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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, 2006
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
(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, 2006 was
$3,681,364,000.
As of February 20, 2007, there were 139,210,404 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 2007 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, 2006
Annual Report on Form 10-K
Year Ended December 31, 2006
Disclosures Regarding Forward-Looking Statements
Certain information included in this report, other materials filed or to be filed with the
Securities and Exchange Commission (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 2006, our proved reserves had the following characteristics:
| • | 1.8 Tcfe of proved reserves; | ||
| • | 82% natural gas; | ||
| • | 63% proved developed; | ||
| • | 80% operated; | ||
| • | a reserve life of 16.3 years (based on fourth quarter 2006 production); and | ||
| • | a pre-tax present value of $2.8 billion ($2.0 billion after tax). |
At year-end 2006, we owned 3,215,000 gross (2,500,000 net) acres of leasehold, which includes
over 70,000 of acres associated with royalties. We have built a multi-year inventory of drilling
projects which is estimated to be over 9,400 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
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through consistent growth in reserves and production on a cost-efficient basis. During the past
five years, we have increased our proved reserves 243%, while production has increased 81% during
that same period.
Our corporate offices are located at 777 Main Street, Suite 800, Fort Worth, Texas 76102. Our
telephone number is (817) 870-2601. Effective May
1st,
2007, our corporate offices will
be located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102.
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. Our strategy requires us to
make significant investments in technical staff, acreage and seismic data and technology 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 Barnett Shale of North Central Texas, the Permian Basin of West Texas and eastern New Mexico, the East Texas Basin, the Texas Panhandle and Anadarko Basin of Western Oklahoma), Appalachian (which includes tight-gas, shale, coal bed methane and conventional oil and gas production in Pennsylvania, Virginia, Ohio, New York and West Virginia) 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. A large, multi-year inventory of drilling projects increases our ability to consistently grow production and reserves. Currently, we have over 9,400 identified drilling locations in inventory. In 2006, we drilled 1,017 gross (704 net) wells. In 2007, our capital program targets the drilling of 924 gross (691 net) wells. | ||
| • | Make Complementary Acquisitions. We target complementary acquisitions in existing core areas and focus on acquisition candidates where our existing operating and technical knowledge is transferable and drilling results can be forecast with confidence. Over the past three years, we have completed $1.3 billion 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 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. Because of the volatility of commodity prices and the risks involved in drilling, we remain flexible and 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 allows us to be more opportunistic in lower price environments as well as providing more consistent financial results. | ||
| • | Equity Ownership and Incentive Compensation. We want our employees to act like owners. To achieve this, we reward and encourage them through equity ownership in Range. As of December 31, 2006, our employees owned equity securities (vested and unvested) which had a market value of over $170.0 million. |
Significant Accomplishments in 2006
| • | Production and reserve growth – The fourth quarter of 2006 marked the 16th consecutive quarter of sequential production growth. In 2006, our annual production averaged 276.1 Mmcfe per day, an increase of 15% from 2005. 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 sixteen quarters will be challenging to sustain, the quality of our technical teams and our sizable drilling inventory bode well for the future. Proven reserves increased 25% in 2006 to 1.8 Tcfe, marking the fifth consecutive year our proven reserves have increased. |
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| • | Successful drilling program – In 2006, we drilled 1,017 gross wells. Competition for quality drilling and completion well services was intense in 2006, yet we were able to increase our number of wells drilled by 21% over 2005. As we continue to build our drilling inventory for the future, our ability to drill a large number of wells each year on a cost effective and efficient basis is important. Production was replaced by 377% through drilling in 2006, and our overall success rate was 99%. The increased pace of drilling did not adversely impact the quality of our drilling program as the 99% success ratio in 2006 compares favorably to the 98% success ratio in 2005. | ||
| • | Continued expansion of drilling inventory and emerging plays – To continue to grow, the size of our prospect inventory must also increase. Our drilling inventory currently includes over 9,400 projects, up from 7,700 at year-end 2005. Meaningful expansion of our coal bed methane plays and our shale plays occurred in 2006. We have now leased 276,000 net acres in our coal bed methane plays and 567,000 net acres in our shale plays. In addition to the expansion of our emerging plays, we have hired additional quality experienced 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 2006. Revenue, net income, and net cash flow provided from operating activities all reached record highs. The balance sheet continued to improve in 2006 as we refinanced $250 million of shorter term bank debt with a like amount of senior subordinated fixed rate 7.5% 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. Future cash flow will be enhanced through lower income tax payments due to a $229.6 million net operating loss carryforward. | ||
| • | Successful acquisition completed – In June 2006 we acquired Stroud Energy, Inc. (“Stroud”) for $171.5 million in cash and 6.5 million shares of our common stock. The transaction was structured as a merger with Stroud shareholders electing to receive either cash, Range stock, or a combination of both cash and stock. Stroud was a private Fort Worth based independent oil and gas company with operations located in the Barnett Shale play in North Texas, the Cotton Valley in East Texas and the Austin Chalk in Central Texas. We estimate the proved reserves attributable to the Stroud properties totaled 171 Bcfe. Over 90% of Stroud’s Barnett Shale acreage is located in the core or expanding core portions of the Barnett Shale play. In the first quarter of 2007, we sold the Austin Chalk properties in Central Texas for proceeds of $80.4 million. |
Plans for 2007
We have announced a $698.0 million capital budget for 2007, excluding acquisitions. The
budget includes $600.0 million to drill 924 gross (691 net) wells and to undertake 72 gross (52
net) recompletions. Approximately 57% of the budget is attributable to the Southwest Division,
with 37% allocated to the Appalachia Division and 6% to the Gulf Coast Division. Also included is
$58.0 million for land, $20.0 million for seismic and $20.0 million for the expansion and
enhancement of gathering systems and facilities. We anticipate drilling slightly fewer shallow
wells in favor of deeper wells in 2007 as we seek to improve returns. Deeper wells are typically
more costly than shallow wells.
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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, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Production |
||||||||||||
Gas (Mmcf) |
75,267 | 63,004 | 50,722 | |||||||||
Crude oil (Mbbl) |
3,160 | 3,031 | 2,512 | |||||||||
Natural gas liquids (Mbbl) |
1,092 | 1,012 | 988 | |||||||||
Total (Mmcfe) (a) |
100,775 | 87,263 | 71,726 | |||||||||
Revenues ($000) |
||||||||||||
Gas |
$ | 497,854 | $ | 380,131 | $ | 225,738 | ||||||
Crude oil |
149,370 | 117,354 | 70,439 | |||||||||
Natural gas liquids |
36,704 | 27,589 | 19,526 | |||||||||
Transportation and gathering |
2,507 | 2,461 | 2,202 | |||||||||
Total |
686,435 | 527,535 | 317,905 | |||||||||
Direct
operating expenses
(b) |
92,224 | 67,112 | 46,308 | |||||||||
Production and ad valorem taxes |
36,915 | 31,516 | 20,504 | |||||||||
Gross margin |
$ | 557,296 | $ | 428,907 | $ | 251,093 | ||||||
Average sales price (excluding hedging) |
||||||||||||
Gas (per mcf) |
$ | 6.58 | $ | 7.98 | $ | 5.79 | ||||||
Crude oil (per bbl) |
62.60 | 53.31 | 39.25 | |||||||||
Natural gas liquids (per bbl) |
33.62 | 31.52 | 23.73 | |||||||||
Total (per mcfe) (a) |
7.25 | 7.98 | 5.80 | |||||||||
Average sales price (including hedging) |
||||||||||||
Gas (per mcf) |
$ | 6.61 | $ | 6.03 | $ | 4.45 | ||||||
Crude oil (per bbl) |
47.27 | 38.71 | 28.04 | |||||||||
Natural gas liquids (per bbl) |
33.62 | 27.27 | 19.76 | |||||||||
Total (per mcfe) (a) |
6.79 | 6.02 | 4.40 | |||||||||
Operating costs (per mcfe) |
||||||||||||
Direct (b) |
$ | 0.92 | $ | 0.77 | $ | 0.65 | ||||||
Production and ad valorem taxes |
0.37 | 0.36 | 0.29 | |||||||||
Total operating costs |
$ | 1.29 | $ | 1.13 | $ | 0.94 | ||||||
Gross margin (per mcfe) |
$ | 5.53 | $ | 4.92 | $ | 3.50 | ||||||
| (a) | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcfe. | |
| (b) | 2006 direct operating expenses include $1.4 million (or $0.01 per mcfe) of non-cash stock-based compensation related to the adoption of SFAS No. 123(R). |
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 our financial or personnel resources
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.
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Employees
As of January 1, 2007, we had 644 full-time employees, 358 of whom were field personnel. All
full-time employees are eligible to receive equity awards approved by the Compensation Committee of
the Board of Directors. No employees are covered by a labor union or other collective bargaining
arrangement. We believe that the relationship with our employees is excellent. We regularly
utilize independent consultants and contractors to perform various professional services,
particularly in the areas of drilling, completion, field and on-site production operation services.
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 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 100 F Street, N.E., 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 website 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 other working interest owners and royalty owners. Gas sales are made
pursuant to a variety of contractual arrangements; generally
month-to-month and one to five-year
contracts. Less than 10% of our production is subject to contracts longer than five years.
Pricing on the month-to-month and short-term contracts is based largely on the New York Mercantile
Exchange (“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 indices. Less than 500 mcf per day is sold under long-term fixed price contracts. Many
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 terms 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 or fixed pricing. All oil pricing is 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 Note 15 to our consolidated financial statements. 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, see the information set forth
in “Item 7. 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. Market volatility due to international political
developments, overall energy supply and demand, fluctuating weather conditions, economic growth
rates and other factors in the United States and worldwide has 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 4,900 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 and interstate pipelines. For additional information, see “Risk Factors – Our business
depends on oil and natural gas transportation facilities, many of which are owned by others,” in
Item 1A. of this report.
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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 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 (“MMS”). These leases contain relatively standardized terms and
require compliance with detailed MMS regulations pursuant to the Outer Continental Shelf Lands Act,
(“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, (“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 (“EPAct 2005”). Among other
matters, the EPAct 2005 amends the Natural Gas Act (“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 (“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
with 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 (“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
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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 capital or other non-recurring expenditures in connection with complying with
environmental laws or environmental remediation matters in 2006, nor do we anticipate that such
expenditures will be material in 2007.
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), known as
the “Superfund” law, imposes liability, without regard to fault or the legality of the original
conduct, on certain classes of persons who are considered to be responsible for the release of a
“hazardous substance” into the environment. These persons include 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 (“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 (“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 Oil Pollution Act (“OPA”) requires owners and operators of facilities that could be the
source of an oil spill into “waters of the United States” (a term defined to include rivers,
creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any
spill of oil into any waters of the United States. OPA also requires affected facility owners and
operators to demonstrate that they have sufficient 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
We are subject to various risks and uncertainties in the course of our business. The
following summarizes some, but not all, of the risks and uncertainties which may adversely affect
our business, financial condition or results of operations.
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 a 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. 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
such as:
| • | the domestic and foreign supply of oil and gas; | ||
| • | the price and availability of alternative fuels; | ||
| • | weather conditions; | ||
| • | the level of consumer demand; | ||
| • | the price of foreign imports; | ||
| • | world-wide economic conditions; | ||
| • | political conditions in oil and gas producing regions; and | ||
| • | domestic and foreign governmental regulations. |
Decreases in oil and natural gas prices from current levels could adversely affect our
revenues, net income, cash flow and proved reserves. Significant 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 would be unable to replace reserves and
production.
Hedging transactions may limit our potential gains and involve other risks
To
manage our exposure to price risk, we, from time to time, enter into hedging arrangements,
utilizing commodity derivatives 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.
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. |
In the fourth quarter of 2005, due to the trading volatility of NYMEX gas contracts, we
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 qualify for hedge
accounting and are 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
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
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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.
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. In the third
quarter of 2006, we recorded a $2.4 million impairment on an offshore property due to declining oil
and gas prices.
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 drill 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.
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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. Recently, we have
experienced substantial increases in premiums especially in areas affected by the hurricanes and
tropical storms. Insurers have imposed 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 at December 31, 2006,
approximately 57% of our debt is at fixed interest rates with the remaining 43% subject to variable
interest rates.
Many 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
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pursue our acquisition strategy may be hindered if we are not able to obtain financing on terms
acceptable to us or regulatory approvals.
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 generally related to offshore operations and
specifically in the Gulf of Mexico
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 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. As of February 20, 2007, we continued to have approximately 1.0 Mmcfe per day of
production shut-in due to the effects of hurricanes Katrina and Rita.
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.
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Our business depends on oil and natural gas transportation facilities, most 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 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 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 $650.0 million to $825.0 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.
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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. In 2006, we issued 6.5 million shares as
part of the Stroud acquisition. 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
limited by our bank credit facility and our 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 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, deferred taxes 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, 2006, the last daily sale price of our common stock reported by the New York Stock
Exchange ranged from a low of $6.25 per share to a high of $31.77 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; or | ||
| • | 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
As of the date of this filing, we have no unresolved comments from the staff of the Securities
and Exchange Commission.
ITEM 2. PROPERTIES
The table below summarizes certain data for our core operating areas for the year ended
December 31, 2006:
| Average | ||||||||||||||||||||
| Daily | Total | Percentage | ||||||||||||||||||
| Production | Total | Percentage | Proved | of Total | ||||||||||||||||
| (mcfe | Production | of Total | Reserves | Proved | ||||||||||||||||
| Division | per day) | (mcfe) | Production | (Mmcfe) | Reserves | |||||||||||||||
Southwest |
150,731 | 55,017,031 | 55 | % | 774,933 | 44 | % | |||||||||||||
Appalachia |
103,032 | 37,606,463 | 37 | % | 915,054 | 52 | % | |||||||||||||
Gulf Coast |
22,334 | 8,151,801 | 8 | % | 68,239 | 4 | % | |||||||||||||
| 276,097 | 100,775,295 | 100 | % | 1,758,226 | 100 | % | ||||||||||||||
Segment reporting is not applicable to us as 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 complete separate financial statement
information by area. We measure financial performance as a single enterprise and not on an
area-by-area basis.
Southwest Division
The Southwest Division conducts drilling, production and field operations in the Barnett Shale
of North Central Texas, 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 2,057 net producing wells, 96% of which we operate. Our average working
interest is 73%. We have approximately 687,000 gross (480,000 net) acres under lease.
Total
proved reserves increased 272.3 Bcfe, or 54%, at December 31, 2006 when compared to year-end 2005.
Production was more than offset by property purchases (122.9 Bcfe) and drilling additions (208.2
Bcfe). Annual production increased 29% over 2005. During 2006, the region spent $313.1 million to
drill 253.0 (212.0 net) development wells, of which 249.0 (210.2 net) were productive and 4 (1.2
net) exploratory wells, of which 2 (0.2 net) were productive. During the year, the region achieved
a 99% drilling success rate.
At December 31, 2006, the Southwest Division had a development inventory of 219 proven
drilling locations and 316 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
properties in this division are located in the Appalachian Basin in the northeastern
United States principally in Ohio, Pennsylvania, New York, West Virginia and Virginia. 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, most of these properties are characterized by gradual decline rates,
typically producing for 10 to 35 years. We own 9,306 net producing wells, 69% of which we operate
and 4,900 miles of gas gathering lines. Our average working interest is 73%. We have
approximately 2.3 million gross (1.9 million net) acres under lease which includes over 70,000
acres associated with royalties.
Reserves at December 31, 2006 increased 76.7 Bcfe, or 9%, from 2005 due to drilling additions
(161.8 Bcfe) which were partially offset by a net unfavorable reserve revision and production.
Annual production increased 10% over 2005. During 2006, the region spent $184.3 million to drill
739 (477.8 net) development wells, of which 737 (477.0 net) were
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productive and 10 (7.0 net)
exploratory wells, of which 9 (6.0 net) were productive. During the year, the region achieved
approximately a 100% drilling success rate. At December 31, 2006, the Appalachia Division had an
inventory of 3,300 proven drilling locations and 212 proven recompletions.
Gulf Coast Division
The Gulf Coast properties are located onshore in Texas, 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, the Upper Oligocene in
South Louisiana at depths of 10,000 to 12,000 feet and 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 102,000 gross (56,000 net) acres under lease. Offshore properties include interests
in 37 platforms in water depths ranging from 11 to 240 feet. We own 33 net producing wells in this
division, 42% of which we operate. Our average working interest is 23%. Our Gulf Coast Division
owns a license to a 3-D seismic database covering over 800 contiguous blocks in the shallow water
of the Gulf of Mexico, primarily offshore Louisiana.
Reserves increased 2.4 Bcfe, or 4%, from 2005 with production more than offset by drilling
additions (9.5 Bcfe) and a favorable reserve revision. On an annual basis, production decreased
23% from 2005. During 2006, the region spent $38.0 million to drill 8 (4.6 net) development wells,
of which 6 (2.6 net) were productive and 3 (1.3 net) exploratory wells, of which 1 (0.7 net) was
productive. During the year, the division had a 56% drilling success rate. At December 31, 2006,
the Gulf Coast Division had an inventory of 13 proven drilling locations and 59 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, | ||||||||||||||||||||
| 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Natural gas (Mmcf) |
||||||||||||||||||||
Developed |
875,395 | 724,876 | 580,006 | 344,187 | 320,224 | |||||||||||||||
Undeveloped |
560,583 | 400,534 | 366,422 | 142,217 | 120,043 | |||||||||||||||
Total |
1,435,978 | 1,125,410 | 946,428 | 486,404 | 440,267 | |||||||||||||||
Oil and NGLs (Mbbls) |
||||||||||||||||||||
Developed |
37,750 | 33,029 | 27,715 | 24,912 | 17,176 | |||||||||||||||
Undeveloped |
15,957 | 13,863 | 10,451 | 8,111 | 5,776 | |||||||||||||||
Total |
53,707 | 46,892 | 38,166 | 33,023 | 22,952 | |||||||||||||||
Total (Mmcfe) (a) |
1,758,226 | 1,406,762 | 1,175,425 | 684,541 | 577,977 | |||||||||||||||
% Developed |
63 | % | 66 | % | 64 | % | 72 | % | 73 | % | ||||||||||
| (a) | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcfe. |
Our percentage of proved developed reserves declined from 2003 to 2004 due to the proved
undeveloped reserves acquired in the Great Lakes and Pine Mountain acquisitions (see Note 3 to our
consolidated financial statements), adding to our future drilling inventory. From 2004 to 2005,
our proved undeveloped percentage declined from 36% to 34% as we continued to aggressively drill.
The Stroud acquisition in June of 2006 was primarily responsible for the decrease in the proved
developed reserve percentage in 2006. The Stroud acquisition significantly increased our Barnett
Shale drilling and prospect inventory.
15
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The following table sets forth summary information by division with respect to estimated
proved reserves at December 31, 2006:
| Pre-tax Present Value (a) | Reserve Volumes | |||||||||||||||||||||||
| Amount | Oil & NGL | Natural Gas | Total | |||||||||||||||||||||
| (In thousands) | % | (Mbbls) | (Mmcf) | (Mmcfe) | % | |||||||||||||||||||
Southwest |
$ | 1,407,302 | 51 | % | 39,859 | 535,770 | 774,933 | 44 | % | |||||||||||||||
Appalachia |
1,181,045 | 43 | % | 12,183 | 841,958 | 915,054 | 52 | % | ||||||||||||||||
Gulf Coast |
183,095 | 6 | % | 1,665 | 58,250 | 68,239 | 4 | % | ||||||||||||||||
Total |
$ | 2,771,442 | 100 | % | 53,707 | 1,435,978 | 1,758,226 | 100 | % | |||||||||||||||
| (a) | This measure was prepared using year-end oil and gas prices adjusted for the location and quality of reserves, discounted at 10% per year. Our pre-tax present value of $2.8 billion less discounted taxes of $0.8 billion equals our standardized measure of $2.0 billion. See Note 19 to our consolidated financial statements. |
At year-end 2006, 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, 2006, these
consultants collectively reviewed approximately 87% of our 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 5%.
The following table sets forth the estimated future net revenues, excluding open hedging
contracts, from proved reserves, the present value of those net revenues and the expected benchmark
prices and average field prices used in projecting them over the past five years (in millions
except prices):
| December 31, | ||||||||||||||||||||
| 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Future net revenue |
$ | 6,391 | $ | 10,429 | $ | 5,035 | $ | 2,687 | $ | 1,817 | ||||||||||
Present value |
||||||||||||||||||||
Pre-tax |
2,771 | 4,887 | 2,396 | 1,396 | 965 | |||||||||||||||
After tax |
2,002 | 3,384 | 1,749 | 1,003 | 500 | |||||||||||||||
Benchmark prices |
||||||||||||||||||||
Oil price (per barrel) |
$ | 61.05 | $ | 61.04 | $ | 43.33 | $ | 32.52 | $ | 31.17 | ||||||||||
Gas price (per mcf) |
$ | 5.64 | $ | 10.08 | $ | 6.18 | $ | 6.19 | $ | 4.75 | ||||||||||
Wellhead prices |
||||||||||||||||||||
Oil price (per barrel) |
$ | 57.66 | $ | 57.80 | $ | 40.44 | $ | 29.48 | $ | 27.52 | ||||||||||
Gas price (per mcf) |
$ | 5.24 | $ | 9.83 | $ | 6.05 | $ | 6.03 | $ | 4.76 | ||||||||||
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
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Producing Wells
The following table sets forth information relating to productive wells at December 31, 2006.
We also own royalty interests in an additional 1,991 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 |
2,381 | 2,038 | 86 | % | ||||||||
Natural gas |
13,330 | 9,358 | 70 | % | ||||||||
Total |
15,711 | 11,396 | 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, 2006, 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, 2006:
| Acres | Average Working | |||||||||||
| Gross | Net | Interest | ||||||||||
Developed |
1,458,500 | 1,139,185 | 78 | % | ||||||||
Undeveloped |
1,756,406 | 1,360,545 | 77 | % | ||||||||
Total (a) |
3,214,906 | 2,499,730 | 78 | % | ||||||||
| (a) | Includes over 70,000 acres in Appalachia in which we own royalty and overriding royalty interests. Also, does not include 24,000 net acres in the Southwest Division attributable to a farm-in. |
Undeveloped Acreage Expirations
The table below summarizes by year our undeveloped acreage scheduled to expire in the next
five years.
| Acres | % of Total | |||||||||||
| As of December 31, | Gross | Net | Undeveloped | |||||||||
2007 |
223,980 | 179,351 | 14 | % | ||||||||
2008 |
227,172 | 164,179 | 13 | % | ||||||||
2009 |
280,443 | 204,338 | 16 | % | ||||||||
2010 |
107,479 | 88,798 | 7 | % | ||||||||
2011 |
277,866 | 217,487 | 17 | % | ||||||||
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Drilling Results
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.
| 2006 | 2005 | 2004 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Development wells |
||||||||||||||||||||||||
Productive |
992.0 | 689.7 | 813.0 | 573.8 | 436.0 | 368.5 | ||||||||||||||||||
Dry |
8.0 | 4.6 | 10.0 | 7.7 | 16.0 | 12.0 | ||||||||||||||||||
Exploratory wells |
||||||||||||||||||||||||
Productive |
12.0 | 6.9 | 13.0 | 8.1 | 14.0 | 9.2 | ||||||||||||||||||
Dry |
5.0 | 2.6 | 5.0 | 3.9 | 10.0 | 6.9 | ||||||||||||||||||
Total wells |
||||||||||||||||||||||||
Productive |
1,004.0 | 696.6 | 826.0 | 581.9 | 450.0 | 377.7 | ||||||||||||||||||
Dry |
13.0 | 7.2 | 15.0 | 11.6 | 26.0 | 18.9 | ||||||||||||||||||
Total |
1,017.0 | 703.8 | 841.0 | 593.5 | 476.0 | 396.6 | ||||||||||||||||||
Success ratio |
99 | % | 99 | % | 98 | % | 98 | % | 95 | % | 95 | % | ||||||||||||
Real Property
We lease approximately 203,700 square feet of office space, primarily in Texas and Oklahoma
under standard office lease arrangements that expire at various dates through 2017. Our
Appalachian Division owns a 34,500 square foot office building and various other field offices. In the first half of 2007, our Fort Worth office will be relocating to 100
Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. 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 minimal 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; or | ||
| • | 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 business. In the opinion of management, such litigation and claims are likely to be resolved
without a material adverse effect on our financial position or
liquidity, although an unfavorable
outcome could have a material adverse effect on the operations of a given interim period or year.
See also Note 14 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
2006.
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PART II
ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES
EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “RRC.”
During 2006, trading volume averaged 1.1 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).
| Cash Dividends | Average Daily | |||||||||||||||
| High | Low | Declared | Volumes | |||||||||||||
2005 |
||||||||||||||||
First quarter |
$ | 17.59 | $ | 12.34 | 0.0133 | 1,072,650 | ||||||||||
Second quarter |
18.62 | 13.50 | 0.0133 | 1,334,709 | ||||||||||||
Third quarter |
26.33 | 18.01 | 0.0133 | 1,203,888 | ||||||||||||
Fourth quarter |
28.37 | 20.71 | 0.02 | 1,565,650 | ||||||||||||
2006 |
||||||||||||||||
First quarter |
$ | 30.52 | $ | 22.52 | 0.02 | 1,343,584 | ||||||||||
Second quarter |
30.29 | 21.74 | 0.02 | 1,202,248 | ||||||||||||
Third quarter |
30.37 | 23.38 | 0.02 | 884,865 | ||||||||||||
Fourth quarter |
31.77 | 22.80 | 0.03 | 895,294 | ||||||||||||
Between January 1, 2007 and February 20, 2007, the common stock traded at prices between
$25.29 and $31.25 per share. Our senior subordinated notes are not listed on an exchange, but
trade over-the-counter.
Holders of Record
On February 20, 2007, there were approximately 1,967 holders of record of our common stock.
Dividends
In December 2006, the Board of Directors increased our quarterly dividend to $0.03 per common
share. The payment of dividends is subject to declaration by the Board of Directors and depends on
earnings, capital expenditures and various other factors. The bank credit facility and our 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.”
Issuer Purchases of Equity Securities
We have a repurchase program approved by the Board of Directors in 2006, for the repurchase of
up to $10.0 million of common stock based on market conditions
and opportunities. There were no repurchases during the fourth
quarter of 2006.
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Table of Contents
ITEM 6. SELECTED FINANCIAL DATA
The following table shows selected financial information for the five years ended December 31,
2006. Significant producing property acquisitions in 2006 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 included elsewhere in this report (in thousands, except per share data).
| Year Ended December 31, | ||||||||||||||||||||
| 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Balance Sheet Data: |
||||||||||||||||||||
Current assets (a) |
$ | 320,337 | $ | 207,977 | $ | 136,336 | $ | 66,092 | $ | 50,619 | ||||||||||
Current liabilities (b) |
232,356 | 321,760 | 177,162 | 106,964 | 67,206 | |||||||||||||||
Oil and gas properties, net |
2,676,676 | 1,741,182 | 1,402,359 | 723,382 | 564,406 | |||||||||||||||
Total assets |
3,187,674 | 2,018,985 | 1,595,406 | 830,091 | 658,484 | |||||||||||||||
Bank debt |
452,000 | 269,200 | 423,900 | 178,200 | 115,800 | |||||||||||||||
Subordinated debt |
596,782 | 346,948 | 196,656 | 109,980 | 90,901 | |||||||||||||||
Stockholders’ equity (c) |
1,256,161 | 696,923 | 566,340 | 274,066 | 206,109 | |||||||||||||||
Weighted average dilutive shares outstanding |
138,711 | 129,125 | 97,998 | 86,775 | 81,627 | |||||||||||||||
Cash dividends declared per common share |
0.09 | .0599 | .0267 | .0067 | — | |||||||||||||||
Cash Flow Data: |
||||||||||||||||||||
Net cash provided from operating activities |
479,875 | 325,745 | 209,249 | 124,680 | 114,472 | |||||||||||||||
Net cash used in investing activities |
911,659 | 432,377 | 624,301 | 186,838 | 103,950 | |||||||||||||||
Net cash provided from (used in) financing
activities |
429,416 | 93,000 | 432,803 | 61,455 | (12,568 | ) | ||||||||||||||
| (a) | 2005, 2004 and 2003 include deferred tax assets of $61.7 million, $26.3 million and $19.9 million, respectively. 2006 includes a $93.6 million hedging asset. | |
| (b) | 2006, 2005, 2004, 2003 and 2002 include hedging liabilities of $4.6 million, $160.1 million, $61.0 million, $54.3 million and $26.0 million, respectively. | |
| (c) | Stockholders’ equity includes other comprehensive income (loss) of $36.5 million, ($147.1 million), ($43.3 million), ($42.9 million) and ($21.2 million) in 2006, 2005, 2004, 2003 and 2002, respectively. |
20
Table of Contents
Statement of Operations Data:
| Year Ended December 31, | ||||||||||||||||||||
| 2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Revenues |
||||||||||||||||||||
Oil and gas sales |
$ | 683,928 | $ | 525,074 | $ | 315,703 | $ | 226,402 | $ | 190,954 | ||||||||||
Transportation and gathering |
2,507 | 2,461 | 2,202 | 3,509 | 3,495 | |||||||||||||||
Gain (loss) on retirement of securities |
— | — | (39 | ) | 18,526 | 3,098 | ||||||||||||||
Mark-to-market on oil and gas derivatives |
86,491 | 10,868 | — | — | — | |||||||||||||||
Other |
6,802 | (2,563 | ) | 2,841 | (2,670 | ) | (5,958 | ) | ||||||||||||
Total revenue |
779,728 | 535,840 | 320,707 | 245,767 | 191,589 | |||||||||||||||
Costs and expenses |
||||||||||||||||||||
Direct operating |
92,224 | 67,112 | 46,308 | 36,423 | 31,869 | |||||||||||||||
Production and ad valorem taxes |
36,915 | 31,516 | 20,504 | 12,894 | 8,574 | |||||||||||||||
Exploration |
45,252 | 30,604 | 21,243 | 13,946 | 11,525 | |||||||||||||||
General and administrative |
49,886 | 33,444 | 20,610 | 17,818 | 16,217 | |||||||||||||||
Deferred compensation plan |
6,873 | 29,474 | 19,176 | 6,559 | 1,023 | |||||||||||||||
Interest expense and dividends on trust preferred |
57,577 | 38,797 | 23,119 | 22,165 | 23,153 | |||||||||||||||
Depletion, depreciation and amortization |
167,262 | 127,514 | 99,408 | 86,549 | 76,820 | |||||||||||||||
Provision for impairment |
2,399 | — | 3,563 | — | — | |||||||||||||||
Total costs and expenses |
458,388 | 358,461 | 253,931 | 196,354 | 169,181 | |||||||||||||||
Income from continuing operations before income taxes
and accounting change |
321,340 | 177,379 | 66,776 | 49,413 | 22,408 | |||||||||||||||
Income tax provision (benefit) |
||||||||||||||||||||
Current |
1,912 | 1,071 | (245 | ) | 170 | (4 | ) | |||||||||||||
Deferred |
121,814 | 65,297 | 24,790 | 18,319 | (3,354 | ) | ||||||||||||||
| 123,726 | 66,368 | 24,545 | 18,489 | (3,358 | ) | |||||||||||||||
Income from continuing operations |
197,614 | 111,011 | 42,231 | 30,924 | 25,766 | |||||||||||||||
Loss from discontinued operations |
(38,912 | ) | — | — | — | — | ||||||||||||||
Income before cumulative effect of changes in
accounting principles |
158,702 | 111,011 | 42,231 | 30,924 | 25,766 | |||||||||||||||
Cumulative effect of changes in accounting principles,
net of taxes |
— | — | — | 4,491 | — | |||||||||||||||
Net income |
158,702 | 111,011 | 42,231 | 35,415 | 25,766 | |||||||||||||||
Preferred dividends |
— | — | (5,163 | ) | (803 | ) | — | |||||||||||||
Net income available to common stockholders |
$ | 158,702 | $ | 111,011 | $ | 37,068 | $ | 34,612 | $ | 25,766 | ||||||||||
Earnings per common share: |
||||||||||||||||||||
Basic – income from continuing operations |
$ | 1.48 | $ | 0.89 | $ | 0.40 | $ | 0.37 | $ | 0.32 | ||||||||||
– loss from discontinued operations |
(0.29 | ) | — | — | — | — | ||||||||||||||
– cumulative effect of changes in accounting
principles |
— | — | — | 0.05 | — | |||||||||||||||
– Net income |
$ | 1.19 | $ | 0.89 | $ | 0.40 | $ | 0.42 | $ | 0.32 | ||||||||||
Diluted – income from continuing operations |
$ | 1.42 | $ | 0.86 | $ | 0.38 | $ | 0.36 | $ | 0.32 | ||||||||||
– loss from discontinued operations |
(0.28 | ) | — | — | — | — | ||||||||||||||
– cumulative effect of changes in accounting
principles |
— | — | — | 0.05 | — | |||||||||||||||
– Net income |
$ | 1.14 | $ | 0.86 | $ | 0.38 | $ | 0.41 | $ | 0.32 | ||||||||||
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. 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 complete separate financial
statement information by area. We measure financial performance as a single enterprise and not on
an area-by-area basis.
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 historical exit of larger independent
producers and 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 remain high in 2007. In addition, we
expect drilling and service costs to remain at a high level in 2007 and for lease operating
expenses to continue to rise as producers are forced to make operational enhancements to maintain
aging fields.
Natural gas is a commodity. The price that we receive for the natural gas we produce is
largely a function of market supply and demand. Demand for natural gas in the United States has
increased dramatically over the last ten years. Demand is impacted by general economic conditions,
estimates of gas in storage, weather and other seasonal condition, including hurricanes and
tropical storms.
Market conditions involving over or under supply of natural gas can result in substantial
price volatility. Historically, commodity prices have been volatile and we expect the volatility
to continue in the future. A substantial or extended decline in oil and gas prices or poor
drilling results could have a material adverse effect on our financial position, results of
operations, cash flows, quantities of oil and gas reserves that may be economically produced and
our ability to access capital markets.
22
Table of Contents
Source of Our Revenues
We derive our revenues from the sale of natural gas and oil that is produced from our
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 2006, 2005 and 2004 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.
Principal Components of Our Cost Structure
| • | Direct Operating Expenses. These are 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 remain high in 2007 as the demand for these services continues to increase. Direct operating expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation. | ||
| • | 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. Exploration expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation. | ||
| • | General and Administrative Expense. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees and legal compliance are included in general and administrative expense. General and administrative expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation. | ||
| • | Interest. We typically finance a portion of our working capital requirements and acquisitions with borrowings under our bank credit facility and with our longer term public 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 2007 capital budget to be funded with internal cash flow and asset sales. | ||
| • | 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 (“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 expense and continue to recognize current tax expense as long as we are generating taxable income. |
23
Table of Contents
Management’s Discussion and Analysis of Income and Operations
Volumes
and Price Data
| 2006 | 2005 | 2004 | ||||||||||
Production: |
||||||||||||
Crude oil (bbls) |
3,159,623 | 3,031,468 | 2,512,434 | |||||||||
NGLs (bbls) |
1,091,785 | 1,011,692 | 988,192 | |||||||||
Natural gas (mcf) |
75,266,847 | 63,003,600 | 50,722,121 | |||||||||
Total (mcfe) (a) |
100,775,295 | 87,262,560 | 71,725,877 | |||||||||
Average daily production: |
||||||||||||
Crude oil (bbls) |
8,656 | 8,305 | 6,865 | |||||||||
NGLs (bbls) |
2,991 | 2,772 | 2,700 | |||||||||
Natural gas (mcf) |
206,210 | 172,613 | 138,585 | |||||||||
Total (mcfe) (a) |
276,097 | 239,076 | 195,972 | |||||||||
Average sales prices (excluding hedging): |
||||||||||||
Crude oil (per bbl) |
$ | 62.60 | $ | 53.31 | $ | 39.25 | ||||||
NGLs (per bbl) |
33.62 | 31.52 | 23.73 | |||||||||
Natural gas (per mcf) |
6.58 | 7.98 | 5.79 | |||||||||
Total (per mcfe) (a) |
7.25 | 7.98 | 5.80 | |||||||||
Average sales prices (including hedging): |
||||||||||||
Crude oil (per bbl) |
$ | 47.27 | $ | 38.71 | $ | 28.04 | ||||||
NGLs (per bbl) |
33.62 | 27.27 | 19.76 | |||||||||
Natural gas (per mcf) |
6.61 | 6.03 | 4.45 | |||||||||
Total (per mcfe) (a) |
6.79 | 6.02 | 4.40 | |||||||||
Average NYMEX prices (b) |
||||||||||||
Oil (per bbl) |
$ | 66.22 | $ | 56.56 | $ | 41.42 | ||||||
Natural gas (per mcf) |
7.26 | 8.55 | 6.09 | |||||||||
| (a) | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcfe. | |
| (b) | Based on average of bid week prompt month prices. |
24
Table of Contents
Overview of 2006 Results
During 2006, we achieved the following results:
| • | 15% production growth and 25% reserve growth; | ||
| • | Drilled over 700 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 171 Bcfe of proved reserves. |
Our 2006 performance reflects another year of successfully executing our strategy of growth
through drilling and complementary acquisitions. 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 and 2006, drilling service and operating cost increases are
more prevalent due to increased competition for goods and services. We faced other challenges in
2006 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.
Total revenues increased 46% in 2006 over the same period of 2005. This increase is due to
higher production and realized oil and gas prices. Our 2006 production growth is due to
acquisitions completed in 2006 and to the continued success of our drilling program. Realized
prices were higher by 13% in 2006 reflecting the expiration of lower priced oil and gas hedges. 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 2006 to 2005
Oil and gas revenue for the years ended December 31, 2006 and 2005 (in thousands) is
summarized in the following table:
| 2006 | 2005 | Change | % | |||||||||||||
Revenues: |
||||||||||||||||
Oil wellhead |
$ | 197,815 | $ | 161,627 | $ | 36,188 | 22 | % | ||||||||
Oil hedges |
(48,445 | ) | (44,273 | ) | (4,172 | ) | 9 | % | ||||||||
Total oil revenue |
$ | 149,370 | $ | 117,354 | $ | 32,016 | 27 | % | ||||||||
Gas wellhead |
$ | 495,920 | $ | 502,691 | $ | (6,771 | ) | 1 | % | |||||||
Gas hedges |
1,934 | (122,560 | ) | 124,494 | 102 | % | ||||||||||
Total gas revenue |
$ | 497,854 | $ | 380,131 | $ | 117,723 | 31 | % | ||||||||
NGL |
$ | 36,704 | $ | 31,891 | $ | 4,813 | 15 | % | ||||||||
NGL hedges |
— | (4,302 | ) | 4,302 | 100 | % | ||||||||||
Total NGL revenue |
$ | 36,704 | $ | 27,589 | $ | 9,115 | 33 | % | ||||||||
Combined wellhead |
$ | 730,439 | $ | 696,209 | $ | 34,230 | 5 | % | ||||||||
Combined hedges |
(46,511 | ) | (171,135 | ) | 124,624 | 73 | % | |||||||||
Total oil and gas revenue |
$ | 683,928 | $ | 525,074 | $ | 158,854 | 30 | % | ||||||||
25
Table of Contents
Average realized price received for oil and gas during 2006 was $6.79 per mcfe, up 13% or
$0.77 per mcfe from 2005. Oil and gas revenues for 2006 reached a record $683.9 million and were
30% higher than 2005 due to higher realized oil and gas prices and a 15% increase in production.
The average price received increased 22% to $47.27 per barrel for oil and increased 10% to $6.61
per mcf for gas from 2005. The effect of our hedging program decreased realized prices $0.46 per
mcfe in 2006 versus a decrease of $1.96 in 2005.
Production volumes increased 15% from 2005 due to continued drilling success and additions from
acquisitions consummated in 2006. Production increased 13.5 Bcfe from 2005. Our production
volumes increased 10% in our Appalachia Division, increased 29% in our Southwest Division and
declined 22% in our Gulf Coast Division.
Mark-to-market on oil and gas derivatives includes a gain of $86.5 million in 2006. In the
fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting due to
the effect of gas price volatility on the correlation between realized prices and hedge
reference prices.
Other revenue increased in 2006 to a gain of $6.8 million from a loss of $2.6 million in 2005.
The 2006 period includes $6.0 million of ineffective hedging gains and income from equity method
investments of $548,000. The 2005 period includes ineffective hedging losses of $3.4 million.
Our operating expenses have increased as we continue to grow. We believe most of our
operating expense fluctuations should be analyzed on a unit-of-production, or per mcfe basis.
The
following table presents information about our operating expenses on an mcfe basis for 2006 and
2005:
| Operating expenses per mcfe | 2006 | 2005 | Change | % | ||||||||||||
Direct operating expense (excluding
$0.01 per mcfe stock-based
compensation in 2006) |
$ | 0.90 | $ | 0.76 | $ | 0.14 | 18 | % | ||||||||
Production and ad valorem tax
expense |
0.37 | 0.36 | 0.01 | 3 | % | |||||||||||
General and administrative expense
(excluding stock-based compensation
of $0.14 per mcfe in 2006 and $0.06
per mcfe in 2005) |
0.35 | 0.33 | 0.02 | 6 | % | |||||||||||
Interest expense |
0.57 | 0.44 | 0.13 | 30 | % | |||||||||||
Depletion, depreciation and
amortization expense (excluding
impairment) |
1.66 | 1.46 | 0.20 | 14 | % | |||||||||||
Direct operating expense (excluding stock-based compensation) increased $24.2 million to $90.8
million due to higher oilfield service costs, higher volumes and the integration of our recent
acquisitions. Our operating expenses are increasing as we add new wells and maintain production
from our existing properties. We incurred $6.7 million of expenses associated with workovers in
2006 versus $7.4 million in 2005. In 2006, 54% of our workover expenses were incurred by our Gulf
Coast division and were primarily hurricane related. 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 (excluding stock-based compensation) were $0.90 per mcfe and increased
$0.14 per mcfe from 2005 with the increase consisting primarily of higher offshore well insurance
($0.02 per mcfe), higher utilities ($0.02 per mcfe), and higher water disposal and equipment costs
($0.06 per mcfe).
Production and ad valorem taxes are paid based on market prices and not hedged prices. These
taxes increased $5.4 million, or 17%, from the same period of the prior year. On a per mcfe basis,
production and ad valorem taxes increased from $0.36 per mcfe in 2005 to $0.37 per mcfe in 2006 due
to higher market prices.
General and administrative expense (excluding stock-based compensation) for 2006 increased
25%, or $7.0 million, due to higher salaries and benefits ($6.0 million) and higher office rent and
general office expense ($1.0 million). On a per mcfe basis, general and administration expense
(excluding stock-based compensation) increased from $0.33 per mcfe in 2005 to $0.35 per mcfe in
2006.
Interest expense for 2006 increased $18.8 million, or 48%, to $57.6 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 2006, we issued $250.0 million of 7.5% senior
subordinated notes which added $9.7 million of interest costs. The proceeds
from this issuance were used to retire shorter term bank debt. In 2006, the average debt
outstanding on the bank credit facility was $347.8 million with an average interest rate of 6.4%
compared to an average debt outstanding in 2005 of $314.8 million with an average interest rates of
4.5%.
26
Table of Contents
Depletion, depreciation and amortization, (“DD&A”), increased $42.1 million, or 33%, due to
higher production and higher depletion rates. DD&A (excluding impairment) increased from $1.46 per
mcfe in 2005 to $1.66 per mcfe in 2006. In the fourth quarter of 2006, we lowered our salvage
value estimates on our Appalachia wells which increased DD&A expense by $4.6 million. In 2006, we
also recorded impairment of $2.4 million on an offshore property due to declining oil and gas
prices which added $0.02 per mcfe. For 2007, based on our current reserve base, we expect our DD&A
rate to average approximately $1.87 per mcfe. The increase in DD&A per mcfe is related to our
Stroud acquisition, increasing drilling costs and the mix of our production.
Operating expenses also include other expenses that generally do not trend with production.
These expenses include stock-based compensation, exploration expense and deferred compensation plan
expense. In 2006, stock-based compensation is a component of direct operating expense ($1.4
million), exploration expense ($3.1 million), general and administrative expense ($14.3 million)
and a $320,000 reduction of gas transportation revenues for a total of $19.1 million. In 2005,
stock-based compensation is equal to $480,000 included in direct operating, $1.2 million included
in exploration expense, $4.9 million included in general and administrative expense and a reduction
of $117,000 of gas transportation revenues for a total of $6.7 million. This expense represents
the amortization of restricted stock grants in 2006 and 2005, expenses related to the adoption of
SFAS No. 123(R) in 2006 and in 2005, the mark-to-market of SARs granted to employees. The increase
in stock-based compensation in 2006 is the result of adopting SFAS No. 123(R) which requires
expensing of stock options.
Exploration expense increased 48% to $45.3 million due to higher seismic costs ($1.6 million),
higher dry hole costs ($9.1 million) and higher personnel costs. The following table details our
exploration-related expenses (in thousands):
| Exploration expenses | 2006 | 2005 | Change | % | ||||||||||||
Dry hole expense |
$ | 16,103 | $ | 7,045 | $ | 9,058 | 129 | % | ||||||||
Seismic |
15,412 | 13,844 | 1,568 | 11 | % | |||||||||||
Personnel expense |
6,917 | 5,872 | 1,045 | 18 | % | |||||||||||
Stock-based compensation
expense |
3,079 | 1,250 | 1,829 | 146 | % | |||||||||||
Other |
3,741 | 2,593 | 1,148 | 44 | % | |||||||||||
Total exploration expense |
$ | 45,252 | $ | 30,604 | $ | 14,648 | 48 | % | ||||||||
Deferred compensation plan expense decreased 77%, or $22.6 million from 2005. This non-cash
expense relates to the increase or decrease 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 to $27.46 per share at the end of 2006.
Income tax expense for 2006 increased $57.4 million, or 86%, over 2005 due to a 81% increase
in income from continuing operations. Our effective tax rate was 39% for 2006 and was 37% for
2005. The twelve months ended December 31, 2006 includes a $2.8 million adjustment for changes in
state tax rates. Given our available net operating loss carryforward, we do not expect to pay
significant federal income taxes. We paid $1.8 million of state income taxes in 2006.
Discontinued operations includes the operating results and impairment losses on the Austin Chalk properties which
were acquired as part of the Stroud transaction. See also Note 4 to our consolidated financial
statements. Due to significant price declines subsequent to the purchase of these properties and
volumes produced since the acquisition, we recognized impairment of $74.9 million. These
properties were sold on February 13, 2007 for proceeds of $80.4 million.
27
Table of Contents
Comparison of 2005 to 2004
Oil and gas revenue for the years ended December 31, 2005 and 2004 (in thousands) is
summarized in the following table:
| 2005 | 2004 | Change | % | |||||||||||||
Revenues |
||||||||||||||||
Oil wellhead |
$ | 161,627 | $ | 98,608 | $ | 63,019 | 64 | % | ||||||||
Oil hedges |
(44,273 | ) | (28,169 | ) | (16,104 | ) | 57 | % | ||||||||
Total oil revenue |
$ | 117,354 | $ | 70,439 | $ | 46,915 | 67 | % | ||||||||
Gas wellhead |
$ | 502,691 | $ | 293,769 | $ | 208,922 | 71 | % | ||||||||
Gas hedges |
(122,560 | ) | (68,031 | ) | (54,529 | ) | 80 | % | ||||||||
Total gas revenue |
$ | 380,131 | $ | 225,738 | $ | 154,393 | 68 | % | ||||||||
NGL |
$ | 31,891 | $ | 23,446 | $ | 8,445 | 36 | % | ||||||||
NGL hedges |
(4,302 | ) | (3,920 | ) | (382 | ) | 10 | % | ||||||||
Total NGL revenue |
$ | 27,589 | $ | 19,526 | $ | 8,063 | 41 | % | ||||||||
Combined wellhead |
$ | 696,209 | $ | 415,823 | $ | 280,386 | 67 | % | ||||||||
Combined hedges |
(171,135 | ) | (100,120 | ) | (71,015 | ) | 71 | % | ||||||||
Total oil and gas revenue |
$ | 525,074 | $ | 315,703 | $ | 209,371 | 66 | % | ||||||||
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 in 2005 increased 38% to $38.71 per barrel for oil and increased 36% to $6.03 per
mcf for gas. The effect of our hedging program decreased realized prices $1.96 per mcfe
in 2005 versus a decrease of $1.40 in 2004.
Production volumes 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 $2.5 million increased $259,000 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 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. 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.
