961 36,578
Earnings per share - basic 0.42 0.34 0.99 0.97
Earnings per share - diluted 0.42 0.34 0.99 0.96
Total assets 689,165 671,826 689,165 671,826
Senior debt 89,900 89,900 89,900 89,900
Non-recourse debt 113,009 113,009 113,009 113,009
Subordinated debt 162,550 162,550 162,550 162,550
Trust Preferred 92,640 92,640 92,640 92,640
Stockholder's equity 185,207 159,944 185,207 159,944
2001
-------------------------------------------------------------------------------------------------
March 31 June 30 September 30
-------------------------------------------------------------------------------------------------
As Filed Restated As Filed Restated As Filed Restated
-------- -------- -------- -------- -------- --------
Revenues $64,202 $63,105 $59,668 $58,445 $51,671 $52,143
Net income (loss) (a) 18,512 20,053 14,740 16,968 6,689 8,198
Earnings per share - basic 0.38 0.42 0.29 0.34 0.13 0.16
Earnings per share - diluted 0.38 0.41 0.29 0.33 0.13 0.16
Total assets 676,476 658,825 712,167 695,418 739,645 584,373
Senior debt 76,800 76,800 88,800 88,800 95,000 95,000
Non-recourse debt 98,006 98,006 99,902 99,902 102,501 102,501
Subordinated debt 160,940 160,940 133,340 133,340 121,840 121,840
Trust Preferred 92,640 92,640 90,290 90,290 90,290 90,290
Stockholder's equity 175,345 151,136 243,781 222,064 266,852 247,635
2001
----------------------------------------------------------------------
December 31 Total
-------------------------------------------------------------
As Filed Restated As Filed Restated
-------- -------- -------- --------
Revenues $ 44,446 $ 45,732 $ 219,987 $ 219,425
Net income (loss) (a) (30,945) (27,556) 8,996 17,663
Earnings per share - basic (0.60) (0.54) 0.19 0.36
Earnings per share - diluted (0.60) (0.54) 0.19 0.36
Total assets 691,565 682,462 691,565 682,462
Senior debt 95,000 95,000 95,000 95,000
Non-recourse debt 98,801 98,801 98,801 98,801
Subordinated debt 108,690 108,690 108,690 108,690
Trust Preferred 89,740 89,740 89,740 89,740
Stockholder's equity 245,687 235,621 245,687 235,621
(a) Includes extraordinary gains on retirement of securities of $3.5 million,
$7.0 million, $4.3 million and $3.0 million in the first, second, third and
fourth quarters, respectively.
(b) Includes extraordinary gains on retirement of securities of $432,000 in the
first quarter. These gains were $1.6 million and a loss of $396,000 in the
second and third quarters, respectively. In the fourth quarter of 2001, the
gain on retirement of securities was $2.3 million.
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 rounding. During the fourth quarter of 2001, the Company recorded $31.1
million of impairments. (See Management's Discussion and Analysis - Results of
Operations.)
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CAPITALIZED TERMS HEREIN ARE DEFINED IN THE
FOOTNOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS CONTAINED HEREIN.)
As described in Note 2 to the consolidated financial statements, a restatement
has been made to correct previously reported financial results.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Company's discussion and analysis of its financial condition and
results of operation are based upon consolidated financial statements, which
have been prepared in accordance with accounting principles generally adopted in
the United States. The preparation of these financial statements requires the
Company to make estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses. Application of certain of the
Company's accounting policies, including those related to oil and gas revenues,
bad debts, oil and gas properties, marketable securities, income taxes and
contingencies and litigation require significant estimates. The Company bases
its estimates on historical experience and various other assumptions that are
believed to be reasonable under the circumstances. Actual results may differ
from these estimates under different assumptions or conditions. The Company
believes the following critical accounting policies affect its more significant
judgments and estimates used in the preparation of its consolidated financial
statements.
Proved oil and natural gas reserves - Proved reserves are defined by
the U.S. Securities and Exchange Commission (SEC) as those volumes of crude oil,
condensate, natural gas liquids and natural gas that geological and engineering
data demonstrate with reasonable certainty are recoverable from known reservoirs
under existing economic and operating conditions. Proved developed reserves are
volumes expected to be recovered through existing wells with existing equipment
and operating methods. Although the Company's engineers are knowledgeable of and
follow the guidelines for reserves as established by the SEC, the estimation of
reserves requires the engineers to make a significant number of assumptions
based on professional judgment. Estimated reserves are often subject to future
revision, certain of which could be substantial, based on the availability of
additional information, including: reservoir performance, new geological and
geophysical data, additional drilling, technological advancements, price changes
and other economic factors. Changes in oil and natural gas prices can lead to a
decision to start-up or shut-in production, which can lead to revisions to
reserve quantities. Reserve revisions inherently lead to adjustments of
depreciation rates utilized by the Company. The Company can not predict the
types of reserve revisions that will be required in future periods.
Successful efforts accounting - The Company utilizes the successful
efforts method to account for exploration and development expenditures.
Unsuccessful exploration wells are expensed and can have a significant effect on
operating results. Successful exploration drilling costs and all development
capital expenditures are capitalized and systematically charged to expense using
the units of production method based on proved developed oil and natural gas
reserves as estimated by the Company's engineers. The Company also uses proved
developed reserves to recognize expense for future estimated dismantlement and
abandonment costs. Costs of exploration wells in progress at year-end 2001 were
not significant.
Impairment of properties - The Company continually monitors its
long-lived assets recorded in Property, Plant and Equipment in the Consolidated
Balance Sheet to make sure that they are fairly presented. The Company must
evaluate its properties for potential impairment when circumstances indicate
that the carrying value of an asset could exceed its fair value. A significant
amount of judgment is involved in performing these evaluations since the results
are based on estimated future events. Such events include a projection of future
oil and natural gas sales prices, an estimate of the ultimate amount of
recoverable oil and natural gas reserves that will be produced from a field, the
timing of this future production, future costs to produce the oil and natural
gas, and future inflation levels. The need to test a property for impairment can
be based on several factors, including a significant reduction in sales prices
for oil and/or natural gas, unfavorable adjustment to reserves, or other changes
to contracts environmental regulations or tax laws. All of these same factors
must be considered when testing a property's carrying value for impairment. The
Company can not predict the amount of impairment charges that may be recorded in
the future.
Income taxes - The Company is subject to income and other similar taxes
in all areas in which it operates. When recording income tax expense, certain
estimates are required because: (a) income tax returns are generally filed
months after the close of its calendar year; (b) tax returns are subject to
audit by taxing authorities and audits can often take years to complete and
settle; and (c) future events often impact the timing of when income tax
expenses and benefits are recognized by the Company. The Company has deferred
tax assets relating to tax operating loss carryforwards and other deductible
differences. The Company routinely evaluates all deferred tax assets to
determine the likelihood of their realization. A valuation allowance is
recognized for deferred tax assets when management believes that certain of
these assets are not likely to be realized.
25
The Company's deferred tax assets exceed deferred tax liabilities at
year-end 2001, before considering the effects of Other comprehensive income
("OCI"). In determining deferred tax liabilities, accounting rules require OCI
to be considered, even though such income (loss) has not yet been earned. The
inclusion of OCI causes deferred tax liabilities to exceed deferred tax assets
by $4.5 million therefore, such amount is recorded as deferred tax liability at
year-end 2001 on the Company's balance sheet. The Company needs to earn
approximately $34.8 million of pre-tax income from the unrealized hedges
included in OCI at year-end before statutory taxes will be recorded on the
income statement. Due to the complexity of the accounting rules regarding taxes,
the timing of when the Company will record deferred taxes is uncertain.
The Company occasionally is challenged by taxing authorities over the
amount and/or timing of recognition of revenues and deductions in its various
income tax returns. Although the Company believes that it has adequate accruals
for matters not resolved with various taxing authorities, gains or losses could
occur in future years from changes in estimates or resolution of outstanding
matters.
Legal, environmental and other contingent matters - A provision for
legal, environmental and other contingent matters is charged to expense when the
loss is probable and the cost can be reasonably estimated. Judgment is often
required to determine when expenses should be recorded for legal, environmental
and contingent matters. In addition, the Company often must estimate the amount
of such losses. In many cases, management's judgment is based on interpretation
of laws and regulations, which can be interpreted differently by regulators
and/or courts of law. The Company's management closely monitors known and
potential legal, environmental and other contingent matters, and makes its best
estimate of when the Company should record losses for these based on information
available to the Company.
Other significant accounting policies requiring estimates include the
following: The Company recognizes revenues from the sale of products and
services in the period delivered. Revenues at IPF are recognized as earned. We
provide an allowance for doubtful accounts for specific receivables we judge
unlikely to be collected. At IPF, all receivables are evaluated quarterly and
provisions for uncollectible amounts are established. The Company records a
write down of marketable securities when the decline in market value is
considered to be other than temporary. Impairments are recorded when management
believes that a property's net book value is not recoverable based on current
estimates of expected future cash flows.
FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY AND CAPITAL RESOURCES
During 2001, the Company spent $89.4 million on development,
exploration and acquisitions. Fixed income obligations including Trust Preferred
and $2.03 Preferred, were reduced by $65.9 million. At December 31, 2001, the
Company had $3.4 million in cash, total assets of $682.5 million and a debt
(including Trust Preferred) to capitalization (including debt, deferred taxes
and stockholders equity) ratio of 63%. Available borrowing capacity on the
Company's bank lines at December 31, 2001 was $25.0 million on the Parent
Facility, $25.0 million on the Great Lakes Facility and $11.2 million on the IPF
Facility. Long-term debt (including Trust Preferred) at December 31, 2001
totaled $392.2 million and included $95.0 million of borrowings under the Parent
Facility, $75.0 million under the non-recourse Great Lakes Facility, $23.8
million under the non-recourse IPF Facility, $79.1 million of 8.75% Senior
Subordinated Notes, $29.6 million of 6% Convertible Subordinated Debentures and
$89.7 million of Trust Preferred.
During 2001, 1.8 million shares of common stock were exchanged for $2.9
million of Trust Preferred, $3.4 million of 8.75% Senior Subordinated Notes and
$5.7 million of 6% Debentures. In addition, $2.3 million of 6% Debentures, $42.5
million of 8.75% Senior Subordinated Notes and $50,000 of 5.75% Trust Preferred
were repurchased. A $4.0 million extraordinary gain net of costs was recorded as
the securities were retired at a discount. In addition, 767,000 shares of common
stock were exchanged for $5.4 million of the $2.03 Preferred and the remaining
were repurchased for $74,000. Since 1998, there have been 13.6 million shares of
common stock exchanged for $85.4 million face value of debt and convertible
preferred stock.
The Company believes its capital resources are adequate to meet its
requirements for at least the next twelve months. However, future cash flows are
subject to a number of variables including the level of production and prices as
well as various economic conditions that have historically affected the oil and
gas business. A material drop in oil and gas prices or a reduction in production
and reserves would reduce its ability to fund capital expenditures, reduce debt
and meet its financial obligations. In addition, the Company's high depletion,
depreciation and amortization rate may make it difficult to remain profitable if
oil and gas prices decline further. The Company operates in an environment with
numerous financial and operating risks, including, but not limited to, the
ability to acquire reserves on an attractive basis, the inherent risks of the
search for, development and production of oil and gas, the ability to sell
production at prices which provide an attractive return and the highly
competitive
26
nature of the industry. The Company's ability to expand its reserve base is, in
part, dependent on obtaining sufficient capital through internal cash flow,
borrowings or the issuance of debt or equity securities. There can be no
assurance that internal cash flow and other capital sources will provide
sufficient funds to maintain planned capital expenditures.
The following summarizes the Company's contractual obligations at
December 31, 2001 and their future maturities (in thousands):
Less than 1 - 3 After
1 Year Years 3 Years Total
------ ----- ------- -----
Long term debt $ -- $193,801* $198,430 $392,231
Non-cancelable operating lease obligations 820 1,560 126 2,506
-------- -------- -------- --------
Total contractual cash obligations $ 820 $195,361 $198,556 $394,737
======== ======== ======== ========
* Due at termination dates in each of the Company's credit facilities, which
the Company expects to renew, but there is no assurance that can be
accomplished.
Total long-term debt (including Trust Preferred) at December 31, 2001,
was $392.2 million. Long-term debt of $193.8 million was at floating interest
rates. Included in long-term debt was $198.4 million of debt securities which
have fixed interest charges. The table below describes the Company's required
annual fixed interest payments on these debt instruments (in thousands):
Interest Annual Interest Maturity
Security Amount Rate Interest Payable Dates
-------- ------ ---- -------- ------- -----
8.75% Sr. Sub. Notes $79,115 8.75% $6,900 January, July 2007
6% Debentures 29,575 6.00% 1,800 February, August 2007
5.75% Trust Preferred 89,740 5.75% 5,200 Feb., May, Aug., Nov. 2027
-------- -------
$198,430 $13,900
======== =======
Cash Flow
The Company's principal sources of cash are operating cash flow and
bank borrowings. The Company's cash flow is highly dependent on oil and gas
prices. The Company has entered into hedging agreements covering approximately
55%, 30%, 15%, and 5% of its anticipated production from proved reserves on an
mcfe basis for 2002, 2003, 2004 and 2005, respectively. Decreases in prices and
lower production at certain properties reduced cash flow sharply in 1998 and
early 1999 and resulted in the reduction of the Company's borrowing base.
Simultaneously, the Company sharply reduced its development and exploration
spending. While the $89.4 million of capital expenditures for 2001 were funded
entirely with internal cash flow, the amount expended was not sufficient to
replace production. The 2002 capital budget of $100.0 million is expected to
increase production 5% or more and expand the reserve base by more than
replacing production. The Company's hedge position is expected to allow the
capital program to be funded with internal cash flow even in this low price
environment. However, in such a low price environment, management expects little
reduction in long-term debt as excess internal cash flow will be limited. With
any further decrease in product prices, it would be unlikely that the Company
would be able to fund the $100.0 million capital program entirely from internal
cash flow. The Company intends to closely monitor its capital expenditure
program and results of operations in 2002; therefore, this current low price
environment may negatively affect the amount of capital spending for the year.
Net cash provided by operations in 1999, 2000 and 2001 was $50.2
million, $74.9 million and $129.6 million, respectively. Cash flow from
operations increased as higher prices and lower interest expense more than
offset increasing direct operating.
Net cash used in (provided by) investing in 1999, 2000 and 2001 was
$(98.2) million, $6.0 million and $78.2 million, respectively. In 1999, a $98.7
million source of cash from the formation of Great Lakes, $17.5 million in asset
sales and $13.2 million of IPF receipts, more than offset additions to oil and
gas properties and IPF investments. In 2000, $47.5 million of additions to oil
and gas properties, offset by $25.9 million proceeds from sales of assets and
$24.8 million of IPF repayments were included. The 2001 period included $87.0
million of additions to oil and gas properties and $11.6 million of IPF
investments, partially offset by $19.0 million of IPF receipts and $3.8 million
of asset sales.
27
Net cash used in financing in 1999, 2000 and 2001 was $146.4 million,
$79.3 million and $50.6 million, respectively. Sources of financing have been
primarily bank borrowings and capital raised through equity and debt offerings.
During 2001, recourse debt increased by $5.1 million and total debt (including
Trust Preferred) decreased by $65.9 million. The reduction in debt was the
result of applying excess cash flow, proceeds from asset sales and from
exchanges of common stock. During 2000, recourse debt decreased by $63.9 million
and total debt (including Trust Preferred) decreased by $118.5 million. The
reduction in debt was the result of applying excess cash flow and proceeds from
the sale of assets to debt repayment and exchanges of common stock for fixed
income securities. The amount of Trust Preferred outstanding decreased $2.3
million in 1999, $25.0 million in 2000 and $2.9 million in 2001 due primarily to
exchanges of such securities into common stock.
Capital Requirements
During 2001, $89.4 million of capital was expended, primarily on
development projects. This represented approximately 69% of internal cash flow.
The Company manages its capital budget with the goal of funding it with internal
cash flow. The 2002 capital budget of $100.0 million is expected to increase
production 5% or more and expand the reserve base by more than replacing
production. The Company's hedge position which covers approximately 55% of
anticipated 2002 production from proved reserves, is expected to allow the
capital program to be funded with internal cash flow even in this low price
environment. However, in such a low price environment, management expects little
reduction in long-term debt as excess internal cash flow will be limited. With
any further decrease in product prices, it would be unlikely that the Company
would be able to fund the $100.0 million capital program entirely from internal
cash flow. The Company intends to closely monitor the capital expenditure
program and results of operations; therefore, this current low price environment
may negatively affect the amount of capital spending for the year. Development
and exploration activities are highly discretionary, and, for the foreseeable
future, management expects such activities to be maintained at levels equal to
or below internal cash flow. See "Business--Development and Exploration
Activities."
