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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark one)
| þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year-ended December 31, 2005
or
or
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 001-12209
RANGE RESOURCES CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
| Delaware | 34-1312571 | |
| (State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification No.) | |
| 777 Main Street, Suite 800, 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:
| Title Of Each Class | Name Of Each Exchange On Which Registered | |
| Common Stock, $.01 par value | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant as a well-known seasoned issuer, as defined in Rule
405 of the Securities Act.
Yes
þ
No o
Indicate by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act.
Yes
o
No þ
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 þ
No o
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. þ
Indicate by check mark whether the registrant is a large accelerated filer, an
accelerated filer or a non-accelerate filer. See definition of “accelerated filer and large
accelerated filer “in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer þ Accelerated Filer o Non-Accelerated Filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Yes o No þ
The aggregate market value of the voting and non-voting common equity held by
non-affiliates (excluding voting shares held by officers and directors) as of June 30, 2005 was
$2,276,192,000.
As of February 20, 2006, there were 130,661,982 shares of Range Resources Corporation Common
Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the registrant’s proxy statement to be furnished to stockholders in connection
with its 2006 Annual Meeting of Stockholders are incorporated by reference in Part III, Items 10-14
of this report.
RANGE RESOURCES CORPORATION
Unless the context otherwise indicates, all references in this report to “Range” “we” “us” or
“our” are to Range Resources Corporation and its subsidiaries. Unless otherwise noted, all
information in the report relating to oil and gas reserves and the estimated future net cash flows
attributable to those reserves are based on estimates and are net to our interest. If you are not
familiar with the oil and gas terms used in this report, please refer to the explanation of such
terms under the caption “Glossary” at the end of Item 15 of this report.
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RANGE RESOURCES CORPORATION
Annual Report on Form 10-K
Year Ended December 31, 2005
Year Ended December 31, 2005
Disclosures Regarding Forward-Looking Statements
Certain information included in this report, other materials filed or to be filed with the
Securities and Exchange Commission or the SEC, as well as information included in oral statements
or other written statements made or to be made by us 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,” “projects”
or “targets” 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: the factors listed
in Item 1A of this report under the heading “Risk Factors,” 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, our ability to implement our business strategy, costs and results of drilling new
projects, mechanical and other inherent risks associated with oil and gas production, weather,
availability of drilling equipment and changes in interest rates. All such forward-looking
statements in this document are expressly qualified in their entirety by the cautionary statements
in this paragraph, and we undertake no obligation to publicly update or revise any forward-looking
statements.
PART I
ITEM 1. BUSINESS
General
We are engaged in the exploration, development and acquisition of oil and gas properties,
primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to
increase reserves and production through internally generated drilling projects coupled with
complementary acquisitions.
At year-end 2005, our proved reserves had the following characteristics:
| • | 1.4 Tcfe of proved reserves; | ||
| • | 80% natural gas; | ||
| • | 66% proved developed; | ||
| • | 78% operated; | ||
| • | a reserve life of 15.3 years (based on fourth quarter 2005 production); and | ||
| • | a pre-tax present value of $4.9 billion. |
At year-end 2005, we owned 2,843,000 gross (2,381,000 net) acres of leasehold, plus over
400,000 royalty acres. We have built a multi-year inventory of drilling projects which includes
over 7,700 identified drilling locations.
Range was incorporated in early 1980 under the name Lomak Petroleum, Inc. and, later that
year, we completed an initial public offering and began trading on the NASDAQ. In 1996, our common
stock was listed on the New York Stock Exchange. In 1998, we changed our name to Range Resources
Corporation. In 1999, we implemented a strategy of internally generated drillbit growth coupled
with complementary acquisitions. Our objective is to build stockholder value through consistent
growth in reserves and production on a cost-efficient basis. During the past four years, we have
increased our proved reserves 143%, while production has increased 59% during that same period.
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Our corporate offices are located at 777 Main Street, Suite 800, Fort Worth, Texas 76102. Our
telephone number is (817) 870-2601.
Business Strategy
Our objective is to build stockholder value through consistent growth in reserves and
production on a cost-efficient basis. Our strategy is to employ internally generated drillbit
growth coupled with complementary acquisitions to achieve such growth. Such a strategy requires us
to make significant investments in technical staff, acreage and seismic to build drilling
inventory. In implementing our strategy, we employ the following principal elements:
| • | Concentrate in Core Operating Areas. We currently operate in three regions; the Southwestern (which includes the Permian Basin of West Texas and eastern New Mexico, the East Texas Basin, the Texas Panhandle and Anadarko Basin of Western Oklahoma), Appalachian and Gulf Coast. Concentrating our drilling and producing activities in these core areas allows us to develop the regional expertise needed to interpret specific geological and operating trends and develop economies of scale. Operating in multiple core areas allows us to combine the production characteristics of each area to balance our portfolio toward our goal of consistent production and reserve growth. | ||
| • | Maintain Multi-Year Drilling Inventory. We focus on areas where multiple prospective productive horizons and development opportunities exist. We use our technical expertise to build and maintain a multi-year drilling inventory. By maintaining a large, multi-year inventory of drilling projects, we believe this increases our ability to consistently grow production and reserves over the next several years. Currently, we have over 7,700 identified drilling locations in inventory. In 2005, we drilled 841 gross (594 net) wells. In 2006, our capital program targets the drilling of 1,065 gross (789 net) wells. | ||
| • | Make Complementary Acquisitions. We target complementary acquisitions in existing core areas and focus on acquisition candidates where our existing scientific knowledge is transferable and drilling results can be forecast with confidence. Over the past three years, we have completed $743.0 million of complementary acquisitions. These acquisitions have been located in the Southwestern and Appalachian regions. | ||
| • | Manage Our Risk Exposure. Allocating the majority of our capital spending to long-term development projects in areas where multiple productive horizons exist serves to reduce our risk exposure. Where our exploration projects may involve high dry hole costs, we often bring in industry partners in order to reduce financial exposure. We try to limit our exploratory expenditures to no more than 20% of our annual capital budget per year. Most of our exploratory drilling projects are structural reservoir projects where we have several years of experience in drilling such projects. We also invest in new seismic data and technology each year. By equipping our geologists and geophysicists with state-of-the-art seismic technology with multiple reprocessing applications, we hope to multiply the number of higher potential exploration prospects we drill without substantially adding to dry hole risk. | ||
| • | Maintain Flexibility. Given the volatility of commodity prices and the risks involved in drilling, we remain flexible and may adjust our capital budget throughout the year. We may defer capital projects in order to seize an attractive acquisition opportunity. If certain areas generate higher than anticipated returns, we may accelerate drilling in those areas and decrease capital expenditures elsewhere. We also believe in maintaining a strong balance sheet and using commodity hedging. This will allow us to be more opportunistic in cyclical price environments as well as providing more consistent financial results. |
Significant Accomplishments in 2005
| • | Production and reserve growth – The fourth quarter of 2005 marked the twelfth consecutive quarter of sequential production growth. Our annual production reached 239.1 Mmcfe per day, an increase of 22% from 2004. This achievement is the result of our continued drilling success and the completion and integration of complementary acquisitions. Our business is inherently volatile, and while consistent growth such as we have experienced over the past twelve quarters will be challenging to sustain, the quality of our technical teams and our sizable drilling inventory bode well for the future. A testament to this fact was the devastating hurricanes that significantly impacted our Gulf Coast and Southwest production. Despite the loss of production from these storms, we were able to continue to increase production with growth in our other core areas. Proven reserves increased 20% in 2005 to 1.4 Tcfe, marking the fourth consecutive year our proven reserves have increased. | ||
| • | Successful drilling program – In 2005, we ended the year with 841 gross wells drilled. Competition for quality drilling and completion well services was intense in 2005, yet we were able to increase our number of wells drilled by 77% over 2004. As we continue to build our drilling inventory for the future, an ability to drill |
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| additional wells each year on a cost effective and efficient basis is important. Production was replaced by over 200% in 2005, and our overall success rate in drilling was 98%. The increased pace of drilling did not adversely impact the quality of our drilling program as the 98% success ratio in 2005 compares favorably to the 95% success ratio in 2004. |
| • | Continued expansion of drilling inventory and emerging plays – To maintain our growth rate, the size of our prospect inventory must also increase. Our drilling inventory currently includes over 7,700 projects, up from approximately 5,000 at year-end 2004. Meaningful expansion of our coal bed methane projects and our shale plays occurred in 2005. We have now leased 370,000 net acres in our coal bed methane plays and 203,000 acres in our shale plays. In addition to the expansion of our emerging plays, we have added several quality veteran technical professionals to assist us in this effort. | ||
| • | Record financial results and balance sheet improvement – Growth in production volumes and higher oil and gas prices drove our record financial performance in 2005. Revenue, net income, and net cash flow provided by operating activities all reached record highs, despite the effect of low-price commodity hedges put in place in prior years. All of the lower priced swaps expired at the end of 2005. The balance sheet continued to improve in 2005 as we refinanced $150 million of shorter term bank debt with a like amount of senior subordinated fixed rate 6.375% notes having a 10-year maturity. This helped to align the maturity schedule of our debt with the long-term life of our assets. Financial leverage, as measured by the debt-to-capitalization ratio improved and total debt was reduced slightly in 2005. Future profitability and cash flow will be enhanced through lower income taxes due to a $207.2 million net operating loss carryforward. | ||
| • | Successful acquisition completed – In June 2005 we acquired 77 Bcfe of proven reserves in New Mexico for $116.4 million. The acquisition was producing approximately 7 Mmcfe per day when it was acquired and was producing approximately 12 Mmcfe per day at year-end. The acquisition was funded with proceeds from a public offering of 6.9 million shares for net proceeds of $109.2 million. Additional growth in production is expected in 2006 due to an active drilling program. |
Plans for 2006
We have announced a $428.9 million capital budget for 2006, excluding acquisitions. The
budget includes $358.4 million to drill 1,065 gross (789 net) wells and to undertake 94 gross (58
net) recompletions. Approximately 46% of the budget is attributable to the Appalachia Division,
with 46% allocated to the Southwest Division and 8% to the Gulf Coast Division. Also included is
$37.6 million for land, $18.5 million for seismic and $14.5 million for the expansion and
enhancement of gathering systems and facilities.
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Production, Revenues and Price History
The following table sets forth information regarding oil and gas production, revenues and
direct operating expenses for the last three years.
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Production |
||||||||||||
Gas (Mmcf) |
63,004 | 50,722 | 43,510 | |||||||||
Crude oil (Mbbl) |
3,031 | 2,512 | 2,023 | |||||||||
Natural gas liquids (Mbbl) |
1,012 | 988 | 401 | |||||||||
Total (Mmcfe) (a) |
87,263 | 71,726 | 58,053 | |||||||||
Revenues ($000) |
||||||||||||
Gas |
$ | 380,131 | $ | 225,738 | $ | 171,291 | ||||||
Crude oil |
117,354 | 70,439 | 47,599 | |||||||||
Natural gas liquids |
27,589 | 19,526 | 7,512 | |||||||||
Transportation and gathering |
2,578 | 2,202 | 3,509 | |||||||||
Total |
527,652 | 317,905 | 229,911 | |||||||||
Direct operating expenses (b) |
98,148 | 66,812 | 49,317 | |||||||||
Gross margin |
$ | 429,504 | $ | 251,093 | $ | 180,594 | ||||||
Average sales price (excluding hedging) |
||||||||||||
Gas (per mcf) |
$ | 7.98 | $ | 5.79 | $ | 5.10 | ||||||
Crude oil (per bbl) |
53.31 | 39.25 | 28.42 | |||||||||
Natural gas liquids (per bbl) |
31.52 | 23.73 | 18.75 | |||||||||
Total (per mcfe) (a) |
7.98 | 5.80 | 4.94 | |||||||||
Average sales price (including hedging) |
||||||||||||
Gas (per mcf) |
$ | 6.03 | $ | 4.45 | $ | 3.94 | ||||||
Crude oil (per bbl) |
38.71 | 28.04 | 23.53 | |||||||||
Natural gas liquids (per bbl) |
27.27 | 19.76 | 18.75 | |||||||||
Total (per mcfe) (a) |
6.02 | 4.40 | 3.90 | |||||||||
Operating costs (per mcfe) |
||||||||||||
Direct |
$ | 0.76 | $ | 0.65 | $ | 0.63 | ||||||
Production and ad valorem taxes |
0.36 | 0.29 | 0.22 | |||||||||
Total |
$ | 1.12 | $ | 0.94 | $ | 0.85 | ||||||
| (a) | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcfe. | |
| (b) | Includes production and ad valorem taxes. |
Competition
We encounter substantial competition in developing and acquiring oil and gas properties,
securing and retaining personnel, conducting drilling and field operations and marketing
production. Competitors in exploration, development, acquisitions and production include the major
oil companies as well as numerous independent oil companies, individual proprietors and others.
Although our sizable acreage position and core area concentration provide some competitive
advantages, many competitors have financial and other resources substantially exceeding ours.
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
Range allow. Our ability to replace and expand our reserve base depends on our ability to attract
and retain quality personnel and identify and acquire suitable producing properties and prospects
for future drilling.
Employees
As of January 1, 2006, we had 578 full-time employees, 330 of whom were field personnel. All
employees are eligible to receive equity awards approved by the Compensation Committee of the Board
of Directors. None is covered by a collective bargaining agreement. Management believes its
relationship with employees is good. We regularly utilize independent consultants and contractors
to perform various services, particularly in the areas of drilling, completion and field production
services such as pumping, maintenance, inspection and testing, permitting and environmental
assessment.
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Available Information
We maintain an internet website under the name “www.rangeresources.com.” We make available,
free of charge, on our website, the annual report on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable
after providing such reports to the SEC. Also, our Corporate Governance Guidelines, the charters
of the Audit Committee, the Compensation Committee, the Dividend Committee, and the Governance and
Nominating Committee, and the Code of Business Conduct and Ethics are also available on our website
and in print to any stockholder who provides a written request to the Corporate Secretary at 777
Main Street, Suite 800, Fort Worth, Texas 76102.
We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on
Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of
1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public
Reference Room at 450 Fifth Street, N.W., Washington DC 20549. The public may obtain information
on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC
maintains an internet website that contains reports, proxy and information statements, and other
information regarding issuers, including Range, that file electronically with the SEC. The public
can obtain any document we file with the SEC at “www.sec.gov.” Information contained on or
connected to our web site is not incorporated by reference into this Form 10-K and should not be
considered part of this report or any other filing that we make with the SEC.
Marketing and Customers
We market nearly all of our oil and gas production from the properties we operate for both our
interest and that of the royalty owners and other working interest owners. Gas sales are made
pursuant to a variety of contractual arrangements, including month-to-month and one-to five-year
contracts. Pricing on the month-to-month and short-term contracts is based largely on the New York
Mercantile Exchange, or NYMEX pricing, with fixed or floating basis. For one-to five-year
contracts, gas is sold on NYMEX pricing, published regional index pricing or percentage of proceeds
sales based on local indexes. Less than 300 mcf per day is sold under long-term fixed price
contracts. Most contracts contain provisions for periodic price adjustment, termination and other
terms customary in the industry. Gas is sold to utilities, marketing companies and industrial
users. Oil is sold under contracts ranging in term from month-to-month, up to as long as one year.
The pricing for oil is based upon the posted prices set by major purchasers in the production area
or upon NYMEX pricing, adjusted for quality and transportation. Oil and gas purchasers are
selected on the basis of price, credit quality and service. For a summary of purchasers of our oil
and gas production that accounted for 10% or more of consolidated revenue, see the information set
forth in the notes to our consolidated financial statements under the caption “Major Customers” in
Note 14. Because alternative purchasers of oil and gas are usually readily available, we believe
that the loss of any of these purchasers would not have a material adverse effect on us.
We enter into hedging transactions with unaffiliated third parties for portions of our
production to achieve more predictable cash flows and to reduce our exposure to short-term
fluctuations in oil and gas prices. For a more detailed discussion, please see the information set
forth in Item 7 of this report “Management’s Discussion and Analysis of Financial Condition and
Results of Operations” and Item 7A “Quantitative and Qualitative Disclosures about Market Risk.”
Proximity to local markets, availability of competitive fuels and overall supply and demand are
factors affecting the prices for which our production can be sold. Increasing market volatility
due to international political developments, overall energy supply and demand, weather conditions,
economic growth rates and other factors in the United States and worldwide have had, and will
continue to have, a significant effect on energy prices.
We incur gathering and transportation expenses to move our natural gas and crude oil from the
wellhead and tanks to purchaser specified delivery points. These expenses vary based on volume,
distance shipped and the fee charged by the third-party transporters. In the Southwestern and Gulf
Coast Divisions, our natural gas and oil production are transported primarily through third-party
trucks, gathering systems and pipelines. Transportation space on these gathering systems and
pipelines is occasionally limited. In Appalachia, we own approximately 4,800 miles of gas
gathering pipelines which transport a majority of our Appalachian gas production as well as
third-party gas to transmission lines and directly to end-users. See “Risk Factors – Our business
depends on oil and natural gas transportation facilities, some of which are owned by others,” in
Item 1A of this report.
Governmental Regulation
Our operations are substantially affected 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 numerous other laws and regulations. All of the jurisdictions in which we own
or operate producing crude oil and natural gas properties have statutory provisions regulating the
exploration for and production of crude oil and natural gas, including provisions related to
permits for the drilling of wells, bonding requirements in order to drill or operate wells, the
location of wells, the method of drilling and
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casing wells, the surface use and restoration of
properties upon which wells are drilled, and the abandonment of wells. Our operations are also
subject to various conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the
unitization or pooling of crude oil and natural gas wells, generally prohibit the venting or
flaring of natural gas, and impose certain requirements regarding the ratability or fair
apportionment of production from fields and individuals wells.
Certain operations that we conduct are on federal oil and gas leases which are administered by
the Minerals Management Service, or the MMS. These leases contain relatively standardized terms
and require compliance with detailed MMS regulations pursuant to the Outer Continental Shelf Lands
Act, or the OCSLA (which are subject to change by the MMS). Lessees must obtain a permit from the
MMS prior to the commencement of drilling, and comply with regulation governing, among other
things, engineering, and construction specifications for production facilities, safety procedures,
plugging and abandonment of Outer Continental Shelf, or OCS, wells, the valuation of production,
and the removal of facilities. Under certain circumstances, the MMS may require our operations on
federal leases to be suspended or terminated. Any such suspension or termination could materially
and adversely affect our financial condition and operation. To cover the various obligations of
lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other
acceptable assurances that such obligations will be met, unless the MMS exempts the lessee from
such obligations. The cost of such bonds or other surety can be substantial and we can provide no
assurance that we can continue to obtain bonds or other surety in all cases.
In August 2005, Congress enacted the Energy Policy Act of 2005, or the EPAct 2005. Among
other matters, the EPAct 2005 amends the Natural Gas Act, or NGA, to make it unlawful for “any
entity”, including otherwise non-jurisdictional producers such as Range, to use any deceptive or
manipulative device or contrivance in connection with the purchase or sale of natural gas or the
purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory
Commission, or FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the
FERC issued rules implementing this provision. The rules make it unlawful in connection with the
purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of
transportation services subject to the jurisdiction of FERC, for any entity, directly or
indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue
statement of material fact or omit to make any such statement necessary to make the statements made
not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any
person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the
NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to
activities that relate only to intrastate or other non-jurisdictional sale or gathering, but does
apply to activities or otherwise non-jurisdictional entities to the extent the activities are
conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.
It therefore reflects a significant expansion of FERC’s enforcement authority. Range does not
anticipate it will be affected any differently than other producers of natural gas.
Failure to comply with applicable laws and regulations can result in substantial penalties.
The regulatory burden on the industry increases the cost of doing business and affects
profitability. Although we believe we are in substantial compliance will all applicable laws and
regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are
unable to predict the future costs or impact of compliance.
Additional proposals and proceedings that affect the oil and gas industry are regularly
considered by Congress, the states, the FERC, and the courts. We cannot predict when or whether
any such proposals may become effective.
Environmental Matters
Our 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 or the 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, affecting growth and 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 our
operations and financial position, as well as the industry in general. We believe we are in
substantial compliance with current applicable environmental laws and regulations. Although we
have not experienced any material adverse effect from compliance with environmental requirements,
there is no assurance that this will continue. We did not have any material
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capital or other
non-recurring expenditures in connection with complying with environmental laws or environmental
remediation matters in 2005, nor do we anticipate that such expenditures will be material in 2006.
The Comprehensive Environmental Response, Compensation and Liability Act, or 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 owners or operators 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. Furthermore, although petroleum, including crude oil
and natural gas, is not a “hazardous substance” under 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 therefore give rise to liability under CERCLA.
Beyond CERCLA, state laws regulate the disposal of oil and gas wastes, and periodically new state
legislative initiatives are proposed that could have a significant impact on us. In addition, 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 pursuant to environmental statutes, common law or both.
The Federal Water Pollution Control Act, or FWPCA, imposes restrictions and strict controls
regarding the discharge of produced waters and other oil and gas wastes into waters of the United
States. 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 Federal National Pollutant Discharge Elimination System permits
applicable to the oil and gas industry generally prohibit the discharge of produced water, sand and
some other substances into coastal waters. The cost to comply with zero discharges mandated under
federal and state law has not had a material adverse impact on our 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 and implementing storm water pollution prevention plans.
The Resource Conservation and Recovery Act, or 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 non-hazardous
solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents,
laboratory wastes and waste compressor oils, can be regulated as hazardous wastes. Although the
costs of managing wastes classified as hazardous waste may be significant, we do not expect to
experience more burdensome costs than similarly situated companies.
The U.S. Oil Pollution Act, or 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
alter the RCRA exemption by reclassifying 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 our
operating costs, as well as the industry in general. Compliance with environmental requirements
generally could have a material adverse effect on our capital expenditures, earnings or competitive
position. Although we have not experienced any material adverse effect from compliance with
environmental requirements, no assurance may be given that this will continue.
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ITEM 1A. RISK FACTORS
Volatility of oil and natural gas prices significantly affects our cash flow and capital resources
and could hamper our ability to produce oil and gas economically
Oil and natural gas prices are volatile, and an extended decline in prices would adversely
affect our profitability and financial condition. The oil and natural gas industry is typically
cyclical, and prices for oil and natural gas have been highly volatile. Historically, the industry
has experienced severe downturns characterized by oversupply and/or weak demand. For example, in
1998 and early 1999, oil and natural gas prices declined, which contributed to the substantial
losses we reported in those years. By early 2001, oil and natural gas prices reached levels above
historical norms. Prices declined in the second half of 2001 but have risen steadily since
mid-2002. Recent oil and natural gas prices are at historic highs, with oil prices recently
reaching $70.85 per barrel and natural gas prices reaching $15.78 per mcf in some markets. Higher
oil and natural gas prices have contributed to our positive earnings over the last several years.
However, long-term supply and demand for oil and natural gas is uncertain and subject to a myriad
of factors including technology, geopolitics, weather patterns and economics.
Many factors affect oil and natural gas prices including general economic conditions, consumer
preferences, discretionary spending levels, interest rates and the availability of capital to the
industry. Decreases in oil and natural gas prices from current levels could adversely affect our
revenues, net income, cash flow and proved reserves. Significant and prolonged price decreases
could have a material adverse effect on our operations and limit our ability to fund capital
expenditures. Without the ability to fund capital expenditures, we will be unable to replace
production.
Hedging transactions may limit our potential gains and involve other risks
To manage our exposure to price risk, we enter into hedging arrangements with respect to a
significant portion of our future production. The goal of these hedges is to lock in prices so as
to limit volatility and increase the predictability of cash flow. These transactions limit our
potential gains if oil and natural gas prices rise above the price established by the hedge. For
example, at December 31, 2005, we were party to swap hedging arrangements covering 6.7 Bcf and 0.1
million barrels of oil. We also had collars covering 82.8 Bcf of gas and 4.8 million barrels of
oil. The derivatives’ fair value was a pre-tax loss of $231.0 million. If oil and natural gas
prices continue to rise, we could be subject to margin calls.
In addition, hedging transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:
| • | Our production is less than expected; | ||
| • | The counterparties to our futures contracts fail to perform under the contracts; or | ||
| • | A sudden, unexpected event materially impacts oil or natural gas prices or the relationship between the hedged price index and the oil and gas sales price. |
Recently, due to the trading volatility of NYMEX gas contracts, we have experienced larger
than usual differentials between actual prices paid at delivery points and NYMEX based gas hedges.
Due to this event, certain of our gas hedges no longer qualified for hedge accounting in the fourth
quarter and were marked-to-market. This may result in more volatility in our income in future
periods.
Information concerning our reserves and future net reserve estimates is uncertain
There are numerous uncertainties inherent in estimating quantities of proved oil and natural
gas reserves and their values, including many factors beyond our control. Estimates of proved
undeveloped reserves, which comprise a significant portion of our reserves, are by their nature
uncertain. Although we believe these estimates are reasonable, actual production, revenues and
costs to develop will likely vary from estimates, and these variances could be material.
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 natural gas in place, recovery rates and future prices for oil and natural gas. Actual
prices, production, development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves will vary from those assumed in our estimates, and such variances may be
material. Any variance in the assumptions could materially affect the estimated quantity and value
of the reserves.
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If oil and natural gas prices decrease or exploration efforts are unsuccessful, we may be required
to take write-downs of our oil and natural gas properties
In the past, we have been required to write down the carrying value of certain of our oil and
natural gas properties, and there is a risk that we will be required to take additional write-downs
in the future. This could occur when oil and natural gas prices are low, or if we have downward
adjustments to our estimated proved reserves, increases in our estimates of operating or
development costs, deterioration in our exploration results or mechanical problems with wells where
the cost to redrill or repair does not justify the expense which might occur due to hurricanes.
Accounting rules require that the carrying value of oil and natural gas properties be
periodically reviewed for possible impairment. “Impairment” is recognized when the book value of a
proven property is greater than the expected undiscounted future net cash flows from that property
and on acreage when conditions indicate the carrying value is not recoverable. We may be required
to write down the carrying value of a property based on oil and natural gas prices at the time of
the impairment review, as well as a continuing evaluation of drilling results, production data,
economics and other factors. While an impairment charge reflects our long-term ability to recover
an investment, it does not impact cash or cash flow from operating activities, but it does reduce
our reported earnings and increases our leverage ratios.
For example, based primarily on the poor performance of certain properties acquired in 1997
and 1998 and significantly lower oil and natural gas prices, we recorded impairments of $215.0
million in 1998 and $29.9 million in 1999. At year-end 2001, we recorded an impairment of $31.1
million due to lower year-end prices. At year-end 2004, we recorded an impairment of $3.6 million
on an offshore property due to hurricane damage and related production declines. As of December
31, 2005, we continued to have production shut-in due to the effects of hurricanes Katrina and Rita
primarily to pipelines and onshore facilities. While we do not currently believe there is any
material long-term damage to the shut-in properties, we cannot yet predict whether impairment
charges may be required due to these storms.
Our business is subject to operating hazards and environmental regulations that could result in
substantial losses or liabilities
Oil and natural gas operations are subject to many risks, including well blowouts, craterings,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with
abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic natural gas and other
environmental hazards and risks. If any of these hazards occur, we could sustain substantial
losses as a result of:
| • | Injury or loss of life; | ||
| • | Severe damage to or destruction of property, natural resources and equipment; | ||
| • | Pollution or other environmental damage; | ||
| • | Clean-up responsibilities; | ||
| • | Regulatory investigations and penalties; or | ||
| • | Suspension of operations. |
As we begin drilling to deeper horizons and in more geologically complex areas, we could
experience a greater increase in operating and financial risks due to inherent higher reservoir
pressures and unknown downhole risk exposures. As we continue to drill deeper, the number of rigs
capable of drilling to such depths will be fewer and we may experience greater competition from
other operators.
Our operations are subject to numerous and increasingly strict federal, state and local laws,
regulations and enforcement policies relating to the environment. We may incur significant costs
and liabilities in complying with existing or future environmental laws, regulations and
enforcement policies and may incur costs arising out of property damage or injuries to employees
and other persons. These costs may result from our current and former operations and even may be
caused by previous owners of property we own or lease. Any past, present or future failure by us
to completely comply with environmental laws, regulations and enforcement policies could cause us
to incur substantial fines, sanctions or liabilities from cleanup costs or other damages.
Incurrence of those costs or damages could reduce or eliminate funds available for exploration,
development or acquisitions or cause us to incur losses.
We maintain insurance against some, but not all, of these potential risks and losses. We may
elect not to obtain insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. Currently, we expect
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substantial increases in premiums especially
in the areas affected by the hurricanes and tropical storms. In addition, we expect insurers to
impose revised limits affecting how much the insurers will pay on actual storm claims plus the cost
to re-drill wells where substantial damage has been incurred. Insurers are also requiring us to
retain larger deductibles and reducing the scope of what insurable losses will include. Even with
the increase in future insurance premiums, coverage will be reduced, requiring us to bear a greater
potential risk if our oil and gas properties are damaged. We do not maintain any business
interruption insurance. In addition, pollution and environmental risks generally are not fully
insurable. If a significant accident or other event occurs that is not fully covered by insurance,
it could have a material adverse affect on our financial condition and results of operations.
We are subject to financing and interest rate exposure risks
Our business and operating results can be harmed by factors such as the availability, terms of
and cost of capital, increases in interest rates or a reduction in credit rating. These changes
could cause our cost of doing business to increase, limit our ability to pursue acquisition
opportunities and place us at a competitive disadvantage. For example, approximately 56% of our
debt is at fixed interest rates with the remaining 44% subject to variable interest rates.
Some of our current and potential competitors have greater resources than we have and we may not be
able to successfully compete in acquiring, exploring and developing new properties
We face competition in every aspect of our business, including, but not limited to, acquiring
reserves and leases, obtaining goods, services and employees needed to operate and manage our
business and marketing oil and natural 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.
The demand for field services and their ability to meet that demand may limit our ability to drill
and produce our oil and natural gas properties
Due to current industry demands, well service providers and related equipment and personnel
are in short supply. This is causing escalating prices, the possibility of poor services coupled
with potential damage to downhole reservoirs and personnel injuries. Such pressures will likely
increase the actual cost of services, extend the time to secure such services and add costs for
damages due to accidents sustained from the over use of equipment and inexperienced personnel.
The oil and natural gas industry is subject to extensive regulation
The oil and natural gas 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 our regulatory burden. Numerous
departments and agencies, both state and federal, are authorized by statute to issue rules and
regulations binding on participants in the oil and natural gas industry. Compliance with such
rules and regulations often increases our cost of doing business and, in turn, decreases our
profitability.
Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential
liabilities and may be disruptive and difficult to integrate into our business
We could be subject to significant liabilities related to our acquisitions. It generally is
not feasible to review in detail every individual property included in an acquisition. 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 in all of the properties, 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.
For example, in 1997, we consummated a large acquisition that proved extremely disappointing.
Production from the acquired properties fell more rapidly than anticipated and further development
results were below the results we had originally projected. The poor production performance of
these properties resulted in material downward reserve revisions. There is no assurance that our
recent and/or future acquisition activity will not result in similarly disappointing results.
In addition, there is intense competition for acquisition opportunities in our industry.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing
acquisitions. Our acquisition strategy is dependent upon,
among other things, our ability to obtain debt and equity financing and, in some cases, regulatory
approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to
obtain financing on terms acceptable to us or regulatory approvals.
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Acquisitions often pose integration risks and difficulties. In connection with recent and
future acquisitions, the process of integrating acquired operations into our existing operations
may result in unforeseen operating difficulties and may require significant management attention
and financial resources that would otherwise be available for the ongoing development or expansion
of existing operations. Future acquisitions could result in our incurring additional debt,
contingent liabilities, expenses and diversion of resources, all of which could have a material
adverse effect on our financial condition and operating results.
Our success depends on key members of our management and our ability to attract and retain
experienced technical and other professional personnel
Our success is highly dependent on our management personnel, none of which is currently
subject to an employment contract. The loss of one or more of these individuals could have a
material adverse effect on our business. Furthermore, competition for experienced technical and
other professional personnel is intense. If we cannot retain our current personnel or attract
additional experienced personnel, our ability to compete could be adversely affected.
Our future success depends on our ability to replace reserves that we produce
Because the rate of production from oil and natural gas properties generally declines as
reserves are depleted, our future success depends upon our ability to economically find or acquire
and produce additional oil and natural gas reserves. Except to the extent that we acquire
additional properties containing proved reserves, conduct successful exploration and development
activities or, through engineering studies, identify additional behind-pipe zones or secondary
recovery reserves, our proved reserves will decline as reserves are produced. Future oil and
natural gas production, therefore, is highly dependent upon our level of success in acquiring or
finding additional reserves that are economically recoverable. We cannot assure you that we will
be able to find or acquire and develop additional reserves at an acceptable cost.
A portion of our business is subject to special risks related to offshore operations generally and
in the Gulf of Mexico specifically
Offshore operations are subject to a variety of operating risks specific to the marine
environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse
weather conditions. These conditions can cause substantial damage to facilities and interrupt
production. As of February 20, 2006, we continued to have 1.6 Mmcfe per day of production shut-in
due to the effects of hurricanes Katrina and Rita. As a result, we could incur substantial expense
and liabilities that could materially reduce the funds available for exploration, development or
leasehold acquisitions or result in the loss of equipment and properties.
Production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly
than from reservoirs in many other producing regions. This results in recovery of a relatively
higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of
production. As a result, reserve replacement needs from new prospects are greater and require us
to incur significant capital expenditures to replace production.
New technologies may cause our current exploration and drilling methods to become obsolete
The oil and natural gas industry is subject to rapid and significant advancements in
technology, including the introduction of new products and services using new technologies. As
competitors use or develop new technologies, we may be placed at a competitive disadvantage, and
competitive pressures may force us to implement new technologies at a substantial cost. In
addition, competitors may have greater financial, technical and personnel resources that allow them
to enjoy technological advantages and may in the future allow them to implement new technologies
before we can. One or more of the technologies that we currently use or that we may implement in
the future may become obsolete. We cannot be certain that we will be able to implement
technologies on a timely basis or at a cost that is acceptable to us. If we are not able to
maintain technological advancements consistent with industry standards, our operations and
financial condition may be adversely affected.