The following table presents information about our operating expenses that generally trend
with changes in production for 2005 and 2004:
| Operating expenses per mcfe | 2005 | 2004 | Change | % | ||||||||||||
Direct operating expense (excluding stock-based
compensation) |
$ | 0.76 | $ | 0.65 | $ | 0.11 | 17 | % | ||||||||
Production and ad valorem tax expense |
0.36 | 0.29 | 0.07 | 24 | % | |||||||||||
General and administration expense (excluding stock-based
compensation of $0.06 per mcfe in 2005) |
0.33 | 0.28 | 0.05 | 18 | % | |||||||||||
Interest expense |
0.44 | 0.32 | 0.12 | 38 | % | |||||||||||
Depletion, depreciation and amortization expense (excluding
impairment) |
1.46 | 1.39 | 0.07 | 5 | % | |||||||||||
28
Table of Contents
Direct operating expense (excluding stock-based compensation) 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 (excluding stock-based compensation) were $0.76 per mcfe and
increased 17% or $0.11 per mcfe from 2004 consisting of higher field level costs ($0.04 per mcfe)
and higher workover costs ($0.07 per mcfe).
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.
General and administrative expense (excluding stock-based compensation) for 2005 increased
42%, or $8.5 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. On a per mcfe basis, general and
administration expense (excluding stock-based compensation) increased 17% from $0.28 per mcfe in
2004 to $0.33 per mcfe 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 (“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.
Operating expenses also include stock-based compensation, exploration expense and non-cash
compensation expense that generally do not trend with production. In 2005, stock-based
compensation expense is a component of direct operating expense ($480,000), exploration expense
($1.2 million) and general and administrative expense ($4.9 million). This expense represents the
amortization of restricted stock grants and the market-to-market of SARs granted to employees. In
2004, stock-based compensation is a component of exploration expense ($24,000) and general and
administrative expense ($541,000).
Exploration expense increased 44% to $30.6 million due to higher seismic costs ($10.5
million), higher personnel costs, higher stock-based compensation expense ($1.2 million), partially
offset by lower dry hole costs ($5.0 million).
| Exploration expenses | 2005 | 2004 | Change | % | ||||||||||||
Dry hole expense |
$ | 7,045 | $ | 12,096 | $ | (5,050 | ) | 42 | % | |||||||
Seismic |
13,844 | 3,329 | 10,515 | 316 | % | |||||||||||
Personnel expense |
5,872 | 4,451 | 1,421 | 32 | % | |||||||||||
Stock-based compensation expense |
1,250 | 24 | 1,226 | 5108 | % | |||||||||||
Other |
2,593 | 1,343 | 1,249 | 93 | % | |||||||||||
Total exploration expense |
$ | 30,604 | $ | 21,243 | $ | 9,361 | 44 | % | ||||||||
Deferred compensation plan expense increased 53%, or $10.3 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.
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.
29
Table of Contents
Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity
During 2006, our cash provided from continuing operations was $467.6 million, and we spent
$898.6 million on capital expenditures (including acquisitions). During this period, financing
activities provided net cash of $429.4 million. Our financing activities included the sale of
$250.0 million of 7.5% senior subordinated notes and additional borrowings under our bank credit
agreement. At December 31, 2006 we had $2.4 million in cash, total assets of $3.2 billion and a
debt-to-capitalization ratio of 45.5%. Long-term debt at December 31, 2006 totaled $1.0 billion,
including $452.0 million of bank debt and $596.8 million of senior subordinated notes. Available
borrowing capacity under the bank credit facility at December 31, 2006 was $348.0 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.
Bank Debt
We maintain an $800.0 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 October 25, 2011. Availability under the bank credit facility is subject to a
borrowing base set by the banks semi-annually with an option to set more often in certain
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 22, 2007, the bank credit facility
had a $1.2 billion borrowing base and an $800.0 million facility amount. Credit availability is
equal to the lesser of the facility amount or the borrowing base resulting in credit availability
of $287.0 million on February 20, 2007. The facility amount can be increased to the borrowing base
with twenty days notice.
Limitations on the payment of dividends and other restricted payments as defined are imposed
under our bank debt and our subordinated notes. Under the bank credit facility, common and
preferred dividends are permitted. The terms of each of our subordinated 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, 2006, approximately
$496.2 million was available under the restricted payment baskets for each of our subordinated
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
$446.4 million was available under the bank credit facility restricted payment basket as of
December 31, 2006. 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, 2006.
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, 2006, we had entered into hedging agreements covering 84.9 Bcfe and 71.7 Bcfe
for 2007 and 2008. The $538.4 million of cash capital expenditures for 2006, excluding
acquisitions, was funded with internal cash flow and borrowing under the bank credit facility. The
$698.0 million capital budget for 2007, 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 2007 capital program is expected to be funded with internal cash
flow and asset sales.
Net cash provided from continuing operations in 2006 was $467.6 million, compared with $325.7
million in 2005 and $209.2 million in 2004. In 2006, cash flow from continuing operations
increased due to higher production
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volumes and higher realized prices partially offset by
increasing operating costs. 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 costs.
Net cash used in investing activities in 2006 was $911.7 million, compared with $432.4 million
in 2005 and $624.3 million in 2004. In 2006, we spent $502.9 million in additions to oil and gas
properties and $360.1 million on acquisitions. The 2005 period included $276.9 million in
additions to oil and gas properties and $153.6 million of acquisitions. The 2004 period included
$166.6 million in additions to oil and gas properties and $485.6 million of acquisitions.
Net cash provided from financing activities in 2006 was $429.4 million compared with $93.0
million in 2005 and $432.8 million in 2004. Historically, sources of financing have been primarily
bank borrowings and capital raised through equity and debt offerings. During 2006, we received
proceeds of $249.5 million from the issuance of our 7.5% Notes. 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 acquisition and the remaining increase the result of funding other acquisitions. Also
in 2004, we redeemed the remaining outstanding 6% Debentures for $11.6 million.
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 2006, $502.9 million of capital was expended on drilling projects. Also in 2006, $360.1
million was expended on acquisitions primarily to purchase producing properties. The capital
program, excluding acquisitions, was funded by net cash flow from operations and borrowings under
our credit facility and our acquisitions were funded primarily with proceeds received from the
issuance of our 7.5% Notes and borrowings under our credit facility. The 2007 capital budget of
$698.0 million, excluding acquisitions, is expected to be funded by cash flow from operations and
asset sales. In February 2007, we sold the Austin Chalk properties for proceeds of $80.4 million.
Development and exploration activities are highly discretionary, and, for the foreseeable future,
we expect such activities to be maintained at levels equal to internal cash flow and asset sales.
To the extent capital requirements exceed internal cash flow and proceeds from asset sales, debt or
equity may be issued to fund these requirements. The Stroud acquisition included the issuance of 6.5 million shares and the assumption of $106.7 million of debt. 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 our subordinated notes. In 2006, we paid $12.2 million in dividends to our common
shareholders ($0.03 per share in the fourth quarter and $0.02 per share in the third, second and
first quarters). 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 quarters). In
2004, we paid $3.2 million in dividends to our common stockholders ($0.0067 per share in the second
and third quarters and $0.0133 per share in the fourth quarter). Also in 2005 and 2004, we paid
$2.2 million and $2.9 million in preferred stock dividends.
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,
2006, we do not have any capital leases nor have we entered into any material long-term contracts
for equipment. As of December 31, 2006, 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, 2006. In addition to the contractual obligations listed on the
table below, our balance sheet at December 31, 2006 reflects accrued interest payable on our bank
debt of $925,000 which is payable in January 2007. We expect to make
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annual interest payments of
$14.8 million per year on our 7.375% Notes, $18.8 million per year on our 7.5% Notes and payments
of $9.6 million per year on our 6.375% Notes.
The following summarizes our contractual financial obligations at December 31, 2006 and their
future maturities. We expect to fund these contractual obligations with cash generated from
operating activities, borrowings under the bank credit facility and proceeds from asset sales
proceeds.
| Payment due by period | ||||||||||||||||||||
| 2008 and | 2010 and | |||||||||||||||||||
| 2007 | 2009 | 2011 | Thereafter | Total | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
Bank debt due 2011 |
$ | — | $ | — | $ | 452,000 | (a) | $ | — | $ | 452,000 | |||||||||
7.375% senior subordinated notes due 2013 |
— | — | — | 200,000 | 200,000 | |||||||||||||||
6.375% senior subordinated notes due 2015 |
— | — | — | 150,000 | 150,000 | |||||||||||||||
7.5% senior subordinated notes due 2016 |
— | — | — | 250,000 | 250,000 | |||||||||||||||
Operating leases |
5,010 | 10,236 | 6,431 | 9,610 | 31,287 | |||||||||||||||
Drilling contracts |
12,830 | 2,160 | — | — | 14,990 | |||||||||||||||
Service contracts |
1,794 | 3,705 | 2,754 | — | 8,253 | |||||||||||||||
Derivative obligations (b) |
4,621 | 266 | — | — | 4,887 | |||||||||||||||
Asset retirement obligation liability |
4,193 | 8,674 | 8,423 | 74,298 | 95,588 | |||||||||||||||
Total contractual obligations (c) |
$ | 28,448 | $ | 25,041 | $ | 469,608 | $ | 683,908 | $ | 1,207,005 | ||||||||||
| (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 $28.9 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, 2006. | |
| (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 derivative agreements to reduce the impact of oil and gas price volatility on
our operations. At December 31, 2006, swaps were in place covering 73.6 Bcf of gas at prices
averaging $9.29 per mcf. We also had collars covering 56.1 Bcf of gas at weighted average floor
and cap prices of $7.42 to $10.49 and 4.5 million barrels of oil at weighted average floor and cap
prices of $55.72 to $70.11. The derivative 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 gain of $149.8 million at December 31,
2006. 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 $46.5 million were recognized in 2006
compared to losses of $171.1 million in 2005 and losses of $100.1 million in 2004. Changes in the
value of the ineffective portion of all open hedges are recognized in earnings quarterly in other
revenue. 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 (“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 volatility of gas prices in the fourth quarter of 2005 and on the
correlation between realized prices and hedge reference prices. These derivatives were
marked-to-market in the amount of a gain of $10.9 million in the fourth quarter of 2005 and as a
gain of $86.5 million in the year ended December 31, 2006.
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At December 31, 2006, the following commodity derivative contracts were outstanding:
| Period | Contract Type | Volume Hedged | Average Hedge Price | |||||||||
Natural Gas |
||||||||||||
2007 |
Swaps | 96,336 Mmbtu/day | $9.13 | |||||||||
2007 |
Collars | 98,500 Mmbtu/day | $7.13 - $9.99 | |||||||||
2008 |
Swaps | 105,000 Mmbtu/day | $9.42 | |||||||||
2008 |
Collars | 55,000 Mmbtu/day | $7.93 - $11.39 | |||||||||
Crude Oil |
||||||||||||
2007 |
Collars | 6,300 bbl/day | $53.46 - $65.33 | |||||||||
2008 |
Collars | 6,000 bbl/day | $58.09 - $75.11 | |||||||||
Interest Rates
At December 31, 2006, we had $1.0 billion of debt outstanding. Of this amount, $600.0 million
bears interest at fixed rates averaging 7.2%. Bank debt totaling $452.0 million bears interest at
floating rates, which averaged 6.4% at year-end 2006. The 30-day LIBOR rate on December 31, 2006
was 5.3%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at
December 31, 2006 would cost us approximately $4.5 million in additional annual interest.
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 a trend that began in 2004 and accelerated during 2005 and 2006, commodity
prices for oil and gas increased significantly. The higher prices have led to increased activity
in the industry and, consequently, rising costs. These costs trends have put pressure not only on
our operating costs but also on our capital costs. We expect further increases in these costs for
2007.
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The following table indicates the average oil and gas prices received over the last five years
and quarterly for 2006, 2005 and 2004. 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) | Average NYMEX Prices (a) | |||||||||||||||||||
| Oil | Natural Gas | Equivalent Mcf | Oil | Natural Gas | ||||||||||||||||
| (Per bbl) | (Per mcf) | (Per mcfe) | (Per bbl) | (Per mcf) | ||||||||||||||||
Annual |
||||||||||||||||||||
2006 |
$ | 62.60 | $ | 6.58 | $ | 7.25 | $ | 66.22 | $ | 7.26 | ||||||||||
2005 |
53.31 | 7.98 | 7.98 | 56.56 | 8.55 | |||||||||||||||
2004 |
39.25 | 5.79 | 5.80 | 41.42 | 6.09 | |||||||||||||||
2003 |
28.42 | 5.10 | 4.94 | 31.04 | 5.44 | |||||||||||||||
2002 |
23.34 | 3.02 | 3.16 | 26.08 | 3.25 | |||||||||||||||
Quarterly |
||||||||||||||||||||
2006 |
||||||||||||||||||||
First |
$ | 59.80 | $ | 8.29 | $ | 8.39 | $ | 63.48 | $ | 9.07 | ||||||||||
Second |
66.25 | 6.30 | 7.19 | 70.70 | 6.82 | |||||||||||||||
Third |
64.69 | 6.12 | 7.00 | 70.48 | 6.53 | |||||||||||||||
Fourth |
59.68 | 5.89 | 6.57 | 60.21 | 6.62 | |||||||||||||||
2005 |
||||||||||||||||||||
First |
$ | 47.09 | $ | 5.97 | $ | 6.24 | $ | 49.84 | $ | 6.32 | ||||||||||
Second |
48.79 | 6.42 | 6.65 | 53.17 | 6.80 | |||||||||||||||
Third |
59.90 | 7.88 | 8.17 | 63.19 | 8.25 | |||||||||||||||
Fourth |
56.39 | 11.30 | 10.57 | 60.02 | 12.85 | |||||||||||||||
2004 |
||||||||||||||||||||
First |
$ | 32.15 | $ | 5.21 | $ | 5.10 | $ | 35.15 | $ | 5.69 | ||||||||||
Second |
35.87 | 5.56 | 5.49 | 38.32 | 5.97 | |||||||||||||||
Third |
40.99 | 5.59 | 5.70 | 43.88 | 5.84 | |||||||||||||||
Fourth |
45.85 | 6.66 | 6.72 | 48.23 | 6.87 | |||||||||||||||
(a) Based on average of bid week prompt month prices.
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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. We base our estimates on historical experience
and various other assumptions that we believe are reasonable; however, actual results may differ.
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.
Oil and Gas Properties
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. To further ensure the
reliability of our reserve estimates, we engage independent petroleum consultants to review our
estimates of proved reserves. Historical variances between our reserve estimates and the aggregate
estimates of our consultants have been less than 5%.
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 2006, 2005 and 2004.
| Audited(a) | ||||||||
| 2006 | 2005 | 2004 | ||||||
87% |
84 | % | 88 | % | ||||
| (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 $226.3 million in
2006 compared to $28.6 million in 2005 and $14.8 million in 2004.
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 19, “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.
We are required to develop estimates of fair value to allocate purchase prices paid to acquire
businesses to the assets acquired and liabilities assumed under the purchase method of accounting.
The purchase price paid to acquire a business is allocated to its assets and liabilities based on
the estimated fair values of the assets acquired and liabilities assumed as of the date of
acquisition. We use all available information to make these fair value determinations. See Note 3
to the consolidated financial statements for information on these acquisitions.
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.” For derivative contracts designated as hedges, 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 other comprehensive income (“OCI”), and then
reclassified to earnings, in oil and gas revenue, when the hedged 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 qualify for hedge accounting due to the volatility
of gas prices and their effect on our basis differentials and are 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.
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.
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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, (“ARO”), 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 depletion, depreciation and amortization in our
consolidated statement of operations.
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 or loss has not yet been earned. 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. At year-end 2006, deferred tax liabilities
exceeded deferred tax assets by $468.6 million, with $21.3 million of deferred tax liabilities
related to unrealized hedging gains included in OCI.
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 September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not
require any new fair value measurements but may require some entities to change their measurement
practices. For Range, SFAS No. 157 will be effective January 1, 2008, with early application
permitted. We are currently evaluating the provisions of this statement.
In July 2006, FASB Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income
Taxes – An Interpretation of FASB Statement No. 109” was issued. FIN 48 clarifies the accounting for
uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with
SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and
measurement attribute for the financial statement recognition and measurement of a tax position
taken or expected to be taken in a tax return. The new standard also provides guidance on
derecognition, classification, interest and penalties, accounting in interim periods and
disclosure. For Range, the provisions of FIN 48 are effective January 1, 2007. The cumulative
effect of adopting FIN 48 will be recorded in retained earnings. Range is currently evaluating the
provisions of FIN 48 to determine the impact on its consolidated financial statements but we do not
expect a material impact on our financial position or results of operations.
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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 derivative arrangements with respect to our oil and gas production.
These arrangements are intended to reduce the impact of oil and gas price fluctuations. Certain
of our derivatives are swaps where we receive a fixed price for our production and pay market
prices to the counterparty. Our derivatives program also includes collars which assume a minimum
floor price and a predetermined ceiling price. The majority of our derivatives qualify as
accounting hedges. 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. 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. Though not all of our derivatives qualify as
accounting hedges, the purpose of entering into the contracts is to economically hedge oil and gas
prices. Those that do not qualify as accounting hedges are marked to market through earnings.
As of December 31, 2006, we had oil and gas swaps in place covering 73.6 Bcf of gas. We also
had collars covering 56.1 Bcf of gas and 4.5 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, 2006, approximated a net pre-tax gain of
$149.8 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
2006, pre-tax losses were realized in the amount of $46.5 million compared to losses of $171.1
million in 2005 and losses of $100.1 million in 2004. Gains and losses due to commodity hedge
ineffectiveness are recognized in earnings in other revenues in our consolidated statement of
operations. The ineffective portion of hedges that qualified for hedge accounting was a gain of
$6.0 million in 2006 compared to a loss of $3.4 million in 2005 and a gain of $712,000 in 2004.
Other Commodity Risk
We are impacted by basis risk, caused by factors that affect the relationship between
commodity futures prices reflected in derivative commodity instruments and the cash market price of
the underlying commodity. Natural gas transaction prices are frequently based on industry
reference prices that may vary from prices experienced in local markets. If commodity prices
changes in one region are not reflected in other regions, derivative commodity instruments may no
longer provide the expected hedge, resulting in increased basis risk. 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 are marked-to-market. This resulted in a gain
of $10.9 million in the fourth quarter of 2005 compared to a
gain of $86.5 million in the year ended December 31, 2006 in the income statement category called mark-to-market on oil and gas derivatives.
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At December 31, 2006, the following commodity derivative contracts were outstanding:
| Period | Contract Type | Volume Hedged | Average Hedge Price | |||||||||
Natural Gas |
||||||||||||
2007 |
Swaps | 96,336 Mmbtu/day | $9.13 | |||||||||
2007 |
Collars | 98,500 Mmbtu/day | $7.13 - $9.99 | |||||||||
2008 |
Swaps | 105,000 Mmbtu/day | $9.42 | |||||||||
2008 |
Collars | 55,000 Mmbtu/day | $7.93 - $11.39 | |||||||||
Crude Oil |
||||||||||||
2007 |
Collars | 6,300 bbl/day | $53.46 - $65.33 | |||||||||
2008 |
Collars | 6,000 bbl/day | $58.09 - $75.11 | |||||||||
In 2006, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging
transactions, would have reduced revenue by $73.4 million. If oil and gas futures prices at
December 31, 2006 had declined by 10%, the unrealized hedging gain at that date would have
increased $74.8 million.
Interest Rate Risk
At December 31, 2006, we had $1.0 billion of debt outstanding. Of this amount, $600.0 million
bears interest at
a fixed rate averaging 7.2%. Bank debt totaling $452.0 million bears interest at floating rates,
which averaged 6.4% on that date. On December 31, 2006, the 30-day LIBOR rate was 5.3%. A 1%
increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2006
would cost us approximately $4.5 million in additional annual interest rates.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
For financial statements required by Item 8, see Item 15 in Part IV of this report.
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,
2006. 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 2006 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 2006 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 2006 annual stockholders’
meeting. Officers are appointed by our board of directors.
| Age | Office Held Since | Position | ||||||||||
Charles L. Blackburn |
79 | 2003 | Director, Chairman of the Board | |||||||||
Anthony V. Dub |
57 | 1995 | Director | |||||||||
V. Richard Eales |
70 | 2001 | Director | |||||||||
Allen Finkelson |
60 | 1994 | Director | |||||||||
Jonathan S. Linker |
58 | 2002 | Director | |||||||||
Kevin S. McCarthy |
47 | 2005 | Director | |||||||||
John H. Pinkerton |
52 | 1990 | Director, President, Chief Executive Officer | |||||||||
Jeffrey L. Ventura |
49 | 2003 | Director, Executive Vice President – Chief Operating Officer | |||||||||
Steven L. Grose |
58 | 2005 | Senior Vice President – Appalachia | |||||||||
Roger S. Manny |
49 | 2003 | Senior Vice President and Chief Financial Officer | |||||||||
Chad L. Stephens |
51 | 1990 | Senior Vice President – Corporate Development | |||||||||
Rodney L. Waller |
57 | 1999 | Senior Vice President, Chief Compliance Officer and Corporate Secretary | |||||||||
Mark D. Whitley |
55 | 2005 | Senior Vice President – Permian Business Unit and Engineering Technology | |||||||||
Charles L. Blackburn was elected as a director in 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 26 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
40
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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 joined
First Reserve Corporation in 1988 and was a Managing Director of the firm from 1996 until July
2001. Mr. Linker is currently Manager of Houston Energy Advisors LLC, an 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, Kayne Anderson Energy Total Return
Fund, Inc. and Kayne Anderson Energy Development Company which are each NYSE listed closed-end
investment companies. Mr. McCarthy joined Kayne Anderson Capital Advisors as a Senior Managing
Director in 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.
Alan
W. Farquharson, Senior Vice President – Reservoir Engineering,
joined Range in 1998. Since joining Range, Mr. Farquharson has held the
positions of Manager and Vice President of Reservoir Engineering.
Previously, Mr. Farquharson held various positions with Union Pacific
Resources including Engineering Manager Business
Development – International. Prior to that, Mr. Farquharson held
various technical and managerial positions at Amoco and Hunt Oil. He
holds a Bachelor of Science degree in Electrical 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. 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.
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
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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 Worcester Polytechnic
Institute and a Master’s degree in Chemical Engineering from the University of Kentucky.
Section 16(a) Beneficial Ownership Reporting Compliance
See the material appearing under the heading “Section 16(a) Beneficial Ownership Reporting
Compliance” in the Range Proxy Statement for the 2007 Annual Meeting of stockholders which is
incorporated herein by reference.
Code of Ethics
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.
Identifying and Evaluating Nominees for Directors
See the material under the heading “Consideration of Director Nominees” in the Range Proxy
Statement for the 2007 Annual Meeting of stockholders which is incorporated herein by reference.
Audit Committee
See the material under the heading “Audit Committee” in the Range Proxy Statement for the 2007
Annual Meeting of stockholders which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is incorporated by reference to such information as set
forth in our definitive Proxy Statement for the 2007 Annual Meeting of stockholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by this item is incorporated by reference to such information as set
forth in our definitive proxy statement for the 2007 Annual Meeting of stockholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information required by this item is incorporated by reference to such information as set
forth in our definitive proxy statement for the 2007 Annual Meeting of stockholders.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required by this item is incorporated by reference to such information as set
forth in our definitive proxy statement for the 2007 Annual Meeting of stockholders.
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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 Sheets as of December 31, 2006 and 2005 |
F- 5 | |||
Consolidated Statements of Operations for the Year Ended December 31, 2006, 2005 and 2004 |
F- 6 | |||
Consolidated Statements of Cash Flows for the Year Ended December 31, 2006, 2005 and 2004 |
F- 7 | |||
Consolidated Statements of Stockholders’ Equity for the Year Ended December 31, 2006, 2005 and 2004 |
F- 8 | |||
Consolidated Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2006, 2005 and 2004 |
F- 9 | |||
Notes to Consolidated Financial Statements |
F-10 | |||
Quarterly Financial Information (Unaudited) |
F-31 | |||
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) |
F-32 | |||
| 2. | 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. | |
| 3. | Exhibits: | |
| (a) See Index of Exhibits on page F-37 for a description of the exhibits filed as a part of this report. |
43
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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.
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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.
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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 26, 2007
| 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 capacity and on the
dates indicated.
/s/ Charles L. Blackburn
|
Chairman of the Board | February 26, 2007 | ||
/s/ John H. Pinkerton
|
President, Chief Executive Officer and Director | February 26, 2007 | ||
/s/ Jeffrey L. Ventura
|
Executive Vice President and Director | February 26, 2007 | ||
/s/ Roger S. Manny
|
Chief Financial and Accounting Officer | February 26, 2007 | ||
/s/ Anthony V. Dub
|
Director | February 26, 2007 | ||
/s/ V. Richard Eales
|
Director | February 26, 2007 | ||
/s/ Allen Finkelson
|
Director | February 26, 2007 | ||
/s/ Jonathan S. Linker
|
Director | February 26, 2007 | ||
/s/ Kevin S. McCarthy
|
Director | February 26, 2007 |
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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 | ||||
Selected Quarterly Financial Information (Unaudited) |
F-31 | |||
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) |
F-32 | |||
F-1
Table of Contents
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To 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 Rule 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, 2006. 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, 2006, 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, 2006, 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 26, 2007
February 26, 2007
F-2
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REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To 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 (the
“Company”) maintained effective internal control over financial reporting as of December 31, 2006,
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 maintained effective internal control over financial reporting as of December 31, 2006, is fairly
stated, in all material respects, based on the COSO criteria. Also, in our opinion, Range
Resources Corporation maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2006, 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 as of December 31, 2006 and 2005 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, 2006 and our report dated February 26, 2007 expressed an
unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
February 26, 2007
February 26, 2007
F-3
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To 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
(the “Company”) as of December 31, 2006 and 2005, 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, 2006. 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 at December 31, 2006 and 2005, and the consolidated results of their operations and
their cash flows for each of the three years in the period ended December 31, 2006, in conformity
with U.S. generally accepted accounting principles.
As
discussed in Note 2 to the consolidated financial statements, in
2006, the Company adopted Statement of Financial Accounting Standards
No. 123(R), “Share-Based Payment.”
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, 2006, 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 26, 2007 expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
February 26, 2007
February 26, 2007
F-4
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
| December 31, | ||||||||
| 2006 | 2005 | |||||||
Assets |
||||||||
Current assets: |
||||||||
Cash and equivalents |
$ | 2,382 | $ | 4,750 | ||||
Accounts receivable, less allowance for doubtful accounts of $746 and $624 |
130,349 | 128,532 | ||||||
Assets held for sale |
79,304 | — | ||||||
Unrealized derivative gain |
93,588 | 425 | ||||||
Deferred tax asset |
— | 61,677 | ||||||
Inventory and other |
14,714 | 12,593 | ||||||
Total current assets |
320,337 | 207,977 | ||||||
Unrealized derivative gain |
61,068 | — | ||||||
Equity method investment |
13,618 | — | ||||||
Oil and gas properties, successful efforts method |
3,641,227 | 2,548,090 | ||||||
Accumulated depletion and depreciation |
(964,551 | ) | (806,908 | ) | ||||
| 2,676,676 | 1,741,182 | |||||||
Transportation and field assets |
80,066 | 65,210 | ||||||
Accumulated depreciation and amortization |
(32,923 | ) | (25,966 | ) | ||||
| 47,143 | 39,244 | |||||||
Other assets |
68,832 | 30,582 | ||||||
Total assets |
$ | 3,187,674 | $ | 2,018,985 | ||||
Liabilities |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 172,081 | $ | 119,907 | ||||
Asset retirement obligations |
4,216 | 3,166 | ||||||
Accrued liabilities |
38,500 | 28,372 | ||||||
Accrued interest |
12,938 | 10,214 | ||||||
Unrealized derivative loss |
4,621 | 160,101 | ||||||
Total current liabilities |
232,356 | 321,760 | ||||||
Bank debt |
452,000 | 269,200 | ||||||
Subordinated notes |
596,782 | 346,948 | ||||||
Deferred tax, net |
468,643 | 174,817 | ||||||
Unrealized derivative loss |
266 | 70,948 | ||||||
Deferred compensation liability |
90,094 | 73,492 | ||||||
Asset retirement obligations |
91,372 | 64,897 | ||||||
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, 138,931,565 issued
at
December 31, 2006 and 129,913,046 issued at December 31, 2005 |
1,389 | 1,299 | ||||||
Common stock held in treasury – 5,826 shares at December 31, 2005 |
— | (81 | ) | |||||
Additional paid-in capital |
1,079,994 | 845,519 | ||||||
Retained earnings |
160,313 | 13,800 | ||||||
Common stock held by employee benefit trust, 1,853,279 and 1,971,605
shares, respectively, at cost |
(22,056 | ) | (11,852 | ) | ||||
Deferred compensation |
— | (4,635 | ) | |||||
Accumulated other comprehensive income (loss) |
36,521 | (147,127 | ) | |||||
Total stockholders’ equity |
1,256,161 | 696,923 | ||||||
Total liabilities and stockholders’ equity |
$ | 3,187,674 | $ | 2,018,985 | ||||
See accompanying notes.
F-5
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Revenues |
||||||||||||
Oil and gas sales |
$ | 683,928 | $ | 525,074 | $ | 315,703 | ||||||
Transportation and gathering |
2,507 | 2,461 | 2,202 | |||||||||
Mark-to-market on oil and gas derivatives |
86,491 | 10,868 | — | |||||||||
Other |
6,802 | (2,563 | ) | 2,802 | ||||||||
Total revenue |
779,728 | 535,840 | 320,707 | |||||||||
Costs and expenses |
||||||||||||
Direct operating |
92,224 | 67,112 | 46,308 | |||||||||
Production and ad valorem taxes |
36,915 | 31,516 | 20,504 | |||||||||
Exploration |
45,252 | 30,604 | 21,219 | |||||||||
General and administrative |
49,886 | 33,444 | 20,634 | |||||||||
Deferred compensation plan |
6,873 | 29,474 | 19,176 | |||||||||
Interest expense |
57,577 | 38,797 | 23,119 | |||||||||
Depletion, depreciation and amortization |
169,661 | 127,514 | 102,971 | |||||||||
Total costs and expenses |
458,388 | 358,461 | 253,931 | |||||||||
Income from continuing operations before income taxes |
321,340 | 177,379 | 66,776 | |||||||||
Income tax provision (benefit) |
||||||||||||
Current |
1,912 | 1,071 | (245 | ) | ||||||||
Deferred |
121,814 | 65,297 | 24,790 | |||||||||
| 123,726 | 66,368 | 24,545 | ||||||||||
Income from continuing operations |
197,614 | 111,011 | 42,231 | |||||||||
Discontinued operations, net of taxes |
(38,912 | ) | — | — | ||||||||
Net income |
158,702 | 111,011 | 42,231 | |||||||||
Preferred dividends |
— | — | (5,163 | ) | ||||||||
Net income available to common stockholders |
$ | 158,702 | $ | 111,011 | $ | 37,068 | ||||||
Earnings per common share: |
||||||||||||
Basic – income from continuing operations |
$ | 1.48 | $ | 0.89 | $ | 0.40 | ||||||
– discontinued operations |
(0.29 | ) | — | — | ||||||||
– net income |
$ | 1.19 | $ | 0.89 | $ | 0.40 | ||||||
Diluted – income from continuing operations |
$ | 1.42 | $ | 0.86 | $ | 0.38 | ||||||
– discontinued operations |
(0.28 | ) | — | — | ||||||||
– net income |
$ | 1.14 | $ | 0.86 | $ | 0.38 | ||||||
See accompanying notes.
F-6
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Operating activities: |
||||||||||||
Net income |
$ | 158,702 | $ | 111,011 | $ | 42,231 | ||||||
Adjustments to reconcile net cash provided from operating activities: |
||||||||||||
Loss from discontinued operations |
38,912 | — | — | |||||||||
Gain from equity method investment |
(548 | ) | — | — | ||||||||
Deferred income tax expense |
121,814 | 65,297 | 24,790 | |||||||||
Depletion, depreciation and amortization |
169,661 | 127,514 | 102,971 | |||||||||
Exploration dry hole costs |
16,103 | 7,045 | 9,493 | |||||||||
Mark-to-market on oil and gas derivatives gains |
(86,491 | ) | (10,868 | ) | — | |||||||
Unrealized derivative (gains) losses |
(5,654 | ) | 3,505 | (1,793 | ) | |||||||
Allowance for bad debts |
80 | 675 | 1,762 | |||||||||
Amortization of deferred financing costs and discount |
1,827 | 1,662 | 1,071 | |||||||||
Non-cash compensation |
27,455 | 37,391 | 20,667 | |||||||||
(Gain) loss on sale of assets and other |
940 | (512 | ) | (3,109 | ) | |||||||
Changes in working capital, net of amounts from business
acquisitions: |
||||||||||||
Accounts receivable |
32,881 | (44,533 | ) | (25,898 | ) | |||||||
Inventory and other |
(1,157 | ) | (3,452 | ) | (6,080 | ) | ||||||
Accounts payable |
(5,049 | ) | 27,472 | 34,746 | ||||||||
Accrued liabilities and other |
(1,861 | ) | 3,538 | 8,398 | ||||||||
Net cash provided from continuing operations |
467,615 | 325,745 | 209,249 | |||||||||
Net cash provided from discontinued operations |
12,260 | — | — | |||||||||
Net cash provided from operating activities |
479,875 | 325,745 | 209,249 | |||||||||
Investing activities: |
||||||||||||
Additions to oil and gas properties |
(502,944 | ) | (276,907 | ) | (166,560 | ) | ||||||
Additions to field service assets |
(14,449 | ) | (11,310 | ) | (4,237 | ) | ||||||
Acquisitions, net of cash acquired |
(360,149 | ) | (153,600 | ) | (485,564 | ) | ||||||
Investing activities of discontinued operations |
(13,496 | ) | — | — | ||||||||
Investment in equity method affiliate and other assets |
(21,009 | ) | — | — | ||||||||
Proceeds from disposal of assets and other repayments |
388 | 9,440 | 32,060 | |||||||||
Net cash used in investing activities |
(911,659 | ) | (432,377 | ) | (624,301 | ) | ||||||
Financing activities: |
||||||||||||
Borrowings on credit facilities |
802,500 | 299,000 | 634,578 | |||||||||
Repayments on credit facilities |
(619,700 | ) | (453,700 | ) | (528,878 | ) | ||||||
Issuance of subordinated notes |
249,500 | 150,000 | 98,125 | |||||||||
Treasury stock purchases |
— | (2,808 | ) | — | ||||||||
Dividends paid – common stock |
(12,189 | ) | (7,614 | ) | (3,219 | ) | ||||||
– preferred stock |
— | (2,213 | ) | (2,950 | ) | |||||||
Debt issuance costs |
(6,960 | ) | (4,119 | ) | (3,630 | ) | ||||||
Issuance of common stock |
16,265 | 114,470 | 250,460 | |||||||||
Other debt repayments |
— | (16 | ) | (11,683 | ) | |||||||
Net cash provided from financing activities |
429,416 | 93,000 | 432,803 | |||||||||
Net increase (decrease) in cash and equivalents |
(2,368 | ) | (13,632 | ) | 17,751 | |||||||
Cash and equivalents at beginning of year |
4,750 | 18,382 | 631 | |||||||||
Cash and equivalents at end of year |
$ | 2,382 | $ | 4,750 | $ | 18,382 | ||||||
See accompanying notes.
F-7
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)
| Accumulated | ||||||||||||||||||||||||||||||||||||||||||||
| Preferred stock | Common stock | Treasury | Additional | Retained | Stock held | other | ||||||||||||||||||||||||||||||||||||||
| Par | Par | common | paid-in | earnings | by employee | Deferred | comprehensive | |||||||||||||||||||||||||||||||||||||
| Shares | Value | Shares | Value | stock | capital | (deficit) | benefit trust | compensation | (loss)/gain | Total | ||||||||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||
Issuance of common stock |
— | — | 9,018 | 90 | — | 234,475 | — | (10,204 | ) | 4,635 | — | 228,996 | ||||||||||||||||||||||||||||||||
Common dividends
($0.09 per share) |
— | — | — | — | — | — | (12,189 | ) | — | — | — | (12,189 | ) | |||||||||||||||||||||||||||||||
Treasury stock issuances |
— | — | — | — | 81 | — | — | — | — | — | 81 | |||||||||||||||||||||||||||||||||
Other comprehensive gain |
— | — | — | — | — | — | — | — | — | 183,648 | 183,648 | |||||||||||||||||||||||||||||||||
Net income |
— | — | — | — | — | — | 158,702 | — | — | — | 158,702 | |||||||||||||||||||||||||||||||||
Balance
December 31, 2006 |
— | $ | — | 138,931 | $ | 1,389 | $ | — | $ | 1,079,994 | $ | 160,313 | $ | (22,056 | ) | $ | — | $ | 36,521 | $ | 1,256,161 | |||||||||||||||||||||||
See accompanying notes.
F-8
Table of Contents
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Net income |
$ | 158,702 | $ | 111,011 | $ | 42,231 | ||||||
Net deferred
hedging gains (losses), net of tax: |
||||||||||||
Contract settlements reclassified to income |
29,302 | 101,209 | 63,633 | |||||||||
Change in unrealized deferred hedging gains (losses) |
152,294 | (206,348 | ) | (64,477 | ) | |||||||
Change in unrealized gains on securities held by
deferred compensation plan, net of taxes |
2,052 | 1,313 | 395 | |||||||||
Comprehensive income |
$ | 342,350 | $ | 7,185 | $ | 41,782 | ||||||
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 all of our
subsidiaries. The statement of operations for the year ended December 31, 2004 includes
50% of the revenues and expenses of Great Lakes up to June 23, 2004 and 100% thereafter.
Investments in entities over which we have significant influence, but not control, are accounted
for using the equity method of accounting and are carried at our share of net assets plus loans and
advances. Income from equity method investments represents our proportionate share of income
generated by equity method investees and is included in other revenues on our consolidated
statement of operations. All material 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.
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 issuance of stock compensation awards 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 (“FASB”), Statement of Financial Accounting Standards
(“SFAS”) No. 131, “Disclosure About Segments of an Enterprise and Related Information,” 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 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 complete 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
$745,900 at December 31, 2006 compared to $623,800 at December 31, 2005.
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, 2006
and December 31, 2005 were not significant. At December 31, 2006, we had recorded a net liability
of $441,200 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.
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 (“DD&A”) rates were $1.68 per mcfe in 2006 compared to
$1.46 per mcfe in 2005 and $1.44 per mcfe in 2004. Depletion is provided on the units of
production method. Unproved properties had a net book value of $226.3 million at December 31, 2006
compared to $28.6 million at December 31, 2005 and $14.8 million at December 31, 2004. The
increase in unproved properties in 2006 is primarily related to
our Stroud acquisition completed in 2006.
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 is less than the estimated expected undiscounted future
net cash flows. The expected future net cash flows are estimated based on our plans to 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. In the third quarter of 2006, we recorded in DD&A a $2.4 million impairment on an
offshore property due to declining oil and gas prices. In the fourth quarter of 2006, we lowered
our salvage value estimates on our Appalachia wells which increased DD&A expense by $4.6 million.
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 $7.5
million in 2006 compared to $6.4 million in 2005 and $4.7 million in 2004.
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 instruments. When an instrument is retired prior to
maturity or modifications significantly change the cash flows, related unamortized costs are expensed. Other assets at
December 31, 2006 include $13.4 million of unamortized debt issuance costs, $44.2 million of
marketable securities held in our deferred compensation plans and $9.0 million of other
investments.
Stock-based Compensation
The 2005 Equity Based Compensation Plan (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 (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 May 18, 2005, the 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
vest over a three year period and expire five years from the date they are granted. Similar to
stock options, stock appreciation rights (“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 instead of options to reduce 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. Compensation expense is
recognized over the balance of the vesting period.
Prior to January 1, 2006, we accounted for stock options granted under our stock-based
compensation plans under the recognition and measurement provisions of APB Opinion No. 25,
“Accounting for Stock Issued to Employees” and related Interpretations, as permitted by SFAS No.
123, “Accounting for Stock-Based Compensation.” For our stock options, no stock-based compensation
expense was recognized in our statements of operations prior to January 1, 2006, as all stock
options granted had an exercise price equal to the market value of the underlying common stock on
the date of grant. Effective January 1, 2006, we adopted the fair value recognition provisions of
SFAS No. 123(R), “Share-Based Payment,” using the modified prospective transition method. Under
this transition method, compensation cost for stock options and stock appreciation rights
recognized in 2006 includes (a) compensation cost ($11.2 million) for
all stock-based payments granted prior to, but not yet vested as of December 31, 2005, based on the
remaining service period and the grant date fair value estimated in accordance with the original
provisions of Statement No. 123 and (b) compensation cost ($3.7 million) for all stock-based
payments granted subsequent to December 31, 2005, based on the service period
(on a straight line basis) and the grant-date
fair value estimated in accordance with SFAS No. 123(R). Pursuant to SFAS No. 123(R), results for
prior periods have not been restated. In 2006, stock–based compensation has been allocated to
direct operating expense ($1.4 million), exploration expense ($2.5 million), general and
administrative expense ($10.7 million) and a $303,000 reduction to transportation and gathering
revenues to align SFAS No. 123(R) expense with the employee’s cash compensation.
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We
also began granting stock-settled SARs in July 2005 as part of our stock-based compensation
plans to reduce the dilutive impact of our equity plans. Prior to January 1, 2006, we accounted
for these SARs grants under the recognition and measurement provisions of APB Opinion No. 25, which
required expense to be recognized equal to the amount by which the quoted market value exceeded the
original grant price on a mark-to-market basis. Therefore, we recognized $5.8 million of
compensation cost in the last six months of 2005 related to SARs. In order to present stock-based
compensation expense on a consistent basis, the $5.8 million of 2005 SARs related expense has been
allocated to direct operating expense ($480,000), exploration expense ($1.2 million), general and
administrative expense ($4.0 million) and a $117,000 reduction to transportation and gathering
revenues. Beginning January 1, 2006, as required under the provisions of SFAS No. 123(R), those
SARs granted prior to, but not yet vested as of December 31, 2005, are being expensed over the
service period based on grant date fair value estimated in accordance with the original provisions
of SFAS No. 123 and all SARs granted subsequent to December 31, 2005 are being expensed over the
service period on a straight line basis based on grant-date fair value estimated in accordance with SFAS No. 123(R).
As a result of adopting SFAS No. 123(R) on January 1, 2006, our income from continuing
operations before income taxes and net income for 2006 is $18.2 million and $11.5 million lower,
respectively, than if we had continued to account for stock-based compensation under APB Opinion
No. 25. Also, as a result of adopting SFAS No. 123(R), our December 31, 2005 unearned deferred
compensation and additional paid-in capital related to our restricted stock issuances was
eliminated. As of December 31, 2006, there was $12.4 million of unrecognized compensation related
to restricted stock awards expected to be recognized over the next 3 years.
The following table illustrates the effect on net income and earnings per share if we had
applied the fair value recognition provisions of SFAS No. 123(R) to options and SARs granted under
our stock-based compensation plans in 2005 and 2004. For the purposes of this pro forma
disclosure, the value is estimated using a Black-Scholes-Merton option-pricing formula and expensed
over the option’s vesting periods.
| Year Ended December 31, | ||||||||
| 2005 | 2004 | |||||||
| (in thousands, except per share data) | ||||||||
Net income as reported |
$ | 111,011 | $ | 42,231 | ||||
Add: Total stock-based employee compensation
expense
included in net income, net of tax |
23,556 | 13,020 | ||||||
Deduct: Total stock-based employee compensation
expense determined under fair value
based method, net of tax |
(29,235 | ) | (17,114 | ) | ||||
Pro forma net income |
$ | 105,332 | $ | 38,137 | ||||
Earnings per share: |
||||||||
Basic – as reported |
$ | 0.89 | $ | 0.40 | ||||
Basic – pro forma |
0.85 | 0.35 | ||||||
Diluted – as reported |
0.86 | 0.38 | ||||||
Diluted – pro forma |
0.82 | 0.34 | ||||||
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 assumptions used for 2005 and 2004: fair value of $8.48 and $4.52 per share;
expected dividend per share of $0.08 and $0.04; expected historical volatility factors of 54% and 67%;
risk-free interest rates of 4.1% and 3.5%, 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
(“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
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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 $149.8 million gain
recorded in OCI at December 31, 2006, $89.0 million is expected to be reclassified to income in
2007, if prices remain at their December 31, 2006 levels. Actual amounts that will be reclassified
will vary as a result of changes in prices. 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 volatility of gas
prices on the correlation between realized prices and hedge reference prices. As a result, we
recognized a gain of $10.9 million in the fourth quarter of 2005 and a gain of $86.5 million in the
year ended December 31, 2006 related to these oil and gas derivatives that no longer
qualify for hedge accounting. We expect these derivative positions will continue to be
marked to market going forward. This may result in more volatility in our income in future
periods.
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.
Deferred Taxes
Deferred tax assets and liabilities are recognized for the estimated future tax consequences
attributable to the differences between the financial statement carrying amounts of assets and
liabilities and their tax bases as reported in our filings with the respective taxing authorities.
The realization of deferred tax assets is assessed periodically based on several interrelated
factors. These factors include our expectation to generate sufficient taxable income including tax
credits and operating loss carryforwards.
Accumulated Other Comprehensive Income (Loss)
We follow the provisions of SFAS No. 130, “Reporting Comprehensive Income” which establishes
standards for reporting comprehensive income. Comprehensive income 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, 2006, we had a $51.3 million pre-tax gain in OCI relating to unrealized
commodity hedges. We also had a pre-tax gain of $6.2 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, 2006, were as follows (in thousands):
| Gross | Tax Effect | Net of Tax | ||||||||||
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 | ) | |||||||
Contract settlements reclassified to income |
46,511 | (17,209 | ) | 29,302 | ||||||||
Change in
unrealized deferred hedging gains |
242,122 | (89,828 | ) | 152,294 | ||||||||
Change in unrealized gains (losses) on
securities held by deferred compensation plan |
3,203 | (1,151 | ) | 2,052 | ||||||||
Accumulated other comprehensive income at December 31,
2006 |
$ | 57,473 | $ | (20,952 | ) | $ | 36,521 | |||||
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Reclassifications
Certain reclassifications of prior years’ data have been made to conform with our current year
classification. This includes a reclassification in 2005 of our SARs mark-to-market expense of
$5.8 million from deferred compensation plan expense to direct operating expense ($480,000),
exploration expense ($1.2 million), general and administrative expense ($4.0 million) and a
$117,000 reduction of gas transportation revenues. This reclassification was made to align the
expense with employee cash compensation. These reclassifications did not impact our net income,
stockholders’ equity or cash flows.
Accounting Pronouncements Implemented
In December 2004, the FASB issued SFAS No. 123(R) as a revision of SFAS No. 123, “Accounting
for Stock-Based Compensation.” This statement requires entities to measure the cost of employee
services received in exchange for an award of equity instruments based on the fair value of the
award on the grant date. That cost is recognized over the period during which an employee is
required to provide service in exchange for the award, usually the vesting period. In addition,
awards classified as liabilities are remeasured at fair value each reporting period.
We adopted SFAS No. 123(R) as of January 1, 2006, for all awards granted, modified or
cancelled after adoption, and for the unvested portion of awards outstanding at January 1, 2006.
At the date of adoption, SFAS No. 123(R) requires that an assumed forfeiture rate be applied to any
unvested awards and that awards classified as liabilities be measured at fair value. Prior to
adopting SFAS No. 123(R), we recognized forfeitures as they occurred and applied the intrinsic
value method to awards classified as liabilities.
SFAS No. 123(R) also requires a company to calculate the pool of excess tax benefits available
to absorb tax deficiencies recognized subsequent to adopting the statement. In November 2005, the
FASB issued FASB Staff Position No. 123(R)-3, “Transition Election Related to Accounting for the
Tax Effects of Share-Based Payment Awards,” to provide an alternative transition election (the
“short-cut method”) to account for the tax effects of share-based payment awards to employees. We
elected the short-cut method to determine our pool of excess tax benefits as of January 1, 2006.
See
“Stock-based compensation” above and Note 12 to the consolidated financial statements for
the disclosures regarding share-based payments required by SFAS No. 123(R).
Effective January 1, 2006, we adopted SFAS No. 154, “Accounting Changes and Error Corrections
– A Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 requires companies
to recognize (1) voluntary changes in accounting principle and (2) changes required by a new
accounting pronouncement, when the pronouncement does not include specific transition provisions,
retrospectively to prior periods’ financial statements, unless it is impracticable to determine
either the period-specific effects or the cumulative effect of the change. The adoption had no
immediate effect on our financial statements.
In September 2006, the SEC issued SEC Staff Accounting Bulletin (“SAB”) No. 108, “Financial
Statements – Considering the Effects of Prior-Year Misstatements When Quantifying Misstatements in
Current Year Financial Statements.” SAB No. 108 addresses how a registrant should quantify the
effect of an error in the financial statements for purposes of assessing materiality and requires
that the effect be computed using both the current year income statement perspective (“rollover”)
and the year-end balance sheet perspective (“iron curtain”) methods for fiscal years ending after
November 15, 2006. If a change in the method of quantifying errors is required under SAB No. 108,
this represents a change in accounting policy; therefore, if the use of both methods results in a
larger, material misstatement than the previously applied method, the financial statements must be
adjusted. SAB No. 108 allows the cumulative effect of such adjustments to be made to opening
retained earnings upon adoption. The adoption of SAB No. 108 did not have a significant effect on
our consolidated results of operations, financial position or cash flows.