Banking
The Company maintains three separate revolving credit facilities: a
$225.0 million facility at the parent company; a $100.0 million facility at IPF
and a $275.0 million facility at Great Lakes. Each facility is secured by
substantially all of the assets of the borrower. The IPF and Great Lakes
facilities are non-recourse to Range. As Great Lakes is 50% owned, half of the
borrowings on its facility are consolidated in Range's financial statements.
Availability under the facilities are subject to borrowing bases set by
banks semi-annually and in certain other circumstances. The borrowing bases are
dependent on a number of factors, primarily the lenders' assessment of future
cash flows. Redeterminations require approval of 75% of the lenders, increases
require unanimous approval.
At March 1, 2002, there was availability under each of the Company's
facilities. At the parent, a $120.0 million borrowing base was in effect of
which $16.5 million was available. At IPF, a $35.0 million borrowing base was in
effect of which $11.7 million was available. At Great Lakes, half of which is
consolidated at Range, a $200.0 million borrowing base was in effect, of which
$54.0 million was available.
Hedging
Oil and Gas Prices
The Company regularly enters into hedging agreements to reduce the
impact of fluctuations in oil and gas prices on its operations. The Company's
current policy, when futures prices justify, is to hedge between 50% and 75% of
projected production from existing proved reserves on a rolling twelve to
eighteen month basis. At December 31, 2001, hedges were in place covering 47.3
Bcf of gas at prices averaging $4.02 per mcf and 700,000 barrels of oil
averaging $25.97 per barrel. Their fair value, excluding hedge contracts with
Enron North America Corp. ("Enron"), represented by the estimated amount that
would be realized on termination, based on contract versus NYMEX prices,
approximate a net unrealized pre-tax gain of $52.1 million at December 31, 2001,
respectively. The contracts expire monthly through December 2005 and cover
approximately 55% of anticipated 2002 production from proved reserves and 30% of
2003 production from proved reserves and lesser amounts of 2004 and 2005
production. Gains or losses on open and closed hedging transactions are
determined as the difference between the contract price and a reference price,
generally closing prices on the NYMEX. Transaction gains and losses are
determined monthly and are included as increases or decreases on oil and gas
revenues in the period the hedged production is sold. Any ineffective portion of
such hedges is recognized in earnings as it occurs. Net pre-tax losses relating
to these derivatives in 1999, 2000 and 2001 were $10.6 million, $43.2 million
and $6.2 million, respectively. Over the last three years, the Company has
recorded cumulative net pre-tax hedging losses of $60.0 million in income,
which, when combined with the $52.1 million
28
unrealized pre-tax gain at year-end 2001, result in a cumulative net loss of
$7.9 million. Effective January 1, 2001, the unrealized gains (losses) on these
hedging positions are recorded at an estimate of fair value which the company
bases on a comparison of the contract price and a reference price, generally
NYMEX, on the Company's balance as OCI, a component of Stockholders' Equity.
The Company had hedge agreements with Enron for 22,700 Mmbtu's per day,
at $3.20 per Mmbtu for the first three months of 2002. Amounts due from Enron
are not included in the open hedges described in the previous paragraph. Based
on accounting regulations, the Company has recorded an allowance for bad debts
at year-end 2001 of $1.4 million, offset by a $318,000 ineffective gain included
in 2001 income and $1.0 million gain included in OCI at year-end 2001 related to
these amounts due from Enron. The gain included in OCI at year-end 2001 will be
included in income in the first quarter of 2002. The last of the Enron contracts
will expire as of March 2002.
Interest Rates
At December 31, 2001, Range had $392.2 million of debt (including Trust
Preferred) outstanding. Of this amount, $198.4 million bears interest at fixed
rates averaging 7.0%. Senior debt and non-recourse debt totaling $193.8 million
bears interest at floating rates, which averaged 4.0% at year-end 2001,
excluding interest rate swaps. At December 31, 2001, Great Lakes had $100.0
million of interest rate swap agreements, of which 50% is consolidated at Range.
Two agreements totaling $45.0 million at rates of 7.1% each expire in May 2004.
Two agreements of $10.0 million each at 6.2% in December 2002 and five
agreements totaling $35.0 million at rates of 4.8%, 4.7%, 4.6%, 4.5%, and 4.5%
expire in June 2003. The agreements expiring in May 2004 may be terminated at
the counter party's option in May 2002. The 30-day LIBOR rate on December 31,
2001 was 1.9%. A 1% increase in short-term interest rates on the floating-rate
debt outstanding at December 31, 2001 would cost the Company approximately $1.4
million in additional annual interest, net of swaps.
Capital Restructuring Program
As described in Note 1 to the Consolidated Financial Statements, the
Company took a number of steps beginning in 1998 to strengthen its financial
position. These steps included the sale of assets and the exchange of common
stock for fixed income securities. These initiatives have helped reduce Parent
company bank debt to $95.0 million and total debt (including Trust Preferred) to
$392.2 million at December 31, 2001. While the Company believes its financial
position has stabilized, management believes debt remains too high. To return to
its historical posture of consistent profitability and growth, the Company
believes it should further reduce debt. The Company currently believes it has
sufficient liquidity and cash flow to meet its obligations for the next twelve
months; however, a drop in oil and gas prices or a reduction in production or
reserves would reduce the Company's ability to fund capital expenditures and
meet its financial obligations.
INFLATION AND CHANGES IN PRICES
The Company's revenues, the value of its assets, its ability to obtain
bank loans or additional capital on attractive terms have been and will continue
to be affected by changes in oil and gas prices. Oil and gas prices are subject
to significant fluctuations that are beyond the Company's ability to control or
predict. During 2001, the Company received an average of $25.59 per barrel of
oil and $3.65 per Mcf of gas after hedging. Although certain of the Company's
costs and expenses are affected by the general inflation, inflation does not
normally have a significant effect on the Company. However, industry specific
inflationary pressures built up over an 18 month period in 2000 and 2001 due to
favorable conditions in the industry. While product prices have recently
declined, the cost of services in the oil and gas industry have not declined by
the same percentage. Any increases in product prices could cause inflationary
pressures specific to the industry to also increase.
29
RESULTS OF OPERATIONS
The following table identifies certain items included in the Company's
results of operations and is presented to assist in comparison of the last three
years. The table should be read in conjunction with the following discussions of
results of operations.
Year Ended December 31,
--------------------------------
1999 2000 2001
-------- -------- --------
(in thousands)
Restated Restated Restated
Increase/(Decrease) in Revenues:
Writedown of marketable securities $ -- $ -- $ (1,715)
Enron bad debt expense -- -- (1,352)
Gain/(Loss) from asset sales (530) (1,116) 689
Effect of SFAS 133 -- -- 2,351
Hedging gains (losses) (10,631) (43,187) (6,194)
Gain on sale - Great Lakes 30,929 -- --
-------- -------- --------
$ 19,768 $(44,303) $ (6,221)
======== ======== ========
Increase/(Decrease) in Expenses:
Provision for impairment $ 29,901 $ -- $ 31,085
Mark-to-market non-cash
compensation expense 160 3,405 (2,410)
Bad debt expense -- 615 688
Effect of SFAS 133 -- -- 1,332
Adjustment of IPF valuation allowance 564 (2,891) 122
-------- -------- --------
$ 30,625 $ 1,129 $ 30,817
======== ======== ========
Extraordinary Items:
Gain on retirement of securities $ 2,430 $ 17,763 $ 3,951
======== ======== ========
Comparison of 2001 to 2000
Net income in 2001 totaled $17.7 million compared to $36.6 million in
2000. A $17.8 million gain on retirement of securities was realized in 2000
versus $4.0 million in 2001. The fourth quarter of 2001 included an impairment
charge of $31.1 million. Production increased to 152.7 Mmcfe per day, a 1%
increase from the prior year period. Revenues benefited from a 20% increase in
average prices per mcfe to $3.75. The average prices received for oil increased
10% to $25.59 per barrel and for gas increased 26% to $3.65 per mcfe. Production
expenses increased $2.9 million to $43.4 million as a result of higher
production and property taxes, increased workover costs and slightly higher
labor and services and supplies. Therefore, operating cost per mcfe produced
averaged $0.78 in 2001 versus $0.73 in 2000.
Transportation and processing revenues decreased 35% to $3.4 million
due to the impact of the sale of a gas processing plant in June 2000 and lower
NGL prices. IPF's $6.6 million of revenues declined 7% from 2000. IPF records
income from payments on accounts with no reserve accrued against them. On
accounts with reserves, IPF reduces the carrying value of the account for
payments received and does not record income. Due to declining prices in 2001,
less income was recorded from payments received. During 2001, IPF expenses
included $1.8 million of administrative costs and $1.8 million of interest. In
2001, a favorable adjustment to IPF reserves of $1.8 million, due to favorable
prices at the time, was more than offset by a year-end increase in reserve for
doubtful accounts of $2.0 million. During 2000, IPF expenses included $1.5
million of administrative costs and $3.4 million of interest costs. In 2000, a
favorable adjustment of $1.3 million was recorded to IPF loss reserves and a
favorable $1.6 million adjustment to the reserve for doubtful accounts.
Exploration expense increased 84% to $5.9 million primarily due to
additional seismic activity and increased personnel expenses. General and
administrative expenses decreased 18% due to a decline in non-cash
mark-to-market compensation expense of $5.8 million offset by additional
personnel costs ($1.4 million), higher legal and occupancy costs ($1.2 million)
and additional costs ($600,000) incurred from having duplicate functions at
Great Lakes and Range. The average number of general and administrative
personnel increased 15% from 2000 to 2001.
30
Interest and other income increased from a loss of $722,000 in 2000 to
a gain of $490,000 in 2001. The 2001 period included $2.3 million of ineffective
hedging gains and a $689,000 gain on asset sales, partially offset by a $1.7
million writedown of marketable securities and a $1.4 million bad debt expense
related to the Enron hedges. The 2000 period included $1.1 million loss on asset
sales. Interest expense decreased 19% to $32.2 million primarily as a result of
lower average outstanding balances and falling interest rates. Average
outstandings on the Parent Facility were $124.7 million and $90.5 million for
2000 and 2001, respectively and the average interest rates were 8.8% and 6.4%,
respectively.
Depletion, depreciation and amortization ("DD&A") increased 16% to
$77.6 million as a result of the mix of production between depletion pools and
higher depletion rates. The per mcfe DD&A rate in 2001 was $1.39, a $0.18
increase from the $1.21 rate in 2000. The DD&A rate is determined based on
ending reserves (valued at prices management believed appropriate at the time)
and the net book value associated with them and to a lesser extent, depreciation
on other assets owned at year-end. The DD&A rate in the fourth quarter of 2001
was $1.60 per mcfe. The Company currently estimates that the consolidated DD&A
rate for 2002 will approximate $1.38 per mcfe.
The Company recorded a provision for impairment on acreage and proved
properties for the year ended 2001. In evaluating possible impairment, the
Company evaluates acreage on a separate basis from proved properties.
Acreage. Acreage is assessed periodically to determine whether there
has been a decline in value. If a decline is indicated, an impairment is
recognized. The Company compares the carrying value of its properties to the
assessment of value that could be recovered from sale, farm-out or exploitation.
The Company considers other additional information it believes is relevant in
evaluating the properties' fair value, such as geological assessment of the
area, other acreage purchases in the area, timing of the associated drilling
program or the properties' uniqueness. The following acreage was impaired for
the reasons indicated (in thousands):
Reason for Impairment
Acreage Pool Impairment Amount
------------ ---------- ------
Matagorda Island 519 Probability of drilling reduced based on current
assessment of risk and cost $1,704
East/West Cameron Condemned portion of leasehold through drilling or
geologic assessment 708
Offshore Other Probability of drilling reduced based on current
assessment of risk and cost 1,216
East Texas Condemned portion of leasehold through drilling 825
West Delta 30 Probability of drilling reduced based on
current assessment of risk and cost 688
------
Total $5,141
======
Proved Properties. The impairment evaluation on proven properties is
based on proved reserves. Estimated future cash flows include revenues from
anticipated oil and production, severance taxes, direct operating expenses and
capital costs. The following properties were impaired based upon an analysis of
future cash flows (in thousands):
Reason for Impairment
Property Pool Impairment Amount
------------- ---------- ------
Matagorda Island 519 Decline in gas price $ 14,401
Offshore Other Decline in gas price 3,302
Gulf Coast Onshore Decline in gas price 8,542
Oceana (GLEP) Decline in oil price 99
--------
Total $ 25,944
========
Comparison of 2000 to 1999
Net income in 2000 totaled $36.6 million, compared to a net loss of
$23.5 million in 1999. Production fell to 151,442 mcfe per day, a 17% decrease
from 1999. A 4% decrease would have been reported if the effect of the Great
Lakes transaction were eliminated. Revenues benefited from a 43% increase in
average prices per mcfe to $3.12, partially offset by the production decrease.
The average prices received for oil increased 58% to $23.30 per barrel and for
gas increased 36% to $2.90 per Mcf.
31
Production expenses fell 6% to $40.6 million largely as a result of the Great
Lakes transaction and asset sales. Operating costs per mcfe produced averaged
$0.65 in 1999 versus $0.73 in 2000 due to higher production taxes and workovers.
Transportation, processing and marketing revenues decreased 32% to $5.3
million as benefits of higher NGL prices were more than offset by the impact of
the Sterling gas plant sale in April 2000. IPF's $7.2 million of revenues
consisted of the return portion of its royalties. IPF's income declined 16% over
that reported in 1999. During 2000, IPF expenses included $1.5 million of
administrative costs, $3.4 million of interest, a $1.3 million favorable
adjustment to IPF reserves and a $1.6 million favorable adjustment to the
reserve for doubtful accounts.
Exploration expense increased 32% to $3.2 million, primarily due to
higher dry hole costs.
General and administrative expenses increased 70% to $14.9 million. The
increase was primarily due to an increase in non-cash mark-to-market
compensation expense of $3.2 million and lower recoupments from third parties
for operations which fell due to the Great Lakes transaction, the expense of
establishing duplicate financial and administrative departments in Fort Worth
and higher bad debt expenses.
Interest and other income decreased $1.1 million primarily due to $1.1
million of losses on sales of assets. Interest expense (excluding IPF) decreased
15% to $40.0 million primarily as a result of the lower outstandings, partially
offset by higher interest rates. The average outstanding balance on the bank
credit facility fell to $125 million from $308 million in the prior year and the
weighted average interest rate rose from 7.1% to 8.8%.
Depletion, depreciation and amortization ("DD&A") decreased 17% as a
result of the mix of production by depletion pool and lower production. The
Company-wide DD&A rate was $1.21 per mcfe in 2000 compared to $1.21 in 1999.
Acreage is assessed periodically to determine whether there has been an
impairment. If an impairment is indicated, a loss is recognized. The Company
compares the carrying value of its acreage to estimated fair value based on a
variety of factors including the value that could be recovered from sale,
farm-out, or exploitation, a geological and engineering assessment, acreage
transactions in the area, the timing of potential drilling and the nature of the
specific property. In the fourth quarter of 2000, the Company raised its DD&A
rate to $1.34 per mcfe to reflect a decline in proved reserves and the increased
book value of properties subject to amortization. Reserves were revised downward
in 2000 due to the removal of drilling and recompletion locations that, based on
perceived risk, will probably not be drilled. See Note 22 to the financial
statements. The Company's high DD&A rate will make it more difficult to remain
profitable if commodity prices fall sharply.
The Company recorded a provision for impairment on acreage ($6.1
million), proved properties ($2.8 million) and a gas plant ($21.0 million) for
the year ended 1999. In evaluating possible impairment, the Company evaluates
acreage on a separate basis from proved properties.
32
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about Range's potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in oil and gas prices and interest rates. The
disclosures are not meant to be precise indicators of expected future losses,
but rather indicators of reasonably possible losses. This forward-looking
information provides indicators of how Range views and manages its ongoing
market risk exposures. All of Range's market risk sensitive instruments were
entered into for purposes other than trading.
Commodity Price Risk. Range's major market risk is exposure to oil and
gas pricing. Realized pricing is primarily driven by worldwide prices for oil
and spot market prices for North American gas production. Oil and gas prices
have been volatile and unpredictable for many years.
The Company periodically enters hedging arrangements with respect to
oil and gas production of proved reserves. Pursuant to these swaps, Range
receives a fixed price for its production and pays market prices to the contract
counterparty. This hedging is intended to reduce the impact of oil and gas price
fluctuations. Realized gains and losses are generally recognized in oil and gas
revenues when the associated production occurs. Starting in 2001, gains or
losses on open contracts are recorded either in current period income or Other
comprehensive income ("OCI"). The gains and losses realized as a result of
hedging are substantially offset in the cash market when the commodity is
delivered. Range does not hold or issue derivative instruments for trading
purposes.
As of December 31, 2001, Range had oil and gas hedges in place covering
47.3 Bcf of gas and 700,000 barrels of oil. Their fair value, excluding hedge
contracts with Enron, represented by the estimated amount that would be realized
upon termination, based on contract versus NYMEX prices, approximated a net
unrealized pre-tax gain of $52.1 million at December 31, 2001. These contracts
expire monthly through December 2005 and cover approximately 55% of anticipated
2002 production from proved reserves and 30% of 2003 production from proved
reserves and lesser amounts of 2004 and 2005 production. Gains or losses on open
and closed hedging transactions are determined as the difference between the
contract price and a reference price, generally closing prices on the NYMEX.