Our business depends on oil and natural gas transportation facilities, many of which are owned by
others
The marketability of our oil and natural gas production depends in part on the availability,
proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack
of available capacity on these systems and facilities
could result in the shut-in of producing wells or the delay or discontinuance of development plans
for properties. Although we have some contractual control over the transportation of our product,
material changes in these business relationships could materially affect our operations. We
generally do not purchase firm transportation on third party facilities and therefore, our
production transportation can be interrupted by those having firm arrangements. Federal and state
regulation
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of oil and natural gas production and transportation, tax and energy policies, changes
in supply and demand, pipeline pressures, damage to or destruction of pipelines and general
economic conditions could adversely affect our ability to produce, gather and transport oil and
natural gas.
The disruption of third-party facilities due to maintenance and/or weather could negatively
impact our ability to market and deliver our products. We have no control over when or if such
facilities are restored or what prices will be charged. A total shut-in of production could
materially affect us due to a lack of cash flow, and if a substantial portion of the production is
hedged at lower than market prices, those financial hedges would have to be paid from borrowings
absent sufficient cash flow.
Our significant indebtedness could limit our ability to successfully operate our business
We are leveraged and our exploration and development program will require substantial capital
resources estimated to range from $450 to $550 million per year over the next three years,
depending on the level of drilling and the expected cost of services. Our existing operations will
also require ongoing capital expenditures. In addition, if we decide to pursue additional
acquisitions, our capital expenditures will increase both to complete such acquisitions and to
explore and develop any newly acquired properties.
The degree to which we are leveraged could have other important consequences, including the
following:
| • | We may be required to dedicate a substantial portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations; | ||
| • | A portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates; | ||
| • | We may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage; | ||
| • | Our degree of leverage may make us more vulnerable to a downturn in our business or the general economy; | ||
| • | The terms of our existing credit arrangements contain numerous financial and other restrictive covenants; | ||
| • | Our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and | ||
| • | We may have difficulties borrowing money in the future. |
Despite our current levels of indebtedness we still may be able to incur substantially more
debt. This could further increase the risks described above.
Any failure to meet our debt obligations could harm our business, financial condition and results
of operations
If our cash flow and capital resources are insufficient to fund our debt obligations, we may
be forced to sell assets, seek additional equity or restructure our debt. In addition, any failure
to make scheduled payments of interest and principal on our outstanding indebtedness would likely
result in a reduction of our credit rating, which could harm our ability to incur additional
indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for
payment of interest on and principal of our debt in the future and any such alternative measures
may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could
cause us to default on our obligations and impair our liquidity.
We exist in a litigious environment
Any constituent could bring suit or allege a violation of an existing contract. This action
could delay when operations can actually commence or could cause a halt to production until such
alleged violations are resolved by the courts. Not only could we incur significant legal and
support expenses in defending our rights, planned operations could be delayed which would impact
our future operations and financial condition. Such legal disputes could also distract management
and other personnel from their primary responsibilities.
Common stockholders will be diluted if additional shares are issued
Since 1998, we have exchanged 31.9 million shares of common stock for debt and convertible
securities. The exchanges were made based on the relative market value of the common stock and the
debt and convertible securities at the time of the exchange. Also in 2004 and 2005, we sold 33.8
million shares of common stock to finance acquisitions. While the exchanges have reduced interest
expense, preferred dividends and future repayment obligations, the larger number of common shares
outstanding had a dilutive effect on our existing stockholders. Our ability to repurchase
securities for cash is
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limited by our bank credit facility, the 7.375% and the 6.375% senior
subordinated note agreements. In addition, we may issue additional shares of common stock,
additional subordinated notes or other securities or debt convertible into common stock, to extend
maturities or fund capital expenditures, including acquisitions. If we issue additional shares of
our common stock in the future, it may have a dilutive effect on our current outstanding
stockholders.
Dividend limitations
Limits on the payment of dividends and other restricted payments, as defined, are imposed
under our bank credit facility and under our 7.375% and 6.375% senior subordinated note agreements.
These limitations may, in certain circumstances, limit or prevent the payment of dividends
independent of our dividend policy.
Our financial statements are complex
Due to accounting rules, our financial statements continue to be complex, particularly with
reference to hedging, asset retirement obligations, equity awards and the accounting for our
deferred compensation plan. We expect such complexity to continue and possibly increase.
Our stock price may be volatile and you may not be able to resell shares of our common stock at or
above the price you paid
The price of our common stock fluctuates significantly, which may result in losses for
investors. The market price of our common stock has been volatile. From January 1, 2004 to
December 31, 2005, the last daily sale price of our common stock reported by the New York Stock
Exchange ranged from a low of $6.29 per share to a high of $28.01 per share. We expect our stock
to continue to be subject to fluctuations as a result of a variety of factors, including factors
beyond our control. These include:
| • | Changes in oil and natural gas prices; | ||
| • | Variations in quarterly drilling, recompletions, acquisitions and operating results; | ||
| • | Changes in financial estimates by securities analysts; | ||
| • | Changes in market valuations of comparable companies; | ||
| • | Additions or departures of key personnel; | ||
| • | Future sales of our stock. |
We may fail to meet expectations of our stockholders or of securities analysts at some time in
the future, and our stock price could decline as a result.
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ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2. PROPERTIES
The table below summarizes certain data for our core operating areas for the year ended
December 31, 2005:
| Average | ||||||||||||||||||||
| Daily | Total | Percentage | ||||||||||||||||||
| Production | Total | Percentage | Proved | of Total | ||||||||||||||||
| (mcfe | Production | of Total | Reserves | Proved | ||||||||||||||||
| Division | per day) | (mcfe) | Production | (Mmcfe) | Reserves | |||||||||||||||
Southwest |
116,490 | 42,518,630 | 49 | % | 502,578 | 35 | % | |||||||||||||
Appalachia |
93,744 | 34,216,554 | 39 | % | 838,312 | 60 | % | |||||||||||||
Gulf Coast |
28,842 | 10,527,376 | 12 | % | 65,872 | 5 | % | |||||||||||||
| 239,076 | 87,262,560 | 100 | % | 1,406,762 | 100 | % | ||||||||||||||
Southwest Division
The Southwest Division conducts drilling, production and field operations in the Permian basin
of West Texas and eastern New Mexico and the East Texas basin as well as in the Texas Panhandle and
the Anadarko Basin of western Oklahoma. In the Southwest Division, we own interests in 1,835 net
producing wells, 92% of which we operate. Our average working interest is 74%. We have
approximately 550,000 gross (384,000 net) acres under lease.
Reserves increased 144.4 Bcfe, or 40%, at December 31, 2005, as compared to year-end 2004.
Production was more than offset by property purchases (76 Bcfe), drilling additions (87 Bcfe) and a
net favorable reserve revision. Annual production increased 14% over 2004. During 2005, the
region spent $158.3 million to drill 198 (161.7 net) development wells, of which 191 (155.9 net)
were productive and 1 (1 net) exploratory well which was not productive. During the year, the
region achieved a 96% drilling success rate.
At December 31, 2005, the Southwest Division had a development inventory of 228 proven
drilling locations and 200 proven recompletions. Development projects include recompletions,
infill drilling and to a lesser extent, installation of secondary recovery projects. These
activities also include increasing reserves and production through aggressive cost control,
upgrading lifting equipment, improving gathering systems and surface facilities and performing
restimulations and refracturing operations.
Appalachia Division
Our property base in this division is located in the Appalachian basin in the northeastern
United States principally in Ohio, Pennsylvania, New York, West Virginia and Virginia and to a
minor extent, the Michigan basin. The reserves principally produce from the Pennsylvanian (coalbed
formation), Upper Devonian, Medina, Clinton, Queenston, Big Lime, Marcellus Shale, Niagaran Reef,
Knox, Huntersville Chert, Oriskany and Trenton Black River formations at depths ranging from 2,500
to 12,500 feet. Generally, after initial flush production, these properties are characterized by
gradual decline rates, typically producing for 10 to 35 years. We own interests in approximately
8,822 net producing wells, 74% of which we operate and 4,800 miles of gas gathering lines. Our
average working interest is 74%. We have approximately 2.1 million gross (1.9 million net) acres
under lease.
Reserves at December 31, 2005 increased 92.0 Bcfe, or 12%, from 2004 due to drilling additions
(123.8 Bcfe) which were partially offset by a net unfavorable reserve revision and production of
34.2 Bcfe. On an annual basis, production increased 69% from 2004 due to our acquisitions in 2004
(See also Note 4 to our consolidated financial statements). During 2005, the region spent $122.6
million to drill 622 (418.7 net) development wells, of which 619 (416.7 net) were productive and 12
(9.3 net) exploratory wells, of which 10 (7.7 net) were productive. During the year, the region
achieved a 99% drilling success rate. At December 31, 2005, the Appalachia Division had an
inventory of 3,114 proven drilling locations and 182 proven recompletions.
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Gulf Coast Division
The Gulf Coast properties are located onshore in south Texas, south Louisiana and Mississippi
and in the shallow waters of the Gulf of Mexico. The division’s wells are characterized by high
initial rates and relatively short reserve lives. Over the past several years, we have shifted our
focus away from offshore to onshore Gulf of Mexico properties that provide greater operating
control, generally lower costs and higher repeatability. Major onshore fields produce from
Hartburg formations at depths of 10,000 to 11,000 feet in the Upper Texas Gulf Coast to the Upper
Oligocene in South Louisiana at depths of 10,000 to 12,000 feet to the Sligo and Hosston formations
at depths of 15,000 to 16,500 feet in the Oakvale field in Mississippi. We operate a majority of
our onshore properties while third parties operate all of our offshore properties. Onshore, we
have approximately 34,000 gross (17,000 net) acres under lease. Offshore properties include
interests in 37 platforms in water depths ranging from 11 to 240 feet. We own interests in 30 net
producing wells in this division, 39% of which we operate. Our average working interest is 22%.
Our Gulf Coast Division also owns a license of a 3-D seismic database covering over 800 contiguous
blocks in the shallow water of the Gulf of Mexico, primarily offshore Louisiana.
Reserves declined 5.1 Bcfe, or 7.2%, from 2004 with production partially offset by drilling
additions (6.9 Bcfe). On an annual basis, production decreased 26% from 2004. During 2005, the
region spent $31.2 million to drill 3 (1.1 net) development wells, of which 3 (1.1 net) were
productive and 5 (1.7 net) exploratory wells, of which 3 (0.4 net) were productive. During the
year, the division had a 55% drilling success rate. At December 31, 2005, the Gulf Coast Division
had an inventory of 12 proven drilling locations and 37 proven recompletions.
Proved Reserves
The following table sets forth our estimated proved reserves at the end of each of the past
five years:
| December 31, | ||||||||||||||||||||
| 2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
Natural gas (Mmcf) |
||||||||||||||||||||
Developed |
724,876 | 580,006 | 344,187 | 320,224 | 276,162 | |||||||||||||||
Undeveloped |
400,534 | 366,422 | 142,217 | 120,043 | 112,765 | |||||||||||||||
Total |
1,125,410 | 946,428 | 486,404 | 440,267 | 388,927 | |||||||||||||||
Oil and NGLs (Mbbls) |
||||||||||||||||||||
Developed |
33,029 | 27,715 | 24,912 | 17,176 | 14,066 | |||||||||||||||
Undeveloped |
13,863 | 10,451 | 8,111 | 5,776 | 6,614 | |||||||||||||||
Total |
46,892 | 38,166 | 33,023 | 22,952 | 20,680 | |||||||||||||||
Total (Mmcfe) (a) |
1,406,762 | 1,175,425 | 684,541 | 577,977 | 513,005 | |||||||||||||||
% Developed |
65.6 | % | 63.5 | % | 72.1 | % | 73.2 | % | 70.3 | % | ||||||||||
| (a) | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcfe. |
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Our percentage of proved developed reserves declined from 2003 to 2004 due to the
significant proved undeveloped reserves acquired in the Great Lakes and Pine Mountain acquisitions
(see Note 4 to our consolidated financial statements), adding to our future drilling inventory.
The Great Lakes acquisition moved our percentage of proved undeveloped reserves from 27% to 32% and
the Pine Mountain acquisition increased that percentage to 37%. At year-end 2005, our proved
undeveloped percentage declined from 37% to 34% as we continue to aggressively drill.
The following table sets forth summary information by division with respect to estimated
proved reserves at December 31, 2005:
| Pre-tax Present Value (a) | Reserve Volumes | |||||||||||||||||||||||
| Amount | Oil & NGL | Natural Gas | Total | |||||||||||||||||||||
| (In thousands) | % | (Mbbls) | (Mmcf) | (Mmcfe) | % | |||||||||||||||||||
Southwest |
$ | 1,814,757 | 37 | % | 34,134 | 297,773 | 502,578 | 35 | % | |||||||||||||||
Appalachia |
2,695,127 | 55 | % | 11,103 | 771,694 | 838,312 | 60 | % | ||||||||||||||||
Gulf Coast |
377,491 | 8 | % | 1,655 | 55,943 | 65,872 | 5 | % | ||||||||||||||||
Total |
$ | 4,887,375 | 100 | % | 46,892 | 1,125,410 | 1,406,762 | 100 | % | |||||||||||||||
| (a) | Future net revenues were discounted using a 10% annual discount rate and constant prices. Our pre-tax present value of $4.9 billion less discounted taxes of $1.5 billion equals our standardized measure of $3.4 billion. See also Note 16 to our consolidated financial statements. |
At year-end 2005, the following independent petroleum consultants reviewed our reserves:
DeGolyer and MacNaughton (Southwest and Gulf Coast), H.J. Gruy and Associates, Inc. (Southwest),
and Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic
expertise and their history in engineering certain properties. At December 31, 2005, these
consultants collectively reviewed approximately 84% of the proved reserves. All estimates of oil
and gas reserves are subject to uncertainty. Historical variances between our reserve estimates
and the aggregate estimates of our consultants have been less than 6%.
The following table sets forth the estimated future net revenues, excluding open hedging
contracts, from proved reserves, the present value of those net revenues, the expected benchmark
prices and average field prices used in projecting them over the past five years (in millions
except prices):
| December 31, | ||||||||||||||||||||
| 2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
Future net revenue |
$ | 10,429 | $ | 5,035 | $ | 2,687 | $ | 1,817 | $ | 750 | ||||||||||
Present value |
||||||||||||||||||||
Pre-tax |
4,887 | 2,396 | 1,396 | 965 | 399 | |||||||||||||||
After tax |
3,384 | 1,749 | 1,003 | 500 | 311 | |||||||||||||||
Benchmark prices |
||||||||||||||||||||
Oil price (per barrel) |
$ | 61.04 | $ | 43.33 | $ | 32.52 | $ | 31.17 | $ | 20.38 | ||||||||||
Gas price (per mcf) |
$ | 10.08 | $ | 6.18 | $ | 6.19 | $ | 4.75 | $ | 2.63 | ||||||||||
Field prices |
||||||||||||||||||||
Oil price (per barrel) |
$ | 57.80 | $ | 40.44 | $ | 29.48 | $ | 27.52 | $ | 17.59 | ||||||||||
Gas price (per mcf) |
$ | 9.83 | $ | 6.05 | $ | 6.03 | $ | 4.76 | $ | 2.70 | ||||||||||
Future net revenues represent projected revenues from the sale of proved reserves net of
production and development costs (including operating expenses and production taxes). Such
calculations, prepared in accordance with Statement of Financial Accounting Standards No. 69,
“Disclosures about Oil and Gas Producing Activities,” are based on costs and prices in effect at
December 31 of each year. There can be no assurance that the proved reserves will be produced
within the periods indicated and prices and costs will not 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 our reserves have been filed with or included in reports to another
federal authority or agency since year-end.
16
Table of Contents
Producing Wells
The following table sets forth information relating to productive wells at December 31, 2005.
We also own royalty interests in an additional 1,656 wells where we do not own a working interest.
If we own both a royalty and a working interest in a well such interests are included in the table
below. Wells are classified as crude oil or natural gas according to their predominant production
stream.
| Average | ||||||||||||
| Total Wells | Working | |||||||||||
| Gross | Net | Interest | ||||||||||
Crude oil |
1,937 | 1,637 | 85 | % | ||||||||
Natural gas |
12,610 | 9,050 | 72 | % | ||||||||
Total |
14,547 | 10,687 | 73 | % | ||||||||
The day-to-day operations of oil and gas properties are the responsibility of the operator
designated under pooling or operating agreements. The operator supervises production, maintains
production records, employs or contracts for field personnel and performs other functions. An
operator receives reimbursement for direct expenses incurred in the performance of its duties as
well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged
by unaffiliated third parties. The charges customarily vary with the depth and location of the
well being operated.
Acreage
At December 31, 2005, we owned interests in developed and undeveloped oil and gas acreage as
set forth in the table below. These ownership interests generally take the form of working
interests in oil and gas leases or licenses that have varying terms. Developed acreage includes
leased acreage that is allocated or assignable to producing wells or wells capable of production
even though shallower or deeper horizons may not have been fully explored. Undeveloped acreage
includes leased acres on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of natural gas or oil, regardless of whether or not
the acreage contains proved reserves.
The following table sets forth certain information regarding our developed and undeveloped
acreage held at December 31, 2005:
| Average | ||||||||||||
| Acres | Working | |||||||||||
| Gross | Net | Interest | ||||||||||
Developed |
1,685,613 | 1,455,315 | 86 | % | ||||||||
Undeveloped |
1,157,140 | 926,003 | 80 | % | ||||||||
Total (a) |
2,842,753 | 2,381,318 | 84 | % | ||||||||
| (a) | Does not include 407,800 acres in Appalachia in which we own royalty and overriding royalty interests ranging from 1.5% to 14.5%. Also, does not include 51,000 acres in the Southwest Division attributable to a farm-in. |
Undeveloped Acreage Expirations
The table below summarizes by year and area our undeveloped acreage scheduled to expire in the
next five years.
| Acres | % of Total | |||||||||||
| As of December 31, | Gross | Net | Undeveloped | |||||||||
2006 |
118,390 | 84,828 | 9 | % | ||||||||
2007 |
199,640 | 145,689 | 16 | % | ||||||||
2008 |
168,092 | 138,683 | 15 | % | ||||||||
2009 |
112,193 | 89,340 | 10 | % | ||||||||
2010 |
76,581 | 67,942 | 7 | % | ||||||||
17
Table of Contents
Drilling Results
We engage in drilling activities on properties presently owned by us and intend to drill or
develop other properties we may lease or acquire in the future. The following table summarizes
drilling activity for the past three years. Gross wells reflect the sum of all wells in which we
own an interest. Net wells reflect the sum of our working interests in gross wells.
| 2005 | 2004 | 2003 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Development wells |
||||||||||||||||||||||||
Productive |
813.0 | 573.8 | 436.0 | 368.5 | 322.0 | 180.7 | ||||||||||||||||||
Dry |
10.0 | 7.7 | 16.0 | 12.0 | 16.0 | 11.4 | ||||||||||||||||||
Exploratory wells |
||||||||||||||||||||||||
Productive |
13.0 | 8.1 | 14.0 | 9.2 | 11.0 | 3.8 | ||||||||||||||||||
Dry |
5.0 | 3.9 | 10.0 | 6.9 | 9.0 | 4.4 | ||||||||||||||||||
Total wells |
||||||||||||||||||||||||
Productive |
826.0 | 581.9 | 450.0 | 377.7 | 333.0 | 184.5 | ||||||||||||||||||
Dry |
15.0 | 11.6 | 26.0 | 18.9 | 25.0 | 15.8 | ||||||||||||||||||
Total |
841.0 | 593.5 | 476.0 | 396.6 | 358.0 | 200.3 | ||||||||||||||||||
Success ratio |
98 | % | 98 | % | 95 | % | 95 | % | 93 | % | 92 | % | ||||||||||||
Real Property
We lease approximately 68,500 square feet of office space primarily in Texas and Oklahoma
under standard office lease arrangements that expire at various dates through April 2010. Our
Appalachian Division owns a 34,500 square foot office building and various other field offices. We
believe our facilities are adequate to meet our current needs and existing space could be expanded
or additional space could be leased if required. We own various vehicles and other equipment that
is used in field operations. We believe such equipment is in good repair and can be readily
replaced if necessary.
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance
with generally accepted industry standards. As is customary in the industry, in the case of
undeveloped properties, often little investigation of record title is made at the time of lease
acquisition. Investigations are made prior to the consummation of an acquisition of producing
properties and before commencement of drilling operations on undeveloped properties. Individual
properties may be subject to burdens that we believe do not materially interfere with the use or
affect the value of the properties. Burdens on properties may include:
| • | Customary royalty interests; | ||
| • | Liens incident to operating agreements and for current taxes; | ||
| • | Obligations or duties under applicable laws; | ||
| • | Development obligations under oil and gas leases; and | ||
| • | Burdens such as net profit interests. |
ITEM 3. LEGAL PROCEEDINGS
We have been named as a defendant in a number of legal actions arising in the ordinary course
of our business. In the opinion of management, such litigation and claims are likely to be
resolved without a material adverse effect on our financial position, cash flows or results of
operations. See also Note 9 to our consolidated financial statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of our security holders during the fourth quarter of
2005.
18
Table of Contents
PART II
ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Our common stock is listed on the New York Stock Exchange, or the NYSE, under the symbol
“RRC.” During 2005, trading volume averaged 1.3 million shares per day. The following table shows
the quarterly high and low sale prices, cash dividends declared and volumes as reported on the NYSE
composite tape for the past two years (as adjusted for a three-for-two stock split effected on
December 2, 2005).
| Average | ||||||||||||||||
| Cash Dividends | Daily | |||||||||||||||
| High | Low | Declared | Volumes | |||||||||||||
2004 |
||||||||||||||||
First quarter |
$ | 8.10 | $ | 6.25 | — | 421,140 | ||||||||||
Second quarter |
9.75 | 7.19 | .0067 | 698,364 | ||||||||||||
Third quarter |
11.79 | 9.03 | .0067 | 694,575 | ||||||||||||
Fourth quarter |
14.43 | 9.97 | .0133 | 1,048,493 | ||||||||||||
2005 |
||||||||||||||||
First quarter |
$ | 17.59 | $ | 12.34 | .0133 | 1,072,650 | ||||||||||
Second quarter |
18.62 | 13.50 | .0133 | 1,334,709 | ||||||||||||
Third quarter |
26.33 | 18.01 | .0133 | 1,203,888 | ||||||||||||
Fourth quarter |
28.37 | 20.71 | .02 | 1,565,650 | ||||||||||||
Between January 1, 2006 and February 20, 2006, the common stock traded at prices between
$23.21 and $30.52 per share. The 7.375% senior subordinated notes and the 6.375% senior
subordinated notes are not listed on an exchange, but trade over-the-counter.
Holders of Record
On February 20, 2006, there were approximately 1,940 holders of record of our common stock.
Dividends
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, the 7.375%
senior subordinated notes and the 6.375% senior subordinated notes allow for the payment of common
and preferred dividends, with certain limitations. The determination of the amount of future
dividends, if any, to be declared and paid is at the sole discretion of our board and will depend
upon our level of earnings and capital expenditures and other matters that the board of directors
deems relevant. For more information see information set forth in Item 7 of this report
“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
19
Table of Contents
ITEM 6. SELECTED FINANCIAL DATA
The following table shows selected financial information for the five years ended December 31,
2005. Significant producing property acquisitions in 2003 and 2004 affect the comparability of
year-to-year financial and operating data. All weighted average shares and per share data have
been adjusted for the three-for-two stock split effected December 2, 2005. This information should
be read in conjunction with Item 7 of this report “Management’s Discussion and Analysis of
Financial Condition and Results of Operations,” and our consolidated financial statements and
related notes (in thousands, except per share data).
Statement of Operations Data:
| Year Ended December 31, | ||||||||||||||||||||
| 2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
Revenues |
||||||||||||||||||||
Oil and gas sales |
$ | 525,074 | $ | 315,703 | $ | 226,402 | $ | 190,954 | $ | 208,854 | ||||||||||
Transportation and gathering |
2,578 | 2,202 | 3,509 | 3,495 | 3,435 | |||||||||||||||
Gain (loss) on retirement of securities |
— | (39 | ) | 18,526 | 3,098 | 3,951 | ||||||||||||||
Mark-to-market on oil and gas derivatives |
10,868 | — | — | — | — | |||||||||||||||
Other |
(2,563 | ) | 2,841 | (2,670 | ) | (5,958 | ) | 3,375 | ||||||||||||
Total revenue |
535,957 | 320,707 | 245,767 | 191,589 | 219,615 | |||||||||||||||
Costs and expenses |
||||||||||||||||||||
Direct operating |
66,632 | 46,308 | 36,423 | 31,869 | 34,884 | |||||||||||||||
Production and ad valorem taxes |
31,516 | 20,504 | 12,894 | 8,574 | 8,546 | |||||||||||||||
Exploration |
29,437 | 21,219 | 13,946 | 11,525 | 5,879 | |||||||||||||||
General and administrative |
29,432 | 20,634 | 17,818 | 16,217 | 14,622 | |||||||||||||||
Non-cash stock compensation |
35,250 | 19,176 | 6,559 | 1,023 | (2,410 | ) | ||||||||||||||
Interest expense and dividends on trust preferred |
38,797 | 23,119 | 22,165 | 23,153 | 32,179 | |||||||||||||||
Depletion, depreciation and amortization |
127,514 | 99,408 | 86,549 | 76,820 | 77,573 | |||||||||||||||
Provision for impairment |
— | 3,563 | — | — | 31,085 | |||||||||||||||
Total costs and expenses |
358,578 | 253,931 | 196,354 | 169,181 | 202,358 | |||||||||||||||
Income before income taxes and accounting change |
177,379 | 66,776 | 49,413 | 22,408 | 17,257 | |||||||||||||||
Income tax (benefit) |
||||||||||||||||||||
Current |
1,071 | (245 | ) | 170 | (4 | ) | (406 | ) | ||||||||||||
Deferred |
65,297 | 24,790 | 18,319 | (3,354 | ) | — | ||||||||||||||
| 66,368 | 24,545 | 18,489 | (3,358 | ) | (406 | ) | ||||||||||||||
Income before cumulative effect of changes in
accounting principles |
111,011 | 42,231 | 30,924 | 25,766 | 17,663 | |||||||||||||||
Cumulative effect of changes in accounting principles,
net of taxes |
— | — | 4,491 | — | — | |||||||||||||||
Net income |
111,011 | 42,231 | 35,415 | 25,766 | 17,663 | |||||||||||||||
Gain on retirement of preferred stock |
— | — | — | 556 | ||||||||||||||||
Preferred dividends |
— | (5,163 | ) | (803 | ) | — | (10 | ) | ||||||||||||
Net income available to common stockholders |
$ | 111,011 | $ | 37,068 | $ | 34,612 | $ | 25,766 | $ | 18,209 | ||||||||||
Earnings per common share: |
||||||||||||||||||||
Net income available to common stockholders |
$ | 0.89 | $ | 0.40 | $ | 0.37 | $ | 0.32 | $ | 0.24 | ||||||||||
Cumulative effect of changes in accounting
principles |
— | — | 0.05 | — | — | |||||||||||||||
Net income per common share |
$ | 0.89 | $ | 0.40 | $ | 0.42 | $ | 0.32 | $ | 0.24 | ||||||||||
Earnings per common share — assuming dilution |
$ | 0.86 | $ | 0.38 | $ | 0.36 | $ | 0.32 | $ | 0.24 | ||||||||||
Cumulative effect of changes in accounting
principles |
— | — | 0.05 | — | — | |||||||||||||||
Net income per common share — assuming dilution |
$ | 0.86 | $ | 0.38 | $ | 0.41 | $ | 0.32 | $ | 0.24 | ||||||||||
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| Year Ended December 31, | ||||||||||||||||||||
| 2005 | 2004 | 2003 | 2002 | 2001 | ||||||||||||||||
Balance Sheet Data: |
||||||||||||||||||||
Current assets (a) |
$ | 207,977 | $ | 136,336 | $ | 66,092 | $ | 50,619 | $ | 77,735 | ||||||||||
Current liabilities (b) |
321,760 | 177,162 | 106,964 | 67,206 | 47,879 | |||||||||||||||
Oil and gas properties, net |
1,741,182 | 1,402,359 | 723,382 | 564,406 | 533,357 | |||||||||||||||
Total assets |
2,018,985 | 1,595,406 | 830,091 | 658,484 | 682,462 | |||||||||||||||
Bank debt |
269,200 | 423,900 | 178,200 | 115,800 | 95,000 | |||||||||||||||
Non-recourse debt |
— | — | 70,000 | 76,500 | 98,801 | |||||||||||||||
Subordinated debt |
346,948 | 196,656 | 109,980 | 90,901 | 108,690 | |||||||||||||||
Trust preferred securities |
— | — | — | 84,840 | 89,740 | |||||||||||||||
Stockholders’ equity (c) |
696,923 | 566,340 | 274,066 | 206,109 | 235,621 | |||||||||||||||
Weighted average dilutive shares outstanding |
129,125 | 97,998 | 86,775 | 81,627 | 76,898 | |||||||||||||||
Cash dividends declared per common share |
.0599 | .0267 | .0067 | — | — | |||||||||||||||
Cash Flow Data: |
||||||||||||||||||||
Net cash provided from operating activities |
325,745 | 209,249 | 124,680 | 114,472 | 130,572 | |||||||||||||||
Net cash used in investing activities |
(432,377 | ) | (624,301 | ) | (186,838 | ) | (103,950 | ) | (79,163 | ) | ||||||||||
Net cash provided from (used in) financing
activities |
93,000 | 432,803 | 61,455 | (12,568 | ) | (50,641 | ) | |||||||||||||
| (a) | 2005, 2004 and 2003 include deferred tax assets of $61.7 million, $26.3 million and $19.9 million, respectively. 2001 includes a hedging asset of $37.2 million. | |
| (b) | 2005, 2004, 2003 and 2002 include hedging liabilities of $160.1 million, $61.0 million, $54.3 million and $26.0 million, respectively. | |
| (c) | Stockholders’ equity includes other comprehensive income (loss) of ($147.1 million), ($43.3 million), ($42.9 million), ($21.2 million) and $45.5 million in 2005, 2004, 2003, 2002 and 2001, respectively. |
21
Table of Contents
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion is intended to assist you in understanding our business and results
of operations together with our present financial condition. This section should be read in
conjunction with Item 6, Selected Financial Data and our consolidated financial statements and the
accompanying notes included elsewhere in this Form 10-K.
Statements in our discussion may be forward looking. These forward-looking statements involve
risks and uncertainties. We caution that a number of factors could cause future production,
revenues and expenses to differ materially from our expectations. See “Disclosures Regarding
Forward-Looking Statements” at the beginning of this Annual Report and “Risk Factors” in Item 1A
for additional discussion of some of these factors and risks.
Overview of Our Business
We are an independent natural gas and oil company engaged in the exploration, development and
acquisition of oil and gas properties, primarily in the Southwestern, Appalachian and Gulf Coast
regions of the United States. We operate in one segment as each of our operating areas has similar
economic characteristics and each meets the criteria for aggregation as defined in Statement of
Financial Accounting Standards No. 131, “Disclosure About Segments of an Enterprise and Related
Information.”
Our strategy is to increase reserves and production through internally generated drilling
projects coupled with complementary acquisitions. Our revenues, profitability and future growth
depend substantially on prevailing prices for oil and gas and on our ability to find, develop and
acquire oil and gas reserves that are economically recoverable. We use the successful efforts
method of accounting for our oil and gas activities.
Industry Environment
We operate entirely within the United States, a mature region for the exploration and
production of oil and gas. As a mature region, while new discoveries of oil and gas occur in the
United States, the size and frequency of these discoveries is declining, while finding and
development costs are increasing. We believe that there remain areas of the United States, such as
the Appalachian basin and certain areas in our Southwest and Gulf Coast Divisions, which are
underexplored or have not been fully explored and developed with the benefit of newly available
exploration, production and reserve enhancement technology. Examples of such technology include
advanced 3-D seismic processing, hydraulic reservoir fracture stimulation, advances in well logging
and analysis, horizontal drilling and completion techniques, secondary and tertiary recovery
practices, and automated remote well monitoring and control devices.
Another characteristic of a mature region is the exit of larger independent producers and the
major oil companies from such regions. These companies, searching for ever larger new discoveries,
have ventured increasingly overseas and offshore, de-emphasizing their onshore United States
assets. This movement out of mature basins by larger companies has provided acquisition
opportunities for companies like ours that maintain well-equipped technical teams capable of
generating additional value from these assets. In other situations, to increase cash flow without
increasing capital spending, larger independent producers and major integrated oil companies have
allowed smaller companies the opportunity to explore and develop reserves on their undeveloped
acreage through joint ventures and farm-in arrangements.
We believe the acquisition market for natural gas properties has become extremely competitive
as producers vie for additional production and expanded drilling opportunities. Acquisition values
have reached historic highs and we expect these values to continue to climb in 2006. In addition,
we expect drilling and service costs to increase in 2006 and for lease operating expenses to
continue to rise as producers are forced to make operational enhancements to maintain aging fields.
Source of Our Revenues
We derive our revenues from the sale of natural gas and oil that is produced from our natural
gas and oil properties. Revenues are a function of the volume produced and the prevailing market
price at the time of sale. The price of oil and natural gas is the primary factor affecting our
revenues. To achieve more predictable cash flows and to reduce our exposure to downward price
fluctuations, we utilize derivative instruments to hedge future sales prices on a significant
portion of our natural gas and oil production. During 2005, 2004 and 2003, the use of derivative
instruments prevented us from realizing the full benefit of upward price movements and may continue
to do so in future periods.