Accounting Pronouncements Not Yet Adopted
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement
defines fair value, establishes a framework for measuring fair value in generally accepted
accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not
require any new fair value measurements but may require some entities to change their measurement
practices. For Range, SFAS No. 157 will be effective January 1, 2008, with early application
permitted. We are currently evaluating the provisions of this statement.
In July 2006, the FASB issued FASB Interpretation (“FIN”) 48, “Accounting for Uncertainty in
Income Taxes – An Interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for
uncertain income taxes recognized in an enterprise’s financial statements in accordance with SFAS
No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement
attribute for the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. The new standard also provides guidance on derecognition,
classification, interest and penalties, accounting in interim
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periods and disclosure. The
cumulative effect of adoption FIN 48 will be recorded in retained earnings. For Range, the
provisions of FIN 48 are effective January 1, 2007. We are currently evaluating the provisions of
FIN 48 to determine the impact on our consolidated financial statements but we do not expect a
material impact on our financial position or results of operations.
In June 2006, the FASB ratified the consensus reached by the EITF regarding Issue No. 06-03,
“How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in
the Income Statement (That Is, Gross versus Net Presentation).” Included in the scope of this
issue are any taxes assessed by a governmental authority that are imposed on and concurrent with a
specific revenue-producing transaction between a seller and a customer. The EITF concluded that
the presentation of such taxes on a gross basis (included in revenues and costs) or a net basis
(excluded from revenues) is an accounting policy decision that should be disclosed pursuant to APB
Opinion No. 22. In addition, the amounts of such taxes reported on a gross basis must be disclosed
if those tax amounts are significant. For Range, the disclosure prescribed by this consensus is
required in our 2007 consolidated financial statements but early application is permitted.
(3) ACQUISITIONS AND DISPOSITIONS
Acquisitions are accounted for as purchases, and accordingly, the results of operations are
included in our statement of operations from the closing 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 $709.0 million in 2006 compared to $173.5 million in 2005 and $648.2 million in
2004. These purchases included $630.1 million, $152.8 million and $619.0 million for proved oil
and gas reserves, respectively; the remainder represents unproved acreage purchases. As part of
our acquisitions for 2006, we allocated $140.0 million to the Austin Chalk properties which were
classified as Assets Held for Sale at December 31, 2006. As part of our acquisitions for 2004, we
allocated $15.5 million to gathering facilities acquired in the transactions. See also Note 19 –
“Costs Incurred for Property Acquisition, Exploration and Development.”
Our purchases in 2006 include the acquisition in June of Stroud Energy, Inc. (“Stroud”), a
private oil and gas company with operations in the Barnett Shale in North Texas, the Cotton Valley
in East Texas and the Austin Chalk in Central Texas. To acquire Stroud, we paid $171.5 million of
cash (including transaction costs) and issued 6.5 million shares of our common stock. The cash
portion of the acquisition was funded with borrowings under our bank facility. We also assumed
$106.7 million of Stroud’s debt which was retired with borrowings under our bank facility. The
fair value of consideration issued was based on the average of our stock price for the five day
period before and after May 11, 2006, the date the acquisition was announced. See also Note 4 for
discussion of assets held for sale.
The following table summarizes the final purchase price allocation of fair values of assets
acquired and liabilities assumed at closing (in thousands):
Purchase price: |
||||
Cash paid (including transaction costs) |
$ | 171,529 | ||
6.5 million shares of common stock (at fair value of
$27.26 per share) |
177,641 | |||
Stock options assumed (652,000 options) |
9,478 | |||
Debt retired |
106,700 | |||
Total |
$ | 465,348 | ||
Allocation of purchase price: |
||||
Working capital deficit |
$ | (13,557 | ) | |
Other long-term assets |
55 | |||
Oil and gas properties |
487,345 | |||
Assets held for sale |
140,000 | |||
Deferred income taxes |
(147,062 | ) | ||
Asset retirement obligations |
(1,433 | ) | ||
Total |
$ | 465,348 | ||
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The following unaudited pro forma data include the results of operations as if the Stroud
acquisition had been consummated at the beginning of 2005. The pro forma information for 2005
includes two material non-recurring amounts not directly related to the transaction and not
expected to reoccur. The year ended December 31, 2005 pro forma information includes an
$18.4 million pre-tax stock compensation expense related to restricted and unrestricted shares
issued to Stroud management and employees and a pre-tax $6.2 million loss on repurchase of
mandatorily redeemable preferred units. The pro forma data is based on historical information and
does not necessarily reflect the actual results that would have occurred nor are they necessarily
indicative of future results of operations (in thousands, except per share data).
| Year Ended | ||||||||
| December 31, | ||||||||
| 2006 | 2005 | |||||||
Revenues |
$ | 814,548 | $ | 553,345 | ||||
Income from continuing operations |
$ | 320,859 | $ | 133,433 | ||||
Net income |
$ | 161,998 | $ | 95,066 | ||||
Per share data: |
||||||||
Income from continuing operations-basic |
$ | 1.44 | $ | 0.63 | ||||
Income from continuing operations-diluted |
$ | 1.39 | $ | 0.61 | ||||
Net income – basic |
$ | 1.18 | $ | 0.73 | ||||
Net income – diluted |
$ | 1.14 | $ | 0.70 | ||||
In 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. Also in 2004, we purchased the
50% of Great Lakes we did not previously own for $200.0 million cash 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 unaudited pro forma data include the results of operations of the Pine Mountain
and Great Lakes 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, except per share amounts).
| 2004 | ||||
Revenues |
$ | 377,564 | ||
Income before income taxes |
84,484 | |||
Net income |
53,385 | |||
Earnings per common share: |
||||
– Basic |
$ | 0.44 | ||
– Diluted |
$ | 0.42 | ||
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(4) ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
As part of the Stroud acquisition (see discussion in Note 3), we purchased Austin Chalk
properties in Central Texas which were sold in February 2007 for
proceeds of $80.4 million. We originally allocated $140.0
million to these properties. However, subsequent to the acquisition
natural gas prices started to decline. As a result, we recognized
impairment of $74.9 million, and at December 31, 2006 the carrying value is equal to sales proceeds less costs to sell. See also Note 17.
We believe we have met the criteria of SFAS No. 144 “Accounting for the Impairment or Disposal of
Long-Lived Assets” that allow us to classify these assets as held for sale on our balance sheet and
have presented the results of operations (revenues less direct expenses, interest, impairment and
taxes) as discontinued operations in all future periods. Discontinued operations for the year
ended December 31, 2006 are summarized as follows (in thousands):
| June 19, | ||||
| 2006 through | ||||
| December 31, | ||||
| 2006 | ||||
Revenues |
$ | 19,342 | ||
Less: |
||||
Direct
operating, production and ad valorem taxes |
1,803 | |||
General, administrative and exploration expense |
1,236 | |||
Interest expense (1) |
1,504 | |||
Impairment and accretion expense (2) |
74,941 | |||
Loss before income taxes |
(60,142 | ) | ||
Income tax benefit |
21,230 | |||
Net loss from discontinued operations |
$ | (38,912 | ) | |
Average daily production: |
||||
Crude oil (bbls) |
96 | |||
Natural gas (mcf) |
17,300 | |||
Total (per mcfe) |
17,876 | |||
| (1) | Interest expense is allocated to discontinued operations based on our ratio of consolidated debt to equity at the time of the acquisition. | |
| (2) | Impairment expense includes losses in fair value resulting from lower oil and gas prices and volumes produced since the acquisition date. |
(5) INCOME TAXES
Our income tax expense from continuing operations was $123.7 million for the year ended
December 31, 2006 compared to $66.4 million in 2005 and $24.5 million in 2004. A reconciliation
between the statutory federal income tax rate and our effective income tax rate is as follows:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Federal statutory tax rate |
35 | % | 35 | % | 35 | % | ||||||
State |
4 | 2 | 2 | |||||||||
Consolidated effective tax rate |
39 | % | 37 | % | 37 | % | ||||||
Income taxes
paid (in thousands) |
$ | 1,973 | $ | 615 | $ | 150 | ||||||
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Income tax provision (benefit) attributable to income from continuing operations consists of the following:
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
Current: |
||||||||||||
U.S. federal |
$ | 150 | $ | — | $ | (192 | ) | |||||
U.S. state and local |
1,762 | 1,071 | (53 | ) | ||||||||
| $ | 1,912 | $ | 1,071 | $ | (245 | ) | ||||||
Deferred: |
||||||||||||
U.S. federal |
$ | 112,270 | $ | 61,767 | $ | 23,450 | ||||||
U.S. state and local |
9,544 | 3,530 | 1,340 | |||||||||
| $ | 121,814 | $ | 65,297 | $ | 24,790 | |||||||
Significant
components of deferred tax assets and liabilities are as follows:
| December 31, | ||||||||
| 2006 | 2005 | |||||||
| (in thousands) | ||||||||
Deferred tax assets |
||||||||
Net operating loss carryover |
$ | 69,141 | $ | 76,944 | ||||
Allowance for doubtful accounts |
962 | 1,166 | ||||||
Net unrealized loss in OCI |
— | 85,462 | ||||||
Deferred compensation |
38,664 | 27,721 | ||||||
AMT credits and other |
30,641 | 44,738 | ||||||
Total deferred tax assets |
139,408 | 236,031 | ||||||
Deferred tax liabilities |
||||||||
Depreciation and depletion |
(547,899 | ) | (346,070 | ) | ||||
Net unrealized gain in OCI |
(21,264 | ) | — | |||||
Valuation allowance and other |
(38,888 | ) | (3,101 | ) | ||||
Total deferred tax liabilities |
(608,051 | ) | (349,171 | ) | ||||
Net deferred tax liability |
$ | (468,643 | ) | $ | (113,140 | ) | ||
At
December 31, 2006, deferred tax liabilities exceeded deferred
tax assets by $468.6 million,
with $21.3 million of deferred tax liabilities related to net deferred hedging gains 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, 2006, we had regular net operating loss
(“NOL”) carryovers of $229.6 million
and alternative minimum tax (“AMT”) NOL carryovers of $192.4 million that expire between 2012 and
2026. 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, 2006, we have AMT credit carryovers of $700,000 that are not subject to
limitation or expiration.
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(6) 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, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
Numerator: |
||||||||||||
Income from continuing operations |
$ | 197,614 | $ | 111,011 | $ | 42,231 | ||||||
Loss from discontinued operations |
(38,912 | ) | — | — | ||||||||
Preferred stock dividends |
— | — | (5,163 | ) | ||||||||
Net income |
$ | 158,702 | $ | 111,011 | $ | 37,068 | ||||||
Denominator: |
||||||||||||
Weighted average shares outstanding |
135,016 | 126,339 | 96,050 | |||||||||
Stock held in deferred compensation plan and treasury shares |
(1,265 | ) | (2,209 | ) | (2,506 | ) | ||||||
Weighted average shares, basic |
133,751 | 124,130 | 93,544 | |||||||||
Effect of dilutive securities: |
||||||||||||
Weighted average shares outstanding |
135,016 | 126,339 | 96,050 | |||||||||
Employee stock options and other |
3,696 | 2,863 | 1,948 | |||||||||
Treasury shares |
(1 | ) | (76 | ) | — | |||||||
Dilutive potential common shares for diluted earnings per share |
138,711 | 129,126 | 97,998 | |||||||||
Basic – income from continuing operations |
$ | 1.48 | $ | 0.89 | $ | 0.40 | ||||||
– discontinued operations |
(0.29 | ) | — | — | ||||||||
– net income |
$ | $1.19 | $ | 0.89 | $ | 0.40 | ||||||
Diluted – income from continuing operations |
$ | 1.42 | $ | 0.86 | $ | 0.38 | ||||||
– discontinued operations |
(0.28 | ) | — | — | ||||||||
– net income |
$ | 1.14 | $ | 0.86 | $ | 0.38 | ||||||
Stock appreciation rights for 88,500 shares were outstanding but not included in the
computations of diluted net income per share for the year ended December 31, 2006 because the
exercise price of the SARs was greater than the average price of the common shares and would be
anti-dilutive to the computations. Options to purchase 318,200 shares of common stock were
outstanding but not included in the computation of diluted net income per shares for the year ended
December 31, 2004 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.
F-20
Table of Contents
(7) SUSPENDED EXPLORATORY WELL COSTS
The following table reflects the changes in capitalized exploratory well costs for the year
ended December 31, 2006, 2005 and 2004 (in thousands):
| 2006 | 2005 | 2004 | ||||||||||
Balance at beginning of period |
$ | 25,340 | $ | 7,332 | $ | 2,043 | ||||||
Additions to capitalized exploratory well costs pending
the
determination of proved reserves |
4,695 | 26,915 | 4,767 | |||||||||
Additions due to purchase of Great Lakes |
— | — | 2,012 | |||||||||
Reclassifications to wells, facilities and equipment based
on determination of proved reserves |
(16,710 | ) | (8,614 | ) | (784 | ) | ||||||
Capitalized exploratory well costs charged to expense |
(3,341 | ) | (293 | ) | (706 | ) | ||||||
Balance at end of period |
9,984 | 25,340 | 7,332 | |||||||||
Less exploratory well costs that have been capitalized for
a period of one year or less |
(4,792 | ) | (21,589 | ) | (6,124 | ) | ||||||
Capitalized exploratory well costs that have been capitalized for
a period greater than one year |
$ | 5,192 | $ | 3,751 | $ | 1,208 | ||||||
Number of projects that have exploratory well costs that have
been capitalized for a period greater than one year |
3 | 3 | 3 | |||||||||
As of December 31, 2006, of the $5.2 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. None of the wells are operated by us. The $10.0
million of capitalized exploratory well costs at December 31, 2006 was incurred in 2006 ($4.7
million), in 2005 ($2.9 million) and in 2004 ($2.4 million).
(8) INDEBTEDNESS
We had the following debt outstanding as of the dates shown below (bank debt interest rate at
December 31, 2006 is shown parenthetically). No interest was capitalized during 2006, 2005, and
2004 (in thousands):
| December 31, | ||||||||
| 2006 | 2005 | |||||||
Bank debt (6.4%) |
$ | 452,000 | $ | 269,200 | ||||
Senior Subordinated Notes: |
||||||||
7.375% Senior Subordinated Notes due 2013, net
of $2.7 million and $3.1 million discount, respectively |
197,262 | 196,948 | ||||||
6.375% Senior Subordinated Notes due 2015 |
150,000 | 150,000 | ||||||
7.5% Senior Subordinated Notes
due 2016, net of $480,000 discount |
249,520 | — | ||||||
Total debt |
$ | 1,048,782 | $ | 616,148 | ||||
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Table of Contents
Bank Debt
In October 2006, we entered into an amended and restated $800.0 million revolving bank credit
facility, which we refer to as our bank debt or bank credit facility, which is secured by
substantially all of our assets. The bank credit facility provides for an initial commitment equal
to the lesser of an $800.0 million facility amount or the borrowing base. The borrowing base as of February 22, 2007 was $1.2 billion. The bank credit facility
provides for a borrowing base subject to redeterminations semi-annually each April and October and
pursuant to certain unscheduled redeterminations. The facility amount may be increased to the
borrowing base amount with twenty days notice. As of December 31, 2006, the outstanding balance
under the bank credit facility was $452.0 million and there was $348.0 million of borrowing
capacity available. The loan matures on October 25, 2011. 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 our 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 6.4% and 4.5% for the years ended December 31, 2006
and 2005, respectively. A commitment fee is paid on the undrawn balance based on an annual rate of
0.25% to 0.375%. At December, 31, 2006, the commitment fee was 0.25% and the interest rate margin
was 1.0%. At February 22, 2007, the interest rate (including applicable margin) was 6.4%.
Senior Subordinated Notes
In 2003, we issued $100.0 million aggregate principal amount of 7.375% senior subordinated
notes due 2013 (“7.375% Notes”). In 2004, we issued an additional $100.0 million of 7.375% Notes;
therefore, $200.0 million of the 7.375% Notes are currently outstanding. The 7.375% Notes were
issued at a discount which will be amortized over the life of the 7.375% Notes into interest
expense. In 2005, we issued $150.0 million of 6.375% senior subordinated notes due 2015 (“6.375%
Notes”). In May 2006, we issued $150.0 million of the 7.5% Senior Subordinated Notes due 2016 (the
“7.5% Notes”). In August 2006, we issued an additional $100.0 million of the 7.5% Notes;
therefore, $250.0 million of the 7.5% Notes are currently outstanding. Interest on our senior
subordinated notes is payable semi-annually and each of the notes are guaranteed by certain of our
subsidiaries.
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 7.375% 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. 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 6.375% 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. We may redeem the 7.5% Notes, in whole or in part, at any time on or after May
15, 2011 at redemption prices from 103.75% of the principal amount as of May 15, 2011 and declining
to 100% on May 15, 2014 and thereafter. Prior to May 15, 2009, we may redeem up to 35% of the
original aggregate principal amount of the 7.5% Notes at a redemption price of 107.5% of principal
amount thereof plus accrued and unpaid interest if any, with the proceeds of certain equity
offerings; provided that at least 65% of the original aggregate principal amount of our 7.5% Notes
remains outstanding immediately after the occurrence of such redemption and provided that such
redemption occurs within 60 days of the date of closing the equity sale.
If we experience a change of control, there may be a requirement to repurchase all or a
portion of the senior subordinated notes at 101% of the principal amount plus accrued and unpaid
interest, if any. All of the senior subordinated 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 we or our subsidiary guarantors are permitted to incur
under the bank credit facility and the indentures governing the subordinated 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, the
6.375% Notes and the 7.5% Notes are full and unconditional and joint and several; any subsidiaries
other than the subsidiary guarantors are minor subsidiaries.
F-22
Table of Contents
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, 2006. 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 $446.4 million was available under the bank credit facility’s restricted payment
basket on December 31, 2006. The terms of each of our subordinated 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, 2006, approximately $496.2
million was available under the restricted payment baskets for each of the subordinated notes.
Following is the principal maturity schedule for the long-term debt outstanding as of December
31, 2006 (in thousands):
| Year Ended | ||||
| December 31: | ||||
2007 |
$ | — | ||
2008 |
— | |||
2009 |
— | |||
2010 |
— | |||
2011 |
452,000 | |||
2012 |
— | |||
Thereafter |
600,000 | |||
| $ | 1,052,000 | |||
(9) ASSET RETIREMENT OBLIGATION
A reconciliation of our liability for plugging and abandonment costs for the years ended
December 31, 2006 and 2005 is as follows (in thousands):
| 2006 | 2005 | |||||||
Beginning of period |
$ | 68,063 | $ | 70,727 | ||||
Liabilities incurred |
4,006 | 3,694 | ||||||
Acquisitions – continuing operations |
790 | 119 | ||||||
Acquisitions – discontinued operations |
742 | — | ||||||
Liabilities settled |
(3,057 | ) | (6,126 | ) | ||||
Accretion expense – continuing operations |
4,824 | 5,072 | ||||||
Accretion expense – discontinued operations |
37 | |||||||
Change in estimate |
20,183 | (5,423 | ) | |||||
End of period |
95,588 | 68,063 | ||||||
Less current portion |
(4,216 | ) | (3,166 | ) | ||||
Long-term portion |
$ | 91,372 | $ | 64,897 | ||||
Accretion expense is recognized as a component of depreciation, depletion and amortization.
The significant increase in 2006 as a result of changes in estimates is primarily related to rising
abandonment costs and lower gas prices which accelerated the timing
of abandonment.
F-23
Table of Contents
(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 affected 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 2005:
| Year Ended December 31, | ||||||||
| 2006 | 2005 | |||||||
Beginning balance |
129,907,220 | 121,829,027 | ||||||
Public offerings |
— | 6,900,000 | ||||||
Shares issued for Stroud acquisition |
6,517,498 | — | ||||||
Shares issued in lieu of bonuses |
20,686 | 25,590 | ||||||
Stock options/SARs exercised |
1,956,164 | 1,105,549 | ||||||
Restricted stock grants |
474,609 | — | ||||||
Deferred compensation plan |
12,998 | 20,885 | ||||||
Shares contributed to 401(k) plan |
36,564 | 33,018 | ||||||
Fractional shares |
— | (1,023 | ) | |||||
Treasury shares |
5,826 | (5,826 | ) | |||||
Ending balance |
138,931,565 | 129,907,220 | ||||||
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 certain
Permian basin properties.
Treasury Stock
During 2005, we bought in open market purchases, 201,000 shares at an average price of $14.00.
As of December 31, 2006, all of these shares had been used for equity compensation. The board of
directors has approved up to an additional $10.0 million of repurchases of common
stock based on market conditions and opportunities.
(11) FAIR VALUE OF FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
Financial instruments include cash and equivalents, receivables, payables, marketable
securities, debt and commodity and interest rate derivatives. The carrying value of cash and
equivalents, receivables, payables is considered to be representative of fair value because of
their short maturity.
F-24
Table of Contents
The following table sets forth our other financial instruments fair values at each of these
dates (in thousands):
| December 31, 2006 | December 31, 2005 | |||||||||||||||
| Book | Fair | Book | Fair | |||||||||||||
| Value | Value | Value | Value | |||||||||||||
Derivatives assets: |
||||||||||||||||
Commodity swaps and collars (a) |
$ | 154,656 | $ | 154,656 | $ | — | $ | — | ||||||||
Interest rate swaps (a) |
— | — | 425 | 425 | ||||||||||||
Derivatives liabilities: |
||||||||||||||||
Commodity swaps and collars(a) |
(4,887 | ) | (4,887 | ) | (231,049 | ) | (231,049 | ) | ||||||||
Net derivatives asset (liability) |
$ | 149,769 | $ | 149,769 | $ | (230,624 | ) | $ | (230,624 | ) | ||||||
Marketable securities (b) |
$ | 44,226 | $ | 44,226 | $ | 21,769 | $ | 21,769 | ||||||||
Long-term debt (c) |
$ | 1,048,782 | $ | 1,058,069 | $ | (616,148 | ) | $ | (619,523 | ) | ||||||
| (a) | All derivatives are marked to market and therefore their book value is assumed to be equal to fair value. | |
| (b) | Marketable securities held in our deferred compensation plans which are marked to market. | |
| (c) | The book value of our bank debt approximates fair value because of their floating rate structure. The fair value of our senior subordinated notes is based on current market quotes. |
At December 31, 2006, we had open swap contracts covering 73.6 Bcf of gas at prices
averaging $9.29 per mcf. We also had collars covering 56.1 Bcf of gas at weighted average floor
and cap prices of $7.42 to $10.49 per mcf and 4.5 million barrels of oil at weighted average floor
and cap prices of $55.72 to $70.11 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 gain of $149.8 million at
December 31, 2006. 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 2006, realized losses were $46.5 million relating to
our hedges compared with losses of $171.1 million in 2005 and losses of $100.1 million in 2004. In
the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting and
were marked to market. This resulted in a gain of $86.5 million in 2006 versus a gain of $10.9
million in 2005. Gains and losses due to commodity hedge ineffectiveness are recognized in
earnings in other revenues. The ineffective portion of hedges that qualified for hedge accounting
was a gain of $6.0 million in 2006 versus a loss of $3.4 million in 2005 and a gain of $712,000 in
2004.
The following table sets forth the hedging volumes by year as of December 31, 2006:
| Period | Contract Type | Volume Hedged | Average Hedge Price | |||
Natural Gas |
||||||
| 2007 | Swaps | 96,336 Mmbtu/day | $9.13 | |||
| 2007 | Collars | 98,500 Mmbtu/day | $7.13 – $9.99 | |||
| 2008 | Swaps | 105,000 Mmbtu/day | $9.42 | |||
| 2008 | Collars | 55,000 Mmbtu/day | $7.93 – $11.39 | |||
| Crude Oil | ||||||
| 2007 | Collars | 6,300 bbl/day | $53.46 – $65.33 | |||
| 2008 | Collars | 6,000 bbl/day | $58.09 – $75.11 |
In the past, we have used 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. Our interest rate swap agreements ended on June
30, 2006.
F-25
Table of Contents
The
combined fair value of net gains on oil and gas derivatives totaling $149.8 million
appears as unrealized derivative gains and unrealized derivative losses on our consolidated balance
sheet at December 31, 2006. 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.
(12) EMPLOYEE BENEFIT AND EQUITY PLANS
Stock and Option Plans
We have six equity-based stock 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. All awards granted under these plans have been issued at the
prevailing market price at the time of the grant. Information with respect to stock option and
SARs activities is summarized below:
| Weighted | ||||||||
| Average | ||||||||
| Exercise | ||||||||
| Shares | Price | |||||||
Outstanding at December 31, 2003 |
5,746,703 | $ | 3.58 | |||||
Granted |
2,514,750 | 7.74 | ||||||
Exercised |
(1,252,905 | ) | 3.46 | |||||
Expired/forfeited |
(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/forfeited |
(167,188 | ) | 9.08 | |||||
Outstanding at December 31, 2005 |
8,742,305 | 9.31 | ||||||
Granted |
1,658,160 | 24.36 | ||||||
Stock options assumed in Stroud acquisition |
652,062 | 19.67 | ||||||
Exercised |
(2,051,237 | ) | 9.22 | |||||
Expired/forfeited |
(149,164 | ) | 18.32 | |||||
Outstanding at December 31, 2006 |
8,852,126 | $ | 12.76 | |||||
The following table shows information with respect to outstanding stock options and SARs at
December 31, 2006:
| Outstanding | Exercisable | |||||||||||||||||||||||
| Weighted- | Weighted | |||||||||||||||||||||||
| Average | Weighted- | Average | ||||||||||||||||||||||
| Range of Exercise | Remaining | Average | Exercise | |||||||||||||||||||||
| Prices | Shares | Contractual Life | Exercise Price | Shares | Price | |||||||||||||||||||
| $ | 0.59 – $4.99 | 2,570,002 | 2.85 | $ | 3.60 | 2,570,002 | $ | 3.60 | ||||||||||||||||
| 5.00 – 9.99 | 1,375,008 | 2.13 | 7.01 | 660,046 | 7.02 | |||||||||||||||||||
| 10.00 – 14.99 | 368,673 | 2.85 | 11.50 | 196,412 | 12.13 | |||||||||||||||||||
| 15.00 – 19.99 | 2,821,048 | 3.78 | 16.98 | 844,274 | 17.58 | |||||||||||||||||||
| 20.00 – 24.99 | 1,554,395 | 4.26 | 24.20 | 97,885 | 24.04 | |||||||||||||||||||
| 25.00 – 30.80 | 163,000 | 4.33 | 26.55 | 21,150 | 25.85 | |||||||||||||||||||
| Total | 8,852,126 | 3.31 | $ | 12.76 | 4,389,769 | $ | 7.74 | |||||||||||||||||
F-26
Table of Contents
The weighted average fair value of an option/SAR to purchase one share of common stock during
2006 was $8.51. The fair value of each stock option/SAR granted during 2006 was estimated as of
the date of grant using the Black-Scholes-Merton option pricing model based on the following assumptions:
risk-free interest rate of 4.8%; dividend yield of 0.3%; expected volatility of 40.9%; and an
expected life of 3.5 years.
As of December 31, 2006, the aggregate intrinsic value (the difference in value between
exercise and market price) of the awards outstanding was $130.1 million. The aggregate intrinsic
value and weighted average remaining contractual life of stock option awards currently exercisable
was $86.5 million and 3.2 years. As of December 31, 2006, the number of fully-vested awards and
awards expected to vest was 8.7 million. The weighted average exercise price and weighted average
remaining contractual life of these awards were $12.60 and 3.3 years and the aggregate intrinsic
value was $128.8 million. As of December 31, 2006, unrecognized compensation cost related to the
awards was $16.5 million, which is expected to be recognized over a weighted average period of 0.84
years.
For the year ended December 31, 2006, total stock-based compensation expense due to the
adoption of SFAS 123(R) was $14.8 million. The total related tax
benefits were $2.3 million. For
the year ended December 31, 2006, cash received upon exercise of stock option/SARs awards was $16.3
million. Due to the net operating loss carryover for tax purposes, tax benefits realized for deductions that
were in excess of the stock-based compensation were not recognized.
Restricted Stock Grants
In 2006, we issued 499,200 shares of restricted stock grants as compensation to directors and
employees, at an average price of $24.43. The restricted grants included 15,000 issued to
directors, which vest immediately, and 484,200 to employees with vesting over a three-year period.
In 2005, we issued 192,500 shares of restricted stock grants (from treasury stock) as compensation
to directors 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 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 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 employees with vesting
over a three-year period. We recorded compensation expense for restricted stock grants of $4.3
million in the year ended December 31, 2006 compared to $942,000 in 2005 and $567,000 in 2004.
A summary of the status of our unvested restricted stock outstanding at December 31, 2006 and
changes during the twelve months then ended, is presented below:
| Weighted | ||||||||
| Average Grant | ||||||||
| Shares | Date Fair Value | |||||||
Outstanding at January 1, 2006 |
238,107 | $ | 14.20 | |||||
Granted |
499,161 | 24.43 | ||||||
Vested |
(212,129 | ) | 17.70 | |||||
Forfeited |
(23,628 | ) | 21.02 | |||||
Outstanding at December 31, 2006 |
501,511 | $ | 22.58 | |||||
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 2006, we
contributed $1.9 million to the 401(k) Plan compared to $1.5 million in 2005 and $1.2 million in
2004. 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, 2006, there were no rights outstanding to purchase shares and
there were 373,000 remaining shares authorized to be granted.
F-27
Table of Contents
Deferred Compensation Plan
In 1996, the Board of Directors adopted a deferred compensation plan (“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 (“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 deferred
compensation plan 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
stockholders’ equity. Changes in the market value of the marketable securities are reflected in
OCI, while changes in the fair value of the liability is charged or credited to deferred
compensation plan expense each quarter. We recorded mark-to-market expenses of $6.9 million in
2006 compared to $29.5 million in 2005 and $19.2 million in 2004. 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.
(13) SUPPLEMENTAL CASH FLOW INFORMATION
| Year Ended December 31, | |||||||||||||
| 2006 | 2005 | 2004 | |||||||||||
| (in thousands) | |||||||||||||
Net cash provided from continuing operations included: |
|||||||||||||
Income taxes paid to taxing authorities |
$ | 1,973 | $ | 615 | $ | 150 | |||||||
Interest paid |
55,925 | 34,148 | 19,216 | ||||||||||
Non-cash investing and finance activities: |
|||||||||||||
Common stock issued under benefit plans |
$ | 2,058 | $ | 3,180 | $ | 2,122 | |||||||
6.5 million shares issued for Stroud acquisition |
177,641 | — | — | ||||||||||
Stock options (652,000) issued in Stroud acquisition |
9,478 | — | — | ||||||||||
Preferred stock converted to common stock |
— | — | (50,000 | ) | |||||||||
Asset retirement costs capitalized, excluding acquisitions (a) |
25,821 | (1,730 | ) | 3,994 | |||||||||
| (a) | For information regarding purchase price allocations of businesses acquired see Note 3. |
(14) COMMITMENTS AND CONTINGENCIES
Litigation
We are involved in various legal actions and claims arising in the ordinary course of our
business. While the outcome of these lawsuits cannot be predicted with certainty, we do not expect
these matters to have a material adverse effect on our financial position, cash flows or results of
operations.
F-28
Table of Contents
Lease Commitments
We lease certain office space and equipment under cancelable and non-cancelable leases. Rent
expense under such arrangements totaled $5.0 million, $2.2 million and $1.7 million in 2006, 2005
and 2004, respectively. Future minimum rental commitments under non-cancelable leases having
remaining lease terms in excess of one year are as follows (in thousands):
| Operating | ||||
| Lease | ||||
| Obligations | ||||
2007 |
$ | 5,010 | ||
2008 |
5,308 | |||
2009 |
4,928 | |||
2010 |
3,867 | |||
2011 |
2,564 | |||
Thereafter |
9,610 | |||
Sublease rentals |
(222 | ) | ||
| $ | 31,065 | |||
Other Commitments
As of December 31, 2006, we have contracts with various drilling contractors to use two
drilling rigs in 2007 with terms of up to 2 years and minimum future commitments of $12.8 million
in 2007 and $2.2 million in 2008. Early termination of these contracts at December 31, 2006 would
have required us to pay maximum penalties of $11.3 million. We do not expect to pay any early
termination penalties related to these contracts.
(15) 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 year ended December 31,
2006, two customers each accounted for 10% or more of total oil and gas revenues and the combined
sales to those customers accounted for 25% of total oil and gas revenues. For the year ended
December 31, 2005, four customers each 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 year ended December 31, 2004, two customers each accounted for 10% or more of total oil and gas
revenue and combined sales to those two customers accounted for 25% 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.
F-29
Table of Contents
(16) EQUITY METHOD INVESTMENTS
On April 18, 2006, we acquired a 50% interest in Whipstock Natural Gas Services, LLC
(Whipstock), an unconsolidated investee in the business of providing oil and gas drilling
equipment, well servicing rigs and equipment, and other well services in Appalachia. On the
acquisition date, we contributed cash of $11.7 million representing the fair value of 50% of the
common stock of Whipstock.
We account for our investment in Whipstock under the equity method of accounting pursuant to
Accounting Principles Board Opinion No. 18, “The Equity Method of Accounting for Investments in
Common Stock.” Under this method, we record our proportionate share of Whipstock’s net earnings,
declared dividends and partnership distributions based on the most recently available financial
statements of the investee. There were no dividends or partnership distributions received from
Whipstock during the year ended December 31, 2006. Whipstock follows a calendar year basis of
financial reporting consistent with Range and our equity in Whipstock’s earnings from the
acquisition date through December 31, 2006 is included in our results of operations for 2006 in other revenue. In
determining our proportionate share of the net earnings of Whipstock, certain adjustments are
required to be made to Whipstock’s reported results. These adjustments are made to eliminate the
profits recognized by Whipstock for services provided to Range. For the year ended December 31,
2006, our equity in the earnings of Whipstock of $548,000 was reduced by $1.1 million in order to
eliminate the profit on services provided to Range. Range and Whipstock have entered into an
agreement whereby Whipstock will provide Range with the right of first refusal such that Range will
have the opportunity to secure services from Whipstock in preference to and in advance of Whipstock
entering into additional commitments for services with other customers. All services provided to
Range will be at Whipstock’s usual and customary terms. We also evaluate our equity method
investment for potential impairment whenever events or changes in circumstances indicate that there
is an other than temporary decline in value of the investment. Such events may include sustained
operating losses by the investee or long-term negative changes in the investee’s industry. These
indicators were not present, and as a result, we did not recognize any impairment charges related
to our investment in Whipstock for the year ended December 31, 2006.
Summarized financial information of investees accounted for under the equity method of
accounting is as follows:
| 2006 | ||||
| ($ in thousands) | ||||
Balance Sheet |
||||
Current assets |
$ | 5,871 | ||
Non-current assets |
30,261 | |||
Current liabilities |
(5,458 | ) | ||
Non-current liabilities |
(4,035 | ) | ||
Members’ equity |
26,639 | |||
Income Statement |
||||
Total revenues |
$ | 23,235 | ||
Gross profit |
7,653 | |||
Income from operations |
3,487 | |||
Interest expense |
(198 | ) | ||
Net income |
3,289 | |||
Our carrying value of our equity method investment is $300,000 higher than the underlying net
assets of the investee. This basis difference is being amortized into earnings over five years.
(17) SUBSEQUENT EVENTS
On February 13, 2007, we sold our Austin Chalk properties for net sales proceeds of $80.4 million.
These properties were classified as Assets Held for Sale at December 31, 2006. See also Note 3
and Note 4.
F-30
Table of Contents
(18) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.
| 2006 | ||||||||||||||||||||
| March | June | September | December | Total | ||||||||||||||||
Revenues |
||||||||||||||||||||
Oil and gas sales |
$ | 176,338 | $ | 157,620 | $ | 172,647 | $ | 177,323 | $ | 683,928 | ||||||||||
Transportation and gathering |
77 | 898 | 1,034 | 498 | 2,507 | |||||||||||||||
Mark-to-market on oil and gas derivatives |
11,281 | 17,503 | 54,950 | 2,757 | 86,491 | |||||||||||||||
Other |
1,432 | 1,572 | 249 | 3,549 | 6,802 | |||||||||||||||
Total revenues |
189,128 | 177,593 | 228,880 | 184,127 | 779,728 | |||||||||||||||
Costs and expenses |
||||||||||||||||||||
Direct operating |
19,662 | 20,541 | 24,784 | 27,237 | 92,224 | |||||||||||||||
Production and ad valorem taxes |
9,727 | 8,669 | 9,985 | 8,534 | 36,915 | |||||||||||||||
Exploration |
10,077 | 7,778 | 16,512 | 10,885 | 45,252 | |||||||||||||||
General and administrative |
11,330 | 12,514 | 12,170 | 13,872 | 49,886 | |||||||||||||||
Deferred compensation plan |
4,479 | (2,188 | ) | (2,638 | ) | 7,220 | 6,873 | |||||||||||||
Interest expense |
10,551 | 12,003 | 16,896 | 18,127 | 57,577 | |||||||||||||||
Depletion, depreciation and amortization |
34,567 | 36,833 | 46,243 | 52,018 | 169,661 | |||||||||||||||
Total costs and expenses |
100,393 | 96,150 | 123,952 | 137,893 | 458,388 | |||||||||||||||
Income from continuing operations |
88,735 | 81,443 | 104,928 | 46,234 | 321,340 | |||||||||||||||
Income tax |
||||||||||||||||||||
Current |
578 | 622 | 615 | 97 | 1,912 | |||||||||||||||
Deferred |
32,482 | 30,116 | 38,899 | 20,317 | 121,814 | |||||||||||||||
| 33,060 | 30,738 | 39,514 | 20,414 | 123,726 | ||||||||||||||||
Income from continuing operations |
55,675 | 50,705 | 65,414 | 25,820 | 197,614 | |||||||||||||||
Discontinued operations, net of taxes |
— | 565 | (14,084 | ) | (25,393 | ) | (38,912 | ) | ||||||||||||
Net income |
$ | 55,675 | $ | 51,270 | $ | 51,330 | $ | 427 | $ | 158,702 | ||||||||||
Earnings per common share: |
||||||||||||||||||||
Basic – income from continuing operations |
$ | 0.43 | $ | 0.39 | $ | 0.48 | $ | 0.19 | $ | 1.48 | ||||||||||
– discontinued operations |
— | — | (0.11 | ) | (0.19 | ) | (0.29 | ) | ||||||||||||
– net income |
$ | 0.43 | $ | 0.39 | $ | 0.37 | $ | — | $ | 1.19 | ||||||||||
Diluted – income from continuing operations |
$ | 0.41 | $ | 0.37 | $ | 0.46 | $ | 0.18 | $ | 1.42 | ||||||||||
– discontinued operations |
— | 0.01 | (0.10 | ) | (0.18 | ) | (0.28 | ) | ||||||||||||
– net income |
$ | 0.41 | $ | 0.38 | $ | 0.36 | $ | — | $ | 1.14 | ||||||||||
F-31
Table of Contents
| 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 | 703 | 599 | 2,461 | |||||||||||||||
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 | 141,790 | 166,406 | 535,840 | |||||||||||||||
Costs and expenses |
||||||||||||||||||||
Direct operating |
14,808 | 17,419 | 16,902 | 17,983 | 67,112 | |||||||||||||||
Production and ad valorem taxes |
5,755 | 7,034 | 8,457 | 10,270 | 31,516 | |||||||||||||||
Exploration |
3,271 | 9,124 | 7,725 | 10,484 | 30,604 | |||||||||||||||
General and administrative |
6,603 | 6,241 | 9,019 | 11,581 | 33,444 | |||||||||||||||
Deferred compensation plan |
4,067 | 5,276 | 17,450 | 2,681 | 29,474 | |||||||||||||||
Interest expense |
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 | 102,363 | 98,171 | 358,461 | |||||||||||||||
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 | ||||||||||
| (19) | 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,” (“SFAS No. 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, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
Oil and gas properties: |
||||||||||||
Properties subject to depletion |
$ | 3,414,964 | $ | 2,519,454 | $ | 2,082,236 | ||||||
Unproved properties |
226,263 | 28,636 | 14,790 | |||||||||
Total |
3,641,227 | 2,548,090 | 2,097,026 | |||||||||
Accumulated depreciation, depletion and
amortization |
(964,551 | ) | (806,908 | ) | (694,667 | ) | ||||||
Net capitalized costs |
$ | 2,676,676 | $ | 1,741,182 | $ | 1,402,359 | ||||||
| (a) | Includes capitalized asset retirement costs and the associated accumulated amortization. |
F-32
Table of Contents
| Year Ended December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
Acquisitions: |
||||||||||||
Acreage purchases |
$ | 79,762 | $ | 20,674 | $ | 9,690 | ||||||
Unproved leasehold |
132,821 | — | 4,043 | |||||||||
Proved oil and gas properties |
209,262 | 131,748 | 522,126 | |||||||||
Purchase price adjustment (b) |
147,062 | 20,966 | 79,352 | |||||||||
Asset retirement obligations |
896 | 119 | 17,524 | |||||||||
Development |
464,586 | 252,574 | 144,007 | |||||||||
Exploration (c) |
70,870 | 59,539 | 31,830 | |||||||||
Gas gathering facilities: |
||||||||||||
Acquisitions |
— | 8 | 15,539 | |||||||||
Exploratory |
3,418 | — | — | |||||||||
Development |
16,272 | 11,415 | 4,778 | |||||||||
Subtotal |
1,124,949 | 497,043 | 828,889 | |||||||||
Asset retirement obligations |
25,821 | (1,730 | ) | 3,994 | ||||||||
Total costs incurred |
$ | 1,150,770 | $ | 495,313 | $ | 832,883 | ||||||
Discontinued operations: |
||||||||||||
Acquisitions |
$ | 140,110 | $ | — | $ | — | ||||||
Development |
$ | 15,012 | $ | — | $ | — | ||||||
| (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 $45,252, $30,604 and $21,219 of exploration costs expensed in 2006, 2005 and 2004, respectively. Exploration expense includes $3,079 and $1,250 of stock-based compensation in 2006 and 2005. |
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, 2006 to estimate reserve information were
$57.66 per barrel for oil, $25.98 per barrel for natural gas liquids and $5.24 per mcf for gas,
using benchmark prices of $61.05 per barrel and $5.64 per Mmbtu. 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
F-33
Table of Contents
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.
| Crude Oil | Natural Gas | |||||||||||
| and NGLs | Natural Gas | Equivalents | ||||||||||
| (Mbbls) | (Mmcf) | (Mmcfe) | ||||||||||
Proved developed and undeveloped reserves: |
||||||||||||
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 | |||||||||
Revisions |
(42 | ) | (48,609 | ) | (48,863 | ) | ||||||
Extensions, discoveries and additions |
10,871 | 314,261 | 379,491 | |||||||||
Purchases |
242 | 121,683 | 123,133 | |||||||||
Sales |
(4 | ) | (1,500 | ) | (1,522 | ) | ||||||
Production |
(4,252 | ) | (75,267 | ) | (100,775 | ) | ||||||
Balance, December 31, 2006 (a) |
53,707 | 1,435,978 | 1,758,226 | |||||||||
Proved developed reserves: |
||||||||||||
December 31, 2004 |
27,715 | 580,006 | 746,299 | |||||||||
December 31, 2005 |
33,029 | 724,876 | 923,050 | |||||||||
December 31, 2006 |
37,750 | 875,395 | 1,101,895 | |||||||||
| (a) | The December 31, 2006 balance excludes reserves associated with the Austin Chalk properties that are shown as Assets Held for Sale on our balance sheet. The total proved developed and undeveloped reserves for these assets at December 31, 2006 were 42.3 Bcfe which is comprised of 39.3 Bcfe of gas. |
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 No. 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.