Transaction gains and losses are determined monthly and are included as
increases or decreases to oil and gas revenues in the period the hedged
production is sold. Any ineffective portion of such hedges is recognized in
earnings as it occurs. Net pre-tax losses relating to these derivatives in 1999,
2000 and 2001 were $10.6 million, $43.2 million and $6.2 million, respectively.
Effective January 1, 2001, the unrealized gains (losses) on these hedging
positions were recorded at an estimate of the fair value based on a comparison
of the contract price and a reference price, generally NYMEX, on the Company's
balance sheet as OCI, a component of Stockholders' Equity.
The Company had hedge agreements with Enron for 22,700 Mmbtu's per day,
at $3.20 per Mmbtu for the first three months of 2002. Amounts due from Enron
are not included in the open hedges described in the previous paragraph. Based
on its accountants guidance, the Company has recorded an allowance for bad debts
at year-end 2001 of $1.4 million, offset by a $318,000 ineffective gain included
in 2001 income and $1.0 million gain included in OCI at year-end 2001 related to
these amounts due from Enron. The gain included in OCI at year-end 2001 will be
included in income in the first quarter of 2002. The last of the Enron contracts
will expire as of March 2002.
In 2001, a 10% reduction in oil and gas prices, excluding amounts fixed
through hedging transactions, would have reduced revenue by $4.4 million. If oil
and gas future prices at December 31, 2001 had declined by 10%, the unrealized
hedging gain at that date would have increased by $15.2 million.
At December 31, 2001, Range had $392.2 million of debt (including Trust
Preferred) outstanding. Of this amount, $198.4 million bears interest at fixed
rates averaging 7.0%. Senior debt and non-recourse debt totaling $193.8 million
bears interest at floating rates, excluding interest rate swaps, which averaged
4.0% at that date. At December 31, 2001, Great Lakes had interest rate swap
agreements totaling $100.0 million, 50% of which is consolidated with Range. Two
agreements totaling $45.0 million at rates of 7.1% each expire in May 2004. Two
agreements of $10.0 million each at 6.2% expire in December 2002 and five
agreements totaling $35.0 million at rates of 4.8%, 4.7%, 4.6%, 4.5% and 4.5%
expire in June 2003. The agreements expiring in May 2004 may be terminated at
the counterparty's option in May 2002. On December 31, 2001, the 30-day LIBOR
rate was 1.9%. A 1% increase in short-term interest rates on the floating-rate
debt outstanding (net of amounts fixed through hedging transactions) at December
31, 2001 would cost the Company approximately $1.4 million in additional annual
interest.
33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to the Index to Financial Statements on page 43 for a
list of financial statements and notes thereto and 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 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, KPMG 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
In July 2002, the Company appointed KPMG LLP as its new independent
auditor.
34
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
The officers and directors are listed below with a description of their
experience and certain other information. Each director was elected for a
one-year term at the Company's 2001 annual stockholders' meeting of
stockholders. Officers are appointed by the Board of Directors.
OFFICE
AGE HELD SINCE POSITION
--- ---------- --------
Thomas J. Edelman 51 1988 Chairman and Chairman of the Board
John H. Pinkerton 47 1990 President and Director
Robert E. Aikman 70 1990 Director
Anthony V. Dub 52 1995 Director
V. Richard Eales 65 2001 Director
Allen Finkelson 55 1994 Director
Alexander P. Lynch 49 2000 Director
James E. McCormick 74 2000 Director
Terry W. Carter 49 2001 Executive Vice President - Exploration and Production
Eddie M. LeBlanc III 53 2000 Senior Vice President and Chief Financial Officer
Herbert A. Newhouse 57 1998 Senior Vice President - Gulf Coast
Chad L. Stephens 46 1990 Senior Vice President - Southwest
Rodney L. Waller 52 1999 Senior Vice President and Corporate Secretary
Thomas J. Edelman, Chairman and Chairman of the Board of Directors,
joined the Company in 1988. From 1981 to 1997, Mr. Edelman served as a director
and President of Snyder Oil Corporation ("SOCO"), a publicly traded independent
oil and gas company. In 1996, Mr. Edelman became Chairman 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 Star Gas Partners, L.P., a publicly-traded
master limited partnership, which distributes fuel oil and propane.
John H. Pinkerton, President and a Director, became a director in 1988.
He joined the Company and was appointed President in 1990. 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 a director of Venus Exploration, Inc., a
publicly traded exploration and production company in which Range owned
approximately a 18% interest at December 31, 2001.
Robert E. Aikman, became a Director 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., Vice-Chairman of
Whamtech, 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. 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 and American Association of Petroleum Landmen.
Mr. Aikman graduated from the University of Oklahoma in 1952.
Anthony V. Dub became a Director 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.
35
Allen Finkelson became a Director in 1994. Mr. Finkelson has been a
partner at Cravath, Swaine & Moore since 1977, with the exception of the period
1983 through 1985, when he was a managing director of Lehman Brothers Kuhn Loeb
Incorporated. Mr. Finkelson joined Cravath, Swaine & Moore in 1971. Mr.
Finkelson a Bachelor of Arts Degree from St. Lawrence University and a Doctor of
Laws Degree from Columbia University School of Law.
V. Richard Eales became a Director in 2001. Mr. Eales has over 35 years
of experience in the energy, high technology and financial industries. He is
currently a financial consultant serving energy and information technology
businesses. Mr. Eales was employed by Union Pacific Resources Group Inc. from
1991 to 1999 serving as Executive Vice President from 1995 through 1999. Prior
to 1991, Mr. Eales served in various financial capacities with Butcher & Singer
and Janney Montgomery Scott, investment banking firms, as CFO of Novell, Inc., a
technology company, and in the treasury department of Mobil Oil Corporation. Mr.
Eales received his Bachelor of Chemical Engineering from Cornell University and
his Masters in Business Administration from Stanford University.
Alexander P. Lynch became a Director in 2000. Mr. Lynch currently
serves as Managing Director of J.P. Morgan, a subsidiary of J.P. MorganChase &
Co., and Director of Patina Oil and Gas Corporation. Until its merger into J.P.
MorganChase, Mr. Lynch was a General Partner of The Beacon Group. Previously, he
was Co-President and Chief Executive Officer of The Bridgeford Group, a
financial advisory firm that was acquired by Beacon in 1997. Prior to 1991, Mr.
Lynch served as a Managing Director with Lehman Brothers, a division of Shearson
Lehman Brothers, Inc. Mr. Lynch received a Bachelor of Arts degree from the
University of Pennsylvania and a Master's Degree from the Wharton School of
Business at the University of Pennsylvania.
James E. McCormick became a Director in 2000. Mr. McCormick has more
than 40 years experience in the oil and gas industry. He currently serves as
Director of Lone Star Technologies, TESCO Corporation and Dallas National Bank.
He served as a Director for Santa Fe Snyder Corporation until its merger with
Devon Energy in August 2000. Mr. McCormick served as President and Chief
Operating Officer for Oryx Energy Company from its inception in 1988 until his
retirement in 1992. Prior to his position at Oryx, he served as President and
Chief Executive Officer of Sun Exploration and Production Company. Mr. McCormick
received a Bachelor of Science degree in Geology from Boston University.
Terry W. Carter, Executive Vice President-Exploration and Production,
joined the Company in January 2001. Previously, Mr. Carter provided consulting
services to independent oil and gas companies. From 1976 to 1999, Mr. Carter was
employed by Oryx Energy Company, holding a variety of positions including
Planning Manager, Development Manager and Manager of Drilling. Mr. Carter
received a Bachelor of Science degree in Petroleum Engineering from Tulsa
University.
Eddie M. LeBlanc III, Senior Vice President and Chief Financial
Officer, joined the Company in 2000. Previously Mr. LeBlanc was a founder of
Interstate Natural Gas Company, which merged into Coho Energy in 1994. At Coho
Energy Mr. LeBlanc served as Senior Vice President and Chief Financial Officer.
Mr. LeBlanc's twenty-six years of experience include assignments in the oil and
gas subsidiaries of Celeron Corporation and Goodyear Tire and Rubber. Prior to
his industry experience, Mr. LeBlanc was with a national accounting firm, he is
a certified public accountant, a chartered financial analyst, and received a
Bachelor of Science degree from University of Southwestern Louisiana.
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 over 30 years of operational and managerial experience in oil
and gas exploration and production. Mr. Newhouse received a Bachelor of Science
degree in Chemical Engineering from Ohio State 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 a
Bachelor of Arts Degree in Finance and Land Management from the University of
Texas.
Rodney L. Waller, Senior Vice President and Corporate Secretary, joined
the Company in 1999. Previously, Mr. Waller had been with Snyder Oil
Corporation, now part of Devon Energy Corporation, since 1977, where he served
as a senior vice president. Before joining Snyder, Mr. Waller was employed by
Arthur Andersen. Mr. Waller received a Bachelor of Arts degree from Harding
University.
The Board has established five committees to assist it in the discharge
of its responsibilities.
36
Audit Committee. The Audit Committee reviews the professional services
provided by independent public accountants and the independence of such
accountants from management. This Committee also reviews the scope of the audit
coverage, the annual financial statements and such other matters with respect to
the accounting, auditing and financial reporting practices and procedures as it
may find appropriate or as have been brought to its attention. Messrs. Aikman,
Dub, Eales and Lynch are the members of the Audit Committee.
Compensation Committee. The Compensation Committee reviews and approves
officers' salaries and administers the bonus, incentive compensation and stock
option plans. The Committee advises and consults with management regarding
benefits and significant compensation policies and practices. This Committee
also considers nominations of candidates for officer positions. The members of
the Compensation Committee are Messrs. Aikman, Finkelson, Lynch and McCormick.
Dividend Committee. The Dividend Committee is authorized and directed
to approve the payment of dividends. The members of the Dividend Committee are
Messrs. Edelman and Pinkerton.
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
Committee will be to review and approve smaller acquisitions. The members of the
Executive Committee are Messrs. Edelman, Finkelson and Pinkerton.
Nominating Committee. The Nominating Committee develops and reviews
background information for candidates for the Board of Directors and makes
recommendations to the Board regarding such candidates. The members of the
Nominating Committee are Messrs. Aikman, Finkelson, Lynch and McCormick.
ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
Information with respect to officers' compensation is incorporated
herein by reference to the Company's 2002 Proxy Statement.
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 2002
Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
37
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.
None.
(c) Exhibits required by Item 601 of Regulation S-K
Exhibits required to be filed 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.
38
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: October 24, 2002
RANGE RESOURCES CORPORATION
By: /s/ John H. Pinkerton
------------------------
John H. Pinkerton
President
39
I, John H. Pinkerton, certify that:
1. I have reviewed this annual report on Form 10-K/A of Range Resources
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report.
Date: October 24, 2002
/s/ John H. Pinkerton
-------------------------------------------
John H. Pinkerton, President
I, Eddie M. LeBlanc, certify that:
1. I have reviewed this annual report on Form 10-K/A of Range Resources
Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report.
Date: October 24, 2002
/s/ Eddie M. LeBlanc
-------------------------------------------
Eddie M. LeBlanc, Chief Financial Officer
40
GLOSSARY
The terms defined in this glossary are used throughout this Form 10-K/A.
bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6
Mcf for each barrel of oil, which reflects the relative energy content.
Credit Facility. The Range Resources Corporation $225 million revolving bank
facility.
Development well. A well drilled within the proved area of an oil or natural gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing either oil or natural gas in
sufficient quantities to justify completion as an oil or gas well.
Exploratory well. A well drilled to find and produce oil or gas in an unproved
area, to find a new reservoir in a field previously found to be productive of
oil or gas in another reservoir, or to extend a known reservoir.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Infill well. A well drilled between known producing wells to better exploit the
reservoir.
LIBOR. London Interbank Offer Rate, the rate of interest at which banks offer to
lend to one another in the wholesale money markets in the City of London. This
rate is a yardstick for lenders involved in high value transactions.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
mcf. One thousand cubic feet.
mcf/d. One thousand cubic feet per day.
mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6
mcf for each barrel of oil, which reflects the relative energy content.
Merger. The acquisition via merger of Domain Energy Corporation by Lomak
Petroleum, Inc. in August 1998. Simultaneously, Lomak's name was changed to
Range Resources Corporation.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
Mmbtu. One million British thermal units. One British thermal unit is the heat
required to raise the temperature of a one-pound mass of water from 58.5 to 59.5
degrees Fahrenheit.
Mmcf. One million cubic feet.
Mmcfe. One million cubic feet of natural gas equivalents.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Net oil and gas sales. Oil and natural gas sales less oil and natural gas
production expenses.
Oil and gas royalty trust. An arrangement whereby typically, the creating
company conveys a net profits interest in certain of its oil and gas properties
to the newly created trust and then distributes ownership units in the trust to
its unitholders. The function of the trust is to serve as agent to distribute
income from the net profits interest to its unitholders.
41
Present Value. The present value, discounted at 10%, of future net cash flows
from estimated proved reserves, using constant prices and costs in effect on the
date of the report (unless such prices or costs are subject to change pursuant
to contractual provisions).
Productive well. A well that is producing oil or gas or that is capable of
production.
Proved developed non-producing reserves. Reserves that consist of (i) proved
reserves from wells which have been completed and tested but are not producing
due to lack of market or minor completion problems which are expected to be
corrected and (ii) proved reserves currently behind the pipe in existing wells
and which are expected to be productive due to both the well log characteristics
and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves. Proved reserves that can be expected to be
recovered from currently producing zones under the continuation of present
operating methods.
Proved developed reserves. Proved reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in another
formation from that in which the well has previously been completed.
Reserve life index. The presentation of proved reserves defined in number of
years of annual production.
Royalty interest. An interest in an oil and gas property entitling the owner to
a share of oil and natural gas production free of costs of production.
Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves after income taxes calculated holding
prices and costs constant at amounts in effect on the date of the report (unless
such prices or costs are subject to change pursuant to contractual provisions)
and otherwise in accordance with the Commission's rules for inclusion of oil and
gas reserve information in financial statements filed with the Commission.
Term overriding royalty. A royalty interest that is carved out of the operating
or working interest in a well. Its term does not extend to the economic life of
the property and is of shorter duration than the underlying working interest.
The term overriding royalties in which the Company participates through its
Independent Producer Finance subsidiary typically extend until amounts financed
and a designated rate of return have been achieved. At such point in time, the
override interest reverts back to the working interest owner.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
42
RANGE RESOURCES CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(ITEM 14[A], [D])
Page
Number
------
Independent Auditors' Report 44
Consolidated balance sheets at December 31, 2000 and 2001 45
Consolidated statements of operations for the years ended December 31, 1999, 2000 and 2001 46
Consolidated statements of cash flows for the years ended December 31, 1999, 2000 and 2001 47
Consolidated statements of stockholders' equity for the years ended December 31, 1999, 2000 and 2001 48
Notes to consolidated financial statements 49
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.
43
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS
RANGE RESOURCES CORPORATION:
We have audited the accompanying consolidated balance sheets of Range
Resources Corporation as of December 31, 2000 and 2001, and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the years in the three-year period ended December 31, 2001. These
consolidated financial statements are the responsibility of Range Resources
Corporation's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Range
Resources Corporation as of December 31, 2000 and 2001, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the
Company has restated their consolidated balance sheets as of December 31, 2000
and 2001, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the years in the three-year period ended
December 31, 2001, which were audited by other auditors who have ceased
operations.
As discussed in Note 3 to the financial statements, effective January 1,
2001, the Company changed their method of accounting for derivative, financial
instruments and hedging activities.