22
Table of Contents
Principal Components of Our Cost Structure
| • | Direct Operating Expenses. The day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include workovers and repairs to our oil and gas properties not covered by insurance. These costs are expected to increase in 2006 as the demand for these services continues to increase. | ||
| • | Production and Ad Valorem Taxes. These costs are primarily paid based on a percentage of market prices and not on hedged prices of production or at fixed rates established by federal, state or local taxing authorities. | ||
| • | Exploration Expense. Geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory wells or dry holes. | ||
| • | General and Administrative Expense. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, managing our production and development operations, audit and other professional fees and legal compliance are included in general and administrative expense. | ||
| • | Interest. We typically finance our working capital requirements and acquisitions with borrowings under our bank credit facility, and with our longer term publically traded debt securities. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We may continue to incur significant interest expense as we continue to grow. We expect our 2006 capital budget to be funded with internal cash flow. | ||
| • | Depreciation, Depletion and Amortization. The systematic expensing of the capital costs incurred to acquire, explore and develop natural gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts, and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. | ||
| • | Income Taxes. We are subject to state and federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs, or IDC. We do pay some state income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on another basis. Currently, all of our federal taxes are deferred; however, at some point, we will utilize all of our net operating loss carryforwards and we will recognize current income tax and continue to recognize current tax expense as long as we are generating taxable income. |
Overview of 2005 Results
During 2005, we achieved the following results:
| • | 22% production growth and 20% reserve growth; | ||
| • | Drilled over 590 net wells; | ||
| • | Continued expansion of drilling inventory and emerging plays; | ||
| • | Record financial results and continued balance sheet improvement; and | ||
| • | Completed an acquisition of properties containing 77 Bcfe of proved reserves. |
23
Table of Contents
Management’s Discussion and Analysis of Income and Operations
Volumes and Price Data
| 2005 | 2004 | 2003 | ||||||||||
Production: |
||||||||||||
Crude oil (bbls) |
3,031,468 | 2,512,434 | 2,023,158 | |||||||||
NGLs (bbls) |
1,011,692 | 988,192 | 400,631 | |||||||||
Natural gas (mcfs) |
63,003,600 | 50,722,121 | 43,510,180 | |||||||||
Total (mcfe) (a) |
87,262,560 | 71,725,877 | 58,052,911 | |||||||||
Average daily production: |
||||||||||||
Crude oil (bbls) |
8,305 | 6,865 | 5,543 | |||||||||
NGLs (bbls) |
2,772 | 2,700 | 1,098 | |||||||||
Natural gas (mcfs) |
172,613 | 138,585 | 119,206 | |||||||||
Total (mcfe) (a) |
239,076 | 195,972 | 159,049 | |||||||||
Average sales prices (excluding hedging): |
||||||||||||
Crude oil (per bbl) |
$ | 53.31 | $ | 39.25 | $ | 28.42 | ||||||
NGLs (per bbl) |
31.52 | 23.73 | 18.75 | |||||||||
Natural gas (per mcf) |
7.98 | 5.79 | 5.10 | |||||||||
Total (per mcfe) (a) |
7.98 | 5.80 | 4.94 | |||||||||
Average sales prices (including hedging): |
||||||||||||
Crude oil (per bbl) |
$ | 38.71 | $ | 28.04 | $ | 23.53 | ||||||
NGLs (per bbl) |
27.27 | 19.76 | 18.75 | |||||||||
Natural gas (per mcf) |
6.03 | 4.45 | 3.94 | |||||||||
Total (per mcfe) (a) |
6.02 | 4.40 | 3.90 | |||||||||
| (a) | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcfe. |
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Overview
Our 2005 performance reflects the benefits of higher oil and gas production, higher oil and
gas prices and continued focus upon our cost structure. The business of exploring for, developing,
and acquiring oil and gas is highly competitive and capital intensive. As in any commodity
business, the costs associated with finding, acquiring, extracting, and financing the operation are
critical to profitability and long-term value creation for stockholders. Generating meaningful
growth while containing costs represents an ongoing challenge for management. During periods of
historically high oil and gas prices, such as 2005, drilling service and operating cost increases
are more prevalent due to increased competition for goods and services. We faced other challenges
in 2005 including attracting and retaining qualified personnel, consummating and integrating
acquisitions, and accessing the capital markets to fund our growth and capital simplification
process on sufficiently favorable terms. We have continued to expand and improve the technical
staff through the hiring of additional experienced professionals. Our inventory of exploration and
development prospects continues to build, providing new growth opportunities, greater
diversification of technical risk and better efficiency.
Revenues increased 67% in 2005 over the same period of 2004. This increase is due to higher
production and realized oil and gas prices. Our 2005 production growth is due to acquisitions
completed in 2004 and to the continued success of our drilling program. Realized prices were
higher by 37% in 2005 reflecting higher market prices and the expiration of lower priced oil and
gas hedges. Since December 31, 2005, oil and gas prices have remained volatile, particularly the
price of natural gas. On February 17, 2006, the NYMEX spot price for natural gas closed at $7.18
per Mmbtu which is significantly below the market price at the end of the year. As discussed in
Item 1A of this report, significant changes in oil and gas prices can have a significant impact on
our balance sheet and our results of operations, particularly on the fair value of our derivatives.
Comparison of 2005 to 2004
Net income increased $68.8 million, with higher average oil and gas prices and volumes as
primary factors contributing to this increase. Increased revenues were partially offset by higher
operating costs and higher DD&A.
Average realized price received for oil and gas during 2005 was $6.02 per mcfe, up 37% or
$1.62 per mcfe from 2004. Oil and gas revenues for 2005 reached a record $525.1 million and were
66% higher than 2004 due to higher oil and gas prices and a 22% increase in production. The
average price received increased 38% to $38.71 per barrel for oil and increased 36% to $6.03 per
mcf for gas from 2004. The effect of our hedging program decreased realized prices $1.96 per mcfe
in 2005 versus a decrease of $1.40 in 2004.
Production volume increased 22% from 2004 due to our drilling program and additions from
acquisitions consummated in 2004, primarily our purchase of the 50% of Great Lakes that we did not
own and Pine Mountain. Production increased 15.5 Bcfe from 2004. Our production volumes increased
69% in our Appalachia Division, increased 14% in our Southwest Division and declined 26% in our
Gulf Coast Division.
Transportation and gathering revenue of $2.6 million increased $376,000 from 2004. This
increase is primarily due to higher gas prices and additional throughput volumes offset by lower
oil marketing revenue.
Mark-to-market on oil and gas derivatives includes a gain of $10.9 million in 2005. In the
fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the
effect of recent volatility of gas prices on the correlation between realized prices and hedge
reference prices.
Other revenue declined in 2005 to a loss of $2.6 million from a gain of $2.8 million in 2004.
The 2005 period includes ineffective hedging losses due to widening basis differentials of $3.4
million offset by net IPF income of $514,000. The 2004 period includes a gain on the sale of
properties of $5.0 million and $712,000 of ineffective hedging gains offset by $2.0 million
write-down of an insurance claim receivable. Other revenue for 2004 also includes net IPF expenses
of $1.8 million.
Direct operating expense increased $20.3 million to $66.6 million due to increased costs from
acquisitions, higher oilfield service costs and higher workover costs primarily in our Gulf Coast
Division. Our operating expenses are increasing as we add new wells and maintain production from
our existing properties. We incurred $7.4 million of expenses associated with workovers in 2005
versus $1.8 million in 2004. In 2005, 58% of our workover expenses were incurred by our Gulf Coast
Division and were primarily hurricane related. On a per mcfe basis, direct operating expenses
were $0.76 per mcfe and increased $0.11 per mcfe from 2004 consisting of higher field level
costs of $0.04 and higher workover costs of $0.07.
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Table of Contents
Production and ad valorem taxes are paid based on market prices and not hedged prices. These
taxes increased $11.0 million, or 54%, from the same period of the prior year. On a per mcfe
basis, production and ad valorem taxes increased from $0.29 per mcfe to $0.36 per mcfe due to
higher market prices.
Exploration expense increased 39% to $29.4 million due to higher seismic costs ($10.5 million)
and higher personnel costs, partially offset by lower dry hole costs ($5.0 million). Exploration
expense includes exploration personnel costs of $6.0 million in 2005 versus $4.4 million in 2004.
General and administrative expense for 2005 increased 43%, or $8.8 million, from 2004 with
additional personnel costs due to the Great Lakes and Pine Mountain acquisitions ($1.8 million),
higher salaries and benefits ($3.5 million), higher legal expenses ($1.3 million) and a $725,000
legal settlement accrual (See also Note 9 to our consolidated financial statements). On a per mcfe
basis, general and administration expense increased from $0.29 per mcfe in 2004 to $0.34 per mcfe
in 2005.
Non-cash stock compensation increased 84%, or $16.1 million, from 2004. This non-cash expense
relates to the increase in value of our common stock and other investments held in our deferred
compensation plans. Our common stock price increased from $13.64 per share at the end of 2004 to
$26.34 per share, at the end of 2005. The twelve months ended December 31, 2005 also includes $5.8
million mark-to-market expense for stock appreciation rights issued in 2005.
Interest expense for 2005 increased $15.7 million, or 68%, to $38.8 million with higher
average interest rates, higher average debt balances and the refinancing of certain debt from
short-term floating to longer-term fixed rates. In March 2005, we issued $150.0 million of 6.375%
senior subordinated notes which added $7.8 million of interest costs. The proceeds from this
issuance were used to retire lower interest bank debt. Average debt outstanding on the bank credit
facility was $314.8 million and $296.6 million for 2005 and 2004, respectively, and the average
interest rates were 4.3% and 3.5%, respectively.
Depletion, depreciation and amortization, or DD&A, increased $24.5 million, or 24%, due to
higher production and higher depletion rates. DD&A increased from $1.39 per mcfe in 2004 to $1.46
per mcfe in 2005. The twelve months ended December 31, 2004 includes a $3.6 million impairment
charge on an offshore property in our Gulf Coast Division. For 2006, based on our current reserve
base, we expect our DD&A rate to average approximately $1.55 per mcfe.
Tax expense for 2005 increased $41.8 million, or 170%, over 2004 due to a 166% increase in
income before taxes. Our effective tax rate for 2005 and 2004 was 37%. Given our available net
operating loss carryforward, we do not expect to pay significant federal income taxes; however, we
do expect to pay $1.1 million of state income taxes.
The following table presents information about our operating expenses per mcfe for 2005 and
2004.
| Operating expenses per mcfe | 2005 | 2004 | Change | % | ||||||||||||
Direct operating expense |
$ | 0.76 | $ | 0.65 | $ | 0.11 | 17 | % | ||||||||
Production and ad valorem tax expense |
0.36 | 0.29 | 0.07 | 24 | % | |||||||||||
General and administration expense |
0.34 | 0.29 | 0.05 | 17 | % | |||||||||||
Interest expense |
0.44 | 0.32 | 0.12 | 38 | % | |||||||||||
Depletion, depreciation and amortization expense
(excluding impairment in 2004) |
1.46 | 1.39 | 0.07 | 5 | % | |||||||||||
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Comparison of 2004 to 2003
Net income increased $6.8 million, with higher average oil and gas prices and volumes as a
primary factor contributing to this increase. Increased revenues were partially offset by higher
operating costs and higher DD&A. The year ended 2003 included an $18.5 million gain on retirement
of debt and convertible securities versus a loss of $39,000 in 2004. The year ended 2003 also
included a $4.5 million favorable cumulative effect of change in accounting principle.
Average realized price received for oil and gas during 2004 was $4.40 per mcfe, up 13%, or
$0.50 per mcfe, from 2003. Oil and gas revenues for 2004 reached $315.7 million and were 39%
higher than 2003 due to higher oil and
gas prices and a 24% increase in production. The average price received increased 19% to $28.04
per barrel for oil and increased 13% to $4.45 per mcf for gas from 2003. The effect of our hedging
program decreased realized prices $1.40 per mcfe in 2004 versus a decrease of $1.04 in 2003.
Production volume increased 24% from 2003 due to our drilling program and additions from
acquisitions consummated in late 2003 and 2004, primarily the Conger Field acquisition in 2003 and
our purchase of the 50% of Great Lakes that we did not own in 2004. Production increased 13.7 Bcfe
from 2003. Our production volumes increased 56% in our Appalachian Division, increased 30% in our
Southwestern Division and declined 14% in our Gulf Coast Division.
Transportation and gathering revenue of $2.2 million declined $1.3 million from 2003. This
decline is due to lower oil marketing revenues and additional gas transportation system employee
expense related to the Conger Field acquisition ($1.1 million) partially offset by additional
revenue related to the Great Lakes acquisition.
Gain (loss) on retirement of securities was a loss of $39,000 in 2004 versus a gain of $19.0
million in 2003. The year ended 2004 includes the purchase for cash of $2.7 million of 6%
debentures. During 2003, 193,500 shares of common stock were exchanged for $880,000 of 6%
debentures with a conversion expense of $465,000 recorded on the exchange. In
addition, 2003 included $9.1 million of 6% debentures, $500,000 of 8.75% Notes, and $5.3 million of
Trust Preferred Securities were repurchased for cash. Also in 2003, $10.2 million of cash and
$50.0 million of our newly issued convertible preferred stock was exchanged for $79.5 million of
Trust Preferred Securities.
Other revenue increased in 2004 to $2.8 million from a loss of $2.7 million in 2003. The 2004
period includes a gain on the sale of properties of $5.0 million and $712,000 of ineffective
hedging gains offset by $2.0 million write-down of an insurance claim receivable. Other revenue
for 2004 also includes net IPF expenses of $1.8 million. Other revenue in 2003 includes an
ineffective hedging loss of $1.2 million and net IPF expenses of $1.4 million.
Direct operating expense increased $9.9 million to $46.3 million due to increased costs from
acquisitions and higher oilfield service costs. Our operating expenses are increasing as we add
new wells and maintain production from our existing properties. We incurred $1.8 million of
expenses associated with workovers in 2004 versus $2.7 million in 2003. On a per mcfe basis,
direct operating expenses increased $0.02 per mcfe with higher field level costs offset by lower
workover costs.
Production and ad valorem taxes are paid based on market prices and not hedged prices. These
taxes increased $7.6 million, or 59%, from the same period of the prior year. On a per mcfe basis,
production and ad valorem taxes increased from $0.22 per mcfe to $0.29 per mcfe due to higher
market prices.
Exploration expense increased 52% to $21.2 million due to higher dry hole costs ($8.5 million)
and higher personnel costs partially offset by lower seismic purchases ($2.6 million). Exploration
expense includes exploration personnel costs of $4.4 million in 2004 versus $3.3 million in 2003.
General and administrative expense for 2004 increased 16%, or $2.8 million, from 2003 due
primarily to higher professional fees and additional personnel costs due to the Great Lakes
acquisition. On a per mcfe basis, general and administrative expense declined from $0.31 per mcfe
in 2003 to $0.29 per mcfe in 2004.
Non-cash stock compensation increased $12.6 million from 2003. This non-cash expense relates
to the increase in value of our common stock and other investments held in our deferred
compensation plans. Our common stock price increased from $6.30 per share at the end of 2003 to
$13.64 per share at the end of 2004.
Interest expense for 2004 increased $1.0 million, or 4%, to $23.1 million with higher interest
rates and average debt balance partially offset by a lower call premiums of $1.8 million. Interest
expense for 2003 included a $2.0 million
call premium on the 8.75% Notes. Average debt outstanding on the bank credit facility was
$262.4 million and $104.7 million for 2004 and 2003, respectively and the average interest rates
were 3.3% and 3.1%, respectively.
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Depletion, depreciation and amortization, or DD&A, increased $16.4 million, or 19%, to $103.0
million due to higher production and a $3.6 million (or $0.05 per mcfe) impairment charge on an
offshore property in our Gulf Coast division. The impairment was attributable to hurricane damage
and related production declines. On a per mcfe basis,
excluding the impairment charge on the offshore property, DD&A declined from $1.49 per mcfe to
$1.39 per mcfe. For 2005, based on our current reserve base, we expect our DD&A rate to average
$1.45 per mcfe.
Tax expense for 2004 increased $6.1 million, or 33%, over 2003 due to a 35% increase in income
before taxes. Year-end 2004 and 2003 provide for a tax rate of 37%. Given our available net
operating loss carryforward, we do not expect to pay significant cash federal income taxes.
The following table presents information about our operating expenses for each of the years in
the two-year period ended December 31, 2004.
| Operating expenses per mcfe | 2004 | 2003 | Change | % | ||||||||||||
Direct operating expense |
$ | 0.65 | $ | 0.63 | $ | 0.02 | 3 | % | ||||||||
Production and ad valorem tax expense |
0.29 | 0.22 | 0.07 | 32 | % | |||||||||||
General and administration expense |
0.29 | 0.31 | (0.02 | ) | (6 | %) | ||||||||||
Interest expense |
0.32 | 0.38 | (0.06 | ) | (16 | %) | ||||||||||
Depletion, depreciation and amortization
expense
(excluding impairment in 2004) |
1.39 | 1.49 | (0.10 | ) | (7 | %) | ||||||||||
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Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity
During 2005, our cash provided from operations was $325.7 million, and we spent $441.8 million
on capital expenditures (including acquisitions). During this period, financing activities
provided net cash of $93.0 million. Our financing activity included the sale in March 2005 of
$150.0 million of 6.375% Notes that enabled us to better match the maturities of our debt with the
life of our properties and decrease our interest rate volatility. In addition, in June 2005 we
issued 6.9 million common shares in a public offering for net proceeds of $109.2 million. At
December 31, 2005 we had $4.7 million in cash, total assets of $2.0 billion and a
debt-to-capitalization ratio of 47%. Long-term debt at December 31, 2005 totaled $616.1 million,
including $269.2 million of bank debt and $346.9 million of senior subordinated notes. Available
borrowing capacity under the bank credit facility at December 31, 2005 was $330.8 million.
Cash is required to fund capital expenditures necessary to offset inherent declines in
production and reserves which is typical in the oil and gas industry. Future success in growing
reserves and production will be highly dependent on capital resources available and the success of
finding or acquiring additional reserves. We believe that net cash generated from operating
activities and unused committed borrowing capacity under the bank credit facility combined with our
oil and gas price hedges currently in place will be adequate to satisfy near term financial
obligations and liquidity needs. However, long-term 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 our ability to fund capital expenditures, reduce
debt, meet financial obligations and remain profitable. We operate in an environment with numerous
financial and operating risks, including, but not limited to, the inherent risks of the search for,
development and production of oil and gas, the ability to buy properties and sell production at
prices which provide an attractive return and the highly competitive nature of the industry. Our
ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through
internal cash flow, bank 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 capital expenditures that we believe are necessary to offset inherent declines in
production and proved reserves.
In 2004, we filed a new universal shelf registration statement with the SEC registering $500.0
million aggregate amount of common stock, preferred stock and other equity and debt securities. In
December 2004, we issued 8.6 million shares of common stock under this shelf registration statement
for an aggregate price of $107.8 million. In June 2005, we issued 6.9 million shares of common
stock under this shelf registration for an aggregate price of $113.9 million. As of December 31,
2005, we have $278.3 million of capacity remaining under the shelf. Range qualifies as a
Well-Known Seasoned Issuer.
Bank Debt
We maintain a $600.0 million revolving credit facility, which we refer to as our bank debt or
our bank credit facility. The bank credit facility is secured by substantially all of our assets
and matures on January 1, 2009. Availability under the bank credit facility is subject to a
borrowing base set by the banks semi-annually and more often in certain other circumstances. The
borrowing base is dependent on a number of factors, primarily the lenders’ assessment of future
cash flows. Redeterminations of the borrowing base require approval of 75% of the lenders;
increases require unanimous approval. At February 20, 2006, the bank credit facility had a $600.0
million borrowing base of which $310.7 million was available.
Limitations on the payment of dividends and other restricted payments as defined are imposed
under our bank debt, the 7.375% Notes and the 6.375% Notes. Under the bank credit facility, common
and preferred dividends are permitted. The terms of both the 7.375% Notes and the 6.375% Notes
limit restricted payments (including dividends) to the greater of $20.0 million or a formula based
on earnings and equity issuances since the original issuances of the notes. At December 31, 2005,
approximately $432.9 million was available under the restricted payment baskets for both the 6.375%
Notes and the 7.375% Notes. The bank credit facility provides for a restricted payment basket of
$20.0 million plus 66-2/3% of net cash proceeds from common stock issuances and 50% of net income.
Approximately $365.8 million was available under the bank credit facility restricted payment basket
as of December 31, 2005. The debt agreements contain customary covenants relating to debt
incurrence, working capital, dividends and financial ratios. We were in compliance with all
covenants at December 31, 2005.
Cash Flow
Our principal sources of cash are operating cash flow, bank borrowings and at times, issuance
of debt and equity securities. Our operating cash flow is highly dependent on oil and gas prices.
As of December 31, 2005, we had entered into hedging agreements covering 61.2 Bcfe, 43.7 Bcfe and
14.3 Bcfe for 2006, 2007 and 2008, respectively. The $288.2 million
29
Table of Contents
of cash capital expenditures
for 2005, excluding acquisitions, was funded with internal cash flow. The $429.0 million capital
budget for 2006, which excludes acquisitions, is expected to increase production and to expand the
reserve base. Based on current projections, oil and gas futures prices and our hedge position, the
2006 capital program is expected to be funded with internal cash flow.
Net cash provided from operating activities in 2005, 2004 and 2003 was $325.7 million, $209.2
million and $124.7 million, respectively. In 2005, cash flow from operations increased due to
higher production volumes and prices partially offset by increasing operating, exploration and
interest expenses. In 2004, cash flow from operations increased due to higher volumes and prices
partially offset by increasing operating and exploration expenses. In 2003, cash flow from
operations increased with higher volumes and higher prices partially offset by increasing operating
and exploration expenses.
Net cash used in investing activities in 2005, 2004 and 2003 was $432.4 million, $624.3
million and $186.8 million, respectively. In 2005, we spent $276.9 million in additions to oil and
gas properties and $153.6 million on acquisitions. The 2004 period included $166.6 million in
additions to oil and gas properties and $485.6 million of acquisitions. The 2003 period included
$91.2 million in additions to oil and gas properties, and $103.9 million of acquisitions, partially
offset by $10.3 million of IPF net repayments.
Net cash provided from financing activities in 2005, 2004 and 2003 was $93.0 million, $432.8
million and $61.5 million, respectively. Historically, sources of financing have been primarily
bank borrowings and capital raised through equity and debt offerings. During 2005, we received
proceeds of $150.0 million and $109.2 million from the issuance of our 6.375% Notes and a common
stock offering. During 2005, the outstanding balance under our bank credit facility declined
$154.7 million primarily due to the proceeds received from the 6.375% Notes being applied to our
bank debt. During 2004, we received proceeds of $98.1 million and $246.1 million from the issuance
of additional 7.375% Notes and two common stock offerings, respectively. During 2004, the
outstanding balance under our bank credit facility increased $245.7 million with $70.0 million
related to the Great Lakes transaction and the remaining increase the result of funding other
acquisitions. Also in 2004, we redeemed the remaining outstanding 6% Debentures for $11.6 million.
During 2003, the outstanding balance under our bank credit facility increased $62.4 million
primarily due to the December acquisition of producing properties in the Conger field. In 2003,
total debt declined $9.9 million. During 2003, we redeemed $84.8 million of the Trust Preferred
Securities and $69.3 million of the 8.75% Notes and issued $100.0 million of 7.375% Notes.
Capital Requirements
Our primary needs for cash are for exploration, development and acquisition of oil and gas
properties, repayment of principal and interest on outstanding debt and payment of dividends.
During 2005, $288.2 million of capital was expended primarily on drilling projects. Also in 2005,
$153.6 million was expended on acquisitions primarily to purchase producing properties. The
capital program, excluding acquisitions, was funded by net cash flow from operations and our
acquisitions were funded primarily with proceeds received from our common stock offering. The 2006
capital budget of $429.0 million, excluding acquisitions, is expected to be funded by cash flow
from operations. Development and exploration activities are highly discretionary, and, for the
foreseeable future, we expect such activities to be maintained at levels equal to or below internal
cash flow. To the extent capital requirements exceed internal cash flow, debt or equity may be
issued to fund these requirements. We currently believe we have sufficient liquidity and cash flow
to meet our obligations for the next twelve months; however, a drop in oil and gas prices or a
reduction in production or reserves could adversely affect our ability to fund capital expenditures
and meet our financial obligations. Also, our obligations may change due to acquisitions,
divestitures and continued growth. We may issue additional shares of stock, subordinated notes or
other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay
debt.
Cash Dividend Payments
The amount of future dividends is subject to declaration by the board of directors and depends
on earnings, capital expenditures and various other factors, such as restrictions under our bank
debt and the 7.375% Notes and the 6.375% Notes. In 2005, we paid $7.6 million in dividends to our
common stockholders ($0.02 per share in the fourth quarter and $0.0133 per share in the third,
second and first quarter). In 2004, we paid $3.2 million in dividends to our common stockholders
($0.0067 per share in the second and third quarter and $0.0133 per share in the fourth quarter).
In 2005, 2004
and 2003, we paid $2.2 million, $2.9 million and $803,000 in preferred stock dividends. As of
December 31, 2004, our 5.9% convertible preferred stock was converted to common stock.
Future Commitments
In addition to our capital expenditure program, we are committed to making cash payments in
the future on two types of contracts: note agreements and operating leases. As of December 31,
2005, we do not have any capital leases nor
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have we entered into any material long-term contracts
for drilling rigs or equipment. As of December 31, 2005, we do not have any off-balance sheet debt
or other such unrecorded obligations and we have not guaranteed the debt of any other party. The
table below provides estimates of the timing of future payments that we are obligated to make based
on agreements in place at December 31, 2005. In addition to the contractual obligations listed on
the table below, our balance sheet at December 31, 2005 reflects accrued interest payable on our
bank debt of $652,000 which is payable in January 2006. We expect to make annual interest payments
of $14.8 million per year on our $200.0 million of 7.375% Notes and payments of $9.6 million per
year on our $150.0 million of 6.375% Notes.
The following summarizes our contractual financial obligations at December 31, 2005 and their
future maturities. We expect to fund these contractual obligations with cash generated from
operating activities and refinancing proceeds.
| Payment due by period | ||||||||||||||||||||
| 2007 and | 2009 and | |||||||||||||||||||
| 2006 | 2008 | 2010 | Thereafter | Total | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
Bank debt due 2009 |
$ | — | $ | — | $ | 269,200 | (a) | $ | — | $ | 269,200 | |||||||||
7.375% senior subordinated notes due 2013 |
— | — | — | 200,000 | 200,000 | |||||||||||||||
6.375% senior subordinated notes due 2015 |
— | — | — | 150,000 | 150,000 | |||||||||||||||
Operating leases |
2,953 | 3,622 | 1,860 | — | 8,435 | |||||||||||||||
Seismic purchase |
400 | 400 | — | — | 800 | |||||||||||||||
Derivative obligations (b) |
160,101 | 70,948 | — | — | 231,049 | |||||||||||||||
Asset retirement obligation liability |
3,166 | 3,715 | 4,186 | 56,996 | 68,063 | |||||||||||||||
Total contractual obligations (c) |
$ | 166,620 | $ | 78,685 | $ | 275,246 | $ | 406,996 | $ | 927,547 | ||||||||||
| (a) | Due at termination date of our bank credit facility, which we expect to renew, but there is no assurance that can be accomplished. Interest paid on our bank credit facility would be approximately $14.5 million each year assuming no change in the interest rate or outstanding balance. | |
| (b) | Derivative obligations represent net open derivative contracts valued as of December 31, 2005. | |
| (c) | This table does not include the liability for the deferred compensation plans since these obligations will be funded with existing plan assets. |
Hedging – Oil and Gas Prices
We enter into hedging agreements to reduce the impact of oil and gas price volatility on our
operations. At December 31, 2005, swaps were in place covering 6.7 Bcf of gas at prices averaging
$6.60 per mcf and 0.1 million barrels of oil at prices averaging $35.00 per barrel. We also had
collars covering 82.8 Bcf of gas at weighted average floor and cap prices of $6.77 to $9.43 and 4.8
million barrels of oil at weighted average floor and cap prices of $45.21 to $56.58. The hedges’
fair value, represented by the estimated amount that would be realized or payable on termination,
based on a comparison of the contract price and a reference price, generally NYMEX, approximated a
pretax loss of $231.0 million at December 31, 2005. The contracts expire monthly through December
2008. Transaction gains and losses are determined monthly and are included as increases or
decreases on oil and gas revenue in the period the hedged production is sold. Realized hedging
losses of $171.1 million $100.1 million and $60.4 million were realized in 2005, 2004 and 2003,
respectively. Changes in the value of the ineffective portion of all open hedges are recognized in
earnings quarterly in other income. Unrealized effective gains and losses on hedging positions are recorded
at an estimate of fair value based on a comparison of the contract price and a reference price,
generally NYMEX, on our consolidated balance sheet as other comprehensive income, or OCI, a
component of stockholders’ equity. As of the fourth quarter of 2005, certain of our gas hedges no
longer qualify for hedge accounting due to the effect of recent volatility of gas prices on the
correlation between realized prices and hedge reference prices and were marked-to-market in the
amount of a gain of $10.9 million.
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At December 31, 2005, the following commodity derivative contracts were outstanding:
| Period | Contract Type | Volume Hedged | Average Hedge Price | |||
Natural gas |
||||||
2006 |
Swaps | 10,788 Mmbtu/day | $6.43 | |||
2006 |
Collars | 113,363 Mmbtu/day | $6.37 - $8.70 | |||
2007 |
Swaps | 7,500 Mmbtu/day | $6.86 | |||
2007 |
Collars | 83,500 Mmbtu/day | $6.93 - $9.63 | |||
2008 |
Collars | 30,000 Mmbtu/day | $7.81 - $11.65 | |||
Crude Oil |
||||||
2006 |
Swaps | 400 bbl/day | $35.00 | |||
2006 |
Collars | 6,864 bbl/day | $39.83 - $49.05 | |||
2007 |
Collars | 4,800 bbl/day | $51.42 - $61.87 | |||
2008 |
Collars | 1,500 bbl/day | $50.00 - $74.12 |
Interest Rates
At December 31, 2005, we had $616.1 million of debt outstanding. Of this amount, $350.0
million bears interest at a fixed rate averaging 7.0%. Bank debt totaling $269.2 million bears
interest at floating rates, which averaged 5.4% at year-end 2005, excluding interest rate swaps.
At December 31, 2005, we had fixed rate interest rate swap agreements on notional debt of $35.0
million. These swaps consist of two agreements at 1.8% which expire in June 2006. The 90-day
LIBOR rate on December 31, 2005 was 4.5%. A 1% increase in short-term interest rates on the
floating-rate debt outstanding at December 31, 2005 would cost us approximately $2.3 million in
additional annual interest, net of swaps.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements to enhance liquidity and
capital resource position, or for any other purpose.
Inflation and Changes in Prices
Our revenues, the value of our assets and our 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 and the costs to produce our reserves. Oil and gas prices are subject to significant
fluctuations that are beyond our ability to control or predict. Although certain of our costs and
expenses are affected by general inflation, inflation does not normally have a significant effect
on our business. In 2005 and 2004, we experienced an overall increase in drilling and service
costs compared to 2003, especially with regard to steel products. We expect further increases in
these costs for 2006.
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The following table indicates the average oil and gas prices received over the last five years
and quarterly for 2005, 2004 and 2003. Average price calculations exclude hedging gains and
losses. Oil is converted to natural gas equivalent at the rate of one
barrel equals six mcfe.
| Average Prices (Excluding Hedging) | ||||||||||||
| Equivalent | ||||||||||||
| Oil | Natural Gas | Mcf | ||||||||||
| (Per bbl) | (Per mcf) | (Per mcfe) | ||||||||||
Annual |
||||||||||||
2005 |
$ | 53.31 | $ | 7.98 | $ | 7.98 | ||||||
2004 |
39.25 | 5.79 | 5.80 | |||||||||
2003 |
28.42 | 5.10 | 4.94 | |||||||||
2002 |
23.34 | 3.02 | 3.16 | |||||||||
2001 |
23.34 | 3.91 | 3.87 | |||||||||
Quarterly |
||||||||||||
2005 |
||||||||||||
First |
$ | 47.09 | $ | 5.97 | $ | 6.24 | ||||||
Second |
48.79 | 6.42 | 6.65 | |||||||||
Third |
52.21 | 6.79 | 7.05 | |||||||||
Fourth |
56.39 | 11.30 | 10.57 | |||||||||
2004 |
||||||||||||
First |
$ | 32.15 | $ | 5.21 | $ | 5.10 | ||||||
Second |
35.87 | 5.56 | 5.49 | |||||||||
Third |
40.99 | 5.59 | 5.70 | |||||||||
Fourth |
45.85 | 6.66 | 6.72 | |||||||||
2003 |
||||||||||||
First |
$ | 31.44 | $ | 6.08 | $ | 5.79 | ||||||
Second |
26.71 | 5.15 | 4.90 | |||||||||
Third |
27.42 | 4.75 | 4.64 | |||||||||
Fourth |
28.27 | 4.51 | 4.49 | |||||||||
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Management’s Discussion of Critical Accounting Estimates
Our discussion and analysis of our financial condition and results of operations are based
upon consolidated financial statements which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of our financial statements
requires us to make estimates and assumptions that affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities at year-end and the reported
amounts of revenues and expenses during the year. Actual results could differ from the estimates
and assumptions used.
Certain accounting estimates are considered to be critical if a) the nature of the estimates
and assumptions is material due to the level of subjectivity and judgment necessary to account for
highly uncertain matters or the susceptibility of such matters to changes; and b) the impact of the
estimates and assumptions on financial condition or operating performance is material.
Property, Plant and Equipment
Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas
liquids and natural gas that geological and engineering data demonstrate with reasonable certainty
are recoverable from known reservoirs under existing economic and operating conditions. Proved
developed reserves are volumes expected to be recovered through existing wells with existing
equipment and operating methods. Although our engineers are knowledgeable of and follow the
guidelines for reserves established by the SEC, the estimation of reserves requires engineers to
make a significant number of assumptions based on professional judgment. Reserve estimates are
updated at least annually and consider recent production levels and other technical information.
Estimated reserves are often subject to future revisions, which could be substantial, based on the
availability of additional information, including: reservoir performance, new geological and
geophysical data, additional drilling, technological advancements, price and cost changes and other
economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in
production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause
adjustments in the depletion rates utilized by us. We cannot predict what reserve revisions may be
required in future periods. Reserve estimates are reviewed and approved by our Vice President of
Reservoir Engineering who reports directly to our Chief Operating Officer. In addition, because
substantially all of our proved reserves are pledged as collateral for our bank credit facility,
our estimates of proved reserves are reviewed twice annually by independent engineers on behalf of
each of the sixteen banks participating in our bank credit facility. To further ensure the
reliability of our reserve estimates, we engage independent petroleum consultants to review our
estimates of proved reserves.