F-34
Table of Contents
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. 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. | ||
| 4. | 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, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
Future cash inflows |
$ | 10,192,067 | $ | 13,520,985 | $ | 7,109,349 | ||||||
Future costs: |
||||||||||||
Production |
(2,575,212 | ) | (2,266,828 | ) | (1,472,484 | ) | ||||||
Development |
(1,225,710 | ) | (825,261 | ) | (601,447 | ) | ||||||
Future net cash flows before income taxes |
6,391,145 | 10,428,896 | 5,035,418 | |||||||||
Future income tax expense |
(1,999,934 | ) | (3,496,799 | ) | (1,523,915 | ) | ||||||
Total future net cash flows before 10% discount |
4,391,211 | 6,932,097 | 3,511,503 | |||||||||
10% annual discount |
(2,388,987 | ) | (3,547,787 | ) | (1,762,092 | ) | ||||||
Standardized measure of discounted future net cash flows |
$ | 2,002,224 | $ | 3,384,310 | $ | 1,749,411 | ||||||
F-35
Table of Contents
The following table summarizes changes in the standardized measure of discounted future net cash flows.
| As of December 31, | ||||||||||||
| 2006 | 2005 | 2004 | ||||||||||
| (in thousands) | ||||||||||||
Beginning of period |
$ | 3,384,310 | $ | 1,749,411 | $ | 1,002,981 | ||||||
Revisions to previous estimates: |
||||||||||||
Changes in prices |
(2,390,159 | ) | 1,633,812 | 129,916 | ||||||||
Revisions in quantities |
(91,793 | ) | 59,244 | (59,591 | ) | |||||||
Changes in future development costs |
(623,607 | ) | (367,732 | ) | (399,562 | ) | ||||||
Accretion of discount |
488,737 | 239,636 | 139,582 | |||||||||
Net change in income taxes |
733,846 | (856,115 | ) | (254,114 | ) | |||||||
Purchases of reserves in place |
231,314 | 321,022 | 1,059,294 | |||||||||
Additions to proved reserves from extensions,
discoveries and improved recovery |
712,902 | 814,973 | 355,742 | |||||||||
Production |
(554,788 | ) | (425,902 | ) | (248,891 | ) | ||||||
Development costs incurred during the period |
223,158 | 143,918 | 72,144 | |||||||||
Sales of natural gas and oil |
(2,859 | ) | (769 | ) | (71,441 | ) | ||||||
Timing and other |
(108,837 | ) | 72,812 | 23,351 | ||||||||
End of period |
$ | 2,002,224 | $ | 3,384,310 | $ | 1,749,411 | ||||||
RANGE RESOURCES CORPORATION
F-36
Table of Contents
INDEX TO EXHIBITS
| Exhibit No. | Description | |
2.1
|
Agreement and Plan of Merger, dated May 10, 2006, by and among Range Resources Corporation, Range Acquisition Texas, Inc. and Stroud Energy, Inc. (incorporated by reference to Exhibit 2.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 16, 2006) | |
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 10-K (File No. 001-12209) as filed with the SEC on March 3, 2004) | |
4.1
|
Form of 7.375% Senior Subordinated Notes due 2013 (included as an exhibit to 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 (included as an exhibit to 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) | |
4.5
|
Form of 7.5% Senior Subordinated Notes due 2016 (included as an exhibit to exhibit 4.6 hereto) | |
4.6
|
Indenture dated May 23, 2006 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 May 23, 2006) | |
10.1*
|
Third Amended and Restated Credit Agreement as of October 25, 2006 among Range (as borrowers) and J.P.Morgan Chase Bank, N.A. and the institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent | |
10.2
|
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) | |
10.3
|
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) | |
10.4
|
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) | |
10.5
|
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) | |
10.6
|
Second Amendment to the Range Resources Corporation 2005 Equity-Based Compensation Plan (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 26, 2006) | |
10.7
|
Third Amendment to the Range Resources Corporation 2005 Equity-Based Compensation Plan (incorporated by reference to Exhibit 10.3 to our Form 8-K (File No. 001-12209) as filed with the SEC on May 26, 2006) | |
10.8
|
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) | |
10.9
|
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) | |
10.10
|
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) | |
10.11
|
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) | |
10.12
|
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) | |
10.13
|
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) |
Table of Contents
| Exhibit No. | Description | |
10.14
|
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) | |
10.15
|
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) | |
10.16
|
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) | |
10.17
|
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) | |
10.18
|
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) | |
10.19
|
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) | |
10.20
|
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) | |
10.21
|
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) | |
10.22
|
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) | |
10.23
|
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) | |
10.24
|
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) | |
10.25
|
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. | |
| ** | Furnished herewith. |
Exhibit 10.1
EXECUTION VERSION
THIRD AMENDED AND RESTATED CREDIT AGREEMENT
dated as of
October 25, 2006
October 25, 2006
among
RANGE RESOURCES CORPORATION,
as Borrower
as Borrower
CERTAIN SUBSIDIARIES OF BORROWER,
as Guarantors
as Guarantors
The Lenders Party Hereto
JPMORGAN CHASE BANK, N.A.,
as Administrative Agent
as Administrative Agent
J.P. MORGAN SECURITIES INC.,
as Sole Bookrunner and Lead Arranger
as Sole Bookrunner and Lead Arranger
$800,000,000 Senior Secured Revolving Credit Facility
TABLE OF CONTENTS
| Page | ||||
ARTICLE I DEFINITIONS |
1 | |||
Section 1.01. Defined Terms |
1 | |||
Section 1.02. Types of Loans and Borrowings |
24 | |||
Section 1.03. Terms Generally |
24 | |||
Section 1.04. Accounting Terms; GAAP |
24 | |||
Section 1.05. Oil and Gas Definitions |
24 | |||
Section 1.06. Time of Day |
25 | |||
ARTICLE II THE CREDITS |
25 | |||
Section 2.01. Commitments |
25 | |||
Section 2.02. Termination and Reduction of the Aggregate Commitment |
25 | |||
Section 2.03. Increases in the Aggregate Commitment |
26 | |||
Section 2.04. Loans and Borrowings |
27 | |||
Section 2.05. Requests for Borrowings |
28 | |||
Section 2.06. Reserved |
28 | |||
Section 2.07. Letters of Credit |
28 | |||
Section 2.08. Funding of Borrowings |
32 | |||
Section 2.09. Interest Elections |
33 | |||
Section 2.10. Repayment of Loans; Evidence of Debt |
34 | |||
Section 2.11. Optional Prepayment of Loans |
35 | |||
Section 2.12. Mandatory Prepayment of Loans |
35 | |||
Section 2.13. Fees |
36 | |||
Section 2.14. Interest |
37 | |||
Section 2.15. Alternate Rate of Interest |
38 | |||
Section 2.16. Increased Costs |
38 | |||
Section 2.17. Break Funding Payments |
39 | |||
Section 2.18. Taxes |
40 | |||
Section 2.19. Payments Generally; Pro Rata Treatment; Sharing of Set-offs |
41 | |||
Section 2.20. Mitigation Obligations; Replacement of Lenders |
43 | |||
ARTICLE III BORROWING BASE |
44 | |||
Section 3.01. Reserve Report; Proposed Borrowing Base |
44 | |||
Section 3.02. Scheduled Redeterminations of the Borrowing Base; Procedures and Standards |
45 | |||
Section 3.03. Special Redeterminations |
46 | |||
Section 3.04. Notice of Redetermination |
46 | |||
ARTICLE IV REPRESENTATIONS AND WARRANTIES |
46 | |||
Section 4.01. Organization; Powers |
46 | |||
Section 4.02. Authorization; Enforceability |
46 | |||
Section 4.03. Governmental Approvals; No Conflicts |
47 | |||
i
| Page | ||||
Section 4.04. Financial Condition; No Material Adverse Change |
47 | |||
Section 4.05. Properties |
47 | |||
Section 4.06. Litigation and Environmental Matters |
48 | |||
Section 4.07. Compliance with Laws and Agreements |
48 | |||
Section 4.08. Investment Company Status |
48 | |||
Section 4.09. Taxes |
48 | |||
Section 4.10. ERISA |
48 | |||
Section 4.11. Disclosure |
49 | |||
Section 4.12. Labor Matters |
49 | |||
Section 4.13. Capitalization and Credit Party Information |
49 | |||
Section 4.14. Margin Stock |
49 | |||
Section 4.15. Oil and Gas Interests |
49 | |||
Section 4.16. Insurance |
50 | |||
Section 4.17. Solvency |
50 | |||
ARTICLE V CONDITIONS |
51 | |||
Section 5.01. Effective Date |
51 | |||
Section 5.02. Each Credit Event |
52 | |||
ARTICLE VI AFFIRMATIVE COVENANTS |
53 | |||
Section 6.01. Financial Statements; Other Information |
53 | |||
Section 6.02. Notices of Material Events |
55 | |||
Section 6.03. Existence; Conduct of Business |
56 | |||
Section 6.04. Payment of Obligations |
56 | |||
Section 6.05. Maintenance of Properties; Insurance |
56 | |||
Section 6.06. Books and Records; Inspection Rights |
56 | |||
Section 6.07. Compliance with Laws |
57 | |||
Section 6.08. Use of Proceeds and Letters of Credit |
57 | |||
Section 6.09. Mortgages |
57 | |||
Section 6.10. Title Data |
57 | |||
Section 6.11. Swap Agreements |
57 | |||
Section 6.12. Operation of Oil and Gas Interests |
58 | |||
Section 6.13. Restricted Subsidiaries |
58 | |||
Section 6.14. Pledged Equity Interests |
59 | |||
ARTICLE VII NEGATIVE COVENANTS |
59 | |||
Section 7.01. Indebtedness |
59 | |||
Section 7.02. Liens |
60 | |||
Section 7.03. Fundamental Changes |
61 | |||
Section 7.04. Investments, Loans, Advances, Guarantees and Acquisitions |
62 | |||
Section 7.05. Swap Agreements |
63 | |||
Section 7.06. Restricted Payments |
63 | |||
Section 7.07. Transactions with Affiliates |
64 | |||
Section 7.08. Restrictive Agreements |
64 | |||
Section 7.09. Disqualified Stock |
64 | |||
ii
| Page | ||||
Section 7.10. Amendments to Organizational Documents |
64 | |||
Section 7.11. Financial Covenants |
65 | |||
Section 7.12. Sale and Leaseback Transactions and other Liabilities |
65 | |||
Section 7.13. Modifications of Senior Subordinated Notes |
65 | |||
ARTICLE VIII GUARANTEE OF OBLIGATIONS |
66 | |||
Section 8.01. Guarantee of Payment |
66 | |||
Section 8.02. Guarantee Absolute |
66 | |||
Section 8.03. Guarantee Irrevocable |
66 | |||
Section 8.04. Reinstatement |
67 | |||
Section 8.05. Subrogation |
67 | |||
Section 8.06. Subordination |
67 | |||
Section 8.07. Payments Generally |
67 | |||
Section 8.08. Setoff |
68 | |||
Section 8.09. Formalities |
68 | |||
Section 8.10. Limitations on Guarantee |
68 | |||
ARTICLE IX EVENTS OF DEFAULT |
69 | |||
ARTICLE X THE ADMINISTRATIVE AGENT |
71 | |||
ARTICLE XI MISCELLANEOUS |
73 | |||
Section 11.01. Notices |
73 | |||
Section 11.02. Waivers; Amendments |
74 | |||
Section 11.03. Expenses; Indemnity; Damage Waiver |
75 | |||
Section 11.04. Successors and Assigns |
76 | |||
Section 11.05. Survival |
79 | |||
Section 11.06. Counterparts; Integration; Effectiveness |
80 | |||
Section 11.07. Severability |
80 | |||
Section 11.08. Right of Setoff |
80 | |||
Section 11.09. GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS |
80 | |||
Section 11.10. WAIVER OF JURY TRIAL |
81 | |||
Section 11.11. Headings |
81 | |||
Section 11.12. Confidentiality |
82 | |||
Section 11.13. Interest Rate Limitation |
82 | |||
Section 11.14. USA PATRIOT Act |
82 | |||
Section 11.15. Original Credit Agreement |
83 | |||
Section 11.16. Reaffirmation and Grant of Security Interest |
83 | |||
Section 11.17. Reallocation of Aggregate Commitment |
83 | |||
SCHEDULES:
Schedule 2.01
|
— | Applicable Percentages and Initial Commitments | ||
Schedule 4.06
|
— | Disclosed Matters | ||
Schedule 4.13
|
— | Capitalization and Credit Party Information |
iii
Schedule 7.01
|
— | Existing Indebtedness | ||
Schedule 7.02
|
— | Existing Liens | ||
Schedule 7.04
|
— | Existing Investments | ||
Schedule 7.07
|
— | Transactions with Affiliates | ||
Schedule 7.08
|
— | Existing Restrictions |
EXHIBITS:
Exhibit A
|
— | Form of Assignment and Assumption | ||
Exhibit B
|
— | Form of Opinion of Borrower’s Counsel | ||
Exhibit C
|
— | Form of Counterpart Agreement | ||
Exhibit D
|
— | Form of Revolving Note |
ii
THIRD AMENDED AND RESTATED CREDIT AGREEMENT dated as of October 25, 2006, among RANGE RESOURCES
CORPORATION, as Borrower, CERTAIN SUBSIDIARIES OF BORROWER, as Guarantors, the LENDERS party
hereto, and JPMORGAN CHASE BANK, N.A., as Administrative Agent.
The parties hereto agree as follows:
Article I
Definitions
Section 1.01. Defined Terms. As used in this Agreement, the following terms have the
meanings specified below:
“ABR”, when used in reference to any Loan or Borrowing, refers to whether such
Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by
reference to the Alternate Base Rate.
“Acquisition” means, the acquisition by the Borrower or any Restricted
Subsidiary, whether by purchase, merger (and, in the case of a merger with any such Person,
with such Person being the surviving corporation) or otherwise, of all or substantially all
of the Equity Interest of, or the business, property or fixed assets of or business line or
unit or a division of, any other Person primarily engaged in the business of producing oil
or natural gas or the acquisition by the Borrower or any Restricted Subsidiary of property
or assets consisting of Oil and Gas Interests.
“Adjusted LIBO Rate” means, with respect to any Eurodollar Borrowing for any
Interest Period, an interest rate per annum (rounded upwards, if necessary, to the next 1/16
of 1%) equal to (a) the LIBO Rate for such Interest Period multiplied by (b) the Statutory
Reserve Rate.
“Administrative Agent” means JPMorgan Chase Bank, in its capacity as
contractual representative of the Lenders hereunder pursuant to Article X and not in its
individual capacity as a Lender, and any successor agent appointed pursuant to Article X.
“Administrative Questionnaire” means an Administrative Questionnaire in a form
supplied by the Administrative Agent.
“Advance Payment Contract” means any contract whereby any Credit Party either
(a) receives or becomes entitled to receive (either directly or indirectly) any payment (an
“Advance Payment”) to be applied toward payment of the purchase price of
Hydrocarbons produced or to be produced from Oil and Gas Interests owned by any Credit Party
and which Advance Payment is, or is to be, paid in advance of actual delivery of such
production to or for the account of the purchaser regardless of such production including
any volumetric production payments, or (b) grants an option or right of refusal to the
purchaser to take delivery of such production in lieu of payment, and, in
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 1
either of the
foregoing instances, the Advance Payment is, or is to be, applied as payment
in full for such production when sold and delivered or is, or is to be, applied as
payment for a portion only of the purchase price thereof or of a percentage or share of such
production; provided that inclusion of the standard “take or pay” provision in any
gas sales or purchase contract or any other similar contract shall not, in and of itself,
constitute such contract as an Advance Payment Contract for the purposes hereof.
“Affiliate” means, with respect to a specified Person, another Person that
directly, or indirectly through one or more intermediaries, Controls or is Controlled by or
is under common Control with the Person specified.
“Aggregate Commitment” means the amount equal to the lesser of (i) the Maximum
Facility Amount and (ii) the Borrowing Base; provided that the initial Aggregate
Commitment is $800,000,000. The Aggregate Commitment may be reduced or increased pursuant
to Section 2.02 and Section 2.03; provided that in no event shall the Aggregate
Commitment exceed the Borrowing Base. If at any time the Borrowing Base is reduced below
the Aggregate Commitment in effect prior to such reduction, the Aggregate Commitment shall
be reduced automatically to the amount of the Borrowing Base in effect at such time.
“Aggregate Credit Exposure” means, as of any date of determination, the
aggregate amount of the Credit Exposure of all of the Lenders as of such date.
“Agreement” means this Third Amended and Restated Credit Agreement, dated as of
October 25, 2006 as it may be amended, supplemented or otherwise modified from time to time.
“Alternate Base Rate” means, for any day, a rate per annum equal to the
greatest of (a) the Prime Rate in effect on such day and (b) the Federal Funds Effective
Rate in effect on such day plus 1/2 of 1%. Any change in the Alternate Base Rate due to a
change in the Prime Rate or the Federal Funds Effective Rate shall be effective from and
including the effective date of such change in the Prime Rate or the Federal Funds Effective
Rate, respectively.
“Appalachia Properties” means, at any time, the Mortgaged Properties owned by
Borrower or any of its Subsidiaries and located in Ohio, Pennsylvania, West Virginia, New
York, Virginia or any other state specified by the Borrower and acceptable to the
Administrative Agent.
“Applicable Percentage” means, with respect to any Lender at any time, the
percentage of the Aggregate Commitment represented by such Lender’s Commitment at such time.
The initial amount of each Lender’s Applicable Percentage is as set forth on Schedule 2.01.
If the Aggregate Commitment has terminated or expired, the Applicable Percentages shall be
determined based upon the Aggregate Commitment most recently in effect, giving effect to any
subsequent assignments.
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 2
“Applicable Rate” means, for any day, with respect to any ABR Loan or
Eurodollar Loan, or with respect to the Unused Commitment Fees payable hereunder, as
the case may be, the applicable rate per annum set forth below under the caption “ABR
Spread”, “Eurodollar Spread” or “Unused Commitment Fee Rate”, as the case may be, based upon
the Borrowing Base Usage applicable on such date:
| Unused | ||||||||||||
| Borrowing | Eurodollar | Commitment | ||||||||||
| Base Usage | Spread | ABR Spread | Fee Rate | |||||||||
³ 90% |
175 b.p. | 50 b.p. | 37.5 b.p. | |||||||||
³ 75% and < 90% |
150 b.p. | 25 b.p. | 35 b.p. | |||||||||
³ 50% and < 75% |
125 b.p. | 0 b.p. | 30 b.p. | |||||||||
< 50% |
100 b.p. | 0 b.p. | 25 b.p. | |||||||||
Each change in the Applicable Rate shall apply during the period commencing on the
effective date of such change and ending on the date immediately preceding the effective
date of the next change.
“Approved Counterparty” means, at any time and from time to time, (i) any
Person engaged in the business of writing Swap Agreements for commodity, interest rate or
currency risk that is acceptable to the Administrative Agent and has (or the credit support
provider of such Person has), at the time Borrower or any Restricted Subsidiary enters into
a Swap Agreement with such Person, a long term senior unsecured debt credit rating of BBB+
or better from S&P or Baa1 or better from Moody’s and (ii) any Lender Counterparty.
“Approved Fund” has the meaning assigned to such term in Section 11.04.
“Approved Petroleum Engineer” means DeGolyer and MacNaughton, H.J. Gruy and
Associates, Inc., Wright and Company, Inc., or one or more other reputable firms of
independent petroleum engineers selected by the Borrower and approved by the Administrative
Agent, which approval shall not be unreasonably withheld or delayed.
“Arranger” means J.P. Morgan Securities Inc. in its capacity as sole bookrunner
and lead arranger.
“Assignment and Assumption” means an assignment and assumption entered into by
a Lender and an Eligible Assignee, and accepted by the Administrative Agent, in the form of
Exhibit A or any other form approved by the Administrative Agent.
“Availability Period” means the period from and including the Effective Date to
but excluding the earlier of the Maturity Date and the date of termination of the Aggregate
Commitment.
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 3
“Board” means the Board of Governors of the Federal Reserve System of the
United States of America.
“Borrower” means Range Resources Corporation, a Delaware corporation, and its
successors and permitted assigns.
“Borrower Materials” has the meaning assigned to such term in Section 6.01.
“Borrowing” means Loans of the same Type, made, converted or continued on the
same date and, in the case of Eurodollar Loans, as to which a single Interest Period is in
effect.
“Borrowing Base” means, at any time an amount equal to the amount determined in
accordance with Section 3.01, as the same may be redetermined, adjusted or reduced from time
to time pursuant to Section 3.02 and Section 3.03.
“Borrowing Base Deficiency” means, as of any date, the amount, if any, by which
the Aggregate Credit Exposure on such date exceeds the Borrowing Base in effect on such
date; provided, that, for purposes of determining the existence and amount of any
Borrowing Base Deficiency, obligations under any Letter of Credit will not be deemed to be
outstanding to the extent such obligations are secured by cash in the manner contemplated by
Section 2.07(j).
“Borrowing Base Properties” means all Oil and Gas Interests included in the
Reserve Report of the Borrower and the Restricted Subsidiaries and evaluated by the Lenders
for purposes of establishing the Borrowing Base.
“Borrowing Base Usage” means, as of any date and for all purposes, the
quotient, expressed as a percentage, of (a) the Aggregate Credit Exposure as of such date,
divided by (b) the Borrowing Base as of such date.
“Borrowing Request” means a request by the Borrower for a Borrowing in
accordance with Section 2.05.
“Business Day” means any day that is not a Saturday, Sunday or other day on
which commercial banks in Chicago, Illinois or Dallas, Texas are authorized or required by
law to remain closed; provided that, when used in connection with a Eurodollar Loan,
the term “Business Day” shall also exclude any day on which banks are not open for
dealings in dollar deposits in the London interbank market.
“Capital Lease Obligations” of any Person means the obligations of such Person
to pay rent or other amounts under any lease of (or other arrangement conveying the right to
use) real or personal property, or a combination thereof, which obligations are required to
be classified and accounted for as capital leases on a balance sheet of such Person under
GAAP, and the amount of such obligations shall be the capitalized amount thereof determined
in accordance with GAAP; provided that obligations with respect to usual and
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 4
customary oil,
gas and mineral leases shall not be included as Capitalized Lease Obligations.
“Cash Management Obligations” means, with respect to any Credit Party, any
obligations of such Credit Party owed to any Lender (or any Affiliate of any Lender) in
respect of treasury management arrangements, depositary or other cash management services.
“Change in Law” means (a) the adoption of any law, rule or regulation after the
date of this Agreement, (b) any change in any law, rule or regulation or in the
interpretation or application thereof by any Governmental Authority after the date of this
Agreement or (c) compliance by any Lender or the Issuing Bank (or, for purposes of Section
2.16(b), by any lending office of such Lender or by such Lender’s or the Issuing Bank’s
holding company, if any) with any request, guideline or directive (whether or not having the
force of law) of any Governmental Authority made or issued after the date of this Agreement.
“Change of Control” means (a) the acquisition of ownership, directly or
indirectly, beneficially or of record, by any Person or group (within the meaning of the
Securities Exchange Act of 1934 and the rules of the Securities and Exchange Commission
thereunder as in effect on the Effective Date) of Equity Interests representing more than
40% of the aggregate ordinary voting power represented by the issued and outstanding Equity
Interests of Borrower; or (b) occupation of a majority of the seats (other than vacant
seats) on the board of directors of Borrower by Persons who were neither (i) nominated by
the board of directors of Borrower nor (ii) appointed by directors so nominated.
“Charges” has the meaning assigned to such term in Section 11.13.
“Code” means the Internal Revenue Code of 1986, as amended from time to time.
“Collateral” means all assets, whether now owned or hereafter acquired by any
Borrower or any other Credit Party, in which a Lien is granted or purported to be granted to
any Secured Party as security for any Obligation including any Borrowing Base Properties
located in Virginia and deemed subject to a Mortgage pursuant to the terms of this
Agreement.
“Commitment” means, with respect to each Lender, the commitment of such Lender
to make Loans and to acquire participations in Letters of Credit hereunder, expressed as an
amount representing the maximum aggregate amount of such Lender’s Credit Exposure hereunder,
as such commitment may be (a) reduced or increased from time to time pursuant to Section
2.02 and Section 2.03, (b) reduced or increased from time to time as a result of changes in
the Borrowing Base pursuant to Article III and (c) reduced or increased from time to time
pursuant to assignments by or to such Lender pursuant to Section 11.04. The initial amount
of each Lender’s Commitment (which amount is such Lender’s Applicable Percentage of the
initial Aggregate Commitment) is
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set forth in Schedule 2.01, or in the Assignment and
Assumption pursuant to which such Lender shall have assumed its Commitment, as applicable.
“Consolidated Current Assets” means, as of any date of determination, the total
of (a) the consolidated current assets of the Borrower and the Consolidated Subsidiaries
determined in accordance with GAAP as of such date, plus, all Unused Commitments as
of such date, (b) less any non-cash assets required to be included in consolidated
current assets of the Borrower and the Consolidated Subsidiaries as a result of the
application of FASB Statement 133 as of such date.
“Consolidated Current Liabilities” means, as of any date of determination, the
total of (a) consolidated current liabilities of the Borrower and the Consolidated
Subsidiaries, as determined in accordance with GAAP as of such date, (b) less
current maturities of the Loans and the Senior Subordinated Notes, (c) less any
non-cash obligations required to be included in consolidated current liabilities of the
Borrower and the Consolidated Subsidiaries as a result of the application of FASB Statement
133 as of such date.
“Consolidated Current Ratio” means, as of any date of determination, the ratio
of Consolidated Current Assets to Consolidated Current Liabilities as of such date.
“Consolidated EBITDAX” means, with respect to the Borrower and its Consolidated
Subsidiaries for any period, Consolidated Net Income for such period; plus, without
duplication and to the extent deducted in the calculation of Consolidated Net Income for
such period, the sum of (a) income or franchise Taxes paid or accrued; (b) Consolidated
Interest Expense; (c) amortization, depletion and depreciation expense; (d) any non-cash
losses or charges resulting from the application of FASB Statements 121, 133 or 143 for that
period; (e) oil and gas exploration expenses (including all drilling, completion, geological
and geophysical costs) for such period; (f) losses from sales or other dispositions of
assets (other than Hydrocarbons produced in the ordinary course of business) and other
extraordinary or non-recurring losses; (g) cash payments made during such period as a result
of the early termination of any Swap Agreement (giving effect to any netting agreements);
and (h) other non-cash charges (excluding accruals for cash expenses made in the ordinary
course of business); minus, to the extent included in the calculation of Consolidated Net
Income for such period; (j) the sum of (i) any non-cash gains resulting from the application
of FASB Statements 121, 133 or 143 for that period; (ii) extraordinary or non-recurring
gains; and (iii) gains from sales or other dispositions of assets (other than Hydrocarbons
produced in the ordinary course of business); provided that, with respect to the
determination of Borrower’s compliance with the leverage ratio set forth in Section 7.11(b)
for any period, Consolidated EBITDAX shall be adjusted to give effect, on a pro forma basis,
to any Acquisitions made during such period as if such Acquisitions were made at the
beginning of such period.
“Consolidated Funded Indebtedness” means, as of any date and without
duplication, Indebtedness of the Borrower and the Restricted Subsidiaries of the type
described in clauses (a, excluding Indebtedness consisting of deposits and advances), (b),
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(c), (e), (g, to the extent any such Guarantees are Guarantees of Indebtedness that is
otherwise Consolidated Funded Indebtedness) or (h) of the definition of Indebtedness.
“Consolidated Interest Expense” means for any period, without duplication, the
aggregate of all interest paid or accrued by the Borrower and its Consolidated Subsidiaries,
on a consolidated basis, in respect of Indebtedness of any such Person, on a consolidated
basis, including all interest, fees and costs payable with respect to the obligations
related to such Indebtedness (other than fees and costs which may be capitalized as
transaction costs in accordance with GAAP) and the interest component of Capitalized Lease
Obligations, all as determined in accordance with GAAP.
“Consolidated Net Income” means for any period, the consolidated net income (or
loss) of the Borrower and its Consolidated Subsidiaries, as applicable, determined on a
consolidated basis in accordance with GAAP; provided that there shall be excluded
(a) the income (or deficit) of any Person accrued prior to the date it becomes a
Consolidated Subsidiary of the Borrower, or is merged into or consolidated with the Borrower
or any of its Consolidated Subsidiaries, as applicable, (b) the income (or deficit) any
Person in which any other Person (other than the Borrower or any of its Restricted
Subsidiaries) has an Equity Interest, except to the extent of the amount of dividends and
other distributions actually paid to the Borrower or any of its Restricted Subsidiaries
during such period and and (c) the undistributed earnings of any Consolidated Subsidiary of
the Borrower, to the extent that the declaration or payment of dividends or similar
distributions by such Consolidated Subsidiary is not at the time permitted by the terms of
any contractual obligation (other than under any Loan Document or the Indenture) or by any
law applicable to such Consolidated Subsidiary.
“Consolidated Subsidiaries” means, for any Person, any Subsidiary or other
entity the accounts of which would be consolidated with those of such Person in its
consolidated financial statements in accordance with GAAP.
“Control” means the possession, directly or indirectly, of the power to direct
or cause the direction of the management or policies of a Person, whether through the
ability to exercise voting power, by contract or otherwise. “Controlling” and
“Controlled” have meanings correlative thereto.
“Counterpart Agreement” means a Counterpart Agreement substantially in the form
of Exhibit C delivered by a Guarantor pursuant to Section 6.13.
“Credit Exposure” means, with respect to any Lender at any time, the sum of the
outstanding principal amount of such Lender’s Loans and its LC Exposure at such time.
“Credit Parties” means collectively, Borrower, and each Guarantor and each
individually, a “Credit Party”.
“Crude Oil” means all crude oil and condensate.
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“Deep Participation Rights” means the right of Marbel to participate in the
drilling or deepening of certain wells located in a specified area of Ohio pursuant to
Section 6.09 of that certain Purchase and Sale Agreement dated June 1, 2004, providing for
the acquisition by the Borrower of all of the outstanding membership interests of
GLEP not already indirectly owned by the Borrower as in effect on the Original
Effective Date.
“Default” means any event or condition which constitutes an Event of Default or
which upon notice, lapse of time or both would, unless cured or waived, become an Event of
Default.
“Defaulting Lender” means any Lender that (a) has failed to fund any portion of
the Loans or participations in LC Disbursements required to be funded by it hereunder within
one Business Day of the date required to be funded by it hereunder, (b) has otherwise failed
to pay over to the Administrative Agent or any other Lender any other amount required to be
paid by it hereunder within one Business Day of the date when due, unless the subject of a
good faith dispute, or (c) has been deemed insolvent or become the subject of a bankruptcy
or insolvency proceeding.
“Disclosed Matters” means the actions, suits and proceedings and the
environmental matters disclosed in Schedule 4.06.
“Disqualified Stock” means any Equity Interest, which, by its terms (or by the
terms of any security into which it is convertible or for which it is exchangeable), or upon
the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund
obligation or otherwise, or is redeemable at the sole option of the holder thereof, in whole
or in part, on or prior to the Maturity Date.
“Dollars” or “$” refers to lawful money of the United States of
America.
“Domestic Subsidiary” means, with respect to any Person, a subsidiary of such
Person that is incorporated or formed under the laws of the United States of America, any
state thereof or the District of Columbia.
“Effective Date” means the date on which the conditions specified in Section
5.01 are satisfied (or waived in accordance with Section 11.02).
“Eligible Assignee” means any Person that qualifies as an assignee pursuant to
Section 11.04(b)(i); provided that notwithstanding the foregoing, “Eligible
Assignee” shall not include the Borrower or any of the Borrower’s Affiliates or
Subsidiaries.
“Engineered Value” means, the value attributed to the Borrowing Base Properties
for purposes of the most recent Redetermination of the Borrowing Base pursuant to Article
III (or for purposes of determining the Initial Borrowing Base in the event no such
Redetermination has occurred), based upon the discounted present value of the estimated
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net
cash flow to be realized from the production of Hydrocarbons from the Borrowing Base
Properties as set forth in the Reserve Report.
“Environmental Laws” means all laws, rules, regulations, codes, ordinances,
orders, decrees, judgments, injunctions, notices or binding agreements issued, promulgated
or entered into by any Governmental Authority, relating in any way to the
environment, preservation or reclamation of natural resources, the management, release
or threatened release of any Hazardous Material or to health and safety matters.
“Environmental Liability” means any liability, contingent or otherwise
(including any liability for damages, costs of environmental remediation, fines, penalties
or indemnities), of any Credit Party directly or indirectly resulting from or based upon (a)
violation of any Environmental Law, (b) the generation, use, handling, transportation,
storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous
Materials, (d) the release or threatened release of any Hazardous Materials into the
environment or (e) any contract, agreement or other consensual arrangement pursuant to which
liability is assumed or imposed with respect to any of the foregoing.
“Equity Interests” means shares of capital stock, partnership interests,
membership interests in a limited liability company, beneficial interests in a trust or
other equity ownership interests in a Person, and any warrants, options or other rights
entitling the holder thereof to purchase or acquire any such equity interest.
“ERISA” means the Employee Retirement Income Security Act of 1974, as amended
from time to time.
“ERISA Affiliate” means any trade or business (whether or not incorporated)
that, together with any Credit Party, is treated as a single employer under Section 414(b)
or (c) of the Code or, solely for purposes of Section 302 of ERISA and Section 412 of the
Code, is treated as a single employer under Section 414 of the Code.
“ERISA Event” means (a) any “reportable event”, as defined in Section 4043 of
ERISA or the regulations issued thereunder with respect to a Plan (other than an event for
which the 30-day notice period is waived); (b) the existence with respect to any Plan of an
“accumulated funding deficiency” (as defined in Section 412 of the Code or Section 302 of
ERISA), whether or not waived; (c) the filing pursuant to Section 412(d) of the Code or
Section 303(d) of ERISA of an application for a waiver of the minimum funding standard with
respect to any Plan; (d) the incurrence by any Credit Party or any of its ERISA Affiliates
of any liability under Title IV of ERISA with respect to the termination of any Plan; (e)
the receipt by any Credit Party or any ERISA Affiliate from the PBGC or a plan administrator
of any notice relating to an intention to terminate any Plan or Plans or to appoint a
trustee to administer any Plan; (f) the incurrence by any Credit Party or any of its ERISA
Affiliates of any liability with respect to the withdrawal or partial withdrawal from any
Plan or Multiemployer Plan; or (g) the receipt by any Credit Party or any ERISA Affiliate of
any notice, or the receipt by any Multiemployer Plan from any Credit Party or any ERISA
Affiliate of any notice, concerning the
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imposition of Withdrawal Liability or a
determination that a Multiemployer Plan is, or is expected to be, insolvent or in
reorganization, within the meaning of Title IV of ERISA.
“Eurodollar”, when used in reference to any Loan or Borrowing, refers to
whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate
determined by reference to the Adjusted LIBO Rate.
“Event of Default” has the meaning assigned to such term in Article IX.
“Excluded Taxes” means, with respect to the Administrative Agent, any Lender,
the Issuing Bank or any other recipient of any payment to be made by or on account of any
obligation of the Borrower hereunder, (a) income or franchise taxes imposed on (or measured
by) its net income by the United States of America, or by the jurisdiction under the laws
of which such recipient is organized or in which its principal office is located or, in the
case of any Lender, in which its applicable lending office is located, (b) any branch
profits taxes imposed by the United States of America or any similar tax imposed by any
other jurisdiction in which the Borrower is located and (c) in the case of a Foreign Lender
(other than an assignee pursuant to a request by the Borrower under Section 2.20(b)), any
withholding tax that is imposed on amounts payable to such Foreign Lender at the time such
Foreign Lender becomes a party to this Agreement (or designates a new lending office) or is
attributable to such Foreign Lender’s failure to comply with Section 2.18(e), except to the
extent that such Foreign Lender (or its assignor, if any) was entitled, at the time of
designation of a new lending office (or assignment), to receive additional amounts from the
Borrower with respect to such withholding tax pursuant to Section 2.18(a).
“Existing Swap Agreements” means any Swap Agreements entered into between the
Borrower or any Guarantor and any Lender Counterparty prior to the Effective Date and in
effect on the Effective Date.
“FASB” means Financial Accounting Standards Board.
“Federal Funds Effective Rate” means, for any day, the weighted average
(rounded upwards, if necessary, to the next 1/100 of 1%) of the rates on overnight Federal
funds transactions with members of the Federal Reserve System arranged by Federal funds
brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New
York, or, if such rate is not so published for any day that is a Business Day, the average
(rounded upwards, if necessary, to the next 1/100 of 1%) of the quotations for such day for
such transactions received by the Administrative Agent from three Federal funds brokers of
recognized standing selected by it.
“Foreign Lender” means any Lender that is organized under the laws of a
jurisdiction other than that in which any Credit Party is located. For purposes of this
definition, the United States of America, each State thereof and the District of Columbia
shall be deemed to constitute a single jurisdiction.
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“GAAP” means generally accepted accounting principles in the United States of
America.
“Gas Balancing Agreement” means any agreement or arrangement whereby the
Borrower or any Restricted Subsidiary, or any other party having an interest in any
Hydrocarbons to be produced from Oil and Gas Interests in which the Borrower or any
Restricted Subsidiary owns an interest, has a right to take more than its proportionate
share of production therefrom.
“GLEP” means Great Lakes Energy Partners, L.L.C., a Delaware limited liability
company and its successors and permitted assigns.
“Governmental Authority” means the government of the United States of America,
any other nation or any political subdivision thereof, whether state or local, and any
agency, authority, instrumentality, regulatory body, court, central bank or other entity
properly exercising executive, legislative, judicial, taxing, regulatory or administrative
powers or functions of or pertaining to government.
“Guarantee” of or by any Person (in this definition, the “guarantor”)
means any obligation, contingent or otherwise, of the guarantor guaranteeing or having the
economic effect of guaranteeing any Indebtedness or other obligation of any other Person
(the “primary obligor”) in any manner, whether directly or indirectly, and including
any obligation of the guarantor, direct or indirect, (a) to purchase or pay (or advance or
supply funds for the purchase or payment of) such Indebtedness or other obligation or to
purchase (or to advance or supply funds for the purchase of) any security for the payment
thereof, (b) to purchase or lease property, securities or services for the purpose of
assuring the owner of such Indebtedness or other obligation of the payment thereof, (c) to
maintain working capital, equity capital or any other financial statement condition or
liquidity of the primary obligor so as to enable the primary obligor to pay such
Indebtedness or other obligation or (d) as an account party in respect of any letter of
credit or letter of guaranty issued to support such Indebtedness or obligation;
provided, that the term Guarantee shall not include endorsements for collection or
deposit in the ordinary course of business.
“Guaranteed Liabilities” has the meaning assigned to such term in Section 8.01.
“Guarantor” means each Restricted Subsidiary that is a party hereto or
hereafter executes and delivers to the Administrative Agent and the Lenders, a Counterpart
Agreement pursuant to Section 6.13 or otherwise.
“Hazardous Materials” means all explosive or radioactive substances or wastes
and all hazardous or toxic substances, wastes or other pollutants, including petroleum or
petroleum distillates, asbestos or asbestos containing materials, polychlorinated biphenyls,
radon gas, infectious or medical wastes and all other substances or wastes of any nature
regulated pursuant to any Environmental Law.
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“Hydrocarbons” means all Crude Oil and Natural Gas produced from or
attributable to the Oil and Gas Interests of the Credit Parties.
“Increased Commitment Date” has the meaning assigned to such term in Section
2.03.
“Indebtedness” of any Person means, without duplication, (a) all obligations of
such Person for borrowed money or with respect to deposits or advances of any kind, (b) all
obligations of such Person evidenced by bonds, debentures, notes or similar instruments, (c)
all obligations of such Person upon which interest charges are paid
(excluding accounts payable incurred in the ordinary course of business, contingent
obligations as a non-operator under oil and gas operating agreements and contingent
obligations under standard and customary provisions of gas sale contracts for make-up
volumes on sales of natural gas), (d) all obligations of such Person under conditional sale
or other title retention agreements relating to property acquired by such Person, (e) all
obligations of such Person in respect of the deferred purchase price of property or services
(excluding current accounts payable incurred in the ordinary course of business), (f) all
Indebtedness of others secured by (or for which the holder of such Indebtedness has an
existing right, contingent or otherwise, to be secured by) any Lien on property owned or
acquired by such Person, whether or not the Indebtedness secured thereby has been assumed,
(g) all Guarantees by such Person of Indebtedness of others, (h) all Capital Lease
Obligations of such Person, (i) all obligations, contingent or otherwise, of such Person as
an account party in respect of letters of credit and letters of guaranty and (j) all
obligations, contingent or otherwise, of such Person in respect of bankers’ acceptances.
The Indebtedness of any Person shall include the Indebtedness of any other entity (including
any partnership in which such Person is a general partner) to the extent such Person is
liable therefor as a result of such Person’s ownership interest in or other relationship
with such entity, except to the extent the terms of such Indebtedness provide that such
Person is not liable therefor.
“Indemnified Taxes” means Taxes other than Excluded Taxes.
“Indemnitee” has the meaning assigned to such term in Section 11.03.
“Indenture” means, collectively, (i) that certain Indenture dated as of July
21, 2003, by and between the Borrower, as issuer, certain of its Subsidiaries, as
guarantors, and JPMorgan Chase Bank, N.A. (successor to Bank One, N.A.), as trustee,
pursuant to which the Borrower issued the Senior Subordinated Notes, as amended and
supplemented by that certain Supplemental Indenture dated as of June 22, 2004 and as further
amended and supplemented from time to time as permitted under the terms thereof, (ii) that
certain Indenture dated March 9, 2005, among the Borrower, as issuer, certain of its
Subsidiaries, as guarantors, and J.P. Morgan Trust Company, National Association, as amended
or supplemented from time to time as permitted under the terms hereof, and (iii) that
certain Indenture dated May 23, 2006, among the Borrower, as issuer, certain of its
Subsidiaries, as guarantors, and J. P. Morgan Trust Company, National Association, as
amended or supplemented from time to time as permitted under the terms hereof.
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“Information” has the meaning assigned to such term in Section 11.12.
“Initial Borrowing Base” has the meaning assigned to such term in Section 3.01.
“Interest Election Request” means a request by the Borrower to convert or
continue a Borrowing in accordance with Section 2.09.
“Interest Payment Date” means (a) with respect to any ABR Loan, the last day of
each calendar month and (b) with respect to any Eurodollar Loan, the last day of the
Interest Period applicable to the Borrowing of which such Loan is a part and, in the case
of a Eurodollar Borrowing with an Interest Period of more than three months’ duration,
each day prior to the last day of such Interest Period that occurs at intervals of three
months’ duration after the first day of such Interest Period.
“Interest Period” means with respect to any Eurodollar Borrowing, the period
commencing on the date of such Borrowing and ending on the numerically corresponding day in
the calendar month that is one, two, three, six or, if at the date of such election a twelve
month placement is available, twelve months thereafter, as the Borrower may elect;
provided, that (a) if any Interest Period would end on a day other than a Business
Day, such Interest Period shall be extended to the next succeeding Business Day unless such
next succeeding Business Day would fall in the next calendar month, in which case such
Interest Period shall end on the next preceding Business Day and (b) any Interest Period
pertaining to a Eurodollar Borrowing that commences on the last Business Day of a calendar
month (or on a day for which there is no numerically corresponding day in the last calendar
month of such Interest Period) shall end on the last Business Day of the last calendar month
of such Interest Period. For purposes hereof, the date of a Borrowing initially shall be
the date on which such Borrowing is made and thereafter shall be the effective date of the
most recent conversion or continuation of such Borrowing.
“Issuing Bank” means JPMorgan Chase Bank, in its capacity as the issuer of
Letters of Credit hereunder, and its successors in such capacity as provided in Section
2.07(i). The Issuing Bank may, in its discretion, arrange for one or more Letters of Credit
to be issued by Affiliates of the Issuing Bank, in which case the term “Issuing Bank” shall
include any such Affiliate with respect to Letters of Credit issued by such Affiliate.
“JPMorgan Chase Bank” and “JPMorgan Chase Bank, N.A.” means JPMorgan
Chase Bank, N.A. and its successors.
“LC Disbursement” means a payment made by the Issuing Bank pursuant to a Letter
of Credit.
“LC Exposure” means, at any time, the sum of (a) the aggregate undrawn amount
of all outstanding Letters of Credit at such time plus (b) the aggregate amount of all LC
Disbursements that have not yet been reimbursed by or on behalf of the Borrower at such
time. The LC Exposure of any Lender at any time shall be its Applicable Percentage of the
total LC Exposure at such time.
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“Lender Counterparty” means any Lender or any Affiliate of a Lender
counterparty to a Swap Agreement with any Credit Party.
“Lenders” means the Persons listed on Schedule 2.01 and any other Person that
shall have become a party hereto pursuant to an Assignment and Assumption, other than any
such Person that ceases to be a party hereto pursuant to an Assignment and Assumption.
“Letter of Credit” means any letter of credit issued pursuant to this Agreement
and, to the extent outstanding on the Effective Date, any letter of credit issued under the
Original Credit Agreement and any renewals thereof.
“LIBO Rate” means, with respect to any Eurodollar Borrowing for any Interest
Period, the rate appearing on Page 3750 of the Moneyline Telerate Service (or on any
successor or substitute page of such Service, or any successor to or substitute for such
Service, providing rate quotations comparable to those currently provided on such page of
such Service, as determined by the Administrative Agent from time to time for purposes of
providing quotations of interest rates applicable to dollar deposits in the London interbank
market) at approximately 11:00 a.m., London time, two Business Days prior to the
commencement of such Interest Period, as the rate for dollar deposits with a maturity
comparable to such Interest Period. In the event that such rate is not available at such
time for any reason, then the “LIBO Rate” with respect to such Eurodollar Borrowing
for such Interest Period shall be the rate at which dollar deposits of $5,000,000 and for a
maturity comparable to such Interest Period are offered by the principal London office of
the Administrative Agent in immediately available funds in the London interbank market at
approximately 11:00 a.m., London time, two Business Days prior to the commencement of such
Interest Period.
“Lien” means, with respect to any asset, (a) any mortgage, deed of trust, lien,
pledge, hypothecation, encumbrance, charge or security interest in, on or of such asset, (b)
the interest of a vendor or a lessor under any conditional sale agreement, capital lease or
title retention agreement (or any financing lease having substantially the same economic
effect as any of the foregoing) relating to such asset and (c) in the case of securities,
any purchase option, call or similar right of a third party with respect to such securities.
“Loan Documents” means this Agreement, any promissory notes executed in
connection herewith, the Security Instruments, the Letters of Credit (and any applications
therefor and reimbursement agreements related thereto), the Fee Letter and any other
agreements executed in connection with this Agreement.
“Loans” means the loans made by the Lenders to the Borrower pursuant to this
Agreement.
“Marbel” means Marbel Holdco, Inc., an Ohio corporation and its successors and
permitted assigns.
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“Material Adverse Effect” means a material adverse effect on (a) the assets or
properties, financial condition, businesses or operations of the Borrower and its
Subsidiaries taken as a whole (it being understood that changes in commodity prices for
Hydrocarbons affecting the oil and gas industry as a whole shall not constitute a material
adverse effect), (b) the ability of the Credit Parties taken as a whole to carry out their
business as of the date of this Agreement or as proposed at the date of this Agreement to be
conducted, (c) the ability of the Credit Parties taken as a whole to perform fully and on a
timely basis their respective obligations under any of the Loan Documents to which
they are a party, or (d) the validity or enforceability of any of the Loan Documents or
the rights and remedies of the Administrative Agent or the Lenders under this Agreement and
the other Loan Documents.
“Material Domestic Subsidiary” means any Domestic Subsidiary that (i) owns or
holds assets, properties or interests (including Oil and Gas Interests) with an aggregate
fair market value, on a consolidated basis, greater than five percent (5%) of the aggregate
fair market value of all of the assets, properties and interests (including Oil and Gas
Interests) of the Borrower and the Restricted Subsidiaries, on a consolidated basis.
“Material Indebtedness” means Indebtedness (other than the Loans and Letters of
Credit), or obligations in respect of one or more Swap Agreements, of the Borrower or any
one or more of the Restricted Subsidiaries in an aggregate principal amount exceeding
$10,000,000. For purposes of determining Material Indebtedness, the “principal amount” of
the obligations of the Borrower or any Guarantor in respect of any Swap Agreement at any
time shall be the maximum aggregate amount (giving effect to any netting agreements) that
the Borrower or such Guarantor would be required to pay if such Swap Agreement were
terminated at such time.
“Maturity Date” means October 25, 2011.
“Maximum Facility Amount” means $1,200,000,000.
“Maximum Liability” has the meaning assigned to such term in Section 8.10.
“Maximum Rate” has the meaning assigned to such term in Section 11.13.
“Moody’s” means Moody’s Investors Service, Inc.
“Mortgaged Properties” means the Oil and Gas Interests described in one or more
duly executed, delivered and filed Mortgages evidencing a Lien prior and superior in right
to any other Person in favor of the Administrative Agent for the benefit of the Secured
Parties and subject only to the Liens permitted pursuant to Section 7.02; provided that the
Borrowing Base Properties of any Credit Party located in Virginia shall be deemed subject to
an executed, delivered and filed Mortgage evidencing such Lien in favor of the
Administrative Agent so long as the Borrower and the Restricted Subsidiaries are in
compliance with Section 6.14 with respect to the Equity Interests of such Credit Party
owning such Virginia Borrowing Base Properties.
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“Mortgages” means all mortgages, deeds of trust, amendments to mortgages,
security agreements, assignments of production, pledge agreements, collateral mortgages,
collateral chattel mortgages, collateral assignments, financing statements and other
documents, instruments and agreements evidencing, creating, perfecting or otherwise
establishing the Liens required by Section 6.09. All Mortgages shall be in form and
substance satisfactory to Administrative Agent in its sole discretion
“Multiemployer Plan” means a multiemployer plan as defined in Section
4001(a)(3) of ERISA.
“Natural Gas” means all natural gas, distillate or sulphur, natural gas liquids
and all products recovered in the processing of natural gas (other than condensate)
including, without limitation, natural gasoline, coalbed methane gas, casinghead gas,
iso-butane, normal butane, propane and ethane (including such methane allowable in
commercial ethane).
“Net Cash Proceeds” means, with respect to the sale of Borrowing Base
Properties by the Borrower or any Restricted Subsidiary, the excess, if any, of (a) the sum
of cash and cash equivalents received in connection with such sale, but only as and when so
received, over (b) the sum of (i) the principal amount of any Indebtedness that is secured
by such asset and that is required to be repaid in connection with the sale thereof (other
than the Loans), (ii) the out-of-pocket expenses incurred by the Borrower or such Restricted
Subsidiary in connection with such sale, (iii) all legal, title and recording tax expense
and all federal, state, provincial, foreign and local taxes required to be accrued as a
liability under GAAP as a consequence of such sale, (iv) all distributions and other
payments required to be made to minority interest holders in Restricted Subsidiaries as a
result of such sale, (v) the deduction of appropriate amounts provided by the seller as a
reserve, in accordance with GAAP, against any liabilities associated with the property or
other assets disposed of in such sale and retained by the Borrower or any Restricted
Subsidiary after such sale, (vi) cash payments made to satisfy obligations resulting from
early termination of Swap Agreements in connection with or as a result of any such sale, and
(vii) any portion of the purchase price from such sale placed in escrow, whether as a
reserve for adjustment of the purchase price, for satisfaction of indemnities in respect of
such sale or otherwise in connection with such sale; provided however, that
upon the termination of that escrow, Net Cash Proceeds will be increased by any portion of
funds in the escrow that are released to the Borrower or any Restricted Subsidiary.
“New Commitments” has the meaning assigned to such term in Section 2.03.
“New Lender” has the meaning assigned to such term in Section 2.03.
“Non-Consenting Lender” has the meaning assigned to such term in Section
2.20(c).
“Obligations” means any and all obligations of every nature, contingent or
otherwise, whether now existing or hereafter arising, of any Credit Party from time to
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 16
time owed to the Administrative Agent, the Issuing Bank, the Lenders or any of them or any Lender
Counterparty arising under or in connection with any Loan Document or Swap Agreement
(including, any and all Cash Management Obligations and any and all obligations, contingent
or otherwise, whether now existing or hereafter arising, of any Credit Party under any
Existing Swap Agreement and any and all obligations, contingent or otherwise, whether now
existing or hereafter arising, of any Credit Party with respect to any transactions under
any Swap Agreement with any Person that was a Lender Counterparty at the time such Credit
Party entered into such transactions regardless of
whether such Person is no longer a Lender Counterparty), whether for principal,
interest, reimbursement of amounts drawn under any Letter of Credit, payments for early
termination of Swap Agreements, funding indemnification amounts, fees, expenses,
indemnification or otherwise.
“Off-Balance Sheet Liability” of a Person means (a) any repurchase obligation
or liability of such Person with respect to accounts or notes receivable sold by such
Person, (b) any liability under any Sale and Leaseback Transaction which is not a Capital
Lease Obligation, (c) any liability under any so-called “synthetic lease” transaction
entered into by such Person, or (d) any obligation arising with respect to any other
transaction which is the functional equivalent of or takes the place of borrowing but which
does not constitute a liability on the balance sheets of such Person, but excluding from the
foregoing clauses (c) and (d) operating leases, joint operating agreements, and usual and
customary oil, gas and mineral leases.