KPMG LLP
Dallas, Texas
September 20, 2002
44
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
DECEMBER 31,
-----------------------------
2000 2001
----------- -----------
ASSETS RESTATED RESTATED
Current assets
Cash and equivalents $ 2,612 $ 3,380
Accounts receivable 33,278 25,295
IPF receivables (Note 5) 20,800 7,000
Unrealized derivative hedging gain (Note 8) -- 37,165
Inventory and other 6,196 4,895
----------- -----------
62,886 77,735
----------- -----------
IPF receivables, net (Note 5) 28,128 34,402
Unrealized derivative hedging gain (Note 8) -- 14,936
Oil and gas properties, successful efforts method (Note 18) 997,049 1,047,629
Accumulated depletion (443,876) (514,272)
----------- -----------
553,173 533,357
----------- -----------
Transportation and field assets (Note 3) 33,593 31,288
Accumulated depreciation (12,339) (13,108)
----------- -----------
21,254 18,180
----------- -----------
Other (Note 3) 6,385 3,852
----------- -----------
$ 671,826 $ 682,462
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 27,823 $ 27,202
Accrued liabilities 16,888 15,036
Accrued interest 7,774 5,244
Unrealized derivative hedging loss (Note 8) 736 397
----------- -----------
53,221 47,879
----------- -----------
Senior debt (Note 7) 89,900 95,000
Non-recourse debt (Note 7) 113,009 98,801
Subordinated notes (Note 7) 162,550 108,690
Trust preferred - mandatorily redeemable securities
of subsidiary (Note 7) 92,640 89,740
Commitments and contingencies (Note 9)
Deferred taxes (Note 14) -- 4,496
Unrealized derivative hedging loss (Note 8) 562 2,235
Stockholders' equity (Notes 10 and 11)
Preferred stock, $1 par, 10,000,000 shares authorized,
$2.03 convertible preferred, 219,935 and -0- issued
and outstanding, respectively (liquidation preference
$5,498,375 and $-0-, respectively) 220 --
Common stock, $.01 par, 100,000,000 shares authorized,
49,187,682 and 52,643,275 issued and outstanding, respectively 492 526
Capital in excess of par value 364,925 378,426
Stock held by employee benefit trust, 851,140 and 1,038,242
shares, respectively (Note 12) (3,496) (4,890)
Retained earnings (deficit) (201,478) (183,825)
Deferred compensation expense (80) (139)
Other comprehensive income (loss) (Note 3) (639) 45,523
----------- -----------
159,944 235,621
----------- -----------
$ 671,826 $ 682,462
=========== ===========
SEE ACCOMPANYING NOTES.
45
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 2000 2001
--------- --------- ---------
RESTATED RESTATED RESTATED
Revenues
Oil and gas sales $ 145,492 $ 173,082 $ 208,854
Transportation and processing 7,770 5,306 3,435
IPF 8,513 7,162 6,646
Interest and other 343 (722) 490
Gain on formation of Great Lakes (Note 20) 30,929 -- --
--------- --------- ---------
193,047 184,828 219,425
--------- --------- ---------
Expenses
Direct operating 43,074 40,552 43,430
IPF 6,389 1,974 3,761
Exploration 2,409 3,187 5,879
General and administrative 8,793 14,953 12,212
Interest expense and dividends on trust preferred 47,085 39,953 32,179
Depletion, depreciation and amortization 80,598 66,968 77,573
Provision for impairment (Note 3) 29,901 -- 31,085
--------- --------- ---------
218,249 167,587 206,119
--------- --------- ---------
Pretax income (loss) (25,202) 17,241 13,306
Income taxes (benefit) (Note 14)
Current 770 (1,574) (406)
Deferred -- -- --
--------- --------- ---------
770 (1,574) (406)
Income (loss) before extraordinary item (25,972) 18,815 13,712
Extraordinary item
Gain on retirement of debt securities, net (Note 21) 2,430 17,763 3,951
--------- --------- ---------
Net income (loss) $ (23,542) $ 36,578 $ 17,663
========= ========= =========
Comprehensive income (loss) (Note 3) $ (23,645) $ 35,750 $ 63,825
========= ========= =========
Earnings (loss) per share basic and diluted (Note 16)
Before extraordinary item
Basic $ (0.78) $ 0.55 $ 0.28
========= ========= =========
Diluted $ (0.78) $ 0.54 $ 0.28
========= ========= =========
After extraordinary item
Basic $ (0.71) $ 0.97 $ 0.36
========= ========= =========
Diluted $ (0.71) $ 0.96 $ 0.36
========= ========= =========
SEE ACCOMPANYING NOTES.
46
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 2000 2001
--------- --------- ---------
RESTATED RESTATED RESTATED
CASH FLOW FROM OPERATIONS:
Net income (loss) $ (23,542) $ 36,578 $ 17,663
Adjustments to reconcile net income (loss) to
net cash provided by operations:
Depletion, depreciation and amortization 80,598 66,968 77,573
Write-down of marketable securities -- -- 1,715
Unrealized hedging gains reclassification -- -- (1,019)
Provision for impairment 29,901 -- 31,085
Allowance for bad debts -- 615 2,040
Allowance for IPF receivables 1,224 (2,891) 122
Amortization of deferred offering costs 1,333 2,020 1,961
Non-cash compensation expense 2,217 4,366 (295)
Gain on retirement of securities (2,430) (17,978) (4,004)
(Gain) loss on sale of assets (30,399) 1,116 (689)
Changes in working capital:
Accounts receivable 7,978 (6,568) 5,540
Inventory and other (1,589) (522) 226
Accounts payable (4,062) (5,627) 548
Accrued liabilities and other (11,042) (3,198) (2,868)
--------- --------- ---------
Net cash provided by operations 50,187 74,879 129,598
--------- --------- ---------
CASH FLOW FROM INVESTING:
Investment in Great Lakes 98,715 -- --
Oil and gas properties (25,093) (47,474) (87,034)
Field service assets (656) (2,263) (2,331)
IPF investments (5,362) (6,985) (11,629)
IPF repayments 13,160 24,764 19,034
Proceeds from sales of assets 17,476 25,944 3,771
--------- --------- ---------
Net cash provided by (used in) investing 98,240 (6,014) (78,189)
--------- --------- ---------
CASH FLOW FROM FINANCING:
Repayments of indebtedness (145,129) (79,611) (52,046)
Preferred dividends (2,334) (1,444) (10)
Common dividends (1,107) -- --
Issuance of common stock 2,152 1,798 1,488
Repurchase of common stock (26) -- --
Repurchase of preferred stock -- -- (73)
--------- --------- ---------
Net cash used in financing (146,444) (79,257) (50,641)
--------- --------- ---------
Change in cash 1,983 (10,392) 768
Cash and equivalents, beginning of year 11,021 13,004 2,612
--------- --------- ---------
Cash and equivalents, end of year $ 13,004 $ 2,612 $ 3,380
========= ========= =========
SEE ACCOMPANYING NOTES.
47
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
STOCK
PREFERRED HELD
STOCK COMMON STOCK CAPITAL BY
----------------- ------------- DEFERRED IN EMPLOYEE RETAINED OTHER
PAR PAR COMPENSATION EXCESS OF BENEFIT EARNINGS COMPREHENSIVE
SHARES VALUE SHARES VALUE EXPENSE PAR VALUE TRUST (DEFICIT) INCOME TOTAL
------- -------- ------ ----- ------------ --------- --------- --------- ------------- ---------
BALANCE
DECEMBER 31, 1998 1,150 $ 1,150 35,933 $ 359 $ -- $ 335,232 $ (1,845) $(209,519) $ 292 $ 125,669
(Restated)
Preferred dividends -- -- -- -- -- -- -- (2,334) -- (2,334)
Common dividends -- -- -- -- -- -- -- (1,107) -- (1,107)
Issuance of common -- -- 1,270 13 (69) 2,596 (1,241) -- -- 1,299
Conversion of
securities -- -- 699 7 -- 3,349 -- -- -- 3,356
Other comprehensive
income -- -- -- -- -- -- -- -- (103) (103)
Net income -- -- -- -- -- -- -- (23,542) -- (23,542)
------- -------- ------ ----- --------- --------- --------- -------- --------- ----------
BALANCE
DECEMBER 31, 1999 1,150 1,150 37,902 379 (69) 341,177 (3,086) (236,502) 189 103,238
(Restated)
Preferred dividends -- -- -- -- -- -- -- (1,554) -- (1,554)
Issuance of common -- -- 974 10 (11) 3,115 (410) -- -- 2,704
Conversion of
securities (930) (930) 10,312 103 -- 20,633 -- -- -- 19,806
Other comprehensive
income -- -- -- -- -- -- -- -- (828) (828)
Net income -- -- -- -- -- -- -- 36,578 -- 36,578
------- -------- ------ ----- --------- --------- --------- ---------- --------- ---------
BALANCE
DECEMBER 31, 2000 220 220 49,188 492 (80) 364,925 (3,496) (201,478) (639) 159,944
(Restated)
Preferred dividends -- -- -- -- -- -- -- (10) -- (10)
Issuance of common -- -- 858 8 (59) 4,030 (1,394) -- -- 2,585
Conversion of
securities (220) (220) 2,597 26 -- 9,471 -- -- -- 9,277
Other comprehensive
income -- -- -- -- -- -- -- -- 46,162 46,162
Net income -- -- -- -- -- -- -- 17,663 -- 17,663
------- -------- ------ ----- --------- --------- --------- ---------- --------- ---------
BALANCE
DECEMBER 31, 2001 -- $ -- 52,643 $ 526 $ (139) $ 378,426 $ (4,890) $(183,825) $ 45,523 $ 235,621
======= ======== ====== ===== ========= ========= ========= ========== ========= =========
SEE ACCOMPANYING NOTES.
48
RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Range Resources Corporation ("Range") is engaged in the development,
acquisition and exploration of oil and gas properties primarily in the
Southwestern, Gulf Coast and Appalachian regions of the United States. The
Company also provides financing to smaller oil and gas producers through a
wholly-owned subsidiary, Independent Producer Finance ("IPF"). The Company seeks
to increase its reserves and production primarily through development drilling
and acquisitions. In 1999, Range and FirstEnergy Corp. ("FirstEnergy")
contributed their Appalachian oil and gas properties to an equally owned joint
venture, Great Lakes Energy Partners L.L.C. ("Great Lakes"). The Company's
financial statements for the three years ended 2001 have been restated (See Note
2).
(2) RESTATEMENT
In July 2002, the Company selected KPMG LLP as its new independent
auditor. The Company also chose to have KPMG reaudit its consolidated financial
statements for the three years ended December 31, 2001, even though a reaudit
was not required. The reaudit was intended to provide additional assurance to
shareholders, insure the Company's ongoing access to the capital markets and to
avoid any possible impediment to future transactions. As part of the selection
process, KPMG performed its normal client acceptance procedures and advised the
Company that it believed a different accounting principle should have been used
to determine the gain recognized in September 1999 on the formation of the Great
Lakes joint venture. Specifically, the gain recognized in September 1999 should
be reduced from $39.8 to $30.9 million and income in subsequent periods should
increase as a result of lower depletion expense.
As a result of the actual reaudit, a series of additional issues came to
light which required restatement of the Company's previously reported operating
results and financial condition. These issues and their impact on pretax income
is outlined below.
In 1998, the Company acquired Domain Energy. In recording the transaction,
the purchase price was not appropriately allocated to the individual oil and gas
properties, causing a subsequent purchase price adjustment to be miscalculated.
As a result of correcting for this matter, impairments recognized at year-end
2001 were reduced. In addition, properties in Appalachia and Michigan, that had
been combined into accounting pools for the purpose of calculating depletion,
were subdivided into smaller pools, as the combined Michigan properties lacked a
common geological formation, and the depreciation rates historically applied on
non-oil and gas assets were reduced. As a result of these changes, pretax income
decreased $7.1 million in 1999, increased $4.8 million in 2000 and increased
$7.6 million in 2001.
The Company maintains a deferred compensation plan (the "Plan"), under
which eligible employees can defer all or a portion of their cash compensation
and invest those amounts in a variety of investment options (including Company
common stock) which are placed in a rabbi trust (the "Trust"). Eligible
employees can also place common stock awards in the Trust. Pursuant to a
consensus of the Emerging Issues Task Force, assets and liabilities of the Trust
must be consolidated on the Company's balance sheet. While the Trust's assets
and liabilities are of identical value, Company common stock held in the Trust
is treated as if it were treasury stock (it is deducted from outstanding shares
as shares held by an employee benefit plan). Furthermore, because the Plan
allows participants to diversify their investments, the liability to Plan
participants must be revalued on the balance sheet each accounting period at the
then-quoted market prices of the Company's common stock held by the Trust and
increases or decreases between accounting periods reflected on the statement of
operations as increases or decreases in compensation expense. Historically, the
Company did not consolidate the Trust in its consolidated financial statements
nor added or subtracted changes in the market value of the Company's common
stock held by the Trust on its statement of operations. However, all material
information about the Plan has historically been disclosed in footnotes to the
financial statements and in proxy statements. In addition, the Company offers
designated employees the ability to purchase shares at a discount under a
shareholder-approved Stock Purchase Plan or to receive bonuses or a portion of
their base pay in restricted common stock issued at a discount from quoted
market prices. Previously, such shares had always been accounted for based on
the Company's estimate of the fair value of the stock granted or purchased. In
the restated financial statements, stock purchased through the Plan or granted
to employees was expensed based on the quoted market value without regard to the
Company's estimate of fair value. The difference between previously reported
values and market value will be included as additional compensation expense on
the restated statements of operations. As a result of these changes, pretax
income decreased $561,000 in 1999, decreased $3.8 million in 2000 and increased
$1.7 million in 2001.
49
At June 30, 2002, the Company corrected a series of unreconciled balance
sheet accounts that had a net minimal statement of operations impact. These
balance sheet general ledger accounts were not supported by the underlying
subsidiary ledger detail when the Company's accounting department moved from
Ohio to Fort Worth. In the restatement, these corrections were reflected in the
periods in which they applied, rather than in the second quarter of 2002 when
the Company originally corrected for the differences. As a result, pretax income
for periods prior to 1999 increased by $1.9 million, increased by $627,000 in
1999, decreased $2.9 million in 2000 increased by $190,000 in 2001.
Finally, certain of GLEP's interest rate swaps had early cancellation
provisions but had been accounted for as cash flow hedges. Upon further review,
the swaps did not meet the documentation and effectiveness provisions of SFAS
133, requiring changes in fair value to be reported as interest expense on the
restated financial statements as opposed to changes in Other Comprehensive
Income. As a result, pretax income decreased $1.4 million in 2001 and will
increase by a corresponding amount in future periods. Additionally, the
ineffective portion of certain commodity hedges increased income $71,000 in
2001.
In total, all of the current changes (including the previously announced
change in the gain on the Great Lakes' transaction) increased net loss by $15.7
million in 1999, decreased net income by $1.4 million in 2000 and increased net
income by $8.7 million in 2001.
The following shows the effect of the restatement (in thousands, except per
share amounts):
PREVIOUSLY
1999 REPORTED RESTATED
---- -------- --------
Gain on formation of Great Lakes $ 39,810 $ 30,929
General and administrative 8,028 8,793
Depletion, depreciation and amortization 76,447 80,598
Provision for impairment 27,118 29,901
Pretax loss (8,622) (25,202)
Income taxes 1,601 770
Loss before extraordinary item (10,223) (25,972)
Net loss (7,793) (23,542)
Loss per share before extraordinary gain
Basic (0.34) (0.78)
Diluted (0.34) (0.78)
Loss per share after extraordinary gain
Basic (0.27) (0.71)
Diluted (0.27) (0.71)
Cash and equivalents 12,937 13,004
Accounts receivable 21,646 25,759
Inventory and other 6,196 6,530
Oil and gas properties 978,919 959,843
Accumulated depletion (383,622) (389,200)
Accounts payable 23,925 26,957
Accrued liabilities 16,074 16,835
Stock held by employee benefit trust -- (3,086)
Capital in excess of par value 340,279 341,177
Other comprehensive income (loss) (7) 189
Retained earnings (deficit) (214,630) (236,502)
Deferred compensation expense -- (69)
Stockholders' equity 127,171 103,307
50
PREVIOUSLY
2000 REPORTED RESTATED
---- -------- --------
Direct operating $ 38,525 $ 40,552
General and administrative 10,323 14,953
Depletion, depreciation and amortization 72,242 66,968
Pretax income 18,624 17,241
Income before extraordinary item 20,198 18,815
Net income 37,961 36,578
Earnings per share before extraordinary gain
Basic 0.57 0.55
Diluted 0.57 0.54
Earnings per share after extraordinary gain
Basic 0.99 0.97
Diluted 0.99 0.96
Cash and equivalents 2,485 2,612
Accounts receivable 33,221 33,278
Inventory and other 5,580 6,196
Oil and gas properties 1,014,939 997,049
Accumulated depletion (443,097) (443,876)
Other 5,855 6,385
Accounts payable 26,744 27,823
Accrued liabilities 11,341 16,888
Unrealized derivative hedging loss - current -- 736
Unrealized derivative hedging loss - noncurrent -- 562
Stock held by employee benefit trust -- (3,496)
Capital in excess of par value 363,625 364,925
Other comprehensive loss (907) (639)
Retained earnings (deficit) (178,223) (201,478)
Deferred compensation expense -- (80)
Stockholders' equity 185,207 159,944
Cash flows -
Net cash provided by operations 74,108 74,879
Net cash used in investing (5,303) (6,014)
51
PREVIOUSLY
2001 REPORTED RESTATED
---- -------- --------
Oil and gas sales $ 209,537 $ 208,854
Direct operating 44,504 43,430
General and administrative 13,511 12,212
Interest 30,689 32,179
Depletion, depreciation and amortization 77,825 77,573
Provision for impairment 38,945 31,085
Pretax income 4,994 13,306
Current income taxes (51) (406)
Income before extraordinary item 5,045 13,712
Net income 8,996 17,663
Earnings per share before extraordinary gain
Basic 0.11 0.28
Diluted 0.11 0.28
Earnings per share after extraordinary gain
Basic 0.19 0.36
Diluted 0.19 0.36
Cash and equivalents 3,253 3,380
Accounts receivable 27,495 25,295
Inventory and other 4,084 4,895
Unrealized derivative hedging gain - current 36,768 37,165
Unrealized derivative hedging gain - noncurrent 12,701 14,936
Oil and gas properties 1,057,881 1,047,629
Accumulated depletion (512,786) (514,272)
Accumulated depreciation (13,576) (13,108)
Other 3,055 3,852
Accounts payable 26,944 27,202
Accrued liabilities 9,947 15,036
Accrued interest 7,105 5,244
Unrealized derivative hedging loss - current -- 397
Unrealized derivative hedging loss - noncurrent -- 2,235
Deferred taxes 9,651 4,496
Stock held by employee benefit trust -- (4,890)
Capital in excess of par value 376,357 378,426
Retained earnings (deficit) (169,237) (183,825)
Other comprehensive income 38,041 45,523
Deferred compensation expense -- (139)
Stockholders' equity 245,687 235,621
Cash flows --
Net cash provided by operations 130,309 129,598
Net cash used in investing (78,900) (78,189)
(3) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts of
the Company, all majority-owned subsidiaries and a pro rata share of the assets,
liabilities, income and expenses of Great Lakes. Liquid investments with
maturities of ninety days or less are considered cash equivalents. The Company
has no other off balance sheet assets or liabilities other than those reported
in the consolidated financial statements.