The following table sets forth a summary of the percent of reserves which were reviewed by
independent petroleum consultants for each of the years ended 2005, 2004 and 2003.
| Audited (a) | ||||
| 2005 | 2004 | 2003 | ||
84% |
88% | 87% | ||
| (a) | Audited reserves are those reserves estimated by our employees and reviewed by an independent petroleum consultant. |
We utilize the successful efforts method to account for exploration and development
expenditures. Unsuccessful exploration drilling costs are expensed and can have a significant
effect on reported operating results. Successful exploration drilling costs and all development
costs are capitalized and systematically charged to expense using the units of production method
based on proved developed oil and gas reserves as estimated by our engineers and reviewed by
independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be
classified as proved are capitalized on our balance sheet if (a) the well has found a sufficient
quantity of reserves to justify its completion as a producing well and (b) we are making sufficient
progress assessing the reserves and the economic and operating viability of the project.
Otherwise, well costs are expensed if a determination as to whether proved reserves were found
cannot be made within one year following completion of drilling and these criteria are not met.
Proven property leasehold costs are charged to expense using the units of production method based
on total proved reserves. Unproved properties are assessed periodically (at least annually) and
impairments to value are charged to expense. The successful efforts method inherently relies upon
the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.
We adhere to the Statement of Financial Accounting Standards No. 19, “Financial Accounting and
Reporting by Oil and Gas Producing Companies,” for recognizing any impairment of capitalized costs
to unproved properties. The greatest portion of these costs generally relate to the acquisition of
leasehold costs. The costs are capitalized and periodically evaluated (at least annually) as to
recoverability, based on changes brought about by economic factors and potential shifts in
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business strategy employed by management. We consider a combination of time, geologic and engineering
factors to evaluate the need for impairment of these costs. Unproved properties had a net book
value of $28.6 million, $14.8 million and $12.2 million in 2005, 2004 and 2003, respectively.
Depletion rates are determined based on reserve quantity estimates and the capitalized costs
of producing properties. As the estimated reserves are adjusted, the depletion expense for a
property will change, assuming no change in production volumes or the capitalized costs. Estimated
reserves are used as the basis for calculating the expected future cash flows from a property,
which are used to determine whether that property may be impaired. Reserves are also used to
estimate the supplemental disclosure of the standardized measure of discounted future net cash
flows relating to oil and gas producing activities and reserve quantities in Note 16, “Supplemental
Information on Natural Gas and Oil Exploration, Development and Production Activities” to our
consolidated financial statements. Changes in the estimated reserves are considered in estimates
for accounting purposes and are reflected on a prospective basis.
We monitor our long-lived assets recorded in property, plant and equipment in our consolidated
balance sheet to ensure they are fairly presented. We must evaluate our 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 gas reserves
that will be produced from a field, the timing of future production, future production costs,
future abandonment costs, and future inflation. The need to test a property for impairment can be
based on several factors, including a significant reduction in sales prices for oil and/or gas,
unfavorable adjustment to reserves, physical damage to production equipment and facilities, a
change in costs, or other changes to contracts, environmental regulations or tax laws. All of
these factors must be considered when testing a property’s carrying value for impairment. We
cannot predict whether impairment charges may be required in the future.
Derivatives
We use commodity derivative contracts to manage our exposure to oil and gas price volatility.
We account for our commodity derivatives in accordance with SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities.” Earnings are affected by the ineffective portion
of a hedge contract (changes in realized prices that do not match the changes in the hedge price).
Ineffective gains or losses are recorded in other revenue while the hedge contract is open and may
increase or reverse until settlement of the contract. This may result in significant volatility to
current period income. For derivatives qualifying as hedges, the effective portion of any changes
in fair value is recognized in stockholders’ equity as OCI, and then reclassified to earnings, in
oil and gas revenue, when the transaction is consummated. This may result in significant
volatility in stockholders’ equity. The fair value of open hedging contracts is an estimated
amount that could be realized upon termination. As of the fourth quarter of 2005, certain of our
gas hedges no longer qualified for hedge accounting due to the volatility of gas prices and their
effect on our basis differentials and were marked-to-market.
The commodity derivatives we use include commodity collars and swaps. While there is a risk
that the financial benefit of rising prices may not be captured, we believe the benefits of stable
and predictable cash flow are more important. Among these benefits are a more efficient
utilization of existing personnel and planning for future staff additions, the flexibility to enter
into long-term projects requiring substantial committed capital, smoother and more efficient
execution of our ongoing development drilling and production enhancement programs, more consistent
returns on invested capital, and better access to bank and other credit markets. We also have two
interest rate swap agreements to help protect against the volatility of variable interest rates
under our bank credit facility.
Asset Retirement Obligations
We have significant obligations to remove tangible equipment and restore land or seabed at the
end of oil and gas production operations. Removal and restoration obligations are primarily
associated with plugging and abandoning wells and removing and disposing of offshore oil and gas
platforms. Estimating the future asset removal costs is difficult and requires us to make
estimates and judgments because most of the removal obligations are many years in the future and
contracts and regulations often have vague descriptions of what constitutes removal. Asset removal
technologies and costs are constantly changing, as are regulatory, political, environmental, safety
and public relations considerations.
Inherent in the fair value calculation are numerous assumptions and judgments including the
ultimate retirement costs, inflation factors, credit adjusted discount rates, timing of retirement,
and changes in the legal, regulatory, environmental and political environments. To the extent
future revisions to these assumptions impact the present value of the existing asset retirement
obligation, or ARO liability, a corresponding adjustment is made to the oil and gas property
balance. In addition, increases in the discounted ARO liability resulting from the passage of time
are reflected as accretion expense, a component of DD&A, in our consolidated statement of
operations.
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Deferred Taxes
We are subject to income and other taxes in all areas in which we operate. When recording
income tax expense, certain estimates are required because income tax returns are generally filed
many months after the close of a calendar year, tax returns are subject to audit which can take
years to complete and future events often impact the timing of when income tax expenses and
benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards
and other deductible differences. We routinely evaluate deferred tax assets to determine the
likelihood of realization. A valuation allowance is recognized on deferred tax assets when we
believe that certain of these assets are not likely to be realized.
In determining deferred tax liabilities, accounting rules require OCI to be considered, even
though such income (loss) has not yet been earned. At year-end 2004, deferred tax liabilities
exceeded deferred tax assets by $91.4 million with $26.0 million of deferred tax assets related to
unrealized deferred hedging losses included in OCI. At year-end 2005, deferred tax liabilities
exceeded deferred tax assets by $113.1 million, with $85.5 million of deferred tax assets related
to unrealized deferred hedging losses included in OCI. Based on our expectations regarding future
profitability and market prices for oil and gas, the unrealized hedging losses are expected to be
offset in the future by higher realization on our production and no year-end 2005 valuation
allowance was deemed necessary.
We may be challenged by taxing authorities over the amount and/or timing of recognition of
revenues and deductions in our various income tax returns. Although we believe that we have
adequately provided for all taxes, gains or losses could occur in the future due to changes in
estimates or resolution of outstanding tax matters.
Contingent Liabilities
A provision for legal, environmental and other contingent matters is charged to expense when
the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often
required to determine when expenses should be recorded for legal, environmental and contingent
matters. In addition, we often must estimate the amount of such losses. In many cases, our
judgment is based on the input of our legal advisors and on the interpretation of laws and
regulations, which can be interpreted differently by regulators and/or the courts. We monitor
known and potential legal, environmental and other contingent matters and make our best estimate of
when to record losses for these matters based on available information. Although we continue to
monitor all contingencies closely, particularly our outstanding litigation, we currently have no
material accruals for contingent liabilities.
Accounting Standards Not Yet Adopted
In December 2004, the Financial Accounting Standards Board, or FASB, issued FASB Statements
No. 123 (revised 2004) “Share-Based Payment,” or SFAS 123(R), which is a revision of FASB Statement
No. 123, Accounting for Stock-Based Compensation. SFAS 123(R) supersedes APB opinion No. 25,
Accounting for Stock Issued to employees, and amends FASB Statement No. 95, Statement of Cash
Flows. Generally, the approach in SFAS 123(R) is similar to the approach described in Statement
123. However, SFAS 123(R) requires all share-based payments to employees, including grants of
employee stock options, to be recognized in the income statements based on their fair values rather
than pro forma footnote disclosure.
SFAS 123(R) permits companies to adopt its requirements using either a “modified prospective”
method, or a “modified retrospective” method. Under the “modified prospective” method,
compensation cost is recognized in the financial statements beginning with the effective date,
based on the requirements of SFAS 123(R) for all share-based payments granted after that date, and
based on the requirements of SFAS 123 for all unvested awards granted prior to the effective date
of SFAS 123(R). Under the “modified retrospective” method, the requirements are the same as under
the “modified prospective” method, but also permits entities to restate financial statements of
previous periods based on pro forma disclosures made in accordance with SFAS 123. We currently
anticipate we will adopt the provisions of SFAS 123(R) using the modified prospective method on
January 1, 2006.
We currently utilize a standard option pricing model (i.e., Black-Scholes) to measure the fair
value of stock options and stock appreciation rights granted. While SFAS 123(R) permits entities
to continue to use such a model, the standard also permits the use of a “lattice” binomial model.
We currently anticipate we will continue using the standard option pricing model (i.e. Black
Sholes) upon adoption of SFAS 123(R).
The adoption of SFAS 123(R) will have a significant impact on our results of operations,
although it will have no impact on our overall financial position. The impact of adoption of
Statement 123(R) cannot be predicted at this time because it will depend on levels of share-based
payments granted in the future. However, had we adopted Statement 123(R)
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in prior periods, the
impact of that standard would have approximated the impact of Statement 123 as described in the
disclosure of pro forma net income and earnings per share as shown in Note 2 “Stock Based
Compensation” in our consolidated financial statements. Statement 123(R) also requires the
benefits of tax deductions in excess of recognized compensation cost to be reported as a financing
cash flow, rather than as an operating cash flow as required under current literature. This
requirement will reduce net operating cash flows and increase net financing cash flows in periods
after adoption, to the extent of associated tax benefits that may be realized in the future. While
we cannot estimate what those amounts will be in the future (because they depend on, among other
things, when employees exercise stock options), there was no impact on our net operating cash flows
in 2005, 2004 or 2003, respectively, as we were not able to recognize a cash benefit due to our net
operating loss carryforward tax position.
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting
Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statements No. 3” or
SFAS 154. SFAS 154 provides guidance on the accounting for a reporting of accounting changes and
error corrections. It establishes, unless impracticable, retrospective application as the required
method for reporting a change in accounting principle in the absence of explicit transition
requirements specific to SFAS 154. The provisions of SFAS 154 shall be effective for accounting
changes and corrections of errors made in fiscal years beginning after December 15, 2005.
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ITEM 7A. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative
and qualitative information about our 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 we view and manage our ongoing market-risk exposure. All of our market-risk sensitive
instruments were entered into for purposes other than trading. All accounts are US dollar
denominated.
Market Risk
Our major market risk is exposure to oil and gas prices. Realized prices are primarily driven
by worldwide prices for oil and spot market prices for North American gas production. Oil and gas
prices have been volatile and unpredictable for many years.
Commodity Price Risk
We periodically enter into hedging arrangements with respect to our oil and gas production.
Hedging is intended to reduce the impact of oil and gas price fluctuations. Certain of our hedges
are swaps where we receive a fixed price for our production and pay market prices to the
counterparty. Our hedging program also includes collars which assume a minimum floor price and a
predetermined ceiling price. In times of increasing price volatility, we may experience losses
from our hedging arrangements and increased basis differentials at the delivery points where we
market our production. Widening basis differentials occur when the physical delivery market prices
do not increase proportionately to the increased prices in the financial trading markets. Realized
gains and losses are recognized in oil and gas revenues when the associated production occurs.
Gains or losses on open contracts are recorded either in current period income or other
comprehensive income, or OCI. Generally, derivative losses occur when market prices increase,
which are offset by gains on the underlying physical commodity transaction. Conversely, derivative
gains occur when market prices decrease, which are offset by losses on the underlying commodity
transaction. Ineffective gains and losses are recognized in earnings as a component of other
revenue. We do not enter into derivative instruments for trading purposes.
As of December 31, 2005, we had oil and gas swaps in place covering 6.7 billion Bcf of gas and
0.1 million barrels of oil. We also had collars covering 82.8 Bcf of gas and 4.8 million barrels
of oil. These contracts expire monthly through December 2008. The fair value, represented by the
estimated amount that would be realized upon immediate liquidation as of December 31, 2005,
approximated a net pre-tax loss of $231.0 million. Gains or losses realized on hedging
transactions are determined monthly based upon the difference between contract price received by us
for the sale of our hedged production and the hedge price, generally closing prices on the NYMEX.
These gains and losses are included as increases or decreases to oil and gas revenues in the period
the hedged production is sold. In 2005, 2004 and 2003, pre-tax losses were realized in the amount
of $171.1 million, $100.1 million and $60.4 million, respectively, relating to our hedges. Losses
due to commodity hedge ineffectiveness are recognized in earnings in other revenues in our
consolidated statement of operations. The ineffective portion of hedges recorded was a loss of
$3.4 million in 2005, a gain of $712,000 in 2004 and a loss of $1.2 million in 2003. As of the
fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the
volatility in gas prices and its effect on our basis differentials and were marked to market as a
gain of $10.9 million.
At December 31, 2005, the following commodity derivative contracts were outstanding:
| Period | Contract Type | Volume Hedged | Average Hedge Price | ||||
Natural gas
|
|||||||
2006 |
Swaps | 10,788 Mmbtu/day | $6.43 | ||||
2006 |
Collars | 113,363 Mmbtu/day | $6.37 - $8.70 | ||||
2007 |
Swaps | 7,500 Mmbtu/day | $6.86 | ||||
2007 |
Collars | 83,500 Mmbtu/day | $6.93 - $9.63 | ||||
2008 |
Collars | 30,000 Mmbtu/day | $7.81 - $11.65 | ||||
Crude Oil
|
|||||||
2006 |
Swaps | 400 bbl/day | $35.00 | ||||
2006 |
Collars | 6,864 bbl/day | $39.83 - $49.05 | ||||
2007 |
Collars | 4,800 bbl/day | $51.42 - $61.87 | ||||
2008 |
Collars | 1,500 bbl/day | $50.00 - $74.12 |
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In 2005, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging
transactions, would have reduced revenue by $70.0 million. If oil and gas futures prices at
December 31, 2005 had declined by 10%, the unrealized hedging loss at that date would have
decreased $118.2 million.
Interest Rate Risk
At December 31, 2005, we had $616.1 million of debt outstanding. Of this amount, $350.0
million bears interest at
a fixed rate averaging 7.0%. Bank debt totaling $269.2 million bears interest at floating rates,
excluding interest rate swaps, which averaged 5.4% on that date. At December 31, 2005, we had
fixed rate interest rate swap agreements totaling $35.0 million. These swaps consist of two
agreements at 1.8% which expire in June 2006. On December 31, 2005, the 90-day LIBOR rate was
4.5%. A 1% increase in short-term interest rates on the floating-rate debt outstanding (net of
amounts fixed through hedging transactions) at December 31, 2005 would cost us approximately $2.3
million in additional annual interest rates, net of swaps.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
For financial statements required by Item 8, see Item 15 in Part IV of this report.
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ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures. As of the end of the period covered by this report, we
carried out an evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our
disclosure controls and procedures (as defined in 13a-15(e) of the Securities Exchange Act of 1934,
or the Exchange Act). Based on that evaluation, our Chief Executive Officer and our Chief
Financial Officer concluded that our disclosure controls and procedures are effective.
Management’s Annual Report on Internal Control over Financial Reporting and Attestation Report
of Registered Public Accounting Firm. Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002,
we have included a report of management’s assessment of the design and effectiveness of its
internal controls as part of this Annual Report on Form 10-K for the fiscal year ended December 31,
2005. Ernst & Young, LLP, our registered public accountants, also attested to, and reported on,
management’s assessment of the effectiveness of internal control over financial reporting.
Management’s report and the independent public accounting firms attestation report are included in
our 2005 Financial Statements in Item 15 under the captions “Management’s Report on Internal
Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm”
and are incorporated herein by reference.
Changes in Internal Control over Financial Reporting. As of the end of the period covered by
this report, we carried out an evaluation, under the supervision and with the participation of our
Chief Executive Officer and Chief Financial Officer, of our internal control over financial
reporting to determine whether any changes occurred during the fourth quarter of 2005 that have
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting. Based on that evaluation, there were no changes in our internal control over
financial reporting or in other factors that have materially affected or are reasonably likely to
materially affect our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
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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 2005 annual stockholders’
meeting. Officers are appointed by our board of directors.
| Office | ||||||
| Held | ||||||
| Age | Since | Position | ||||
Charles L. Blackburn |
78 | 2003 | Director, Chairman of the Board | |||
Anthony V. Dub |
56 | 1995 | Director | |||
V. Richard Eales |
69 | 2001 | Director | |||
Allen Finkelson |
59 | 1994 | Director | |||
Jonathan S. Linker |
57 | 2002 | Director | |||
Kevin S. McCarthy |
46 | 2005 | Director | |||
John H. Pinkerton |
51 | 1990 | Director, President, Chief Executive Officer | |||
Jeffrey L. Ventura |
48 | 2003 | Director, Executive Vice President — Chief Operating Officer | |||
Steven L. Grose |
57 | 2005 | Senior Vice President — Appalachia | |||
Roger S. Manny |
48 | 2003 | Senior Vice President and Chief Financial Officer | |||
Chad L. Stephens |
50 | 1990 | Senior Vice President — Corporate Development | |||
Rodney L. Waller |
56 | 1999 | Senior Vice President, Chief Compliance Officer and Corporate Secretary | |||
Mark D. Whitley |
54 | 2005 | Senior Vice President — Permian Business Unit and Engineering Technology |
Charles L. Blackburn was elected as a director in April 2003 and appointed as the
non-executive Chairman of the Board. Mr. Blackburn has more than 40 years experience in oil and
gas exploration and production serving in several executive and board positions. Previously, he
served as Chairman and Chief Executive Officer of Maxus Energy Corporation from 1987 until that
company’s sale to YPF Socieded Anonima in 1995. Maxus was the oil and gas producer which remained
after Diamond Shamrock Corporation’s spin-off of its refining and marketing operations. Mr.
Blackburn joined Diamond Shamrock in 1986 as President of their exploration and production
subsidiary. From 1952 through 1986, Mr. Blackburn was with Shell Oil Company, serving as Director
and Executive Vice President for exploration and production for the final ten years of that period.
Mr. Blackburn has previously served on the Boards of Anderson Clayton and Co. (1978-1986), King
Ranch Corp. (1987-1988), Penrod Drilling Co. (1988-1991), Landmark Graphics Corp. (1992-1996) and
Lone Star Technologies, Inc. (1991-2001). Currently, Mr. Blackburn also serves as an advisory
director to the oil and gas loan committee of Guaranty Bank. Mr. Blackburn received his Bachelor
of Science degree in Engineering Physics 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. Prior to forming Indigo Capital in 1997, he served as
an officer of Credit Suisse First Boston (“CSFB”). Mr. Dub joined CSFB in 1971 and was named a
Managing Director in 1981. Mr. Dub led a number of departments during his 27 year career at CSFB
including the Investment Banking Department. After leaving CSFB, Mr. Dub became Vice Chairman and
a director of Capital IQ, Inc. until its sale to Standard and Poor’s in 2004. Capital IQ is the
leader in helping organizations capitalize on synergistic integration of market intelligence,
institutional knowledge and relationships. Mr. Dub received a Bachelor of Arts, magna cum laude,
from Princeton University.
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 retired, having been a financial
consultant serving energy and information technology businesses from 1999 through 2002. 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.
Allen Finkelson became a director in 1994. Mr. Finkelson has been a partner at Cravath,
Swaine & Moore LLP since 1977, with the exception of the period 1983 through 1985, when he was a
managing director of Lehman Brothers Kuhn
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Loeb Incorporated. Mr. Finkelson joined Cravath, Swaine & Moore, LLP in 1971. Mr. Finkelson earned a
Bachelor of Arts from St. Lawrence University and a J.D. from Columbia University School of Law.
Jonathan S. Linker became a director in 2002. Mr. Linker previously served as a director of
Range from 1998 to 2000. He has been active in the energy business since 1972. Mr. Linker began
working with First Reserve Corporation in 1988 and was a Managing Director of the firm from 1996
until July 2001. Mr. Linker is currently President of Houston Energy Advisors LLC, a registered
investment advisor providing management and investment services to two private equity funds. Mr.
Linker has been President and a director of IDC Energy Corporation since 1987, a director and
officer of Sunset Production Corporation since 1991 serving currently as Chairman, and Manager of
Shelby Resources Inc., all small, privately-owned exploration and production companies. Mr. Linker
received a Bachelor of Arts in Geology from Amherst College, a Masters in Geology from Harvard
University and an MBA from Harvard University’s Graduate School of Business Administration.
Kevin S. McCarthy became a director in 2005. Mr. McCarthy is Chairman, Chief Executive
Officer and President of Kayne Anderson MLP Investment Company and Kayne Anderson Energy Total
Return Fund, Inc. which are each NYSE listed closed-end investment companies. Mr. McCarthy joined
Kayne Anderson Capital Advisors as a Senior Managing Director in June 2004 from UBS Securities LLC
where he was global head of energy investment banking. In this role, he had senior responsibility
for all of UBS’ energy investment banking activities, including direct responsibilities for
securities underwriting and mergers and acquisitions in the energy industry. From 1995 to 2000,
Mr. McCarthy led the energy investment banking activities of Dean Witter Reynolds and then
PaineWebber Incorporated. He began his investment banking career in 1984. He is also on the board
of directors of Clearwater Natural Resources, L.P. He earned a Bachelor of Arts in Economics and
Geology from Amherst College and an MBA in Finance from the University of Pennsylvania’s Wharton
School.
John H. Pinkerton,
President, Chief Executive Officer and a director, became a director in
1988. He joined Range as President in 1990 and was appointed Chief Executive Officer in 1992.
Previously, Mr. Pinkerton was Senior Vice President of Snyder Oil Corporation (“SOCO”). Prior to
joining SOCO in 1980, Mr. Pinkerton was with Arthur Andersen. Mr. Pinkerton received his Bachelor
of Arts in Business Administration from Texas Christian University
and a masters degree from the University of Texas at Arlington.
Jeffrey L. Ventura, Executive Vice President — Chief Operating Officer, joined Range in 2003
and became a director in 2005. Previously, Mr. Ventura served as President and Chief Operating
Officer of Matador Petroleum Corporation which he joined in 1997. Prior to 1997, Mr. Ventura spent
eight years at Maxus Energy Corporation where he managed various engineering, exploration and
development operations and was responsible for coordination of engineering technology. Previously,
Mr. Ventura was with Tenneco, where he held various engineering and operating positions. Mr.
Ventura holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering from
Pennsylvania State University.
Steven L. Grose, Senior Vice President — Appalachia, joined Range in 1980. Previously, Mr.
Grose was employed by Halliburton Services, Inc. from 1971 until 1978. Upon the formation of Great
Lakes Energy Partners L.L.C. 1999, Mr. Grose was placed in charge of all operations of the joint
venture. Mr. Grose is a member of the Society of Petroleum Engineers and is a past president of
The Ohio Oil and Gas Association. Mr. Grose received his Bachelor of Science degree in Petroleum
Engineering from Marietta College.
Roger S. Manny, Senior Vice President and Chief Financial Officer, joined Range in 2003.
Previously, Mr. Manny served as Executive Vice President and Chief Financial Officer of Matador
Petroleum Corporation since 1998. Prior to 1998, Mr. Manny spent 18 years at Bank of America and
its predecessors where he served as Senior Vice President in the energy group. Mr. Manny holds a
Bachelor of Business Administration degree from the University of Houston and a Masters of Business
Administration from Houston Baptist University.
Chad L. Stephens, Senior Vice President — Corporate Development, joined Range in 1990. Prior
to 2002, Mr. Stephens held the position of Senior Vice President —Southwest. Previously, Mr.
Stephens was with Duer Wagner & Co., an independent oil and gas producer for approximately two
years. Prior to that, 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 in Finance and Land Management from the University of Texas.
Rodney L. Waller, Senior Vice President and Corporate Secretary, joined Range in 1999. Since
joining Range, Mr. Waller has held the position of Senior Vice President and Corporate Secretary.
Previously, Mr. Waller was Senior Vice President of SOCO, now part of Devon Energy Corporation.
Before joining SOCO, Mr. Waller was with Arthur Andersen. Mr. Waller is a certified public
accountant and petroleum land man. Mr. Waller served as a director of Range from 1988 to 1994.
Mr. Waller received a Bachelor of Arts degree in Accounting from Harding University.
42
Table of Contents
Mark D. Whitley, Senior Vice President — Permian Business Unit and Engineering Technology,
joined Range in 2005. Previously, he served as Vice President — Operations with Quicksilver
Resources for two years. Prior to that, he served as Production/Operation Manager for Devon
Energy, following the Devon/Mitchell merger. From 1982 to 2002, Mr. Whitley held a variety of
technical and managerial roles with Mitchell Energy. Notably, he led the team of engineers at
Mitchell Energy who applied new stimulation techniques to unlock the shale gas potential in the
Fort Worth Basin. Previous positions included serving as a production and reservoir engineer with
Shell Oil. He holds a Bachelor’s degree in Chemical Engineering from Worchester Polytechnic
Institute and a Master’s degree in Chemical Engineering from the University of Kentucky.
Code of Ethics. We have adopted a Code of Ethics that applies to our principal
executive officers, principal financial officer, principal accounting officer, or persons
performing similar functions. A copy is available on our website, www.rangeresources.com. We
intend to disclose any amendments to or waivers of the Code of Ethics on behalf of our Chief
Executive Officer, Chief Financial Officer, Controller and persons performing similar functions on
our website at www.rangeresources.com, under the Corporate Governance caption, promptly following
the date of such amendment or waiver.
Board of Directors Committees
See “Governance of the Company” in the Range Resources Corporation Proxy Statement for the
Annual Meeting of Stockholders’ of Range Resources to be held May 24, 2006 which is incorporated
herein by reference.
Section 16(a) Beneficial Ownership Reporting Compliance
See “Section 16(a) Beneficial Ownership Reporting Compliance” in the Range Resources Corporate
Proxy Statement for the Annual Meeting of Stockholders’ of Range Resources to be held May 24, 2006
which is incorporated herein by reference.
ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
The information required by Item 11 of Form 10-K is incorporated herein by reference to such
information as set forth in our definitive Proxy Statement for the 2006 Annual Meeting of
Stockholders to be held May 24, 2006.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by Item 12 of Form 10-K is incorporated herein by reference to such
information as set forth in our definitive proxy statement for the 2006 Annual Meeting of
Stockholders to be held on May 24, 2006.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by Item 14 of Form 10-K is incorporated herein by reference to such
information as set forth in our definitive proxy statement for the 2006 Annual Meeting of
Stockholders to be held on May 24, 2006.
43
Table of Contents
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as part of the report
| 1. Financial Statements: | ||||
| PAGE | ||||
Index to Financial Statements |
F- 1 | |||
Management’s Report on Internal Controls Over Financial Reporting |
F- 2 | |||
Report of Independent Registered Public Accounting Firm — Internal Control Over Financial Reporting |
F- 3 | |||
Report of Independent Registered Public Accounting Firm — Financial Statements |
F- 4 | |||
Consolidated Balance Sheet as of December 31, 2005 and 2004 |
F- 5 | |||
Consolidated Statement of Operations for the Years Ended December 31, 2005, 2004 and 2003 |
F- 6 | |||
Consolidated Statement of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003 |
F- 7 | |||
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003 |
F- 8 | |||
Consolidated Statement of Comprehensive Income (Loss) for the Years Ended December 31, 2005, 2004 and 2003 |
F- 9 | |||
Notes to Consolidated Financial Statements |
F-10 | |||
Quarterly Financial Information (Unaudited) |
F-27 | |||
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (unaudited) |
F-28 | |||
All other schedules are omitted because they are not applicable, not required, or because the
required information is included in the financial statements or related notes.
2. Exhibits:
(a) See Index of Exhibits on page F-38 for a description of the exhibits filed as a
part of this report.
44
Table of Contents
GLOSSARY
The terms defined in this glossary are used in this report.
bbl. One stock tank barrel, or 42 U.S. gallons liquid volumes, used herein in reference to crude
oil or other liquid hydrocarbons.
bcf. One billion cubic feet of gas.
bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel
of oil or NGL, which reflects the relative energy content.
development well. A well drilled within the proved area of an oil or natural gas reservoir to the
depth of a stratigraphic horizon known to be productive.
dry hole. A well found to be incapable of producing oil or natural gas in sufficient economic
quantities.
exploratory well. A well drilled to find oil or gas in an unproved area, to find a new reservoir
in an existing field 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 many debt transactions.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
mcf. One thousand cubic feet of gas.
mcf per day. One thousand cubic feet of gas per day.
mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each
barrel of oil or NGL, which reflects relative energy content.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
Mmbtu. One million British thermal units. A British thermal unit is the heat required to raise
the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.
Mmcf. One million cubic feet of gas.
Mmcfe. One million cubic feet of gas equivalents.
NGLs. Natural gas liquids.
net acres or net wells. The sum of the fractional working interests owned in gross acres or gross
wells.
present value (PV). The present value of future net cash flows, using a 10% discount rate, 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). The after
tax present value is the Standardized Measure.
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.
45
Table of Contents
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 economics 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 an existing well bore in another formation from that
in which the well has been previously completed.
reserve life index. Proved reserves at a point in time divided by the then production rate (annual
or quarterly).
royalty acreage. Acreage represented by a fee mineral or royalty interest which entitles the owner
to receive free and clear of all production costs a specified portion of the oil and gas produced
or a specified portion of the value of such 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.
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.
46
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
Dated: February 22, 2006 |
||||
| RANGE RESOURCES CORPORATION | ||||
| By: | /s/ John H. Pinkerton | |||
| John H. Pinkerton | ||||
| President and Chief Executive Officer | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated.
/s/ Charles L. Blackburn
|
Chairman of the Board | February 22, 2006 | ||
/s/ John H. Pinkerton
|
President, Chief Executive Officer and Director | February 22, 2006 | ||
/s/ Jeffrey L. Ventura
|
Executive Vice President and Director | February 22, 2006 | ||
/s/ Roger S. Manny
|
Chief Financial and Accounting Officer | February 22, 2006 | ||
/s/ Anthony V. Dub
|
Director | February 22, 2006 | ||
/s/ V. Richard Eales
|
Director | February 22, 2006 | ||
/s/ Allen Finkelson
|
Director | February 22, 2006 | ||
/s/ Jonathan S. Linker
|
Director | February 22, 2006 | ||
/s/ Kevin S. McCarthy
|
Director | February 22, 2006 | ||
47
RANGE RESOURCES CORPORATION
INDEX TO FINANCIAL STATEMENTS
| Page | ||
| Number | ||
| F- 2 | ||
| F- 3 | ||
| F- 4 | ||
| F- 5 | ||
| F- 6 | ||
| F- 7 | ||
| F- 8 | ||
| F- 9 | ||
| F-10 | ||
| F-27 | ||
| F-28 |
F-1
Table of Contents
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
Range Resources Corporation:
Range Resources Corporation:
Management is responsible for establishing and maintaining adequate internal control over
financial reporting (as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934). Our
internal control over financial reporting is designed to provide reasonable assurance to management
and board of directors regarding the preparation and fair presentation of published financial
statements. Because of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement preparation and presentation.
Management assessed the effectiveness of our internal control over financial reporting as of
December 31, 2005. In making this assessment, management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control –
Integrated Framework. Based on our assessment, we believe that, as of December 31, 2005, our
internal control over financial reporting is effective based on those criteria.
Management’s assessment of the effectiveness of internal control over financial reporting as
of December 31, 2005, has been audited by Ernst & Young, LLP, an independent registered public
accounting firm which also audited our consolidated financial statements. Ernst & Young’s
attestation report on management’s assessment of our internal control over financial reporting is
included under the heading “Report of Independent Registered Public Accounting Firm on Internal
Control Over Financial Reporting.”
By:
|
/s/ John H. Pinkerton | By: | /s/ Roger S. Manny | |||||
| John H. Pinkerton | Roger S. Manny | |||||||
| President and Chief Executive Officer | Senior Vice President and Chief Financial Officer |
Fort Worth, Texas
February 22, 2006
February 22, 2006
F-2
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
Range Resources Corporation:
Range Resources Corporation:
We have audited management’s assessment, included in the accompanying Management’s Report on
Internal Control Over Financial Reporting, that Range Resources Corporation and subsidiaries (the
“Company”) maintained effective internal control over financial reporting as of December 31, 2005,
based on criteria established in Internal Control – Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management
is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting. Our responsibility
is to express an opinion on management’s assessment and an opinion on the effectiveness of the
Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management’s assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinion.