“Oil and Gas Interest(s)” means: (a) direct and indirect interests in and
rights with respect to oil, gas, mineral and related properties and assets of any kind and
nature, direct or indirect, including, without limitation, working, royalty and overriding
royalty interests, mineral interests, leasehold interests, production payments, operating
rights, net profits interests, other non-working interests, contractual interests,
non-operating interests and rights in any pooled, unitized or communitized acreage by virtue
of such interest being a part thereof; (b) interests in and rights with respect to
Hydrocarbons other minerals or revenues therefrom and contracts and agreements in connection
therewith and claims and rights thereto (including oil and gas leases, operating agreements,
unitization, communitization and pooling agreements and orders, division orders, transfer
orders, mineral deeds, royalty deeds, oil and gas sales, exchange and processing contracts
and agreements and, in each case, interests thereunder), and surface interests, fee
interests, reversionary interests, reservations and concessions related to any of the
foregoing; (c) easements, rights-of-way, licenses, permits, leases, and other interests
associated with, appurtenant to, or necessary for the operation of any of the foregoing; (d)
interests in oil, gas, water, disposal and injection wells, equipment and machinery
(including well equipment and machinery), oil and gas production, gathering, transmission,
compression, treating, processing and storage facilities (including tanks, tank batteries,
pipelines and gathering systems), pumps, water plants, electric plants, gasoline and gas
processing plants, refineries and other tangible or intangible, movable or immovable, real
or personal property and fixtures located on, associated with, appurtenant to, or necessary
for the operation of any of the foregoing; and (e) all seismic, geological, geophysical and
engineering records, data, information, maps, licenses and interpretations.
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 17
“Organizational Documents” means (a) with respect to any corporation, its
certificate or articles of incorporation or organization, as amended, and its by-laws, as
amended, (b) with respect to any limited partnership, its certificate of limited
partnership, as amended, and its partnership agreement, as amended, (c) with respect to any
general partnership, its partnership agreement, as amended, and (d) with respect to any
limited liability company, its certificate of formation or articles of organization, as
amended, and its limited liability company agreement or operating agreement, as amended.
“Original Credit Agreement” means, that certain Second Amended and Restated
Credit Agreement dated June 23, 2004, among Borrower and GLEP, as borrowers, the lenders
from time to time a party thereto, and JPMorgan Chase Bank N.A. (successor by merger to Bank
One, N.A. (Illinois)), as administrative agent, as amended, supplemented or otherwise
modified from time to time prior to the Effective Date.
“Original Effective Date” means the “Effective Date” as defined in the Original
Credit Agreement.
“Original Loans” means the loans and other extensions of credit outstanding
under the Original Credit Agreement as of the Effective Date.
“Other Taxes” means any and all present or future stamp or documentary taxes or
any other excise or property taxes, charges or similar levies arising from any payment made
hereunder or from the execution, delivery or enforcement of, or otherwise with respect to,
this Agreement.
“Participant” has the meaning assigned to such term in Section 11.04.
“Payment Currency” has the meaning assigned to such term in Section 8.07.
“PBGC” means the Pension Benefit Guaranty Corporation referred to and defined
in ERISA and any successor entity performing similar functions.
“Permitted Encumbrances” means:
(a) Liens imposed by law for Taxes that are not yet due or are being contested in
compliance with Section 6.04;
(b) carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s and other like
Liens imposed by law, landlords’ liens, and contractual Liens granted to operators and
non-operators under oil and gas operating agreements, in each case, arising in the ordinary
course of business or incident to the exploration, development, operation and maintenance of
Oil and Gas Interests and securing obligations that are not overdue by more than 30 days or
are being contested in compliance with Section 6.04;
(c) pledges and deposits made in the ordinary course of business in compliance with
workers’ compensation, unemployment insurance and other social security laws or regulations;
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(d) deposits to secure the performance of bids, trade contracts, leases, statutory
obligations, surety and appeal bonds, performance bonds and other obligations of a like
nature, in each case in the ordinary course of business;
(e) judgment liens in respect of judgments that do not constitute an Event of Default
under clause (k) of Article IX;
(f) easements, zoning restrictions, rights-of-way, servitudes, permits, surface leases,
and similar encumbrances on real property imposed by law or arising in the ordinary course
of business that do not secure any monetary obligations and do not materially detract from
the value of the affected property or interfere with the ordinary conduct of business of any
Credit Party;
(g) royalties, overriding royalties, reversionary interests, production payments, sales
contracts, and similar burdens with respect to the Oil and Gas Interests owned by the
Borrower or such Restricted Subsidiary, as the case may be, if the net cumulative effect of
such burdens does not operate to deprive the Borrower or any Restricted Subsidiary of any
material right in respect of its assets or properties (except for rights customarily granted
with respect to such interests);
(h) Liens arising from Uniform Commercial Code financing statement filings and real
property record filings regarding operating leases entered into by the Borrower or any
Restricted Subsidiary in the ordinary course of business covering the property under the
lease;
(i) routine operational agreements, preferential rights to purchase, and provisions
requiring a third party’s consent prior to assignment and similar restraints on alienation,
in each case, granted pursuant to an oil and gas operating agreement or lease and arising in
the ordinary course of business or incident to the exploration, development, operation and
maintenance of Oil and Gas Interests; provided such right, requirement or restraint does not
materially and adversely affect the value of such Oil and Gas Interests;
(j) Liens arising pursuant to Section 9.343 of the Texas Uniform Commercial Code or
other similar statutory provisions of other states with respect to production purchased from
others; and
(k) Liens (other than Liens on Collateral) that secure obligations under Swap
Agreements to Persons other than a Lender Counterparty.
provided that the term “Permitted Encumbrances” shall not include any Lien securing
Indebtedness (other than contractual Liens described in the foregoing clause (b) granted to
operators and non-operators under oil and gas operating agreements and leases to the extent the
obligations secured by such Liens constitute Indebtedness).
“Permitted Investments” means:
(a) U.S. Government Securities;
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(b) investments in demand and time deposit accounts, certificates of deposit and money
market deposits maturing within 180 days of the date of acquisition thereof issued by a bank
or trust company which is organized under the laws of the United States of America, any
State thereof or any foreign country recognized by the United States of America, and which
bank or trust company has capital, surplus and undivided profits aggregating in excess of
$50,000,000 (or the foreign currency equivalent thereof) and has
outstanding debt which is rated “A” (or such similar equivalent rating) or higher by at
least one nationally recognized statistical rating organization (as defined in Rule 436
under the Securities Act of 1933, as amended) or any money-market fund sponsored by a
registered broker dealer or mutual fund distributor;
(c) investments in deposits available for withdrawal on demand with any commercial bank
that is organized under the laws of any country in which the Borrower or any Restricted
Subsidiary maintains an office or is engaged in the oil and gas business;
(d) repurchase obligations with a term of not more than 30 days for underlying
securities of the types described in clause (a) above entered into with a bank meeting the
qualifications described in clause (b) above;
(e) investments in commercial paper, maturing not more than 90 days after the date of
acquisition, issued by a corporation (other than an Affiliate of the Borrower) organized and
in existence under the laws of the United States of America or any foreign country
recognized by the United States of America with a rating at the time as of which any
investment therein is made of “P-1” (or higher) according to Moody’s or “A-l” (or higher)
according to S&P;
(f) investments in securities with maturities of six months or less from the date of
acquisition issued or fully guaranteed by any state, commonwealth or territory of the United
States of America, or by any political subdivision or taxing authority thereof, and rated at
least “A” by S&P or “A” by Moody’s; and
(g) investments in money market funds that invest substantially all their assets in
securities of the types described in clauses (a) through (f) above
“Person” means any natural person, corporation, limited liability company,
trust, joint venture, association, company, partnership, Governmental Authority or other
entity.
“Plan” means any employee pension benefit plan (other than a Multiemployer
Plan) subject to the provisions of Title IV of ERISA or Section 412 of the Code or Section
302 of ERISA, and in respect of which any Credit Party or any ERISA Affiliate is (or, if
such plan were terminated, would under Section 4069 of ERISA be deemed to be) an “employer”
as defined in Section 3(5) of ERISA.
“Platform” has the meaning assigned to such term in Section 6.01.
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“Pledge Agreement” means a Pledge and Security Agreement in favor of the
Administrative Agent for the benefit of the Secured Parties covering, among other things,
the rights and interests of Borrower or any Restricted Subsidiary in the Equity Interest of
each Restricted Subsidiary and otherwise in form and substance satisfactory to the
Administrative Agent and the Required Lenders.
“Prime Rate” means the rate of interest per annum publicly announced from time
to time by JPMorgan Chase Bank as its prime rate in effect at its principal office in
Chicago, Illinois, each change in the Prime Rate shall be effective from and including
the date such change is publicly announced as being effective.
“Projections” means the Borrower’s forecasted (a) balance sheets, (b) profit
and loss statements, and (c) cash flow statements, all prepared on a basis consistent with
the historical financial statements described in Section 4.04 and after giving effect to the
Transactions, together with appropriate supporting details and a statement of underlying
assumptions, in each case in form and substance satisfactory to the Lenders.
“Public Lender” has the meaning assigned to such term in Section 6.01.
“Redetermination” means any Scheduled Redetermination or Special
Redetermination.
“Redetermination Date” means (a) with respect to any Scheduled Redetermination,
on or about each April 1 and October 1 of each year, commencing April 1, 2007, and (b) with
respect to any Special Redetermination, the first day of the first month which is not less
than twenty (20) Business Days following the date of a request for, or the event giving rise
to, a Special Redetermination.
“Register” has the meaning assigned to such term in Section 11.04.
“Related Parties” means, with respect to any specified Person, such Person’s
Affiliates and the respective directors, officers, employees, agents and advisors of such
Person and such Person’s Affiliates.
“Required Lenders” means, at any time, Lenders having Credit Exposures and
Unused Commitments representing at least fifty percent (50%) of the sum of the Aggregate
Credit Exposure and all Unused Commitments of all Lenders at such time or, if the Aggregate
Commitment has been terminated, Lenders having Credit Exposures representing at least fifty
percent (50%) of the Aggregate Credit Exposure of all Lenders at such time; provided
that the Commitment of and the Credit Exposures held or deemed held by any Defaulting Lender
shall be excluded for purposes of making a determination of the Required Lenders.
“Reserve Report” means an unsuperseded engineering analysis of the Borrowing
Base Properties, in form and substance reasonably acceptable to the Administrative
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 21
Agent,
prepared in accordance with ordinary, customary and prudent practices in the petroleum
engineering industry.
“Responsible Officer” means the chief executive officer, president, vice
president (including without limitation any senior or executive vice president), chief
financial officer, principal accounting officer, treasurer or assistant treasurer of a
Credit Party. Any document delivered hereunder that is signed by a Responsible Officer of a
Credit Party shall be conclusively presumed to have been authorized by all necessary
corporate, partnership and/or other action on the part of such Credit Party and such
Responsible Officer shall be conclusively presumed to have acted on behalf of such Credit
Party.
“Restricted Payment” means, collectively, (i) any dividend or other
distribution (whether in cash, securities or other property) with respect to any Equity
Interests in any Credit Party, or any payment (whether in cash, securities or other
property), including any sinking fund or similar deposit, on account of the purchase,
redemption, retirement, acquisition, cancellation or termination of any such Equity
Interests in any Credit Party or any option, warrant or other right to acquire any such
Equity Interests in any Credit Party and (ii) any payment or prepayment of principal of,
premium on, or redemption, purchase, retirement, defeasance (including in-substance or legal
defeasance) sinking fund or similar payment with respect to the Senior Subordinated Notes.
“Restricted Subsidiary” means any Subsidiary that is not an Unrestricted
Subsidiary.
“S&P” means Standard & Poor’s Ratings Group, a division of The McGraw Hill
Corporation.
“Sale and Leaseback Transaction” means any sale or other transfer of any
property by any Person with the intent to lease such property as lessee.
“Scheduled Redetermination” means any redetermination of the Borrowing Base
pursuant to Section 3.02.
“Secured Party” means the Administrative Agent, any Lender and any Lender
Counterparty and shall include Lenders and Lender Counterparties to the extent that any
Obligations owing to such Persons were incurred while such Persons were Lenders or Lender
Counterparties.
“Security Instruments” means collectively, all Guarantees of the Obligations
evidenced by the Loan Documents and all mortgages, security agreements, pledge agreements,
collateral assignments and other collateral documents covering the Oil and Gas Interests of
the Borrower and the Restricted Subsidiaries and the Equity Interests of the Restricted
Subsidiaries and other personal property, equipment, oil and gas inventory and proceeds of
the foregoing, all such documents to be in form and substance reasonably satisfactory to the
Administrative Agent.
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“Senior Subordinated Notes” means (i) the 7 3/8% Senior Subordinated Notes due
2013, issued pursuant to the Indenture, (ii) the 6 3/8% Senior Subordinated Notes due 2015,
issued pursuant to the Indenture and (iii) the 7 1/2% Senior Subordinated Notes due 2016,
issued pursuant to the Indenture.
“Special Redetermination” means any redetermination of the Borrowing Base made
pursuant to Section 3.03.
“Statutory Reserve Rate” means a fraction (expressed as a decimal), the
numerator of which is the number one and the denominator of which is the number one minus
the aggregate of the maximum reserve percentages (including any marginal, special, emergency
or supplemental reserves) expressed as a decimal established by the
Board to which the Administrative Agent is subject for eurocurrency funding (currently
referred to as “Eurocurrency Liabilities” in Regulation D of the Board). Such reserve
percentages shall include those imposed pursuant to such Regulation D. Eurodollar Loans
shall be deemed to constitute eurocurrency funding and to be subject to such reserve
requirements without benefit of or credit for proration, exemptions or offsets that may be
available from time to time to any Lender under such Regulation D or any comparable
regulation. The Statutory Reserve Rate shall be adjusted automatically on and as of the
effective date of any change in any reserve percentage.
“Subsidiary” means, with respect to any Person (the “parent”) at any
date, any corporation, limited liability company, partnership, association or other entity
(a) of which securities or other ownership interests representing more than 50% of the
equity or more than 50% of the ordinary voting power or, in the case of a partnership, more
than 50% of the general partnership interests are, as of such date, owned, controlled or
held, or (b) that is, as of such date, otherwise Controlled, by the parent or one or more
subsidiaries of the parent or by the parent and one or more subsidiaries of the parent.
Unless the context otherwise clearly requires, references herein to a “Subsidiary” refer to
a Subsidiary of the Borrower.
“Super Majority Lenders” means, at any time, Lenders having Credit Exposures
and Unused Commitments representing at least sixty-six and two-thirds percent (66 2/3%) of
the sum of the Aggregate Credit Exposure and all Unused Commitments of all Lenders at such
time or, if the Aggregate Commitment has been terminated, Lenders having Credit Exposures
representing at least sixty-six and two-thirds percent (66 2/3%) of the Aggregate Credit
Exposure of all Lenders at such time; provided that the Commitment of and the Credit
Exposures held or deemed held by any Defaulting Lender shall be excluded for purposes of
making a determination of the Super Majority Lenders.
“Swap Agreement” means any agreement with respect to any swap, forward, future
or derivative transaction or option or similar agreement involving, or settled by reference
to, one or more rates, currencies, commodities, equity or debt instruments or securities, or
economic, financial or pricing indices or measures of economic, financial or pricing risk or
value or any similar transaction or any combination of these transactions; provided
that no phantom stock or similar plan providing for payments only on account
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of services
provided by current or former directors, officers, employees or consultants of the Credit
Parties shall be a Swap Agreement.
“Taxes” means any and all present or future taxes, levies, imposts, duties,
deductions, charges or withholdings imposed by any Governmental Authority.
“Transactions” means the (i) the execution, delivery and performance by the
Credit Parties of this Agreement and the Loan Documents, (ii) the borrowing of Loans, (iii)
the use of the proceeds thereof, and (iv) the issuance of Letters of Credit hereunder.
“Type”, when used in reference to any Loan or Borrowing, refers to whether the
rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by
reference to the Adjusted LIBO Rate or the Alternate Base Rate.
“Unrestricted Subsidiary” means (a) any Subsidiary that at the time of
determination shall be designated an Unrestricted Subsidiary by the Board of Directors of
the Borrower in the manner provided below and (b) any Subsidiary of an Unrestricted
Subsidiary. The Board of Directors of the Borrower may designate any Subsidiary (including
any newly acquired or newly formed Subsidiary) to be an Unrestricted Subsidiary unless such
Subsidiary or any of its Subsidiaries is a Material Domestic Subsidiary or a Subsidiary
owning Oil and Gas Interests included in the Borrowing Base Properties.
“Unused Commitment” means, with respect to each Lender at any time, such
Lender’s Commitment at such time minus such Lender’s Credit Exposure at such time.
“Unused Commitment Fee” has the meaning assigned to such term in Section
2.13(a).
“U.S. Government Securities” means direct obligations of, or obligations the
principal of and interest on which are unconditionally guaranteed by, the United States of
America (or by any agency thereof to the extent such obligations are backed by the full
faith and credit of the United States of America), in each case maturing within one year
from the date of acquisition thereof.
“Withdrawal Liability” means liability to a Multiemployer Plan as a result of a
complete or partial withdrawal from such Multiemployer Plan, as such terms are defined in
Part I of Subtitle E of Title IV of ERISA.
Section 1.02. Types of Loans and Borrowings. For purposes of this Agreement, Loans
may be classified and referred to by Type (e.g., a “Eurodollar Loan”). Borrowings also may
be classified and referred to by Type (e.g., a “Eurodollar Borrowing”).
Section 1.03. Terms Generally. The definitions of terms herein shall apply equally
to the singular and plural forms of the terms defined. Whenever the context may require, any
pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”,
“includes” and “including” shall be deemed to be followed by the phrase “without limitation”.
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 24
The
word “will” shall be construed to have the same meaning and effect as the word “shall.” Unless the
context requires otherwise (a) any definition of or reference to any agreement, instrument or other
document herein shall be construed as referring to such agreement, instrument or other document as
from time to time amended, supplemented or otherwise modified (subject to any restrictions on such
amendments, supplements or modifications set forth herein), (b) any reference herein to any Person
shall be construed to include such Person’s successors and assigns, (c) the words “herein”,
“hereof” and “hereunder”, and words of similar import, shall be construed to refer to this
Agreement in its entirety and not to any particular provision hereof, (d) all references herein to
Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of,
and Exhibits and Schedules to, this Agreement and (e) the words “asset” and “property” shall be
construed to have the same meaning and effect and to refer to any and all tangible and intangible
assets and properties, including cash, securities, accounts and contract rights.
Section 1.04. Accounting Terms; GAAP. Except as otherwise expressly provided herein,
all terms of an accounting or financial nature shall be construed in accordance with GAAP, as in
effect from time to time; provided that, if the Borrower notifies the Administrative Agent
that the Borrower requests an amendment to any provision hereof to eliminate the effect of any
change occurring after the date hereof in GAAP or in the application thereof on the operation of
such provision (or if the Administrative Agent notifies the Borrower that the Required Lenders
request an amendment to any provision hereof for such purpose), regardless of whether any such
notice is given before or after such change in GAAP or in the application thereof, then such
provision shall be interpreted on the basis of GAAP as in effect and applied immediately before
such change shall have become effective until such notice shall have been withdrawn or such
provision amended in accordance herewith.
Section 1.05. Oil and Gas Definitions. For purposes of this Agreement, the terms
“proved [or] proven reserves,” “proved developed reserves,” “proved [or] proven undeveloped
reserves,” “proved [or] proven developed nonproducing reserves” and “proved [or] proven developed
producing reserves,” have the meaning given such terms from time to time and at the time in
question by the Society of Petroleum Engineers of the American Institute of Mining Engineers.
Section 1.06. Time of Day. Unless otherwise specified, all references to times of
day shall be references to Central time (daylight or standard, as applicable).
Article II
The Credits
Section 2.01. Commitments. Subject to the terms and conditions set forth herein,
each Lender agrees to continue the Original Loans and to make Loans to the Borrower from time to
time during the Availability Period in an aggregate principal amount that will not result in (a)
such Lender’s Credit Exposure exceeding such Lender’s Commitment or (b) the Aggregate Credit
Exposure exceeding the Aggregate Commitment. Within the foregoing limits and subject
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to the terms
and conditions set forth herein, the Borrower may borrow, prepay and reborrow Loans.
Section 2.02. Termination and Reduction of the Aggregate Commitment.
(a) Unless previously terminated, the Aggregate Commitment shall terminate on the Maturity
Date.
(b) The Borrower may at any time terminate, or from time to time reduce, the Aggregate
Commitment; provided that (i) each reduction of the Aggregate Commitment shall be in an
amount that is an integral multiple of $10,000,000, and (ii) the Borrower shall not terminate or
reduce the Aggregate Commitment if, after giving effect to any concurrent prepayment of the Loans
in accordance with Section 2.11 and Section 2.12, the Aggregate Credit Exposure would exceed the
Aggregate Commitment.
(c) The Borrower shall notify the Administrative Agent of any election to terminate or reduce
the Aggregate Commitment under paragraph (b) of this Section at least three Business Days prior to
the effective date of such termination or reduction, specifying such election and the effective
date thereof. Promptly following receipt of any notice, the Administrative Agent shall advise the
Lenders of the contents thereof. Each notice delivered by the Borrower pursuant to this Section
shall be irrevocable; provided that a notice of termination of the Aggregate Commitment
delivered by the Borrower may state that such notice is conditioned upon the effectiveness of other
credit facilities, in which case such notice may be revoked by the Borrower (by notice to the
Administrative Agent on or prior to the specified effective date) if such condition is not
satisfied. Any termination of the Aggregate Commitment shall be permanent. Each reduction of the
Aggregate Commitment shall be made ratably among the Lenders in accordance with their respective
Commitment.
(d) With respect to any sale, transfer or disposition of Borrowing Base Properties (other than
sales, transfers or dispositions permitted under Section 7.03(a)(vi)), the Borrowing Base shall be
automatically reduced by an amount equal to the value assigned to such Borrowing Base Properties by
the Administrative Agent in connection with the most recent Redetermination of the Borrowing Base
preceding the date of such sale (or in connection with the determination of the Initial Borrowing
Base with respect to any sale occurring prior to the first Redetermination of the Borrowing Base).
Section 2.03. Increases in the Aggregate Commitment. So long as no Default has
occurred and is continuing or would be caused by such increase, the Borrower may by written notice
to the Administrative Agent, elect to increase the existing Aggregate Commitment in a minimum
amount of $50,000,000 and integral multiples of $10,000,000 in excess of that amount (any such
increase, the “New Commitments”); provided that the amount of such increase
together with the existing Aggregate Commitment does not, in the aggregate, exceed the lesser of
(a) the Maximum Facility Amount, or (b) the Borrowing Base then in effect. Each such notice shall
specify the date (each an “Increased Commitment Date”) on which the Borrower proposes that
the New Commitments shall be effective, which shall be a date no less than 20 days after the date
on which such notice is delivered to the Administrative Agent. Within 5 days of such notice
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from
the Borrower, the Administrative Agent shall notify each Lender of the amount of the New
Commitments and each Lender’s allocation of the New Commitments based on each Lender’s Applicable
Percentage of the existing Aggregate Commitment. Within 10 days of such notice from the Borrower,
each Lender, in its sole discretion, may elect or decline to provide its allocation of the New
Commitments. In the event any Lender declines to provide its allocation of the New Commitments or
fails to respond within ten days of such notice, each Lender that has elected to provide its
allocation, in its sole discretion, may elect or decline to provide a portion of any other Lender’s
declined allocation in the same proportion that such Lender’s allocation bears to the aggregate
amount of the allocations of all Lenders electing to provide their respective allocations. In the
event the Lenders do not elect to provide all of the New Commitments, the Arranger and the
Administrative Agent shall, in consultation with the Borrower, use commercially reasonable efforts
to identify one or more Eligible Assignees to provide the New Commitments the existing Lenders have
declined to provide (each, a “New Lender”). Such New Commitments shall become effective as
of such Increased Commitment Date in an aggregate amount equal to the amount the Lenders and any
New Lenders have elected to provide as of such
date; provided that (1) no Default exists on such Increased Commitment Date before or
after giving effect to such New Commitments, (2) the Borrower and its Consolidated Subsidiaries are
in pro forma compliance with each of the financial covenants set forth in Section 7.11 as of the
last day of the most recently ended fiscal quarter of the Borrower after giving effect to such New
Commitments, (3) if any portion of the New Commitments are provided by a New Lender, the New
Commitments of such New Lender shall be effected pursuant to an Assignment and Assumption, (4) the
Borrower shall make any payments required pursuant to Section 2.13 in connection with the New
Commitments and (5) to the extent requested in writing, the Administrative Agent has received (i)
copies, certified by the secretary of the Borrower and each Guarantor, of their respective Board of
Directors’ resolutions and of resolutions or actions of any other body authorizing the increase in
the Aggregate Commitment and the confirmation and ratification of the Guarantees and all other Loan
Documents, (ii) a certificate, signed by a Responsible Officer, showing that before and after
giving effect to the New Commitments, no Default or Event of Default shall exist and the Borrower
is in compliance with all covenants in this Agreement and in pro forma compliance with the
financial covenants set forth in Section 7.11, (iii) copies of all governmental and nongovernmental
consents, approvals, authorizations, declarations, registrations or filings, if any, required on
the part of the Borrower or any Guarantor in connection with the New Commitments, certified as true
and correct in full force and effect as of the date of the increase by a duly authorized officer of
the Borrower, or if none are required, a certificate of such officer to that effect, (iv) evidence
satisfactory to the Administrative Agent that no event, change or circumstance shall have occurred
with respect to the Borrower and its Subsidiaries since the most recent financial statements
provided to the Lenders hereunder that could reasonably be expected to result in a Material Adverse
Effect and (v) such other documents and conditions as the Administrative Agent or its counsel may
have reasonably requested.
(a) On any Increased Commitment Date on which New Commitments are effected, subject to the
satisfaction of the foregoing terms and conditions, (a) each of the Lenders shall assign to each of
the New Lenders, and each of the New Lenders shall purchase from each of the Lenders, at the
principal amount thereof (together with accrued interest), such interests in the
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 27
Loans outstanding
on such Increased Commitment Date as shall be necessary in order that, after giving effect to all
such assignments and purchases, such Loans will be held by existing Lenders and New Lenders ratably
in accordance with their Commitments after giving effect to the addition of such New Commitments to
the Commitments, (b) each New Commitment shall be deemed for all purposes a Commitment and each
Loan made thereunder shall be deemed, for all purposes, a Loan and (c) each New Lender shall become
a Lender with respect to the New Commitment and all matters relating thereto.
Section 2.04. Loans and Borrowings.
(a) Each Loan shall be made as part of a Borrowing consisting of Loans made by the Lenders
ratably in accordance with their respective Commitments. The failure of any Lender to make any
Loan required to be made by it shall not relieve any other Lender of its obligations hereunder;
provided that the Commitments of the Lenders are several and no Lender shall be responsible
for any other Lender’s failure to make Loans as required.
(b) Subject to Section 2.15, each Borrowing shall be comprised entirely of ABR Loans or
Eurodollar Loans as the Borrower may request in accordance herewith. Each Lender at its option may
make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to
make such Loan; provided that any exercise of such option shall not affect the obligation
of the Borrower to repay such Loan in accordance with the terms of this Agreement and the exercise
of such option would not, in and of itself, give rise to the obligation of Borrower to pay
Indemnified Taxes..
(c) At the commencement of each Interest Period for any Eurodollar Borrowing, such Borrowing
shall be in an aggregate amount that is an integral multiple of $1,000,000 and not less than
$5,000,000. At the time that each ABR Borrowing is made, such Borrowing shall be in an aggregate
amount that is an integral multiple of $500,000 and not less than $2,000,000; provided that
an ABR Borrowing may be in an aggregate amount that is equal to the entire unused balance of the
Aggregate Commitment or that is required to finance the reimbursement of an LC Disbursement as
contemplated by Section 2.07(e). Borrowings of more than one Type may be outstanding at the same
time; provided that there shall not at any time be more than a total of ten (10) Eurodollar
Borrowings outstanding.
(d) Notwithstanding any other provision of this Agreement, the Borrower shall not be entitled
to request, or to elect to convert or continue, any Eurodollar Borrowing if the Interest Period
requested with respect thereto would end after the Maturity Date.
Section 2.05. Requests for Borrowings. To request a Borrowing, the Borrower shall
notify the Administrative Agent of such request by telephone (a) in the case of a Eurodollar
Borrowing, not later than 11:00 a.m., three Business Days before the date of the proposed
Eurodollar Borrowing or (b) in the case of an ABR Borrowing, not later than 10:00 a.m. on the
Business Day of the proposed Borrowing. Each such telephonic Borrowing Request shall be
irrevocable and shall be confirmed promptly by hand delivery or telecopy to the Administrative
Agent of a written Borrowing Request in a form approved by the Administrative Agent and
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signed by
the Borrower. Each such telephonic and written Borrowing Request shall specify the following
information in compliance with Section 2.04:
(i) the aggregate amount of the requested Borrowing;
(ii) the date of such Borrowing, which shall be a Business Day;
(iii) whether such Borrowing is to be an ABR Borrowing or a Eurodollar Borrowing;
(iv) in the case of a Eurodollar Borrowing, the initial Interest Period to be
applicable thereto, which shall be a period contemplated by the definition of the term
“Interest Period”; and
(v) the location and number of the Borrower’s account to which funds are to be
disbursed, which shall comply with the requirements of Section 2.08.
If no election as to the Type of Borrowing is specified, then the requested Borrowing shall be an
ABR Borrowing. If no Interest Period is specified with respect to any requested Eurodollar
Borrowing, then the Borrower shall be deemed to have selected an Interest Period of one month’s
duration. Promptly following receipt of a Borrowing Request in accordance with this Section, the
Administrative Agent shall advise each Lender of the details thereof and of the amount of such
Lender’s Loan to be made as part of the requested Borrowing.
Section 2.06. Reserved.
Section 2.07. Letters of Credit.
(a) General. Subject to the terms and conditions set forth herein, the Borrower may
request the issuance of Letters of Credit for its own or the account of any Restricted Subsidiary
in a form reasonably acceptable to the Administrative Agent and the Issuing Bank, at any time and
from time to time during the Availability Period. In the event of any inconsistency between the
terms and conditions of this Agreement and the terms and conditions of any form of letter of credit
application or other agreement submitted by the Borrower to, or entered into by the Borrower with,
the Issuing Bank relating to any Letter of Credit, the terms and conditions of this Agreement shall
control.
(b) Notice of Issuance, Amendment, Renewal, Extension; Certain Conditions. To request
the issuance of a Letter of Credit (or the amendment, renewal or extension of an outstanding Letter
of Credit), the Borrower shall hand deliver or telecopy (or transmit by electronic communication,
if arrangements for doing so have been approved by the Issuing Bank) to the Issuing Bank and the
Administrative Agent (reasonably in advance of the requested date of issuance, amendment, renewal
or extension) a notice requesting the issuance of a Letter of Credit, or identifying the Letter of
Credit to be amended, renewed or extended, and specifying the date of issuance, amendment, renewal
or extension (which shall be a Business Day), the date on which such Letter of Credit is to expire
(which shall comply with paragraph (c) of this Section), the amount of such Letter of Credit, the
name and address of the beneficiary thereof
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and such other information as shall be necessary to
prepare, amend, renew or extend such Letter of Credit. If requested by the Issuing Bank, the
Borrower also shall submit a letter of credit application on the Issuing Bank’s standard form in
connection with any request for a Letter of Credit. A Letter of Credit shall be issued, amended,
renewed or extended only if (and upon issuance, amendment, renewal or extension of each Letter of
Credit the Borrower shall be deemed to represent and warrant that), after giving effect to such
issuance, amendment, renewal or extension (i) the LC Exposure shall not exceed $50,000,000 and (ii)
the Aggregate Credit Exposure shall not exceed the Aggregate Commitment.
(c) Expiration Date. Each Letter of Credit shall expire at or prior to the close of
business on the earlier of (i) the date one year after the date of the issuance of such Letter of
Credit (or, in the case of any renewal or extension thereof, one year after such renewal or
extension) and (ii) the date that is five Business Days prior to the Maturity Date.
(d) Participations. By the issuance of a Letter of Credit (or an amendment to a
Letter of Credit increasing the amount thereof) and without any further action on the part of the
Issuing Bank or the Lenders, the Issuing Bank hereby grants to each Lender, and each Lender hereby
acquires from the Issuing Bank, a participation in such Letter of Credit equal to such
Lender’s Applicable Percentage of the aggregate amount available to be drawn under such Letter of
Credit. In consideration and in furtherance of the foregoing, each Lender hereby absolutely and
unconditionally agrees to pay to the Administrative Agent, for the account of the Issuing Bank,
such Lender’s Applicable Percentage of each LC Disbursement made by the Issuing Bank and not
reimbursed by the Borrower on the date due as provided in paragraph (e) of this Section, or of any
reimbursement payment required to be refunded to the Borrower for any reason. Each Lender
acknowledges and agrees that its obligation to acquire participations pursuant to this paragraph in
respect of Letters of Credit is absolute and unconditional and shall not be affected by any
circumstance whatsoever, including any amendment, renewal or extension of any Letter of Credit or
the occurrence and continuance of a Default or reduction or termination of the Aggregate
Commitment, and that each such payment shall be made without any offset, abatement, withholding or
reduction whatsoever.
(e) Reimbursement. If the Issuing Bank shall make any LC Disbursement in respect of a
Letter of Credit, the Borrower shall reimburse such LC Disbursement by paying to the Administrative
Agent an amount equal to such LC Disbursement not later than 12:00 noon on the date that such LC
Disbursement is made, if the Borrower shall have received notice of such LC Disbursement prior to
10:00 a.m. on such date, or, if such notice has not been received by the Borrower prior to such
time on such date, then not later than 12:00 noon on (i) the Business Day that the Borrower
receives such notice, if such notice is received prior to 10:00 a.m. on the day of receipt, or (ii)
the Business Day immediately following the day that the Borrower receives such notice, if such
notice is not received prior to such time on the day of receipt; provided that the Borrower
may, subject to the conditions to borrowing set forth herein, request in accordance with Section
2.05 that such payment be financed with an ABR Borrowing in an equivalent amount and, to the extent
so financed, the Borrower’s obligation to make such payment shall be discharged and replaced by the
resulting ABR Borrowing. If the Borrower fails to make such payment when due, the Administrative
Agent shall notify each Lender of the applicable LC Disbursement, the payment then due from the
Borrower in respect thereof and such Lender’s
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Applicable Percentage thereof. Promptly following
receipt of such notice, each Lender shall pay to the Administrative Agent its Applicable Percentage
of the payment then due from the Borrower, in the same manner as provided in Section 2.08 with
respect to Loans made by such Lender (and Section 2.08 shall apply, mutatis
mutandis, to the payment obligations of the Lenders), and the Administrative Agent shall
promptly pay to the Issuing Bank the amounts so received by it from the Lenders. Promptly
following receipt by the Administrative Agent of any payment from the Borrower pursuant to this
paragraph, the Administrative Agent shall distribute such payment to the Issuing Bank or, to the
extent that Lenders have made payments pursuant to this paragraph to reimburse the Issuing Bank,
then to such Lenders and the Issuing Bank as their interests may appear. Any payment made by a
Lender pursuant to this paragraph to reimburse the Issuing Bank for any LC Disbursement (other than
the funding of ABR Loans as contemplated above) shall not constitute a Loan and shall not relieve
the Borrower of its obligation to reimburse such LC Disbursement.
(f) Obligations Absolute. The Borrower’s obligation to reimburse LC Disbursements as
provided in paragraph (e) of this Section shall be absolute, unconditional and irrevocable, and
shall be performed strictly in accordance with the terms of this Agreement under any and all
circumstances whatsoever and irrespective of (i) any lack of validity or enforceability of any
Letter of Credit or this Agreement, or any term or provision therein, (ii) any draft or other
document presented under a Letter of Credit proving to be forged, fraudulent or invalid in any
respect or any statement therein being untrue or inaccurate in any respect, (iii) payment by the
Issuing Bank under a Letter of Credit against presentation of a draft or other document that does
not comply with the terms of such Letter of Credit, or (iv) any other event or circumstance
whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of
this Section, constitute a legal or equitable discharge of, or provide a right of setoff against,
the Borrower’s obligations hereunder. Neither the Administrative Agent, the Lenders nor the
Issuing Bank, nor any of their Related Parties, shall have any liability or responsibility by
reason of or in connection with the issuance or transfer of any Letter of Credit or any payment or
failure to make any payment thereunder (irrespective of any of the circumstances referred to in the
preceding sentence), or any error, omission, interruption, loss or delay in transmission or
delivery of any draft, notice or other communication under or relating to any Letter of Credit
(including any document required to make a drawing thereunder), any error in interpretation of
technical terms or any consequence arising from causes beyond the control of the Issuing Bank;
provided that the foregoing shall not be construed to excuse the Issuing Bank from
liability to the Borrower to the extent of any direct damages (as opposed to consequential damages,
claims in respect of which are hereby waived by the Borrower to the extent permitted by applicable
law) suffered by the Borrower that are caused by the Issuing Bank’s failure to exercise care when
determining whether drafts and other documents presented under a Letter of Credit comply with the
terms thereof. The parties hereto expressly agree that, in the absence of gross negligence or
willful misconduct on the part of the Issuing Bank (as finally determined by a court of competent
jurisdiction), the Issuing Bank shall be deemed to have exercised care in each such determination.
In furtherance of the foregoing and without limiting the generality thereof, the parties agree
that, with respect to documents presented which appear on their face to be in substantial
compliance with the terms of a Letter of Credit, the Issuing Bank may, in its sole discretion,
either accept and make payment upon such documents without responsibility for
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 31
further
investigation, regardless of any notice or information to the contrary, or refuse to accept and
make payment upon such documents if such documents are not in strict compliance with the terms of
such Letter of Credit.
(g) Disbursement Procedures. The Issuing Bank shall, promptly following its receipt
thereof, examine all documents purporting to represent a demand for payment under a Letter of
Credit. The Issuing Bank shall promptly notify the Administrative Agent and the Borrower by
telephone (confirmed by telecopy) of such demand for payment and whether the Issuing Bank has made
or will make an LC Disbursement thereunder; provided that any failure to give or delay in
giving such notice shall not relieve the Borrower of its obligation to reimburse the Issuing Bank
and the Lenders with respect to any such LC Disbursement.
(h) Interim Interest. If the Issuing Bank shall make any LC Disbursement, then,
unless the Borrower shall reimburse such LC Disbursement in full on the date such LC Disbursement
is made, the unpaid amount thereof shall bear interest, for each day from and including the date
such LC Disbursement is made to but excluding the date that the Borrower reimburses such LC
Disbursement, at the rate per annum then applicable to ABR Loans; provided that, if the
Borrower fails to reimburse such LC Disbursement when due pursuant to
paragraph (e) of this Section, then Section 2.14(c) shall apply. Interest accrued pursuant to
this paragraph shall be for the account of the Issuing Bank, except that interest accrued on and
after the date of payment by any Lender pursuant to paragraph (e) of this Section to reimburse the
Issuing Bank shall be for the account of such Lender to the extent of such payment.
(i) Replacement of the Issuing Bank. The Issuing Bank may be replaced at any time by
written agreement among the Borrower, the Administrative Agent, the replaced Issuing Bank and the
successor Issuing Bank. The Administrative Agent shall notify the Lenders of any such replacement
of the Issuing Bank. At the time any such replacement shall become effective, the Borrower shall
pay all unpaid fees accrued for the account of the replaced Issuing Bank pursuant to Section
2.13(b). From and after the effective date of any such replacement, (i) the successor Issuing Bank
shall have all the rights and obligations of the Issuing Bank under this Agreement with respect to
Letters of Credit to be issued thereafter and (ii) references herein to the term “Issuing Bank”
shall be deemed to refer to such successor or to any previous Issuing Bank, or to such successor
and all previous Issuing Banks, as the context shall require. After the replacement of an Issuing
Bank hereunder, the replaced Issuing Bank shall remain a party hereto and shall continue to have
all the rights and obligations of an Issuing Bank under this Agreement with respect to Letters of
Credit issued by it prior to such replacement, but shall not be required to issue additional
Letters of Credit.
(j) Cash Collateralization. If any Event of Default shall occur and be continuing, on
or before the fifth (5th) Business Day after the Borrower receives notice from the
Administrative Agent or the Required Lenders (or, if the maturity of the Loans has been
accelerated, Lenders with LC Exposure representing greater than sixty-six and two-thirds percent
(66 2/3%) of the total LC Exposure) demanding the deposit of cash collateral pursuant to this
paragraph, the Borrower shall deposit in an account with the Administrative Agent, in the name of
the Administrative Agent and for the benefit of the Lenders, an amount in cash equal to the LC
Exposure as of such date plus any accrued and unpaid interest thereon; provided that the
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 32
obligation to deposit such cash collateral shall become effective immediately, and such deposit
shall become immediately due and payable, without demand or other notice of any kind, upon the
occurrence of any Event of Default with respect to the Borrower described in clause (h) or (i) of
Article IX. Such deposit shall be held by the Administrative Agent as Collateral for the payment
and performance of the obligations of the Borrower under this Agreement. So long as such Event of
Default is continuing, the Administrative Agent shall have exclusive dominion and control,
including the exclusive right of withdrawal, over such account. Other than any interest earned on
the investment of such deposits and interest at the rate per annum in effect for accounts of the
same type maintained with the Administrative Agent at such time, which investments shall be made at
the option and sole discretion of the Administrative Agent and at the Borrower’s risk and expense,
such deposits shall not bear interest. Interest or profits, if any, on such investments shall
accumulate in such account. Moneys in such account shall be applied by the Administrative Agent to
reimburse the Issuing Bank for LC Disbursements for which it has not been reimbursed and, to the
extent not so applied, shall be held for the satisfaction of the reimbursement obligations of the
Borrower for the LC Exposure at such time or, if the maturity of the Loans has been accelerated
(but subject to the consent of Lenders with LC Exposure representing 66-2/3% or more of the total
LC Exposure), be applied to satisfy other obligations of the Borrower under this Agreement. If the
Borrower is required to provide an amount of cash
collateral hereunder as a result of the occurrence of an Event of Default, such amount (to the
extent not applied as aforesaid) shall be returned to the Borrower within three Business Days after
all Events of Default have been cured or waived.
Section 2.08. Funding of Borrowings.
(a) Each Lender shall make each Loan to be made by it hereunder on the proposed date thereof
by wire transfer of immediately available funds by 12:00 noon to the account of the Administrative
Agent most recently designated by it for such purpose by notice to the Lenders. The Administrative
Agent will make such Loans available to the Borrower by promptly crediting the amounts so received,
in like funds, to an account of the Borrower designated by the Borrower in the applicable Borrowing
Request; provided that ABR Loans made to finance the reimbursement of an LC Disbursement as
provided in Section 2.07(e) shall be remitted by the Administrative Agent to the Issuing Bank.
(b) Unless the Administrative Agent shall have received notice from a Lender prior to the
proposed date of any Borrowing that such Lender will not make available to the Administrative Agent
such Lender’s share of such Borrowing, the Administrative Agent may assume that such Lender has
made such share available on such date in accordance with paragraph (a) of this Section and may, in
reliance upon such assumption, make available to the Borrower a corresponding amount. In such
event, if a Lender has not in fact made its share of the applicable Borrowing available to the
Administrative Agent, then the applicable Lender and the Borrower severally agree to pay to the
Administrative Agent forthwith on demand such corresponding amount with interest thereon, for each
day from and including the date such amount is made available to the Borrower to but excluding the
date of payment to the Administrative Agent, at (i) in the case of such Lender, the greater of the
Federal Funds Effective Rate and a rate determined by the Administrative Agent in accordance with
banking industry rules on interbank compensation or (ii) in the case of the Borrower, the interest
rate applicable to
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 33
ABR Loans. If such Lender pays such amount to the Administrative Agent, then
such amount shall constitute such Lender’s Loan included in such Borrowing.
Section 2.09. Interest Elections.
(a) Each Borrowing initially shall be of the Type specified in the applicable Borrowing
Request and, in the case of a Eurodollar Borrowing, shall have an initial Interest Period as
specified in such Borrowing Request; provided that all “LIBOR Loans” (as defined in the
Original Credit Agreement) outstanding as of the Effective Date shall continue as Eurodollar
Borrowings for the Interest Period applicable to such Borrowings. Thereafter, the Borrower may
elect to convert such Borrowing to a different Type or to continue such Borrowing and, in the case
of a Eurodollar Borrowing, may elect Interest Periods therefor, all as provided in this Section.
The Borrower may elect different options with respect to different portions of the affected
Borrowing, in which case each such portion shall be allocated ratably among the Lenders holding the
Loans comprising such Borrowing, and the Loans comprising each such portion shall be considered a
separate Borrowing.
(b) To make an election pursuant to this Section, the Borrower shall notify the Administrative
Agent of such election by telephone by the time that a Borrowing Request would
be required under Section 2.05 if the Borrower were requesting a Borrowing of the Type
resulting from such election to be made on the effective date of such election. Each such
telephonic Interest Election Request shall be irrevocable and shall be confirmed promptly by hand
delivery or telecopy to the Administrative Agent of a written Interest Election Request in a form
approved by the Administrative Agent and signed by the Borrower.
(c) Each telephonic and written Interest Election Request shall specify the following
information in compliance with Section 2.04:
(i) the Borrowing to which such Interest Election Request applies and, if different
options are being elected with respect to different portions thereof, the portions thereof
to be allocated to each resulting Borrowing (in which case the information to be specified
pursuant to clauses (iii) and (iv) below shall be specified for each resulting Borrowing);
(ii) the effective date of the election made pursuant to such Interest Election
Request, which shall be a Business Day;
(iii) whether the resulting Borrowing is to be an ABR Borrowing or a Eurodollar
Borrowing; and
(iv) if the resulting Borrowing is a Eurodollar Borrowing, the Interest Period to be
applicable thereto after giving effect to such election, which shall be a period
contemplated by the definition of the term “Interest Period”.
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If any such Interest Election Request requests a Eurodollar Borrowing but does not specify an
Interest Period, then the Borrower shall be deemed to have selected an Interest Period of one
month’s duration.
(d) Promptly following receipt of an Interest Election Request, the Administrative Agent shall
advise each Lender of the details thereof and of such Lender’s portion of each resulting Borrowing.
(e) If the Borrower fails to deliver a timely Interest Election Request with respect to a
Eurodollar Borrowing prior to the end of the Interest Period applicable thereto, then, unless such
Borrowing is repaid as provided herein, at the end of such Interest Period such Borrowing shall be
converted to an ABR Borrowing. Notwithstanding any contrary provision hereof, if an Event of
Default has occurred and is continuing and the Administrative Agent, at the request of the Required
Lenders, so notifies the Borrower, then, so long as an Event of Default is continuing (i) no
outstanding Borrowing may be converted to or continued as a Eurodollar Borrowing and (ii) unless
repaid, each Eurodollar Borrowing shall be converted to an ABR Borrowing at the end of the Interest
Period applicable thereto.
Section 2.10. Repayment of Loans; Evidence of Debt.
(a) The Borrower hereby unconditionally promises to pay to the Administrative Agent for the
account of each Lender the then unpaid principal amount of each Loan on the Maturity Date.
(b) Each Lender shall maintain in accordance with its usual practice an account or accounts
evidencing the indebtedness of the Borrower to such Lender resulting from each Loan made by such
Lender, including the amounts of principal and interest payable and paid to such Lender from time
to time hereunder.
(c) The Administrative Agent shall maintain accounts in which it shall record (i) the amount
of each Loan made hereunder, the Type thereof and the Interest Period applicable thereto, (ii) the
amount of any principal or interest due and payable or to become due and payable from the Borrower
to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent
hereunder for the account of the Lenders and each Lender’s share thereof.
(d) The entries made in the accounts maintained pursuant to paragraph (b) or (c) of this
Section shall be prima facie evidence of the existence and amounts of the
obligations recorded therein; provided that the failure of any Lender or the Administrative
Agent to maintain such accounts or any error therein shall not in any manner affect the obligation
of the Borrower to repay the Loans in accordance with the terms of this Agreement.
(e) Any Lender or Participant may request that Loans made by it be evidenced by a promissory
note. In such event, the Borrower shall prepare, execute and deliver to such Lender or Participant
a promissory note payable to the order of such Lender or Participant (or, if requested by such
Lender or Participant, to such Lender or Participant and its registered assigns)
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and in the form
attached hereto as Exhibit D. Thereafter, the Loans evidenced by such promissory note and interest
thereon shall at all times (including after assignment pursuant to Section 11.04) be represented by
one or more promissory notes in such form payable to the order of the payee named therein (or, if
such promissory note is a registered note, to such payee and its registered assigns).
Section 2.11. Optional Prepayment of Loans.
(a) The Borrower shall have the right at any time and from time to time to prepay, subject to
the payment of any funding indemnification amounts required by Section 2.17 but without premium or
penalty, any Borrowing in whole and or in part, subject to prior notice in accordance with
paragraph (b) of this Section.