52
REVENUE RECOGNITION
The Company recognizes revenues from the sale of products and services in
the period delivered. Revenues at IPF are recognized as received. The Company's
receivables are concentrated in the oil and gas industry. The Company had
allowances for doubtful accounts relating to its exploration and production
business of $2.3 million and $2.9 million at December 31, 2000 and 2001,
respectively. At the same dates, IPF had valuation allowances of $15.3 million
and $17.3 million, respectively. A decrease in oil prices could cause an
increase in IPF's valuation allowances and a corresponding decrease in income.
MARKETABLE SECURITIES
The Company has adopted Statement of Financial Accounting Standards
("SFAS") No. 115, "Accounting for Certain Investments." Pursuant to SFAS 115,
the Company's holdings of equity securities qualify as available-for-sale and
are recorded at fair value. Unrealized gains and losses are reflected in
Stockholders' equity as a component of Other comprehensive income. A decline in
the market value of a security below cost deemed other than temporary is charged
to earnings. Realized gains and losses are reflected in income. During 2001, the
Company determined that the decline in the market value of an equity security it
holds was other than temporary and losses of $1.7 million were recorded as
reductions to Interest and other revenues.
INDEPENDENT PRODUCER FINANCE
IPF acquires dollar denominated royalties in oil and gas properties from
smaller producers. These royalties are accounted for as receivables because the
investment is recovered from an agreed-upon share of revenues until a specified
rate of return is received. The portion of payments received relating to the
return is recognized as income; remaining receipts are considered a return of
capital and reduce receivables. Receivables classified as current represent the
return of capital expected to be received within twelve months. All receivables
are evaluated quarterly and provisions for uncollectible amounts are established
based on the Company's valuation of its royalty interest in the oil and gas
properties. At December 31, 2001, the valuation allowance totaled $17.3 million.
Due to favorable oil and gas prices during the last nine months of 2000 and the
first six months of 2001, certain of these receivables began to generate all or
a greater than anticipated cash flow which favorably impacted the valuation of
the receivables. As a result, $1.8 million of increases in receivables were
recorded as a reduction in IPF expenses in the first nine months of 2001.
However, because of lower prices, IPF increased its reserve allowance by $2.0
million in the fourth quarter of 2001. During 2000 and 2001, IPF expenses were
comprised of $1.5 million and $1.8 million of general and administrative costs
and $3.4 million and $1.8 million of interest, respectively. In 2000, IPF
recorded a $2.9 million favorable adjustment to their valuation allowance. The
valuation allowance at December 31, 2000 and 2001 was $13.7 million and $17.3
million, respectively.
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting.
Exploratory drilling costs are capitalized pending determination of whether a
well is successful. Costs resulting in discoveries and development costs 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 six mcf per
barrel. The depletion, depreciation and amortization ("DD&A") rates (as
restated) were $1.21, $1.21 and $1.39 per mcfe in 1999, 2000 and 2001,
respectively. Unproved properties had a net book value of $61.8 million, $49.5
million and $25.7 million at December 31, 1999, 2000 and 2001, 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.
Acreage is assessed periodically to determine whether there has been a
decline in value. If such decline is indicated, a loss is recognized. The
Company compares the carrying value of its acreage to their estimated fair
value, using information such as an assessment of value that could be recovered
from sale, farm-out or exploitation, a geological assessment of the acreage,
other acreage purchases in the area, timing of the associated drilling program
or the property's unique nature. During 1999 and 2001, the Company recorded $6.1
million and $5.1 million, respectively, for impairment of acreage. The amount of
impairment was calculated by determining fair value using management's best
estimate of the value of these properties.
53
The following acreage was impaired for the reasons indicated (in
thousands):
Year Ended Impairment
December 31, Property Reason for Impairment Amount
------------ -------- --------------------- ----------
1999 Offshore Other Reserve revisions and lower oil and
gas prices $ 6,100
==========
2001 Matagorda Island 519 Probability of drilling reduced based on
current assessment of risk and cost/
cost overruns and delays $ 1,704
West Delta 30 Probability of drilling reduced based
on current assessment of risk and cost 688
East/West Cameron Condemned portion of leasehold through
drilling or geologic assessment 708
Offshore Other Probability of drilling reduced based
on current assessment of risk and cost 1,216
East Texas Condemned portion of leasehold
through drilling 825
----------
Total $ 5,141
==========
Impairment is recognized only if the carrying amount of a property is
greater than its expected undiscounted future cash flows. Impairment on proved
properties is generally based on the difference between the carrying amount of
the assets and the present value of the estimated future cash flows from proved
reserves.
The following are the proved property values impaired, due to declines in
gas prices, in 1999 and 2001 based on the analysis of estimated future cash
flows (in thousands):
Year Ended Impairment
December 31, Property Reason for Impairment Amount
------------ -------- --------------------- ----------
Restated
1999 Oceana (GLEP) Decline in gas price $ 1,566
Permian Other Decline in gas price 1,217
----------
$ 2,783
==========
2001 Matagorda Island 519 Decline in gas price $ 14,001
Offshore Other Decline in gas price 3,302
Gulf Coast Onshore Decline in gas price 8,542
Oceana (GLEP) Decline in gas price 99
----------
Total $ 25,944
==========
TRANSPORTATION, PROCESSING AND FIELD ASSETS
The Company's gas gathering systems are located in proximity to certain of
its principal fields. Depreciation on these systems is provided on the
straight-line method based on estimated useful lives of four to fifteen years.
The Company sold its only remaining gas processing facility in June 2000. In
connection with the sale of the gas processing plant, an impairment loss of
$21.0 million was recorded in 1999. See Note 6.
The Company receives fees for providing certain field services which are
recognized as earned. Depreciation on the associated assets is calculated on the
straight-line method based on estimated useful lives ranging from three to seven
years. Buildings are depreciated over ten years.
54
SECURITY ISSUANCE COSTS
Expenses associated with the issuance of debt are capitalized and included
in Other assets on the balance sheet. These costs are generally amortized over
the expected life of the related securities. When a security is retired prior to
maturity, related unamortized costs are expensed. At December 31, 2001, such
deferred financing costs totaled $3.0 million.
GAS IMBALANCES
The Company uses the sales method to account for gas imbalances,
recognizing revenue based on cash received rather than gas produced. At December
31, 2000 and December 31, 2001, gas imbalance liabilities of $318,000 and
$114,000 were included in Accrued liabilities, respectively.
COMPREHENSIVE INCOME
The Company follows SFAS No. 130, "Reporting Comprehensive Income,"
defined as changes in Stockholders' equity from nonowner sources. The following
is a calculation of comprehensive income for each of the three years ended
December 31, 2001 (in thousands).
Year Ended December 31,
-------------------------------------------
1999 2000 2001
--------- --------- ---------
Restated Restated Restated
Net income (loss) $ (23,542) $ 36,578 $ 17,663
Cumulative effect of change in accounting principle -- -- (72,100)
Change in unrealized hedging gain/(losses), net -- -- 116,659
Unrealized loss from available-for-sale securities (103) (828) 931
Defaulted hedge contracts, net* -- -- 672
--------- --------- ---------
Comprehensive income (loss) $ (23,645) $ 35,750 $ 63,825
========= ========= =========
* Includes $1.0 million gain related to amounts due from Enron. On
adopting SFAS 133 on January 1, 2001, the Company recorded a $72.1 million
liability for an unrealized pre-tax hedging loss on its balance sheet and an
offsetting deficit in Comprehensive income.
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 assets, liabilities, revenues and expenses
as well as disclosure of contingent assets and liabilities. Actual results could
differ from those estimates. Estimates which may significantly impact the
Company's financial statements include reserve estimates, analysis of impairment
of oil and gas properties, reserve requirement for IPF receivables and fair
value estimates of derivatives.
RECENT ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) 141 "Business Combinations"
and 142 "Goodwill". SFAS 141 required that business combinations initiated after
June 30, 2001 be accounted for as purchases and SFAS 142 required that goodwill
be reviewed for impairment instead of amortized. To date, these statements have
had no impact on the Company.
In April 2002, the FASB issued SFAS 145 relating to the extinguishment of
debt. The Company has not yet determined the effects of this Statement but it
appears gains or losses on debt extinguishment will no longer be treated as
extraordinary. The Company intends to adopt SFAS 145 on January 1, 2003.
In June 2001, FASB issued SFAS 143 "Asset Retirement Obligations"
establishing a new accounting model for the recognition of retirement
obligations associated with tangible long-lived assets and requiring that
retirement cost should be
55
capitalized as part of an asset's cost and subsequently systematically expensed.
The Company will adopt SFAS 143 on January 1, 2003 and the related transition
adjustment will be reported as a cumulative effect of a change in accounting
principle. The Company cannot yet reasonably estimate the effect of the adoption
on either its financial position or results of operations.
In August 2001, the FASB issued SFAS 144, "Impairment or Disposal of
Long-Lived Assets" establishing a single accounting model for long-lived assets
to be disposed of by sale and providing additional guidance for assets to be
held and used and assets to be disposed of other than by sale. The Company
adopted the Statement on January 1, 2002.
Beginning in 2001, SFAS 133 "Derivatives" required that derivatives be
recorded on the balance sheet as assets or liabilities at fair value and that
changes in fair value should be recognized immediately in earnings unless the
derivative qualified as a hedge of future cash flows. For derivatives qualifying
as hedges of future cash flows, the effective portion of any changes in fair
value is recognized in a component of stockholders' equity called OCI and then
reclassified to earnings when the underlying transaction is consummated. Any
ineffective portion of such hedges is recognized in earnings as it occurs. On
adopting SFAS 133 in January 2001, the Company recorded $72.1 million of
unrealized pre-tax hedging loss on its balance sheet and an offsetting deficit
in OCI. Due to the decline in oil and gas prices between January 1, 2001 and
December 31, 2001, this loss had become a net $52.1 million unrealized pre-tax
gain by year-end. SFAS 133 tends to increase earnings volatility in independent
oil companies.
The Company had hedge agreements with Enron North America Corp. ("Enron")
for 22,700 Mmbtu per day, at $3.20 per Mmbtu covering the first three months of
2002. Based on accounting requirements, the Company recorded an allowance for
bad debts at year-end 2001 of $1.4 million, offset by a $318,000 ineffective
gain included in 2001 income and $1.0 million gain included in OCI at year-end
2001 due to Enron's collapse. The gain included in OCI at year-end 2001 was
included in income in the first quarter of 2002. The last Enron contracts
expired in March 2002.
The Company regularly enters into contracts to reduce the effect of
fluctuations in oil and gas prices. These contracts generally qualify as cash
flow hedges. Prior to 2001, gains and losses were determined monthly and
included in oil and gas revenues in the period the hedged production was sold.
Starting in 2001, gains or losses on open contracts are recorded either in
current period income or in OCI. The Company also enters into swap agreements to
reduce the risk of changing interest rates. These agreements qualify as fair
value hedges and related income or expense is recorded as an adjustment to
interest expense in the period covered.
Interest and other revenues in the Consolidated Statements of Operations
was increased for ineffective hedging gains of $2.3 million in the year ended
December 31, 2001. Unrealized hedging gains and losses (excluding Enron),
including interest rate swaps, of $49.5 million and restated OCI of $45.5
million, net of taxes, were recorded on the balance sheet at December 31, 2001.
See Note 8.
RECLASSIFICATIONS
Certain reclassifications have been made to the presentation of prior
periods to conform with current classifications.
(4) ACQUISITIONS
All acquisitions have been accounted for as purchases. Purchase prices
were allocated to acquired assets and assumed liabilities based on their
estimated fair value at acquisition. Acquisitions have been funded with internal
cash flow, bank borrowings and the issuance of debt and equity securities. The
Company purchased various other properties for consideration of $846,000, $4.7
million and $9.5 million during the years ended December 31, 1999, 2000 and
2001, respectively.
(5) IPF RECEIVABLES
At December 31, 2000 and 2001, IPF had net receivables of $48.9 million
and $41.4 million, respectively. The receivables represent overriding royalty
interests payable from an agreed-upon share of revenues until a specified return
is achieved. The royalties constitute property interests that serve as security
for the receivables. Due to favorable oil and gas prices during the last nine
months of 2000 and the first half of 2001, some of these receivables began to
generate a greater proportion of their contractual return. In the first nine
months of 2001, the book value of the affected receivables was increased and
approximately $1.8 million was recorded as a reduction to IPF expense. However,
because of lower prices, IPF
56
increased its reserve allowance by $2.0 million in the fourth quarter of 2001.
The Company estimates that $7.0 million of receivables at December 31, 2001 will
be repaid in the next twelve months and has classified them as current. IPF
receivables reflected valuation allowances of $13.7 million and $17.3 million at
December 31, 2000 and 2001, respectively. A further decline in the price of oil
could cause an increase in IPF's valuation allowances and a corresponding
decrease in income.
(6) DISPOSITIONS
In June 2000, the Company sold a gas plant for $19.7 million and recorded
a $716,000 loss.
The following table presents unaudited pro forma operating results as if
the sale of the gas plant had occurred on January 1, 2000 (in thousands, except
per share data).
Pro Forma
Year Ended
December 31,
2000
------------
Restated
Revenues $182,683
Net income 36,879
Earnings per share - basic and diluted 0.98
Total assets 669,179
Stockholders' equity 157,063
The pro forma results have been prepared for comparative purposes only.
They do not purport to present actual results that would have been achieved or
to be indicative of future results.
(7) INDEBTEDNESS
The Company had the following debt and Trust preferred outstanding as of
the dates shown. Interest rates, excluding the impact of interest rate swaps, at
December 31, 2001 are shown parenthetically (in thousands):
December 31,
-----------------------
2000 2001
-------- --------
SENIOR DEBT
Credit Facility (3.9%) $ 89,900 $ 95,000
NON-RECOURSE DEBT
Great Lakes credit facility (3.9%) 84,509 75,001
IPF credit facility (4.4%) 28,500 23,800
-------- --------
113,009 98,801
-------- --------
SUBORDINATED DEBT
8.75% Senior Subordinated Notes due 2007 125,000 79,115
6% Convertible Subordinated Debentures due 2007 37,550 29,575
-------- --------
162,550 108,690
-------- --------
TOTAL DEBT
365,459 302,491
======== ========
TRUST PREFERRED - MANDITORILY REDEEMABLE SECURITIES OF SUBSIDIARY 92,640 89,740
======== ========
TOTAL $458,099 $392,231
======== ========
57
From January 1, 2002 to March 1, 2002, the Company exchanged an additional
$0.9 million face amount of the 8.75% Notes. Interest paid in cash during the
years ended December 31, 2000 and 2001 totaled $42.2 million and $31.2 million,
respectively. No interest expense was capitalized during 1999, 2000 or 2001.
SENIOR DEBT
The Company maintains a $225 million secured revolving bank facility (the
"Parent Facility"). The Parent Facility provides for a borrowing base which is
subject to semi-annual redeterminations in April and October. On March 1, 2002,
the borrowing base on the Parent Facility was $120.0 million of which $16.5
million was available. Redeterminations are based on a variety of factors,
including banks' projection of future cash flows. Redeterminations require
approval by 75% of the lenders, redeterminations which result in an increase
require 100% approval. Interest is payable the earlier of quarterly or as LIBOR
notes mature. The loan matures in February 2003. A commitment fee is paid
quarterly on the undrawn balance at an annual rate of 0.25% to 0.50%. The
interest rate on the Parent Facility is LIBOR plus 1.50% to 2.25%, depending on
outstandings. At December 31, 2001, the commitment fee was 0.50% and the
interest rate margin was 0.75%. The weighted average interest rates on the
Parent Facility was 8.8% and 6.4% for the years ended December 31, 2000 and
2001, respectively. As of March 1, 2002, the interest rate was 3.3%.