A company’s internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company’s assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to future periods
are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
In our opinion,
management’s assessment that Range Resources Corporation and subsidiaries maintained effective internal control
over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based
on the COSO criteria. Also, in our opinion, Range Resources Corporation and subsidiaries maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2005, based on the COSO
criteria.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated balance sheets of Range Resources Corporation and
subsidiaries as of December 31, 2005 and 2004 and the related consolidated statements of
operations, stockholders’ equity, comprehensive income (loss) and cash flows for each of the three
years in the period ended December 31, 2005 and our report dated February 21, 2006
expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
February 21, 2006
February 21, 2006
F-3
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board
of Directors and Stockholders of
Range Resources Corporation:
Range Resources Corporation:
We have audited the accompanying consolidated balance sheets of Range Resources Corporation
and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated
statements of operations, stockholders’ equity, comprehensive income (loss) and cash flows for each
of the three years in the period ended December 31, 2005. These consolidated financial statements
are the responsibility of the Company’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 the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the consolidated 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 consolidated financial position of Range Resources Corporation and
subsidiaries at December 31, 2005 and 2004, and the consolidated results of their operations and
their cash flows for each of the three years in the period ended December 31, 2005, in conformity
with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated February 21, 2006 expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
February 21, 2006
February 21, 2006
F-4
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE
SHEET
(In thousands)
(In thousands)
| December 31, | ||||||||
| Assets | 2005 | 2004 | ||||||
Current assets |
||||||||
Cash and equivalents |
$ | 4,750 | $ | 18,382 | ||||
Accounts receivable, less allowance for doubtful accounts of $624 and $967 |
128,532 | 81,942 | ||||||
Unrealized derivative gain |
425 | 534 | ||||||
Deferred tax asset |
61,677 | 26,310 | ||||||
Inventory and other |
12,593 | 9,168 | ||||||
Total current assets |
207,977 | 136,336 | ||||||
Unrealized derivative gain |
— | 206 | ||||||
Oil and gas properties, successful efforts method |
2,548,090 | 2,097,026 | ||||||
Accumulated depletion and depreciation |
(806,908 | ) | (694,667 | ) | ||||
| 1,741,182 | 1,402,359 | |||||||
Transportation and field assets |
65,210 | 59,423 | ||||||
Accumulated depreciation and amortization |
(25,966 | ) | (22,141 | ) | ||||
| 39,244 | 37,282 | |||||||
Other assets |
30,582 | 19,223 | ||||||
Total assets |
$ | 2,018,985 | $ | 1,595,406 | ||||
Liabilities |
||||||||
Current liabilities
|
||||||||
Accounts payable |
$ | 119,907 | $ | 78,723 | ||||
Asset retirement obligations |
3,166 | 6,822 | ||||||
Accrued liabilities |
28,372 | 23,292 | ||||||
Accrued interest |
10,214 | 7,320 | ||||||
Unrealized derivative loss |
160,101 | 61,005 | ||||||
Total current liabilities |
321,760 | 177,162 | ||||||
Bank debt |
269,200 | 423,900 | ||||||
Subordinated notes |
346,948 | 196,656 | ||||||
Deferred tax, net |
174,817 | 117,713 | ||||||
Unrealized derivative loss |
70,948 | 10,926 | ||||||
Deferred compensation liability |
73,492 | 38,799 | ||||||
Asset retirement obligations |
64,897 | 63,905 | ||||||
Long-term capital lease obligation |
— | 5 | ||||||
Commitments and contingencies |
— | — | ||||||
Stockholders’ Equity |
||||||||
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding |
— | — | ||||||
Common stock, $.01 par, 250,000,000 shares authorized,
129,913,046 and 121,829,027 issued, respectively |
1,299 | 1,218 | ||||||
Common stock held in treasury — 5,826 at December 31, 2005 |
(81 | ) | — | |||||
Capital in excess of par value |
845,519 | 707,463 | ||||||
Retained earnings (deficit) |
13,800 | (89,597 | ) | |||||
Common stock held by employee benefit trust, 1,971,605 and 2,162,626
shares, respectively, at cost |
(11,852 | ) | (8,186 | ) | ||||
Deferred compensation |
(4,635 | ) | (1,257 | ) | ||||
Accumulated other comprehensive income (loss) |
(147,127 | ) | (43,301 | ) | ||||
Total stockholders’ equity |
696,923 | 566,340 | ||||||
Total liabilities and stockholders’ equity |
$ | 2,018,985 | $ | 1,595,406 | ||||
See accompanying notes.
F-5
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share data)
(In thousands, except per share data)
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Revenues |
||||||||||||
Oil and gas sales |
$ | 525,074 | $ | 315,703 | $ | 226,402 | ||||||
Transportation and gathering |
2,578 | 2,202 | 3,509 | |||||||||
Gain (loss) on retirement of securities |
— | (39 | ) | 18,526 | ||||||||
Mark-to-market on oil and gas derivatives |
10,868 | — | — | |||||||||
Other |
(2,563 | ) | 2,841 | (2,670 | ) | |||||||
Total revenue |
535,957 | 320,707 | 245,767 | |||||||||
Costs and expenses |
||||||||||||
Direct operating |
66,632 | 46,308 | 36,423 | |||||||||
Production and ad valorem taxes |
31,516 | 20,504 | 12,894 | |||||||||
Exploration |
29,437 | 21,219 | 13,946 | |||||||||
General and administrative |
29,432 | 20,634 | 17,818 | |||||||||
Non-cash stock compensation |
35,250 | 19,176 | 6,559 | |||||||||
Interest expense and dividends on trust preferred |
38,797 | 23,119 | 22,165 | |||||||||
Depletion, depreciation and amortization |
127,514 | 102,971 | 86,549 | |||||||||
Total costs and expenses |
358,578 | 253,931 | 196,354 | |||||||||
Income before income taxes and accounting change |
177,379 | 66,776 | 49,413 | |||||||||
Income tax (benefit)
|
||||||||||||
Current |
1,071 | (245 | ) | 170 | ||||||||
Deferred |
65,297 | 24,790 | 18,319 | |||||||||
| 66,368 | 24,545 | 18,489 | ||||||||||
Income before cumulative effect of changes in
accounting principles |
111,011 | 42,231 | 30,924 | |||||||||
Cumulative effect of changes in accounting principles,
net of taxes |
— | — | 4,491 | |||||||||
Net income |
111,011 | 42,231 | 35,415 | |||||||||
Preferred dividends |
— | (5,163 | ) | (803 | ) | |||||||
Net income available to common stockholders |
$ | 111,011 | $ | 37,068 | $ | 34,612 | ||||||
Earnings per common share: |
||||||||||||
Net income available to common stockholders |
$ | 0.89 | $ | 0.40 | $ | 0.37 | ||||||
Cumulative effect of changes in accounting principles |
— | — | 0.05 | |||||||||
Net income per common share |
$ | 0.89 | $ | 0.40 | $ | 0.42 | ||||||
Earnings per common share — assuming dilution |
$ | 0.86 | $ | 0.38 | $ | 0.36 | ||||||
Cumulative effect of changes in accounting principles |
— | — | 0.05 | |||||||||
Net income per common share — assuming dilution |
$ | 0.86 | $ | 0.38 | $ | 0.41 | ||||||
See accompanying notes.
F-6
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Increase (decrease) in cash and equivalents |
||||||||||||
Operating activities: |
||||||||||||
Net income |
$ | 111,011 | $ | 42,231 | $ | 35,415 | ||||||
Adjustments to reconcile
net cash provided from operating activities: |
||||||||||||
Deferred income tax expense |
65,297 | 24,790 | 18,319 | |||||||||
Cumulative effect of changes in accounting principles, net |
— | — | (4,491 | ) | ||||||||
Depletion, depreciation and amortization |
127,514 | 102,971 | 86,549 | |||||||||
Exploration dry hole costs |
7,045 | 9,493 | 3,576 | |||||||||
Mark-to-market on oil and gas derivatives (gains) losses |
(10,868 | ) | — | — | ||||||||
Unrealized derivative (gains) losses |
3,505 | (1,793 | ) | 679 | ||||||||
Allowance for bad debts |
675 | 1,762 | 2,138 | |||||||||
Amortization of deferred issuance costs and discount |
1,662 | 1,071 | 1,207 | |||||||||
Debt conversion and extinguishment expense |
— | — | 465 | |||||||||
Deferred compensation adjustments |
37,391 | 20,667 | 6,867 | |||||||||
(Gain) loss on retirement of securities |
— | 34 | (19,634 | ) | ||||||||
(Gain) loss on sale of assets and other |
(512 | ) | (3,143 | ) | 217 | |||||||
Changes in working capital: |
||||||||||||
Accounts receivable |
(44,533 | ) | (25,898 | ) | (11,530 | ) | ||||||
Inventory and other |
(3,452 | ) | (6,080 | ) | 501 | |||||||
Accounts payable |
27,472 | 34,746 | 2,982 | |||||||||
Accrued liabilities and other |
3,538 | 8,398 | 1,420 | |||||||||
Net cash provided from operating activities |
325,745 | 209,249 | 124,680 | |||||||||
Investing activities: |
||||||||||||
Additions to oil and gas properties |
(276,907 | ) | (166,560 | ) | (91,188 | ) | ||||||
Additions to field service assets |
(11,310 | ) | (4,237 | ) | (2,618 | ) | ||||||
Acquisitions (net of cash acquired) |
(153,600 | ) | (485,564 | ) | (103,869 | ) | ||||||
IPF net repayments |
6,008 | 5,938 | 10,308 | |||||||||
Disposal of assets |
3,432 | 26,122 | 529 | |||||||||
Net cash used in investing activities |
(432,377 | ) | (624,301 | ) | (186,838 | ) | ||||||
Financing activities: |
||||||||||||
Borrowings on credit facilities |
299,000 | 634,578 | 318,700 | |||||||||
Repayments on credit facilities |
(453,700 | ) | (528,878 | ) | (262,800 | ) | ||||||
Issuance of subordinated notes |
150,000 | 98,125 | 98,272 | |||||||||
Treasury stock purchases |
(2,808 | ) | — | — | ||||||||
Dividends paid — common stock |
(7,614 | ) | (3,219 | ) | — | |||||||
— preferred stock |
(2,213 | ) | (2,950 | ) | (803 | ) | ||||||
Debt issuance costs |
(4,119 | ) | (3,630 | ) | (2,183 | ) | ||||||
Issuance of common stock |
114,470 | 250,460 | 2,777 | |||||||||
Other debt repayments |
(16 | ) | (11,683 | ) | (92,508 | ) | ||||||
Net cash provided from financing activities |
93,000 | 432,803 | 61,455 | |||||||||
Net increase (decrease) in cash and equivalents |
(13,632 | ) | 17,751 | (703 | ) | |||||||
Cash and equivalents at beginning of year |
18,382 | 631 | 1,334 | |||||||||
Cash and equivalents at end of year |
$ | 4,750 | $ | 18,382 | $ | 631 | ||||||
See accompanying notes.
F-7
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In thousands)
(In thousands)
| Accumulated | ||||||||||||||||||||||||||||||||||||||||||||
| Preferred stock | Common stock | Treasury | Capital in | Retained | Stock held | other | ||||||||||||||||||||||||||||||||||||||
| Par | Par | Common | excess of | earnings | by employee | Deferred | comprehensive | |||||||||||||||||||||||||||||||||||||
| Shares | Value | Shares | Value | Stock | par value | (deficit) | benefit trust | compensation | loss | Total | ||||||||||||||||||||||||||||||||||
Balance
December 31, 2002 |
— | $ | — | 82,488 | $ | 825 | — | $ | 390,807 | $ | (158,059 | ) | $ | (6,188 | ) | $ | (125 | ) | $ | (21,151 | ) | $ | 206,109 | |||||||||||||||||||||
Issuance of preferred stock |
1,000 | 50,000 | — | — | — | — | — | — | — | — | 50,000 | |||||||||||||||||||||||||||||||||
Preferred dividends ($0.80 per share) |
— | — | — | — | — | — | (803 | ) | — | — | — | (803 | ) | |||||||||||||||||||||||||||||||
Issuance of common stock |
— | — | 1,934 | 19 | — | 7,205 | — | (2,253 | ) | (731 | ) | — | 4,240 | |||||||||||||||||||||||||||||||
Common dividends ($0.0067 per share) |
— | — | — | — | — | — | (564 | ) | — | — | — | (564 | ) | |||||||||||||||||||||||||||||||
Conversion of securities |
— | — | 194 | 2 | — | 1,368 | — | — | — | — | 1,370 | |||||||||||||||||||||||||||||||||
Other comprehensive loss |
— | — | — | — | — | — | — | — | — | (21,701 | ) | (21,701 | ) | |||||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | 35,415 | — | — | — | 35,415 | |||||||||||||||||||||||||||||||||
Balance
December 31, 2003 |
1,000 | 50,000 | 84,616 | 846 | — | 399,380 | (124,011 | ) | (8,441 | ) | (856 | ) | (42,852 | ) | 274,066 | |||||||||||||||||||||||||||||
Preferred dividends ($5.16 per share) |
— | — | — | — | — | — | (5,163 | ) | — | — | — | (5,163 | ) | |||||||||||||||||||||||||||||||
Issuance of common stock |
— | — | 28,390 | 284 | — | 258,171 | — | 255 | (401 | ) | — | 258,309 | ||||||||||||||||||||||||||||||||
Common dividends($0.0267 per share) |
— | — | — | — | — | — | (2,654 | ) | — | — | — | (2,654 | ) | |||||||||||||||||||||||||||||||
Conversion of securities |
(1,000 | ) | (50,000 | ) | 8,823 | 88 | — | 49,912 | — | — | — | — | — | |||||||||||||||||||||||||||||||
Other comprehensive loss |
— | — | — | — | — | — | — | — | — | (449 | ) | (449 | ) | |||||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | 42,231 | — | — | — | 42,231 | |||||||||||||||||||||||||||||||||
Balance
December 31, 2004 |
— | — | 121,829 | 1,218 | — | 707,463 | (89,597 | ) | (8,186 | ) | (1,257 | ) | (43,301 | ) | 566,340 | |||||||||||||||||||||||||||||
Issuance of common stock |
— | — | 8,084 | 81 | — | 138,056 | — | (3,666 | ) | (3,378 | ) | — | 131,093 | |||||||||||||||||||||||||||||||
Common dividends ($0.0599 per share) |
— | — | — | — | — | — | (7,614 | ) | — | — | — | (7,614 | ) | |||||||||||||||||||||||||||||||
Treasury stock purchases |
— | — | — | — | (2,808 | ) | — | — | — | — | — | (2,808 | ) | |||||||||||||||||||||||||||||||
Treasury stock issuances |
— | — | — | — | 2,727 | — | — | — | — | — | 2,727 | |||||||||||||||||||||||||||||||||
Other comprehensive loss |
— | — | — | — | — | — | — | — | — | (103,826 | ) | (103,826 | ) | |||||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | 111,011 | — | — | — | 111,011 | |||||||||||||||||||||||||||||||||
Balance
December 31, 2005 |
— | $ | — | 129,913 | $ | 1,299 | $ | (81 | ) | $ | 845,519 | $ | 13,800 | $ | (11,852 | ) | $ | (4,635 | ) | $ | (147,127 | ) | $ | 696,923 | ||||||||||||||||||||
See accompanying notes.
F-8
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Net income |
$ | 111,011 | $ | 42,231 | $ | 35,415 | ||||||
Net deferred hedge gains (losses), net of tax: |
||||||||||||
Contract settlements reclassified to income |
101,209 | 63,633 | 39,640 | |||||||||
Change in unrealized deferred hedging losses |
(206,348 | ) | (64,477 | ) | (61,531 | ) | ||||||
Change in unrealized gains (losses) on securities held by
deferred compensation plan, net of taxes |
1,313 | 395 | 190 | |||||||||
Comprehensive income |
$ | 7,185 | $ | 41,782 | $ | 13,714 | ||||||
See accompanying notes.
F-9
Table of Contents
RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS
Range Resources Corporation (“Range” “we” “us” or “our”) is engaged in the exploration,
development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian
and Gulf Coast regions of the United States. We seek to increase our reserves and production
primarily through drilling and complementary acquisitions. Prior to June 2004, we held our
Appalachian oil and gas assets through a 50% owned joint venture, Great Lakes Energy Partners
L.L.C. or Great Lakes. In June 2004, we purchased the 50% of Great Lakes that we did not own.
Range is a Delaware corporation whose common stock is listed and traded on the New York Stock
Exchange.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Range, our
wholly-owned subsidiaries and a 50% pro rata share of the income and expenses of Great Lakes
through June 23, 2004. The statement of operations for the twelve months ended December 31, 2004
includes 50% of the revenues and expenses of Great Lakes up to June 23, 2004 and 100% thereafter.
All significant intercompany balances and transactions have been eliminated.
Use of Estimates
The preparation of financial statements in accordance with generally accepted accounting
principles in the United States requires us to make estimates and assumptions that affect the
reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at
year-end and the reported amounts of revenues and expenses during the year. Actual results could
differ from the estimates and assumptions used. Depletion of oil and gas properties is determined
using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the projection of future rates of production and
the timing of development expenditures. Similarly, evaluation for impairment of proved and
unproved oil and gas properties is subject to numerous uncertainties including estimates of future
recoverable reserves and commodity price outlook. Other estimates which may significantly impact
our financial statements include asset retirement obligations, deferred income tax assets and fair
value of derivatives.
Income per Common Share
Basic net income per share is calculated based on the weighted average number of common shares
outstanding. Diluted net income per share assumes exercise of stock options and conversion of
convertible debt and preferred securities, provided the effect is not antidilutive. All common
stock shares and per share amounts in the accompanying financial statements have been adjusted for
the three-for-two stock split effected on December 2, 2005.
Business Segment Information
The Financial Accounting Standards Board, or the FASB, Statement of Financial Accounting
Standards No. 131, “Disclosure About Segments of an Enterprise and Related Information,” or SFAS
131, establishes standards for reporting information about operating segments. Operating segments
are defined as components of an enterprise that engage in activities from which it may earn
revenues and incur expenses for which separate operational financial information is available and
this information is regularly evaluated by the chief decision maker for the purpose of allocating
resources and assessing performance.
Segment reporting is not applicable to us as each of our core operating areas has similar
economic characteristics and each meets the criteria for aggregation as defined in SFAS 131. All
of our operations involve the exploration, development and production of natural gas and oil and
all of our operations are located in the United States. We have a single company-wide management
team that administers all properties as a whole rather than by discrete operating segments. We
track only basic operational data by area. We do not maintain separate financial statement
information by area. We measure financial performance as a single enterprise and not on an
area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project
basis, across our entire asset base to maximize profitability without regard to individual areas or
segments.
F-10
Table of Contents
Revenue Recognition and Gas Imbalances
Oil, gas and natural gas liquids revenues are recognized when the products are sold and
delivery to the purchaser has occurred. Although receivables are concentrated in the oil and gas
industry, we do not view this as unusual credit risk. We provide for an allowance for doubtful
accounts for specific receivables judged unlikely to be collected based on the age of the
receivable, our experience with the debtor, potential offsets to the amount owed and economic
conditions. In certain instances, we require purchasers to post stand-by letters of credit. We
have allowances for doubtful accounts relating to exploration and production receivables of
$623,800 and $967,000 at December 31, 2005 and 2004, respectively.
We use the sales method to account for gas imbalances, recognizing revenue based on gas
delivered rather than our working interest share of the gas produced. A liability is recognized
when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at December 31, 2005
and December 31, 2004 were not significant. At December 31, 2005, we had recorded a net liability
of $854,000 for those wells where it was determined that there was insufficient reserves to recover
the imbalance situation.
Cash and Equivalents
Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid
debt instruments with maturities of three months or less. The December 2004 balance sheet includes
$17.3 million of cash in an escrow account. These funds were proceeds received from the sale of
oil and gas properties which were held in escrow to be used to purchase similar assets. In the
second quarter of 2005, these escrow proceeds less transaction expenses were applied towards the
bank credit facility.
Marketable Securities
Holdings of equity securities qualify as available-for-sale or trading and are recorded at
fair value.
Inventories
Inventories consist primarily of tubular goods used in our operations and are stated at the
lower of specific cost of each inventory item or market value.
Oil and Gas Properties
We follow the successful efforts method of accounting for oil and gas producing activities.
Costs to drill exploratory wells that do not find proved reserves, geological and geophysical
costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs
incurred for exploratory wells that find reserves that cannot yet be classified as proved are
capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion
as a producing well and (b) we are making sufficient progress assessing the reserves and the
economic and operating viability of the project. Well costs are expensed if a determination as to
whether proved reserves were found cannot be made within one year. The status of suspended well
costs is monitored continuously and reviewed not less than quarterly. Costs resulting in
exploratory discoveries and all development costs, whether successful or not, are capitalized. Oil
and NGLs are converted to gas equivalent basis or mcfe at the rate one barrel equals 6 mcf. The
depletion, depreciation and amortization rates were $1.46, $1.44 and $1.49 per mcfe in 2005, 2004
and 2003, respectively. Depletion is provided on the unit-of-production method. Unproved
properties had a net book value of $28.6 million, $14.8 million and $12.2 million at December 31,
2005, 2004 and 2003, respectively. Unproved properties are reviewed quarterly for impairment and
impaired if conditions indicate we will not explore the acreage prior to expiration or the carrying
value is above fair value.
Our long-lived assets are reviewed for impairment periodically for events or changes in
circumstances that indicate that the carrying amount of an asset may not be recoverable.
Long-lived assets are reviewed for potential impairments at the lowest levels for which there are
identifiable cash flows that are largely independent of other groups of assets. The review is done
by determining if the historical cost of proved properties less the applicable accumulated
depreciation, depletion and amortization and abandonment is less than the estimated expected
undiscounted future net cash flows. The expected future net cash flows are estimated based on our
plans produce and develop proved reserves. Expected future cash inflow from the sale of production
of reserves is calculated based on estimated future prices. We estimate prices based upon market
related information including published futures prices. The estimated future level of production
is based on assumptions surrounding future levels of prices and costs, field decline rates, market
demand and supply, and the economic and regulatory climates. When the carrying value exceeds the
sum of future net cash flows, an impairment loss is recognized for the difference between the
estimated fair market value, (as determined by discounted future net cash flows) and the carrying
value of the asset.
Proceeds from the disposal of miscellaneous properties are credited to the net book value of
their amortization group with no immediate effect on income. However, gain or loss is recognized
from the sale of less than an entire amortization group if the disposition is significant enough to
materially impact the depletion rate of the remaining properties in the amortization base.
F-11
Table of Contents
Transportation and Field Assets
Our gas transportation and gathering systems are generally located in proximity to certain of
our principal fields. Depreciation on these systems is provided on the straight-line method based
on estimated useful lives of 10 to 15 years. We receive third-party income for providing certain
transportation and field services which is recognized as earned. Depreciation on
the associated assets is calculated on the straight-line method based on estimated useful
lives ranging from five to seven years. Buildings are depreciated over 10 to 15 years.
Depreciation expense was $6.4 million, $4.7 million and $3.0 million in 2005, 2004 and 2003,
respectively.
Other Assets
The expenses of issuing debt are capitalized and included in other assets on our consolidated
balance sheet. These costs are amortized over the expected life of the related securities. When a
security is retired prior to maturity, related unamortized costs are expensed. Other assets at
December 31, 2005 include $7.9 million unamortized debt issuance costs, $21.8 million of marketable
securities held in the deferred compensation plan and $904,000 of long-term deposits. Other assets
also includes an IPF receivable of $2.6 million offset by an IPF allowance of $2.6 million.
Stock-based Compensation
The 2005 Equity Based Compensation Plan, or the 2005 Plan, authorizes the Compensation
Committee of the Board of Directors to grant stock options, stock appreciation rights, restricted
stock awards, and phantom stock rights to employees. The Non-Employee Director Stock Plan, or the
Director Plan, allows grants to our non-employee directors of our Board of Directors. The 2005
Plan was approved by shareholders in May 2005 and replaces our 1999 stock option plan. No new
grants will be made from the 1999 stock option plan. The number of shares that may be issued under
the 2005 Plan is equal to (i) 5.6 million shares (15.0 million less the 2.2 million shares issued
under the 1999 Stock Options Plan prior to the May 18, 2005, effective date of the 2005 Plan and
less the 7.2 million shares issuable pursuant to awards under the 1999 Stock Option Plan
outstanding as of the effective date of the 2005 Plan) plus (ii) the number of shares subject to
1999 Stock Option Plan awards outstanding at May 18, 2005, that subsequently lapse or terminate
without the underlying shares being issued. The Director Plan was approved by shareholders in May
2004 and no more than 300,000 shares of common stock may be issued under the Plan.
Stock options represent the right to purchase shares of stock in the future at the fair market
value of the stock on the date of grant. Most stock options granted under our stock option plans
generally vest over a three year period and expire five years from the date they are granted.
Similar to stock options, stock appreciation rights, or SARs, represent the right to receive a
payment equal to the excess of the fair market value of shares of common stock on the date the
right is exercised over the value of the stock on the date of grant. All SARs granted under the
2005 Plan will be settled in shares of stock, vest over a three year period and have a maximum term
of five years from the date they are granted. We began issuing SARs in 2005 to limit the dilution
impact of our equity compensation plans.
The Compensation Committee grants restricted stock to certain employees and to non-employee
directors of the Board of Directors as part of their compensation. Unearned compensation is
charged to equity when restricted stock is granted. Compensation expense is recognized over the
balance of the vesting period or the period for services to be rendered.
We apply the intrinsic value-based method of accounting prescribed by Accounting Principles
Board Opinion No. 25, “Accounting for Stock Issued to Employees, and related interpretations,” in
accounting for our stock options. As such, compensation expense is recorded on the date of grant
only if the current market price of the underlying stock exceeds the exercise price. SFAS No. 123,
“Accounting for Stock-Based Compensation,” or SFAS 123, established accounting and disclosure
requirements using a fair value-based method of accounting for stock-based employee compensation
plans. As allowed by SFAS 123, we have elected to continue to apply the intrinsic value-based
method of accounting described above, and we have adopted the disclosure requirements of SFAS 123,
which was amended by SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and
Disclosures.” See also “Accounting Pronouncements Not Yet Adopted” below.
F-12
Table of Contents
We have adopted the disclosure-only provisions of SFAS 123. Accordingly, no compensation cost
has been recognized for our stock options because the exercise prices of the stock options equals
the market prices of the underlying stock on the date of grant. However, compensation expense of
$5.8 million has been recognized for our SARs granted during the year. If compensation cost had
been determined based on the fair value at the grant date for awards in 2005, 2004 and 2003
consistent with the provisions of SFAS 123, our net income and earnings per share would have been
reduced to the pro forma amounts indicated below:
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (in thousands, except per share data) | ||||||||||||
Net income as reported |
$ | 111,011 | $ | 42,231 | $ | 35,415 | ||||||
Add: Total stock-based employee compensation
expense
included in net income, net of tax |
23,556 | 13,020 | 4,326 | |||||||||
Deduct: Total stock-based employee compensation
expense determined under fair value
based method, net of tax |
(29,235 | ) | (17,114 | ) | (6,365 | ) | ||||||
Pro forma net income |
$ | 105,332 | $ | 38,137 | $ | 33,376 | ||||||
Earnings per share: |
||||||||||||
Basic-as reported |
$ | 0.89 | $ | 0.40 | $ | 0.42 | ||||||
Basic-pro forma |
0.85 | 0.35 | 0.40 | |||||||||
Diluted-as reported |
0.86 | 0.38 | 0.41 | |||||||||
Diluted-pro forma |
0.82 | 0.34 | 0.38 | |||||||||
As required,
the pro forma disclosures above included options and SARs granted since January
1, 1995. For purposes of pro forma disclosures, the estimated fair value is amortized to expense
over the vesting period. For options with graded vesting, expense is recognized on a straight-line
basis over the vesting period. The fair value of each option grant on the date of grant for the
disclosures is estimated by using the Black-Scholes option pricing model with the following
weighted-average assumption used for 2005, 2004 and 2003, respectively: fair value of $8.48, $4.52
and $2.61 per share; expected dividend per share of $0.08, $0.04 and $0.00; expected volatility
factors of 54%, 67% and 73%; risk-free interest rates of 4.1%, 3.5% and 3.2%, and an average
expected life of 5 years.
Derivative Financial Instruments and Hedging
We use commodity-based
derivatives to reduce the volatility of oil and gas prices. 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 other comprehensive income, or
OCI, and then reclassified to income, as a component of oil and gas revenues, when the underlying
anticipated transaction occurs. Any ineffective portion (changes in realized prices that do not
match changes in the reference price used to settle the hedge) is recognized in earnings, as a
component of other revenues, as it occurs. Ineffective gains or losses are recorded while the
hedge contract is open and may increase or reverse until settlement of the contract. Typically,
when oil and gas prices increase, OCI decreases. Of the
$236.9 million pre-tax loss recorded in OCI at December 2005,
$171.5 million is expected to be reclassed to income in 2006, if
prices remain at their December 31, 2005 levels. As of the fourth quarter of 2005, certain of our oil and gas derivatives no longer qualify for hedge accounting due to the effect of recent volatility of gas
prices on the correlation between realized prices and hedge reference prices. As a result, we
recognized $10.9 million of gain in the fourth quarter because oil and gas derivatives in our Southwestern Division
no longer qualified for hedge accounting. These derivative positions will continue to be
marked-to-market in going forward into 2006. This may result in more volatility in our income in
future periods. We have also entered into swap agreements to reduce the
risk of changing
interest rates. These interest rate swaps are not designated as hedges and are marked to market
each month as a component of interest expense.
F-13
Table of Contents
Asset Retirement Obligations
The fair values of asset retirement obligations are recognized in the period they are
incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations
primarily relate to the abandonment of oil and gas producing facilities and include costs to
dismantle and relocate or dispose of production platforms, gathering systems, wells and related
structures. Estimates are based on historical experience in plugging and abandoning wells,
estimated remaining lives of those wells based on reserve estimates, external estimates as to the
cost to plug and abandon the wells in the future and federal and state regulatory requirements.
Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations
are recorded over time. The depreciation will generally be determined on a units-of-production
basis while accretion to be recognized will escalate over the life of the producing assets. We do
not provide for a market risk premium associated with asset retirement obligations because a
reliable estimate cannot be determined.
Accumulated Other Comprehensive Income (Loss)
We follow the provisions of SFAS 130, “Reporting Comprehensive Income” which establishes
standards for reporting comprehensive income. Comprehensive income, or OCI, includes net income as
well as all changes in equity during the period, except those resulting from investments and
distributions to owners. At December 31, 2005, we had a $236.9 million pre-tax loss in OCI
relating to unrealized commodity hedges. We also had a pre-tax gain of $2.9 million relating to
our marketable securities held in the deferred compensation plan.
The components of accumulated other comprehensive income (loss) and related tax effects for
three years ended December 31, 2005, were as follows (in thousands):
| Gross | Tax Effect | Net of Tax | ||||||||||
Accumulated other comprehensive loss at December 31, 2002 |
$ | (32,539 | ) | $ | 11,388 | $ | (21,151 | ) | ||||
Contract settlements reclassified to income |
60,427 | (20,787 | ) | 39,640 | ||||||||
Change in unrealized deferred hedging losses |
(95,657 | ) | 34,126 | (61,531 | ) | |||||||
Change in unrealized gains (losses) on
securities held by deferred compensation plan |
297 | (107 | ) | 190 | ||||||||
Accumulated other comprehensive loss at December 31, 2003 |
(67,472 | ) | 24,620 | (42,852 | ) | |||||||
Contract settlements reclassified to income |
100,121 | (36,488 | ) | 63,633 | ||||||||
Change in unrealized deferred hedging losses |
(102,506 | ) | 38,029 | (64,477 | ) | |||||||
Change in unrealized gains (losses) on
securities held by deferred compensation plan |
626 | (231 | ) | 395 | ||||||||
Accumulated other comprehensive loss at December 31, 2004 |
(69,231 | ) | 25,930 | (43,301 | ) | |||||||
Contract settlements reclassified to income |
160,267 | (59,058 | ) | 101,209 | ||||||||
Change in unrealized deferred hedging losses |
(327,448 | ) | 121,100 | (206,348 | ) | |||||||
Change in unrealized gains (losses) on
securities held by deferred compensation plan |
2,049 | (736 | ) | 1,313 | ||||||||
Accumulated other comprehensive loss at December 31, 2005 |
$ | (234,363 | ) | $ | 87,236 | $ | (147,127 | ) | ||||
Reclassifications
Certain reclassifications of prior years’ data have been made to conform with our current year
classification.
Accounting Pronouncements Implemented
In April 2005, the FASB issued Staff Position No. FAS 19-1, “Accounting for Suspended Well
Costs,” or FSP 19-1. FSP 19-1 amends SFAS No. 19, “Financial Accounting and Reporting by Oil and
Gas Producing Companies,” or SFAS 19, to allow continued capitalization of exploratory well costs
beyond one year from the completion of drilling under circumstances where the wells has found a
sufficient quantity of reserves to justify its completion as a producing well and the enterprise is
making sufficient progress assessing the reserves and the economic and operating viability of the
project. FSP 19-1 also amends SFAS 19 to require enhanced disclosures of suspended exploratory
well costs in the notes to the financial statements for annual and interim periods when there has
been a significant change from the previous disclosure. The guidance in FSP 19-1 was effective for
the first reporting period beginning after April 4, 2005. Accordingly, we adopted the new
requirements on July 1, 2005 and have included the required disclosures in footnote 3. The
adoption of FSP 19-1 did not impact our consolidated financial position or results of operations.
F - 14
Table of Contents
Accounting Pronouncements Not Yet Adopted
In December 2004, the Financial Accounting Standards Board, or FASB, issued FASB Statement No.
123 (revised 2004) “Share-Based Payment,” or SFAS 123(R), which is a revision of FASB Statement No.
123, Accounting for Stock-Based Compensation. SFAS 123(R) supersedes APB opinion No. 25,
Accounting for Stock Issued to employees, and amends FASB Statement No. 95, Statement of Cash
Flows. Generally, the approach in SFAS 123(R) is similar to the approach described in Statement
123. However, SFAS 123(R) requires all share-based payments to employees, including grants of
employee stock options, to be recognized in the income statement based on their fair values rather
than pro forma footnote disclosure.
SFAS 123(R) permits companies to adopt its requirements using either a “modified prospective”
method, or a “modified retrospective” method. Under the “modified prospective” method,
compensation costs is recognized in the financial statements beginning with the effective date,
based on the requirements of SFAS 123(R) for all share-based payments granted after that date, and
based on the requirements of SFAS 123 for all unvested awards granted prior to the effective date
of SFAS 123(R). Under the “modified retrospective” method, the requirements are the same as under
the “modified prospective” method, but also permits entities to restate financial statements of
previous periods based on pro forma disclosures made in accordance with SFAS 123. We have elected
to adopt the provisions of SFAS 123(R) using modified prospective method on January 1, 2006.
We currently utilize a standard option pricing model called Black-Scholes to measure the fair
value of stock options and stock appreciation rights granted. While SFAS 123(R) permits entities
to continue to use such a model, the standard also permits the use of a “lattice” binomial model.
We currently anticipate we will continue using Black Scholes upon adoption of SFAS 123(R).
The adoption of SFAS 123(R) will have a significant impact on our consolidated statement of
operations, although it will have no impact on our overall financial position. The impact of
adoption of Statement 123(R) cannot be predicted at this time because it will depend on levels of
share-based payments granted in the future. However, had we adopted Statement 123(R) in prior
periods, the impact of that standard would have approximated the impact of Statement 123 as
described in the disclosure of pro forma net income and earnings per share above. SFAS 123(R) also
requires the benefits of tax deductions in excess of recognized compensation cost to be reported as
a financing cash flow, rather than as an operating cash flow as required under current literature.
This requirement will reduce net operating cash flows and increase net financing cash flows in
periods after adoption, to the extent of associated tax benefits that may be realized in the
future. While we cannot estimate what those amounts will be in the future (because they depend on
when employees exercise stock options, among other things), there was no impact on our net
operating cash flows in 2005, 2004 or 2003, respectively, as we were not able to recognize a cash
benefit due to our net operating loss carryforward tax position.