(b) The Borrower shall notify the Administrative Agent by telephone (confirmed by telecopy) of
any prepayment hereunder (i) in the case of prepayment of a Eurodollar Borrowing, not later than
11:00 a.m. three Business Days before the date of prepayment or (ii) in the case of prepayment of
an ABR Borrowing, not later than 10:00 a.m. on the Business Day of the date of prepayment. Each
such notice shall be irrevocable and shall specify the prepayment date and the principal amount of
each Borrowing or portion thereof to be prepaid; provided that, if a notice of
prepayment is given in connection with a conditional notice of termination or reduction of the
Aggregate Commitment as contemplated by Section 2.02, then such notice of prepayment may be revoked
if such notice of termination or reduction is revoked in accordance with Section 2.02. Promptly
following receipt of any such notice relating to a Borrowing, the Administrative Agent shall advise
the Lenders of the contents thereof. Each partial prepayment of any Borrowing shall be in an
integral multiple of $1,000,000. Each prepayment of a Borrowing shall be applied ratably to the
Loans included in the prepaid Borrowing. Prepayments shall be accompanied by accrued interest to
the extent required by Section 2.14.
Section 2.12. Mandatory Prepayment of Loans.
(a) Except as otherwise provided in Section 2.12(b), in the event a Borrowing Base Deficiency
exists, the Borrower shall either (a) within fifteen (15) days after written notice from the
Administrative Agent to the Borrower of such Borrowing Base Deficiency, by instruments satisfactory
in form and substance to the Required Lenders, provide the Lenders with additional security
consisting of Oil and Gas Interests with value and quality satisfactory to the Lenders in their
sole discretion to eliminate such Borrowing Base Deficiency, or prepay, without premium or
penalty, the principal amount of the Loans in an amount sufficient to eliminate such Borrowing Base
Deficiency (or by a combination of such additional security and such prepayment eliminate such
Borrowing Base Deficiency), or (b) within fifteen (15) days after written notice from the
Administrative Agent to the Borrower of such Borrowing Base Deficiency, elect to prepay, subject to
the payment of any funding indemnification amounts required by Section 2.17 but without premium or
penalty, the principal amount of such Borrowing Base Deficiency in not more than six (6) equal
monthly installments plus accrued interest thereon with the first such monthly payment being due
upon the 30th day after the Borrower’s receipt of notice of such Borrowing Base Deficiency. In the
event Aggregate Credit Exposure exceeds the Aggregate Commitment at any time, the Borrower shall,
subject to the
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payment of any funding indemnification amounts required by Section 2.17 but without
premium or penalty, immediately prepay the principal amount of the Loans in an amount sufficient to
eliminate such excess.
(b) If the Borrower or any Restricted Subsidiary sells, transfers or otherwise disposes of any
Borrowing Base Properties at any time a Borrowing Base Deficiency exists or would exist after
giving effect to such sale, transfer or disposition, the Borrower shall prepay the Borrowings in an
amount equal to the Net Cash Proceeds received from such sale, transfer or other disposition on the
date it or any Restricted Subsidiary receives such Net Cash Proceeds; provided,
however that amounts applied to the payment of Borrowings pursuant to this Section may be
reborrowed subject to and in accordance with the terms of this Agreement. Amounts applied to the
prepayment of Borrowings pursuant to this Section shall be first applied, ratably to ABR Borrowings
then outstanding and, upon payment in full of all outstanding ABR Borrowings, second, to Eurodollar
Borrowings then outstanding, and if more than one Eurodollar Borrowing is then outstanding, to each
such Eurodollar Borrowing beginning with the Eurodollar Borrowing with the least number of days
remaining in the Interest Period applicable thereto and ending with the Eurodollar Borrowing with
the most number of days remaining in the Interest Period applicable thereto, subject to the payment
of any funding indemnification amounts required by Section 2.17 but without penalty or premium.
Section 2.13. Fees.
(a) The Borrower agrees to pay to the Administrative Agent, for the account of each Lender, an
unused commitment fee (the “Unused Commitment Fee”) equivalent to the Applicable Rate times
the daily average of the total Unused Commitments. Such Unused Commitment Fee shall be calculated
on the basis of a year consisting of 360 days. The Unused Commitment Fee shall be payable in
arrears on the last day of March, June, September and December of each year, commencing with the
first such date to occur after the Effective Date, and on the Maturity Date for any period then
ending for which the Unused Commitment Fee shall not have been theretofore paid. In the event the
Aggregate Commitment terminates on any date other than the last day of March, June, September or
December of any year, the Borrower agrees to pay to the Administrative Agent, for the account of
each Lender, on the date of such termination, the total Unused Commitment Fee due for the period
from the last day of the immediately preceding March, June, September or December, as the case may
be, to the date such termination occurs.
(b) The Borrower agrees to pay (i) to the Administrative Agent for the account of each Lender
a participation fee with respect to its participations in Letters of Credit, which shall accrue at
the same Applicable Rate used to determine the interest rate applicable to Eurodollar Loans on the
average daily amount of such Lender’s LC Exposure (excluding any portion thereof attributable to
unreimbursed LC Disbursements) during the period from and including the Effective Date to but
excluding the later of the date on which such Lender’s Commitment terminates and the date on which
such Lender ceases to have any LC Exposure, and (ii) to the Issuing Bank a fronting fee, which
shall accrue at the rate or rates per annum separately agreed upon between the Borrower and the
Issuing Bank on the average daily amount of the LC Exposure (excluding any portion thereof
attributable to unreimbursed LC Disbursements) during
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the period from and including the Effective
Date to but excluding the later of the date of termination of the Aggregate Commitment and the date
on which there ceases to be any LC Exposure, as well as the Issuing Bank’s standard fees with
respect to the issuance, amendment, renewal or extension of any Letter of Credit or processing of
drawings thereunder. Participation fees and fronting fees accrued through and including the last
day of March, June, September and December of each year shall be payable on the third Business Day
following such last day, commencing on the first such date to occur after the Effective Date;
provided that all such fees shall be payable on the date on which the Aggregate Commitment
terminates and any such fees accruing after the date on which the Aggregate Commitment terminates
shall be payable on demand. Any other fees payable to the Issuing Bank pursuant to this paragraph
shall be payable within 10 days after demand. All participation fees and fronting fees shall be
computed on the basis of a year of 360 days and shall be payable for the actual number of days
elapsed (including the first day but excluding the last day).
(c) Borrower agrees to pay to the Administrative Agent, for its own account, fees payable in
the amounts and at the times separately agreed upon between the Borrower and the Administrative
Agent pursuant to the fee letter dated September 26, 2006 between the Borrower and the
Administrative Agent, and fees payable upon any increase in the Aggregate Commitment pursuant to
Section 2.03.
(d) All fees payable hereunder shall be paid on the dates due, in immediately available funds,
to the Administrative Agent (or to the Issuing Bank, in the case of fees payable to it) for
distribution, in the case of Unused Commitment Fees and participation fees, to the Lenders. Fees
paid shall not be refundable under any circumstances.
Section 2.14. Interest.
(a) The Loans comprising each ABR Borrowing shall bear interest at the Alternate Base Rate
plus the Applicable Rate.
(b) The Loans comprising each Eurodollar Borrowing shall bear interest at the Adjusted LIBO
Rate for the Interest Period in effect for such Borrowing plus the Applicable Rate.
(c) Notwithstanding the foregoing, if any principal of or interest on any Loan or any fee or
other amount payable by the Borrower hereunder is not paid when due, whether at stated maturity,
upon acceleration or otherwise, such overdue amount, at the election of the Required Lenders by
written notice of such election from the Administrative Agent to the Borrower, shall bear interest,
after as well as before judgment, at a rate per annum equal to (i) in the case of overdue principal
of any Loan, 2% plus the rate otherwise applicable to such Loan as provided in the preceding
paragraphs of this Section or (ii) in the case of any other amount, 2% plus the rate applicable to
ABR Loans as provided in paragraph (a) of this Section; provided that upon the occurrence and
during the continuation of any Event of Default pursuant to clause (h) or (i) of Article IX, the
interest rate set forth in the foregoing clauses (i) and (ii) shall be applicable without any
election by or notice from the Administrative Agent or any Lender.
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(d) Accrued interest on each Loan shall be payable in arrears on each Interest Payment Date
for such Loan and upon termination of the Aggregate Commitment and on the Maturity Date;
provided that (i) interest accrued pursuant to paragraph (c) of this Section shall be
payable on demand, (ii) in the event of any repayment or prepayment of any Loan (other than a
prepayment of an ABR Loan prior to the end of the Availability Period at a time when no Borrowing
Base Deficiency exists), accrued interest on the principal amount repaid or prepaid shall be
payable on the date of such repayment or prepayment and (iii) in the event of any conversion of any
Eurodollar Loan prior to the end of the current Interest Period therefor, accrued interest on such
Loan shall be payable on the effective date of such conversion.
(e) All interest hereunder shall be computed on the basis of a year of 360 days, except that
interest computed by reference to the Alternate Base Rate at times when the Alternate Base Rate is
based on the Prime Rate shall be computed on the basis of a year of 365 days (or 366 days in a leap
year), and in each case shall be payable for the actual number of days elapsed (including the first
day but excluding the last day). The applicable Alternate Base Rate, Adjusted LIBO Rate or LIBO
Rate shall be determined by the Administrative Agent, and such determination shall be conclusive
absent manifest error.
Section 2.15. Alternate Rate of Interest. If prior to the commencement of any
Interest Period for a Eurodollar Borrowing:
(a) the Administrative Agent determines (which determination shall be conclusive absent
manifest error) that adequate and reasonable means do not exist for ascertaining the Adjusted LIBO
Rate or the LIBO Rate, as applicable, for such Interest Period; or
(b) the Administrative Agent is advised by the Required Lenders that the Adjusted LIBO Rate or
the LIBO Rate, as applicable, for such Interest Period will not adequately and fairly reflect the
cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in
such Borrowing for such Interest Period;
then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by
telephone or telecopy as promptly as practicable thereafter and, until the Administrative Agent
notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer
exist, (i) any Interest Election Request that requests the conversion of any Borrowing to, or
continuation of any Borrowing as, a Eurodollar Borrowing shall be ineffective, and (ii) if any
Borrowing Request requests a Eurodollar Borrowing, such Borrowing shall be made as an ABR
Borrowing.
Section 2.16. Increased Costs.
(a) If any Change in Law shall:
(i) impose, modify or deem applicable any reserve, special deposit or similar
requirement against assets of, deposits with or for the account of, or credit extended by,
any Lender (except any such reserve requirement reflected in the Adjusted LIBO Rate) or the
Issuing Bank; or
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(ii) impose on any Lender or the Issuing Bank or the London interbank market any other
condition affecting this Agreement or Eurodollar Loans made by such Lender or any Letter of
Credit or participation therein;
and the result of any of the foregoing shall be to increase the cost to such Lender of
making or maintaining any Eurodollar Loan (or of maintaining its obligation to make any such
Loan) or to increase the cost to such Lender or the Issuing Bank of participating in,
issuing or maintaining any Letter of Credit or to reduce the amount of any sum received or
receivable by such Lender or the Issuing Bank hereunder (whether of principal, interest or
otherwise), then the Borrower will pay to such Lender or the Issuing Bank, as the case may
be, such additional amount or amounts as will compensate such Lender or the Issuing Bank, as
the case may be, for such additional costs incurred or reduction suffered provided such
Lender or Issuing Bank is generally charging such costs to other similarly situated
borrowers under similar credit facilities.
(b) If any Lender or the Issuing Bank determines that any Change in Law regarding capital
requirements has or would have the effect of reducing the rate of return on such Lender’s or the
Issuing Bank’s capital or on the capital of such Lender’s or the Issuing Bank’s holding company, if
any, as a consequence of this Agreement or the Loans made by, or participations in Letters of
Credit held by, such Lender, or the Letters of Credit issued by the Issuing Bank, to a level below
that which such Lender or the Issuing Bank or such Lender’s or the Issuing Bank’s
holding company could have achieved but for such Change in Law (taking into consideration such
Lender’s or the Issuing Bank’s policies and the policies of such Lender’s or the Issuing Bank’s
holding company with respect to capital adequacy and provided such Lender or Issuing Bank’s holding
company is generally charging such costs to other similarly situated borrowers under similar credit
facilities), then from time to time the Borrower will pay to such Lender or the Issuing Bank, as
the case may be, such additional amount or amounts as will compensate such Lender or the Issuing
Bank or such Lender’s or the Issuing Bank’s holding company for any such reduction suffered.
(c) A certificate of a Lender or the Issuing Bank setting forth (i) the amount or amounts
reasonably necessary to compensate such Lender or the Issuing Bank or its holding company, as the
case may be, as specified in paragraph (a) or (b) of this Section, (ii) the factual basis for such
compensation and (iii) the manner in which such amount or amounts were calculated shall be
delivered to the Borrower. Such certificate shall be conclusive absent manifest error. The
Borrower shall pay such Lender or the Issuing Bank, as the case may be, the amount shown as due on
any such certificate within 10 days after receipt thereof.
(d) Failure or delay on the part of any Lender or the Issuing Bank to demand compensation
pursuant to this Section shall not constitute a waiver of such Lender’s or the Issuing Bank’s right
to demand such compensation; provided that the Borrower shall not be required to compensate
a Lender or the Issuing Bank pursuant to this Section for any increased costs or reductions
incurred more than 180 days prior to the date that such Lender or the Issuing Bank, as the case may
be, notifies the Borrower of the Change in Law giving rise to such increased costs or reductions
and of such Lender’s or the Issuing Bank’s intention to claim compensation therefor;
provided further that, if the Change in Law giving rise to such increased
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 40
costs or
reductions is retroactive, then the 180-day period referred to above shall be extended to include
the period of retroactive effect thereof.
Section 2.17. Break Funding Payments. In the event of (a) the payment of any
principal of any Eurodollar Loan other than on the last day of an Interest Period applicable
thereto (including as a result of an Event of Default), (b) the conversion of any Eurodollar Loan
other than on the last day of the Interest Period applicable thereto, (c) the failure to borrow,
convert, continue or prepay any Eurodollar Loan on the date specified in any notice delivered
pursuant hereto (regardless of whether such notice may be revoked under Section 2.11(b) and is
revoked in accordance therewith), (d) the assignment of any Eurodollar Loan other than on the last
day of the Interest Period applicable thereto as a result of a request by the Borrower pursuant to
Section 2.20, then, in any such event, the Borrower shall compensate each Lender for the loss, cost
and expense attributable to such event. In the case of a Eurodollar Loan, such loss, cost or
expense to any Lender shall be deemed to include an amount determined by such Lender to be the
excess, if any, of (i) the amount of interest which would have accrued on the principal amount of
such Loan had such event not occurred, at the Adjusted LIBO Rate that would have been applicable to
such Loan, for the period from the date of such event to the last day of the then current Interest
Period therefor (or, in the case of a failure to borrow, convert or continue, for the period that
would have been the Interest Period for such Loan), over (ii) the amount of interest which would
accrue on such principal amount for such period at the interest rate which such Lender would bid
were it to bid, at the commencement of such period, for dollar deposits of a comparable amount
and period from other banks in the eurodollar market. A certificate of any Lender setting
forth any amount or amounts that such Lender is entitled to receive pursuant to this Section shall
be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay
such Lender the amount shown as due on any such certificate within 10 days after receipt thereof.
Section 2.18. Taxes.
(a) Any and all payments by or on account of any obligation of the Borrower hereunder shall be
made free and clear of and without deduction for any Indemnified Taxes or Other Taxes;
provided that if the Borrower shall be required to deduct any Indemnified Taxes or Other
Taxes from such payments, then (i) the sum payable shall be increased as necessary so that after
making all required deductions (including deductions applicable to additional sums payable under
this Section) the Administrative Agent, Lender or Issuing Bank (as the case may be) receives an
amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower
shall make such deductions and (iii) the Borrower shall pay the full amount deducted to the
relevant Governmental Authority in accordance with applicable law.
(b) In addition, the Borrower shall pay any Other Taxes to the relevant Governmental Authority
in accordance with applicable law.
(c) The Borrower shall indemnify the Administrative Agent, each Lender and the Issuing Bank,
within 10 days after written demand therefor, for the full amount of any Indemnified Taxes or Other
Taxes paid by the Administrative Agent, such Lender or the Issuing Bank, as the case may be, on or
with respect to any payment by or on account of any obligation
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 41
of the Borrower hereunder (including
Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under
this Section) and any penalties, interest and reasonable expenses arising therefrom or with respect
thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or
asserted by the relevant Governmental Authority. A certificate delivered to the Borrower by a
Lender or the Issuing Bank, or by the Administrative Agent on its own behalf or on behalf of a
Lender or the Issuing Bank, setting forth (i) the amount of such payment or liability reasonably
necessary to compensate the Administrative Agent, such Lender or the Issuing Bank, as the case may
be, (ii) the factual basis for such compensation and (iii) the manner in which such amount or
amounts were calculated, shall be conclusive absent manifest error.
(d) As soon as practicable after any payment of Indemnified Taxes or Other Taxes by the
Borrower to a Governmental Authority, the Borrower shall deliver to the Administrative Agent the
original or a certified copy of a receipt issued by such Governmental Authority evidencing such
payment, a copy of the return reporting such payment or other evidence of such payment reasonably
satisfactory to the Administrative Agent.
(e) Any Foreign Lender that is entitled to an exemption from or reduction of withholding tax
under the law of the jurisdiction in which the Borrower is located, or any treaty to which such
jurisdiction is a party, with respect to payments under this Agreement shall deliver to the
Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable
law, such properly completed and executed documentation prescribed by applicable
law or reasonably requested by the Borrower as will permit such payments to be made without
withholding or at a reduced rate.
(f) If the Administrative Agent or a Lender determines, in its sole discretion, that it has
received a refund of any Taxes or Other Taxes as to which it has been indemnified by the Borrower
or with respect to which the Borrower have paid additional amounts pursuant to this Section 2.18,
it shall pay over such refund to the Borrower (but only to the extent of indemnity payments made,
or additional amounts paid, by the Borrower under this Section 2.18 with respect to the Taxes or
Other Taxes giving rise to such refund), net of all out-of-pocket expenses of the Administrative
Agent or such Lender and without interest (other than any interest paid by the relevant
Governmental Authority with respect to such refund); provided, that the Borrower, upon the request
of the Administrative Agent or such Lender, agrees to repay the amount paid over to the Borrower
(plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to
the Administrative Agent or such Lender in the event the Administrative Agent or such Lender is
required to repay such refund to such Governmental Authority. This Section shall not be construed
to require the Administrative Agent or any Lender to make available its tax returns (or any other
information relating to its taxes which it deems confidential) to the Borrower or any other Person.
Section 2.19. Payments Generally; Pro Rata Treatment; Sharing of Set-offs.
(a) The Borrower shall make each payment required to be made by it hereunder (whether of
principal, interest, fees or reimbursement of LC Disbursements, or of amounts payable under Section
2.16, Section 2.17 or Section 2.18, or otherwise) prior to 12:00 noon on
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 42
the date when due, in
immediately available funds, without set-off or counterclaim. Any amounts received after such time
on any date may, in the discretion of the Administrative Agent, be deemed to have been received on
the next succeeding Business Day for purposes of calculating interest thereon. All such payments
shall be made to the Administrative Agent at its offices at JPMorgan Loan Services, 10 South
Dearborn, 19th Floor, Chicago, Illinois 60603-2003, except payments to be made directly to the
Issuing Bank as expressly provided herein and except that payments pursuant to Section 2.16,
Section 2.17, Section 2.18 and Section 11.03 shall be made directly to the Persons entitled
thereto. The Administrative Agent shall distribute any such payments received by it for the
account of any other Person to the appropriate recipient promptly following receipt thereof. If
any payment hereunder shall be due on a day that is not a Business Day, the date for payment shall
be extended to the next succeeding Business Day, and, in the case of any payment accruing interest,
interest thereon shall be payable for the period of such extension. All payments hereunder shall
be made in Dollars.
(b) If at any time insufficient funds are received by and available to the Administrative
Agent to pay fully all amounts of principal, unreimbursed LC Disbursements, interest, fees and
other Obligations then due hereunder, such funds shall be applied (i) first, towards payment of
interest and fees then due hereunder, ratably among the parties entitled thereto in accordance with
the amounts of interest and fees then due to such parties, and (ii) second, towards payment of
principal and unreimbursed LC Disbursements then due hereunder, ratably among the parties entitled
thereto in accordance with the amounts of principal and unreimbursed LC Disbursements then due to
such parties; provided that in the event such funds
are received by and available to the Administrative Agent as a result of the exercise of any
rights and remedies with respect to any Collateral under the Security Instruments, the parties
entitled to a ratable share of such funds pursuant to the foregoing clause (ii) and the
determination of each parties’ ratable share shall include, on a pari passu basis, the Lender
Counterparties and the actual aggregate amounts then due and owing to each Lender Counterparty by
the Borrower or any Guarantor as a result of the early termination of any transactions under any
Swap Agreements included in the Obligations (after giving effect to any netting agreements).
(c) If any Lender shall, by exercising any right of set-off or counterclaim or otherwise,
obtain payment in respect of any principal of or interest on any of its Loans or participations in
LC Disbursements resulting in such Lender receiving payment of a greater proportion of the
aggregate amount of its Loans and participations in LC Disbursements and accrued interest thereon
than the proportion received by any other Lender, then the Lender receiving such greater proportion
shall purchase (for cash at face value) participations in the Loans and participations in LC
Disbursements of other Lenders to the extent necessary so that the benefit of all such payments
shall be shared by the Lenders ratably in accordance with the aggregate amount of principal of and
accrued interest on their respective Loans and participations in LC Disbursements, provided
that (i) if any such participations are purchased and all or any portion of the payment giving rise
thereto is recovered, such participations shall be rescinded and the purchase price restored to
the extent of such recovery, without interest, and (ii) the provisions of this paragraph shall not
be construed to apply to any payment made by the Borrower pursuant to and in accordance with the
express terms of this Agreement or any payment obtained by a Lender as consideration for the
assignment of or sale of a participation in any of its Loans or participations in LC Disbursements
to any assignee or participant, other than
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 43
to the Borrower or any Subsidiary or Affiliate thereof
(as to which the provisions of this paragraph shall apply). The Borrower consents to the foregoing
and agrees, to the extent it may effectively do so under applicable law, that any Lender acquiring
a participation pursuant to the foregoing arrangements may exercise against the Borrower rights of
set-off and counterclaim with respect to such participation as fully as if such Lender were a
direct creditor of the Borrower in the amount of such participation.
(d) Unless the Administrative Agent shall have received notice from the Borrower prior to the
date on which any payment is due to the Administrative Agent for the account of the Lenders or the
Issuing Bank hereunder that the Borrower will not make such payment, the Administrative Agent may
assume that the Borrower have made such payment on such date in accordance herewith and may, in
reliance upon such assumption, distribute to the Lenders or the Issuing Bank, as the case may be,
the amount due. In such event, if the Borrower have not in fact made such payment, then each of
the Lenders or the Issuing Bank, as the case may be, severally agrees to repay to the
Administrative Agent forthwith on demand the amount so distributed to such Lender or Issuing Bank
with interest thereon, for each day from and including the date such amount is distributed to it to
but excluding the date of payment to the Administrative Agent, at the greater of the Federal Funds
Effective Rate and a rate determined by the Administrative Agent in accordance with banking
industry rules on interbank compensation.
(e) If any Lender shall fail to make any payment required to be made by it pursuant to Section
2.07(d) or Section 2.07(e), Section 2.08(b), Section 2.19(d) or Section 11.03(c), then the
Administrative Agent may, in its discretion (notwithstanding any contrary provision hereof), apply
any amounts thereafter received by the Administrative Agent for the account of such Lender to
satisfy such Lender’s obligations under such Sections until all such unsatisfied obligations are
fully paid.
Section 2.20. Mitigation Obligations; Replacement of Lenders.
(a) If any Lender requests compensation under Section 2.16, or if the Borrower is required to
pay any additional amount to any Lender or any Governmental Authority for the account of any Lender
pursuant to Section 2.18, then such Lender shall use reasonable efforts to designate a different
lending office for funding or booking its Loans hereunder or to assign its rights and obligations
hereunder to another of its offices, branches or affiliates, if, in the judgment of such Lender,
such designation or assignment (i) would eliminate or reduce amounts payable pursuant to Section
2.16 or Section 2.18, as the case may be, in the future and (ii) would not subject such Lender to
any unreimbursed cost or expense and would not otherwise be disadvantageous to such Lender. The
Borrower hereby agrees to pay all reasonable costs and expenses incurred by any Lender in
connection with any such designation or assignment.
(b) If any Lender requests compensation under Section 2.16, or if the Borrower is required to
pay any additional amount to any Lender or any Governmental Authority for the account of any Lender
pursuant to Section 2.18, or if any Lender defaults in its obligation to fund Loans hereunder, then
the Borrower may, at its sole expense and effort, upon notice to such Lender and the Administrative
Agent, require such Lender to assign and delegate, without
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recourse (in accordance with and subject
to the restrictions contained in Section 11.04), all its interests, rights and obligations under
this Agreement to an assignee that shall assume such obligations (which assignee may be another
Lender, if a Lender accepts such assignment); provided that (i) the Borrower shall have
received the prior written consent of the Administrative Agent (and if a Commitment is being
assigned, the Issuing Bank), which consent shall not unreasonably be withheld or delayed, (ii) such
Lender shall have received payment of an amount equal to the outstanding principal of its Loans and
participations in LC Disbursements, accrued interest thereon, accrued fees and all other amounts
payable to it hereunder, from the assignee (to the extent of such outstanding principal and accrued
interest and fees) or the Borrower (in the case of all other amounts) and (iii) in the case of any
such assignment resulting from a claim for compensation under Section 2.16 or payments required to
be made pursuant to Section 2.18, such assignment will result in a reduction in such compensation
or payments. A Lender shall not be required to make any such assignment and delegation if, prior
thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the
Borrower to require such assignment and delegation cease to apply.
(c) If in connection with any proposed amendment, modification, termination, waiver or consent
with respect to any of the provisions of this Agreement or any other Loan Document as contemplated
by Section 11.02, the consent of Required Lenders shall have been obtained but the consent of one
or more of such other Lenders (each a “Non-Consenting Lender”) whose consent is required
has not been obtained or if Lender is a Defaulting Lender; then, the Borrower
may elect to replace such Non-Consenting Lender or Defaulting Lender, as the case may be, as a
Lender party to this Agreement in accordance with and subject to the restrictions contained in, and
consents required by Section 11.04; provided that (i) the Borrower shall have received the
prior written consent of the Administrative Agent (and if a Commitment is being assigned, the
Issuing Bank), which consent shall not unreasonably be withheld or delayed, (ii) such Lender shall
have received payment of an amount equal to the outstanding principal of its Loans and
participations in LC Disbursements, accrued interest thereon, accrued fees and all other amounts
payable to it hereunder, from the assignee (to the extent of such outstanding principal and accrued
interest and fees) or the Borrower (in the case of all other amounts) and (iii) in the case of any
such assignment resulting from a claim for compensation under Section 2.16 or payments required to
be made pursuant to Section 2.18, such assignment will result in a reduction in such compensation
or payments. A Lender shall not be required to make any such assignment and delegation if, prior
thereto, as a result of a waiver by such Lender or otherwise, the circumstances entitling the
Borrower to require such assignment and delegation cease to apply or, in the case of a Defaulting
Lender, such Lender is no longer a Defaulting Lender.
Article III
Borrowing Base
Section 3.01. Reserve Report; Proposed Borrowing Base. During the period from the
Effective Date until the first Redetermination after the Effective Date, the Borrowing Base shall
be $1,200,000,000 (the “Initial Borrowing Base”). As soon as available and in any event by
March 1 and September 1 of each year, beginning March 1, 2007, the Borrower shall deliver to the
Administrative Agent and each Lender a Reserve Report, prepared as of the immediately
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 45
preceding December 31 and June 30, respectively, in form and substance reasonably satisfactory
to the Administrative Agent and prepared by an Approved Petroleum Engineer (or, in the case of the
Reserve Report due on September 1 of each year, by petroleum engineers employed by the Borrower or
any of its Subsidiaries), said Reserve Report to utilize economic and pricing parameters
established from time to time by the Administrative Agent, together with such other information,
reports and data concerning the value of the Borrowing Base Properties as the Administrative Agent
shall deem reasonably necessary to determine the value of such Borrowing Base Properties.
Simultaneously with the delivery to the Administrative Agent and the Lenders of each Reserve
Report, the Borrower shall submit to the Administrative Agent and each Lender the Borrower’s
requested amount of the Borrowing Base as of the next Redetermination Date. Promptly after the
receipt by the Administrative Agent of such Reserve Report and Borrower’s requested amount for the
Borrowing Base, the Administrative Agent shall submit to the Lenders a recommended amount of the
Borrowing Base to become effective for the period commencing on the next Redetermination Date.
Section 3.02. Scheduled Redeterminations of the Borrowing Base; Procedures and
Standards. Based on the Reserve Reports made available to the Administrative Agent and the
Lenders pursuant to Section 3.01, the requisite Lenders shall redetermine the Borrowing Base on or
prior to the next Redetermination Date (or such date promptly thereafter as reasonably possible
based on the engineering and other information available to the Lenders) in accordance with this
Section 3.02. Any Borrowing Base which becomes effective as a result of any Redetermination shall
be subject to the following restrictions: (a) such Borrowing Base shall not exceed the Maximum
Facility Amount, (b) to the extent such Borrowing Base represents an increase in the Borrowing Base
in effect prior to such Redetermination, such Borrowing Base must be approved by all Lenders, and
(c) to the extent such Borrowing Base represents a reaffirmation or decrease in the Borrowing Base
in effect prior to such Redetermination or a reaffirmation of such prior Borrowing Base, such
Borrowing Base must be approved by the Administrative Agent and Super Majority Lenders. If a
redetermined Borrowing Base is not approved by the Administrative Agent and Super Majority Lenders
within twenty (20) days after the submission to the Lenders by the Administrative Agent of its
recommended Borrowing Base pursuant to Section 3.01, or by all Lenders within such twenty (20) day
period in the case of any increase in the Borrowing Base, the Administrative Agent shall notify
each Lender that the recommended Borrowing Base has not been approved and request that each Lender
submit to the Administrative Agent within ten (10) days thereafter its proposed Borrowing Base.
Promptly following the 10th day after the Administrative Agent’s request for each
Lender’s proposed Borrowing Base, the Administrative Agent shall determine the Borrowing Base for
such Redetermination by calculating the highest Borrowing Base then acceptable to the
Administrative Agent and a number of Lenders sufficient to constitute Super Majority Lenders (or
all Lenders in the case of an increase in the Borrowing Base). The Borrower acknowledges and
agrees that each Redetermination shall be based upon the loan collateral value which the
Administrative Agent and each Lender in its sole discretion (using such methodology, assumptions
and discount rates as the Administrative Agent and such Lender customarily uses in assigning
collateral value to Oil and Gas Interests) assigns to the Borrowing Base Properties at the time in
question and based upon such other credit factors consistently applied (including, without
limitation, the assets, liabilities, cash flow, business, properties, prospects, management
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 46
and ownership of the Credit Parties) as the Administrative Agent and such Lender customarily
considers in evaluating similar oil and gas credits, including adjustments to reflect the effect of
any Swap Agreements of the Borrower and the Restricted Subsidiaries as such exist at the time of
such Redetermination. It is expressly understood that the Administrative Agent and Lenders have no
obligation to designate the Borrowing Base at any particular amount, except in the exercise of
their discretion, whether in relation to the Aggregate Commitment or otherwise. If the Borrower
does not furnish all information, reports and data required to be delivered by any date specified
in this Article III, unless such failure is not the fault of the Borrower, the Administrative Agent
and Lenders may nonetheless designate the Borrowing Base at any amounts which the Administrative
Agent and Lenders in their reasonable discretion determine and may redesignate the Borrowing Base
from time to time thereafter until the Administrative Agent and Lenders receive all such
information, reports and data, whereupon the Administrative Agent and Lenders shall designate a new
Borrowing Base, as described above.
Section 3.03. Special Redeterminations. The Borrower shall be permitted to request a
Special Redetermination of the Borrowing Base once between each Scheduled Redetermination and the
Required Lenders shall be permitted to request a Special Redetermination twice between each
Scheduled Redetermination. Any request by Borrower pursuant to this Section 3.03 shall be
submitted to the Administrative Agent and each Lender and at the time of such request (or within
twenty (20) days thereafter in the case of the Reserve Report) Borrower shall (1) deliver to the
Administrative Agent and each Lender a Reserve Report prepared as of a date prior to the date of
such request that is reasonably acceptable to the Administrative Agent and such other information
which the Administrative Agent shall reasonably request, and (2) notify the Administrative Agent
and each Lender of the Borrowing Base requested by Borrower in connection with such Special
Redetermination. Any request by Required Lenders for a Special Redetermination pursuant to this
Section 3.03 shall be submitted to the Administrative Agent and the Borrower. In addition to the
Scheduled Redeterminations and requested Special Redeterminations, there shall be a Redetermination
of the Borrowing Base at such time as the Borrower or any Restricted Subsidiary sells, transfers,
leases, exchanges, abandons or otherwise disposes of Borrowing Base Properties in accordance with
clauses (vi) and (vii) of Section 7.03(a). Any Special Redetermination shall be made by the
Administrative Agent and Lenders in accordance with the procedures and standards set forth in
Section 3.02; provided that no Reserve Report is required to be delivered to the
Administrative Agent or the Lenders in connection with any Special Redetermination requested by the
Required Lenders pursuant to this Section 3.03.
Section 3.04. Notice of Redetermination. Promptly following any Redetermination of
the Borrowing Base, the Administrative Agent shall notify the Borrower of the amount of the
redetermined Borrowing Base, which Borrowing Base shall be effective as of the date specified in
such notice, and such Borrowing Base shall remain in effect for all purposes of this Agreement
until the next Redetermination.
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Article IV
Representations and Warranties
Each Credit Party represents and warrants to the Lenders that: (it being understood and agreed
that with respect to the Effective Date such representations and warranties are deemed to be made
concurrently with and after giving effect to the consummation of the Transactions):
Section 4.01. Organization; Powers. Each Credit Party is duly organized, validly
existing and in good standing under the laws of the jurisdiction of its organization, has all
requisite power and authority to carry on its business as now conducted and, except where the
failure to do so, individually or in the aggregate, could not reasonably be expected to result in a
Material Adverse Effect, is qualified to do business in, and is in good standing in, every
jurisdiction where such qualification is required.
Section 4.02. Authorization; Enforceability. The Transactions are within each Credit
Party’s corporate, limited liability company or partnership powers and have been duly authorized by
all necessary corporate, limited liability company or partnership and, if required, stockholder
action. This Agreement has been duly executed and delivered by each Credit Party and constitutes a
legal, valid and binding obligation of each Credit Party, enforceable in accordance with its terms,
subject to applicable bankruptcy, insolvency, reorganization, moratorium or other laws affecting
creditors’ rights generally and subject to general principles of equity, regardless of whether
considered in a proceeding in equity or at law.
Section 4.03. Governmental Approvals; No Conflicts. The Transactions (a) do not
require any consent or approval of, registration or filing with, or any other action by, any
Governmental Authority, except such as have been obtained or made and are in full force and effect
and, after the Effective Date, any required filings with the Securities and Exchange Commission,
(b) will not violate any applicable law or regulation or the charter, by-laws or other
Organizational Documents of the Borrower or any Restricted Subsidiary or any order of any
Governmental Authority, (c) will not violate or result in a default under any indenture, agreement
or other instrument evidencing Material Indebtedness binding upon the Borrower or any Restricted
Subsidiary or any of their respective assets, or give rise to a right thereunder to require any
payment to be made by the Borrower or any Restricted Subsidiary, and (d) will not result in the
creation or imposition of any Lien on any asset of the Borrower or any Restricted Subsidiary not
otherwise permitted under Section 7.02.
Section 4.04. Financial Condition; No Material Adverse Change.
(a) The Borrower has heretofore furnished to the Lenders the unaudited consolidated balance
sheet and related statements of income and cash flows of the Borrower and its Consolidated
Subsidiaries as of and for the six (6) month period ended June 30, 2006 certified by a Responsible
Officer. Such financial statements present fairly, in all material respects, the financial
position and results of operations and cash flows of the Borrower and its Consolidated Subsidiaries
as of such dates and for such periods in accordance with GAAP, subject to year-end audit
adjustments and reclassifications and the absence of footnotes.
(b) Since June 30, 2006, there has been no material adverse change in the business, assets,
operations or financial condition of the Borrower and its Subsidiaries, taken as a whole (it
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being understood that changes in commodity prices for Hydrocarbons affecting the oil and gas
industry as a whole shall not constitute a material adverse change).
Section 4.05. Properties.
(a) Except as otherwise provided in Section 4.15 with respect to Oil and Gas Interests, the
Borrower and each Restricted Subsidiary has good title to, or valid leasehold interests in, all
such real and personal property material to its business, except for minor defects in title that do
not interfere with its ability to conduct its business as currently conducted or to utilize such
properties for their intended purposes.
(b) The Borrower and each Restricted Subsidiary owns, or is licensed to use, all trademarks,
tradenames, copyrights, patents and other intellectual property material to its business, and the
use thereof by the Borrower and such Restricted Subsidiaries, as the case may be, does not infringe
upon the rights of any other Person, except for any such infringements that, individually or in the
aggregate, could not reasonably be expected to result in a Material Adverse Effect.
Section 4.06. Litigation and Environmental Matters.
(a) There are no actions, suits or proceedings by or before any arbitrator or Governmental
Authority pending against or, to the knowledge of the Borrower, threatened against or affecting the
Borrower or any Restricted Subsidiary, (i) as to which there is a reasonable possibility of an
adverse determination and that, if adversely determined, could reasonably be expected, individually
or in the aggregate, to result in a Material Adverse Effect (other than the Disclosed Matters) or
(ii) that involve this Agreement or the Transactions.
(b) Except for the Disclosed Matters and except with respect to any other matters that,
individually or in the aggregate, could not reasonably be expected to result in a Material Adverse
Effect, neither the Borrower nor any Restricted Subsidiary to the Borrower’s knowledge (i) has
failed to comply with any Environmental Law or to obtain, maintain or comply with any permit,
license or other approval required under any Environmental Law, (ii) has become subject to any
Environmental Liability, (iii) has received notice of any claim with respect to any Environmental
Liability or (iv) knows of any basis for any Environmental Liability.
(c) Since the date of this Agreement, there has been no change in the status of the Disclosed
Matters that, individually or in the aggregate, could reasonably be expected to have Material
Adverse Effect.
Section 4.07. Compliance with Laws and Agreements. The Borrower and each Restricted
Subsidiary is in compliance with all laws, regulations and orders of any Governmental Authority
applicable to it or its property and all indentures, agreements and other instruments binding upon
it or its property, except where the failure to do so, individually or in the aggregate, could not
reasonably be expected to result in a Material Adverse Effect. No Default has occurred and is
continuing.
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Section 4.08. Investment Company Status. Neither the Borrower nor any Restricted
Subsidiary is an “investment company” as defined in, or subject to regulation under, the Investment
Company Act of 1940.
Section 4.09. Taxes. The Borrower and each Restricted Subsidiary has timely filed or
caused to be filed all Tax returns and reports required to have been filed and has paid or caused
to be paid all Taxes required to have been paid by it, except (a) Taxes that are being contested in
good faith by appropriate proceedings and for which the Borrower or such Restricted Subsidiary, as
applicable, has set aside on its books adequate reserves or (b) to the extent that the failure to
do so could not reasonably be expected to result in a Material Adverse Effect.
Section 4.10. ERISA. No ERISA Event has occurred or is reasonably expected to occur
that, when taken together with all other such ERISA Events for which liability is reasonably
expected to occur, could reasonably be expected to result in a Material Adverse Effect. The
present value of all accumulated benefit obligations under each Plan (based on the assumptions used
for purposes of FASB Statement 87) did not, as of the date of the most recent financial statements
reflecting such amounts, exceed by more than $5,000,000 the fair market value of the assets of such
Plan, and the present value of all accumulated benefit obligations of all underfunded Plans (based
on the assumptions used for purposes of FASB Statement 87) did not, as of the date of the most
recent financial statements reflecting such amounts, exceed by more than $5,000,000 the fair market
value of the assets of all such underfunded Plans.
Section 4.11. Disclosure. The Borrower has disclosed to the Lenders all agreements,
instruments and corporate or other restrictions to which it or any Restricted Subsidiary is
subject, and all other matters known to it, that, individually or in the aggregate, could
reasonably be expected to result in a Material Adverse Effect. None of the other reports,
financial statements, certificates or other information furnished by or on behalf of the Borrower
or any Restricted Subsidiary to the Administrative Agent or any Lender in connection with the
negotiation of this Agreement or delivered hereunder (as modified or supplemented by other
information so furnished) contains any material misstatement of fact or omits to state any material
fact necessary to make the statements therein, in the light of the circumstances under which they
were made, not misleading; provided that, with respect to the Projections, the Borrower
represents only that such information was prepared in good faith based on assumptions believed to
be reasonable at the time.
Section 4.12. Labor Matters. There are no strikes, lockouts or slowdowns against the
Borrower or any of its Restricted Subsidiaries pending or, to the knowledge of the Borrower,
threatened that could reasonably be expected to have a Material Adverse Effect. The hours worked
by and payments made to employees of the Borrower and its Restricted Subsidiaries have not been in
violation of the Fair Labor Standards Act or any other Law dealing with such matters to the extent
that such violation could reasonably be expected to have a Material Adverse Effect.
Section 4.13. Capitalization and Credit Party Information. Schedule 4.13 lists, as of
the Effective Date (a) each Subsidiary that is an Unrestricted Subsidiary, (b) for the Borrower,
its full legal name, its jurisdiction of organization and its federal tax identification number,
and (c)
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for each Restricted Subsidiary its full legal name, its jurisdiction of organization, its
federal tax identification number, the number of shares of capital stock or other Equity Interests
outstanding and the owner(s) of such Equity Interests.
Section 4.14. Margin Stock. Neither the Borrower nor any Restricted Subsidiary is
engaged principally, or as one of its important activities, in the business of extending credit for
the purpose of purchasing or carrying margin stock (within the meaning of Regulation U issued by
the Board), and no part of the proceeds of any Loan will be used to purchase or carry any margin
stock or to extend credit to others for the purpose of purchasing or carrying margin stock except
in compliance with applicable law.
Section 4.15. Oil and Gas Interests. Each Credit Party has, in all material respects,
good and defensible title to all proved reserves included in the Oil and Gas Interests (for
purposes of this Section 4.15, “proved Oil and Gas Interests”) described in the most recent Reserve
Report provided to the Administrative Agent, free and clear of all Liens except Liens permitted
pursuant to Section 7.02. All such proved Oil and Gas Interests are valid, subsisting, and in full
force and effect, in all material respects, and all rentals, royalties, and other amounts due and
payable in respect thereof have, in all material respects, been duly paid or if not duly paid, are
being contested in good faith in the ordinary course of business. Without regard to any consent or
non-consent provisions of any joint operating agreement covering any Credit Party’s proved Oil and
Gas Interests, such Credit Party’s share of (a) the costs for each proved Oil and Gas Interest
described in the Reserve Report is not materially greater than the decimal fraction set forth in
the Reserve Report, before and after payout, as the case may be, and described therein by the
respective designations “working interests,” “WI,” “gross working interest,” “GWI,” or similar
terms (except in such cases where there is a corresponding increase in the net revenue interest),
and (b) production from, allocated to, or attributed to each such proved Oil and Gas Interest is
not materially less than the decimal fraction set forth in the Reserve Report, before and after
payout, as the case may be, and described therein by the designations “net revenue interest,”
“NRI,” or similar terms. Each well drilled in respect of proved producing Oil and Gas Interests
described in the Reserve Report (i) is capable of, and is presently, either producing Hydrocarbons
in commercially profitable quantities or in the process of being worked over or enhanced, and the
Credit Party that owns such proved producing Oil and Gas Interests is currently receiving payments
for its share of production, with no funds in respect of any thereof being presently held in
suspense, other than any such funds being held in suspense pending delivery of appropriate division
orders, and (ii) has been drilled, bottomed, completed, and operated in compliance with all
applicable laws, in the case of clauses (i) and (ii), except where any failure to satisfy clause
(i) or to comply with clause (ii) could not reasonably be expected to have a Material Adverse
Effect, and no such well which is currently producing Hydrocarbons is subject to any penalty in
production by reason of such well having produced in excess of its allowable production that could
reasonably be expected to have a Material Adverse Effect.
Section 4.16. Insurance. All insurance reasonably necessary in the Credit Parties’
ordinary course of business is in effect and all premiums due on such insurance have been paid.
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Section 4.17. Solvency.
(a) Immediately after the consummation of the Transactions and immediately following the
making of the initial Borrowing made on the Effective Date and after giving effect to the
application of the proceeds thereof, (i) the fair value of the assets of the Credit Parties on a
consolidated basis, at a fair valuation, will exceed the debts and liabilities, subordinated,
contingent or otherwise, of the Credit Parties on a consolidated basis; (ii) the present fair
saleable value of the real and personal property of the Credit Parties on a consolidated basis will
be greater than the amount that will be required to pay the probable liability of the Credit
Parties on a consolidated basis on their debts and other liabilities, subordinated, contingent or
otherwise, as such debts and other liabilities become absolute and matured; (iii) the Credit
Parties on a consolidated basis will be able to pay their debts and liabilities, subordinated,
contingent or otherwise, as such debts and liabilities become absolute and matured; and (iv) the
Credit Parties on a consolidated basis will not have unreasonably small capital with which to
conduct the businesses in which they are engaged as such businesses are now conducted and are
proposed to be conducted after the date hereof.
(b) The Credit Parties do not intend to, and do not believe that they will, incur debts beyond
their ability to pay such debts as they mature, taking into account the timing of and amounts of
cash to be received by it and the timing of the amounts of cash to be payable on or in respect of
its Indebtedness.
Article V
Conditions
Section 5.01. Effective Date. The obligations of the Lenders to continue the Original
Loans and the obligations of the Lenders to make Loans and of the Issuing Bank to continue any
Letters of Credit outstanding under the Original Credit Agreement and to issue Letters of Credit
hereunder shall not become effective until the date on which each of the following conditions is
satisfied (or waived in accordance with Section 11.02):
(a) The Administrative Agent (or its counsel) shall have received from each party hereto
either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence
satisfactory to the Administrative Agent (which may include telecopy transmission of a signed
signature page of this Agreement) that such party has signed a counterpart of this Agreement.
(b) The Administrative Agent shall have received a favorable written opinion (addressed to the
Administrative Agent and the Lenders and dated the Effective Date) of Vinson & Elkins LLP, counsel
for the Credit Parties, substantially in the form of Exhibit B, and covering such other matters
relating to the Credit Parties, this Agreement or the Transactions as the Required Lenders shall
reasonably request. The Credit Parties hereby request such counsel to deliver such opinion.
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(c) The Administrative Agent shall have received such documents and certificates as the
Administrative Agent or its counsel may reasonably request relating to the organization, existence
and good standing of each Credit Party, the authorization of the Transactions and any other legal
matters relating to the Credit Parties, this Agreement or the Transactions, all in form and
substance satisfactory to the Administrative Agent and its counsel.
(d) The Administrative Agent shall have received a certificate, dated the Effective Date and
signed by a Responsible Officer of the Borrower, confirming that (i) the Credit Parties have (1)
complied with the conditions set forth in paragraphs (a) and (b) of Section 5.02 and (2) complied
with the requirements of Section 6.09 and (ii) after giving effect to the Transactions, the
Obligations constitute “Senior Debt” (as such term is defined in the Indenture) permitted to be
incurred under the terms of the Indenture and accompanied by reasonably detailed calculations
demonstrating compliance with Section 4.09(c) of the Indenture.
(e) The Administrative Agent, the Lenders and the Arranger shall have received all fees and
other amounts due and payable on or prior to the Effective Date, and, to the extent invoiced,
reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the
Borrower hereunder, including all fees, expenses and disbursements of counsel for the
Administrative Agent to the extent invoiced on or prior to the Effective Date.
(f) The Administrative Agent shall have received the Mortgages to be executed on the Effective
Date pursuant to Section 6.09 of this Agreement, duly executed and delivered by the appropriate
Credit Party, together with such other assignments, conveyances, amendments, agreements and other
writings, including, without limitation, UCC-1 financing statements, tax affidavits and applicable
department of revenue documentation, creating a Lien prior and superior in right to any other
Person, subject to Permitted Encumbrances, in Borrowing Base Properties having an Engineered Value
equal to or greater than 135% of the Aggregate Commitment; provided that the Engineered Value of
the Virginia Borrowing Base Properties do not exceed fifty percent (50%) of such Engineered Value.
(g) On or prior to the Effective Date, the Administrative Agent shall have received a
Borrowing Request acceptable to the Administrative Agent setting forth the Loans requested by the
Borrower on the Effective Date, the Type and amount of each Loan and the accounts to which such
Loans are to be funded; provided that all Borrowings on the Effective Date shall be ABR
Borrowings (it being understood that some LIBOR Loans (as defined in the Original Credit Agreement)
outstanding as the Effective Date shall continue as a Eurodollar Loan under this Agreement on the
Effective Date for the Interest Period applicable thereto and other LIBOR Loans may be terminated
on the Effective Date in connection with the changes in the Commitments and certain funding
indemnification obligations incurred by the Borrower and GLEP under the Original Credit Agreement
as a result of such terminations shall be paid by the Borrower on the Effective Date).