NON-RECOURSE DEBT
The Company consolidates its proportionate share of borrowings on Great
Lakes' $275.0 million secured revolving bank facility (the "Great Lakes
Facility"). The Great Lakes Facility is non-recourse to Range and provides for a
borrowing base, which is subject to semi-annual redeterminations in April and
October. On March 1, 2002, the borrowing base was $200.0 million of which $54.0
million was available. Interest is payable the earlier of quarterly or as LIBOR
notes mature. The loan matures in September 2003. The interest rate on the
facility is LIBOR plus 1.50% to 2.00%, depending on outstandings. A commitment
fee is paid quarterly on the undrawn balance at an annual rate of 0.25% to
0.50%. At December 31, 2001, the commitment fee was 0.50% and the interest rate
margin was 0.625%. The weighted average interest rates on these borrowings,
excluding interest rate hedges, were 8.5% and 6.4% for the years ended December
31, 2000 and 2001, respectively. After hedging, the rate was 8.6% and 9.4% for
the twelve months ended December 30, 2000 and 2001, respectively. At March 1,
2002, the interest rate was 3.6%, excluding interest rate hedges and 6.5%
including interest rate hedges.
IPF has a $100.0 million secured revolving credit facility (the "IPF
Facility"). The IPF Facility is non-recourse to Range and matures in January
2004. The borrowing base under the IPF Facility is subject to semi-annual
redeterminations in April and October. On March 1, 2002, the borrowing base on
the IPF Facility was $35.0 million of which $11.7 million was available. The IPF
Facility bears interest at LIBOR plus 1.75% to 2.25% depending on outstandings.
Interest expense in the IPF Facility is included in IPF expenses in the
Consolidated Statements of Income and amounted to $3.4 million and $1.8 million
for the years ended December 31, 2000 and 2001, respectively. A commitment fee
is paid quarterly on the undrawn balance at an annual rate of 0.375% to 0.50%.
The weighted average interest rate on these borrowings was 8.5% and 6.4% for the
years ended December 31, 2000 and 2001, respectively. As of March 1, 2002, the
interest rate was 4.3%.
SUBORDINATED NOTES
The 8.75% Senior Subordinated Notes due 2007 (the "8.75% Notes") become
redeemable beginning on January 15, 2002, in whole or in part, at 104.375% of
principal, declining 1.46% each January 15 to par in 2005. The 8.75% Notes are
unsecured general obligations subordinated to all senior debt (as defined). The
8.75% Notes are guaranteed on a senior subordinated basis by the Company's
subsidiaries. Interest is payable semi-annually in January and July. During the
twelve months ended December 31, 2001, the Company repurchased $42.5 million
face amount of the 8.75% Notes at a discount. The Company also exchanged $3.4
million of the 8.75% Notes for common stock. Exchanges are not reflected on the
cash flow statement. The cash flow reflects a $41.2 million Repayment of debt
relating to these repurchases. The gain on these repurchases is included as a
Gain on retirement of securities on the Consolidated Statements of Operations.
The repurchased notes are held in treasury and may be reissued. Subsequent to
December 31, 2001, the Company exchanged for common stock an additional $0.9
million face amount of the 8.75% Notes. As of March 1, 2002, $78.2 million of
the 8.75% Notes remained outstanding.
The 6% Convertible Subordinated Debentures Due 2007 (the "6% Debentures")
are convertible into common stock at the option of the holder at any time at a
price of $19.25 per share. Interest is payable semi-annually in February and
58
August. The 6% Debentures mature in 2007 and are currently redeemable at 103.5%
of principal, declining 0.5% each February to 101% in 2006, remaining at that
level until it becomes par at maturity. The 6% Debentures are unsecured general
obligations subordinated to all senior indebtedness (as defined), including the
8.75% Notes. During 2000 and 2001, $13.8 million and $5.7 million of 6%
Debentures were retired at a discount in exchange for 2.5 million and 0.7
million shares of common stock, respectively. In addition, $2.3 million were
repurchased in 2001. Exchanges are not reflected on the cash flow statement.
Extraordinary gains of $4.3 million and $1.9 million were recorded in 2000 and
2001, respectively. As of March 1, 2002, $29.6 million of the 6% Debentures
remained outstanding.
TRUST PREFERRED - MANDITORILY REDEEMABLE SECURITIES OF SUBSIDIARY
In 1997, a special purpose affiliate, (the "Trust") issued $120 million of
5-3/4% Trust Convertible Preferred Securities (the "Trust Preferred"),
represented by 2,400,000 shares of Trust Preferred priced at $50 a share. The
Trust Preferred is convertible into common stock at a price of $23.50 per share.
The Trust invested the proceeds in 5-3/4% convertible junior subordinated
debentures issued by the Company (the "Junior Debentures"), its sole asset. The
Junior Debentures and the Trust Preferred mature in November 2027. At December
31, 2001, the Junior Debentures and the related Trust Preferred are redeemable
in whole or in part at 103.450% of principal declining 0.58% each November to
par in 2007.
The Company guarantees payments on the Trust Preferred only to the extent
the Trust has funds available. Such guarantee, taken together with other
obligations provides a full subordinated guarantee of the Trust Preferred. The
Company has the right, at its sole discretion, to suspend payment of all
distributions on the Trust Preferred for five years without triggering a
default. The accounts of the Trust are included in Range's consolidated
financial statements after eliminations. Distributions recorded as interest
expense in the statement of operations are deductible for tax purposes, and are
subject to limitations in the Parent Facility as described below. In the twelve
months ended December 31, 2001, $2.9 million of Trust Preferred was reacquired
at a discount in exchange for 291,000 shares of common stock. In addition,
$50,000 of Trust Preferred were repurchased. An extraordinary gain of $1.2
million was recorded in 2001. The exchange transactions are not reflected on the
cash flow statement because no cash was involved. As of March 1, 2002, $89.7
million of the Trust Preferred remained outstanding.
The debt agreements contain various covenants relating to net worth,
working capital maintenance, restrictions on dividends and financial ratio. If
certain ratio requirements are not met, payments of interest on the Trust
Preferred would be restricted. The Parent Facility prohibits the payment of
dividends on common stock. The Company was in compliance with all such covenants
at December 31, 2001. Under the most restrictive covenant, $3.0 million of
dividends or other restricted payments could be paid at December 31, 2001. Under
the Parent Facility, common dividends are prohibited and dividends may not be
paid on the Trust Preferred unless certain ratio requirements are met.
Following is the principal maturity schedule for the long-term debt outstanding
as of December 31, 2001 (in thousands):
Year ending December 31:
2002 $ --
2003 170,001
2004 23,800
2005 --
2006 --
2007 108,690
Thereafter 89,740
--------
$392,231
========
(8) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
The Company's financial instruments include cash and equivalents, accounts
receivable, accounts payable, debt obligations and commodity and interest rate
derivatives. The book value of cash and equivalents and accounts receivable and
payable are considered to be representative of fair value because of their short
maturity. The book values of borrowings under the Parent Facility, the Great
Lakes Facility, and IPF Facility are believed to approximate fair value because
of their floating rate structure.
A portion of the Company's future oil and gas sales is periodically hedged
through the use of option or swap contracts. Realized gains and losses on these
instruments are reflected in the contract month being hedged as an adjustment to
oil and gas revenue. At times, the Company seeks to manage interest rate risk on
its credit facilities through the use of swaps. Gains and losses on these swaps
are included as an adjustment to interest expense in the relevant periods.
59
The following table sets forth the book and estimated fair values of financial
instruments (in thousands):
December 31, 2000 December 31, 2001
------------------------------------ ---------------------------------
Book Fair Book Fair
Value Value Value Value
--------------- --------------- --------------- --------------
Restated Restated Restated Restated
Assets
Cash and equivalents $ 2,612 $ 2,612 $ 3,380 $ 3,380
Marketable securities 2,861 2,861 2,323 2,323
Commodity swaps* - - 52,100 52,100
--------------- --------------- --------------- --------------
Total 5,473 5,473 57,803 57,803
--------------- --------------- --------------- --------------
Liabilities
Commodity swaps - (72,090) - -
Interest rate swaps - (879) (2,631) (2,631)
Long-term debt (365,459) (348,257) (302,491) (292,028)
Trust Preferred (92,640) (53,268) (89,740) (50,254)
--------------- --------------- --------------- --------------
Total (458,099) (474,494) (394,862) (344,913)
--------------- --------------- --------------- --------------
Net financial instruments $ (452,626) $ (469,021) $ (337,059) $ (287,110)
=============== =============== =============== ==============
* Excluding hedge agreements with Enron (see below)
At December 31, 2001, the Company had open hedging contracts (excluding
contracts with Enron) covering 47.3 Bcf of gas at prices averaging $4.02 per mcf
and 700,000 barrels of oil at prices averaging $25.97 barrel. Their fair value,
represented by the estimated amount that would be realized upon termination,
based on contract versus New York Mercantile Exchange ("NYMEX") price,
approximated a net unrealized pre-tax gain of $52.1 million at December 31,
2001. These contracts expire monthly through December 2005. Gains or losses on
open and closed hedging transactions are determined as the difference between
the contract price and the reference price, generally closing prices on the
NYMEX. Transaction gains and losses are determined monthly and are included as
increases or decreases to oil and gas revenues in the period the hedged
production is sold. Net pre-tax losses incurred relating to these derivatives
for the years ended December 31, 1999, 2000 and 2001 were $10.6 million, $43.2
million, and $6.2 million, respectively. These hedging positions are recorded on
the Company's balance sheet at an estimate of fair value based on a comparison
of the contract price and a reference price, generally NYMEX.
The Company had hedge agreements with Enron for 22,700 Mmbtu per day,
at $3.20 per Mmbtu for the first three months of 2002. Amounts due from Enron
are not included in the open hedges described in the previous paragraph. Based
on accounting requirements, the Company has recorded an allowance for bad debts
at year-end 2001 of $1.4 million, offset by a $318,000 ineffective gain included
in 2001 income and $1.0 million gain included in OCI at year-end 2001 related to
these amounts due from Enron. The gain included in OCI at year-end 2001 will be
included in income in the first quarter of 2002. The last of the Enron contracts
will expire as of March 2002.
60
The following schedule shows the effect of the Company's hedge position
for the four quarters ended December 31, 2001 and the projected impact of open
contracts (excluding contracts with Enron) as of that date.
Hedging
Gain (Loss)
Quarter Ended Exposure
-------------- --------------
Closed contracts:
March 31, 2001 $ (23,440)
June 30, 2001 (5,250)
September 30, 2001 8,450
December 31, 2001 14,047
--------------
Total $ (6,193)
==============
Open Contracts:
March 31, 2002 11,010
June 30, 2002 9,809
September 30, 2002 8,613
December 31, 2002 7,732
March 31, 2003 3,233
June 30, 2003 2,897
September 30, 2003 2,828
December 31, 2003 2,628
March 31, 2004 619
June 30, 2004 668
September 30, 2004 657
December 31, 2004 701
March 31, 2005 167
June 30, 2005 165
September 30, 2005 187
December 30, 2005 186
--------------
Total $ 52,100
==============
Interest rate swap agreements are accounted for on the accrual basis.
Income or expense resulting from these agreements is recorded as an adjustment
to interest expense in the period covered. At December 31, 2001, Great Lakes had
interest rate swap agreements totaling $100.0 million, 50% of which is
consolidated at Range. Two agreements totaling $45.0 million at rates of 7.1%
each expire in May 2004. Two agreements of $10.0 million each at 6.2% which
expire in December 2002. Five agreements totaling $35.0 million at rates of
4.8%, 4.7%, 4.6%, 4.5% and 4.5% which expire in June of 2003. Range's share of
the fair value of the swaps at December 31, 2001, was a net loss of $2.6 million
based on current quotes. The agreements expiring in May 2004 may be terminated
at the counterparty's option in May 2002. On December 31, 2001, the 30-day LIBOR
rate was 1.9%. The value of these swap agreements is marked to market each
quarter. In 2001, GLEP incurred additional interest expense of $2.5 million due
to interest swaps.
The combined fair value of oil and gas hedging contracts and interest
rate swaps, totaling $49.5 million appear as Unrealized derivative hedging gains
and Unrealized derivative hedging losses on the balance sheet at December 31,
2001. Hedging activities are conducted with major financial or commodities
trading institutions which management believes are acceptable credit risks. At
times, such risks may be concentrated with certain counterparties. The credit
worthiness of these counterparties is subject to continuing review.
(9) COMMITMENTS AND CONTINGENCIES
The Company is involved in various legal actions and claims arising in
the ordinary course of business. In the opinion of management, such litigation
and claims are likely to be resolved without material adverse effect on the
Company's financial position or results of operations. During 2001, the Company
incurred approximately $480,000 of litigation costs. During 1998, the Company
recorded a $2.5 million liability as part of the consideration for the Domain
acquisition. The
61
provision was designed to cover the anticipated costs of resolving a shareholder
suit and certain other litigation and contingent liabilities. During 2000,
certain of the litigation and disputes were settled at a cost including legal
fees of $621,000, a level well below that anticipated. As a result, the
liability was able to be reduced by $1.0 million which was credited to general
and administrative expense. In 2001, a further $817,000 was expended on legal
fees and in settlement of litigation and disputes related to the $2.5 million
liability.
In 2000, a royalty owner filed a suit asking for a class action
certification against Great Lakes and the Company in New York, alleging that gas
was sold to affiliates and gas marketers at low prices, inappropriate post
production expenses reduced proceeds to the royalty owners, and that Great Lakes
improperly accounted for the royalty owners' share of gas. The action sought a
proper accounting for all gas sold, an amount equal to the difference in prices
paid and the highest obtainable prices, punitive damages and attorneys' fees.
The case has been remanded to state court in New York. While the outcome of this
suit is uncertain, the Company believes it will be resolved without material
adverse effect on its financial position or results of operations.
The Company leases certain office space and equipment under cancelable
and non-cancelable leases, most of which expire within three years and may be
renewed by the Company. Rent expense under such arrangements totaled $1.1
million, $1.0 million and $1.1 million in 1999, 2000 and 2001, respectively.
Future minimum rental commitments under non-cancelable leases are as follows (in
thousands):
2002 $ 820
2003 546
2004 513
2005 501
2006 126
------
$2,506
======
(10) STOCKHOLDERS' EQUITY
In 1995, the Company issued 1,150,000 shares of $2.03 Convertible
Exchangeable Preferred Stock (the "$2.03 Preferred") for $28.8 million. The
$2.03 Preferred was convertible into 2.632 shares of common stock representing a
conversion price of $9.50 per common share. Through December 31, 2000, $23.2
million of the $2.03 Preferred had been exchanged for 4.6 million of common
stock. For the twelve months ended December 31, 2001, the majority of the
outstanding $2.03 Preferred was exchanged for 767,000 shares of common stock and
the remaining shares were repurchased for cash. Gains on exchanges of $2.03
Preferred are not included in net income but they are included in income
available to common shareholders for earnings per share purposes. Exchange
transactions are not reflected on the cash flow statement because no cash was
involved. The elimination of the $2.03 Convertible Preferred stock has reduced
the annual dividend requirement by $2.3 million.
The following is a schedule of changes in outstanding common shares:
Year Ended December 31,
------------------------------
2000 2001
---------- ----------
Beginning Balance 37,901,789 49,187,682
Issuances:
Benefit plans 269,714 372,398
Stock options exercised 241,637 223,594
Exchange for:
6% Debentures 2,496,789 758,597
Trust Preferred 3,231,548 291,211
$2.03 Preferred 4,583,993 766,889
8.75% Senior Notes - 779,960
Stock Purchase Plan 363,422 263,000
In lieu of dividends 106,597 -
Other (7,807) (56)
---------- ----------
11,285,893 3,455,593
---------- ----------
Ending Balance 49,187,682 52,643,275
========== ==========
62
Supplemental disclosures of non-cash investing and financing activities
Year Ended December 31,
----------------------------------------------
1999 2000 2001
--------------- ------------- -----------
(in thousands)
Restated Restated Restated
Common stock issued:
Under benefit plans $ 1,440 $ 650 $ 1,385
In exchange for fixed income securities $ 2,978 $ 37,086 $ 14,222
In payment of preferred dividends $ - $ 110 $ -
(11) STOCK OPTION AND PURCHASE PLANS
The Company has five stock option plans, of which two are active, and a
stock purchase plan. Under these plans, incentive and non-qualified options and
stock purchase rights are issued to directors, officers, and employees pursuant
to decisions of the Compensation Committee of the Board. Information with
respect to the stock option plans is summarized below:
Inactive Active
----------------------------------------------------------------------------
Domain Average
Domain Directors' 1989 Directors' 1999 Exercise
Plan Plan Plan Plan Plan Total Price
---------- ---------- ---------- ---------- ---------- ---------- ----------
Outstanding at December 31, 1998 934,141 9,670 2,159,102 140,000 - 3,242,913 $ 8.39
Granted - - 904,150 40,000 60,000 1,004,150 2.89
Exercised (374,264) - (70,000) - - (444,264) 0.68
Expired/cancelled (1,445) - (483,562) (12,000) - (497,007) 8.64
---------- ---------- ---------- ---------- ---------- ---------- ----------
Outstanding at December 31, 1999 558,432 9,670 2,509,690 168,000 60,000 3,305,792 7.72
Granted - - - 56,000 643,200 699,200 2.12
Exercised (98,697) - (246,575) (8,000) - (353,272) 2.57
Expired/cancelled (210,770) (9,670) (1,080,222) (80,000) (38,000) (1,418,662) 8.58
---------- ---------- ---------- ---------- ---------- ---------- ----------
Outstanding at December 31, 2000 248,965 - 1,182,893 136,000 665,200 2,233,058 6.23
Granted - - - 56,000 774,350 830,350 6.46
Exercised (111,481) - (59,113) - (53,000) (223,594) 1.63
Expired/cancelled - - (581,080) (72,000) (71,437) (724,517) 13.05
---------- ---------- ---------- ---------- ---------- ---------- ----------
Outstanding at December 31, 2001 137,484 - 542,700 120,000 1,315,113 2,115,297 $ 4.47
========== ========== ========== ========== ========== ========== ==========
There were options exercisable of 1,995,242 (weighted average price of $7.81),
1,043,452 (weighted average price of $9.32) and 585,526 (weighted average price
of $4.04) at December 31, 1999, 2000 and 2001.