In June 2005, the Compensation Committee of the Board of Directors approved the acceleration
of certain unvested options. Certain unvested options with vesting dates between January 1, 2006
and April 1, 2006 were accelerated so they would vest on December 31, 2005, representing an average
acceleration of 46 days. There were approximately 1.1 million options held by management and
non-management employees affected by the acceleration which was undertaken primarily to reduce
future stock-based compensation under SFAS 123(R).
In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting
Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statements No. 3,” or
SFAS 154, which provides guidance on the accounting for a reporting of accounting changes and error
corrections. It establishes, unless impracticable, retrospective application as the required
method for reporting a change in accounting principle in the absence of explicit transition
requirements specific to SFAS 154. The provisions of SFAS 154 shall be effective for accounting
changes and corrections of errors made in fiscal years beginning after December 15, 2005.
F-15
Table of Contents
(3) SUSPENDED EXPLORATORY WELL COSTS
The following table reflects the changes in capitalized exploratory well costs for the twelve
months ended December 31, 2005, 2004 and 2003 (in thousands):
| 2005 | 2004 | 2003 | ||||||||||
Balance at beginning of period |
$ | 7,332 | $ | 2,043 | $ | 4 | ||||||
Additions to capitalized exploratory well costs pending
the
determination of proved reserves |
26,915 | 4,767 | 2,039 | |||||||||
Additions due to purchase of Great Lakes |
— | 2,012 | — | |||||||||
Reclassifications to wells, facilities and equipment based
on determination of proved reserves |
(8,614 | ) | (784 | ) | — | |||||||
Capitalized exploratory well costs charged to expense |
(293 | ) | (706 | ) | — | |||||||
Balance at end of period |
25,340 | 7,332 | 2,043 | |||||||||
Less exploratory well costs that have been capitalized for
a period of one year or less |
(21,589 | ) | (6,124 | ) | (2,039 | ) | ||||||
Capitalized exploratory well costs that have been capitalized for
a period greater than one year |
$ | 3,751 | $ | 1,208 | $ | 4 | ||||||
Number of projects that have exploratory well costs that have
been capitalized for a period greater than one year |
3 | 3 | — | |||||||||
As of December 31, 2005, of the $3.8 million of capitalized exploratory well costs that have
been capitalized for more than one year, all of the wells have additional exploratory wells in the
same prospect area drilling or firmly planned. The $25.3 million of capitalized exploratory well
costs at December 31, 2005 was incurred in 2005 ($21.6 million), in 2004 ($3.5 million) and in 2003
($200,000).
(4) ACQUISITIONS AND DISPOSITIONS
Acquisitions are accounted for as purchases, and accordingly, the results of operations are
included in our statement of operations from the effective date of the acquisition. Purchase
prices are allocated to acquired assets and assumed liabilities based on their estimated fair value
at the time of the acquisition. Acquisitions have been funded with internal cash flow, bank
borrowings and the issuance of debt and equity securities. We purchased various properties for
consideration of $173.5 million, $648.2 million and $100.9 million, during the years ended December
31, 2005, 2004 and 2003, respectively. These purchases included $152.8 million, $619.0 million and
$90.7 million for proved oil and gas reserves, respectively; the remainder represents unproved
acreage purchases. As part of our acquisitions for 2004 and 2003, we allocated $15.5 million and
$4.6 million to gathering facilities acquired in the transactions. See also Note 16 – Costs
Incurred for Property Acquisition, Exploration and Development.
On December 10, 2004, we purchased Appalachian oil and gas properties, through the purchase of
Pine Mountain, for $152.4 million cash paid to the seller, $57.2 million cash paid to repay debt
and $13.3 million for the retirement of oil and gas commodity hedges. The following table
summarizes the final allocation of the purchase price to assets acquired and liabilities assumed at
the date of acquisition (in thousands):
| Pine Mountain | ||||
Purchase price: |
||||
Cash paid (including transaction costs) |
$ | 223,917 | ||
Total |
$ | 223,917 | ||
Allocation of purchase price: |
||||
Working capital |
5,960 | |||
Oil and gas properties |
297,265 | |||
Field assets and gathering system assets |
1,046 | |||
Deferred income taxes, net |
(79,860 | ) | ||
Asset retirement obligations and other |
(494 | ) | ||
Total |
$ | 223,917 | ||
F-16
Table of Contents
On June 23, 2004, we purchased the 50% of Great Lakes we did not previously own for $200.0
million paid to the seller plus the assumption of $70.0 million of Great Lakes bank debt and the
retirement of $27.7 million of oil and gas commodity hedges. The debt assumed was refinanced and
consolidated with our existing credit facility as of the purchase date. The following table
summarizes the final allocation of the purchase price to the assets acquired and liabilities
assumed at the date of acquisition (in thousands):
| Great Lakes | ||||
Purchase price: |
||||
Cash paid (including transaction costs) |
$ | 228,824 | ||
Total |
$ | 228,824 | ||
Allocation of purchase price: |
||||
Working capital |
5,062 | |||
Oil and gas properties |
296,160 | |||
Field assets and gathering system assets |
14,429 | |||
Other non-current assets |
866 | |||
Asset retirement obligations and other |
(17,693 | ) | ||
Long-term debt |
(70,000 | ) | ||
Total |
$ | 228,824 | ||
The following unaudited pro forma data include the results of operations of the above
acquisitions as if they had been consummated at the beginning of 2004. The pro forma data are
based on historical information and do not necessarily reflect the actual results that would have
occurred nor are they necessarily indicative of future results of operations (in thousands).
| 2004 | ||||
Revenues |
$ | 377,564 | ||
Income before income taxes |
84,484 | |||
Net income |
53,385 | |||
Earnings per common share: |
||||
- Basic |
$ | 0.44 | ||
- Diluted |
$ | 0.42 | ||
In June 2005, we purchased Permian Basin properties for $116.4 million. As a preliminary
allocation of purchase price, we have recorded $136.8 million to oil and gas properties $133,000 of
working capital, $20.5 million of deferred tax liability and $119,000 of additional asset
retirement obligations. The acquisition was partially funded with the proceeds from a public
offering of 4.6 million common shares for $109.2 million. No pro forma information has been
provided as the acquisition was not considered significant.
(5) ASSET RETIREMENT OBLIGATION
A reconciliation of our liability for plugging and abandonment costs for the years ended
December 31, 2005 and 2004 is as follows (in thousands):
| 2005 | 2004 | |||||||
Asset retirement obligation — beginning of period |
$ | 70,727 | $ | 51,844 | ||||
Liabilities incurred |
3,813 | 20,237 | ||||||
Liabilities settled |
(6,126 | ) | (7,175 | ) | ||||
Accretion expense |
5,072 | 4,539 | ||||||
Change in estimate |
(5,423 | ) | 1,282 | |||||
Total |
68,063 | 70,727 | ||||||
Less current portion |
(3,166 | ) | (6,822 | ) | ||||
Asset retirement obligation — end of period |
$ | 64,897 | $ | 63,905 | ||||
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Table of Contents
(6) SUPPLEMENTAL CASH FLOW INFORMATION
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (in thousands) | ||||||||||||
Net cash provided from operating activities included: |
||||||||||||
Income taxes paid to taxing authorities |
$ | 615 | $ | 150 | $ | 110 | ||||||
Interest paid |
34,148 | 19,216 | 21,579 | |||||||||
Non-cash investing and financing activities included: |
||||||||||||
Common stock issued: |
||||||||||||
Under benefit plans |
$ | 3,180 | $ | 2,122 | $ | 3,672 | ||||||
Exchanged for fixed income securities |
— | — | 1,370 | |||||||||
Preferred stock issued |
— | — | 50,000 | |||||||||
Preferred stock converted to common stock |
— | (50,000 | ) | — | ||||||||
Asset retirement costs capitalized, excluding acquisitions(a) |
(1,730 | ) | 3,994 | 4,597 | ||||||||
| (a) | For information regarding purchase price allocations of businesses acquired see Note 4. |
(7) INDEBTEDNESS
We had the following debt outstanding as of the dates shown (interest rates, excluding the
impact of interest rate swaps, at December 31, 2005 are shown parenthetically). No interest was
capitalized during 2005, 2004, and 2003 (in thousands):
| December 31, | ||||||||
| 2005 | 2004 | |||||||
Bank debt (5.4%) |
$ | 269,200 | $ | 423,900 | ||||
Subordinated debt: |
||||||||
7.375% Senior Subordinated Notes due 2013, net
of $3.1 million and $3.3 million discount, respectively |
196,948 | 196,656 | ||||||
6.375% Senior Subordinated Notes due 2015 |
150,000 | — | ||||||
Total debt |
$ | 616,148 | $ | 620,556 | ||||
Bank Debt
In June 2004, we entered into an amended and restated $600.0 million revolving bank credit
facility, which is secured by substantially all of our assets. The bank credit facility provides
for a borrowing base subject to redeterminations semi-annually each April and October and to
certain unscheduled redeterminations. As of December 31, 2005, the outstanding balance under the
bank credit facility was $269.2 million and there was $330.8 million of borrowing capacity
available. The loan matures on January 1, 2009. Borrowing under the bank credit facility can
either be base rate loans or LIBOR loans. On all base rate loans, the rate per annum is equal to
the lesser of (i) the maximum rate (the “weekly ceiling” as defined in Section 303 of the Texas
Finance Code or other applicable laws if greater) (the “Maximum Rate”) or, (ii) the sum of (A) the
higher of (1) the prime rate for such date, or (2) the sum of the federal funds effective rate for
such date plus one-half of one percent (0.50%) per annum, plus a base rate margin of between 0.0%
to 0.5% per annum depending on the total outstanding under the bank credit facility relative to the
borrowing base. On all LIBOR loans, we pay a varying rate per annum equal to the lesser of (i) the
Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B) one minus
the reserve requirement applicable to such interest period, plus a LIBOR margin of between 1.0% and
1.75% per annum depending on the total outstanding under the bank credit facility relative to the
borrowing base. We may elect, from time-to-time, to convert all or any part of its LIBOR loans to
base rate loans or to convert all or any of the base rate loans to LIBOR loans. The weighted
average interest rate was 4.5% and 3.2% for the years ended December 31, 2005 and 2004,
respectively. A commitment fee is paid on the undrawn balance based on an annual rate of 0.25% to
0.50%. At December, 31, 2005, the commitment fee was 0.25% and the interest rate margin was 1.0%.
At February 20, 2006, the interest rate (including applicable margin) was 5.6%.
F-18
Table of Contents
7.375% Senior Subordinated Notes due 2013
In July 2003, we issued $100.0 million aggregate principal amount of 7.375% senior
subordinated notes due 2013, or the 7.375% Notes. In June 2004, we issued an additional $100.0
million of 7.375% Notes; therefore, $200.0 million of the 7.375% Notes are currently outstanding.
We pay interest on the 7.375% Notes semi-annually in January and July of each year. The 7.375%
Notes mature in July 2013 and are guaranteed by certain of our subsidiaries. The 7.375% Notes were
issued at a discount which will be amortized over the life of the 7.375% Notes into interest
expense.
We may redeem the 7.375% Notes, in whole or in part, at any time on or after July 15, 2008, at
redemption prices of 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on
July 15, 2011 and thereafter. Prior to July 15, 2006, we may redeem up to 35% of the original
aggregate principal amount of the notes at a redemption price of 107.4% of the principal amount
thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings.
If we experience a change of control, there may be a requirement to repurchase all or a portion of
the 7.375% Notes at 101% of the principal amount thereof plus accrued and unpaid interest, if any.
The 7.375% Notes and the guarantees by our subsidiary guarantors are general, unsecured
obligations and are subordinated to our bank debt and will be subordinated to future senior debt
that Range and our subsidiary guarantors are permitted to incur under the bank credit facility and
the indenture governing the 7.375% Notes.
6.375% Senior Subordinated Notes Due 2015
In March 2005, we issued $150.0 million of 6.375% senior subordinated notes due 2015, or the
6.375% Notes. We pay interest on the 6.375% Notes semi-annually in March and September of each
year. The 6.375% Notes mature in March 2015 and are guaranteed by certain of our subsidiaries.
We may redeem the 6.375% Notes, in whole or in part, at any time on or after March 15, 2010,
at redemption prices from 103.2% of the principal amount as of March 15, 2010 and declining to 100%
on March 15, 2013 and thereafter. Prior to March 15, 2008, we may redeem up to 35% of the original
aggregate principal amount of the notes at a redemption price of 106.4% of the principal amount
thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings.
If we experience a change of control, there may be a requirement to repurchase all or a portion of
the 6.375% Notes at 101% of the principal amount plus accrued and unpaid interest, if any.
The 6.375% Notes and the guarantees by our subsidiary guarantors are general, unsecured
obligations and are subordinated to our bank debt and will be subordinated to future senior debt
that Range and our subsidiary guarantors are permitted to incur under the bank credit facility and
the indenture governing the 6.375% Notes.
Guarantees
Range Resources Corporation is a holding company which owns no operating assets and has no
significant operations independent of its subsidiaries. The guarantees of the 7.375% Notes and the
6.375% Notes are full and unconditional and joint and several; any subsidiaries other than the
subsidiary guarantors are either minor subsidiaries or indirect subsidiaries, or both.
Debt Covenants
The debt agreements contain covenants relating to working capital, dividends and financial
ratios. We were in compliance with all covenants at December 31, 2005. Under the bank credit
facility, common and preferred dividends are permitted, subject to the provisions of the restricted
payment basket. The bank credit facility provides for a restricted payment basket of $20.0 million
plus 50% of net income plus 66-2/3% of net cash proceeds from common stock issuances.
Approximately $365.8 million was available under the bank credit facility’s restricted payment
basket on December 31, 2005. The terms of both the 6.375% Notes and the 7.375% Notes limit
restricted payments (including dividends) to the greater of $20.0 million or a formula based on
earnings and equity issuances since the original issuances of the notes. At December 31, 2005,
approximately $432.9 million was available under the restricted payment baskets for both the 6.375%
Notes and the 7.375% Notes.
F-19
Table of Contents
Following is the principal maturity schedule for the long-term debt outstanding as of December
31, 2005 (in thousands):
Year Ended
December 31: |
||||
2006 |
$ | — | ||
2007 |
— | |||
2008 |
— | |||
2009 |
269,200 | |||
2010 |
— | |||
2011 |
||||
Thereafter |
350,000 | |||
| $ | 619,200 | |||
(8) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
Financial instruments include cash and equivalents, receivables, payables, debt and commodity
and interest rate derivatives. The book value of cash and equivalents, receivables and payables is
considered to be representative of fair value because of their short maturity. We mark to market
all derivatives; therefore, the book value is assumed to be equal to fair value. The book value of
bank borrowings is believed to approximate fair value because of their floating rate structure.
The following table sets forth the book and estimated fair values of financial instruments (in
thousands):
| December 31, 2005 | December 31, 2004 | |||||||||||||||
| Book | Fair | Book | Fair | |||||||||||||
| Value | Value | Value | Value | |||||||||||||
Assets |
||||||||||||||||
Cash and equivalents |
$ | 4,750 | $ | 4,750 | $ | 18,382 | $ | 18,382 | ||||||||
Accounts receivable |
128,532 | 128,532 | 80,562 | 80,562 | ||||||||||||
IPF receivable |
— | — | 4,508 | 4,508 | ||||||||||||
Marketable securities (b) |
21,769 | 21,769 | 9,866 | 9,866 | ||||||||||||
Interest rate swaps |
425 | 425 | 740 | 740 | ||||||||||||
Total |
155,476 | 155,476 | 114,058 | 114,058 | ||||||||||||
Liabilities |
||||||||||||||||
Accounts payable |
(119,907 | ) | (119,907 | ) | (78,723 | ) | (78,723 | ) | ||||||||
Commodity swaps and collars |
(231,049 | ) | (231,049 | ) | (71,931 | ) | (71,931 | ) | ||||||||
Long-term debt (a) |
(616,148 | ) | (619,523 | ) | (620,556 | ) | (633,556 | ) | ||||||||
Total |
(967,104 | ) | (970,479 | ) | (771,210 | ) | (784,210 | ) | ||||||||
| $ | (811,628 | ) | $ | (815,003 | ) | $ | (657,152 | ) | $ | (670,152 | ) | |||||
| (a) | Fair value based on quotes received from certain brokerage firms. Quotes for December 31, 2005 were 103% for the 7.375% Notes and 98% for the 6.375% Notes. | |
| (b) | Marketable securities held in the deferred compensation plans. |
At December 31, 2005, we had open swap contracts covering 6.7 Bcf of gas at prices
averaging $6.60 per mcf and 0.1 million barrels of oil at prices averaging $35.00 per barrel. We
also had collars covering 82.8 Bcf of gas at weighted average floor and cap prices of $6.77 to
$9.43 per mcf and 4.8 million barrels of oil at weighted average floor and cap prices of $45.21 to
$56.58 per barrel. Their fair value, represented by the estimated amount that would be realized
upon termination, based on a comparison of the contract price and a reference price, generally
NYMEX, approximated a net unrealized pre-tax loss of $231.0 million at December 31, 2005. These
contracts expire monthly through December 2008. 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. In 2005, 2004 and 2003, losses relating to our hedges of $171.1 million,
$100.1 million and $60.4 million were realized, respectively. In addition, gains of $10.9 million
were recognized in the fourth quarter of 2005 relating to positions which did not qualify for hedge
accounting due to market volatility. Our hedging positions are recorded on our consolidated
balance sheet at an estimate of fair value based on a comparison of the contract price and a
reference price, generally NYMEX. Other revenues in the consolidated statement of operations were
decreased for ineffective hedging losses on hedges that qualified for hedge accounting of $3.4
million and increased for ineffective gains of $712,000 in the twelve months ended December 31,
2005 and 2004 and decreased for ineffective hedging losses of $1.2 million in the year ended
December 31, 2003.
F-20
Table of Contents
The following table sets forth the hedging volumes by year as of December 31, 2005:
| Period | Contract Type | Volume Hedged | Average Hedge Price | |||||||||
Natural gas |
||||||||||||
2006 |
Swaps | 10,788 Mmbtu/day | $ | 6.43 | ||||||||
2006 |
Collars | 113,363 Mmbtu/day | $ | 6.37 - $8.70 | ||||||||
2007 |
Swaps | 7,500 Mmbtu/day | $ | 6.86 | ||||||||
2007 |
Collars | 83,500 Mmbtu/day | $ | 6.93 - $9.63 | ||||||||
2008 |
Collars | 30,000 Mmbtu/day | $ | 7.81 - $11.65 | ||||||||
Crude Oil |
||||||||||||
2006 |
Swaps | 400 bbl/day | $ | 35.00 | ||||||||
2006 |
Collars | 6,864 bbl/day | $ | 39.83 - $49.05 | ||||||||
2007 |
Collars | 4,800 bbl/day | $ | 51.42 - $61.87 | ||||||||
2008 |
Collars | 1,500 bbl/day | $ | 50.00 - $74.12 | ||||||||
We use interest rate swap agreements to manage the risk that interest payments on amounts
outstanding under the variable rate bank credit facility may be adversely affected by volatility in
market interest rates. Under interest rate swap agreements, we agree to pay an amount equal to a
specified fixed rate of interest times a notional principal amount, and to receive in return, a
specified variable rate of interest times the same notional principal amount. Our interest rate
swaps are not designated as hedges and are marked to market each month as a component of interest
expense. At December 31, 2005, we had interest rate swap agreements totaling $35.0 million. These
swaps consist of two agreements at 1.8% which expire in June 2006. The fair value of the swaps at
December 31, 2005, was an asset of $425,000 based on current quotes. On December 31, 2005, the
90-day LIBOR rate was 4.5%.
The combined fair value of net losses on oil and gas derivatives and net gains on interest
rate swaps totaling $230.6 million appears as unrealized derivative gains and unrealized derivative
losses on our consolidated balance sheet at December 31, 2005. Hedging activities are conducted
with major financial or commodities trading institutions which we believe are acceptable credit
risk. At times, such risk may be concentrated with certain counterparties. The credit worthiness
of these counterparties is subject to continuing review.
(9) COMMITMENTS AND CONTINGENCIES
We are involved in various legal actions and claims arising in the ordinary course of
business, the largest of which is Jack Freeman, et al. v. Great Lakes Energy Partners L.L.C., et
al., a class-action suit filed in 2000 which is currently pending against Great Lakes and Range in
the state court of Chautauqua County, New York. The plaintiffs were seeking to recover actual
damages and expenses plus punitive damages based on allegations that we sold gas to affiliates and
gas marketers at low prices, that inappropriate post production expenses were used to reduce
proceeds to the royalty owners and that improper accounting was used for the royalty owners’ share
of gas. A negotiated and pending settlement of this suit is pending the judge’s review. An
estimated settlement of $725,000 is reflected in general and administrative expense in the twelve
months ended December 31, 2005. In management’s opinion, we are not involved in any litigation,
the outcome of which would have a material adverse effect on our financial position, results of
operations or liquidity.
F-21
Table of Contents
We lease certain office space and equipment under cancelable and non-cancelable leases, most
of which expire within three years and may be renewed. Rent expense under such arrangements
totaled $2.2 million, $1.7 million and $1.6 million in 2005, 2004 and 2003, respectively. We
periodically enter into arrangements to purchase seismic data over several years. These
commitments total $400,000 in both 2006 and 2007. Future minimum rental commitments under
non-cancelable leases having remaining non-cancelable lease terms in excess of one year are as
follows (in thousands):
| Operating | ||||
| Lease | ||||
| Obligations | ||||
2006 |
$ | 2,953 | ||
2007 |
2,018 | |||
2008 |
1,604 | |||
2009 |
1,297 | |||
2010 and thereafter |
563 | |||
| $ | 8,435 | |||
(10) CAPITAL STOCK
We have authorized capital stock of 260 million shares which includes 250 million shares of
common stock and 10 million shares of preferred stock. All shares have been adjusted for the
three-for-two common stock split effected on December 2, 2005. All common stock shares and
treasury shares have been retroactively restated to reflect this stock split.
The following is a schedule of changes in the number of outstanding common shares since the
beginning of 2004:
| Year Ended December 31, | ||||||||
| 2005 | 2004 | |||||||
Beginning balance |
121,829,027 | 84,614,687 | ||||||
Issuances: |
||||||||
Public offerings |
6,900,000 | 26,910,000 | ||||||
In lieu of fees and bonuses |
25,590 | 45,688 | ||||||
Stock options exercised |
1,105,549 | 1,251,806 | ||||||
Restricted stock grants |
— | 121,350 | ||||||
Deferred compensation plan |
20,885 | 5,506 | ||||||
Contributed to 401(k) Plan |
33,018 | 56,460 | ||||||
Fractional
shares |
(1,023 | ) | — | |||||
Exchanged for: |
||||||||
5.9% Convertible Preferred |
— | 8,823,530 | ||||||
| 8,084,019 | 37,214,340 | |||||||
Total |
129,913,046 | 121,829,027 | ||||||
Treasury shares |
(5,826 | ) | — | |||||
Ending balance |
129,907,220 | 121,829,027 | ||||||
In June 2005, we completed a public offering of 6.9 million shares of common stock at $16.51
per share. Net proceeds from the offering of $109.2 million funded our acquisition of the Permian
basin properties. In December 2004, we completed a public offering of 8.6 million shares of common
stock at $12.49 per share. Net proceeds from the offering of $103.2 million funded our acquisition
of Pine Mountain. In June 2004, we completed a public offering of 18.3 million shares of common
stock at $8.17 per share. Net proceeds from the offering and net proceeds from the concurrent sale
of $100.0 million of our 7.375% Notes were used to fund our acquisition of Great Lakes (See also
Note 4).
Treasury Stock
During 2005, we bought in open market purchases, 201,000 shares at an average price of $14.00.
As of December 31, 2005, 195,000 of these shares had been used for equity compensation. The board
of directors has approved of up to $5.0 million of additional repurchases of common stock based on
market conditions and opportunities.
F-22
Table of Contents
Shelf Registration Statement
In 2004, we filed a new universal shelf registration statement with the SEC registering $500.0
million aggregate amount of common stock, preferred stock and other equity and debt securities. In
2004, we issued 8.6 million shares of common stock under the shelf registration for an aggregate
price of $107.8 million. In 2005, we issued 6.9 million shares of common stock under the shelf
registration for an aggregate price of $113.9 million. As of December 31, 2005, we have $278.3
million of capacity remaining under the shelf.
(11) EMPLOYEE BENEFIT AND EQUITY PLANS
Stock and Option Plans
We have five equity plans, of which two are active. Under the active plans, incentive and
non-qualified options, stock appreciation rights (SARs), restricted stock awards, phantom stock
rights and annual cash incentive awards may be issued to directors and employees pursuant to
decisions of the Compensation Committee of the Board of Directors which is made up of outside
independent directors. Information with respect to stock option and SARs activity is summarized
below:
| Weighted | ||||||||
| Average | ||||||||
| Exercise | ||||||||
| Shares | Price | |||||||
Outstanding at December 31, 2002 |
4,923,216 | $ | 3.15 | |||||
Granted |
2,535,600 | 3.95 | ||||||
Exercised |
(1,031,827 | ) | 2.37 | |||||
Expired/canceled |
(680,286 | ) | 3.64 | |||||
Outstanding at December 31, 2003 |
5,746,703 | 3.58 | ||||||
Granted |
2,514,750 | 7.74 | ||||||
Exercised |
(1,252,905 | ) | 3.46 | |||||
Expired/canceled |
(135,443 | ) | 5.14 | |||||
Outstanding at December 31, 2004 |
6,873,105 | 5.09 | ||||||
Granted |
3,141,937 | 16.96 | ||||||
Exercised |
(1,105,549 | ) | 4.84 | |||||
Expired/canceled |
(167,188 | ) | 9.08 | |||||
Outstanding at December 31, 2005
(a) |
8,742,305 | $ | 9.31 | |||||
| (a) Includes options outstanding under our inactive plans of 6,647,704 under the 1999 stock option plan, 324,000 under the outside director’s stock option plan and 116,474 under the 1989 stock option plan. Outstanding at December 31, 2005 includes 1,570,125 of SARs. | ||
The following table shows information with respect to outstanding stock options and SARs
at December 31, 2005:
| Outstanding | Exercisable | |||||||||||||||||||
| Weighted- | Weighted | |||||||||||||||||||
| Average | Weighted- | Average | ||||||||||||||||||
| Range of | Remaining | Average | Exercise | |||||||||||||||||
| Exercise Prices | Shares | Contractual Life | Exercise Price | Shares | Price | |||||||||||||||
| $ 1.29 – $ 4.99 | 3,547,096 | 3.57 | $ | 3.58 | 3,351,226 | $ | 3.55 | |||||||||||||
5.00
– 9.99 |
1,720,108 | 3.17 | 7.02 | 970,361 | 7.02 | |||||||||||||||
10.00
– 14.99 |
458,863 | 3.95 | 11.46 | 155,518 | 12.78 | |||||||||||||||
15.00
– 19.99 |
2,904,488 | 4.32 | 16.73 | 871,329 | 16.73 | |||||||||||||||
20.00
– 24.99 |
30,000 | 4.76 | 22.79 | — | — | |||||||||||||||
25.00
– 29.99 |
81,750 | 4.87 | 25.80 | — | — | |||||||||||||||
Total |
8,742,305 | 3.78 | $ | 9.31 | 5,348,434 | $ | 6.60 | |||||||||||||
F-23
Table of Contents
Restricted Stock Grants
In 2005, we issued 192,500 shares of restricted stock grants (from treasury stock) as
compensation to directors, officers and employees, at an average
price of $22.47. The restricted
grants included 26,200 issued to directors, which vest immediately, and 166,300 to officers and key
employees with vesting over a three-to-four year period. In 2004, we issued 121,400 shares of restricted
stock grants as compensation to directors, officers and employees, at an average price of $7.93.
The restricted grants included 36,000 issued to directors, which vest immediately, and 85,400 to
officers and key employees with vesting over a three-year period. During 2003, we issued 351,000
restricted shares of common stock as compensation to directors, officers and key employees at an
average price of $4.27. The restricted share awards included 204,000 that were granted to
directors, which vested immediately, and 147,000 to officers and employees with vesting over a
three-year period. We recorded compensation expense of $942,000, $567,000 and $191,000 in the
twelve months ended December 31, 2005, 2004 and 2003, respectively, for restricted stock grants.
401(k) Plan
We maintain a 401(k) Plan for our employees. The 401(k) Plan permits employees to contribute
up to 50% of their salary (subject to Internal Revenue Service limitations) on a pretax basis.
Historically, we have made discretionary contributions of our common stock to the 401(k) Plan
annually. In 2005, we began matching contributions of up to 3% of salary in cash with the
remainder of our contribution in common stock. All our contributions become fully vested after the
individual employee has three years of service with us. Great Lakes also maintained a 401(k) plan
for its employees which was merged into our plan effective January 1, 2005. In 2005, 2004 and
2003, we contributed $1.5 million, $1.2 million and $912,000, respectively, to the 401(k) Plan. We
do not require that employees hold the contributed Range stock in their account. Employees have a
variety of investment options in the 401(k) Plan. Employees may, at anytime, diversify out of our
stock, based on their personal investment strategy.
Stock Purchase Plan
In 1997, stockholders approved a stock purchase plan which authorized the sale of up to 1.75
million shares of common stock to officers, directors, key employees and consultants. Under the
stock purchase plan, the right to purchase shares may be granted at prices ranging from 50% to 85%
of market value. At December 31, 2005, there were no rights outstanding to purchase shares and
there were 373,000 remaining shares authorized to be granted.
Deferred Compensation Plan
In 1996, the Board of Directors adopted a deferred compensation plan or the Plan. The Plan
gives directors, certain officers and key employees the ability to defer all or a portion of their
salaries and bonuses and invests in Range common stock or makes other investments at the
individual’s discretion. Great Lakes also had a deferred compensation plan that allowed certain
employees to defer all or a portion of their salaries and bonuses and invest such amounts in
certain investments at the employee’s discretion. In December 2004, we adopted the Range Resources
Corporation Deferred Compensation Plan, or the 2005 Deferred Compensation Plan. The 2005 Deferred
Compensation Plan is intended to operate in a manner substantially similar to the old plans,
subject to new requirements and changes mandated under Section 409A of the Internal Revenue Code.
The old plans were frozen and will not receive additional contributions. The assets of all of the
plans are held in a rabbi trust, which we refer to as the Rabbi Trust, and are therefore available
to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock held in
the Rabbi Trust is treated in a manner similar to treasury stock with an offsetting amount
reflected as a deferred compensation liability and the carrying value of the deferred compensation
plan liability is adjusted to fair value each reporting period by a charge or credit to non-cash
stock compensation expense category on our consolidated statement of operations. The assets of the
Rabbi Trust, other than our common stock, are invested in marketable securities and reported at
market value in other assets on our consolidated balance sheet. The deferred compensation
liability on our consolidated balance sheet reflects the market value of the securities held in the
Rabbi Trust. The cost of common stock held in the Rabbi Trust is shown as a reduction to
stockholder’s equity. Changes in the market value of the marketable securities are reflected in
OCI, while changes in the market value of our common stock held in the Rabbi Trust is charged or
credited to non-cash stock compensation expense each quarter. We recorded mark-to-market expenses
related to deferred compensation of $29.5 million in 2005, $19.2 million in 2004 and $6.6 million
in 2003. Since we actually issue the common shares to the Rabbi Trust, we do not incur additional
cash expense other than the original fair market value of the stock when issued.
F-24
Table of Contents
(12) INCOME TAXES
Our income tax expense for the years ended December 31, 2005, 2004 and 2003, was $66.4
million, $24.5 million and $18.5 million, respectively. In addition, $2.4 million of tax expense
was recognized as part of the cumulative effect of changes in accounting principles at December 31,
2003. A reconciliation between the statutory federal income tax rate and our effective income tax
rate is as follows:
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (in thousands) | ||||||||||||
Federal statutory tax rate |
35 | % | 35 | % | 35 | % | ||||||
State |
2 | 2 | 2 | |||||||||
Consolidated effective tax rate |
37 | % | 37 | % | 37 | % | ||||||
Income taxes paid |
$ | 615 | $ | 150 | $ | 110 | ||||||
Income tax provision (benefit) attributable to income before cumulative effect of change in
accounting principle consists of the following:
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (in thousands) | ||||||||||||
Current: |
||||||||||||
U.S. federal |
$ | — | $ | (192 | ) | $ | 191 | |||||
U.S. state and local |
1,071 | (53 | ) | (21 | ) | |||||||
| $ | 1,071 | $ | (245 | ) | $ | 170 | ||||||
Deferred: |
||||||||||||
U.S. federal |
$ | 61,767 | $ | 23,450 | $ | 17,329 | ||||||
U.S. state and local |
3,530 | 1,340 | 990 | |||||||||
| $ | 65,297 | $ | 24,790 | $ | 18,319 | |||||||
Significant components of deferred tax liabilities and assets are as follows:
| December 31, | ||||||||
| 2005 | 2004 | |||||||
| (in thousands) | ||||||||
Deferred tax assets |
||||||||
Net operating loss carryover |
$ | 76,944 | $ | 82,206 | ||||
Allowance for doubtful accounts |
1,166 | 1,303 | ||||||
Net unrealized loss in OCI |
85,462 | 25,930 | ||||||
Deferred compensation |
27,721 | 13,329 | ||||||
AMT credits and other |
44,738 | 14,414 | ||||||
Total deferred tax assets |
236,031 | 137,182 | ||||||
Deferred tax liabilities |
||||||||
Depreciation and depletion |
(346,070 | ) | (225,142 | ) | ||||
Valuation allowance |
(3,101 | ) | (3,443 | ) | ||||
Total deferred tax liabilities |
(349,171 | ) | (228,585 | ) | ||||
Net deferred tax liability |
$ | (113,140 | ) | $ | (91,403 | ) | ||
F-25
Table of Contents
At December 31, 2005, deferred tax liabilities exceeded deferred tax assets by $113.1 million,
with $85.5 million of deferred tax assets related to net deferred hedging losses included in OCI.
A portion of our deferred tax assets relate to items which are capital assets, which upon
disposition will result in capital losses. Due to the uncertainty related to the utilization of
the capital loss, a valuation allowance was recognized in the amount of $3.1 million.