(h) Each Credit Party shall have obtained all approvals required from any Governmental
Authority and all consents of other Persons, in each case that are necessary or advisable in
connection with the Transactions and each of the foregoing shall be in full force and effect and in
form and substance reasonably satisfactory to the Administrative Agent. All
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applicable waiting periods, if any, shall have expired without any action being taken or
threatened by any competent authority which would restrain, prevent or otherwise impose adverse
conditions on the transactions contemplated by the Loan Documents or the financing thereof and no
action, request for stay, petition for review or rehearing, reconsideration, or appeal with respect
to any of the foregoing shall be pending, and the time for any applicable agency to take action to
set aside its consent on its own motion shall have expired.
(i) There shall not exist any action, suit, investigation, litigation or proceeding or other
legal or regulatory developments, pending or threatened in any court or before any arbitrator or
Governmental Authority that, in the reasonable opinion of Administrative Agent, singly or in the
aggregate, materially impairs the Transactions, the financing thereof or any of the other
transactions contemplated by the Loan Documents or that could reasonably be expected to have a
Material Adverse Effect.
The Administrative Agent shall notify the Borrower and the Lenders of the Effective Date, and such
notice shall be conclusive and binding. Notwithstanding the foregoing, the obligations of the
Lenders to make Loans and of the Issuing Bank to issue Letters of Credit hereunder shall not become
effective unless each of the foregoing conditions is satisfied (or waived pursuant to Section
11.02) at or prior to 3:00 p.m. on October 31, 2006 (and, in the event such conditions are not so
satisfied or waived, the Aggregate Commitment shall terminate at such time).
Section 5.02. Each Credit Event. The obligation of each Lender to make a Loan on the
occasion of any Borrowing, and of the Issuing Bank to issue, amend, renew or extend any Letter of
Credit, is subject to the satisfaction of the following conditions:
(a) The representations and warranties of each Credit Party set forth in the Loan Documents
shall be true and correct in all material respects on and as of the date of such Borrowing or the
date of issuance, amendment, renewal or extension of such Letter of Credit, as applicable except to
the extent that such representations and warranties specifically refer to an earlier date, in which
case they shall be true and correct as of such earlier date.
(b) At the time of and immediately after giving effect to such Borrowing or the issuance,
amendment, renewal or extension of such Letter of Credit, as applicable, no Default shall have
occurred and be continuing.
(c) At the time of and immediately after giving effect to such Borrowing or the issuance,
amendment, renewal or extension of such Letter of Credit, as applicable, no Borrowing Base
Deficiency exists or would be caused thereby.
Each Borrowing and each issuance, amendment, renewal or extension of a Letter of Credit shall be
deemed to constitute a representation and warranty by the Borrower on the date thereof as to the
matters specified in paragraphs (a), (b) and (c) of this Section 5.02.
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Article VI
Affirmative Covenants
Until the Aggregate Commitment has expired or been terminated and the principal of and
interest on each Loan and all fees payable hereunder shall have been paid in full and all Letters
of Credit shall have expired or terminated and all LC Disbursements shall have been reimbursed,
each Credit Party covenants and agrees with the Lenders that:
Section 6.01. Financial Statements; Other Information. The Borrower will furnish to
the Administrative Agent and each Lender:
(a) within 90 days after the end of each fiscal year of the Borrower, the audited consolidated
(and unaudited consolidating) balance sheet and related consolidated (and with respect to
statements of operations, consolidating) statements of operations, stockholders’ equity and cash
flows of the Borrower and its Consolidated Subsidiaries as of the end of and for such year, setting
forth in each case in comparative form the figures for the previous fiscal year, all reported on by
a firm of independent public accountants reasonably acceptable to Administrative Agent (without a
“going concern” or like qualification or exception and without any qualification or exception as to
the scope of such audit) to the effect that such consolidated financial statements present fairly
in all material respects the financial condition and results of operations of the Borrower and its
Consolidated Subsidiaries on a consolidated basis in accordance with GAAP consistently applied;
(b) within 45 days after the end of each of the first three fiscal quarter of the Borrower and
within 60 days after the end of the last fiscal quarter of the Borrower, the consolidated (and
consolidating) balance sheet and related consolidated (and with respect to statements of
operations, consolidating) statements of operations and cash flows of the Borrower and its
Consolidated Subsidiaries as of the end of and for such fiscal quarter and the then elapsed portion
of the fiscal year, setting forth in each case in comparative form the figures for the
corresponding period or periods of (or, in the case of the balance sheet, as of the end of) the
previous fiscal year, all certified by a Responsible Officer as presenting fairly in all material
respects the financial condition and results of operations of the Borrower and its Consolidated
Subsidiaries on a consolidated basis in accordance with GAAP consistently applied, subject to
normal year-end audit adjustments, reclassifications, and the absence of footnotes;
(c) concurrently with any delivery of financial statements under clause (a) or (b) above, a
certificate in a form reasonably acceptable to Administrative Agent signed by a Responsible Officer
of the Borrower (i) certifying as to whether a Default has occurred and, if a Default has occurred,
specifying the details thereof and any action taken or proposed to be taken with respect thereto,
and (ii) setting forth reasonably detailed calculations demonstrating compliance with Section 7.11;
(d) as soon as available, and in any event no later than March 1 and September 1 of each year,
the Reserve Reports required on such dates pursuant to Section 3.01;
(e) together with the Reserve Reports required under clause (d) above, a report, in reasonable
detail, setting forth the Swap Agreements then in effect, the notional volumes of and prices for,
on a monthly basis and in the aggregate, the Crude Oil and Natural Gas for each such Swap Agreement
and the term of each such Swap Agreement; and together with the Reserve
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Report required no later than March 1 under clause (d) above, (i) a true and correct schedule
of the Mortgaged Properties, (ii) the percentage of the Aggregate Commitment that the Engineered
Value of the Mortgaged Properties represents and (iii) a description of the additional Oil and Gas
Interests, if any, to be mortgaged by the Credit Parties to comply with Section 6.09;
(f) promptly following any request therefor, such other information regarding the operations,
business affairs and financial condition of any Credit Party, or compliance with the terms of this
Agreement, as the Administrative Agent or any Lender may reasonably request including any
management letter or comparable analysis prepared by the auditors for and received by any Credit
Party.
Documents required to be delivered pursuant to Section 6.01(a) or Section 6.01(b) or Section 6.02
may be delivered electronically and if so delivered, shall be deemed to have been delivered on the
date (i) on which the Borrower (or the Administrative Agent on behalf of Borrower and at Borrower’s
request) posts such documents, or provides a link thereto on the Borrower’s website on the Internet
at the website address identified in Section 11.01 on which such documents are posted on the
Borrower’s behalf on an Internet or intranet website, if any, to which each Lender and the
Administrative Agent have access (whether a commercial, third-party website or whether sponsored by
the Administrative Agent); provided that: (i) the Borrower shall deliver paper copies of
such documents to the Administrative Agent or any Lender that requests the Borrower to deliver such
paper copies until a written request to cease delivering paper copies is given by the
Administrative Agent or such Lender and (ii) the Borrower shall notify the Administrative Agent (by
telecopier or electronic mail) of the posting of any such documents and provide to the
Administrative Agent by electronic mail electronic versions (i.e., soft copies) of such
documents. Notwithstanding anything contained herein, in every instance the Borrower shall be
required to provide paper copies of the Compliance Certificates required by Section 6.01(c) to the
Administrative Agent. Except for such Compliance Certificates, the Administrative Agent shall have
no obligation to request the delivery or to maintain copies of the documents referred to above, and
in any event shall have no responsibility to monitor compliance by the Borrower with any such
request for delivery, and each Lender shall be solely responsible for requesting delivery to it or
maintaining its copies of such documents.
The Borrower hereby acknowledges that (a) the Administrative Agent and/or the Arranger will
make available to the Lenders and the Issuing Bank materials and/or information provided by or on
behalf of the Borrower hereunder (collectively, “Borrower Materials”) by posting the
Borrower Materials on IntraLinks or another similar electronic system (the “Platform”) and
(b) certain of the Lenders may be “public-side” Lenders (i.e., Lenders that do not wish to receive
material non-public information with respect to the Borrower or its securities) (each, a
“Public Lender”). The Borrower hereby agrees that (w) all Borrower Materials that are to
be made available to Public Lenders shall be clearly and conspicuously marked “PUBLIC” which, at a
minimum, shall mean that the word “PUBLIC” shall appear prominently on the first page thereof; (x)
by marking Borrower Materials “PUBLIC,” the Borrower shall be deemed to have authorized the
Administrative Agent, the Arranger, the Issuing Bank and the Lenders to treat such Borrower
Materials as either publicly available information or not material information (although it may be
sensitive and proprietary) with respect to the Borrower or its securities for purposes of United
States Federal and state securities laws; (y) all Borrower
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Materials marked “PUBLIC” are permitted to be made available through a portion of the Platform
designated “Public Investor;” and (z) the Administrative Agent and the Arranger shall be entitled
to treat Borrower’s Materials that are not marked “PUBLIC” as being suitable only for posting on a
portion of the Platform not designated “Public Investor.”
Section 6.02. Notices of Material Events. The Borrower will furnish to the
Administrative Agent and each Lender, which delivery may be electronic to the extent permitted in
Section 6.01, prompt written notice of the following:
(a) the occurrence of any Default;
(b) the filing or commencement of any action, suit or proceeding by or before any arbitrator
or Governmental Authority against or affecting any Credit Party or any Affiliate thereof that, if
adversely determined, could reasonably be expected to result in a Material Adverse Effect;
(c) the occurrence of any ERISA Event that, alone or together with any other ERISA Events that
have occurred, could reasonably be expected to result in liability of the Borrower and the
Restricted Subsidiaries in an aggregate amount exceeding $5,000,000;
(d) any written notice or written claim to the effect that any Credit Party is or may be
liable to any Person as a result of the release by any Credit Party, or any other Person of any
Hazardous Materials into the environment, which could reasonably be expected to have a Material
Adverse Effect;
(e) any written notice alleging any violation of any Environmental Law by any Credit Party,
which could reasonably be expected to have a Material Adverse Effect; and
(f) any other development that results in, or could reasonably be expected to result in, a
Material Adverse Effect.
Each notice delivered under this Section shall be accompanied by a statement of a Responsible
Officer or other executive officer of the Borrower setting forth the details of the event or
development requiring such notice and any action taken or proposed to be taken with respect
thereto.
Section 6.03. Existence; Conduct of Business. The Borrower will, and will cause each
Restricted Subsidiary to, do or cause to be done all things necessary to preserve, renew and keep
in full force and effect its legal existence and the rights, licenses, permits, privileges and
franchises material to the conduct of its business; provided that the foregoing shall not
prohibit any merger, consolidation, liquidation or dissolution permitted under Section 7.03.
Section 6.04. Payment of Obligations. The Borrower will, and will cause each
Restricted Subsidiary to, pay its obligations, including Tax liabilities, that, if not paid, could
result in a Material Adverse Effect before the same shall become delinquent or in default, except
where (a) the validity or amount thereof is being contested in good faith by appropriate
proceedings, (b) the Borrower or such Restricted Subsidiary has set aside on its books adequate
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 57
reserves with respect thereto in accordance with GAAP and (c) the failure to make payment
pending such contest could not reasonably be expected to result in a Material Adverse Effect.
Section 6.05. Maintenance of Properties; Insurance. The Borrower will, and will cause
each Restricted Subsidiary to, (a) keep and maintain all property material to the conduct of its
business in good working order and condition, ordinary wear and tear excepted, and (b) maintain,
with financially sound and reputable insurance companies, insurance in such amounts and against
such risks as are customarily maintained by companies engaged in the same or similar businesses
operating in the same or similar locations. Upon request of the Administrative Agent, the Borrower
will furnish or cause to be furnished to the Administrative Agent from time to time a summary of
the respective insurance coverage of the Borrower and its Restricted Subsidiaries in form and
substance reasonably satisfactory to the Administrative Agent, and, if requested, will furnish the
Administrative Agent copies of the applicable policies. Upon demand by Administrative Agent, the
Borrower will cause any insurance policies covering any such property to be endorsed (i) to provide
that such policies may not be cancelled, reduced or affected in any manner for any reason without
fifteen (15) days prior notice to Administrative Agent, and (ii) to provide for such other matters
as the Lenders may reasonably require.
Section 6.06. Books and Records; Inspection Rights. The Borrower will, and will cause
each Restricted Subsidiary to, keep proper books of record and account in which full, true and
correct entries are made of all dealings and transactions in relation to its business and
activities. The Borrower will, and will cause each Restricted Subsidiary to, permit any
representatives designated by the Administrative Agent or any Lender, upon reasonable prior notice,
to visit and inspect its properties, to examine and make extracts from its books and records, and
to discuss its affairs, finances and condition with its officers and, provided an officer of the
Borrower has the reasonable opportunity to participate, its independent accountants, all at such
reasonable times and as often as reasonably requested.
Section 6.07. Compliance with Laws. The Borrower will, and will cause each Restricted
Subsidiary to, comply with all laws, rules, regulations and orders of any Governmental Authority
applicable to it or its property, except where the failure to do so, individually or in the
aggregate, could not reasonably be expected to result in a Material Adverse Effect.
Section 6.08. Use of Proceeds and Letters of Credit. The proceeds of the Loans will
be used only to (a) pay the fees, expenses and transaction costs of the Transactions, (b) to
satisfy reimbursement obligations with respect to Letters of Credit, (c) to make Restricted
Payments permitted by Section 7.06(d), (d) to make investments permitted by Section 7.04 and (e)
finance the working capital needs of the Borrower, including capital expenditures, and for general
corporate purposes of the Borrower and the Guarantors, in the ordinary course of business,
including the exploration, acquisition and development of Oil and Gas Interests. No part of the
proceeds of any Loan will be used, whether directly or indirectly, to purchase or carry any margin
stock (as defined in Regulation U issued by the Board) except in accordance with applicable law.
Letters of Credit will be issued only to support general corporate purposes of the Borrower and the
Restricted Subsidiaries.
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Section 6.09. Mortgages. Each Borrower will, and will cause each Guarantor to,
execute and deliver to the Administrative Agent, for the benefit of the Secured Parties, Mortgages
in form and substance acceptable to the Administrative Agent together with such other assignments,
conveyances, amendments, agreements and other writings, including, without limitation, UCC-1
financing statements (each duly authorized and executed, as applicable) as the Administrative Agent
shall deem necessary or appropriate to grant, evidence, perfect and maintain Liens in Borrowing
Base Properties having an Engineered Value equal to or greater than 135% of the Aggregate
Commitment provided that the Engineered Value of the Virginia Borrowing Base Properties do not
exceed fifty percent (50%) of such Engineered Value.
Section 6.10. Title Data. The Borrower will, and will cause each Guarantor to,
deliver to the Administrative Agent such evidence of title as the Administrative Agent shall deem
reasonably necessary or appropriate to verify (a) the ownership of (i) at all times, eighty percent
(80%) of the Engineered Value of the Mortgaged Properties of the Borrower and the Guarantors (other
than the Appalachia Properties) taken as a whole and (ii) as of the Effective Date, nineteen
percent (19%), and at all times after December 31, 2006, thirty percent (30%), of the Engineered
Value of that portion of the Mortgaged Properties that are Appalachia Properties, taken as a whole
and (b) the validity, perfection and priority of the Liens created by such Mortgages and such other
matters regarding such Mortgages as Administrative Agent shall reasonably request.
Section 6.11. Swap Agreements. The Borrower will, and will cause each Restricted
Subsidiary to, maintain the Existing Swap Agreements and none of the Existing Swap Agreements may
be materially amended, modified or cancelled by any Borrower or any Restricted Subsidiary unless
the Borrower, or such Restricted Subsidiary, as the case may be, provides written notice thereof to
the Administrative Agent within three (3) Business Days after such amendment, modification or
cancellation, as the case may be. Upon the request of the Required Lenders, the Borrower and each
Restricted Subsidiary shall use their commercially reasonable efforts to cause each Swap Agreement
to which the Borrower or any Restricted Subsidiary is a party to (a) expressly permit such
assignment and (b) upon the occurrence of any default or event of default under such agreement or
contract, (i) to permit the Lenders to cure such default or event of default and assume the
obligations of such Credit Party under such agreement or contract and (ii) to prohibit the
termination of such agreement or contract by the counterparty thereto if the Lenders assume the
obligations of such Credit Party under such agreement or contract and the Lenders take the actions
required under the foregoing clause (i). Upon the request of the Administrative Agent, the
Borrower shall, within thirty (30) days of such request, provide to the Administrative Agent and
each Lender copies of all agreements, documents and instruments evidencing the Swap Agreements not
previously delivered to the Administrative Agent and Lenders, certified as true and correct by a
Responsible Officer of the Borrower, and such other information regarding such Swap Agreements as
the Administrative Agent and Lenders may reasonably request.
Section 6.12. Operation of Oil and Gas Interests.
(a) Each Borrower will, and will cause each Restricted Subsidiary to, maintain, develop and
operate its Oil and Gas Interests in a good and workmanlike manner, and observe and comply with all
of the terms and provisions, express or implied, of all oil and gas leases
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relating to such Oil and Gas Interests so long as such Oil and Gas Interests are capable of
producing Hydrocarbons and accompanying elements in paying quantities, except where such failure to
comply could not reasonably be expected to have a Material Adverse Effect.
(b) Borrower will, and will cause each Restricted Subsidiary to, comply in all respects with
all contracts and agreements applicable to or relating to its Oil and Gas Interests or the
production and sale of Hydrocarbons and accompanying elements therefrom, except to the extent a
failure to so comply could not reasonably be expected to have a Material Adverse Effect.
Section 6.13. Restricted Subsidiaries. In the event any Person is or becomes a
Restricted Subsidiary, Borrower will (a) promptly take all action necessary to comply with Section
6.14, (b) promptly take all such action and execute and deliver, or cause to be executed and
delivered, to the Administrative Agent all such documents, opinions, instruments, agreements, and
certificates similar to those described in Section 5.01(b) and Section 5.01(c) that the
Administrative Agent may reasonably request, and (c) promptly cause such Restricted Subsidiary to
(i) become a party to this Agreement and Guarantee the Obligations by executing and delivering to
the Administrative Agent a Counterpart Agreement in the form of Exhibit C, and (ii) to the extent
required to comply with Section 6.09 or as requested by the Administrative Agent, execute and
deliver Mortgages and other Security Instruments creating a Lien prior and superior in right to any
other Person, subject to Permitted Encumbrances, in such Restricted Subsidiary’s Oil and Gas
Interests and other assets. Upon delivery of any such Counterpart Agreement to the Administrative
Agent, notice of which is hereby waived by each Credit Party, such Restricted Subsidiary shall be a
Guarantor and shall be as fully a party hereto as if such Restricted Subsidiary were an original
signatory hereto. Each Credit Party expressly agrees that its obligations arising hereunder shall
not be affected or diminished by the addition or release of any other Credit Party hereunder. This
Agreement shall be fully effective as to any Credit Party that is or becomes a party hereto
regardless of whether any other Person becomes or fails to become or ceases to be a Credit Party
hereunder. With respect to each such Restricted Subsidiary, the Borrower shall promptly send to
the Administrative Agent written notice setting forth with respect to such Person the date on which
such Person became a Restricted Subsidiary of the Borrower, and supplement the data required to be
set forth in the Schedules to this Agreement as a result of the acquisition or creation of such
Restricted Subsidiary; provided that such supplemental data must be reasonably acceptable
to the Administrative Agent and Required Lenders.
Section 6.14. Pledged Equity Interests. At the time that any Restricted Subsidiary of
the Borrower is created or acquired or any Unrestricted Subsidiary becomes a Restricted Subsidiary,
the Borrower and the Subsidiaries (as applicable) shall execute and deliver to the Administrative
Agent for the benefit of the Secured Parties, a Pledge Agreement from the Borrower and/or the
Subsidiaries (as applicable) covering all Equity Interests owned by the Borrower or such Restricted
Subsidiaries in such Restricted Subsidiaries, together with all certificates (or other evidence
acceptable to Administrative Agent) evidencing the issued and outstanding Equity Interests of each
such Restricted Subsidiary of every class owned by such Credit Party (as applicable) which, if
certificated, shall be duly endorsed or accompanied by stock powers executed in blank (as
applicable), as Administrative Agent shall deem necessary or appropriate
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to grant, evidence and perfect a first priority security interest in the issued and
outstanding Equity Interests owned by Borrower or any Restricted Subsidiary in each Restricted
Subsidiary.
Article VII
Negative Covenants
Until the Aggregate Commitment has expired or terminated and the principal of and interest on
each Loan and all fees payable hereunder have been paid in full and all Letters of Credit have
expired or terminated and all LC Disbursements shall have been reimbursed, each Credit Party
covenants and agrees with the Lenders that:
Section 7.01. Indebtedness. The Borrower will not, nor will it permit any of its
Restricted Subsidiaries to, create, incur, assume or permit to exist any Indebtedness, except:
(a) The Obligations;
(b) Indebtedness existing on the date hereof and set forth in Schedule 7.01 and extensions,
renewals and replacements of any such Indebtedness that do not increase the outstanding principal
amount thereof;
(c) Indebtedness of the Borrower to any Guarantor and of any Guarantor to the Borrower or any
other Guarantor; provided, that all such Indebtedness shall be unsecured and subordinated
in right of payment to the payment in full of all of the Obligations as provided in Section 8.06;
(d) Guarantees of the Obligations;
(e) Indebtedness of the Borrower and the Restricted Subsidiaries incurred to finance the
acquisition, construction or improvement of any fixed or capital assets, including Capital Lease
Obligations and any Indebtedness assumed in connection with the acquisition of any such assets or
secured by a Lien on any such assets prior to the acquisition thereof, and extensions, renewals and
replacements of any such Indebtedness that do not increase the outstanding principal amount
thereof; provided that (i) such Indebtedness is incurred prior to or within 90 days after
such acquisition or the completion of such construction or improvement and (ii) the aggregate
principal amount of Indebtedness permitted by this clause (e) shall not exceed $25,000,000 at any
time outstanding;
(f) Indebtedness incurred or deposits made by the Borrower and any Restricted Subsidiary (i)
under worker’s compensation laws, unemployment insurance laws or similar legislation, or (ii) in
connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to
which such Credit Party is a party, (iii) to secure public or statutory obligations of such Credit
Party, and (iv) of cash or U.S. Government Securities made to secure the performance of statutory
obligations, surety, stay, customs and appeal bonds to which such Credit Party is a party in
connection with the operation of the Oil and Gas Interests, in each case in the ordinary course of
business;
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(g) Indebtedness of any Borrower or any Restricted Subsidiary under Swap Agreements to the
extent permitted under Section 7.05;
(h) Indebtedness under the Senior Subordinated Notes in an aggregate principal amount not
exceeding $600,000,000 at any time outstanding and extensions, renewals, replacements and
refinancing of any such Indebtedness that does not exceed the maximum principal amount permitted
under this clause (h); provided that any documentation which replaces the Senior Subordinated Notes
and pursuant to which the Senior Subordinated Notes are refinanced does not contain, either
initially or by amendment or other modification, any material terms, conditions, covenants or
defaults other than those which then exist in the Indenture and the Senior Subordinated Notes or
which could be included in the Indenture or the Senior Subordinated Notes by an amendment or other
modification that would not be prohibited by the terms of this Agreement; and
(i) Other unsecured Indebtedness of the Credit Parties in an aggregate principal amount not
exceeding $10,000,000 at any time outstanding.
Section 7.02. Liens. The Borrower will not, nor will it permit any of its Restricted
Subsidiaries to, create, incur, assume or permit to exist any Lien on any property or asset now
owned or hereafter acquired by it, or assign or sell any income or revenues (including accounts
receivable) or rights in respect of any thereof, except:
(a) any Lien created pursuant to this Agreement or the Security Instruments;
(b) Permitted Encumbrances;
(c) any Lien on any property or asset of the Borrower or any Restricted Subsidiary existing on
the date hereof and set forth in Schedule 7.02; provided that (i) such Lien shall not apply
to any other property or asset of the Borrower or any other Restricted Subsidiary and (ii) such
Lien shall secure only those obligations which it secures on the date hereof and extensions,
renewals and replacements thereof that do not increase the outstanding principal amount thereof;
(d) any Lien existing on any property or asset prior to the acquisition thereof by the
Borrower or any Restricted Subsidiary or existing on any property or asset of any Person that
becomes a Restricted Subsidiary after the date hereof prior to the time such Person becomes a
Restricted Subsidiary; provided that (i) such Lien secures Indebtedness permitted by
Section 7.01(e), (ii) such Lien is not created in contemplation of or in connection with such
acquisition or such Person becoming a Restricted Subsidiary, as the case may be, (iii) such Lien
shall not apply to any other property or assets of the Borrower or any other Restricted Subsidiary
and (iv) such Lien shall secure only those obligations which it secures on the date of such
acquisition or the date such Person becomes a Restricted Subsidiary, as the case may be and
extensions, renewals and replacements thereof that do not increase the outstanding principal amount
thereof; and
(e) Liens on fixed or capital assets acquired, constructed or improved by the Borrower or any
Restricted Subsidiary; provided that (i) such Liens, secure Indebtedness permitted by
Section 7.01, (ii) such security interests and the Indebtedness secured thereby are
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incurred prior to or within 90 days after such acquisition or the completion of such
construction or improvement, (iii) the Indebtedness secured thereby does not exceed the cost of
acquiring, constructing or improving such fixed or capital assets and (iv) such security interests
shall not apply to any other property or assets of the Borrower or any other Restricted
Subsidiaries.
Section 7.03. Fundamental Changes.
(a) The Borrower will not, nor will it permit any of its Restricted Subsidiaries to, merge
into or consolidate with any other Person, or permit any other Person to merge into or consolidate
with it, or sell, transfer, lease or otherwise dispose of (in one transaction or in a series of
transactions) all or any substantial part of the assets of the Borrower and its Restricted
Subsidiaries taken as a whole, or any of its Borrowing Base Properties or any of the Equity
Interests of any Restricted Subsidiary (in each case, whether now owned or hereafter acquired), or
liquidate or dissolve, except that, the Borrower or any Restricted Subsidiary may sell Hydrocarbons
produced from its Oil and Gas Interests in the ordinary course of business, and if at the time
thereof and immediately after giving effect thereto no Default shall have occurred and be
continuing, (i) any Restricted Subsidiary may merge into the Borrower in a transaction in which the
Borrower is the surviving entity, (ii) any Restricted Subsidiary may merge into any other
Restricted Subsidiary in a transaction in which the surviving entity is a Restricted Subsidiary,
(iii) any Restricted Subsidiary may sell, transfer, lease or otherwise dispose of its assets to the
Borrower or to another Restricted Subsidiary, (iv) any Restricted Subsidiary may liquidate or
dissolve if the Borrower determines in good faith that such liquidation or dissolution is in the
best interests of the Borrower and is not materially disadvantageous to the Lenders, (v) the
Borrower or any Restricted Subsidiary may sell, transfer, lease or otherwise dispose of equipment
and related items in the ordinary course of business, that are obsolete or no longer necessary in
the business of the Borrower or any of its Restricted Subsidiaries or that is being replaced by
equipment of comparable value and utility, (vi) subject to Section 2.12(b), the Borrower or any
Restricted Subsidiary may sell, transfer, lease, exchange, abandon or otherwise dispose of
Borrowing Base Properties with a value not exceeding, in the aggregate for the Borrower and its
Restricted Subsidiaries taken as a whole, ten percent (10%) of the Borrowing Base between Scheduled
Redeterminations, (vii) the Borrower or any Restricted Subsidiary may sell, transfer, abandon or
otherwise dispose of the Deep Participation Rights, and (viii) with the prior written consent of
Super Majority Lenders and subject to Section 2.12(b), the Borrower or any Restricted Subsidiary
may sell, transfer, lease, exchange, abandon or otherwise dispose of Borrowing Base Properties not
otherwise permitted pursuant to the foregoing clauses (vi) and (vii). For purposes of the
foregoing clause (vi), the value of any Oil and Gas Interests included in the Borrowing Base
Properties shall be the Engineered Value of such Oil and Gas Interests and the value of all other
Oil and Gas Interests shall be the value which would be assigned to such Oil and Gas Interests
using the same methodology, assumptions and discount rates used to determine the Engineered Value
of the Borrowing Base Properties as of the most recent Redetermination. In addition, for purposes
of determining compliance with clause (vi) of this Section with respect to any exchange of Oil and
Gas Interests, the value of such exchange shall be the net reduction, if any, in Engineered Value
realized or resulting from such exchange.
(b) The Borrower will not, nor will it permit any of its Restricted Subsidiaries to, engage to
any material extent in any business other than businesses of the type conducted by the
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Borrower and its Restricted Subsidiaries on the date of execution of this Agreement and after
giving effect to the Transactions and businesses reasonably related thereto.
Section 7.04. Investments, Loans, Advances, Guarantees and Acquisitions. The Borrower
will not, nor will it permit any of its Restricted Subsidiaries to, purchase, hold or acquire
(including pursuant to any merger with any Person that was not a wholly owned Restricted Subsidiary
prior to such merger) any capital stock, evidences of Indebtedness or other securities (including
any option, warrant or other right to acquire any of the foregoing) of, make or permit to exist any
loans or advances to, Guarantee any Indebtedness of, or make or permit to exist any investment or
any other interest in, any other Person, or purchase or otherwise acquire (in one transaction or a
series of transactions) any assets of any other Person constituting a business unit, except:
(a) Permitted Investments;
(b) investments by the Borrower in the Equity Interests of any Restricted Subsidiary;
(c) investments by the Borrower or Guarantor consisting of intercompany Indebtedness permitted
under Section 7.01(c)
(d) Guarantees constituting Indebtedness permitted by Section 7.01;
(e) investments by the Borrower and its Restricted Subsidiaries that are (1) customary in the
oil and gas business, (2) made in the ordinary course of the Borrower’s or such Restricted
Subsidiary’s business, and (3) made in the form of, or pursuant to, oil, gas and mineral leases,
operating agreements, farm-in agreements, farm-out agreements, development agreements, unitization
agreements, joint bidding agreements, services contracts and other similar agreements that a
reasonable and prudent oil and gas industry owner or operator would find acceptable;
(f) investments consisting of Swap Agreements to the extent permitted under Section 7.05; and
(g) investments existing on the date hereof and set forth on Schedule 7.04 but not any
increases in or additions to such investments except as otherwise permitted by this Section 7.04;
(h) investments consisting of Restricted Payments to the extent permitted by Section 7.06(d);
and
(i) other investments by the Borrower and the Restricted Subsidiaries; provided that,
on the date any such other investment is made, the amount of such investment, together with all
other investments made pursuant to this clause (i) of Section 7.04 (in each case determined based
on the cost of such investment) since the Effective Date, does not exceed in the aggregate, ten
percent (10%) of the Borrowing Base in effect on the Effective Date.
Section 7.05. Swap Agreements. The Borrower will not, nor will it permit any of its
Restricted Subsidiaries to, enter into or maintain any Swap Agreement, except the Existing Swap
Agreements, and Swap Agreements entered into in the ordinary course of business with
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Approved Counterparties and not for speculative purposes to (a) hedge or mitigate Crude Oil
and Natural Gas price risks to which the Borrower or any Restricted Subsidiary has actual exposure,
and (b) effectively cap, collar or exchange interest rates (from fixed to floating rates, from one
floating rate to another floating rate or otherwise) with respect to any interest-bearing liability
or investment of any Credit Party; provided that such Swap Agreements (at the time each
transaction under such Swap Agreement is entered into) would (i) not cause the aggregate notional
amount of Hydrocarbons under all Swap Agreements then in effect (including the Existing Swap
Agreements) to exceed at any time (1) ninety percent (90%) of the forecasted production from proved
developed producing reserves of the Borrower and the Restricted Subsidiaries for the first three
years of the forthcoming five year period and (2) eighty percent (80%) of the forecasted production
from proved producing reserves of the Borrower and the Restricted Subsidiaries for the fourth and
fifth years of the forthcoming five year period, and (ii) with respect to interest rates, not
cause all Swap Agreements then in effect (including the Existing Swap Agreements) to exceed eighty
percent (80%) of the aggregate funded Indebtedness of the Borrower and its Subsidiaries projected
to be outstanding for the forthcoming three year period. Once the Borrower or any Restricted
Subsidiaries enters into a Swap Agreement or any hedge transaction pursuant to any Swap Agreement,
the terms and conditions of such Swap Agreement and such hedge transaction may not be materially
amended modified or cancelled unless the Borrower or such Restricted Subsidiary, as the case may
be, provides written notice thereof to the Administrative Agent within three (3) Business Days
after such amendment, modification or cancellation. Each Credit Party agrees and acknowledges that
(A) the Existing Swap Agreements are Swap Agreements permitted under this Section 7.05 and (B) as
of the Effective Date, the counterparty to each Existing Swap Agreement is a Lender Counterparty.
Each Credit Party and each Lender agrees and acknowledges that the obligations of the Credit
Parties under the Existing Swap Agreements are included in the defined term “Obligations” and such
obligations are entitled to the benefits of, and are secured by the Liens granted under, the
Security Instruments.
Section 7.06. Restricted Payments. The Borrower will not, nor will it permit any of
its Restricted Subsidiaries to, declare or make, or agree to pay or make, directly or indirectly,
any Restricted Payment, except that (a) the Borrower may declare and pay dividends and make
distributions with respect to its Equity Interests payable solely in additional Equity Interests of
the Borrower, other than Disqualified Stock, (b) so long as no Default shall have occurred and is
continuing or would be caused thereby, the Borrower may make Restricted Payments pursuant to and in
accordance with stock option plans or other benefit plans for management or employees of the
Borrower and its Restricted Subsidiaries in an aggregate amount not to exceed $10,000,000 in any
fiscal year; provided that any such Restricted Payments that are required to be made by the
issuance of additional Equity Interests of the Borrower may be made regardless of whether a Default
shall have occurred and is continuing, (c) any Restricted Subsidiary may make Restricted Payments
to the Borrower or any Guarantor and (d) so long as no Default shall have occurred and is
continuing or would be caused thereby, Restricted Payments in an aggregate amount not to exceed
$20,000,000, plus (i) 50% of cumulative Consolidated Net Income after December 31, 2001
(excluding any non-cash gains or losses associated with the application of FASB Statement 121 or
133), plus (ii) 66-2/3% of the aggregate net cash proceeds received by the Borrower from
the issuance of its Equity Interests (other than Disqualified Stock)
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at any time after December 31, 2001, minus (iii) Restricted Payments made pursuant to
Section 13(c)(ii) of the Original Credit Agreement prior to the Effective Date.
Section 7.07. Transactions with Affiliates. The Borrower will not, nor will it permit
any of its Restricted Subsidiaries to, sell, lease or otherwise transfer any property or assets to,
or purchase, lease or otherwise acquire any property or assets from, or otherwise engage in any
other transactions with, any of its Affiliates, except (a) in the ordinary course of business at
prices and on terms and conditions not less favorable to the Borrower or such Restricted Subsidiary
than could be obtained on an arm’s-length basis from unrelated third parties, (b) transactions
between or among the Borrower and its Restricted Subsidiaries not involving any other Affiliate,
including transactions permitted under Section 7.03(a)(iii), (c) transactions described on Schedule
7.07, and (d) any Restricted Payment permitted by Section 7.06.
Section 7.08. Restrictive Agreements. The Borrower will not, nor will it permit any
of its Restricted Subsidiaries to, directly or indirectly, enter into, incur or permit to exist any
agreement or other arrangement that prohibits, restricts or imposes any condition upon (a) the
ability of the Borrower or any Restricted Subsidiary to create, incur or permit to exist any Lien
upon any of its property or assets, or (b) the ability of any Restricted Subsidiary to pay
dividends or other distributions with respect to any of its Equity Interests or to make or repay
loans or advances to the Borrower or any Restricted Subsidiary or to Guarantee Indebtedness of the
Borrower or any Restricted Subsidiary; provided that (i) the foregoing shall not apply to
restrictions and conditions imposed by law, this Agreement or the Indenture (or any documents
evidencing any permitted refinancing of the Senior Subordinated Notes), (ii) the foregoing shall
not apply to restrictions and conditions existing on the date hereof identified on Schedule 7.08
(but shall apply to any extension or renewal of, or any amendment or modification expanding the
scope of, any such restriction or condition), (iii) clause (a) of the foregoing shall not apply to
restrictions or conditions imposed by any agreement relating to secured Indebtedness permitted by
this Agreement if such restrictions or conditions apply only to the property or assets securing
such Indebtedness and (iv) clause (a) of the foregoing shall not apply to customary provisions in
leases and other contracts restricting the assignment thereof.
Section 7.09. Disqualified Stock. The Borrower will not, nor will it permit any of
its Restricted Subsidiaries to, issue any Disqualified Stock.
Section 7.10. Amendments to Organizational Documents. The Borrower will not, nor will
it permit any of its Restricted Subsidiaries to, enter into or permit any material modification or
amendment of, or waive any material right or obligation of any Person under its Organizational
Documents other than amendments, modifications or waivers required in connection with any
transactions among the Borrower and the Restricted Subsidiaries permitted under Section 7.03(a) and
not involving any other Person.
Section 7.11. Financial Covenants.
(a) Consolidated Current Ratio. The Borrower will not permit the Consolidated Current
Ratio as of the end of any fiscal quarter to be less than 1.00 to 1.00.
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(b) Leverage Ratio. The Borrower will not permit the ratio, determined as of the end
of any fiscal quarter, of (A) Consolidated Funded Indebtedness as of the end of such fiscal
quarter, to (B) Consolidated EBITDAX for the trailing four (4) fiscal quarter period ending on
such date to be greater than 4.0 to 1.0.
Section 7.12. Sale and Leaseback Transactions and other Liabilities. The Borrower
will not, nor will it permit any Restricted Subsidiary to, enter into or suffer to exist any (a)
Sale and Leaseback Transaction, (b) Advance Payment Contracts or (c) any other transaction pursuant
to which it incurs or has incurred Off-Balance Sheet Liabilities, except for Swap Agreements
permitted under Section 7.05 and Advance Payment Contracts; provided, that the
aggregate outstanding amount of all Advance Payments received by the Credit Parties from various
customers in connection with the Credit Parties’ credit management of such customers that have not
been satisfied by delivery of production does not exceed $25,000,000 at any time and the aggregate
amount of all other Advance Payments received by the Credit Parties that have not been satisfied by
delivery of production does not exceed $5,000,000 at any time.
Section 7.13. Modifications of Senior Subordinated Notes. Prior to the termination of
all Commitments and the payment and performance in full of the Loans, the Borrower will not, nor
will it permit any Restricted Subsidiary to, agree to any amendment, modification or supplement to
the Senior Subordinated Notes (or any notes issued in connection with any refinancing of such
Senior Subordinated Notes) or any indenture, agreement, document or instrument evidencing or
relating to the Senior Subordinated Notes (or any refinancing thereof) the effect of which is to
(a) increase the maximum principal amount of the Senior Subordinated Notes or the rate of interest
on any of the Senior Subordinated Notes (other than as a result of the imposition of a default rate
of interest in accordance with the terms of the Senior Subordinated Notes), (b) change or add any
event of default or any covenant with respect to the Senior Subordinated Notes if the effect of
such change or addition is to cause any one or more of the Senior Subordinated Notes to be more
restrictive on the Borrower or any of its Subsidiaries than such Senior Subordinated Notes were
prior to such change or addition, (c) change the dates upon which payments of principal or interest
on the Senior Subordinated Notes are due, if the effect of such change is to cause any such
payments to be due earlier or more frequently than such payments are due as of the Effective Date,
(d) change any redemption or prepayment provisions of the Senior Subordinated Notes if the effect
of such change is to require any such redemption or prepayment to be made prior to the dates
required as of the Effective Date, (e) alter the subordination provisions with respect to any of
the Senior Subordinated Notes or the definition of “Senior Debt” with respect to the Senior
Subordinated Notes, or (f) grant any Liens in any assets of the Borrower or any of its Subsidiaries
to secure the Senior Subordinated Notes.
Article VIII
Guarantee of Obligations
Section 8.01. Guarantee of Payment. Each Guarantor unconditionally and irrevocably
guarantees to the Administrative Agent for the benefit of the Secured Parties, the punctual payment
of all Obligations now or which may in the future be owing by the Borrower under the Loan Documents
and all Obligations which may now or which may in the future be owing by the
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Borrower or any other Guarantor to any Secured Party under any Swap Agreement (the
“Guaranteed Liabilities”). This Guarantee is a guaranty of payment and not of collection
only. The Administrative Agent shall not be required to exhaust any right or remedy or take any
action against the Borrower or any other Person or any Collateral. The Guaranteed Liabilities
include interest accruing after the commencement of a proceeding under bankruptcy, insolvency or
similar laws of any jurisdiction at the rate or rates provided in the Loan Documents, or the Swap
Agreements between any Credit Party and any Secured Party, as the case may be, regardless of
whether such interest is an allowed claim. Each Guarantor agrees that, as between the Guarantor
and the Administrative Agent, the Guaranteed Liabilities may be declared to be due and payable for
the purposes of this Guarantee notwithstanding any stay, injunction or other prohibition which may
prevent, delay or vitiate any declaration as regards the Borrower or any other Guarantor and that
in the event of a declaration or attempted declaration, the Guaranteed Liabilities shall
immediately become due and payable by each Guarantor for the purposes of this Guarantee.
Section 8.02. Guarantee Absolute. Each Guarantor guarantees that the Guaranteed
Liabilities shall be paid strictly in accordance with the terms of this Agreement and the Swap
Agreements to which any Secured Party is a party. The liability of each Guarantor hereunder is
absolute and unconditional irrespective of: (a) any change in the time, manner or place of payment
of, or in any other term of, all or any of the Loan Documents or the Guaranteed Liabilities, or any
other amendment or waiver of or any consent to departure from any of the terms of any Loan Document
or Guaranteed Liability, including any increase or decrease in the rate of interest thereon; (b)
any release or amendment or waiver of, or consent to departure from, any other guaranty or support
document, or any exchange, release or non-perfection of any Collateral, for all or any of the Loan
Documents or Guaranteed Liabilities; (c) any present or future law, regulation or order of any
jurisdiction (whether of right or in fact) or of any agency thereof purporting to reduce, amend,
restructure or otherwise affect any term of any Loan Document or Guaranteed Liability; (d) without
being limited by the foregoing, any lack of validity or enforceability of any Loan Document or
Guaranteed Liability; and (e) any other setoff, defense or counterclaim whatsoever (in any case,
whether based on contract, tort or any other theory) with respect to the Loan Documents or the
transactions contemplated thereby which might constitute a legal or equitable defense available to,
or discharge of, the Borrower or a Guarantor.
Section 8.03. Guarantee Irrevocable. This Guarantee is a continuing guaranty of the
payment of all Guaranteed Liabilities now or hereafter existing under this Agreement and such Swap
Agreements to which any Secured Party is a party and shall remain in full force and effect until
payment in full of all Guaranteed Liabilities and other amounts payable hereunder and until this
Agreement and the Swap Agreements are no longer in effect or, if earlier, when the Guarantor has
given the Administrative Agent written notice that this Guarantee has been revoked;
provided that any notice under this Section shall not release the revoking Guarantor from
any Guaranteed Liability, absolute or contingent, existing prior to the Administrative Agent’s
actual receipt of the notice at its branches or departments responsible for this Agreement and such
Swap Agreements and reasonable opportunity to act upon such notice.
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Section 8.04. Reinstatement. This Guarantee shall continue to be effective or be
reinstated, as the case may be, if at any time any payment of any of the Guaranteed Liabilities is
rescinded or must otherwise be returned by any Secured Party on the insolvency, bankruptcy or
reorganization of the Borrower, or any other Credit Party, or otherwise, all as though the payment
had not been made.
Section 8.05. Subrogation. No Guarantor shall exercise any rights which it may
acquire by way of subrogation, by any payment made under this Guarantee or otherwise, until all the
Guaranteed Liabilities have been paid in full and this Agreement and the Swap Agreements to which
any Lender Counterparty is a party are no longer in effect. If any amount is paid to the Guarantor
on account of subrogation rights under this Guarantee at any time when all the Guaranteed
Liabilities have not been paid in full, the amount shall be held in trust for the benefit of the
Lenders and the Lender Counterparties and shall be promptly paid to the Administrative Agent to be
credited and applied to the Guaranteed Liabilities, whether matured or unmatured or absolute or
contingent, in accordance with the terms of this Agreement and such Swap Agreements. If any
Guarantor makes payment to the Administrative Agent, Lenders, or any Lender Counterparties of all
or any part of the Guaranteed Liabilities and all the Guaranteed Liabilities are paid in full and
this Agreement and such Swap Agreements are no longer in effect, the Administrative Agent, Lenders
and Lender Counterparties shall, at such Guarantor’s request, execute and deliver to such Guarantor
appropriate documents, without recourse and without representation or warranty, necessary to
evidence the transfer by subrogation to such Guarantor of an interest in the Guaranteed Liabilities
resulting from the payment.
Section 8.06. Subordination. Without limiting the rights of the Administrative Agent,
the Lenders and the Lender Counterparties under any other agreement, any liabilities owed by the
Borrower to any Guarantor in connection with any extension of credit or financial accommodation by
any Guarantor to or for the account of the Borrower, including but not limited to interest accruing
at the agreed contract rate after the commencement of a bankruptcy or similar proceeding, are
hereby subordinated to the Guaranteed Liabilities, and such liabilities of the Borrower to such
Guarantor, if the Administrative Agent so requests, shall be collected, enforced and received by
any Guarantor as trustee for the Administrative Agent and shall be paid over to the Administrative
Agent on account of the Guaranteed Liabilities but without reducing or affecting in any manner the
liability of the Guarantor under the other provisions of this Guarantee.
Section 8.07. Payments Generally. All payments by the Guarantors shall be made in the
manner, at the place and in the currency (the “Payment Currency”) required by the Loan
Documents and the Swap Agreement to which any Lender Counterparty is a party, as the case may be;
provided, however, that (if the Payment Currency is other than Dollars) any
Guarantor may, at its option (or, if for any reason whatsoever any Guarantor is unable to effect
payments in the foregoing manner, such Guarantor shall be obligated to) pay to the Administrative
Agent at its principal office the equivalent amount in Dollars computed at the selling rate of the
Administrative Agent or a selling rate chosen by the Administrative Agent, most recently in effect
on or prior to the date the Guaranteed Liability becomes due, for cable transfers of the Payment
Currency to the place where the Guaranteed Liability is payable. In any case in which any
Guarantor makes or is obligated to make payment in Dollars, the Guarantor shall hold the
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Administrative Agent, the Lenders and the Lender Counterparties harmless from any loss
incurred by the Administrative Agent, any Lender or any Lender Counterparty arising from any change
in the value of Dollars in relation to the Payment Currency between the date the Guaranteed
Liability becomes due and the date the Administrative Agent, such Lender or such Lender
Counterparty is actually able, following the conversion of the Dollars paid by such Guarantor into
the Payment Currency and remittance of such Payment Currency to the place where such Guaranteed
Liability is payable, to apply such Payment Currency to such Guaranteed Liability.
Section 8.08. Setoff. Each Guarantor agrees that, in addition to (and without
limitation of) any right of setoff, banker’s lien or counterclaim the Administrative Agent, any
Lender or any Lender Counterparty may otherwise have, the Administrative Agent, such Lender or such
Lender Counterparty shall be entitled, at its option, to offset balances (general or special, time
or demand, provisional or final) held by it for the account of any Guarantor at any office of the
Administrative Agent, such Lender or such Lender Counterparty, in Dollars or in any other currency,
against any amount payable by such Guarantor under this Guarantee which is not paid when due
(regardless of whether such balances are then due to such Guarantor), in which case it shall
promptly notify such Guarantor thereof; provided that the failure of the Administrative
Agent, such Lender, or such Lender Counterparty to give such notice shall not affect the validity
thereof.
Section 8.09. Formalities. Each Guarantor waives presentment, notice of dishonor,
protest, notice of acceptance of this Guarantee or incurrence of any Guaranteed Liability and any
other formality with respect to any of the Guaranteed Liabilities or this Guarantee.
Section 8.10. Limitations on Guarantee. The provisions of the Guarantee under this
Article VIII are severable, and in any action or proceeding involving any state corporate law, or
any state, federal or foreign bankruptcy, insolvency, reorganization or other law affecting the
rights of creditors generally, if the obligations of any Guarantor under this Guarantee would
otherwise be held or determined to be avoidable, invalid or unenforceable on account of the amount
of such Guarantor’s liability under this Guarantee, then, notwithstanding any other provision of
this Guarantee to the contrary, the amount of such liability shall, without any further action by
the Guarantors, the Administrative Agent, any Lender or any Lender Counterparty, be automatically
limited and reduced to the highest amount that is valid and enforceable as determined in such
action or proceeding (such highest amount determined hereunder being the relevant Guarantor’s
“Maximum Liability”). This Section 8.10 with respect to the Maximum Liability of the Guarantors is
intended solely to preserve the rights of the Administrative Agent, Lenders and Lender
Counterparties hereunder to the maximum extent not subject to avoidance under applicable law, and
no Guarantor nor any other Person shall have any right or claim under this Section 8.10 with
respect to the Maximum Liability, except to the extent necessary so that none of the obligations
of any Guarantor hereunder shall not be rendered voidable under applicable law.