Two years ago, shareholders approved the 1999 Stock Option Plan (the
"1999 Plan") providing for the issuance of options on 1.4 million common shares.
In May 2001, shareholders approved an increase in the number of options issuable
to 3.4 million shares. All options issued under the 1999 Plan vest 25% per year
beginning a year after grant and expire in 10 years. During the year-ended
December 31, 2001, 774,350 options were granted under the 1999 Plan at exercise
prices of $4.17 to $6.67 a share. At December 31, 2001, 1.3 million options were
outstanding under the 1999 Plan at exercise prices of $1.94 to $6.67.
The Company also maintains the 1989 Stock Option Plan (the "1989 Plan")
which authorized the issuance of options on 3.0 million common shares. Options
have been granted under this plan since the 1989 Plan was adopted. Options
issued under
63
the 1989 Plan vest 30% after one year, 60% after two years and 100% after three
years and expire in 5 years. At December 31, 2001, 542,700 options remained
outstanding under the 1989 Plan at exercise prices of $2.63 to $17.75.
In 1994, shareholders approved the Outside Directors' Stock Option Plan
(the "Directors' Plan"). In 2000, shareholders approved an increase in the
number of options issuable under the Directors' Plan to 300,000, extended the
term of the options to ten years and set the vesting period at 25% per year
beginning a year after grant. During the twelve months ended December 31, 2001,
56,000 options were granted under the Directors' Plan at exercise prices of
$5.52 to $6.00 a share. At December 31, 2001, 120,000 options were outstanding
under the Directors' Plan at exercise prices of $2.81 to $6.00.
The Domain stock option plan was adopted when Domain was acquired, with
existing Domain options becoming exercisable into Range common stock. Since
August 1998, no further options have been granted under the Plan. At December
31, 2001, 137,484 options remained outstanding under the Plan at a price of
$3.46 a share.
In total, 2.1 million options are outstanding at December 31, 2001 at
exercise prices ranging from $1.94 to $17.75 as follows:
Inactive Active
------------------- --------------------------------
Range of Average Weighted Average Domain 1989 Directors' 1999
Exercise price Exercise price Remaining Life(Yrs) Plan Plan Plan Plan Total
-------------- -------------- ------------------- ---- ---- ---- ---- -----
$1.94-$4.99 $ 2.58 $7.3 137,484 378,487 64,000 563,763 1,143,734
5.00-9.99 6.69 8.2 - 163,713 56,000 751,350 971,063
17.75 17.75 .2 - 500 - - 500
------- ------- ------- --------- ---------
Total 137,484 542,700 120,000 1,315,113 2,115,297
======= ======= ======= ========= =========
In 1997, shareholders approved a Stock Purchase Plan (the "Stock
Purchase Plan") authorizing the sale of 900,000 shares of common stock to
officers, directors, key employees and consultants. Under the Stock Purchase
Plan, the right to purchase shares at prices ranging from 50% to 85% of market
value may be granted and there is a one year hold requirement. To date, all
purchase rights have been granted at 75% of market. Due to the discount from
market value, in the restatement, the Company recorded additional compensation
expense of $140,000, $236,000 and $375,000 during 1999, 2000 and 2001,
respectively (restated). In May 2001, shareholders approved an increase in the
number of shares authorized under the Plan to 1,750,000. Through December 31,
2001, 1,121,319 shares have been sold under the Plan for $4.7 million. At
December 31, 2001, rights to purchase 203,000 shares were outstanding with terms
expiring in May, 2003.
The Company has adopted the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." Accordingly, no compensation cost has
been recognized for the stock option plans. Had compensation cost been
determined based on the fair value at the grant date for awards in 1999, 2000
and 2001 consistent with the provisions of SFAS No. 123, the Company's net
income (loss) and earnings (loss) per share would have been reduced to the pro
forma amounts indicated below:
Year Ended December 31,
-----------------------
1999 2000 2001
---- ---- ----
Restated Restated Restated
(in thousands, except per share data)
As reported -
Net income (loss) $ (23,542) $ 36,578 $ 17,663
Earnings (loss) per share
-basic (0.71) 0.97 0.36
-diluted (0.71) 0.96 0.36
Pro forma -
Net income (loss) $ (24,607) $ 36,412 $ 16,877
Earnings (loss) per share
-basic (0.74) 0.97 0.35
-diluted (0.74) 0.95 0.34
64
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 1999, 2000 and 2001, respectively: fair value of $1.37,
$2.14 and $6.50 per share; dividend yields of $0.03, $0 and $0 per share;
expected volatility factors of 3.55, 64.89 and 69.80; risk-free interest rates
of 5.10%, 5.51% and 4.98%, and an average expected life of six years.
(12) DEFERRED COMPENSATION
In 1996, the Board of Directors of the Company adopted a deferred
compensation plan (the Plan) to encourage employees to invest in the shares of
the Company. The Plan gives employees the ability to defer all or a portion of
their salaries and bonuses and invest in Common Stock of the Company at a
discount to market prices or make other investments at the employee's
discretion. The stock held in the employee benefit trust is treated in a manner
similar to treasury stock with an offsetting amount reflected as a deferred
compensation liability of the Company and is marked-to-market, with any
necessary adjustment to general and administrative expense. The Company recorded
total expenses related to deferred compensation of $421,000 and $3.5 million in
1999 and 2000 respectively, and a net benefit of $2.1 million in 2001.
(13) BENEFIT PLAN
The Company maintains a 401(k) Plan for its employees. The Plan permits
employees to contribute up to 15% of their salary on a pre-tax basis. The
Company makes discretionary contributions to the 401(k) Plan annually which are
fully vested after four years of service. In 1999, 2000 and 2001, the Company
contributed $854,000, $483,000 and $554,000 of common stock (valued at market)
to the 401(k) Plan. Employees have a variety of investment options available in
the 401K Plan and are encouraged to maintain diversity in accordance with their
personnal investment strategy.
(14) INCOME TAXES
The Company's federal income tax provision (benefit) for the years
ended December 31, 1999, 2000 and 2001 was $388,000, ($355,000) and $14,505,
respectively. The current portion of income tax provision for 1999 represented
state income tax payable. A reconciliation between the statutory federal income
tax rate and the Company's effective federal income tax rate is as follows:
Year Ended December 31,
----------------------------------------------------
1999 2000 2001
-------- -------- ----------
Restated Restated
Statutory tax rate (34)% 34% 35 %
Gain on retirement of securities - 34 10
Permanent differences - 11 1
Valuation allowance 34 (88) (45)
State 19 (6) (1)
Other - (14) (4)
-------- --------- -------
Effective tax rate 19 % (29)% 0 %
-------- --------- -------
Income taxes paid (refunded) $388,000 ($355,000) $14,505
======== ========= =======
The Company follows SFAS Statement No. 109, "Accounting for Income
Taxes," pursuant to which the liability method is used. Under this method,
deferred tax assets and liabilities are determined based on differences between
financial reporting and tax bases of assets and liabilities and are measured
using the enacted tax rates and regulations that will be in effect when the
differences are expected to reverse.
65
Significant components of the Company's deferred tax liabilities and assets are
as follows (in thousands):
December 31,
-----------------------------
2000 2001
--------- ---------
Restated Restated
Deferred tax assets
Net operating loss carry over $ 55,180 $ 53,977
Allowance for doubtful accounts 6,125 7,035
Percentage depletion carryover 4,895 5,256
AMT credits and other 660 660
--------- ---------
Total deferred tax assets 72,425 66,928
Deferred tax liabilities
Depreciation (54,110) (54,732)
Unrealized gain on hedging - (16,692)
--------- ---------
Net deferred tax assets (liabilities) $ 18,315 $ (4,496)
========= =========
Valuation allowance $ (18,315) $ -
========= =========
A valuation allowance on the net deferred tax asset was originally
established due to the uncertainty of whether future taxable income would be
sufficient to utilize it. Increased oil and gas prices in early 2001 allowed the
reversal of the valuation allowance during the first half of 2001. Therefore,
income taxes were recorded at a statutory rate for financial reporting in the
second and third quarters of 2001. Due to the Company's tax loss carryover,
percentage depletion carryover and AMT credits, such statutory taxes were
deferred. However, due to the property impairments recorded in the fourth
quarter of 2001, taxes recorded earlier in the year were reversed and no
statutory provision for taxes was required in 2001. A deferred tax liability of
$4.5 million is recorded on the balance sheet at year-end 2001. Without
considering Other comprehensive income (loss), deferred tax assets exceed
deferred tax liabilities by $12.2 million. The inclusion of OCI causes the
deferred tax liabilities to exceed deferred tax assets by the amount recorded on
the balance sheet and accordingly, the valuation allowance on the deferred tax
asset was reversed in 2001. As of January 1, 2002, the Company needs to earn
approximately $35.0 million of pre-tax income from the unrealized hedge included
in OCI at year-end before statutory taxes will be recorded on the statement of
operations. Timing of when the Company will record deferred taxes is uncertain.
At December 31, 2001, the Company had regular net operating loss
("NOL") carryovers of $174.3 million and alternative minimum tax ("AMT") NOL
carryovers of $155.9 million that expire between 2012 and 2020. Regular NOLs
generally offset taxable income and to such extent, no income tax payments are
required. To the extent that AMT NOLs offset AMT income, no alternative minimum
tax payment is due. NOLs generated prior to a change of control are subject to
limitations. The Company experienced several change of control events between
1994 and 1998 due to acquisitions. Consequently the use of $34.1 million of NOLs
is limited to $10.2 million per year. Remaining NOLs are not limited. At
December 31, 2001, the Company had a statutory depletion carryover of $6.6
million and an AMT credit carryovers of $660,000 which are not subject to
limitation or expiration.
66
The following table sets forth the year of expiration of NOL (pretax)
carryovers which generate the largest component of the deferred tax assets
listed above:
NOL Carryover Amount
--------------------
Expiration Regular AMT
---------- -------- --------
in thousands)
2002 $ -- $ --
2003 -- --
2004 -- --
2005 -- --
Thereafter 174,319 155,865
-------- --------
Total $174,319 $155,865
======== ========
(15) RESTRUCTURING COSTS
In late 1998, the Company initiated a restructuring plan to reduce
costs. The restructuring plan included closing field office, eliminating certain
geological and exploration positions, canceling certain exploration and drilling
obligations and consolidating administrative functions at the remaining
locations. The plan was completed in 1999.
(16) EARNINGS (LOSS) PER COMMON SHARE
The following table sets forth the computation of basic and diluted
earnings (loss) per common share (in thousands except per share amounts):
Year Ended December 31,
---------------------------------------------
1999 2000 2001
-------- -------- --------
Restated Restated Restated
Numerator:
Income (loss) before extraordinary item $ (25,972) $ 18,815 $13,712
Gain on retirement of $2.03 Preferred Stock - 5,966 556
Preferred dividends (2,334) (1,554) (10)
--------- -------- -------
Numerator for earnings (loss) per share,
before extraordinary item (28,306) 23,227 14,258
Extraordinary item
Gain on retirement of securities, net 2,430 17,763 3,951
--------- -------- -------
Numerator for earnings (loss) per share,
basic and diluted $ (25,876) $ 40,990 $18,209
========= ======== =======
Denominator:
Weighted average shares 36,933 42,882 51,159
Stock held by employee benefit trust (407) (767) (1,002)
--------- -------- -------
Weighted average shares - basic 36,526 42,115 50,157
Stock held by employee benefit trust 407 767 1,002
Dilutive potential common shares stock options - 50 106
--------- -------- -------
Denominator for diluted earnings per share 36,933 42,932 51,265
========= ======== =======
Earnings (loss) per share basic and diluted:
Before extraordinary item
Basic $ (0.78) $ 0.55 $ 0.28
Diluted $ (0.78) $ 0.54 $ 0.28
After extraordinary item
Basic $ (0.71) $ 0.97 $ 0.36
Diluted $ (0.71) $ 0.96 $ 0.36
67
During 2000 and 2001, 75,000 and 129,000 stock options were included in
the computation of diluted earnings per share. All remaining stock options, the
6% Debentures, Trust Preferred and the $2.03 Preferred were not included because
their inclusion would have been antidilutive. In 1999, 18 common shares held by
the employee benefit trust are excluded because they are antidilutive.
The Company has and will continue to consider exchanging common stock
or other equity-linked securities for fixed income securities. Existing common
stockholders may be materially diluted if substantial exchanges are consummated.
The extent of dilution will depend on the number of shares and price at which
common stock is issued, the price at which newly issued securities are
convertible into common stock, and the price at which fixed income securities
are reacquired.
(17) MAJOR CUSTOMERS
The Company markets its production on a competitive basis. Gas is sold
under various types of contracts ranging from life-of-the-well to short-term
contracts that are cancelable within 30 days. Oil purchasers may be changed on
30 days notice. The price for oil is generally equal to a posted price set by
major purchasers in the area. The Company sells to oil purchasers on the basis
of price and service. For the year ended December 31, 2001, three customers
accounted for 10% or more of total oil and gas revenues and the combined sales
to those three customers accounted for 50% of total oil and gas revenues.
Management believes that the loss of any one customer would not have a material
long-term adverse effect on the Company.
From the inception of the Great Lakes joint venture through June 30,
2001, Great Lakes sold approximately 90% of its gas production to FirstEnergy,
at prices based on the close of NYMEX each month plus a basis differential.
Effective July 1, 2001, Great Lakes began selling its gas to several different
companies, including FirstEnergy. In the year ended December 31, 2001,
approximately 91% of Great Lakes gas was sold at prices based on the close of
NYMEX contracts each month plus a basis differential. The remainder is sold at a
fixed price.
(18) OIL AND GAS ACTIVITIES
The following summarizes selected information with respect to producing
activities (in thousands):
Year Ended December 31,
---------------------------------------------
1999 2000 2001
--------- --------- -----------
Restated Restated Restated
Oil and gas properties:
Subject to depletion $ 898,031 $ 947,526 $ 1,021,898
Unproved 61,812 49,523 25,731
--------- --------- -----------
Total 959,843 997,049 1,047,629
Accumulated depletion (389,200) (443,876) (514,272)
--------- --------- -----------
Net $ 570,643 $ 553,173 $ 533,357
========= ========= ===========
Costs incurred:
Acquisition $ 846 $ 4,701 $ 9,489
Development 30,597 46,032 69,162
Exploration 3,604 4,498 11,405
--------- --------- -----------
Total $ 35,047 $ 55,231 $ 90,056
========= ========= ===========
Acquisition costs in 1999 do not reflect $68 million of value
associated with the Company receiving a 50% interest in the reserves contributed
by FirstEnergy to Great Lakes. The Company's share of such reserves was 81.6
Bcfe. Exploration costs include capitalized as well as expensed outlays.
68
(19) INVESTMENT IN GREAT LAKES
The Company owns 50% of Great Lakes and consolidates its proportionate
interest in the joint venture's assets, liabilities, revenues and expenses. The
following table summarizes the interest in Great Lakes' audited financial
statements as of or for the year ended December 31, 2001.