At December 31, 2005, we had regular net operating loss (“NOL”) carryovers of $207.2 million
and alternative minimum tax (“AMT”) NOL carryovers of $179.2 million that expire between 2012 and
2025. Regular NOLs generally offset taxable income and to such extent, no income tax payments are
required. We have $26.9 million of NOLs generated in years prior to 1998 which are subject to
yearly limitations due to IRC Section 382. We do not believe the application of the Section 382
limitation hinders our ability to utilize such NOLs and therefore, no valuation allowance has been
provided. At December 31, 2005, we have AMT credit carryovers of $0.7 million that are not subject
to limitation or expiration.
(13) EARNINGS PER COMMON SHARE
The following table sets forth the computation of basic and diluted earnings per common share
(in thousands, except per share amounts):
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
Numerator: |
||||||||||||
Income before cumulative effect of changes in accounting principles |
$ | 111,011 | $ | 42,231 | $ | 30,924 | ||||||
Preferred stock dividends |
— | (5,163 | ) | (803 | ) | |||||||
Numerator for basic earnings per share before cumulative effect of
changes in accounting principles |
111,011 | 37,068 | 30,121 | |||||||||
Cumulative effect of accounting change |
— | — | 4,491 | |||||||||
Numerator for basic earnings per share |
$ | 111,011 | $ | 37,068 | $ | 34,612 | ||||||
Numerator for diluted earnings per share before cumulative effect
of changes in accounting principles |
$ | 111,011 | $ | 37,068 | $ | 30,924 | ||||||
Cumulative effect of accounting change |
— | — | 4,491 | |||||||||
Numerator for diluted earnings per share after assumed conversions
and cumulative effect of changes in accounting principles |
$ | 111,011 | $ | 37,068 | $ | 35,415 | ||||||
Denominator: |
||||||||||||
Weighted average shares outstanding |
126,339 | 96,050 | 83,694 | |||||||||
Stock held in deferred compensation plan and treasury shares |
(2,209 | ) | (2,506 | ) | (2,286 | ) | ||||||
Weighted average shares, basic |
124,130 | 93,544 | 81,408 | |||||||||
Effect of dilutive securities: |
||||||||||||
Weighted average shares outstanding |
126,339 | 96,050 | 83,694 | |||||||||
Employee stock options and other |
2,863 | 1,948 | 663 | |||||||||
Treasury shares |
(76 | ) | — | — | ||||||||
Common shares assumed for 5.9% convertible preferred stock |
— | — | 2,418 | |||||||||
Dilutive potential common shares for diluted earnings per share |
129,126 | 97,998 | 86,775 | |||||||||
Earnings per share basic and diluted: |
||||||||||||
Before cumulative effect of accounting change |
||||||||||||
Basic |
$ | 0.89 | $ | 0.40 | $ | 0.37 | ||||||
Diluted |
$ | 0.86 | $ | 0.38 | $ | 0.36 | ||||||
After cumulative effect of accounting change |
||||||||||||
Basic |
$ | 0.89 | $ | 0.40 | $ | 0.42 | ||||||
Diluted |
$ | 0.86 | $ | 0.38 | $ | 0.41 | ||||||
Options to purchase 318,200 and 193,350 shares of common stock were outstanding but not
included in the computation of diluted net income per shares for the twelve months ended December
31, 2004 and 2003, respectively, because the exercise prices of the options were greater than the
average market price of the common shares and would be anti-dilutive to the computations. Our 5.9%
convertible preferred stock was antidilutive in the third quarter and the nine months ended
September 30, 2004.
F-26
Table of Contents
(14) MAJOR CUSTOMERS
We market our production on a competitive basis. Gas is sold under various types of contracts
including month-to-month, and one-to-five-year contracts. 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
or is based on NYMEX pricing, adjusted for quality and transportation. We sell to oil and gas
purchasers on the basis of price, credit quality and service. For the twelve months ended December
31, 2005, four customers accounted for 10% or more of total oil and gas revenues and the combined
sales to those four customers accounted for 56% of total oil and gas revenues. For the twelve
months ended December 31, 2004, two customers accounted for 10% or more of total oil and gas
revenues and the combined sales to those two customers accounted for 25% of total oil and gas
revenues. For the year ended December 31, 2003, three customers accounted for 10% or more of total
oil and gas revenue and combined sales to those three customers accounted for 49% of total oil and
gas revenues. We believe that the loss of any one customer would not have a material adverse
effect on our results.
| (15) | SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) |
The following tables set forth unaudited financial information on a quarterly basis for each
of the last two years. Significant producing property acquisitions in 2004 affect the
comparability of the financial data (in thousands, except per share data):
| 2005 | ||||||||||||||||||||
| March | June | September | December | Total | ||||||||||||||||
Revenues |
||||||||||||||||||||
Oil and gas sales |
$ | 107,415 | $ | 118,723 | $ | 142,055 | $ | 156,881 | $ | 525,074 | ||||||||||
Transportation and gathering |
528 | 631 | 758 | 661 | 2,578 | |||||||||||||||
Mark-to-market on oil and gas derivatives |
— | — | — | 10,868 | 10,868 | |||||||||||||||
Other |
17 | 330 | (968 | ) | (1,942 | ) | (2,563 | ) | ||||||||||||
Total revenues |
107,960 | 119,684 | 141,845 | 166,468 | 535,957 | |||||||||||||||
Costs and expenses |
||||||||||||||||||||
Direct operating |
14,808 | 17,419 | 16,676 | 17,729 | 66,632 | |||||||||||||||
Production and ad valorem taxes |
5,755 | 7,034 | 8,457 | 10,270 | 31,516 | |||||||||||||||
Exploration |
3,271 | 9,124 | 7,174 | 9,868 | 29,437 | |||||||||||||||
General and administrative |
6,603 | 6,241 | 7,183 | 9,405 | 29,432 | |||||||||||||||
Non-cash stock compensation |
4,067 | 5,276 | 20,118 | 5,789 | 35,250 | |||||||||||||||
Interest expense and dividends on trust preferred |
8,584 | 9,547 | 9,910 | 10,756 | 38,797 | |||||||||||||||
Depletion, depreciation and amortization |
29,762 | 30,436 | 32,900 | 34,416 | 127,514 | |||||||||||||||
Total costs and expenses |
72,850 | 85,077 | 102,418 | 98,233 | 358,578 | |||||||||||||||
Income before income taxes |
35,110 | 34,607 | 39,427 | 68,235 | 177,379 | |||||||||||||||
Income tax |
||||||||||||||||||||
Current |
— | — | 331 | 740 | 1,071 | |||||||||||||||
Deferred |
13,107 | 12,946 | 14,431 | 24,813 | 65,297 | |||||||||||||||
| 13,107 | 12,946 | 14,762 | 25,553 | 66,368 | ||||||||||||||||
Net income |
$ | 22,003 | $ | 21,661 | $ | 24,665 | $ | 42,682 | $ | 111,011 | ||||||||||
Earnings per common share: |
||||||||||||||||||||
Basic |
$ | 0.18 | $ | 0.18 | $ | 0.19 | $ | 0.33 | $ | 0.89 | ||||||||||
Diluted |
$ | 0.18 | $ | 0.17 | $ | 0.19 | $ | 0.32 | $ | 0.86 | ||||||||||
F -27
Table of Contents
| 2004 | ||||||||||||||||||||
| March | June | September | December | Total | ||||||||||||||||
Revenues |
||||||||||||||||||||
Oil and gas sales |
$ | 65,368 | $ | 67,553 | $ | 85,574 | $ | 97,208 | $ | 315,703 | ||||||||||
Transportation and gathering |
467 | 344 | 296 | 1,095 | 2,202 | |||||||||||||||
Gain on retirement of securities |
— | (34 | ) | (5 | ) | — | (39 | ) | ||||||||||||
Other |
(2,302 | ) | 833 | 349 | 3,961 | 2,841 | ||||||||||||||
Total revenue |
63,533 | 68,696 | 86,214 | 102,264 | 320,707 | |||||||||||||||
Costs and expenses |
||||||||||||||||||||
Direct operating |
9,995 | 10,406 | 12,718 | 13,189 | 46,308 | |||||||||||||||
Production and ad valorem taxes |
4,250 | 4,801 | 5,331 | 6,122 | 20,504 | |||||||||||||||
Exploration |
3,567 | 4,200 | 4,615 | 8,837 | 21,219 | |||||||||||||||
General and administrative |
4,436 | 5,052 | 5,301 | 5,845 | 20,634 | |||||||||||||||
Non-cash stock compensation |
4,385 | 4,303 | 4,829 | 5,659 | 19,176 | |||||||||||||||
Interest expense and dividends on trust preferred |
4,145 | 4,422 | 6,913 | 7,639 | 23,119 | |||||||||||||||
Depletion, depreciation and amortization |
22,248 | 22,444 | 26,306 | 31,973 | 102,971 | |||||||||||||||
Total costs and expenses |
53,026 | 55,628 | 66,013 | 79,264 | 253,931 | |||||||||||||||
Income before income taxes |
10,507 | 13,068 | 20,201 | 23,000 | 66,776 | |||||||||||||||
Income tax (benefit) |
||||||||||||||||||||
Current |
— | 44 | (132 | ) | (157 | ) | (245 | ) | ||||||||||||
Deferred |
3,887 | 4,835 | 7,454 | 8,614 | 24,790 | |||||||||||||||
| 3,887 | 4,879 | 7,322 | 8,457 | 24,545 | ||||||||||||||||
Net income |
6,620 | 8,189 | 12,879 | 14,543 | 42,231 | |||||||||||||||
Preferred dividends |
(738 | ) | (737 | ) | (737 | ) | (2,951 | ) | (5,163 | ) | ||||||||||
Net income available to common stockholders |
$ | 5,882 | $ | 7,452 | $ | 12,142 | $ | 11,592 | $ | 37,068 | ||||||||||
Earnings per common share |
||||||||||||||||||||
Basic |
$ | 0.07 | $ | 0.09 | $ | 0.12 | $ | 0.11 | $ | 0.40 | ||||||||||
Diluted |
$ | 0.07 | $ | 0.08 | $ | 0.11 | $ | 0.11 | $ | 0.38 | ||||||||||
| (16) | SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES |
The following information concerning our natural gas and oil operations has been provided
pursuant to Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas
Producing Activities”, or SFAS 69. Our natural gas and oil producing activities are conducted
onshore within the continental United States and offshore in the Gulf of Mexico.
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (in thousands) | ||||||||||||
Oil and gas properties: |
||||||||||||
Properties subject to depletion |
$ | 2,519,454 | $ | 2,082,236 | $ | 1,350,616 | ||||||
Unproved properties |
28,636 | 14,790 | 12,195 | |||||||||
Total |
2,548,090 | 2,097,026 | 1,362,811 | |||||||||
Accumulated depreciation, depletion and
amortization |
(806,908 | ) | (694,667 | ) | (639,429 | ) | ||||||
Net capitalized costs |
$ | 1,741,182 | $ | 1,402,359 | $ | 723,382 | ||||||
| (a) | Includes capitalized asset retirement costs and the associated accumulated amortization. |
F -28
Table of Contents
Costs Incurred for Property Acquisition, Exploration and Development (a)
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (in thousands) | ||||||||||||
Acquisitions: |
||||||||||||
Acreage purchases |
$ | 20,674 | $ | 9,690 | $ | 5,580 | ||||||
Unproved leasehold |
— | 4,043 | — | |||||||||
Proved oil and gas properties |
131,748 | 522,126 | 88,588 | |||||||||
Purchase price adjustment (b) |
20,966 | 79,352 | — | |||||||||
Asset retirement obligations |
119 | 17,524 | 2,135 | |||||||||
Development |
252,574 | 144,007 | 80,482 | |||||||||
Exploration (c) |
59,539 | 31,830 | 22,564 | |||||||||
Gas gathering facilities: |
||||||||||||
Acquisitions |
8 | 15,539 | 4,622 | |||||||||
Development |
11,415 | 4,778 | 2,951 | |||||||||
Subtotal |
497,043 | 828,889 | 206,922 | |||||||||
Asset retirement obligations |
(1,730 | ) | 3,994 | 4,597 | ||||||||
Total costs incurred |
$ | 495,313 | $ | 832,883 | $ | 211,519 | ||||||
| (a) | Includes cost incurred whether capitalized or expensed. | |
| (b) | Represents non-cash gross up to account for differences in book and tax basis. | |
| (c) | Includes $29,437, $21,219 and $13,946 of exploration costs expensed in 2005, 2004 and 2003, respectively. |
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)
Reserves of crude oil, condensate, natural gas liquids and natural gas are estimated by our
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 SEC 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
developed reserves are those proved reserves which can be expected to be recovered from existing
wells with existing equipment and operating methods. 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.
The reported value of proved reserves is not necessarily indicative of either fair market
value or present value of future net 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 realized prices used at December 31, 2005 to estimate reserve information were
$57.80 per barrel for oil, $36.00 per barrel for natural gas liquids and $9.83 per mcf for gas,
using benchmark prices of $61.04 per barrel and $10.08 per Mmbtu. The average realized prices used
at December 31, 2004 to estimate reserve information were $40.44 per barrel for oil, $25.05 per
barrel for natural gas liquids and $6.05 per mcf for gas, using benchmark prices of $43.33 per
barrel and $6.18 per Mmbtu. The average prices used at December 31, 2003 to estimate reserve
information were $29.48 per barrel for oil, $19.93 per barrel for natural gas liquids and $6.03 per
mcf for gas, using benchmark prices of $32.52 per barrel and $6.19 per Mmbtu.
F -29
Table of Contents
| Crude Oil | Natural Gas | |||||||||||
| and NGLs | Natural Gas | Equivalents | ||||||||||
| (Mbbls) | (Mmcf) | (Mmcfe) | ||||||||||
Proved developed and undeveloped reserves: |
||||||||||||
Balance, December 31, 2002 |
22,952 | 440,267 | 577,977 | |||||||||
Revisions |
445 | 4,625 | 7,294 | |||||||||
Extensions, discoveries and additions |
3,331 | 48,364 | 68,351 | |||||||||
Purchases |
8,758 | 37,734 | 90,284 | |||||||||
Sales |
(39 | ) | (1,076 | ) | (1,312 | ) | ||||||
Production |
(2,424 | ) | (43,510 | ) | (58,053 | ) | ||||||
Balance, December 31, 2003 |
33,023 | 486,404 | 684,541 | |||||||||
Revisions |
(312 | ) | (24,251 | ) | (26,111 | ) | ||||||
Extensions, discoveries and additions |
5,515 | 122,790 | 155,875 | |||||||||
Purchases |
7,062 | 421,775 | 464,149 | |||||||||
Sales |
(3,622 | ) | (9,568 | ) | (31,303 | ) | ||||||
Production |
(3,500 | ) | (50,722 | ) | (71,726 | ) | ||||||
Balance, December 31, 2004 |
38,166 | 946,428 | 1,175,425 | |||||||||
Revisions |
2,499 | 809 | 15,802 | |||||||||
Extensions, discoveries and additions |
7,932 | 169,785 | 217,377 | |||||||||
Purchases |
2,343 | 71,569 | 85,626 | |||||||||
Sales |
(5 | ) | (177 | ) | (205 | ) | ||||||
Production |
(4,043 | ) | (63,004 | ) | (87,263 | ) | ||||||
Balance, December 31, 2005 |
46,892 | 1,125,410 | 1,406,762 | |||||||||
Proved developed reserves: |
||||||||||||
December 31, 2003 |
24,912 | 344,187 | 493,659 | |||||||||
December 31, 2004 |
27,715 | 580,006 | 746,299 | |||||||||
December 31, 2005 |
33,029 | 724,876 | 923,050 | |||||||||
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
(Unaudited)
The following summarizes the policies we used in the preparation of the accompanying natural
gas and oil reserve disclosures, standardized measures of discounted future net cash flows from
proved natural gas and oil reserves and the reconciliations of standardized measures from year to
year. The information disclosed, as prescribed by SFAS 69, is an attempt to present the
information in a manner comparable with industry peers.
The information is based on estimates of proved reserves attributable to our interest in
natural gas and oil properties as of December 31 of the years presented. These estimates were
prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural
gas and crude oil which geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and operating conditions.
The standardized measure of discounted future net cash flows from production of proved
reserves was developed as follows:
| 1. | Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions. | ||
| 2. | Estimated future cash inflows are calculated by applying current year-end prices of natural gas and oil relating to our proved reserves to the quantities of those reserves produced in each future year. | ||
| 3. | Future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. |
F -30
Table of Contents
| 4. | Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the natural gas and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves. | ||
| 5. | The resulting future net cash flows are discounted to present value by applying a discount rate of 10%. |
The standardized measure of discounted future net cash flows does not purport, nor should it
be interpreted, to present the fair value of our natural gas and oil reserves. An estimate of fair
value would also take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a discount factor more
representative of the time value of money and the risks inherent in reserve estimates.
The standardized measure of discounted future net cash flows relating to proved natural gas
and oil reserves is as follows and does not include cash flows associated with hedges outstanding
at each of the respective reporting dates.
| Year Ended December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (in thousands) | ||||||||||||
Future cash inflows |
$ | 13,520,985 | $ | 7,109,349 | $ | 3,803,479 | ||||||
Future costs: |
||||||||||||
Production |
(2,266,828 | ) | (1,472,484 | ) | (842,052 | ) | ||||||
Development |
(825,261 | ) | (601,447 | ) | (274,029 | ) | ||||||
Future net cash flows before income taxes |
10,428,896 | 5,035,418 | 2,687,398 | |||||||||
Future income tax expense |
(3,496,799 | ) | (1,523,915 | ) | (740,965 | ) | ||||||
Total future net cash flows before 10% discount |
6,932,097 | 3,511,503 | 1,946,433 | |||||||||
10% annual discount |
(3,547,787 | ) | (1,762,092 | ) | (943,452 | ) | ||||||
Standardized measure of discounted future net cash flows |
$ | 3,384,310 | $ | 1,749,411 | $ | 1,002,981 | ||||||
The following table summarizes changes in the standardized measure of discounted future net cash flows.
| As of December 31, | ||||||||||||
| 2005 | 2004 | 2003 | ||||||||||
| (in thousands) | ||||||||||||
Beginning of period |
$ | 1,749,411 | $ | 1,002,981 | $ | 499,633 | ||||||
Revisions to previous estimates: |
||||||||||||
Changes in prices |
1,633,812 | 129,916 | 160,932 | |||||||||
Revisions in quantities |
59,244 | (59,591 | ) | 267,906 | ||||||||
Changes in future development costs |
(367,732 | ) | (399,562 | ) | (100,656 | ) | ||||||
Accretion of discount |
239,636 | 139,582 | 96,361 | |||||||||
Net change in income taxes |
(856,115 | ) | (254,114 | ) | (103,375 | ) | ||||||
Purchases of reserves in place |
321,022 | 1,059,294 | 145,772 | |||||||||
Additions to proved reserves from extensions,
discoveries and improved recovery |
814,973 | 355,742 | 110,358 | |||||||||
Production |
(425,902 | ) | (248,891 | ) | (177,085 | ) | ||||||
Development costs incurred during the period |
143,918 | 72,144 | 51,005 | |||||||||
Sales of natural gas and oil |
(769 | ) | (71,441 | ) | (2,117 | ) | ||||||
Timing and other |
72,812 | 23,351 | 54,247 | |||||||||
End of period |
$ | 3,384,310 | $ | 1,749,411 | $ | 1,002,981 | ||||||
F -31
Table of Contents
RANGE RESOURCES CORPORATION
INDEX TO EXHIBITS
| Exhibit No. | Description | |
3.1
|
Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004) as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005) | |
3.2
|
Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.2 to our Form 10K (File No. 001-12209) as filed with the SEC on March 3, 2004) | |
4.1
|
Form of 7.375% Senior Subordinated Notes due 2013 (contained as an exhibit 4.2 hereto) | |
4.2
|
Indenture dated July 21, 2003 by and among Range, as issuer, the Subsidiary Guarantors (as defined herein), as guarantors, and Bank One, National Association, as trustee (incorporated by reference to Exhibit 4.4.2 to our Form 10-Q (File No. 001-12209) as filed with the SEC on August 6, 2003) | |
4.3
|
Form of 6.375% Senior Subordinated Notes due 2015 (contained as exhibit 4.4 hereto) | |
4.4
|
Indenture dated March 9, 2005 by and among Range, as issuer, the Subsidiary Guarantors (as defined herein), as guarantors and J.P.Morgan Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 on our Form 8-K (File No. 001-12209) as filed with the SEC on March 15, 2005) | |
10.1
|
Consulting Agreement dated May 21, 2003 by and between Range and Thomas J. Edelman (incorporated by reference to Exhibit 10.2 to our Form 10-Q (File No. 001-12209) as filed with the SEC on August 6, 2003) | |
10.2
|
Second Amended and Restated Credit Agreement as of June 23, 2004 among Range and Great Lakes Energy Partners L.L.C. (as borrowers) and Bank One NA, and the institutions named (therein) as lenders, Bank One NA as Administrative Agent and Banc One Capital Market, Inc. as Sale Lead Arranger and Bookrunner (incorporated by reference to Exhibit 10.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 29, 2004) | |
10.3
|
First Amendment to the Second Amended and Restated Credit Agreement dated December 6, 2004 among Range and Great Lakes Energy Partners L.L.C.(as borrowers) and J.P.Morgan Chase Bank, N.A. (successor to merger to Bank One, N.A.), a national banking association (J.P.Morgan Chase) and the institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with SEC on December 10, 2004) | |
10.4
|
Second Amendment to the Second Amended and Restated Credit Agreement dated March 2, 2005 among Range and Great Lakes Energy Partners L.L.C. (as borrowers) and J.P.Morgan Chase Bank, N.A. (successor to merger to Bank One, N.A.), a national banking association (J.P.Morgan Chase) and the institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on March 8, 2005) | |
10.5*
|
Third Amendment to the Second Amended and Restated Credit Agreement dated March 2, 2005 among Range and Great Lakes Energy Partners L.L.C. (as borrowers) and J.P.Morgan Chase Bank, N.A. (successor to merger to Bank One, N.A.), a national banking association (J.P.Morgan Chase) and the institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent | |
10.6*
|
Fourth Amendment to the Second Amended and Restated Credit Agreement dated March 2, 2005 among Range and Great Lakes Energy Partners L.L.C. (as borrowers) and J.P.Morgan Chase Bank, N.A. (successor to merger to Bank One, N.A.), a national banking association (J.P.Morgan Chase) and the institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent | |
10.7
|
Range Resources Corporation Deferred Compensation Plan for Directors and Select Employees effective December 28, 2004 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on January 3, 2005) | |
10.8
|
Form of Indemnity Agreement (incorporated by reference to Exhibit 10.5 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 18, 2005) | |
10.9
|
Range Resources Corporation 2005 Equity-Based Compensation (incorporated by reference to Exhibit 10.7 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 18, 2005) | |
10.10
|
First Amendment to the Range Resources Corporation 2005 Equity-Based Compensation Plan (incorporated by reference to Exhibit 10.8 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 18, 2005) | |
10.11
|
Lomak 1989 Stock Option Plan dated March 13, 1989 (incorporated by reference to Exhibit 10.1(d) to Lomak’s Form S-1 (File No. 33-31558) as filed with the SEC on October 13, 1989) |
49
Table of Contents
| Exhibit No. | Description | |
10.12
|
Amendment to the Lomak 1989 Stock Option Plan, as amended (incorporated by reference to Exhibit 4.1 to Lomak’s Form S-8 (File No. 333-10719) as filed with the SEC on August 23, 1996) | |
10.13
|
Amendment to the Lomak 1989 Stock Option Plan, as amended (incorporated by reference to Exhibit 4.2 to Lomak’s Form S-8 (File No. 333-44821) as filed with the SEC on January 23, 1998) | |
10.14
|
Lomak 1994 Outside Directors Stock Option Plan (incorporated by reference to Exhibit 4.2 to Lomak’s Form S-8 (File No. 333-10719) as filed with the SEC on August 23, 1996) | |
10.15
|
First Amendment to the Lomak 1994 Outside Directors Stock Option Plan dated June 8, 1995 (incorporated by reference to Exhibit 4.6 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29, 2000) | |
10.16
|
Second Amendment to the Lomak 1994 Outside Directors Stock Option Plan dated August 21, 1996 (incorporated by reference to Exhibit 4.7 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29, 2000) | |
10.17
|
Third Amendment to the Lomak 1994 Outside Directors Stock Option Plan dated June 1, 1999 (incorporated by reference to Exhibit 4.8 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29, 2000) | |
10.18
|
Fourth Amendment to the Lomak 1994 Outside Directors Stock Plan dated May 24, 2000 (incorporated by reference to Exhibit 4.9 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29, 2000) | |
10.19
|
2004 Non-Employee Director Stock Option Plan dated May 19, 2004 (incorporated by reference to Exhibit 4.2 to our Form S-8 (File No. 333-116320) as filed with the SEC on June 9, 2004) | |
10.20
|
Lomak 1997 Stock Purchase Plan, as amended, dated June 19, 1997 (incorporated by reference to Exhibit 10.1(1) to Lomak’s Form 10-K (File No. 001-12209) as filed with the SEC on March 20, 1998) | |
10.21
|
First Amendment to the Lomak 1997 Stock Purchase Plan dated May 26, 1999 (incorporated by reference to Exhibit 4.2 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29, 2000) | |
10.22
|
Second Amendment to the Lomak 1997 Stock Purchase Plan dated September 28, 1999 (incorporated by reference to Exhibit 4.3 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29, 2000) | |
10.23
|
Third Amendment to the Lomak 1997 Stock Purchase Plan dated May 24, 2000 (incorporated by reference to Exhibit 4.4 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29, 2000) | |
10.24
|
Fourth Amendment to the Lomak 1997 Stock Purchase Plan dated May 24, 2001 (incorporated by reference to Exhibit 4.7 to our Form S-8 (File No. 333-63764) as filed with the SEC on June 25, 2001) | |
10.25
|
Amended and Restated 1999 Stock Option Plan (as amended May 21, 2003) (incorporated by reference to Exhibit 4.1 to our Form S-8 (File No. 333-105895) as filed with the SEC on June 6, 2003) | |
10.26
|
Fourth Amendment to the Amended and Restated 1999 Stock Option Plan dated May 19, 2004 (incorporated by reference to Exhibit 4.1 to our Form S-8 (File No. 333-116320) as filed with the SEC on June 9, 2004) | |
10.27
|
Range Resources Corporation 401(k) Plan (incorporated by reference to Exhibit 10.14 to our Form S-4 (File No. 333-108516) as filed with the SEC on September 4, 2003) | |
10.28
|
Range Resources Corporation Executive Change in Control Severance Benefit Plan dated March 28, 2005 (incorporated by reference to exhibit 10.1 to our Form 8-k (File No. 001-12209) as filed with the SEC on March 31, 2005) | |
14.1
|
Amended Code of Business Conduct and Ethics, as amended (incorporated by reference to Exhibit 10.4 to our Form 8-K (File No. 001-12209) as filed with the SEC on February 22, 2005) | |
21.1*
|
Subsidiaries of Registrant | |
23.1*
|
Consent of Independent Registered Public Accounting Firm | |
23.2*
|
Consent of H.J. Gruy and Associates, Inc., independent consulting engineers | |
23.3*
|
Consent of DeGoyler and MacNaughton, independent consulting engineers | |
23.4*
|
Consent of Wright and Company, independent consulting engineers | |
31.1*
|
Certification by the President and Chief Executive Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
31.2*
|
Certification by the Chief Financial Officer of Range Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
32.1*
|
Certification by the President and Chief Executive Officer of Range Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
32.2*
|
Certification by the Chief Financial Officer of Range Pursuant to 18 U.S.C. Section 350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
| * | Filed herewith. |
50
Exhibit 10.5
EXECUTION VERSION
EXECUTION VERSION
THIRD AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT
This THIRD AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT (hereinafter referred to
as the “Amendment”) executed as of the 15th day of April, 2005, by and among
RANGE RESOURCES CORPORATION, a Delaware corporation (“Company”), GREAT LAKES ENERGY
PARTNERS, L.L.C., a Delaware limited liability company (“GLEP”, together with the Company and each
of their respective successors and permitted assigns, the “Borrowers” and each a
“Borrower”), JPMORGAN CHASE BANK, N.A. (successor by merger to Bank One, N.A. (Illinois)),
a national banking association (“JPMorgan Chase”), each of the financial institutions which
is a party hereto (as evidenced by the signature pages to this Amendment) or which may from time to
time become a party to the Credit Agreement pursuant to the provisions of Section 29 thereof or any
successor or permitted assignee thereof (hereinafter collectively referred to as “Lenders”,
and individually, “Lender”), JPMorgan Chase, as Administrative Agent (in its capacity as
Administrative Agent and together with its successors in such capacity, “Agent”).
Capitalized terms used but not defined in this Amendment have the meanings assigned to such terms
in that certain Second Amended and Restated Credit Agreement dated as of June 23, 2004, by and
among Borrower, Agent and Lenders (as amended, supplemented or otherwise modified from time to
time, the “Credit Agreement”).
WITNESSETH:
WHEREAS, the Borrowers have requested that the Agent and the Lenders amend the Credit
Agreement to (i) extend the Maturity Date and (ii) increase the Borrowing Base; and Agent and the
Lenders have agreed to do so on the terms and conditions hereinafter set forth; and
NOW, THEREFORE, for and in consideration of the mutual covenants and agreements herein
contained and other good and valuable consideration, the receipt and sufficiency of which are
hereby acknowledged and confessed, the Borrowers, Agent and the Lenders, hereby agree as follows:
SECTION 1. Amendments to Credit Agreement. Subject to the satisfaction or waiver in writing of
each condition precedent set forth in Section 3 hereof, and in reliance on the
representations, warranties, covenants and agreements contained in this Amendment, the Credit
Agreement shall be amended in the manner provided in this Section 1.
1.1 Amended Definitions. The following definitions set forth in Section 1 of the Credit
Agreement shall be and they hereby are amended in their entirety to read as follows:
Lender or Lenders are used herein as defined in the preamble hereof and
notwithstanding anything to the contrary in any Security Instrument, for purposes of identifying
the beneficiaries of any Lien granted under any Security Instrument, the terms “Lender” and
“Lenders” shall mean the Persons who are from time to time a “Lender” or “Lenders” as defined in the
Third Amendment to Second Amended and Restated Credit Agreement – Page 1
DALLAS 1508075v4
DALLAS 1508075v4
preamble hereof and the Lender Counterparties.
Maturity Date shall mean January 1, 2009.
1.2 Borrowing Base. Section 7(a) of the Credit Agreement shall be and it hereby is
amended in its entirety to read as follows:
(a) Borrowing Base. Subject to Section 7(b) hereof, the Borrowing Base shall
be $600,000,000.
1.3 Pricing Schedule. The Pricing Schedule to the Credit Agreement shall be amended
in its entirety by substituting the Pricing Schedule which is attached hereto.
1.4 Annex A. Annex A to the Credit Agreement shall be amended in its entirety by
substituting Annex A which is attached hereto.
SECTION 2. Allocation of Borrowing Base Increase and Commitment Percentage Adjustment. The Lenders
have agreed among themselves to allocate the Borrowing Base increase contemplated by this Amendment
among Harris Nesbitt Financing, Inc., Natexis Banques Populaires, Key Bank, Wachovia Bank, National
Association and The Frost National Bank and to increase their interests in the Commitments and the
Loans accordingly. After such reallocation of the Commitments, on the date hereof, the Lenders
shall own the Commitment Percentages set forth on Annex A to the Credit Agreement. Each Lender
shall surrender its existing Note and be issued a new Note in a face amount equal to such Lender’s
Commitment Percentage times $600,000,000. Each said Note to be in the form of Exhibit “B” to the
Credit Agreement with appropriate insertions. The funds delivered to Agent by Harris Nesbitt
Financing, Inc., Natexis Banques Populaires, Key Bank, Wachovia Bank, National Association and The
Frost National Bank to increase their interests in the Commitments and the Loans shall be allocated
such that after giving effect to such allocation each of the Lenders shall own the Commitment
Percentages set forth on Annex A to the Credit Agreement.
SECTION 3. Conditions. The amendments to the Credit Agreement contained in Section 1 of
this Amendment shall be effective upon the satisfaction of each of the conditions set forth in this
Section 3.
3.1 Execution and Delivery. Each Borrower and each Guarantor shall have executed and
delivered this Amendment and each Borrower shall have executed and delivered the fee letter in form
and substance satisfactory to Agent.
3.2 Representations and Warranties. The representations and warranties of each Borrower
under this Amendment are true and correct in all material respects as of such date, as if then made
(except to the extent that such representations and warranties relate solely to an earlier date).
Third Amendment to Second Amended and Restated Credit Agreement — Page 2
DALLAS 1508075v4
DALLAS 1508075v4
3.3 No Event of Default. No Event of Default shall have occurred and be continuing nor shall
any event have occurred or failed to occur which, with the passage of time or service of notice, or
both, would constitute an Event of Default.
3.4 Other Documents. The Agent shall have received such other instruments and documents
incidental and appropriate to the transaction provided for herein as the Agent or its special
counsel may reasonably request, and all such documents shall be in form and substance satisfactory
to the Agent.
3.5 Legal Matters Satisfactory. All legal matters incident to the consummation of the
transactions contemplated hereby shall be reasonably satisfactory to special counsel for the Agent
retained at the expense of the Borrowers.
3.6 Guaranty and Pledge Agreement. The Company shall cause (a) RB Operating Company, a
Delaware corporation (“RBOC”) to execute and deliver to Agent a Guaranty, (b) RBOC to deliver to
Agent (1) an executed officers certificate certifying the names of the officers of RBOC authorized
to sign Loan Documents on behalf of RBOC, together with the true signatures of each such officer,
(2) evidence of the existence and good standing for RBOC in its jurisdiction of incorporation and
evidence of its qualification in each other jurisdiction in which its failure to be qualified could
reasonably be expected to have a Material Adverse Effect, (3) copies of the Organizational
Documents for RBOC together with all amendments thereto, appropriately certified by governmental
authority in the jurisdiction of incorporation of RBOC as being true, correct and complete and (4)
evidence satisfactory to the Agent of the compliance by the Borrowers and each Person of their
obligations under the pledge agreements and the other Security Instruments required under Section 6
of the Credit Agreement (including, without limitation, their obligations to execute and deliver
UCC financing statements, originals of securities or instruments as provided therein); and (c)
Range Energy I, Inc. to deliver to Agent a fully executed pledge agreement covering all of the
issued and outstanding Capital Stock of RBOC in form and substance satisfactory to the Agent.