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Article IX
Events of Default
If any of the following events (“Events of Default”) shall occur:
(a) the Borrower shall fail to pay any principal of any Loan or any reimbursement obligation
in respect of any LC Disbursement when and as the same shall become due and payable, whether at the
due date thereof or at a date fixed for prepayment thereof or otherwise;
(b) the Borrower shall fail to pay any interest on any Loan or any fee or any other amount
(other than an amount referred to in clause (a) of this Article) payable under this Agreement, when
and as the same shall become due and payable, and such failure shall continue unremedied for a
period of three (3) days;
(c) any representation or warranty made or deemed made by or on behalf of the Borrower or any
Restricted Subsidiary in or in connection with this Agreement or any amendment or modification
hereof or waiver hereunder, or in any report, certificate, financial statement or other document
furnished pursuant to or in connection with this Agreement or any amendment or modification hereof
or waiver hereunder or in any Loan Document furnished pursuant to or in connection with this
Agreement or any amendment or modification thereof or waiver hereunder, shall prove to have been
incorrect in any material respect when made or deemed made;
(d) the Borrower or any Restricted Subsidiary shall fail to observe or perform any covenant,
condition or agreement contained in Article VII;
(e) the Borrower or any Restricted Subsidiary shall fail to observe or perform any covenant,
condition or agreement contained in this Agreement (other than those specified in clause (a), (b)
or (d) of this Article) or any Loan Document, and such failure shall continue unremedied for a
period of thirty (30) days after notice thereof from the Administrative Agent to the Borrower
(which notice will be given at the request of any Lender);
(f) the Borrower or any Restricted Subsidiary shall fail to make any payment (whether of
principal or interest and regardless of amount) in respect of any Material Indebtedness, when and
as the same shall become due and payable and such failure shall continue unremedied beyond any
grace period applicable thereto;
(g) any event or condition occurs that results in any Material Indebtedness becoming due prior
to its scheduled maturity or that enables or permits the holder or holders of any Material
Indebtedness or any trustee or agent on its or their behalf to cause any Material Indebtedness to
become due, or to require the prepayment, repurchase, redemption or defeasance thereof, prior to
its scheduled maturity; provided that this clause (g) shall not apply to secured
Indebtedness that becomes due as a result of the voluntary sale or transfer of the property or
assets securing such Indebtedness or to obligations of the Borrower or any Guarantor in respect of
any Swap Agreement unless such Swap Agreement has been terminated;
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(h) an involuntary proceeding shall be commenced or an involuntary petition shall be filed
seeking (i) liquidation, reorganization or other relief in respect of the Borrower or any
Restricted Subsidiary or its debts, or of a substantial part of its assets, under any Federal,
state or foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect or
(ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar
official for the Borrower or any Restricted Subsidiary or for a substantial part of its assets,
and, in any such case, such proceeding or petition shall continue undismissed for 60 days or an
order or decree approving or ordering any of the foregoing shall be entered;
(i) the Borrower or any Restricted Subsidiary shall (i) voluntarily commence any proceeding or
file any petition seeking liquidation, reorganization or other relief under any Federal, state or
foreign bankruptcy, insolvency, receivership or similar law now or hereafter in effect, (ii)
consent to the institution of, or fail to contest in a timely and appropriate manner, any
proceeding or petition described in clause (h) of this Article, (iii) apply for or consent to the
appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for
the Borrower or any Restricted Subsidiary or for a substantial part of its assets, (iv) file an
answer admitting the material allegations of a petition filed against it in any such proceeding,
(v) make a general assignment for the benefit of creditors or (vi) take any action for the purpose
of effecting any of the foregoing;
(j) the Borrower or any Restricted Subsidiary shall become unable, admit in writing its
inability or fail generally to pay its debts as they become due;
(k) one or more uninsured judgments for the payment of money in an aggregate amount in excess
of $5,000,000 shall be rendered against the Borrower or any Restricted Subsidiary or any
combination thereof and the same shall remain undischarged for a period of 30 consecutive days
during which execution shall not be effectively stayed or bonded, or any action shall be legally
taken by a judgment creditor to attach or levy upon any assets of the Borrower or any Restricted
Subsidiary to enforce any such judgment which action has not been stayed or bonded;
(l) an ERISA Event shall have occurred that, in the opinion of the Required Lenders, when
taken together with all other ERISA Events that have occurred, could reasonably be expected to
result in a Material Adverse Effect;
(m) the delivery by any Guarantor to the Administrative Agent of written notice that its
Guarantee under Article VIII has been revoked or is otherwise declared invalid or unenforceable; or
(n) a Change of Control shall occur;
then, and in every such event (other than an event with respect to the Borrower or any Restricted
Subsidiary described in clause (h) or (i) of this Article), and at any time thereafter during the
continuance of such event, the Administrative Agent may, and at the request of the Required Lenders
shall, by notice to the Borrower, take either or both of the following actions, at the same or
different times: (i) terminate the Aggregate Commitment, and thereupon the Aggregate
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Commitment shall terminate immediately, and (ii) declare the Loans then outstanding to be due and
payable in whole (or in part, in which case any principal not so declared to be due and payable may
thereafter be declared to be due and payable), and thereupon the principal of the Loans so declared
to be due and payable, together with accrued interest thereon and all fees and other obligations of
the Borrower accrued hereunder, shall become due and payable immediately, without presentment,
demand, protest or other notice of any kind, all of which are hereby waived by the Borrower; and in
case of any event with respect to the Borrower described in clause (h) or (i) of this Article, the
Aggregate Commitment shall automatically terminate and the principal of the Loans then outstanding,
together with accrued interest thereon and all fees and other obligations of the Borrower accrued
hereunder, shall automatically become due and payable, without presentment, demand, protest or
other notice of any kind, all of which are hereby waived by the Borrower.
Article X
The Administrative Agent
Each of the Lenders and the Issuing Bank hereby irrevocably appoints the Administrative Agent
as its agent and authorizes the Administrative Agent to take such actions on its behalf and to
exercise such powers as are delegated to the Administrative Agent by the terms hereof, together
with such actions and powers as are reasonably incidental thereto.
The bank serving as the Administrative Agent hereunder shall have the same rights and powers
in its capacity as a Lender as any other Lender and may exercise the same as though it were not the
Administrative Agent, and such bank and its Affiliates may accept deposits from, lend money to and
generally engage in any kind of business with any Credit Party or other Affiliate thereof as if it
were not the Administrative Agent hereunder.
The Administrative Agent shall not have any duties or obligations except those expressly set
forth herein. Without limiting the generality of the foregoing, (a) the Administrative Agent shall
not be subject to any fiduciary or other implied duties, regardless of whether a Default has
occurred and is continuing, (b) the Administrative Agent shall not have any duty to take any
discretionary action or exercise any discretionary powers, except discretionary rights and powers
expressly contemplated hereby that the Administrative Agent is required to exercise in writing as
directed by the Required Lenders (or such other number or percentage of the Lenders as shall be
necessary under the circumstances as provided in Section 11.02), and (c) except as expressly set
forth herein, the Administrative Agent shall not have any duty to disclose, and shall not be liable
for the failure to disclose, any information relating to any Credit Party that is communicated to
or obtained by the bank serving as Administrative Agent or any of its Affiliates in any capacity.
The Administrative Agent shall not be liable for any action taken or not taken by it with the
consent or at the request of the Required Lenders (or such other number or percentage of the
Lenders as shall be necessary under the circumstances as provided in Section 11.02) or in the
absence of its own gross negligence or willful misconduct. The Administrative Agent shall be
deemed not to have knowledge of any Default unless and until written notice thereof is given to the
Administrative Agent by the Borrower or a Lender, and the Administrative Agent shall not be
responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or
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representation made in or in connection with this Agreement, (ii) the contents of any
certificate, report or other document delivered hereunder or in connection herewith, (iii) the
performance or observance of any of the covenants, agreements or other terms or conditions set
forth herein, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement or
any other agreement, instrument or document, or (v) the satisfaction of any condition set forth in
Article V or elsewhere herein, other than to confirm receipt of items expressly required to be
delivered to the Administrative Agent. None of the Persons identified as a Syndication Agent,
Documentation Agent, Co-Agent or Agent on Schedule 2.01 shall have any responsibility or liability
as an agent of the Lenders under this Agreement or any other Loan Document.
The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for
relying upon, any notice, request, certificate, consent, statement, instrument, document or other
writing believed by it to be genuine and to have been signed or sent by the proper Person. The
Administrative Agent also may rely upon any statement made to it orally or by telephone and
believed by it to be made by the proper Person, and shall not incur any liability for relying
thereon. The Administrative Agent may consult with legal counsel (who may be counsel for the
Borrower), independent accountants and other experts selected by it, and shall not be liable for
any action taken or not taken by it in accordance with the advice of any such counsel, accountants
or experts.
The Administrative Agent may perform any and all its duties and exercise its rights and powers
by or through any one or more sub-agents appointed by the Administrative Agent. The Administrative
Agent and any such sub-agent may perform any and all its duties and exercise its rights and powers
through their respective Related Parties. The exculpatory provisions of the preceding paragraphs
shall apply to any such sub-agent and to the Related Parties of the Administrative Agent and any
such sub-agent, and shall apply to their respective activities in connection with the syndication
of the credit facilities provided for herein as well as activities as Administrative Agent.
Subject to the appointment and acceptance of a successor Administrative Agent as provided in
this paragraph, the Administrative Agent may resign at any time by notifying the Lenders, the
Issuing Bank and the Borrower. Upon any such resignation, the Required Lenders shall have the
right, in consultation with the Borrower, to appoint a successor. If no successor shall have been
so appointed by the Required Lenders and shall have accepted such appointment within 30 days after
the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative
Agent may, on behalf of the Lenders and the Issuing Bank, appoint a successor Administrative Agent
which shall be a bank with an office in Chicago, Illinois or New York, New York, or an Affiliate of
any such bank. Upon the acceptance of its appointment as Administrative Agent hereunder by a
successor, such successor shall succeed to and become vested with all the rights, powers,
privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent
shall be discharged from its duties and obligations hereunder. The fees payable by the Borrower to
a successor Administrative Agent shall be the same as those payable to its predecessor unless
otherwise agreed between the Borrower and such successor. After the Administrative Agent’s
resignation hereunder, the provisions of this Article and Section 11.03 shall continue in effect
for the benefit of such retiring Administrative Agent, its
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sub-agents and their respective Related Parties in respect of any actions taken or omitted to
be taken by any of them while it was acting as Administrative Agent.
Each Lender acknowledges that it has, independently and without reliance upon the
Administrative Agent or any other Lender and based on such documents and information as it has
deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each
Lender also acknowledges that it will, independently and without reliance upon the Administrative
Agent or any other Lender and based on such documents and information as it shall from time to time
deem appropriate, continue to make its own decisions in taking or not taking action under or based
upon this Agreement, any related agreement or any document furnished hereunder or thereunder.
Article XI
Miscellaneous
Section 11.01. Notices.
(a) Except in the case of notices and other communications expressly permitted to be given by
telephone (and subject to paragraph (b) below), all notices and other communications provided for
herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by
certified or registered mail or sent by telecopy, as follows:
(i) if to the Borrower, to Range Resources Corporation, 777 Main Street, Suite 800,
Fort Worth, Texas 76102, Attention: Roger Manny, Chief Financial Officer, Telecopy No.
(817) 810-1921. For purposes of delivering the documents pursuant to Section 6.01(a),
Section 6.01(b) and Section 6.01(d), the website address is www.rangeresources.com;
(ii) if to the Administrative Agent or Issuing Bank, to JPMorgan Chase Bank, N.A.,
JPMorgan Loan Services, 10 South Dearborn St., 19th Floor, Chicago, Illinois 60603-2003,
Telecopy No.: (312) 385-7096, Attention: Claudia Kech
(claudia.kech@jpmchase.com), with a
copy to JPMorgan Chase Bank, N.A., 1717 Main Street, TX1-2448, Dallas, Texas 75201, Telecopy
No. (214) 290-2332, Attention: Wm. Mark Cranmer, Senior Vice President
(mark.cranmer@chase.com); and
(iii) if to any other Lender, to it at its address (or telecopy number) set forth in
its Administrative Questionnaire.
(b) Notices and other communications to the Lenders hereunder may be delivered or furnished by
electronic communications pursuant to procedures approved by the Administrative Agent;
provided that the foregoing shall not apply to notices pursuant to Article II unless
otherwise agreed by the Administrative Agent and the applicable Lender. The Administrative Agent
or the Borrower may, in their discretion, agree to accept notices and other communications to it
hereunder by electronic communications pursuant to procedures approved
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 75
by it; provided that approval of such procedures may be limited to particular notices
or communications.
(c) Any party hereto may change its address or telecopy number for notices and other
communications hereunder by notice to the other parties hereto. All notices and other
communications given to any party hereto in accordance with the provisions of this Agreement shall
be deemed to have been given on the date of receipt.
Section 11.02. Waivers; Amendments.
(a) No failure or delay by the Administrative Agent, the Issuing Bank or any Lender in
exercising any right or power hereunder shall operate as a waiver thereof, nor shall any single or
partial exercise of any such right or power, or any abandonment or discontinuance of steps to
enforce such a right or power, preclude any other or further exercise thereof or the exercise of
any other right or power. The rights and remedies of the Administrative Agent, the Issuing Bank
and the Lenders hereunder are cumulative and are not exclusive of any rights or remedies that they
would otherwise have. No waiver of any provision of this Agreement or consent to any departure by
the Borrower therefrom shall in any event be effective unless the same shall be permitted by
paragraph (b) of this Section, and then such waiver or consent shall be effective only in the
specific instance and for the purpose for which given. Without limiting the generality of the
foregoing, the making of a Loan or issuance of a Letter of Credit shall not be construed as a
waiver of any Default, regardless of whether the Administrative Agent, any Lender or the Issuing
Bank may have had notice or knowledge of such Default at the time.
(b) Neither this Agreement nor any provision hereof may be waived, amended or modified except
pursuant to an agreement or agreements in writing entered into by the Credit Parties and the
Required Lenders or by the Credit Parties and the Administrative Agent with the consent of the
Required Lenders; provided that no such agreement shall (i) increase the Borrowing Base
without the written consent of each Lender, (ii) increase the Applicable Percentage or Commitment
of any Lender without the written consent of such Lender or the Aggregate Commitment above the
Maximum Facility Amount without the written consent of all Lenders, (iii) reduce the principal
amount of any Loan or LC Disbursement or reduce the rate of interest thereon (other than reductions
in the interest rates otherwise applicable pursuant to Section 2.14(c)), or reduce any fees payable
hereunder, without the written consent of each Lender affected thereby, (iv) postpone the scheduled
date of payment of the principal amount of any Loan or LC Disbursement, or any interest thereon, or
any fees payable hereunder, or reduce the amount of, waive or excuse any such payment, or postpone
the scheduled date of expiration of any of the Aggregate Commitment, without the written consent of
each Lender affected thereby, (v) change Section 2.19(b) or Section 2.19(c) in a manner that would
alter the pro rata sharing of payments required thereby, without the written consent of each
Lender, (vi) release any Credit Party from its obligations under the Loan Documents or, except in
connection with any sales, transfers, leases or other dispositions permitted in Section 7.03,
release any of the Collateral without the written consent of each Lender, or (vii) change any of
the provisions of this Section or the definition of “Required Lenders” or any other provision
hereof specifying the number or percentage of Lenders required to waive, amend or modify any rights
hereunder or make any determination or grant any consent hereunder, without the written consent of
each
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Lender; provided further that no such agreement shall amend, modify or
otherwise affect the rights or duties of the Administrative Agent or the Issuing Bank hereunder
without the prior written consent of the Administrative Agent or the Issuing Bank, as the case may
be. Notwithstanding anything to the contrary herein, no Defaulting Lender shall have any right to
approve or disapprove any amendment, waiver or consent hereunder, except that the Commitment of
such Lender may not be increased or extended without the consent of such Lender.
Section 11.03. Expenses; Indemnity; Damage Waiver.
(a) The Borrower shall pay (i) all reasonable out-of-pocket expenses incurred by the
Administrative Agent and its Affiliates, including the reasonable fees, charges and disbursements
of counsel for the Administrative Agent, in connection with the syndication of the credit
facilities provided for herein, the preparation and administration of this Agreement and the other
Loan Documents or any amendments, modifications or waivers of the provisions hereof (whether or not
the transactions contemplated hereby or thereby shall be consummated), (ii) all reasonable
out-of-pocket expenses incurred by the Issuing Bank in connection with the issuance, amendment,
renewal or extension of any Letter of Credit or any demand for payment thereunder and (iii) all
out-of-pocket expenses incurred by the Administrative Agent, the Issuing Bank or any Lender,
including the fees, charges and disbursements of any counsel for the Administrative Agent, the
Issuing Bank or any Lender, in connection with the enforcement or protection of its rights in
connection with the Loan Documents, including its rights under this Section, or the Loans made or
Letters of Credit issued hereunder, including all such out-of-pocket expenses incurred during any
workout, restructuring or negotiations in respect of such Loans or Letters of Credit.
(b) THE CREDIT PARTIES SHALL INDEMNIFY THE ADMINISTRATIVE AGENT, THE ISSUING BANK AND EACH
LENDER, AND EACH RELATED PARTY OF ANY OF THE FOREGOING PERSONS (EACH SUCH PERSON BEING CALLED AN
“INDEMNITEE”) AGAINST, AND HOLD EACH INDEMNITEE HARMLESS FROM, ANY AND ALL LOSSES, CLAIMS,
DAMAGES, LIABILITIES AND RELATED EXPENSES, INCLUDING THE FEES, CHARGES AND DISBURSEMENTS OF ANY
COUNSEL FOR ANY INDEMNITEE, INCURRED BY OR ASSERTED AGAINST ANY INDEMNITEE ARISING OUT OF, IN
CONNECTION WITH, OR AS A RESULT OF (I) THE EXECUTION OR DELIVERY OF THIS AGREEMENT OR ANY AGREEMENT
OR INSTRUMENT CONTEMPLATED HEREBY, THE PERFORMANCE BY THE PARTIES HERETO OF THEIR RESPECTIVE
OBLIGATIONS HEREUNDER OR THE CONSUMMATION OF THE TRANSACTIONS OR ANY OTHER TRANSACTIONS
CONTEMPLATED HEREBY, (II) ANY LOAN OR LETTER OF CREDIT OR THE USE OF THE PROCEEDS THEREFROM
(INCLUDING ANY REFUSAL BY THE ISSUING BANK TO HONOR A DEMAND FOR PAYMENT UNDER A LETTER OF CREDIT
IF THE DOCUMENTS PRESENTED IN CONNECTION WITH SUCH DEMAND DO NOT STRICTLY COMPLY WITH THE TERMS OF
SUCH LETTER OF CREDIT), (III) ANY ACTUAL OR ALLEGED PRESENCE OR RELEASE OF HAZARDOUS MATERIALS ON
OR FROM ANY PROPERTY OWNED OR OPERATED BY THE BORROWER OR ANY SUBSIDIARY,
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OR ANY ENVIRONMENTAL LIABILITY RELATED IN ANY WAY TO THE BORROWER OR ANY SUBSIDIARY, OR (IV)
ANY ACTUAL OR PROSPECTIVE CLAIM, LITIGATION, INVESTIGATION OR PROCEEDING RELATING TO ANY OF THE
FOREGOING, WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY AND REGARDLESS OF WHETHER ANY
INDEMNITEE IS A PARTY THERETO; PROVIDED THAT SUCH INDEMNITY SHALL NOT, AS TO ANY
INDEMNITEE, BE AVAILABLE TO THE EXTENT THAT SUCH LOSSES, CLAIMS, DAMAGES, LIABILITIES OR RELATED
EXPENSES ARE DETERMINED BY A COURT OF COMPETENT JURISDICTION BY FINAL AND NONAPPEALABLE JUDGMENT TO
HAVE RESULTED FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SUCH INDEMNITEE.
(c) To the extent that any Credit Party fails to pay any amount required to be paid by it to
the Administrative Agent or the Issuing Bank under paragraph (a) or (b) of this Section, each
Lender severally agrees to pay to the Administrative Agent or the Issuing Bank, as the case may be,
such Lender’s Applicable Percentage (in each case, determined as of the time that the applicable
unreimbursed expense or indemnity payment is sought) of such unpaid amount; provided that
the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the
case may be, was incurred by or asserted against the Administrative Agent or the Issuing Bank in
its capacity as such.
(d) To the extent permitted by applicable law, the Credit Parties shall not assert, and hereby
waive, any claim against any Indemnitee, on any theory of liability, for special, indirect,
consequential or punitive damages (as opposed to direct or actual damages) arising out of, in
connection with, or as a result of, this Agreement or any agreement or instrument contemplated
hereby, the Transactions, any Loan or Letter of Credit or the use of the proceeds thereof.
(e) All amounts due under this Section shall be payable not later than thirty (30) days after
written demand therefor.
Section 11.04. Successors and Assigns.
(a) The provisions of this Agreement shall be binding upon and inure to the benefit of the
parties hereto and their respective successors and assigns permitted hereby (including any
Affiliate of the Issuing Bank that issues any Letter of Credit), except that (i) no Credit Party
may assign or otherwise transfer any of its rights or obligations hereunder without the prior
written consent of each Lender (and any attempted assignment or transfer by such Credit Party
without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer
its rights or obligations hereunder except in accordance with this Section. Nothing in this
Agreement, expressed or implied, shall be construed to confer upon any Person (other than the
parties hereto, their respective successors and assigns permitted hereby (including any Affiliate
of the Issuing Bank that issues any Letter of Credit), Participants (to the extent provided in
paragraph (c) of this Section) and, to the extent expressly contemplated hereby, the Related
Parties of each of the Administrative Agent, the Issuing Bank and the Lenders) any legal or
equitable right, remedy or claim under or by reason of this Agreement.
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(b)
(i) Subject to the conditions set forth in paragraph (b)(ii) below, any Lender may
assign to one or more assignees all or a portion of its rights and obligations under this
Agreement (including all or a portion of its Commitment and the Loans at the time owing to
it) with the prior written consent (such consent not to be unreasonably withheld) of:
(A) the Borrower, provided that no consent of the Borrower shall be
required for an assignment to a Lender, an Affiliate of a Lender, a Federal Reserve
Bank, an Approved Fund or, if an Event of Default has occurred and is continuing,
any other assignee; and
(B) the Administrative Agent, provided that no consent of the
Administrative Agent shall be required for an assignment of any Commitment to an
assignee that is a Lender with a Commitment immediately prior to giving effect to
such assignment; or
(C) the Issuing Bank.
(ii) Assignments shall be subject to the following additional conditions:
(A) except in the case of an assignment to a Lender, an Affiliate of a Lender,
an Approved Fund or an assignment of the entire remaining amount of the assigning
Lender’s Commitment or Loans, the amount of the Commitment or Loans of the assigning
Lender subject to each such assignment (determined as of the date the Assignment and
Assumption with respect to such assignment is delivered to the Administrative Agent)
shall not be less than $5,000,000 unless each of the Borrower and the Administrative
Agent otherwise consent, provided that no such consent of the Borrower shall
be required if an Event of Default has occurred and is continuing;
(B) each partial assignment shall be made as an assignment of a proportionate
part of all the assigning Lender’s rights and obligations in respect of such
Lender’s Commitment and such Lender’s Loans under this Agreement;
(C) the parties to each assignment shall execute and deliver to the
Administrative Agent an Assignment and Assumption, together with a processing and
recordation fee of $3,500; and
(D) the assignee, if it shall not be a Lender, shall deliver to the
Administrative Agent an Administrative Questionnaire.
For the purposes of this Section 11.04(b), the term “Approved Fund” has the
following meaning:
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“Approved Fund” means any Person (other than a natural person) that is engaged
in making, purchasing, holding or investing in bank loans and similar extensions of credit
in the ordinary course of its business and that is administered or managed by (a) a Lender,
(b) an Affiliate of a Lender or (c) an entity or an Affiliate of an entity that administers
or manages a Lender.
(iii) Subject to acceptance and recording thereof pursuant to paragraph (b)(iv) of this
Section, from and after the effective date specified in each Assignment and Assumption the
assignee thereunder shall be a party hereto and, to the extent of the interest assigned by
such Assignment and Assumption, have the rights and obligations of a Lender under this
Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned
by such Assignment and Assumption, be released from its obligations under this Agreement
(and, in the case of an Assignment and Assumption covering all of the assigning Lender’s
rights and obligations under this Agreement, such Lender shall cease to be a party hereto
but shall continue to be entitled to the benefits of Section 2.16, Section 2.17, Section
2.18 and Section 11.03). Any assignment or transfer by a Lender of rights or obligations
under this Agreement that does not comply with this Section 11.04 shall be treated for
purposes of this Agreement as a sale by such Lender of a participation in such rights and
obligations in accordance with paragraph (c) of this Section except that any attempted
assignment or transfer by any Lender that does not comply with clause (C) of Section
11.04(b)(ii) shall be null and void.
(iv) The Administrative Agent, acting for this purpose as an agent of the Borrower,
shall maintain at one of its offices a copy of each Assignment and Assumption delivered to
it and a register for the recordation of the names and addresses of the Lenders, and the
Commitment and Applicable Percentage of, and principal amount of the Loans and LC
Disbursements owing to, each Lender pursuant to the terms hereof from time to time (the
“Register”). The entries in the Register shall be conclusive, and the Credit
Parties, the Administrative Agent, the Issuing Bank and the Lenders may treat each Person
whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder
for all purposes of this Agreement, notwithstanding notice to the contrary. The Register
shall be available for inspection by the Credit Parties, the Issuing Bank and any Lender, at
any reasonable time and from time to time upon reasonable prior notice.
(v) Upon its receipt of a duly completed Assignment and Assumption executed by an
assigning Lender and an assignee, the assignee’s completed Administrative Questionnaire
(unless the assignee shall already be a Lender hereunder), the processing and recordation
fee referred to in paragraph (b) of this Section any written consent to such assignment
required by paragraph (b) of this Section, the Administrative Agent shall accept such
Assignment and Assumption and record the information contained therein in the Register;
provided that if either the assigning Lender or the assignee shall have failed to
make any payment required to be made by it pursuant to Section 2.07(d) or Section 2.07(e),
Section 2.08, Section 2.19(d) or Section 11.03(c), the Administrative Agent shall have no
obligation to accept such Assignment and Assumption and record the information therein in
the Register unless and until such
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 80
payment shall have been made in full, together with all accrued interest thereon. No
assignment shall be effective for purposes of this Agreement unless it has been recorded in
the Register as provided in this paragraph.
(c)
(i) Any Lender may, without the consent of the Borrower, the Administrative Agent or
the Issuing Bank, sell participations to one or more banks or other entities (a
“Participant”) in all or a portion of such Lender’s rights and obligations under
this Agreement (including all or a portion of its Commitment and the Loans owing to it);
provided that (A) such Lender’s obligations under this Agreement shall remain
unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for
the performance of such obligations and (C) the Borrower, the Administrative Agent, the
Issuing Bank and the other Lenders shall continue to deal solely and directly with such
Lender in connection with such Lender’s rights and obligations under this Agreement. Any
agreement or instrument pursuant to which a Lender sells such a participation shall provide
that such Lender shall retain the sole right to enforce this Agreement and to approve any
amendment, modification or waiver of any provision of this Agreement; provided that
such agreement or instrument may provide that such Lender will not, without the consent of
the Participant, agree to any amendment, modification or waiver described in the first
proviso to Section 11.02(b) that affects such Participant. Subject to paragraph (c)(ii) of
this Section, the Borrower agrees that each Participant shall be entitled to the benefits of
Section 2.16, Section 2.17 and Section 2.18 to the same extent as if it were a Lender and
had acquired its interest by assignment pursuant to paragraph (b) of this Section. To the
extent permitted by law, each Participant also shall be entitled to the benefits of Section
11.08 as though it were a Lender, provided such Participant agrees to be subject to Section
2.19(c) as though it were a Lender.
(ii) A Participant shall not be entitled to receive any greater payment under Section
2.16 or Section 2.18 than the applicable Lender would have been entitled to receive with
respect to the participation sold to such Participant, unless the sale of the participation
to such Participant is made with the prior written consent of the Borrower. A Participant
that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of
Section 2.18 unless the Borrower is notified of the participation sold to such Participant
and such Participant agrees, for the benefit of the Borrower, to comply with Section 2.18(e)
as though it were a Lender.
(d) Any Lender may at any time pledge or assign a security interest in all or any portion of
its rights under this Agreement to secure obligations of such Lender, including without limitation
any pledge or assignment to secure obligations to a Federal Reserve Bank, and this Section shall
not apply to any such pledge or assignment of a security interest; provided that no such
pledge or assignment of a security interest shall release a Lender from any of its obligations
hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.
Section 11.05. Survival. All covenants, agreements, representations and warranties
made by the Credit Parties herein and in the certificates or other instruments delivered in
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connection with or pursuant to this Agreement shall be considered to have been relied upon by
the other parties hereto and shall survive the execution and delivery of this Agreement and the
making of any Loans and issuance of any Letters of Credit, regardless of any investigation made by
any such other party or on its behalf and notwithstanding that the Administrative Agent, the
Issuing Bank or any Lender may have had notice or knowledge of any Default or incorrect
representation or warranty at the time any credit is extended hereunder, and shall continue in full
force and effect as long as the principal of or any accrued interest on any Loan or any fee or any
other amount payable under this Agreement is outstanding and unpaid or any Letter of Credit is
outstanding and so long as the Aggregate Commitment has not expired or terminated. The provisions
of Section 2.16, Section 2.17, Section 2.18 and Section 11.03 and Article X shall survive and
remain in full force and effect regardless of the consummation of the transactions contemplated
hereby, the repayment of the Loans, the expiration or termination of the Letters of Credit and the
Aggregate Commitment or the termination of this Agreement or any provision hereof.
Section 11.06. Counterparts; Integration; Effectiveness. This Agreement may be
executed in counterparts (and by different parties hereto on different counterparts), each of which
shall constitute an original, but all of which when taken together shall constitute a single
contract. This Agreement and any separate letter agreements with respect to fees payable to the
Administrative Agent constitute the entire contract among the parties relating to the subject
matter hereof and supersede any and all previous agreements and understandings, oral or written,
relating to the subject matter hereof. THIS WRITTEN CREDIT AND GUARANTY AGREEMENT AND THE OTHER
LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY
EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO
UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. Except as provided in Section 5.01, this Agreement
shall become effective when it shall have been executed by the Administrative Agent and when the
Administrative Agent shall have received counterparts hereof which, when taken together, bear the
signatures of each of the other parties hereto, and thereafter shall be binding upon and inure to
the benefit of the parties hereto and their respective successors and assigns. Delivery of an
executed counterpart of a signature page of this Agreement by telecopy shall be effective as
delivery of a manually executed counterpart of this Agreement.
Section 11.07. Severability. Any provision of this Agreement held to be invalid,
illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the
extent of such invalidity, illegality or unenforceability without affecting the validity, legality
and enforceability of the remaining provisions hereof; and the invalidity of a particular provision
in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.
Section 11.08. Right of Setoff. If an Event of Default shall have occurred and be
continuing, each Lender and each of its Affiliates is hereby authorized at any time and from time
to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general
or special, time or demand, provisional or final) at any time held and other obligations at any
time owing by such Lender or Affiliate to or for the credit or the account of the Borrower against
any of and all the obligations of any Credit Party now or hereafter existing under this Agreement
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held by such Lender, irrespective of whether or not such Lender shall have made any demand
under this Agreement and although such obligations may be unmatured. The rights of each Lender
under this Section and Section 8.08 are in addition to other rights and remedies (including other
rights of setoff) which such Lender may have.
Section 11.09. GOVERNING LAW; JURISDICTION; CONSENT TO SERVICE OF PROCESS.
(a) THIS AGREEMENT SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAW OF THE STATE
OF TEXAS.
(b) EACH CREDIT PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS
PROPERTY, TO THE NONEXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR TEXAS STATE COURT
SITTING IN DALLAS, TEXAS IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT,
OR FOR RECOGNITION OR ENFORCEMENT OF ANY JUDGMENT, AND EACH OF THE PARTIES HERETO HEREBY
IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING
MAY BE HEARD AND DETERMINED IN SUCH TEXAS STATE OR, TO THE EXTENT PERMITTED BY LAW, IN SUCH FEDERAL
COURT. EACH OF THE PARTIES HERETO AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING
SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY
OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT SHALL AFFECT ANY RIGHT THAT THE
ADMINISTRATIVE AGENT, THE ISSUING BANK OR ANY LENDER MAY OTHERWISE HAVE TO BRING ANY ACTION OR
PROCEEDING RELATING TO THIS AGREEMENT AGAINST ANY CREDIT PARTY OR ITS PROPERTIES IN THE COURTS OF
ANY JURISDICTION.
(c) EACH CREDIT PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT IT
MAY LEGALLY AND EFFECTIVELY DO SO, ANY OBJECTION WHICH IT MAY NOW OR HEREAFTER HAVE TO THE LAYING
OF VENUE OF ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT IN ANY
COURT REFERRED TO IN PARAGRAPH (B) OF THIS SECTION. EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY
WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE
MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT.
(d) EACH PARTY TO THIS AGREEMENT IRREVOCABLY CONSENTS TO SERVICE OF PROCESS IN THE MANNER
PROVIDED FOR NOTICES IN Section 11.01. NOTHING IN THIS AGREEMENT WILL AFFECT THE RIGHT OF ANY
PARTY TO THIS AGREEMENT TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY LAW.
Section 11.10. WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST
EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT
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IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF
OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT,
TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR
ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD
NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT
AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS,
THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.
Section 11.11. Headings. Article and Section headings and the Table of Contents used
herein are for convenience of reference only, are not part of this Agreement and shall not affect
the construction of, or be taken into consideration in interpreting, this Agreement.
Section 11.12. Confidentiality. Each of the Administrative Agent, the Issuing Bank
and the Lenders agrees to maintain the confidentiality of the Information (as defined below),
except that Information may be disclosed (a) to its and its Affiliates’ directors, officers,
employees and agents, including accountants, legal counsel and other advisors (it being understood
that the Persons to whom such disclosure is made will be informed of the confidential nature of
such Information and instructed to keep such Information confidential), (b) to the extent requested
by any regulatory authority, (c) to the extent required by applicable laws or regulations or by any
subpoena or similar legal process, or self-regulatory body (it being understood that any such
self-regulatory body to whom such disclosure is made will be informed of the confidential nature of
such Information and instructed to keep such Information confidential) (d) to any other party to
this Agreement, (e) in connection with the exercise of any remedies hereunder or any suit, action
or proceeding relating to this Agreement or the enforcement of rights hereunder, (f) subject to an
agreement containing provisions substantially the same as those of this Section, to (i) any
assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights
or obligations under this Agreement or (ii) any actual or prospective counterparty (or its
advisors) to any swap or derivative transaction relating to the Credit Parties and their
obligations, (g) with the consent of the Borrower or (h) to the extent such Information (i) becomes
publicly available other than as a result of a breach of this Section or (ii) becomes available to
the Administrative Agent, the Issuing Bank or any Lender on a nonconfidential basis from a source
other than a Credit Party. For the purposes of this Section, “Information” means all
information received from any Credit Party relating to any Credit Party or its business, other than
any such information that is available to the Administrative Agent, the Issuing Bank or any Lender
on a nonconfidential basis prior to disclosure by any Credit Party. Any Person required to
maintain the confidentiality of Information as provided in this Section shall be considered to have
complied with its obligation to do so if such Person has exercised the same degree of care to
maintain the confidentiality of such Information as such Person would accord to its own
confidential information.
Section 11.13. Interest Rate Limitation. Notwithstanding anything herein to the
contrary, if at any time the interest rate applicable to any Loan, together with all fees, charges
and other amounts which are treated as interest on such Loan under applicable law (collectively
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the “Charges”), shall exceed the maximum lawful rate (the “Maximum Rate”)
which may be contracted for, charged, taken, received or reserved by the Lender holding such Loan
in accordance with applicable law, the rate of interest payable in respect of such Loan hereunder,
together with all Charges payable in respect thereof, shall be limited to the Maximum Rate and, to
the extent lawful, the interest and Charges that would have been payable in respect of such Loan
but were not payable as a result of the operation of this Section shall be cumulated and the
interest and Charges payable to such Lender in respect of other Loans or periods shall be increased
(but not above the Maximum Rate therefor) until such cumulated amount, together with interest
thereon at the Federal Funds Effective Rate to the date of repayment, shall have been received by
such Lender. Chapter 346 of the Texas Finance Code (which regulates certain revolving credit
accounts (formerly Tex. Rev. Civ. Stat. Ann. Art. 5069, Ch. 15)) shall not apply to this Agreement
or to any Loan, nor shall this Agreement or any Loan be governed by or be subject to the provisions
of such Chapter 346 in any manner whatsoever.
Section 11.14. USA PATRIOT Act. Each Lender that is subject to the requirements of
the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Act”)
hereby notifies each Credit Party that pursuant to the requirements of the Act, it is required to
obtain, verify and record information that identifies each Credit Party, which information includes
the name and address of each Credit Party and other information that will allow such Lender to
identify each Credit Party in accordance with the Act.
Section 11.15. Original Credit Agreement. Upon the Effective Date, this Agreement
shall supersede and replace in its entirety the Original Credit Agreement; provided,
however, that (a) all loans, letters of credit, and other indebtedness, obligations and
liabilities outstanding under the Original Credit Agreement on such date shall continue to
constitute Loans, Letters of Credit and other indebtedness, obligations and liabilities under this
Agreement, (b) the execution and delivery of this Agreement or any of the Loan Documents hereunder
shall not constitute a novation, refinancing or any other fundamental change in the relationship
among the parties and (c) the Loans, Letters of Credit, and other indebtedness, obligations and
liabilities outstanding hereunder, to the extent outstanding under the Original Credit Agreement
immediately prior to the date hereof, shall constitute the same loans, letters of credit, and other
indebtedness, obligations and liabilities as were outstanding under the Original Credit Agreement.
Section 11.16. Reaffirmation and Grant of Security Interest. Each Credit Party hereby
(i) confirms that each Security Instrument (as defined in the Original Credit Agreement) to which
it is a party or is otherwise bound and all Collateral encumbered thereby, will continue to
guarantee or secure, as the case may be, to the fullest extent possible in accordance with the Loan
Documents and regardless of whether any Guarantor under this Agreement was a “Borrower” under the
Original Credit Agreement, the payment and performance of all Obligations and Guaranteed
Liabilities under this Agreement and the Secured Obligations (as such term is defined in the
Security Instruments) under the Security Instruments, as the case may be, including without
limitation the payment and performance of all such Obligations and Guaranteed Liabilities under
this Agreement and the Secured Obligations under the Security Instruments, and (ii) reaffirms its
grant to the Administrative Agent for the benefit of the Secured Parties of a continuing Lien on
and security interest in and to such Credit Party’s right, title and interest in, to and under all
Collateral as collateral security for the prompt payment and
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 85
performance in full when due of the Obligations and Guaranteed Liabilities under this
Agreement and the Secured Obligations under the Security Instruments (whether at stated maturity,
by acceleration or otherwise) in accordance with the terms thereof. With respect to the other Loan
Documents, (a) the defined term “Bank One” shall be deemed to mean JPMorgan Chase Bank, (b) the
defined term “Agent” shall be deemed to mean JPMorgan Chase Bank, in its capacity as Administrative
Agent and (c) the defined term “Rate Management Transaction” shall be deemed to mean indebtedness,
liabilities and obligations of any Credit Party with respect to transactions under Swap Agreements
between such Credit Party and any Lender Counterparty that are included in the defined term
“Obligations” under this Agreement.
Section 11.17. Reallocation of Aggregate Commitment. The Lenders (as defined in the
Original Credit Agreement) have agreed among themselves to reallocate the Commitment (as defined in
the Original Credit Agreement) as contemplated by this Agreement and to adjust their interests in
the Commitment and the Loans (as defined in the Original Credit Agreement) accordingly. On the
Effective Date and after giving effect to such reallocation and adjustment of such Commitment and
such Loans, the Lenders (as defined in this Agreement) shall own the Applicable Percentages set
forth on Schedule 2.01. The outstanding Loans (as defined in the Original Credit Agreement) and
the funds delivered to the Administrative Agent on the Effective Date by the Lenders (other than
the Lenders under the Original Credit Agreement) and the other Lenders shall be allocated such that
after giving effect to such allocation each of the Lenders (as defined in this Agreement) shall own
the Applicable Percentages of the Aggregate Commitment and the Commitments set forth on Schedule
2.01 and such Lenders shall own the Loans (as defined in this Agreement) consistent with the
Applicable Percentages set forth on Schedule 2.01.
[Signature Pages Follow]
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — Page 86
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by
their respective authorized officers as of the day and year first above written.
| BORROWER: | ||||||
| RANGE RESOURCES CORPORATION | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
| GUARANTORS: | ||||||
| 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 | ||||||||
| RANGE ENERGY I, INC., | ||||||||
| a Delaware corporation | ||||||||
| By: | ||||||||
| Name: Roger S. Manny | ||||||||
| Title: Senior Vice President | ||||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| 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 | ||||||
| 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 | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| 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 | ||||||
| PMOG HOLDINGS, INC., | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| PINE MOUNTAIN ACQUISITION, INC., | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
| PINE MOUNTAIN OIL AND GAS, INC., | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
| RANGE OPERATING NEW MEXICO, INC., | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
| RANGE OPERATING TEXAS, LLC, | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
| STROUD ENERGY GP, LLC, | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
| STROUD ENERGY LP, LLC, | ||||||
| By: | ||||||
| Name: Thomas M. Strauss | ||||||
| Title: Manager | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| STROUD ENERGY, LTD., | ||||||
| By: | Stroud Energy Management GP, LLC | |||||
| Its general partner | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
| STROUD ENERGY MANAGEMENT GP, LLC, | ||||||
| By: | ||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
| STROUD OIL PROPERTIES, L.P., | ||||||
| By: | Stroud Energy GP, LLC | |||||
| Its general partner | ||||||
| By:
|
||||||
| Name: Roger S. Manny | ||||||
| Title: Senior Vice President | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| JPMORGAN CHASE BANK, N.A. | ||||||
| (successor by merger to Bank One, N.A. (Illinois)
as Administration Agent and a Lender |
||||||
| By: | ||||||
| Name: Wm. Mark Cranmer | ||||||
| Title: Senior Vice President | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| BANK OF SCOTLAND, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| CALYON NEW YORK BRANCH, | ||||||
| as a Syndicated Agent and a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| COMPASS BANK, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| BANK OF AMERICA, N.A., | ||||||
| as a Documentation Agent and a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| FORTIS CAPITAL CORP., | ||||||
| as a Documentation Agent and a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| NATEXIS BANQUES POPULAIRES, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| COMERICA BANK, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| CAPITAL ONE, N.A. (f/k/a Hibernia National | ||||||
| Bank), as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| AMEGY BANK N.A. (f/k/a Southwest Bank of | ||||||
| Texas N.A.), as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| BMO CAPITAL MARKETS FINANCING, INC. | ||||||
| (f/k/a HARRIS NESBITT FINANCING, INC.), | ||||||
| as a Syndication Agent and a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| KEY BANK, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| WACHOVIA BANK, NATIONAL | ||||||
| ASSOCIATION, as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| UNION BANK OF CALIFORNIA, N.A., | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| THE BANK OF NOVA SCOTIA, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| THE FROST NATIONAL BANK, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| CITIBANK, N.A., | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| CREDIT SUISSE, Cayman Islands Branch, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| SUNTRUST BANK, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| SOCIÉTÉ GÉNÉRALE, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| U.S. BANK NATIONAL ASSOCIATION, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
| DEUTSCHE BANK TRUST COMPANY AMERICAS, | ||||||
| as a Lender | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
| By: | ||||||
| Name: | ||||||
| Title: | ||||||
RANGE RESOURCES THIRD AMENDED AND RESTATED CREDIT AGREEMENT — SIGNATURE PAGE
SCHEDULE 2.01
APPLICABLE PERCENTAGES AND INITIAL COMMITMENTS
| Applicable | ||||||||||
| Lender | Title | Percentage | Initial Commitment | |||||||
JPMorgan Chase Bank , N.A. |
Administrative Agent | 5.6250000 | % | $ | 45,000,000 | |||||
Bank of America, N.A. |
Documentation Agent | 5.6250000 | % | $ | 45,000,000 | |||||
Fortis Capital Corp. |
Documentation Agent | 5.6250000 | % | $ | 45,000,000 | |||||
Calyon New York Branch |
Syndicated Agent | 5.6250000 | % | $ | 45,000,000 | |||||
BMO Capital Markets
Financing, Inc., (f/k/a
Harris Nesbitt Financing,
Inc.) |
Syndication Agent | 5.6250000 | % | $ | 45,000,000 | |||||
Union Bank of California, N.A. |
Co-Agent | 5.0000000 | % | $ | 40,000,000 | |||||
Bank of Scotland |
Agent | 5.6250000 | % | $ | 45,000,000 | |||||
Wachovia Bank, National
Association |
Co-Agent | 4.3750000 | % | $ | 35,000,000 | |||||
Citibank, N.A. |
Co-Agent | 4.3750000 | % | $ | 35,000,000 | |||||
Comerica Bank |
Co-Agent | 5.0000000 | % | $ | 40,000,000 | |||||
Compass Bank |
3.1250000 | % | $ | 25,000,000 | ||||||
Credit Suisse, Cayman Islands
Branch |
3.7500000 | % | $ | 30,000,000 | ||||||
Deutsche Bank Trust Company
Americas |
Co-Agent | 4.3750000 | % | $ | 35,000,000 | |||||
Key Bank |
Co-Agent | 4.3750000 | % | $ | 35,000,000 | |||||
Natexis Banques Populaires |
Co-Agent | 4.3750000 | % | $ | 35,000,000 | |||||
The Bank of Nova Scotia |
Co-Agent | 5.0000000 | % | $ | 40,000,000 | |||||
Société Générale |
4.3750000 | % | $ | 35,000,000 | ||||||
Suntrust Bank |
4.3750000 | % | $ | 35,000,000 | ||||||
The Frost National Bank |
3.1250000 | % | $ | 25,000,000 | ||||||
Amegy Bank N.A. (f/k/a
Southwest Bank of Texas N.A.) |
3.1250000 | % | $ | 25,000,000 | ||||||
US Bank, National Association |
4.3750000 | % | $ | 35,000,000 | ||||||
Capital One, N.A. (f/k/a
Hibernia National Bank) |
3.1250000 | % | $ | 25,000,000 | ||||||
TOTAL |
100.00000 | % | $ | 800,000,000 | ||||||
SCHEDULE 2.01 — PAGE 1
EXHIBIT 21
RANGE RESOURCES CORPORATION
Subsidiaries of Registrant
| Jurisdiction of | Percentage of Voting Securities | |||||
| Name | 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 | % | |||
Range Operating Texas, L.L.C.
|
Delaware | 100 | % | |||
Stroud Energy GP, L.L.C.
|
Delaware | 100 | % | |||
Stroud Energy LP, L.L.C.
|
Delaware | 100 | % | |||
WCR/Range GP, L.L.C
|
Texas | 100 | % | |||
| (a) | Dormant subsidiary with no assets. |
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 26, 2007 with respect to the consolidated
financial statements of Range Resources Corporation, 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 included in this Annual Report (Form 10-K) for the year ended December 31, 2006.
| /s/ Ernst & Young LLP |
Fort Worth, Texas
February 26, 2007
February 26, 2007
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 14, 2007, prepared for Range Resources Corporation in the Range
Resources Corporation Annual Report on Form 10-K for the year ended December 31, 2006. 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 22, 2007
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, 2006, to which this consent is an exhibit. We also consent to the
incorporation of information contained in our “Appraisal Report
as of December 31, 2006 on 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, 2007
February 22, 2007
EXHIBIT 23.4
CONSENT OF WRIGHT & COMPANY, INC.
We hereby consent to the
use of the name Wright & Company, Inc. and 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, 2006, to
which this consent is an exhibit.
| WRIGHT & COMPANY, INC. |
Brentwood, Tennessee
February 23, 2007
February 23, 2007
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 26, 2007 | /s/ JOHN H. PINKERTON | |||
| 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 26, 2007 | /s/ ROGER S. MANNY | |||
| 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,
2006 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 | |||
| John H. Pinkerton February 26, 2007 |
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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,
2006 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 | |||
| Roger S. Manny February 26, 2007 |
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