December 31, 2001
(In thousands)
-----------------
Restated
Current assets $ 15,954
Oil and gas properties, net 168,090
Transportation and field assets, net 15,645
Other assets 110
Current liabilities 11,248
Long-term debt 75,000
Members' equity 111,206
Revenues 52,735
Net income 11,528
(20) GAIN ON FORMATION OF GREAT LAKES
In September 1999, Range transferred all of its Appalachian oil and gas
properties and associated gas gathering and transportation systems to Great
Lakes in exchange for a 50% ownership interest. Additionally, the Company
contributed $188.3 million of indebtedness to Great Lakes. The Great Lakes
partners have no commitment to support the operations or obligations of Great
Lakes. Range recognized a gain of $30.9 million (restated), which was
attributable to the portion of the net assets associated with the 50% interest
of the Company's joint venture partner. The gain was calculated by comparing the
estimate of the fair value of the assets and liabilities conveyed to their net
book value for the assets deemed sold by Range. Great Lakes' DD&A rate is higher
than the Company's DD&A rate for its share of such production due to the lower
cost basis attributed to Range's investment in Great Lakes versus its
proportionate share of Great Lakes assets. DD&A is reduced in consolidation to
reflect the Company's investment.
(21) EXTRAORDINARY ITEMS
During 1999, 699,000 shares of common stock were exchanged for $2.3
million of Trust Preferred and $3.6 million of 6% Debentures. During 2000, 5.7
million shares of common stock were exchanged for $25.0 million of Trust
Preferred and $13.8 million of 6% Debentures. During 2001, 1.8 million shares of
common stock were exchanged for $2.9 million of Trust Preferred, $5.7 million of
6% Debentures and $3.4 million of 8.75% Senior Subordinated Notes. In addition,
$50,000 of Trust Preferred, $2.3 million of 6% Debentures and $42.5 million of
8.75% Senior Subordinated Notes were repurchased. Since 1998, there have been
13.6 million shares of common stock exchanged for convertible debt and
securities in the amount of $85.4 million. In connection with these exchanges,
an extraordinary gain net of costs of $2.4 million, $17.8 million and $4.0
million was recorded in 1999, 2000 and 2001, respectively, because the
securities were retired at a discount. In addition, 4.6 million and 767,000
shares of common stock were exchanged for $23.2 million and $5.4 million of the
$2.03 Preferred during 2000 and 2001, respectively. In 2001, the remaining of
$2.03 Preferred were repurchased for $74,000.
(22) UNAUDITED SUPPLEMENTAL RESERVE INFORMATION
The Company and its 50% pro rata portion of Great Lakes' proved oil and
gas reserves are located in the United States. Proved reserves are those
quantities of crude oil and natural gas which, based 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.
69
The following schedules are presented in accordance with SFAS No. 69
("SFAS 69"), "Disclosures about Oil and Gas Producing Activities", to provide
users with a common base for preparing estimates of future cash flows and
comparing reserves among companies. Additional background information allows
concerning four of the schedules.
Estimated Net Proved Oil and Natural Gas Reserves - Reserves of crude
oil, condensate, natural gas liquids and natural gas estimated by the Company's
engineers and are adjusted to reflect contractual arrangements and royalty rates
in effect at the end of each year. Many assumptions and judgmental decisions are
required to estimate reserves. Reported quantities are subject to future
revisions, some of which may be substantial, as additional information becomes
available from: reservoir performance, new geological and geophysical data,
additional drilling, technological advancements, price changes and other
economic factors.
The U.S. Securities and Exchange Commission defines proved reserves as
those volumes of crude oil, condensate, natural gas liquids and natural gas that
geological and engineering data demonstrate with reasonable certainty are
recoverable from known reservoirs under existing economic and operating
conditions. Proved undeveloped reserves are volumes expected to be recovered as
a result of additional investments for drilling new wells to offset productive
units, recompleting existing wells, and/or installing facilities to collect and
transport production.
Production quantities shown are net volumes withdrawn from reservoirs.
These may differ from sales quantities due to inventory changes, and especially
in the case of natural gas, volumes consumed for fuel and/or shrinkage from
extraction of natural gas liquids.
SFAS 69 requires calculation of future net cash flows using a 10%
annual discount factor and year-end prices, costs and statutory tax rates,
except for known future changes such as contracted prices and legislated tax
rates. The reported value of proved reserves is not necessarily indicative of
either fair market value or present value of future cash flows because prices,
costs and governmental policies do not remain static; appropriate discount rates
may vary; and extensive judgment is required to estimate the timing of
production. Other logical assumptions would likely have resulted in
significantly different amounts.
The average prices used at December 31, 2001 to estimate the reserve
information were $17.59 per barrel for oil, $12.38 per barrel for natural gas
liquids and $2.70 per Mcf for gas using the benchmark NYMEX prices of $20.38 per
barrel and $2.63 per Mmbtu. The average prices at December 31, 2000 were $24.46
per barrel for oil, $14.91 per barrel for natural gas liquids and $9.57 per Mcf
for gas using the benchmark NYMEX prices of $26.80 per barrel and $9.77 per
Mmbtu. The average prices at December 31, 1999 were $23.48 per barrel for oil,
$15.69 per barrel for natural gas liquids and $2.34 per mcfe for gas using the
benchmark NYMEX prices of $25.60 per barrel and $2.44 per Mmbtu.
70
QUANTITIES OF PROVED RESERVES
Crude Oil Natural
and Gas
NGLs Natural Gas Equivalent
--------- ----------- ----------
(Mbbls) (Mmcf) (Mmcfe)
Balance, December 31, 1998 27,129 633,317 796,091
Revisions 1,294 (39,298) (31,534)
Extensions, discoveries and additions 307 11,066 12,908
Purchases 5,241 51,751 83,197
Sales (2,495) (162,245) (177,215)
Production (2,659) (50,808) (66,762)
------ -------- --------
Balance, December 31, 1999 28,817 443,783 616,685
Revisions (1,699) (1,186) (11,380)
Extensions, discoveries and additions 1,226 26,639 33,995
Purchases 226 1,605 2,961
Sales (170) (2,135) (3,155)
Production (2,398) (41,039) (55,427)
------ -------- --------
Balance, December 31, 2000 26,002 427,667 583,679
Revisions (3,360) (33,575) (53,735)
Extensions, discoveries and additions 479 31,542 34,416
Purchases 427 5,761 8,323
Sales (627) (190) (3,952)
Production (2,242) (42,278) (55,730)
------ -------- --------
Balance, December 31, 2001 20,679 388,927 513,001
====== ======== ========
PROVED DEVELOPED RESERVES
December 31, 1999 17,884 299,436 406,740
====== ======== ========
December 31, 2000 17,215 305,796 409,086
====== ======== ========
December 31, 2001 14,066 276,162 360,558
====== ======== ========
The "Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves" ("Standardized Measure") is a disclosure
requirement of SFAS 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.
71
STANDARDIZED MEASURE
As of December 31,
-------------------------------------------------
1999 2000 2001
----------- ----------- -----------
(in thousands)
Future cash inflows $ 1,689,541 $ 4,697,062 $ 1,397,897
Future costs:
Production (486,618) (755,727) (471,144)
Development (189,784) (177,070) (176,799)
----------- ----------- -----------
Future net cash flows 1,013,139 3,764,265 749,954
Income taxes (131,529) (457,996) (87,745)
----------- ----------- -----------
Total undiscounted future net cash flows 881,610 3,306,269 662,209
10% discount factor (378,459) (1,800,007) (350,801)
----------- ----------- -----------
Standardized measure $ 503,151 $ 1,506,262 $ 311,408
=========== =========== ===========
CHANGES IN STANDARDIZED MEASURE
As of December 31,
-------------------------------------------------
1999 2000 2001
----------- ----------- -----------
(in thousands)
Standardized measure, beginning of year $ 517,095 $ 503,151 $ 1,506,262
Revisions:
Prices 128,799 1,184,950 (1,076,168)
Quantities (37,911) (89,180) (8,244)
Estimated future development cost 8,941 36,650 4,620
Accretion of discount 45,420 63,468 196,426
Income taxes (14,307) (130,626) 114,556
----------- ----------- -----------
Net revisions 130,942 1,065,262 (768,810)
Purchases 71,022 8,003 6,245
Extensions, discoveries and additions 16,354 91,855 25,815
Production (77,884) (134,556) (165,033)
Sales (136,491) (8,525) (2,967)
Changes in timing and other (17,887) (18,928) (290,104)
----------- ----------- -----------
Standardized measure, end of year $ 503,151 $ 1,506,262 $ 311,408
=========== =========== ===========
72
RANGE RESOURCES CORPORATION
INDEX TO EXHIBITS
(Item 14[a 3])
Exhibit No. Description
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3.1.1. Certificate of Incorporation of Lomak dated March 24, 1980 (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
3.1.2. Certificate of Amendment of Certificate of Incorporation dated July 22, 1981 (incorporated by
reference to the Company's Registration Statement (No. 33-31558)).
3.1.3. Certificate of Amendment of Certificate of Incorporation dated September 8, 1982 (incorporated by
reference to the Company's Registration Statement (No. 33-31558)).
3.1.4. Certificate of Amendment of Certificate of Incorporation dated December 28, 1988 (incorporated by
reference to the Company's Registration Statement (No. 33-31558)).
3.1.5. Certificate of Amendment of Certificate of Incorporation dated August 31, 1989 (incorporated by
reference to the Company's Registration Statement (No. 33-31558)).
3.1.6. Certificate of Amendment of Certificate of Incorporation dated May 30, 1991 (incorporated by
reference to the Company's Registration Statement (No. 333-20259)).
3.1.7. Certificate of Amendment of Certificate of Incorporation dated November 20, 1992 (incorporated by
reference to the Company's Registration Statement (No. 333-20257)).
3.1.8. Certificate of Amendment of Certificate of Incorporation dated May 24, 1996 (incorporated by
reference to the Company's Registration Statement (No. 333-20257)).
3.1.9. Certificate of Amendment of Certificate of Incorporation dated October 2, 1996 (incorporated by
reference to the Company's Registration Statement (No. 333-20257)).
3.1.10. 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)).
3.1.11. Certificate of Amendment of Certificate of Incorporation dated August 25, 1998 (incorporated by
reference to the Company's Registration Statement (No. 333-62439)).
3.1.12 Certificate of Amendment of Certificate of Incorporation dated May 25, 2000 (incorporated by
reference to the Company's Form 10-Q dated August 8, 2000).
3.2 By-Laws of the Company (incorporated by reference to the Company's Registration Statement (No.
33-31558)).
4.1 Specimen certificate of Lomak Petroleum, Inc. (incorporated by reference to the Company's
Registration Statement (No. 333-20257)).
4.2 Certificate of Trust of Lomak Financing Trust (incorporated by reference to the Company's
Registration Statement (No. 333-43823)).
4.3 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)).
4.4.1 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)).
4.4.2 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)).
4.5 Form of 5-3/4% Preferred Convertible Securities.
4.6 Form of 5-3/4% Convertible Junior Subordinated Debentures.
4.7 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)).
4.8 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)).
Exhibit No. Description
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4.9 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)).
4.10 Credit Agreement, dated as of June 7, 1996, between Domain Finance Corporation and Compass Bank --
Houston (including the First and the Second Amendment thereto) (incorporated by reference to Exhibit
10.3 of Domain Energy Corporation's Registration Statement on Form S-1 filed with the Commission on
April 4, 1997 and Exhibit 10.3 of Amendment No. 1 to Domain Energy Corporation's Registration
Statement on Form S-1 filed with the Commission on May 21, 1997) (File No. 333-24641).
4.11 Corrected Certificate of Designations of Preferred Stock of Range Resources Corporation Designated As
$2.03 Convertible Exchangeable Preferred Stock, Series D (incorporated by reference to the Company's
Form 10-Q dated November 6, 2000).
10.1 Incentive and Non-Qualified Stock Option Plan dated March 13, 1989 (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
10.2 Advisory Agreement dated September 29, 1988 between Lomak and SOCO (incorporated by reference to the
Company's Registration Statement (No. 33-31558)).
10.3.1 1989 Stock Purchase Plan (incorporated by reference to the Company's Registration Statement (No.
33-31558)).
10.3.2 Amendment to the Lomak Petroleum, Inc., 1989 Stock Purchase Plan, as amended (incorporated by
reference to the Company's Registration Statement (No. 333-44821)).
10.4 Form of Directors Indemnification Agreement (incorporated by reference to the Company's Registration
Statement (No. 333-47544)).
10.5.1 1994 Outside Directors Stock Option Plan (incorporated by reference to the Company's Registration
Statement (No. 33-47544)).
10.5.2 1994 Outside Directors Stock Option Plan - Amendment No. 1 (incorporated by reference to the
Company's Registration Statement No. 333-40380)
10.5.3 1994 Outside Directors Stock Option Plan - Amendment No. 2 (incorporated by reference to the
Company's Registration Statement No. 333-40380)
10.5.4 1994 Outside Directors Stock Option Plan - Amendment No. 3 (incorporated by reference to the
Company's Registration Statement No. 333-40380)
10.5.5 1994 Outside Directors Stock Option Plan - Amendment No. 4 (incorporated by reference to the
Company's Registration Statement No. 333-40380)
10.6 1994 Stock Option Plan (incorporated by reference to the Company's Registration Statement (No.
33-47544)).
10.7 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)).
10.8.1 1997 Stock Purchase Plan (incorporated by reference to the Company's Registration Statement (No.
333-44821)).
10.8.2 1997 Stock Purchase Plan, as amended (incorporated by reference to the Company's Registration
Statement (No. 333-44821)).
10.8.3 1997 Stock Purchase Plan - Amendment No. 1 (incorporated by reference to the Company's Registration
Statement No. 333-40380)
10.8.4 1997 Stock Purchase Plan - Amendment No. 2 (incorporated by reference to the Company's Registration
Statement No. 333-40380)
10.8.5 1997 Stock Purchase Plan - Amendment No. 3 (incorporated by reference to the Company's Registration
Statement No. 333-40380)
10.9 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)).
10.10 Domain Energy Corporation 1997 Stock Option Plan for Nonemployee Directors (incorporated by reference
to the Company's Registration Statement (No. 333-62439)).
10.11 $100,000,000 Credit Agreement between Range Energy Finance Corporation, as Borrower, and Credit
Lyonnais New York Branch, as Administrative Agent and Certain Lenders dated December 14, 1999
(incorporated by reference to the Company's 1999 10K dated March 20, 2000.)
Exhibit No. Description
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10.11.1 $100,000,000 Second Amendment to Credit Agreement between Range Energy Finance Corporation, as
Borrower, and Credit Lyonnais New York Branch, as Administrative Agent and Certain Lenders dated
December 14, 1999 (incorporated by reference to the Company's 1999 10K dated March 20, 2000.)
10.12 Purchase and Sale Agreement - Dated April 20, 2000 between Range Pipeline Systems, L.P. as Seller and
Conoco Inc., as Buyer (incorporated by reference to the Company's 10-Q dated August 8, 2000).
10.13 Gas Purchase Contract - Dated July 1, 2000 between Range Production I, L.P. as Seller and Conoco Inc.,
as Buyer (incorporated by reference to the Company's 10-Q dated August 8, 2000).
10.14 Application Service Provider and Outsourcing Agreement - Dated June 1, 2000 between Range Resources
and Applied Terravision Systems Inc. (incorporated by reference to the Company's 10-Q dated August 8,
2000).
10.15.1 $225,000,000 Amended and Restated Credit Agreement among Range Resources Corporation, as Borrower, The
Lenders from Time to Time Parties Hereto, as Lenders, Bank One, Texas, N.A., as Administrative Agent,
Chase Bank of Texas, N.A., as Syndication Agent, and Bank of America, N.A., as Documentation Agent
dated September 30, 1999 incorporated by reference to the Company's 10Q dated November 10, 1999.
10.15.2 $225,000,000 First Amendment to Credit Agreement among Range Resources Corporation, as Borrower,
certain parties, as Lenders, Bank One, Texas, N.A., as Administrative Agent, Chase Bank of Texas,
N.A., as Syndication Agent, and Bank of America, N.A., as Documentation Agent dated September 30, 1999
10.15.3 $225,000,000 Second Amendment to Credit Agreement among Range Resources Corporation, as Borrower, certain
parties, as Lenders, Bank One, Texas, N.A., as Administrative Agent, Chase Bank of Texas, N.A., as
Syndication Agent, and Bank of America, N.A., as Documentation Agent dated September 30, 1999
(incorporated by reference to the Company's 10-Q dated August 8, 2000.
10.15.4 $225,000,000 Third Amendment to Credit Agreement among Range Resources Corporation, as Borrower,
certain parties as Lenders, Bank One, Texas, N.A., as Administrative Agent, Chase Bank of Texas, N.A.,
as Syndication
10.15.5 Agent, and Bank of America, N.A., as Documentation Agent dated September 30, 1999 (incorporated by
reference to the Company's 10-Q dated August 8, 2000).
10.19 The Amended and Restated Deferred Compensation Plan for Directors and Selected Employees, effective
September 1, 2000.
21.1* Subsidiaries of Registrant.
23.1* Consent of Independent Public Accountants.
23.2* Consent of H.J. Gruy and Associates, Inc., independent consulting petroleum engineers.
23.3* Consent of DeGoyler and MacNaughton, independent consulting petroleum engineers.
23.4* Consent of Wright and Company, independent consulting engineers.
*Filed herewith.