3.7 Borrowing Base Increase and Extension Fees. In addition to the fees set forth in that
certain fee letter, dated of even date hereof, the Borrowers shall pay to the Agent, (i) for the
ratable benefit of the Lenders increasing their Commitment, a Borrowing Base increase fee equal to
one-quarter of one percent (.25%) of the amount of the $25,000,000 increase in the Borrowing Base
with each such increasing Lender receiving a portion of such fee equal such increasing Lender
portion of the $25,000,000 increase in the Borrowing Base and (ii) for the ratable benefit of the
Lenders, an extension fee equal to one-tenth of one percent (.10%) of the Commitment, which fees
are due and payable on the date hereof.
SECTION 4. Representations and Warranties of Borrowers. To induce the Lenders to enter
into this Amendment, the Borrowers hereby represent and warrant to the Lenders as follows:
4.1 Reaffirmation of Representations and Warranties/Further Assurances. After giving effect
to the amendments herein, each representation and warranty of any Borrower or any Guarantor
contained in the Credit Agreement or in any of the other Loan Documents is true and
Third Amendment to Second Amended and Restated Credit Agreement — Page 3
DALLAS 1508075v4
DALLAS 1508075v4
correct in all
material respects on the date hereof (except to the extent such representations and warranties
relate solely to an earlier date).
4.2 Corporate Authority; No Conflicts. The execution, delivery and performance by each
Borrower and each Guarantor (to the extent a party hereto or thereto) of this Amendment and all
documents, instruments and agreements contemplated herein are within each such Borrower’s or such
Guarantor’s corporate or other organizational powers, have been duly authorized by necessary
action, require no action by or in respect of, or filing with, any court or agency of government
and do not violate or constitute a default under any provision of any applicable law or other
agreements binding upon any Borrower or any Guarantor or result in the creation or imposition of
any Lien upon any of the assets of any Borrower or any Guarantor except for Permitted Liens and
otherwise as permitted in the Credit Agreement.
4.3 Enforceability. This Amendment constitutes the valid and binding obligation of each
Borrower and each Guarantor enforceable in accordance with its terms, except as (i) the
enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting
creditor’s rights generally, and (ii) the availability of equitable remedies may be limited by
equitable principles of general application.
SECTION 5. Miscellaneous.
5.1 Reaffirmation of Loan Documents and Liens. Any and all of the terms and provisions of the
Credit Agreement and the Loan Documents shall, except as amended and modified hereby, remain in
full force and effect. Each Borrower hereby agrees that the amendments and modifications herein
contained shall in no manner affect or impair the liabilities, duties and obligations of such
Borrower or any Guarantor under the Credit Agreement and the other Loan Documents or the Liens
securing the payment and performance thereof.
5.2 Parties in Interest. All of the terms and provisions of this Amendment shall bind and
inure to the benefit of the parties hereto and their respective successors and assigns.
5.3 Post-Closing Covenant. On or before July 1, 2005, the Borrower and each Guarantor, where
applicable, shall execute (1) any and all mortgages requested by Agent to secure the indebtedness,
liabilities and obligations to the Lenders under the Loan Agreement and (2) any and all amendments
to the existing mortgages to reflect the extension of the Maturity Date, both in form and substance
acceptable to the Agent. Borrowers further agree that any failure to comply with and perform this
covenant shall constitute an Event of Default under the Credit Agreement.
5.4 Legal Expenses. The Borrowers hereby agree, jointly and severally, to pay all reasonable
fees and expenses of special counsel to the Agent incurred by the Agent in connection with the
preparation, negotiation and execution of this Amendment and all related documents.
5.5 Counterparts. This Amendment may be executed in one or more counterparts and by different
parties hereto in separate counterparts each of which when so executed and delivered shall be
deemed an original, but all such counterparts together shall constitute but one and the same
instrument; signature pages may be detached from multiple separate counterparts
Third Amendment to Second Amended and Restated Credit Agreement — Page 4
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and attached to a
single counterpart so that all signature pages are physically attached to the same document.
However, this Amendment shall bind no party until the Borrowers, the Lenders, and the Agent have
executed a counterpart. Delivery of photocopies of the signature pages to this Amendment by
facsimile or electronic mail shall be effective as delivery of manually executed counterparts of
this Amendment.
5.6 Complete Agreement. THIS AMENDMENT, THE CREDIT AGREEMENT, AND THE OTHER LOAN DOCUMENTS
REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR,
CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN
THE PARTIES.
5.7 Headings. The headings, captions and arrangements used in this Amendment are, unless
specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the
terms of this Amendment, nor affect the meaning thereof.
[Signature Pages Follow]
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IN WITNESS WHEREOF, the parties have caused this Third Amendment to Amended and Restated
Credit Agreement to be duly executed as of the date first above written.
| BORROWER: | ||||||
| RANGE RESOURCES CORPORATION | ||||||
| a Delaware corporation | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| GREAT LAKES ENERGY PARTNERS, L.L.C. | ||||||
| a Delaware limited liability company | ||||||
| By: | Range Holdco, Inc. | |||||
| Its member | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| By: | Range Energy I, Inc. | |||||
| Its member | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
Third Amendment to Second Amended and Restated Credit Agreement — Signature Page
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| JPMORGAN CHASE BANK, N.A., formerly known as JPMorgan Chase Bank and (successor by merger to Bank One, N.A. (Illinois)), as Agent and a Lender |
||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| BANK OF SCOTLAND | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| CALYON NEW YORK BRANCH | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| COMPASS BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| FLEET NATIONAL BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| FORTIS CAPITAL CORP. | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| NATEXIS BANQUES POPULAIRES | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| COMERICA BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| HIBERNIA NATIONAL BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| AMEGY BANK N.A. (f/k/a Southwest Bank of Texas N.A.) | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| HARRIS NESBITT FINANCING, INC. | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| KEY BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| WACHOVIA BANK, NATIONAL ASSOCIATION | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| UNION BANK OF CALIFORNIA, N.A. | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| THE BANK OF NOVA SCOTIA | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| THE FROST NATIONAL BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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CONSENT AND REAFFIRMATION
The undersigned (each a “Guarantor”) hereby (i) acknowledges receipt of a copy of the
foregoing Third Amendment to Second Amended and Restated Credit Agreement (the “Third
Amendment”); (ii) consents to Borrower’s execution and delivery thereof; (iii) agrees to be
bound thereby; (iv) affirms that nothing contained therein shall modify in any respect whatsoever
its guaranty of the obligations of the Borrower to Lenders pursuant to the terms of its Guaranty in
favor of Agent and the Lenders (the “Guaranty”) and (v) reaffirms that the Guaranty is and
shall continue to remain in full force and effect. Although Guarantor has been informed of the
matters set forth herein and has acknowledged and agreed to same, Guarantor understands that the
Lenders have no obligation to inform Guarantor of such matters in the future or to seek Guarantor’s
acknowledgment or agreement to future amendments or waivers, and nothing herein shall create such
duty.
IN WITNESS WHEREOF, the undersigned has executed this Consent and Reaffirmation on and as of
the date of this Third Amendment.
| GUARANTORS: | ||||||
| RANGE ENERGY I, INC. a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| RANGE HOLDCO, INC. a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| RANGE PRODUCTION COMPANY a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
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| RANGE ENERGY VENTURES CORPORATION, a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| GULFSTAR ENERGY, INC. a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| RANGE ENERGY FINANCE CORPORATION a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
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| RANGE PRODUCTION I, L.P. a Texas limited partnership |
||||||
| By: | RANGE PRODUCTION COMPANY | |||||
| Its general partner | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| RANGE RESOURCES, L.L.C. a Oklahoma limited liability company |
||||||
| By: | RANGE PRODUCTION COMPANY | |||||
| Its member | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| By: | RANGE HOLDCO, INC. | |||||
| Its member | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
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PRICING SCHEDULE
APPLICABLE MARGIN
APPLICABLE MARGIN
| Applicable Margin | ||||||||||||
| for | ||||||||||||
| Applicable Margin | Applicable Margin for | Unused | ||||||||||
| Borrowing Base Usage | for Base Rate Loans | LIBOR Loans | Commitment Fee | |||||||||
Greater than or equal to 90%
|
.50 | % | 1.75 | % | .375 | % | ||||||
Greater than or equal to
75% and less than 90%
|
.25 | % | 1.50 | % | .375 | % | ||||||
Greater than or equal to
50% and less than 75%
|
0 | % | 1.25 | % | .375 | % | ||||||
Less than 50%
|
0 | % | 1.00 | % | .25 | % | ||||||
Third Amendment to Second Amended and Restated Credit Agreement — Pricing Schedule
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ANNEX A
COMMITMENT PERCENTAGES
| LENDER | COMMITMENT PERCENTAGE | |||
JPMorgan Chase Bank, N.A.
|
7.833333333 | % | ||
21 South Clark Street |
||||
Mail Code IL1-0634 |
||||
Chicago, Illinois 60670-0634 |
||||
Attention: Jim Moore |
||||
Telephone:
(312) 385-7057 |
||||
Facsimile:
(312) 385-7096 |
||||
Bank of Scotland
|
7.833333333 | % | ||
565 Fifth Avenue |
||||
New York, New York 10017 |
||||
Attention: Ms. Shirley Vargas |
||||
Telephone: (212) 450-0875 |
||||
Facsimile: (212) 479-2807 |
||||
Compass Bank
|
4.166666667 | % | ||
24 Greenway Plaza, Suite 1400 |
||||
Houston, Texas 77046 |
||||
Attention: Ellan Watkins |
||||
Telephone: (713) 968-8279 |
||||
Facsimile: (713) 968-8292 |
||||
Calyon New York Branch
|
7.833333333 | % | ||
1301 Avenue of the Americas |
||||
New York, New York 10019 |
||||
Attention: Gener David |
||||
Telephone: (212) 261-7741 |
||||
Facsimile: (917) 849-5440 |
||||
Fleet National Bank
|
7.833333333 | % | ||
100 Federal Street, MA DE 10008A |
||||
Boston, Massachusetts 02110 |
||||
Attention: Jeffrey Rathkamp |
||||
Telephone: (617) 434-9061 |
||||
Facsimile: (617) 434-3652 |
||||
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| LENDER | COMMITMENT PERCENTAGE | |||
Fortis Capital Corp.
|
7.833333333 | % | ||
15455 North Dallas Parkway, |
||||
Suite 1400 |
||||
Addison, Texas 75001 |
||||
Attention: Frank Campanelli |
||||
Telephone: (203) 705-5898 |
||||
Facsimile: (203) 705-5888 |
||||
Natexis Banques Populaires
|
5.833333333 | % | ||
Southwest Representative Office |
||||
333 Clay Street, Suite 4340 |
||||
Houston, Texas 77002 |
||||
Attention: Tanya McAllister |
||||
Telephone: (713) 759-9409 |
||||
Facsimile: (713) 571-6165 |
||||
Comerica Bank
|
7.083333333 | % | ||
1601 Elm Street, 2nd Floor |
||||
Dallas, Texas 75201 |
||||
Attention: Michele Jones with a copy to Cathy Watson |
||||
Telephone: (214) 969-6564 |
||||
Facsimile: (214) 969-6561 |
||||
Hibernia National Bank
|
2.500000000 | % | ||
313 Carondelet Street, 10th Floor |
||||
New Orleans, Louisiana 70130 |
||||
Attention: Joyce Baker |
||||
Telephone: (504) 533-5352 |
||||
Facsimile: (504) 533-5434 |
||||
Amegy Bank (f/k/a Southwest Bank of Texas, N.A.)
|
3.333333333 | % | ||
4295 San Felipe |
||||
Houston, Texas 77027 |
||||
Attention: Maxine Hunter |
||||
Telephone: (713) 232-6355 |
||||
Facsimile: (713) 963-7467 |
||||
Harris Nesbitt Financing, Inc.
|
7.833333333 | % | ||
115 S. LaSalle Streeet |
||||
Chicago, Illinois 60603 |
||||
Attention: Terri Mikula |
||||
Telephone:
(312) 750-5947 |
||||
Facsimile:
(312) 750-6061 |
||||
Third Amendment to Second Amended and Restated Credit Agreement — Annex A
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| LENDER | COMMITMENT PERCENTAGE | |||
Key Bank
|
6.000000000 | % | ||
127 Public Square |
||||
Cleveland, Ohio 44114 |
||||
Attention: Anita Anders |
||||
Telephone: (216) 689-4561 |
||||
Facsimile: (216) 689-5962 |
||||
Wachovia Bank, National Association
|
6.000000000 | % | ||
201 S. College, CP-9 |
||||
Charlotte, NC 28288 |
||||
Attention: Cynthia Rawson |
||||
Telephone: (704) 374-4425 |
||||
Facsimile: (704) 715-0097 |
||||
Union Bank of California, N.A. |
7.083333333 | % | ||
1980 Saturn Street, Mail Code |
||||
Monterey Park, California 91755 |
||||
Attention: Maria Suncin |
||||
Telephone: (323) 720-2870 |
||||
Facsimile: (323) 720-2252 |
||||
The Bank of Nova Scotia
|
7.083333333 | % | ||
600 Peachtree St. NE |
||||
Suite 2700 |
||||
Atlanta, Georgia 30308 |
||||
Attention: Jill A. Retess |
||||
Telephone: (404) 877-1544 |
||||
Facsimile: (404) 888-8998 |
||||
The Frost National Bank
|
3.916666667 | % | ||
777 Main Street |
||||
Suite 100 |
||||
Fort Worth, Texas 76102 |
||||
Attention: Karen Moore |
||||
Telephone: (210) 420-5673 |
||||
Facsimile: (210) 420-5250 |
||||
Third Amendment to Second Amended and Restated Credit Agreement — Annex A
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Exhibit 10.6
EXECUTION VERSION
FOURTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT
This FOURTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT (hereinafter referred to
as the “Amendment”) executed as of the 30th day of September, 2005, by and among
RANGE RESOURCES CORPORATION, a Delaware corporation (“Company”), GREAT LAKES ENERGY
PARTNERS, L.L.C., a Delaware limited liability company (“GLEP”, and together with the
Company and each of their respective successors and permitted assigns, the “Borrowers” and
each a “Borrower”), JPMORGAN CHASE BANK, N.A. (successor by merger to Bank One, N.A.
(Illinois)), a national banking association (“JPMorgan Chase”), each of the financial
institutions which is a party hereto (as evidenced by the signature pages to this Amendment) or
which may from time to time become a party to the Credit Agreement pursuant to the provisions of
Section 29 thereof or any successor or permitted assignee thereof (hereinafter collectively
referred to as “Lenders”, and individually, “Lender”), JPMorgan Chase, as
Administrative Agent (in its capacity as Administrative Agent and together with its successors in
such capacity, “Agent”). Capitalized terms used but not defined in this Amendment have the
meanings assigned to such terms in that certain Second Amended and Restated Credit Agreement dated
as of June 23, 2004, by and among Borrower, Agent and Lenders (as amended, supplemented or
otherwise modified from time to time, the “Credit Agreement”).
WITNESSETH:
WHEREAS, the Borrowers have requested that the Agent and the Lenders amend the Credit
Agreement to (i) modify certain Collateral requirements and (ii) reaffirm the Borrowing Base; and
Agent and the Lenders have agreed to do so on the terms and conditions hereinafter set forth; and
NOW, THEREFORE, for and in consideration of the mutual covenants and agreements herein
contained and other good and valuable consideration, the receipt and sufficiency of which are
hereby acknowledged and confessed, the Borrowers, Agent and the Lenders, hereby agree as follows:
SECTION 1. Amendments to Credit Agreement. Subject to the satisfaction or waiver in writing of
each condition precedent set forth in Section 2 hereof, and in reliance on the
representations, warranties, covenants and agreements contained in this Amendment, the Credit
Agreement shall be amended in the manner provided in this Section 1.
1.1 Additional Definition. The following definition shall be and it hereby is added to
Section 1 of the Credit Agreement in correct alphabetical order:
Fourth Amendment means that certain Fourth Amendment to Second Amended and Restated
Loan Agreement, dated September 30, 2005, by and among the Borrowers, the Agent
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and the Lenders.
1.2 Amended Definition. The following definition set forth in Section 1 of the Credit
Agreement shall be and it hereby is amended in its entirety to read as follows:
Oil and Gas Properties means all oil, gas and mineral properties and interests, and
all related personal properties of any Borrower or any Guarantor which are evaluated by the Lenders
for purposes of determining the Borrowing Base.
1.3 Collateral Security. The second sentence of the first paragraph of Section 6 of
the Credit Agreement shall be and it hereby is amended in its entirety to read as follows:
The Oil and Gas Properties heretofore and hereafter assigned and mortgaged to the Agent by
Borrowers and the Guarantors shall represent not less than 70% of the Engineered Value (as
hereinafter defined) of Borrowers’ and Guarantors’ Oil and Gas Properties, taken as a whole.
1.4 Collateral Security. The last sentence of the second paragraph of Section 6 of
the Credit Agreement shall be and it hereby is amended in its entirety to read as follows:
Borrowers will cause to be executed and delivered to the Agent, in the future, additional Security
Instruments if the Agent reasonably deems such are necessary to insure perfection or maintenance of
Lenders’ security interests and Liens in not less than 70% of the Engineered Value of the Oil and
Gas Properties or any part thereof of Borrowers and Guarantors, taken as a whole.
1.5 Borrowing Base. Section 7(a) of the Credit Agreement shall be and it hereby is
amended in its entirety to read as follows:
(a) Borrowing Base. Subject to Section 7(b) hereof, during the period from the
date of the Fourth Amendment to the first Determination Date after the date of the Fourth
Amendment, the Borrowing Base shall be $600,000,000.
1.6 Borrowing Base. Section 7 of the Credit Agreement shall be and it hereby is
amended by inserting the following as clause (c) of such section:
(c) Notice of Redetermination. Promptly following any redetermination of the
Borrowing Base pursuant to this Section 7, the Agent shall notify the Borrowers of the amount
of the redetermined Borrowing Base, which Borrowing Base shall be effective as of the
Determination Date specified in such notice, and such Borrowing Base shall remain in effect
for all purposes of this Agreement until the next Determination Date.
1.7 Additional Collateral. The first sentence of Section 12(v) of the Credit
Agreement shall be and it hereby is amended in its entirety to read as follows:
Borrowers agree to regularly monitor engineering data covering all producing oil and gas properties
and interests owned or acquired by Borrowers and the Guarantors on or after the
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date hereof and to mortgage or cause to be mortgaged such of the same to Agent for the ratable
benefit of the Lenders in substantially the form of the Security Instruments, as applicable, to the
extent that the Lenders shall at all times during the existence of the Commitment be secured by
perfected Liens and security interests covering not less than seventy percent (70%) of the
Engineered Value of the Oil and Gas Properties of Borrowers and the Guarantors, taken as a whole.
1.8 Additional Collateral. The third sentence of Section 12(v) of the Credit
Agreement shall be and it hereby is amended in its entirety to read as follows:
In order to assist Borrowers in monitoring its mortgage coverage, Agent agrees to notify Borrowers
if the Lenders determine that the coverage required by this paragraph ever falls below 70%.
1.9 Additional Collateral. The last sentence of Section 12(v) of the Credit Agreement
shall be and it hereby is amended in its entirety to read as follows:
Upon receipt of any such notice from the Agent, Borrowers shall, within thirty (30) days of
receipt of such notice, execute and deliver, or cause to be executed and delivered, Security
Instruments in form and substance satisfactory to the Agent covering sufficient additional Oil and
Gas Properties to bring the coverage to at least 70%.
SECTION 2. Conditions. The amendments to the Credit Agreement contained in Section 1 of
this Amendment shall be effective upon the satisfaction of each of the conditions set forth in this
Section 2.
2.1 Execution and Delivery. Each Borrower and each Guarantor shall have executed and
delivered this Amendment.
2.2 Representations and Warranties. The representations and warranties of each Borrower under
this Amendment are true and correct in all material respects as of such date, as if then made
(except to the extent that such representations and warranties relate solely to an earlier date).
2.3 No Event of Default. No Event of Default shall have occurred and be continuing nor shall
any event have occurred or failed to occur which, with the passage of time or service of notice, or
both, would constitute an Event of Default.
2.4 Other Documents. The Agent shall have received such other instruments and documents
incidental and appropriate to the transaction provided for herein as the Agent or its special
counsel may reasonably request, and all such documents shall be in form and substance satisfactory
to the Agent.
2.5 Legal Matters Satisfactory. All legal matters incident to the consummation of the
transactions contemplated hereby shall be reasonably satisfactory to special counsel for the Agent
retained at the expense of the Borrowers.
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SECTION 3. Representations and Warranties of Borrowers. To induce the Lenders to enter
into this Amendment, the Borrowers hereby represent and warrant to the Lenders as follows:
3.1 Reaffirmation of Representations and Warranties/Further Assurances. After giving effect
to the amendments herein, each representation and warranty of any Borrower or any Guarantor
contained in the Credit Agreement or in any of the other Loan Documents is true and correct in all
material respects on the date hereof (except to the extent such representations and warranties
relate solely to an earlier date).
3.2 Corporate Authority; No Conflicts. The execution, delivery and performance by each
Borrower and each Guarantor (to the extent a party hereto or thereto) of this Amendment and all
documents, instruments and agreements contemplated herein are within each such Borrower’s or such
Guarantor’s corporate or other organizational powers, have been duly authorized by necessary
action, require no action by or in respect of, or filing with, any court or agency of government
and do not violate or constitute a default under any provision of any applicable law or other
agreements binding upon any Borrower or any Guarantor or result in the creation or imposition of
any Lien upon any of the assets of any Borrower or any Guarantor except for Permitted Liens and
otherwise as permitted in the Credit Agreement.
3.3 Enforceability. This Amendment constitutes the valid and binding obligation of each
Borrower and each Guarantor enforceable in accordance with its terms, except as (i) the
enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting
creditor’s rights generally, and (ii) the availability of equitable remedies may be limited by
equitable principles of general application.
SECTION 4. Miscellaneous.
4.1 Reaffirmation of Loan Documents and Liens. Any and all of the terms and provisions of the
Credit Agreement and the Loan Documents shall, except as amended and modified hereby, remain in
full force and effect. Each Borrower hereby agrees that the amendments and modifications herein
contained shall in no manner affect or impair the liabilities, duties and obligations of such
Borrower or any Guarantor under the Credit Agreement and the other Loan Documents or the Liens
securing the payment and performance thereof.
4.2 Parties in Interest. All of the terms and provisions of this Amendment shall bind and
inure to the benefit of the parties hereto and their respective successors and assigns.
4.3 Legal Expenses. The Borrowers hereby agree, jointly and severally, to pay all reasonable
fees and expenses of special counsel to the Agent incurred by the Agent in connection with the
preparation, negotiation and execution of this Amendment and all related documents.
4.4 Counterparts. This Amendment may be executed in one or more counterparts and by different
parties hereto in separate counterparts each of which when so executed and delivered shall be
deemed an original, but all such counterparts together shall constitute but one and the same
instrument; signature pages may be detached from multiple separate counterparts
Fourth Amendment to Second Amended and Restated Credit Agreement — Page 4
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and attached to a single counterpart so that all signature pages are physically attached to
the same document. However, this Amendment shall bind no party until the Borrowers, the Lenders,
and the Agent have executed a counterpart. Delivery of photocopies of the signature pages to this
Amendment by facsimile or electronic mail shall be effective as delivery of manually executed
counterparts of this Amendment.
4.5 Complete Agreement. THIS AMENDMENT, THE CREDIT AGREEMENT, AND THE OTHER LOAN DOCUMENTS
REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR,
CONTEMPORANEOUS OR ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN
THE PARTIES.
4.6 Headings. The headings, captions and arrangements used in this Amendment are, unless
specified otherwise, for convenience only and shall not be deemed to limit, amplify or modify the
terms of this Amendment, nor affect the meaning thereof.
[Signature Pages Follow]
Fourth Amendment to Second Amended and Restated Credit Agreement — Page 5
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IN WITNESS WHEREOF, the parties have caused this Fourth Amendment to Amended and Restated
Credit Agreement to be duly executed as of the date first above written.
| BORROWER: | ||||||
| RANGE RESOURCES CORPORATION a Delaware corporation |
||||||
| By: | ||||||
| Name: | ||||||
| Title: | Senior Vice President | |||||
| GREAT LAKES ENERGY PARTNERS, L.L.C. a Delaware limited liability company |
||||||
| By: | Range Holdco, Inc. | |||||
| Its member | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| By: | Range Energy I, Inc. | |||||
| Its member | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
Fourth Amendment to Second Amended and Restated Credit Agreement — Signature Page
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| JPMORGAN CHASE BANK, N.A., formerly known as JPMorgan Chase Bank and (successor by merger to Bank One, N.A. (Illinois)), as Agent and a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
Fourth Amendment to Second Amended and Restated Credit Agreement — Signature Page
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| BANK OF SCOTLAND | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| CALYON NEW YORK BRANCH | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| COMPASS BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| FLEET NATIONAL BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| FORTIS CAPITAL CORP. | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| NATEXIS BANQUES POPULAIRES | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| COMERICA BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| HIBERNIA NATIONAL BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| AMEGY BANK N.A. (f/k/a Southwest Bank of Texas N.A.) | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| HARRIS NESBITT FINANCING, INC. | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| KEY BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| WACHOVIA BANK, NATIONAL ASSOCIATION | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| UNION BANK OF CALIFORNIA, N.A. | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| THE BANK OF NOVA SCOTIA | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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| THE FROST NATIONAL BANK | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
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CONSENT AND REAFFIRMATION
The undersigned (each a “Guarantor”) hereby (i) acknowledges receipt of a copy of the
foregoing Fourth Amendment to Second Amended and Restated Credit Agreement (the “Fourth
Amendment”); (ii) consents to Borrower’s execution and delivery thereof; (iii) agrees to be
bound thereby; (iv) affirms that nothing contained therein shall modify in any respect whatsoever
its guaranty of the obligations of the Borrower to Lenders pursuant to the terms of its Guaranty in
favor of Agent and the Lenders (the “Guaranty”) and (v) reaffirms that the Guaranty is and
shall continue to remain in full force and effect. Although Guarantor has been informed of the
matters set forth herein and has acknowledged and agreed to same, Guarantor understands that the
Lenders have no obligation to inform Guarantor of such matters in the future or to seek Guarantor’s
acknowledgment or agreement to future amendments or waivers, and nothing herein shall create such
duty.
IN WITNESS WHEREOF, the undersigned has executed this Consent and Reaffirmation on and as of
the date of this Fourth Amendment.
| GUARANTORS: | ||||||
| RANGE ENERGY I, INC. a Delaware corporation |
||||||
| By: | ||||||
| Name: | ||||||
| Title: | Senior Vice President | |||||
| RANGE HOLDCO, INC. a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| RANGE PRODUCTION COMPANY a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
Fourth Amendment to Second Amended and Restated Credit Agreement — Consent and Reaffirmation
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| RANGE ENERGY VENTURES CORPORATION, a Delaware corporation |
||||||
| By: | ||||||
| Name: | ||||||
| Title: | Senior Vice President | |||||
| GULFSTAR ENERGY, INC. a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| RANGE ENERGY FINANCE CORPORATION a Delaware corporation |
||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
Fourth Amendment to Second Amended and Restated Credit Agreement — Consent and Reaffirmation
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| RANGE PRODUCTION I, L.P. a Texas limited partnership |
||||||
| By: | RANGE PRODUCTION COMPANY | |||||
| Its general partner | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | Senior Vice President | |||||
| RANGE RESOURCES, L.L.C. a Oklahoma limited liability company |
||||||
| By: | RANGE PRODUCTION COMPANY | |||||
| Its member | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
| By: | RANGE HOLDCO, INC. | |||||
| Its member | ||||||
| By: | ||||||
| Name: | Roger S. Manny | |||||
| Title: | Senior Vice President | |||||
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EXHIBIT 21
RANGE RESOURCES CORPORATION
Subsidiaries of Registrant
| Percentage of Voting Securities | ||||
| Name | Jurisdiction of Incorporation | Owned by Immediate Parent | ||
Range Production Company |
Delaware | 100% | ||
Range Energy Services Company |
Delaware | 100% | ||
Range Holdco, Inc. |
Delaware | 100% | ||
Range Energy I, Inc. |
Delaware | 100% | ||
Range Gathering & Processing Company |
Delaware | 100% | ||
Range Gas Company |
Delaware | 100% | ||
RRC Operating Company |
Ohio | 100% | ||
Range Energy Finance Corporation |
Delaware | 100% | ||
Range Energy Ventures Corporation |
Delaware | 100% | ||
Gulfstar Energy, Inc. |
Delaware | 100% | ||
Gulfstar Seismic, Inc. |
Delaware | 100% | ||
Domain Energy International Corporation (a) |
British Virgin Islands | 100% | ||
Energy Assets Operating Company |
Delaware | 100% | ||
Range
Operating New Mexico, Inc. |
Delaware | 100% | ||
PMOG Holdings, Inc. |
Delaware | 100% | ||
Pine Mountain Acquisition, Inc. |
Delaware | 100% | ||
Pine Mountain Oil & Gas, Inc. |
Virginia | 100% | ||
Great Lakes Energy Partners, L.L.C. |
Delaware | 100% | ||
Ohio Interstate Gas Transmission Company |
Ohio | 100% | ||
Victory Energy Partners, L.L.C. |
Texas | 100% |
| (a) | Dormant subsidiary with no assets. |
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FRIM
We consent
to the incorporation by reference in the Registration Statements on Form S-3/A (Nos.
333-76837 and 333-118417), on Form S-4 (Nos. 333-78231,
333-108516, 333-117834 and 333-123534) and on Form
S-8 (Nos. 333-125665, 333-90760, 333-63764, 333-40380, 333-30534, 333-88657, 333-69905, 333-62439,
333-44821, 333-10719, 333-105895 and 333-116320) of Range Resources Corporation and in the related
Prospectuses of our reports dated February 21, 2006 with respect to the consolidated financial
statements of Range Resources Corporation and subsidiaries, Range
Resources Corporation management’s assessment of the
effectiveness of internal control over financial reporting, and the effectiveness of internal
control over financial reporting of Range Resources Corporation and subsidiaries, included in this Annual
Report (Form 10-K) for the year ended December 31, 2005.
/s/ Ernst & Young LLP
Fort Worth, Texas
February 21, 2006
February 21, 2006
EXHIBIT 23.2
CONSENT OF H.J. GRUY AND ASSOCIATES, INC.
We hereby consent to the use of the name H.J. Gruy and Associates, Inc., and of references to
H.J. Gruy and Associates, Inc. and to the inclusion of and references
to our report, or information contained therein, dated February
13, 2006, prepared for Range Resources Corporation in the Range Resources Corporation Annual Report
on Form 10-K for the year ended December 31, 2005. We are unable to verify the accuracy of the
reserves and discounted present worth values contained therein because our estimates of reserves
and discounted present worth have been combined with estimates of reserves and present worth
prepared by other petroleum consultants.
H.J. GRUY AND ASSOCIATES, INC.
February 20,
2006
Houston, Texas
Houston, Texas
EXHIBIT 23.3
CONSENT OF DEGOLYER AND MACNAUGHTON
We
hereby consent to the reference to DeGolyer and MacNaughton under the heading “Item 2. Properties – Proved
Reserves” in the Annual Report on Form 10-K of Range Resources Corporation for the year ended
December 31, 2005, to which this consent is an exhibit. We also consent to the incorporation of
information contained in our “Appraisal Report as of December 31, 2005, of Certain Interests owned
by Range Resources Corporation,” provided, however, that we are necessarily unable to verify the
accuracy of the reserves and discounted present worth values contained therein because our
estimates of reserves and discounted present worth have been combined with estimates of reserves
and present worth prepared by other petroleum consultants.
DEGOLYER AND MACNAUGHTON
Dallas, Texas
February 22, 2006
February 22, 2006
EXHIBIT 23.4
CONSENT
OF WRIGHT & COMPANY, INC.
We hereby consent to the incorporation by reference of our name in the Annual Report on Form
10-K of Range Resources Corporation (the “Company”) for the fiscal year ended December 31, 2005, to
which this consent is an exhibit.
WRIGHT & COMPANY
Brentwood, Tennessee
February 20, 2006
February 20, 2006
EXHIBIT 31.1
CERTIFICATION
I, John H. Pinkerton, certify that:
| 1. | I have reviewed this report on Form 10-K of Range Resources Corporation; | ||
| 2. | Based on my knowledge, this 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 report; | ||
| 3. | Based on my knowledge, the financial statements, and other financial information included in this 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 report; | ||
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
| (c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
| (d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and | ||
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: February 22, 2006
|
/s/ JOHN H. PINKERTON | |||
| President and Chief Executive Officer |
EXHIBIT 31.2
CERTIFICATION
I, Roger S. Manny, certify that:
| 1. | I have reviewed this report on Form 10-K of Range Resources Corporation; | ||
| 2. | Based on my knowledge, this report does not contain any untrue statement of 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 report; | ||
| 3. | Based on my knowledge, the financial statements, and other financial information included in this 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 report; | ||
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have: |
| (a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; | ||
| (b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; | ||
| (c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and | ||
| (d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
| (a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and | ||
| (b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: February 22, 2006
|
/s/ ROGER S. MANNY | |||
| Senior Vice President and Chief Financial Officer |
EXHIBIT 32.1
CERTIFICATION OF
PRESIDENT AND CHIEF EXECUTIVE OFFICER
OF RANGE RESOURCES CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350
PRESIDENT AND CHIEF EXECUTIVE OFFICER
OF RANGE RESOURCES CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350
In connection with the accompanying report on Form 10-K for the period ending December 31,
2005 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I,
John H. Pinkerton, President and Chief Executive Officer of Range Resources Corporation (the
“Company”), hereby certify that:
| 1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and | ||
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
| By: | /s/ JOHN H. PINKERTON | |||||
| February 22, 2006 |
EXHIBIT 32.2
CERTIFICATION OF
CHIEF FINANCIAL OFFICER
OF RANGE RESOURCES CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350
CHIEF FINANCIAL OFFICER
OF RANGE RESOURCES CORPORATION
PURSUANT TO 18 U.S.C. SECTION 1350
In connection with the accompanying report on Form 10-K for the period ending December 31,
2005 and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I,
Roger S. Manny, Chief Financial Officer of Range Resources Corporation (the “Company”), hereby
certify that:
| 1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and | ||
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
| By: | /s/ ROGER S. MANNY | |||||
| February 22, 2006 |